United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-80-038a
December 1980
Air
o-EPA
Bulk Gasoline
Terminals —
Background
Information for
Proposed Standards
Draft
EIS
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EPA-450/3-80-038a
Bulk Gasoline Terminals -
Background Information
for
Proposed 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
December 1980
-------
This report has been reviewed by the Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, Office of Air, Noise,
and Radiation, Environmental Protection Agency, and approved for publica-
tion. Mention of company or product names does not constitute endorsement
by EPA. Copies are available free of charge to Federal employees, current
contractors and grantees, and non-profit organizations - as supplies permit
from the Library Services Office, MD-35, Environmental Protection Agency
Research Triangle Park, NC 27711; or may be obtained, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
VA 22161.
Publication No. EPA-450/3-80-038a
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Draft
Environmental Impact Statement
for Bulk Gasoline Terminals
Prepared by:
Don R. Goodwin I (Date)
Director, Emission Standards and Engineering Division
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
1. The proposed standards of performance would 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 other interested parties
3. The comment period for review of this document is 60 days.
Ms. Susan R. Wyatt may be contacted regarding the date of the
comment period.
4. For additional information contact:
Ms. Susan R. Wyatt
Standards Development Branch (MD-13)
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
telephone: (919) 541-5477
5. 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
iii
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TABLE OF CONTENTS
Title Page
1.0 SUMMARY 1-1
1.1 Regulatory Alternatives 1-1
1.2 Environmental Impacts 1-2
1.3 Economic Impact 1-4
2.0 INTRODUCTION 2-1
2.1 Background and Authority for Standards 2-1
2.2 Selection of Categories of Stationary Sources . . . 2-5
2.3 Procedure for Development of Standards of
Performance 2-6
2.4 Consideration of Costs 2-8
2.5 Consideration of Environmental Impacts 2-9
2.6 Impact on Existing Sources 2-11
2.7 Revision of Standards of Performance 2-11
3.0 THE BULK GASOLINE TERMINAL INDUSTRY 3-1
3.1 General 3-1
3.1.1 Introduction 3-1
3.1.2 Terminal Locations and Sizes 3-1
3.2 Gasoline Loading Operations and Their Emissions . . 3-2
3.2.1 Introduction 3-2
3.2.2 Gasoline Loading at Bulk Terminals 3-2
3.2.3 Emissions from Loading Operations 3-11
3.2.4 Gasohol 3-18
3.3 Baseline Emissions 3-21
3.3.1 Introduction 3-21
3.3.2 Control Techniques Guidelines 3-21
3.3.3 Calculation of Baseline Emission Level 3-22
3.4 References 3-28
4.0 EMISSION CONTROL TECHNIQUES 4-1
4.1 Introduction " 4-1
4.2 Process Modifications 4-1
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Title Page
4.3 Control of Fugitive Emissions 4-2
4.3.1 Tank Truck Leakage 4-2
4.3.2 Vapor Collection System Leakage 4-3
4.4 Typical Collection System 4-4
4.5 Vapor Processing Systems 4-5
4.5.1 Description of Control Technologies 4-5
4.5.2 Operation and Maintenance Practices 4-22
4.6 Emissions Due to Gasohol Loading 4-23
4.7 References 4-25
5.0 MODIFICATION AND RECONSTRUCTION 5-1
5.1 40 CFR Part 60 Provisions for Modification and
Reconstruction 5-2
5.1.1 Modification . » 5-2
5.1.2 Reconstruction 5-3
5.2 Applicability to Bulk Gasoline Terminals 5-3
5.2.1 Modification 5-3
5.2.2 Reconstruction 5-5
5.3 References 5-7
6.0 MODEL PLANT PARAMETERS AND REGULATORY ALTERNATIVES ... 6-1
6.1 Introduction 6-1
6.2 Model Plant Parameters 6-1
6.2.1 Definition of a Bulk Gasoline Terminal 6-1
6.2.2 Designation of Affected Facility 6-2
6.2.3 Data Base for Model Plant Parameters 6-7
6.2.4 Model Plant Parameters for Bulk Gasoline
Terminals 6-7
6.2.5 Model Firm Parameters for For-Hire Tank
Truck Companies 6-12
6.3 Regulatory Alternatives 6-14
6.3.1 Vapor Leakage from Tank Trucks 6-14
6.3.2 Selection of Emission Limits 6-16
6.3.3 Description of Regulatory Alternatives 6-16
6.4 References 6-21
vi
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Title Page
7.0 ENVIRONMENTAL IMPACT 7-1
7.1 Air Pollution Impacts 7-1
7.1.1 Air Pollution Impact on Model Plants 7-1
7.1.2 National Air Pollution Impacts 7-4
7.2 Water Pollution Impact 7-6
7.3 Solid Waste Disposal Impact 7-7
7.4 Energy Consumption Impact 7-7
7.5 Other Environmental Impacts 7-11
7.6 References 7-12
8.0 ECONOMIC IMPACT 8-1
8.1 Industry Characterization 8-1
8.1.1 General Profile 8-1
8.1.2 Trends 8-14
8.1.3 Tank Truck Industry 8-22
8.2 Cost Analysis of Regulatory Alternatives 8-28
8.2.1 Introduction 8-28
8.2.2 New Facilities 8-31
8.2.3 Modified/Reconstructed Facilities 8-53
8.2.4 Compliance Costs 8-63
8.2.5 Tank Truck Industry Control Costs 8-66
8.2.6 Nationwide Control Cost Summary 8-70
8.3 Other Cost Considerations 8-73
8.4 Economic Impact of Regulatory Alternatives 8-74
8.4.1 Impacts on Bulk Gasoline Terminals 8-74
8.4.2 Impacts on the Independent Tank Truck
Industry 8-103
8.5 Potential Socioeconomic and Inflationary Impacts. . . 8-114
8.5.1 Additional Control Costs 8-115
8.5.2 Excessive Additional Production Costs 8-116
8.5.3 Net National Energy Consumption 8-116
8.5.4 Demand for Scarce Materials 8-117
8.5.5 Ottier Impacts 8-117
8.6 References 8-118
vii
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Title Page
APPENDIX A - EVOLUTION OF THE BACKGROUND
INFORMATION DOCUMENT A-l
A.I Chronology A-2
APPENDIX B - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS . . B-l
APPENDIX C - EMISSION SOURCE TEST DATA C-l
C.I Summary of Test Activity C-2
C.I.I General C-2
C.I.2 EPA-Conducted Tests . . . . C-2
C.I.3 Other Vapor Processor Tests C-2
C.I.4 Tank Truck Leakage Tests C-7
C.2 Test Results and Calculations C-10
C.2.1 Factors Affecting Test Results C-10
C.2.2 System Leakage Calculations C-13
C.3 Summaries of EPA-Conducted Tests C-14
C.3.1 Bulk Terminal Test No. 1 C-14
C.3.2 Bulk Terminal Test No. 2 C-15
C.3.3 Bulk Terminal Test No. 3 C-16
C.3.4 Bulk Terminal Test No. 4 C-17
C.3.5 Bulk Terminal Test No. 5 C-18
C.3.6 Bulk Terminal Test No. 6 C-19
C.3.7 Bulk Terminal Test No. 7 C-19
C.3.8 Bulk Terminal Test No. 8 C-20
C.3.9 Bulk Terminal Test No. 9 C-21
C.3.10 Bulk Terminal Test No. 10 C-21
C.3.11 Bulk Terminal Test No. 11 C-22
C.3.12 Bulk Terminal Test No. 12 C-23
C.3.13 Bulk Terminal Test No. 13 C-24
C.3.14 Bulk Terminal Test No. 14 C-25
C.3.15 Bulk Terminal Test No. 15 C-26
C.3.16 Bulk Terminal Test No. 16 C-27
C.3.17 Bulk Terminal Test No. 17 C-27
C.3.18 Bulk Terminal Test No. 18 C-28
C.3.19 Bulk Terminal Test No. 19 C-28
viti
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Title Page
C.3.20 Bulk Terminal Test No. 20 C-29
C.3.21 Bulk Terminal Test No. 21 C-30
C.3.22 Bulk Terminal Test No. 22 C-31
C.4 References . , C-32
APPENDIX D - EMISSION MEASUREMENT AND CONTINUOUS MONITORING . D-l
D.I Gasoline Tank Trucks D-2
D.I.I Performance Test Method D-2
D.I.2 Emission Testing and Measurement Methods D-4
D.I.3 Monitoring Systems and Devices D-6
D.2 Vapor Collection and Processing Equipment D-7
D.2.1 Performance Test Method D-7
D.2.2 Emission Testing and Measurement Methods D-9
D.2.3 Monitoring Systems and Devices D-10
D.3 Vapor Processor Exhaust Outlet D-ll
D.3.1 Performance Test Method D-ll
D.3.2 Emission Testing and Measurement Methods D-18
D.3.3 Monitoring Systems and Devices D-18
D.4 References D-22
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LIST OF FIGURES
Ti tle Page
3-1 Example of Gasoline Loading at Bulk Terminals 3-3
3-2 Top Loading Methods Without Vapor Collection 3-5
3-3 Top Loading Systems With Vapor Collection 3-6
3-4 Bottom Loading 3-8
3-5 Typical Bottom Loading System With Vapor Collection . . 3-9
3-6 Major Tank Truck Leakage Sources 3-17
4-1 Schematic Diagram of a Carbon Adsorption System (CA) . . 4-10
4-2 Schematic Diagram of a Thermal Oxidizer System (TO). . . 4-13
4-3 Schematic Diagram of a Refrigeration System (REF) . . . 4-15
4-4 Schematic Diagram of a Compression-Refrigeration-
Absorption System (CRA) 4-18
4-5 Schematic Diagram of a Compression-Refrigeration-
Condensation System (CRC) 4-19
4-6 Schematic Diagram of a Lean Oil Absorption System (LOA). 4-21
8-1 Gasoline Distribution in the U.S 8-2
8-2 Petroleum Administration for Defense Districts 8-5
8-3 DOE Demand Regions 8-15
8-4 Control Equipment Purchase Costs 8-37
8-5 Control Equipment Installation Costs as a Function
of Purchase Cost 8-40
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LIST OF TABLES
Title Page
1-1 Assessment of Environmental and Economic Impacts
for Each Regulatory Alternative Considered 1-3
3-1 Example Air-Gasoline Vapor Mixture Composition 3-12
3-2 Uncontrolled VOC Emissions From Bulk Gasoline
Terminals 3-14
3-3 Properties of Ethanol and Gasoline 3-20
3-4 State Regulatory Coverage for Bulk Gasoline Terminals . 3-23
3-5 Source Emission Factors 3-25
3-6 Baseline Emissions (Base Year 1982) ... 3-27
4-1 VOC Emission Test Data Summary 4-6
6-1 Design Parameters for Bulk Gasoline Terminals 6-8
6-2 Bulk Gasoline Terminal Model Plant Parameters 6-11
6-3 Tank Truck Company Model Firm Parameters 6-15
6-4 Regulatory Alternatives for Bulk Gasoline Terminals . . 6-17
7-1 Baseline and Alternative VOC Emissions from Bulk
Gasoline Terminal Model Plants 7-2
7-2 National Air Quality Impacts of Regulatory Alternatives
on Bulk Gasoline Terminal Industry 7-5
7-3 Energy Consumption Impacts of Control Equipment on the
Bulk Gasoline Terminal Model Plants 7-8
7-4 Nationwide Net Energy Impacts of the Regulatory
Alternatives 7-10
8-1 1978 Bulk Terminal Population 8-4
8-2 1978 Regional Product Supply/Demand 8-7
8-3 Petroleum Bulk Terminal Storage Distribution 8-8
8-4 Petroleum Bulk Terminal Throughput Distribution .... 8-9
8-5 Petroleum Bulk Terminal Ownership 8-11
8-6 Gasoline Terminal Distribution by Size and Ownership . . 8-12
8-7 Petroleum Bulk Terminal Employment 8-13
8-8 DOE Projection Series 8-16
8-9 Regional Gasoline Consumption and Demand Forecasts . . . 8-17
8-10 Components of Highway Gasoline Use 8-18
8-11 Regional Gasoline Production and Supply Forecasts . . . 8-20
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Title Page
8-12 Estimated Number of Affected Facilities in Various
Years 8-23
8-13 Estimated Age Distribution of Gasoline Tank Trucks at
Bulk Terminals 8-25
8-14 Regional Trends in Gasoline Delivery Tank Distribution
by Year of Manufacture 8-26
8-15 Estimated Number of Affected Tank Truck Companies
and Tank Trucks in Various Years 8-27
8-16 Tanks with Bottom Loading and Vapor Recovery as a
Function of Company Size 8-29
8-17 Estimated Control Costs for Regulatory Alternative II
New Facility in Attainment Area 8-32
8-18 Estimated Control Costs for Regulatory Alternative III
New Facility in Attainment Area 8-33
8-19 Estimated Control Costs for Regulatory Alternative IV
New Facility in Attainment Area 8-34
8-20 Installation Cost Elements 8-38
8-21 Cost Factors Used in Developing Annualized Costs .... 8-41
8-22 Calculation of Annualized Costs of Vapor Control
Units 8-42
8-23 Electrical Consumption and Operating Schedules of
Vapor Control Units 8-44
8-24 Annualized Tank Truck Vapor-Tight Maintenance Costs. . . 8-47
8-25 Gasoline Recovery Credits 8-48
8-26 Incremental VOC Controlled 8-49
8-27 Cost-Effectiveness of Control Options - New Facilities . 8-51
8-28 Facility Base Cost Components 8-52
8-29 Estimated Control Costs for Regulatory Alternative II
Existing Facility, Bottom Loaded - Attainment Area . . . 8-54
8-30 Estimated Control Costs for Regulatory Alternative III
Existing Facility, Bottom Loaded - Attainment Area . . . 8-55
8-31 Estimated Control Costs for Regulatory Alternative IV
Existing Facility, Bottom Loaded - Attainment Area . . . 8-56
8-32 Estimated Control Costs for Regulatory Alternative II
Existing Facility, Top Loaded - Attainment Area .... 8-57
8-33 Estimated Control Costs for Regulatory Alternative III
Existing Facility, Top Loaded - Attainment Area .... 8-58
8-34 Estimated Control Costs for Regulatory Alternative IV
Existing Facility, Top Loaded - Attainment Area .... 8-59
xii
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Title Page
8-35 Estimated Control Costs for Regulatory Alternatives III.
& IV, Existing Facility, Unit Replaced - Non-Attainment
Area 8-60
8-36 Estimated Control Costs for Regulatory Alternatives III
& IV, Existing Facility, Secondary Unit Added on -
Non-Attainment Area 8-61
8-37 Cost-Effectiveness of Control Options - Existing
Facilities 8-64
8-38 Capital Investment and Annualized Cost for Three
Compliance Options 8-67
8-39 Control Cost Estimates For Tank Truck Model Firms. . . . 8-71
8-40 Total National Cost Analysis of Regulatory
Alternatives 8-72
8-41 Sales and Ratio Statistics - Majors and
Semi-Majors 8-77
8-42 Selected Financial Statistics - Petroleum Bulk
Storage Specialists 8-78
8-43 Debt Service Coverage Ratio for New Facilities 8-82
8-44 Estimated Capital Investment for New Facilities .... 8-83
8-45 Maximum Percentage Price Increases, Cost
Pass-Through: New Facilities 8-87
8-46 After-Controls, After-Tax Return on Investment:
New Facilities 8-89
8-47 Debt Service Coverage Ratio, Existing Facility -
Baseline 8-94
8-48 Debt Service Coverage Ratio, Existing Facility,
Bottom Loaded - Attainment Area 8-95
8-49 Debt Service Coverage Ratio, Existing Facility,
Top Loaded - Attainment Area 8-96
8-50 Debt Service Coverage Ratio for Existing Facility,
Unit Replaced - Non-Attainment Area 8-97
8-51 Debt Service Coverage Ratio, Existing Facility,
Secondary Unit Added On - Non-Attainment Area 8-98
8-52 Maximum Percentage Price Increases, Cost Pass-Through:
Existing Facilities 8-99
8-53 After-Controls, After-Tax Return on Investment:
Existing Facilities 8-101
xiii
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Title Page
8-54 Operating Expenses and Revenues for Tank
Truck Firms 8-104
8-55 Financial Ratios and Statistics 8-106
8-56 ROTI Analysis 8-107
8-57 Cost Pass-through Analysis 8-109
8-58 Per-Trailer Control Costs As a Percent of
Per-Trailer Expenses 8-110
8-59 Debt Service Coverage Analysis 8-112
C-l Weighted Averages of Calculated Emission Test
Parameters C-3
C-2 Results of Vapor Recovery System Tests Performed
by San Francisco Bay Area Air Quality Management
District C-8
C-3 Tank Tightness History C-ll
C-4 Results of EPA-Sponsored Tank Truck Leakage
Tests C-12
xiv
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1.0 SUMMARY
Background information on proposed new source performance standards
for the bulk gasoline terminal industry is contained in this document.
New source performance standards are proposed under authority of
Section 111, 301(a) of the Clean Air Act, as amended.
1.1 REGULATORY ALTERNATIVES
Review of the technical support data led to the development of
four regulatory alternatives. Alternative I would require no additional
regulatory action. This alternative would rely on the State Implemen-
tation Plans (SIP) to regulate bulk terminals primarily in non-attainment
areas for ozone. A typical SIP for terminals would limit vapor processor
outlet volatile organic compound (VOC) emissions to 80 mg/liter and
would require periodic testing of tank trucks for vapor tightness. It
is estimated that SIPs will affect about 72 percent of the bulk terminals
nationwide by the year 1982.
Alternative II would limit VOC emissions from a bulk terminal's
vapor collection system to 80 mg/liter and would require the owner or
operator to restrict loadings of gasoline tank trucks to those which
had passed an annual vapor-tight test. Even though the emission limit
of Alternative II is the same as in the SIPs, greater emission reduction
would be achieved because the requirements would be extended to include
all areas of the country not regulated by SIPs.
Alternative III would limit VOC emissions from a vapor collection
system to 35 mg/liter. This alternative would rely on the SIPs to
control tank truck vapor leakage in most areas of the country.
Alternative IV would also limit vapor collection system emissions
to 35 mg/liter, but would require a terminal owner or operator to
restrict loadings of gasoline tank trucks to those which had passed an
annual vapor-tight test. This alternative would extend the tank truck
vapor-tight requirement to previously unregulated areas of the country.
1-1
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1.2 ENVIRONMENTAL IMPACTS
Under Alternative I, there would be no VOC emission reduction
from baseline emission levels because there is no additional regulatory
action associated with Alternative I. Under Alternative II, nationwide
VOC emissions would be reduced by 5,750 Mg/year by 1985. This represents
a reduction of about 60 percent in the VOC emissions from all new,
modified, or reconstructed terminals, and a reduction of approximately
4 percent in the emissions from all bulk gasoline terminals.
Under Alternative III, nationwide VOC emissions would be reduced
by 4,510 Mg/year by 1985, a reduction of about 50 percent in the
emissions from affected terminals and a reduction of about 3 percent
in emissions from all bulk gasoline terminals. The lower emission
reduction of Alternative III when compared to Alternative II illustrates
the significance of tank truck vapor leakage. Even though processor
outlet emissions under Alternative III would be reduced from 80 mg/liter
to 35 mg/liter, the lack of vapor-tight testing requirements for tank
trucks in attainment areas more than offsets the additional processor
outlet VOC reduction.
Under Alternative IV, nationwide VOC emissions by 1985 would
decrease by 6,620 Mg/year. This represents a reduction of about
70 percent in the nationwide VOC emissions from affected terminals,
and a reduction of about 5 percent for all bulk gasoline terminals.
The regulatory alternatives would result in negligible impacts on
noise, space, and availability of resources.
The air quality impacts, as well as all environmental impacts,
are summarized in Table 1-1.
None of the control systems evaluated uses water as a collection
medium. Some control systems handle small amounts of water removed
from the air; however, all product is removed in a gasoline/water
separator. The impact on water quality would be small.
No solid waste is directly generated by any system evaluated. An
indirect solid waste impact may be encountered by the disposal of
spent activated carbon from carbon adsorption control systems. Even
in the worst case, where all systems used were carbon units and where
1-2
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TABLE 1-1. ASSESSMENT OF ENVIRONMENTAL AND ECONOMIC IMPACTS
FOR EACH REGULATORY ALTERNATIVE CONSIDERED
Regulatory
Alternative
I
II
III
IV
Keyi +
-
0
1
2
Air Water
Impact Impact
0 0
+2** -2*
+2** -2*
+3** -2*
Beneficial Impact
Adverse Impact
No impact
Negligible Impact
Smal 1 Impact
Solid Waste Energy Noise
Impact Impact Impact
000
_!** +2** -1*
-1** +2** _i*
_!** +3** -l*
3 Moderate Impact
4 Large Impact
* Short- Term Impact
** Long-Term Impact
*** Irreversible Impact
Inf la-
Economic tionary
Impact Impact
0 0
-1* -i*
_1* -i*
-1* -i*
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the carbon was discarded after its useful life at the terminal, the
solid waste impact would be minimal.
Energy impacts were derived by assuming that all VOC reduction
would be recovered as liquid product and that this product is equivalent
to gasoline. Positive energy impacts would be realized with each alternative
even when it is assumed that as many as half of the small terminals
could use thermal oxidation systems which do not recover any product.
Fuel savings by 1985 could be as much as 9 million liters of gasoline
per year under Alternative IV.
1.3 ECONOMIC IMPACTS
The total capital cost to the bulk gasoline terminal industry for
the installed vapor control equipment necessary to meet Alternative II
on all new, modified, or reconstructed terminals would be approximately
$23.0 million through the first five years of the standard. The
terminal industry annualized cost in 1985 would be $3.3 million. The
total capital cost to the for-hire tank truck industry by 1985 would
be about $1.3 million, and the annualized cost to this industry in
1985 would be $0.7 million. The total annualized cost for these two
industries, coupled with the annual emission reduction expected under
Alternative II, would yield an annualized cost-effectiveness of $696/Mg
($632/ton) of VOC controlled.
The total capital cost for vapor control equipment necessary
through the first five years to meet Alternative III would be approxi-
mately $24.0 million. The terminal industry annualized cost which
would be experienced in 1985 would be $4.1 million. The total capital
cost to the for-hire tank truck industry would be the same as under
Alternative II, and the annualized cost in 1985 would be $0.6 million.
The total annualized cost to both industries, coupled with the emission
reduction expected under Alternative III, would yield an industry
annualized cost-effectiveness in 1985 of $l,042/Mg ($946/ton) of VOC
controlled.
The total capital cost for vapor control equipment necessary
through the first five years of the standard to meet Alternative IV
would be approximately $24.0 million. The industry annualized cost
which would be experienced in 1985 would be $3.6 million. Total
1-4
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capital and annualized costs to the for-hire tank truck industry would
be the same as under Alternative II. The total annualized cost to
both industries, coupled with the emission reduction expected under
Alternative IV, would result in an annualized cost-effectiveness in
1985 of $650/Mg ($590/ton) of VOC controlled.
Capital availability should not be a limiting factor in the
attempt of the smaller new bulk gasoline terminals to comply with the
proposed standards. Terminals in the smaller size range would have to
pass through most of the control costs to remain reasonable investments.
The necessary degree of cost pass-through appears possible. The
larger terminals are considered attractive investment possibilities.
Consequently, industry growth, considering that principally the larger
terminals are most likely to be constructed in the absence of new
standards, would not be restricted by implementation of any regulatory
alternative.
Existing top loaded terminals in attainment areas, of medium
throughput, would have to pass through most of their control costs in
order to maintain a reasonable rate of return under any alternative.
As in the case of the smallest terminals, most of the control costs
should be able to be passed through. The current trend toward the
consolidation of existing facilities of marginal profitability is
expected to continue, but no additional closures are projected to
result due to any of the alternatives.
The cost pass-through analyses for both new and existing terminals
show that the maximum retail price increase for gasoline would be less
than 0.6 percent under any alternative. This represents a worst case
situation within the bulk terminal industry, and nationwide gasoline
prices would not be affected.
The regulatory alternatives would affect the independent tank
truck industry with minor impacts. The profitability of the firms in
the industry would not be impacted significantly since regulatory cost
absorption would be minimal. Most of the regulatory costs would be
passed through to the consumer, causing a maximum increase in retail
gasoline prices of less than 0.05 percent for any of the alternatives.
This increase would not affect nationwide gasoline prices, but represents
1-5
-------
a worst case situation within the independent tank truck industry if
all control costs were passed through. Additionally, no closures or
dislocations of tank truck firms are expected to result from any of
the regulatory alternatives.
1-6
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2.0 INTRODUCTION
2.1 BACKGROUND AND AUTHORITY FOR STANDARDS
Before standards of performance are proposed as a Federal
regulation, air pollution control methods available to the affected
industry and the associated costs of installing and maintaining the
i
control equipment are examined in detail. Various levels of control
based on different technologies and degrees of efficiency are expressed
as regulatory alternatives. Each of these alternatives is studied by
EPA as a prospective basis for a standard. The alternatives are
investigated in terms of their impacts on the economics and well-being
of the industry, the impacts on the national economy, and the impacts
on the environment. This document summarizes the information obtained
through these studies so that interested persons will be able to see
the information considered by EPA in the development of the proposed
standard.
Standards of performance for new stationary sources are established
under Section 111 of the Clean Air Act (42 U.S.C 7411) as amended,
hereinafter referred to as the Act. Section 111 directs the Adminis-
trator to establish standards of performance for any category of new
stationary source of air pollution which "... causes, or contributes
significantly to air pollution which may reasonably be anticipated to
endanger public health or welfare."
The Act requires that standards of performance for stationary
sources reflect, "... the degree of emission reduction achievable
which (taking into consideration the cost of achieving such emission
reduction, and any non-air quality health and environmental impact and
energy requirements) the Administrator determines has been adequately
demonstrated for that category of sources." The standards apply only
to stationary sources, the construction or modification of which
commences after regulations are proposed by publication in the Federal
Register.
2-1
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The 1977 amendments to the Act altered or added numerous provisions
that apply to the process of establishing standards of performance.
1. EPA is required to list the categories of major stationary
sources that have not already been listed and regulated under standards
of performance. Regulations must be promulgated for these new categories
on the following schedule:
a. 25 percent of the listed categories by August 7, 1980.
b. 75 percent of the listed categories by August 7, 1981.
c. 100 percent of the listed categories by August 7, 1982.
A governor of a State may apply to the Administrator to add a category
not on the list or may apply to the Administrator to have a standard
of performance revised.
2. EPA is required to review the standards of performance every
four years and, if appropriate, revise them.
3. EPA is authorized to promulgate a standard based on design,
equipment, work practice, or operational procedures when a standard
based on emission levels is not feasible.
4. The term "standards of performance" is redefined, and a new
term "technological system of continuous emission reduction" is defined.
The new definitions clarify that the control system must be continuous
and may include a low- or non-polluting process or operation.
5. The time between the proposal and promulgation of a standard
under Section 111 of the Act may be extended to six months.
Standards of performance, by themselves, do not guarantee protection
of health or welfare because they are not designed to achieve any
specific air quality levels. Rather, they are designed to reflect
the degree of emission 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 non-air quality health and environmental
impacts, and energy requirements.
Congress had several reasons for including these requirements.
First, standards with a degree of uniformity are needed to avoid
situations where some States may attract industries by relaxing standards
relative to other States. Second, stringent standards enhance the
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potential for long-term growth. Third, stringent standards may help
achieve long-term cost savings by avoiding the need for more retro-
fitting when pollution ceilings may be reduced in the future. Fourth,
certain types of standards for coal-burning sources can adversely
affect the coal market by driving up the price of low-sulfur coal or
effectively excluding certain coals from the reserve base because
their untreated pollution potentials are high. Congress does not
intend that new source performance standards contribute to these
problems. Fifth, the standard-setting process should create
incentives for improved technology.
Promulgation of standards of performance does not prevent State
or local agencies from adopting more stringent emission limitations
for the same sources. States are free under Section 116 of the Act to
establish even more stringent emission limits than those established
under Section 111 or those necessary to attain or maintain the National
Ambient Air Quality Standards (NAAQS) under Section 110. Thus, new
sources may in some cases be subject to limitations more stringent
than standards of performance under Section 111, and prospective
owners and operators of new sources should be aware of this possibility
in planning for such facilities.
A similar situation may arise when a major emitting facility is
to be constructed in a geographic area that falls under the prevention
of significant deterioration of air quality provisions of Part C of
the Act. These provisions require, among other things, that major
emitting facilities to be constructed in such areas are to be subject
to best available control technology. The term Best Available Control
Technology (BACT), as defined in the Act, means
... an emission limitation based on the maximum degree of
reduction of each pollutant subject to regulation under
this Act emitted from, or which results from, any major
emitting facility, which the permitting authority, on a
case-by-case basis, taking into account energy, environ-
mental, and economic impacts and other costs, determines
is achievable for such facility through application of
production processes and available methods, systems, and
techniques, including fuel cleaning or treatment or
innovative fuel combustion techniques for control of each
such pollutant. In no event shall application of "best
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available control technology" result in emissions of any
pollutants which will exceed the emissions allowed by any
applicable standard established pursuant to Section 111
or 112 of this Act. (Section 169(3))
Although standards of performance are normally structured in terms
of numerical emission limits where feasible, alternative approaches are
sometimes necessary. In some cases physical measurement of emissions
from a new source may be impractical or exorbitantly expensive.
Section lll(h) provides that the Administrator may promulgate a design
or equipment standard in those cases where it is not feasible to
prescribe or enforce a standard of performance. For example, emissions
of hydrocarbons from storage vessels for petroleum liquids are greatest
during tank filling. The nature of the emissions, high concentrations
for short periods during filling and low concentrations for longer
periods during storage, and the configuration of storage tanks make
direct emission measurement impractical. Therefore, a more practical
approach to standards of performance for storage vessels has been
equipment specification.
In addition, Section lll(j) authorizes the Administrator to grant
waivers of compliance to permit a source to use innovative continuous
emission control technology. In order to grant the waiver, the Adminis-
trator must find: (1) a substantial likelihood that the technology will
produce greater emission reductions than the standards require or an
equivalent reduction at lower economic energy or environmental cost;
(2) the proposed system has not been adequately demonstrated; (3) the
technology will not cause or contribute to an unreasonable risk to the
public health, welfare, or safety; (4) the governor of the State where
the source is located consents; and (5) the waiver will not prevent the
attainment or maintenance of any ambient standard. A waiver may have
conditions attached to assure the source will not prevent attainment of
any NAAQS. Any such condition will have the force of a performance
standard. Finally, waivers have definite end dates and may be termi-
nated earlier if the conditions are not met or if the system fails to
perform as expected. In such a case, the source may be given up to three
years to meet the standards with a mandatory progress schedule.
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2.2 SELECTION OF CATEGORIES OF STATIONARY SOURCES
Section 111 of the Act directs the Administrator to list categories
of stationary sources. The Administrator "... shall include a category
of sources in such list if in his judgment it causes, or contributes
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare." Proposal and promulgation of
standards of performance are to follow.
Since passage of the Clean Air Amendments of 1970, considerable
attention has been given to the development of a system for assigning
priorities to various source categories. The approach specifies areas
of interest by considering the broad strategy of the Agency for imple-
menting the Clean Air Act. Often, these "areas" are actually pollutants
emitted by stationary sources. Source categories that emit these
pollutants are evaluated and ranked by a process involving such factors
as: (1) the level of emission control (if any) already required by
State regulations, (2) estimated levels of control that might be
required from standards of performance for the source category,
(3) projections of growth and replacement of existing facilities
for the source category, and (4) the estimated incremental amount
of air pollution that could be prevented in a preselected future
year by standards of performance for the source category. Sources
for which new source performance standards were promulgated or under
development during 1977, or earlier, were selected on these criteria.
The Act amendments of August 1977 establish specific criteria to
be used in determining priorities for all major source categories not
yet listed by EPA. These are: (1) the quantity of air pollutant
emissions that each such category will emit, or will be designed to
emit; (2) the extent to which each such pollutant may reasonably be
anticipated to endanger public health or welfare; and (3) the mobility
and competitive nature of each such category of sources and the consequent
need for nationally applicable new source standards of performance.
The Administrator is to promulgate standards for these categories
according to the schedule referred to earlier.
In some cases, it may not be feasible immediately to develop a
standard for a source category with a high priority. This might
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happen when a program of research is needed to develop control techniques
or because techniques for sampling and measuring emissions may require
refinement. In the developing of standards, differences in the time
required to complete the necessary investigation for different source
categories must also be considered. For example, substantially more
time may be necessary if numerous pollutants must be investigated
from a single source category. Further, even late in the development
process the schedule for completion of a standard may change. For
example, inability to obtain emission data from well-control 1 ed
sources in time to pursue the development process in a systematic
fashion may force a change in scheduling. Nevertheless, priority
ranking is, and will continue to be, used to establish the order in
which projects are initiated and resources assigned.
After the source category has been chosen, the types of facilities
within the source category to which the standard will apply must be
determined. A source category may have several facilities that cause
air pollution, and emissions from some of these facilities may vary
from insignificant to very expensive to control. Economic studies of
the source category and of applicable control technology may show that
air pollution control is better served by applying standards to the
more severe pollution sources. For this reason, and because there is
no adequately demonstrated system for controlling emissions from
certain facilities, standards often do not apply to all facilities at
a source. For the same reasons, the standards may not apply to all
air pollutants emitted. Thus, although a source category may be
selected to be covered by a standard of performance, not all pollutants
or facilities within that source category may be covered by the standards,
2.3 PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE
Standards of performance must (1) realistically reflect best
demonstrated control practice; (2) adequately consider the cost, the
non-air quality health and environmental impacts, and the energy
requirements of such control; (3) be applicable to existing sources
that are modified or reconstructed as well as new installations; and
(4) meet these conditions for all variations of operating conditions
being considered anywhere in the country.
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The objective of a program for developing standards is to identify
the best technological system of continuous emission reduction that
has been adequately demonstrated. The standard-setting process involves
three principal phases of activity: (1) information gathering,
(2) analysis of the information, and (3) development of the standard
of performance.
During the information-gathering phase, industries are queried
through a telephone survey, letters of inquiry, and plant visits by
EPA representatives. Information is also gathered from many other
sources, and a literature search is conducted. From the knowledge
acquired about the industry, EPA selects certain plants at which
emission tests are conducted to provide reliable data that characterize
the pollutant emissions from well-control 1ed existing facilities.
In the second phase of a project, the information about the
industry and the pollutants emitted is used in analytical studies.
Hypothetical "model plants" are defined to provide a common basis for
analysis. The model plant definitions, national pollutant emission
data, and existing State regulations governing emissions from the
source category are then used in establishing "regulatory alternatives."
These regulatory alternatives are essentially different levels of
emission control.
EPA conducts studies to determine the impact of each regulatory
alternative on the economics of the industry and on the national
economy, on the environment, and on energy consumption. From several
possibly applicable alternatives, EPA selects the single most plausible
regulatory alternative as the basis for a standard of performance for
the source category under study.
In the third phase of a project, the selected regulatory alternative
is translated into a standard of performance, which, in turn, is
written in the form of a federal regulation. The federal regulation,
when applied to newly constructed plants, will limit emissions to the
levels indicated in the selected regulatory alternative.
As early as is practical in each standard-setting project, EPA
representatives' discuss the possibilities of a standard and the form
it might take with members of the National Air Pollution Control
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Techniques Advisory Committee. Industry representatives and other
interested parties also participate in these meetings.
The information acquired in the project is summarized in the
Background Information Document (BID). The BID, the standard, and a
preamble explaining the standard are widely circulated to the industry
being considered for control, environmental groups, other government
agencies, and offices within EPA. Through this extensive review
process, the points of view of expert reviewers are taken into
consideration as changes are made to the documentation.
A "proposal package" is assembled and sent through the offices of
EPA Assistant Administrators for concurrence before the proposed stan-
dard is officially endorsed by the EPA Administrator. After being
approved by the EPA Administrator, the preamble and the proposed regu-
lation are published in the Federal Register.
As a part of the Federal Register announcement of the proposed
regulation, the public is invited to participate in the standard-setting
process. EPA invites written comments on the proposal and also holds
a public hearing to discuss the proposed standard with interested
parties. All public comments are summarized and incorporated into a
second volume of the BID. All information reviewed and generated in
studies in support of the standard of performance is available to the
public in a "docket" on file in Washington, D. C.
Comments from the public are evaluated, and the standard of
performance may be altered in response to the comments.
The significant comments and EPA's position on the issues raised
are included in the "preamble" of a "promulgation package," which also
contains the draft of the final regulation. The regulation is then
subjected to another round of review and refinement until it is approved
by the EPA Administrator. After the Administrator signs the regulation,
it is published as a "final rule" in the Federal Register.
2.4 CONSIDERATION OF COSTS
Section 317 of the Act requires an economic impact assessment
with respect to any standard of performance established under Section
111 of the Act. The assessment is required to contain an analysis of:
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(1) the costs of compliance with the regulation, including the extent
to which the cost of compliance varies depending on the effective date
of the regulation and the development of less expensive or more efficient
methods of compliance; (2) the potential inflationary or recessionary
effects of the regulation; (3) the effects the regulation might have
on small business with respect to competition; (4) the effects of the
regulation on consumer costs; and (5) the effects of the regulation on
energy use. Section 317 also requires that the economic impact
assessment be as extensive as practicable.
The economic impact of a proposed standard upon an industry is
usually addressed both in absolute terms and in terms of the control
costs that would be incurred as a result of compliance with typical,
existing State control regulations. An incremental approach is
necessary because both new and existing plants would be required to
comply with State regulations in the absence of a federal standard of
performance. This approach requires a detailed analysis of the
economic impact from the cost differential that would exist between a
proposed standard of performance and the typical State standard.
Air pollutant emissions may cause water pollution problems, and
captured potential air pollutants may pose a solid waste disposal
problem. The total environmental impact of an emission source must,
therefore, be analyzed and the costs determined whenever possible.
A thorough study of the profitability and price-setting mechanisms
of the industry is essential to the analysis so that an accurate
estimate of potential adverse economic impacts can be made for proposed
standards. It is also essential to know the capital requirements for
pollution control systems already placed on plants so that the additional
capital requirements necessitated by these federal standards can be
placed in proper perspective. Finally, it is necessary to assess the
availability of capital to provide the additional control equipment
needed to meet the standards of performance.
2.5 CONSIDERATION OF ENVIRONMENTAL IMPACTS
Section 102(2)(C) of the National Environmental Policy Act (NEPA)
of 1969 requires federal agencies to prepare detailed environmental
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impact statements on proposals for legislation and other major federal
actions significantly affecting the quality of the human environment.
The objective of NEPA is to build into the decision-making process of
federal agencies a careful consideration of all environmental aspects
of proposed actions.
In a number of legal challenges to standards of performance for
various industries, the United States Court of Appeals for the District
of Columbia Circuit has held that environmental impact statements need
not be prepared by the Agency for proposed actions under Section 111
of the Clean Air Act. Essentially, the Court of Appeals has determined
that the best system of emission reduction requires the Administrator
to take into account counter-productive environmental effects of a
proposed standard, as well as economic costs to the industry. On this
basis, therefore, the Court established a narrow exemption from NEPA
for EPA determination under Section 111.
In addition to these judicial determinations, the Energy Supply
and Environmental Coordination Act (ESECA) of 1974 (PL-93-319)
specifically exempted proposed actions under the Clean Air Act from
NEPA requirements. According to Section 7(c)(l), "No action taken
under the Clean Air Act shall be deemed a major Federal action
significantly affecting the quality of the human environment within
the meaning of the National Environmental Policy Act of 1969." (15
U.S.C. 793(c)(l))
Nevertheless, the Agency has concluded that the preparation of
environmental impact statements could have beneficial effects on
certain regulatory actions. Consequently, although not legally required
to do so by Section 102(2)(C) of NEPA, EPA has adopted a policy requiring
that environmental impact statements be prepared for various regulatory
actions, including standards of performance developed under Section 111
of the Act. This voluntary preparation of environmental impact state-
ments, however, in no way legally subjects the Agency to NEPA require-
ments.
To implement this policy, a separate Section in this document is
devoted solely to an analysis of the potential environmental impacts
associated with the proposed standards. Both adverse and beneficial
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impacts in such areas as air and water pollution, increased solid
waste disposal, and increased energy consumption are discussed.
2.6 IMPACT ON EXISTING SOURCES
Section 111 of the Act defines a new source as "... any stationary
source, the construction or modification of which is commenced..."
after the proposed standards are published. An existing source is
redefined as a new source if "modified" or "reconstructed" as defined
in amendments to the general provisions of Subpart A of 40 CFR Part 60,
which were promulgated in the Federal Register on December 16, 1975
(40 FR 58416).
Promulgation of a standard of performance requires States to
establish standards of performance for existing sources in the same
industry under Section lll(d) of the Act if the standard for new
sources limits emissions of a designated pollutant (i.e., a pollutant
for which air quality criteria have not been issued under Section 108
or which has not been listed as a hazardous pollutant under Section 112),
If a State does not act, EPA must establish such standards. General
provisions outlining procedures for control of existing sources under
Section lll(d) were promulgated on November 17, 1975, as Subpart B of
40 CFR Part 60 (40 FR 53340).
2.7 REVISION OF STANDARDS OF PERFORMANCE
Congress was aware that the level of air pollution control
achievable by an industry may improve with technological advances.
Accordingly, Section 111 of the Act provides that the Administrator
"... shall, at least every 4 years, review and, if appropriate,
revise..." the standards. Revisions are made to assure that the
standards continue to reflect the best systems that become available
in the future. Such revisions will not be retroactive, but will apply
to stationary sources constructed or modified after the proposal of
the revised standards.
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3.0 THE BULK GASOLINE TERMINAL INDUSTRY
3.1 GENERAL
3.1.1 Introduction
A bulk gasoline terminal is typically any wholesale marketing
facility which receives gasoline from refineries by pipeline, ship, or
barge; stores it in large aboveground tanks; and dispenses it into
tank trucks for delivery to customers. Only a small number (less than
2 percent) of bulk terminals dispense gasoline into rail cars. Gasoline
is delivered from bulk terminals to smaller bulk facilities, known as
bulk plants, or directly to retail accounts. Typically, bulk plants
have throughputs less than 76,000 liters (20,000 gallons) per day
while terminals typically have throughputs greater than 76,000 liters
per day. Terminals handle several petroleum products in addition to
gasoline, including diesel fuel and heating oil.
For the purpose of this study, gasoline is defined as a petroleum
distillate or a petroleum distillate/alcohol blend having a Reid Vapor
Pressure of 27.6 kPa (4 psi) or greater that is used as fuel for
internal combustion engines. Gasoline is by far the largest volume
petroleum product marketed in the U.S., with a nationwide consumption
of 443 billion liters (117 billion gallons) in 1978.l Since the major
use for gasoline is the fueling of the passenger automobile, the
demand for gasoline is assured as long as automobiles are the primary
means of transportation in the country. Other uses for gasoline
include light-duty trucks, motorcycles, power boats, and small devices
such as electrical generators and lawn mowers. Expected future trends
in gasoline consumption and in the size of the bulk gasoline terminal
population are discussed in Section 8.1 of Chapter 8.
3.1.2 Terminal Locations and Sizes
There are presently an estimated 1,511 bulk terminals storing
2
gasoline in the U.S. About half of these terminals receive products
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from refineries by pipeline, and half receive products by ship or
barge delivery. Most of the terminals (66 percent) are located along
the east coast and in the Midwest. The remainder are dispersed throughout
the country, with locations largely determined by population patterns.
The combined gasoline storage capacity of all the terminals is
approximately 47 million cubic meters (m ), with the largest segment
of the terminal population being composed of smaller facilities (less
3
than 32,000 m capacity). The average gasoline throughput, or business
3
volume, of all terminals is approximately 2 million liters per day.
3.2 GASOLINE LOADING OPERATIONS AND THEIR EMISSIONS
3.2.1 Introduction
Bulk gasoline terminals serve as redistribution points for the
gasoline produced at refineries and, as such, they do not perform any
processing operations on the gasoline, although sometimes additives
are mixed with gasoline at terminals. All movement of gasoline at a
bulk terminal involves only loading, unloading, and transfer. Gasoline
stored in tanks is pumped through metered loading areas, called loading
racks, and into delivery tank trucks, which service various wholesale
and retail accounts in the marketing network. Figure 3-1 shows a
schematic diagram of the transfer of gasoline at a bulk terminal. The
following section describes in more detail the major components in
terminal loading operations.
3.2.2 Gasoline Loading at Bulk Terminals
3.2.2.1 Storage Tanks. A typical terminal has four or five
aboveground storage tanks for gasoline, each with a capacity ranging
from 1,500 to 15,000 m3 (9,400 to 94,000 barrels). Most tanks in
gasoline service have a floating roof to prevent the loss of product
through evaporation and working losses. Fixed roof tanks use
pressure-vacuum (P-V) vents to control breathing losses and use vapor
balancing or processing equipment to control working losses.
A new source performance standard (NSPS) has been promulgated for
controlling the escape of hydrocarbon vapors from storage vessels for
A
petroleum liquids. Thus, emissions from gasoline storage tanks will
not be discussed further.
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CO
I
U)
Gasoline From
Pipeline, —•
Ship, or Barge
Vapor to
Collection System
or Atmosphere
Floating Roof
Storage Tanks
Gasoline
Pumps
Top or Bottom
Loading Racks
111 UJ
Tank
Trucks
Figure 3-1. Example of Gasoline Loading at Bulk Terminals
-------
3.2.2.2 Loading Racks. Loading racks contain the equipment
necessary to fill delivery tank trucks with liquid product. A typical
loading rack includes fuel loading arms, pumps, meters, shutoff valves,
relief valves, check valves, electrical grounding, and lighting.
Terminals generally utilize two to four rack positions for gasoline,
each having from one to four loading arms. Gasoline is loaded through
a loading arm at an average rate of 2,270 liters per minute (600 gpm),
with the rate at various terminals ranging from 1,320 liters per
minute (350 gpm) to 3,790 liters per minute (1,000 gpm). Loading may
be performed using either top splash, top submerged, or bottom loading
methods. These systems will be discussed in greater detail in the
following subsections.
3.2.2.2.1 Top loading. Top loading is divided into top splash
loading, with and without vapor collection, top submerged, and top
tight submerged loading. Top loading involves loading of products
into the compartment via the hatchway which is located on top of the
tank. Gasoline is loaded directly into the compartment through a top
loading fill pipe (splash fill). Attachment of a fixed or extensible
downspout to the fill pipe provides a means of introducing the product
near the bottom of the tank (submerged fill). Top splash loading
creates more turbulence during loading and can create a vapor mist.
Submerged loading greatly reduces the turbulence. See Figure 3-2.
Top loading can also be designed for vapor collection. A top
loading vapor head, compatible with the truck hatch opening, creates a
vapor-tight seal between the loading head and the hatch to minimize
vapor leakage during transfer of product. An annular space in the
vapor head routes vapors into the vapor collection system. See Figure 3-3.
In a top tight submerged fill installation, the loading of product
is performed through a vapor-tight loading adapter mounted on top of
each compartment and attached to a permanently fixed submerged fill
pipe. For vapor collection, the vapor spaces of each compartment are
routed to the overturn rail or to a vapor return line. Vapors from
all compartments are manifolded together into one vapor line.
Figure 3-3 shows one of these configurations. One advantage of this
permanently affixed top tight submerged fill system is that the hatch/
dome covers remain closed at all times except for cleanup and repair.
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FILL PIPE
VAPOR EMISSIONS
-HATCH COVER
CARGO TANK
a. Top Splash Loading
VAPOR EMISSIONS
FILL PIPE
HATCH COVER
CARGO TANK
b. Top Submerged Loading
Figure 3-2. Top Loading Methods Without Vapor Collection
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Vapor Line
Hatch Cover
Liquid LinV
Lift Cylinder
Truck Tank Shell
Drop Tube
TOP LOADING VAPOR HEAD SYSTEM
Top Loading Arm_
Flexible Hose
Compatible Vapor Tight Adapters
Permanent
Submerged
Fill Pipe
Vapor
Line
Vapor Connector
TOP TIGHT LOADING SYSTEM
Figure 3-3. Top Loading Systems With Vapor Collection
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This minimizes wear on the hatch and vapor containment equipment. The
top tight and vapor head systems allow the collection of vapors expelled
from the tank during product loading.
The top tight loading system is not in widespread use at terminals.
Simplified loading combined with vapor collection is generally accomplished
using bottom loading, which is described in the following section.
3.2.2.2.2 Bottom loading. Bottom loading refers simply to the
loading of products into the cargo tank from the bottom. Figure 3-4
illustrates the principle of bottom loading. Submerged loading occurs
naturally using this method and turbulence is again held to a minimum.
Some of the advantages cited for bottom loading include: (1) improved
safety, (2) faster loading, and (3) reduced labor costs. Safety is
improved since the operator does not have to climb on top of the
truck. This is especially advantageous during wet or icy conditions
when the top of the truck may be slick. Loading can be accomplished
in a shorter time because all the equipment is at ground level where
it can be easily handled by the operator. Faster loadings reduce
labor costs because more loadings can be done per labor-hour.
Loading gasoline into a tank truck through bottom connectors is a
simple operation. Dry-break couplers are used to attach loading arms
to trucks so that liquid loss can be minimized during connecting and
disconnecting. For vapor collection, a flexible hose or swing-type
arm is usually connected to a vapor collection line on the truck.
This line routes gasoline vapors to a vapor collection and processing
system. See Figure 3-5.
3.2.2.2.3 Overfill protection. In order to measure the quantity
of gasoline delivered during bottom loading and to provide protection
against overfilling, set-stop meters are used to shut off the flow of
gasoline when a preset quantity has been delivered. Liquid level
sensing devices are commonly used with preset meters to provide
secondary control in the event of a malfunction or human error.
Liquid level sensors are devices used to detect a full condition in the
compartment being loaded. These devices are electrically connected to
close flow control valves or shut off the delivery pumps if the level
approaches the top of the tank. This eliminates the possibility of
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TO RECOVERY
OR ATMOSPHERE
HATCH CLOSED
n
I \X ,
VAPORS
CARGOTANK
FILL PIPE
Figure 3-4. Bottom Loading
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SENSOR
VAPOR RECOVERY HOOD
PRODUCT
SUPPLY
TO VAPOR
PROCESSOR
Figure 3-5. Typical Bottom Loading System With Vapor Collection
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overfilling the compartment. Commonly used sensing devices include
fiber optics systems, electric probe, and float switches.
3.2.2.3 Tank Trucks. Oil companies operating bulk terminals
typically operate from 3 to 20 gasoline tank trucks at a single terminal,
although many terminals are served entirely by "for-hire" tank trucks
operated by outside companies. These tank trucks range in size from
15,000 to 38,000 liters (4,000 to 10,000 gallons), averaging about
32,200 liter (8,500 gallon) capacity.5 While there are several configu-
rations of delivery tank vehicles in service, the single term "tank
truck" will generally be used throughout this document to include all
of them. Model firms for the for-hire tank truck industry are discussed
in Section 6.2.5, and an industry profile and economic impact analysis
for this industry are contained in Sections 8.1.3 and 8.4.2 of Chapter 8.
Just as there are several loading methods and types of rack
equipment to fill tank trucks with gasoline, there are several com-
patible truck loading systems. Tank trucks are normally divided into
compartments with a hatchway at the top of each compartment. Top
loading can be accomplished by opening the hatch cover and dispensing
product directly through the hatch by splash or submerged fill. A top
loading vapor head compatible with the hatch also permits loading
through the hatch wh.ile vapors are collected. A better vapor-tight
seal is realized when top loading is performed through a top tight
loading adapter mounted in each compartment.
During a bottom loading operation, an internal valve is opened to
allow product flow, and tank vents open to permit the exit of vapors
which are displaced by the incoming product. Vapor collection systems
on tank trucks incorporating bottom loading equipment collect vapors
from the compartment vents through a common vapor manifold. The tank
truck vapor line terminates at a connector on the side or at the rear
of the truck which is compatible with the terminal vapor collection
equipment.
A recent survey covering approximately 1,900 tank vehicles, or
about 2 percent of the gasoline tank truck population, indicated that
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22.8 percent of tank trucks have only top loading, while the remaining
77.2 percent can be either top or bottom loaded. The trend is toward
more trucks using bottom loading, due to State vapor recovery regulations
and the advantages cited earlier.
3.2.3 Emissions From Loading Operations
Since there are no other processes associated with the loading of
gasoline into tank trucks at bulk terminals, the only emissions from
the operation are volatile organic compounds (VOC) consisting of the
gasoline vapors displaced from tank trucks during loading. These
compounds are primarily C. and C^ paraffins and olefins which are
photochemically reactive (precursors to ozone). Table 3-1 presents an
example of the major components of the air-vapor mixture emitted
during the loading operation. The exact composition depends on the
particular gasoline being loaded and the vapor concentration in the
tank.
3.2.3.1 Switch Loading. It was mentioned earlier (Section 3.1.1)
that bulk gasoline terminals may handle liquid petroleum products
other than gasoline. VOC emissions from products such as fuel oil,
diesel, and jet fuel can be considered negligible when compared to
gasoline, because of the lower vapor pressures of these products. The
emissions from the loading of these products are 0.02, 2.4, and
3.6 milligrams, respectively, for each liter of product loaded. The
emission factors for the loading of gasoline are discussed in the next
section. At many terminals, "switch loading" of delivery tank trucks
is practiced. Switch loading involves the transport, in a single tank
compartment on successive deliveries, of one or more other products in
addition to gasoline. Gasoline vapors can be displaced either by
incoming gasoline or by any other liquid product when vapors from a
previous load of gasoline are left in the delivery tank. As an example,
fuel oil loaded into a tank compartment which had carried gasoline on
the previous load would displace gasoline vapors, producing VOC emissions.
Thus, VOC emissions can occur at gasoline loading racks, and also at
product loading racks which switch load into tank trucks which transport
gasoline.
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Table 3-1. EXAMPLE AIR-GASOLINE VAPOR MIXTURE COMPOSITION8
Component Volume Percent
Air 74.5
N-Butane 12.2
Iso-Pentane 6.5
Iso-Butane 3.0
N-Pentane 2.5
Butene 0.5
Propane 0.4
Hexane 0.3
Benzene 0.1
Total 100.0
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Without emission controls on the loading operation, the quantities
of VOC emitted depend on such factors as the loading method used and
the concentration of the vapors in the tank truck at the start of
loading. These factors are discussed in the following subsection.
3.2.3.2 Factors Affecting Emissions. When gasoline is loaded,
the rate of emission of VOC is affected by the manner in which the
gasoline is introduced into tank trucks. Top splash loading creates a
turbulent loading operation which causes the entrainment of gasoline
mist and droplets in the vapor space. The mist and droplets are
subsequently emitted to the atmosphere through the open hatches. The
emissions for uncontrolled splash loading are 1,440 milligrams of VOC
emitted for each liter of gasoline loaded (nig/liter) (12 pounds/
1000 gallons). For submerged fill or bottom loading the emissions
are reduced to 600 mg/liter (5 pounds/1000 gallons). These factors
apply to normal service, in which tank trucks do not exchange gasoline
for air-vapor mixture when unloading at bulk plants or retail accounts.
The emissions from loading trucks in "balance service" are affected
by the concentration of vapors in the tank air space during loading.
"Balance service" applies to tank trucks which have exchanged their
liquid gasoline for the vapors displaced by filling the gasoline
storage tanks at the service station or bulk plant. The amount of
vapors exchanged depends upon the vapor tightness of the tank truck.
If leaks occur, air enters the compartment and the amount of vapors
transferred, and hence the concentration in the compartment, decreases.
VOC vapor levels may approach saturation in a tank truck servicing
delivery points where a vapor balance system is utilized. The emissions
for both splash fill and bottom loading of tank trucks in balance
service are 960 mg/liter (8 pounds/1000 gallons). The requirement
for vapor balancing of tank trucks is expected to be in effect by the
end of 1982 in areas where bulk terminals are regulated by SIPs.
Table 3-2 presents the uncontrolled VOC emissions from terminals
in selected size ranges. The data indicate that these emissions from
terminals are generally greater than 100 Mg/year.
3.2.3.3 Va*por Collection at Loading Racks. In open top loading
without vapor recovery the displaced air-vapor mixture escapes to the
3-13
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Table 3-2. UNCONTROLLED VOC EMISSIONS FROM BULK GASOLINE TERMINALS
CO
Splash Loading3 Submerged Loading
Gasoline Throughput Mg/yr Ton/yr Mg/yr Ton/yr
380,000 liters/day
(100,000 gal/day) 185 205 80 85
950,000 liters/day
(250,000 gal/day) 465 510 195 215
1,900,000 liters/day
(500,000 gal/day) 930 1,020 390 425
3,800,000 liters/day
(1,000,000 gal/day) 1,860 2,040 775 850
Balance Service
Mg/yr Ton/yr
125 135
310 340
620 680
1 ,240 1 ,360
Emission Factor = 1,440 mg/liter.
Emission Factor = 600 mg/liter. Pertains to top submerged and bottom loading.
Emission Factor = 960 mg/liter. Pertains to top or bottom loading, and represents a delivery
tank whose previous load was balanced with displaced vapors
during filling of a bulk plant or service station storage tank,
-------
atmosphere through the open hatchway. The emission factors for
uncontrolled emissions discussed earlier apply to this type of
loading. The other types of loading include provisions for recovering
the vapors so that they can be processed (destroyed or condensed into
liquid product). The emissions from such controlled loading depend on
the control efficiency of the vapor processor and the amount of leakage
in the vapor collection system.
The flexible hoses or swing-type arms at the loading racks, which
collect air-vapor mixture from loading tank trucks, are manifolded
together and all of the collected vapors are piped to a single vapor
processor. In the case where two tank trucks are loading simultaneously
at different racks, it is possible for the air-vapor mixture displaced
from one tank to pass through the vapor piping and escape through the
other tank. This phenomenon has been observed in several terminal
tests. To avoid this problem, most bulk terminals install check
valves or similar devices in the vapor return lines to isolate
individual lines and ensure that vapors are routed to the vapor
processor. The processors which are in current usage are discussed in
Chapter 4. Acceptable collection efficiency of controlled loading
operations depends on the absence of vapor leaks in the system. The
following subsections describe several places in the collection system
where fugitive (leakage) emissions can occur.
3.2.3.3.1 Tank truck leakage. The effectiveness of vapor control
systems at bulk terminals is dependent upon the minimization of leaks
in the vapor-containing equipment. Some gasoline delivery tank trucks
have been demonstrated to be major sources of vapor leakage during
loading operations. The average vapor leakage from delivery tanks
measured in EPA-sponsored terminal tests was found to be 30 percent.
These tests were performed in areas having no tank truck vapor
tightness regulations. Vapor leakage as high as 100 percent for
g
individual tank loadings was recorded. In contrast, the average
leakage in an area of California requiring vapor tightness certifi-
cation testing was found to be 10 percent. Sources of leakage
include dome covers, pressure-vacuum (P-V) vents, and vapor collection
piping and vents.
3-15
-------
Dome cover assemblies consist of a series of openings, clamps,
and seals, each of which is a potential source of VOC vapor leakage.
Leakage can occur when foreign material becomes lodged in the inter-
face between the hatchway collar and the dome base ring or between the
base ring and the dome lid. The normal vibration of these components
during product transport may also lead to gradual seal failure. In
addition, the dome lid can become warped or damaged if it is opened
and closed frequently, or if struck by a top loading arm.
P-V vents are normally installed in the dome lids to prevent
dangerous pressure differentials from damaging the tanks. Dome lids
are spring-loaded to serve as backup pressure release to the P-V vents
installed in the lids. Emissions may occur if a P-V vent is not
installed correctly or the valve seat is damaged or dirty and is not
sealing properly. Figure 3-6 illustrates the primary sources of
leakage for a typical configuration.
On those truck delivery tanks which have vapor recovery equipment
installed, VOC can leak from the vapor collection equipment. Normally,
each compartment has a vent valve which is opened when that compartment
is being loaded or unloaded. This vent allows vapors to be removed
from or returned to the compartment through piping in the vapor col-
lection system. The compartment vent valve is covered with either a
rubber boot assembly or a metal cover, bolted or welded in place, to
contain the vapors in the vapor transfer system. The vapor return
line can be either rubber hose or metal pipe mounted on top of the
tank or incorporated into the overturn rail, or any combination of
these. The vapor return line, which is manifolded to each compartment,
contains joints or connectors in the piping for each compartment.
VOC vapors can leak from the vent valve cover due to tears in the
rubber boot, leaks in gaskets at bolted covers, or faulty welds in
welded covers. Leaks can occur in the vapor line connectors from poor
seals or clamping mechanisms with rubber hoses, or faulty welds or
seals with metal piping. VOC emissions may also be detected at the
vapor return coupler. This is caused by vapors leaking out through
the vapor transfer lines due to improperly sealing internal valves.
Other sources of vapor leakage on tank trucks which occur less
frequently than those already discussed include tank shell flaws,
3-16
-------
OVERTURN
(VAPOR RETURN)
RAIL
RUBBER BOOT
OR
COVER
VENT
VALVE
OVERFILL SENSOR
DOME LID SEAL
BASE RING GASKET
TANK SHELL
Figure 3-6. Major Tank Truck Leakage Sources
3-17
-------
improperly welded seams, and improperly installed or loosened overfill
protection sensors.
3.2.3.3.2 Vapor collection system leakage. The most common
leakage points in a vapor collection system include vapor connectors
and hoses, interfaces between top loading vapor recovery heads and
tank hatch openings, and vapor piping to control units.
Leakage occurs from connectors and hoses when they are improperly
connected or are allowed to deteriorate to a highly worn condition.
Vapor piping can leak due to faulty flange gaskets or accidental
damage. P-V vents on knockout (condensate) tanks and vapor holders
can also be sources of leakage in the vapor collection system. In
one EPA test, approximately 81 percent of the displaced vapors
leaked from a vapor holder before reaching the processor, and in
another EPA test about 48 percent of the vapors escaped from leaks
12
in tank trucks and loading rack P-V vents and check valves.
For top loading vapor collection systems, a significant source of
leakage is the interface between the top loading vapor head and the
tank truck hatch. The vapor heads are designed to seal at the hatch
through the compression of a cone-shaped rubber ring. However, in
practice these vapor heads do not seal consistently at the hatch
interface and can be a sizeable source of leaks.
3.2.4 Gasohol
There is a growing worldwide interest, both in the developing
countries and the more affluent industrialized nations, in the use of
13
gasohol. At present, Brazil is pursuing the most ambitious alcohol
14
fuel program. A large percentage of most current publications deal
with political issues, ' cost-effectiveness, and alternative processes
for increasing alcohol production, in addition to the effects of
gasohol on automobile operation.
3.2.4.1 Gasohol Market Trends. Current market reports (August
1980) indicate that gasohol, primarily because of weak gasoline
prices and high alcohol prices from primary suppliers, is having
difficulty in maintaining a competitive edge. For example, one
large chain, which found gasohol accounting for 12 to 15 percent
of total sales in 1979, when it could price the product at 2 cents
3-18
-------
per gallon over unleaded gasoline, now finds the ratio as low as
5 percent because of a 6 cent per gallon differential over
unleaded.
One of the major factors which will determine whether alcohol
fuels will remain competitive is the number of States which will set
tax exemptions for gasohol. So far, only 17 States have offered
exemptions and just 9 of these provide substantial financial advantages.
The other eight offer nominal reductions or reductions for alcohol
produced only in those States. While some States have sacrificed
substantial tax revenues to help gasohol become a staple in the marketplace,
four-fifths of the States have not made such commitments. These tax
advantages are essential if gasohol is to survive until alcohol production
18
is sufficient to moderate or even reduce prices.
3.2.4.2 Properties of Gasohol. Gasohol is an automotive fuel
which contains 10 volume percent ethanol and 90 volume percent gasoline.
A profile of the properties of gasohol may prove useful in considering
the potential effect of gasohol on the operation of vapor control
systems. Gasoline is composed of several hydrocarbon constituents and
contains less than 1 percent of elements other than hydrogen and carbon.
Ethanol, ChLChLOH, contains almost 35 percent oxygen. A few of the
pertinent properties of ethanol and gasoline are listed in Table 3-3.
The Reid Vapor Pressure (RVP) of gasoline will increase due to
the addition of 10 percent ethanol from approximately 8.7 psia to
9.8 psia. As a result, evaporative emissions from gasohol are
approximately 50 percent higher than those from straight gasoline,
20
even with blend and gasoline matched in vapor pressure.
Ethanol is completely miscible with water as well as with gasoline;
a small amount of water can be tolerated in gasohol. However, less
than 1 percent water at ambient temperatures or lower will result in
separation of the phases, with the ethanol concentration higher in the
water phase. This water phase is less dense than pure water and can
be corrosive to steel, aluminum, or zinc.
Additional properties include the cleansing effect of gasohol.
Gum, varnish, sediment, and rust can be loosened and suspended by the
gasohol, which in automobiles may result in the clogging of the fuel
filter.19
3-19
-------
Table 3-3. PROPERTIES OF ETHANOL AND GASOLINE19
CHEMICAL PROPERTIES
Formula
Molecular Weight
% Carbon (by weight)
% Hydrogen (by weight)
% Oxygen (by weight)
PHYSICAL PROPERTIES
Specific Gravity
Liquid Density ^Ib/ft3
Ib/gal
psi at 100°F (Reid)
psi at 77°F
Boiling Point (°F)
Freezing Point (°F)
Solubility in Water
THERMAL PROPERTIES
Lower Heating Value
Btu/lb
Btu/gal
Higher Heating Value
Btu/lb at 68°F
Btu/gal
Heat of Vaporization
Btu/lb
Btu/gal
Flammability Limits (% by volume in air)
Specific Heat (Btu/lb - °F)
Gasoline
C4"C12
varies
85-88
12-15
indefinite
Gasoline
0.70-0.78
43.6 approx.
5.8-6.5
7-15
0.3 approx.
80-440
-70 approx.
240 ppm
Gasoline
18,900 (avg)
115,400 (avg)
20,260
124,800
150
900
1.4-7.6
0.48
Ethanol
CH3CH2OH
46.1
52.1
13.1
4.7
Ethanol
0.794
49.3
6.59
2.5
0.85
173
-173
infinite
Ethanol
11,500
73,560
12,800
84,400
396
3,378
4.3-19.0
0.60
3-20
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3.3 BASELINE EMISSIONS
3.3.1 Introduction
The baseline emission level represents the level of emissions
achieved due to State and local regulations in the absence of addi-
tional standards of performance. This parameter is used as an aid in
assessing the environmental and economic impacts associated with
various emission regulatory alternatives. Most of the States are
incorporating regulations to control VOC emissions from bulk terminal
gasoline loading operations into their State Implementation Plans
21
(SIPs). A Control Techniques Guideline (CT6) for this source category
has been prepared by EPA. This CTG is intended primarily for areas
where National Ambient Air Quality Standards (NAAQS) for oxidants are
not being attained under present control regulations. The SIPs for
States with such non-attainment areas are expected to reflect the
recommendations of the CTG by the year 1982. Several of these States
will require the CTG level of control throughout the State, and several
of the States with no non-attainment areas for oxidants are not expected
to require any control measures on gasoline loading operations.
A CTG related to the control of VOC emissions from tank trucks
22
and vapor collection systems (see Sections 3.2.3.3.1 and 3.2.3.3.2)
has also been issued by EPA. These two CTG documents are expected to
be incorporated together into SIPs.
3.3.2 Control Techniques Guidelines
The bulk terminal CTG recommended emission limit which represents
the presumptive norm that can be achieved through the application of
reasonably available control technology (RACT) is 80 milligrams of
VOCs per liter of gasoline loaded. RACT is defined as the lowest
emission limit that a particular source is capable of meeting by the
application of control technology that is reasonably available
considering technological and economic feasibility.
In order to ensure that vapor control processors function
effectively, the fugitive emissions from tank trucks and collection
system components other than the processor must be controlled. Since
tank trucks are'the major source of leakage in these systems, the CTG
controlling fugitive emissions will be referred to as the "tank truck
3-21
-------
CTG." The control approach taken in this CTG is to ensure that good
maintenance practices are followed. The recommended regulation pre-
scribes a pressure/vacuum test for gasoline truck tanks and a procedure
to test potential leakage points in the vapor collection system. In
addition, regulatory agencies may monitor truck tanks and collection
systems using a specified combustible gas detection procedure.
3.3.3 Calculation of Baseline Emission Level
3.3.3.1 SIP Regulatory Coverage. The Control Programs Development
Division (CPDD) of EPA provided information concerning the extent of
regulations expected to be incorporated in SIPs. In addition, proposed
SIP revisions for several States were examined to determine compatibility
with CTG recommendations. EPA regional offices and State agencies
provided updates of information on State regulatory coverage. From
these inputs, estimates of regulatory coverage for each State were
obtained. From the SIP revision examinations, it is apparent that
most States are defining control using two different approaches. The
first requires an emission limit of 80 mg/liter, which is consistent
with the CTG. The second approach is to require a VOC collection and
recovery (or disposal) efficiency of 90 percent. For the purpose of
the baseline emissions calculations, these are considered essentially
equivalent.
Table 3-4 lists the regulatory coverage expected for each State
by the base year 1982. The States listed in the first column require
that all terminals within their boundaries achieve a level of control
consistent with that of the CTG recommendations (80 mg/liter). The
second column includes States which require controls consistent with
the CTG only for areas within the State which do not meet the NAAQS
for ozone (non-attainment areas). Remaining areas of these States
are either covered by submerged fill regulations or are left unregu-
lated. The third column includes States and U.S. Territories which do
not have any emission control regulations pertaining to bulk gasoline
terminals.
3.3.3.2 Source Emission Factor Categories. As discussed earlier
(Section 3.2.3.2), the emission factor for uncontrolled gasoline
loading depends in part on the loading method. Emissions from
3-22
-------
Table 3-4. STATE REGULATORY COVERAGE FOR BULK GASOLINE TERMINALS23'24'25'26
Entire State
Consistent
CTG Controls3
CTG Controls in
Non-Attainment
Areas Only
No Control
Regulations
California
Connecticut
District of Columbia
Georgia
Illinois
Indiana
Louisiana
Maine
Massachusetts
Michigan
New Hampshire
New Jersey
Ohio
Pennsylvania
Rhode Island
South Carolina
Tennessee
Utah
Virginia
Al abama
Arkansas
Colorado
Delaware
Florida
Iowa
Kentucky
Maryl and
Minnesota
Missouri
Nevada
New York
North Carolina
North Dakota0
Okl ahoma
Oregon
Texas
Vermont
Washington
West Virginia
Wisconsin
Alaska
Ari zona
Hawai i
Idaho
Kansas
Mississippi
Montana
Nebraska
New Mexico
South Dakota
Wyomi ng
Guam6
Puerto Rico6
Virgin Islands6
American Samoa6
CTG Controls = 80 mg/liter standard or lower, tank truck vapor-tight controls.
Portion of State not covered by CTG controls is covered by submerged
fill requirements.
°North Dakota has no non-attainment areas for ozone but entire State
covered by submerged fill regulations.
Approximately 90 percent of total throughput is loaded by submerged
f i 11.
H%
No non-attainment areas for ozone and gasoline throughput not
included in total.
3-23
-------
controlled operations (using a vapor control system) are assumed to be
equal to the emission limit imposed by the regulation in effect. The
total gasoline throughput subject to a particular method of loading or
control regulation provides the input necessary to calculate the
baseline emission level.
The "normal service" emission factors for uncontrolled splash
loading and submerged fill are 1,440 and 600 mg/liter, respectively.
These factors are estimated using an American Petroleum Institute
calculation method which accounts for such variables as liquid
temperature and true vapor pressure, vapor molecular weight, and a
saturation factor which depends on tank loading method. The factors
can be considered to apply to terminals whose loading is not con-
trolled or is controlled by a requirement for submerged filling. Such
terminals are located in the States and U.S. Territories listed in the
second and third columns of Table 3-4. The States in the second
column of the table, which require submerged filling, are noted with
the appropriate designation. Also, some terminals in States with no
control regulations use submerged fill or bottom loading. The
percentage of total gasoline throughput in submerged fill or bottom
loading categories is estimated to be 90 percent in those States where
27 28 29 30
no vapor recovery regulations are in effect. ' ' ' Thus, the
remaining 10 percent of the throughput in these States is assigned the
emission factor associated with splash loading.
The non-attainment areas of the States in the second column of
Table 3-4 are regulated by the level of control recommended in the
CTG. All terminals in the States in the first column are similarly
regulated. The terminals CTG recommends an adjusted emission limit of
80 mg/liter. The adjusted limit represents the vapor processor emissions
in a leak-free vapor collection system. The processor emission factor
used, therefore, for terminals covered by CTG-consistent regulations
is 80 mg/liter. In addition, a tank truck leakage emission factor of
96 mg/liter has been included for CTG-controlled terminals. This
represents 10 percent leakage during loading of trucks which are in
balance service at their customer accounts.
3-24
-------
The emission factors used for calculation of the baseline emission
level are summarized in Table 3-5.
Table 3-5. SOURCE EMISSION FACTORS
Category Emission Factor
Uncontrolled (Splash fill) 1,440 mg/liter
Submerged Fill 600 mg/liter
CTG-Controlled (Processor) 80 mg/liter
CTG-Controlled (Tank truck) 96 mg/liter
3.3.3.3 Baseline Emission Level Calculations. Since the VOC
emission factors for gasoline loading at bulk terminals are expressed
in terms of the volume of gasoline loaded, it is necessary to distribute
the gasoline throughput into emission factor categories. During the
year 1978, 443 billion liters (117 billion gallons) of gasoline was
consumed in the U.S. It is assumed that all gasoline consumed within
a State was loaded at a terminal in that State. Any errors due to
interstate transport of gasoline in tank trucks were assumed to balance
out.
The throughputs for States whose regulatory coverage applies
statewide (either controlled or uncontrolled) are readily assigned to
the appropriate emission factor category. For those States where the
regulations differ in separate geographical areas, fractions of the
total State gasoline consumption can be assigned to the proper regula-
tory categories by assuming that the gasoline consumption in these
areas is proportional to the population. Although the ideal situation
would have been to know the location of all 1,511 terminals in the
country, this information is not readily available. Thus, the estimate
of location based on population was used to assign gasoline throughput
fractions to emission factor categories. This method is commonly used
for emissions estimation when exact point source locations are unknown.
Since the regulatory geographical areas almost exclusively follow
3-25
-------
31
county boundaries, population estimates for each area are obtainable
for the purpose of calculating the percentage of throughput associated
with each emission factor. The gasoline consumption in the area in
question is determined by the following relationship:
Population of Area X
Gasoline Consumption = x State Gasoline
in Area X State Population Consumption
This method was used to categorize the gasoline throughputs for all of
the States. These calculations indicate that approximately 71 percent
of the nationwide gasoline loading at existing terminals will be
controlled to the level recommended by the CTG.
Based upon government estimates, gasoline consumption will experience
32
little net change from 1978 to 1985. This is due to economic factors
and increasing automobile fuel efficiency. The 1978 gasoline throughput
was, therefore, assumed to be equivalent to that in the base year of
1982. Section 8.1.2.1 of Chapter 8 discusses gasoline supply and
demand further.
Emissions for the base year were calculated using the selected
emission factors and the gasoline throughputs for each category.
Table 3-6 presents the results of these calculations, which indicate
that, although the uncontrolled and submerged fill categories represent
only about 28 percent of the nationwide gasoline throughput, they
account for almost 60 percent of the total emissions.
3-26
-------
Table 3-6. BASELINE EMISSIONS
(Base Year 1982)
Category
Uncontrolled
(Splash Fill)
Submerged Fill
CT6 Control:
Processors
Tank Trucks
Total
Gasoline Percent of
Throughput Total
(10° liters) Throughput
9,997
113,734
319,087
442,818
2.3
25.7
72.0
100.0
Emission
Factor
(mg /liter)
1,440
600
80
96
VOC
Emissions
(Mg/year)
14,396
68,240
25,527
30,632
138,795
Percent of
Total
Emissions
10.3
49.2
18.4
22.1
100.0
3-27
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3.4 REFERENCES
1. Gasoline Consumption by States. National Petroleum News Factbook
Issue. Vol. 71. No. 6A: p. 82. Mid-June 1979.
2. Arthur D. Little, Incorporated. The Economic Impact of Vapor
Control Regulations on the Bulk Storage Industry. U.S. Environ-
mental Protection Agency. Research Triangle Park, N.C. ADL
No. C-79911-11 (Draft). June 1979. p. II-6.
3. Ref. 2, p. 11-11.
4. U.S. Environmental Protection Agency. Standards of Performance
for Storage Vessels for Petroleum Liquids, as amended July 1977.
42 FR 37936. Code of Federal Regulations (CFR), Title 40, Part 60,
Subpart K. Washington, D.C. The Bureau of National Affairs,
Incorporated. August 1978.
5. Hang, J.C., and R.R. Sakaida. Survey of Gasoline Tank Trucks
and Rail Cars. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/3-79-004. March
1979. p. 2-15 - 2-18.
6. Ref. 5, p. 2-14.
7. Transportation and Marketing of Petroleum Liquids. In: Compila-
tion of Air Pollutant Emission Factors. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. July 1979.
p. 4.4-9.
8. Scott Environmental Technology, Incorporated. Benzene Control
Efficiency of Vapor Processor at the Exxon Bulk Gasoline Loading
Terminal, Philadelphia, Pennsylvania. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. EPA Contract
No. 68-02-2813, Work Assignment No. 12. February 1978. 48 p.
9. 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.
10. Norton, Robert L. Evaluation of Vapor Leaks and Development
of Monitoring Procedures for Gasoline Tank Trucks and Vapor
Piping. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/3-79-018. April
1979. 94 p.
11. 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.
3-28
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12. 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.
13. O'Sulliyan, D.A. UN Workshop Urges Wider Use of Ethanol. Chemical
and Engineering News. jx7(17). April 1979.
14. Yand, V. and S.C. Trindade. Brazil's Gasohol Program. Chemical
Engineering Progress. .75_(4). April 1979.
15. Dumas, A. and G. Karey. Washington Goes on a Gasohol Binge.
National Petroleum News. _72_(3). March 1980.
16. Clock, G. Gasohol: Is it a Plus or Minus in the U.S.? Oil & Gas
Journal. 7£(9). March 1980.
17. Reid, M. Slumping Gasoline Sales are Depressing Markets. National
Petroleum News. 72_(7). July 1980.
18. Dumas, A. Gasohol Craze Fades as Supply Tightens and Prices
Soar. National Petroleum News. .72_(6). June 1980.
19. Midwest Research Institute, Solar Energy Research Institute.
Fuel from Farms. U.S. Department of Energy. Contract
No. EG-77-C-01-4042. February 1980. p. D-3.
20. Keller, J.L. Alcohols as Motor Fuel. Hydrocarbon Processing.
.58(5). May 1979.
21. Polglase, W., W. Kelly, and J. Pratapas. Control of Hydrocarbons
from Tank Truck Gasoline Loading Terminals. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Publication
No. EPA-450/2-77-026. October 1977. 60 p.
22. Shedd, S.A. and N.D. Mclaughlin. Control of Volatile Organic
Compound Leaks from Gasoline Tank Trucks and Vapor Collection
Systems. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/2-78-051.
December 1978. 30 p.
23. Telecon. Norton, Robert, Pacific Environmental Services,
Incorporated, with Calcagni, John, U.S. Environmental Protection
Agency. June 1, 1979. Incorporation of terminal CTG into
SIPs.
24. Telecon. LaFlam, Greg, Pacific Environmental Services,
Incorporated, with Calcagni, John, U.S. Environmental Protection
Agency. August 3, 1979. Updating of information obtained in
Ref. 13.
3-29
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25. Memorandum from Polglase, W. and Calcagni, J., U.S. Environmental
Protection Agency to Helms, G.T., U.S. Environmental Protection
Agency. September 19, 1979. Summary of State Implementation Plan
VOC Regulations.
26. GCA Corporation. Status Summary of State Group I VOC RACT
Regulations as of March 10, 1980. Report to U.S. Environmental
Protection Agency under Contract 68-02-2607, Task No. 44.
Research Triangle Park, N.C. May 1980. 168 p.
27. Telecon. Norton, Robert, Pacific Environmental Services,
Incorporated, with Bolsted, John, Montana Air Quality Bureau.
June 7, 1979. Method of loading for uncontrolled terminals.
28. Telecon. Norton, Robert, Pacific Environmental Services,
Incorporated, with Anderson, Anthony, Georgia Department of
Natural Resources. June 7, 1979. SIP coverage for terminals
in the State of Georgia.
29. Telecon. LaFlam, Greg, Pacific Environmental Services, Incor-
porated, with Beall, F.J., Texaco. January 18, 1980. Prevalence
of splash truck loading at major oil company terminals.
30. Telecon. LaFlam, Greg, Pacific Environmental Services, Incor-
porated, with Percy, A.W., Union Oil Company. January 18, 1980.
Splash truck loading at Union Oil terminals.
31. U.S. Bureau of the Census. Current Population Reports, Series
P-25, No. 739, Estimates of the Population of Counties and
Metropolitan Areas: July 1, 1975 and July 1, 1976. Washington, D.C,
November 1978.
32. U.S. Department of Energy. Annual Report to Congress 1978.
Volume Three, Supplement One. Midterm Energy Projections
for the United States. Washington, D.C. Publication No.
DOE/EIA-0173/3-S1. July 9, 1979.
3-30
-------
4.0 EMISSION CONTROL TECHNIQUES
4.1 INTRODUCTION
It is estimated that about 400 vapor control systems are in
commercial operation at bulk gasoline terminals in the U.S. The
primary impetus for the installation of these systems has been the
regulations contained in State Implementation Plans (SIP).
The control of VOC emissions at a bulk terminal begins with the
method of gasoline loading used at the loading racks. For example, in
the absence of a vapor control system, a tank truck filled by top
splash loading will emit a greater quantity of VOC than will a tank
truck filled by the top submerged or bottom loading method. Also, in
a system using vapor control, the vapor-tight condition of the tank
trucks is a major factor in determining the overall total VOC emis-
sions from the loading activity. Finally, the various components of
the collection system, such as flexible hose, relief valves, and the
vapor holder (when used), are potential sources of leakage and must be
inspected and maintained in order to ensure that they are vapor-tight.
4.2 PROCESS MODIFICATIONS
Gasoline loading activity at a bulk terminal is generally a
process which is fixed by the type of equipment installed at the
terminal. Thus, for a given loading rack equipment configuration,
there is little opportunity for process changes which would reduce VOC
emissions. There is no evidence that lowering the gasoline pumping
rate, for example, would result in lower emissions through decreased
surface turbulence inside the tank truck. A well-maintained and
properly operating vapor processor is designed to collect sufficient
VOC vapors so that in conjunction with a leak-free system the prescribed
emission limit is achieved. A properly designed and sized vapor
collection system, including piping and valves, will not subject the
4-1
-------
tank truck to excessive back pressure. The system should be designed
so that the back pressure does not exceed 34 millimeters of mercury
(18 in. of water) gage pressure (see Section 4.3.1).
The most effective modifications leading to emission reduction
involve changes in equipment, including the elimination of vapor leaks
in tank trucks, conversion from top splash to submerged fill or bottom
loading of gasoline, and installation of a vapor control system.
4.3 CONTROL OF FUGITIVE EMISSIONS
4.3.1 Tank Truck Leakage
The effectiveness of vapor control systems at bulk terminals is
dependent upon the absence of leaks in the vapor-containing equipment.
Gasoline delivery tank trucks have been demonstrated to be major
sources of vapor leakage during loading operations, accounting for VOC
control system losses as high as 100 percent for some individual tank
truck loadings. In the EPA-sponsored terminal tests, the average
vapor loss due to tank truck leakage was 30 percent. These tests were
performed in areas having no tank truck vapor tightness regulations.
The existence of regulations requiring tank truck vapor tightness can
result in a lower average vapor leakage. The average leakage in an
area of California requiring vapor tightness certification testing was
2
found to be 10 percent.
An average 10 percent tank truck leakage rate was found in an EPA
test program where tank truck vapor leakage was monitored prior to
any maintenance necessary to pass the annual certification test.
During the 2-week test period 27 tanks were quantitatively tested for
vapor leakage using a pressure/vacuum test. The time since the last
certification varied from 20 days to 365 days. Leakage rates varied
from less than 2 percent to about 35 percent. A more thorough discussion
of these data can be found in Appendix C, Section C.1.4. Sources of
vapor leakage on tank trucks include dome covers, pressure-vacuum
vents, and vapor collection piping and vents. Smaller instances of
leakage occur at tank welds, liquid and vapor transfer hoses, overfill
sensors, and vapor couplers.
In order to achieve significant VOC emission reduction at bulk
terminals, tank truck vapor leakage must be controlled. The Control
A
Techniques Guideline (CTG) for gasoline tank trucks recommends a
4-2
-------
vapor tightness regulation and test procedure which reduces VOC losses
from tank trucks due to vapor leaks. Under this recommended regulation,
the tanks and their vapor collection equipment are not to sustain a
pressure change of more than 5.6 mm of mercury (3 in. of F^O) in
5 minutes when pressurized to 34 mm of mercury (18 in. of O) or
evacuated to 11 mm of mercury (6 in. of H^O). These pressure limits
reflect the way in which the pressure-vacuum vent valves operate on
tank trucks. The valves are spring loaded and designed to open slowly
and be fully open at 1 psi (27 in. of HJ)) pressure and 0.4 psi
(10 in. of HpO) vacuum. The limits of 34 mm of mercury and
11 mm of mercury recommended in the CTG represent the maximum pres-
sures which can be applied to the tank before the vents begin to
5
open. The pressure change limit of 5.6 mm of mercury represents
an approximate 99 percent tank vapor containment efficiency.
The vapor tightness of tank trucks can deteriorate quickly during
normal use. Test data have shown that some trucks may not be able to
meet the vapor-tight criteria as soon as two weeks after vapor-tight
certification. The monitoring provisions of the regulations recom-
mended by the CTG permit monitoring as needed using a portable
combustible gas detector.
Through installation of the proper equipment, and through periodic
inspection and subsequent repair or replacement of defective components,
leakage from tank trucks can be minimized to the extent that the
certification criteria specified by the CTG can be satisfied. Earlier
o
EPA reports summarize the appropriate maintenance procedures, as well
o
as tank truck retrofit considerations. Costs involved in placing a
truck in vapor-tight condition and maintaining the condition are
discussed in Section 8.2 of Chapter 8.
4.3.2 Vapor Collection System Leakage
Leakage from collection system components between the tank truck
and the vapor processing system was discussed in Section 3.2.3.2.2.
Such leaks in the collection system are minimized when inspection of
all such vapor handling equipment is included in the routine mainte-
nance program at a terminal, and faulty components are replaced or
repaired. Designing a system in order to maintain the lowest
4-3
-------
practicable working pressures will also aid in maintaining leakage
rates at minimum levels. One practical means of locating leakage
points is through a visual examination of collection system components.
This method would not be a quantitative measure of vapor leakage, but
would identify the major sources of leakage through sound, smell, or
visual appearance of fumes near a leak. A visual examination would
not require any instrumentation. Another means of leak checking
involves the use of a combustible gas detector, which can locate
smaller, less noticeable leaks.
4.4 TYPICAL COLLECTION SYSTEM
As discussed in Section 3.2, a vapor collection system consists
of all the piping and components necessary to safely transfer the
air-vapor mixture from tank trucks to a vapor processor. The three
most common pieces of equipment utilized between the loading racks and
the processor are the liquid knockout tank, the saturator tank, and
the vapor holder.
The liquid knockout tank removes liquid gasoline from the vapor
return line and stores it for subsequent recovery or disposal. Liquid
can enter the vapor line due to accidental overfilling or can form in
the line under certain ambient conditions. Of the 22 systems tested
by EPA, 7 of them utilized a liquid trap or knockout tank.
Saturator tanks contain gasoline sprays to raise the VOC vapor
concentration above the explosive range. Saturation spraying is also
used in conjunction with vapor holders and as a first stage in some
vapor processing systems. Ten of the systems tested by EPA utilized
saturation, or enrichment of the vapor stream.
Vapor holders store air-vapor mixture generated at the loading
racks until some preset capacity is reached, and then release it to
the control system for processing. Thus, fluctuations in VOC concen-
tration and volume are minimized, and the vapors are processed on a
batch basis rather than running the processor continuously. Generally,
a vapor holder consists of a large tank containing a flexible bladder
used as a level sensor. Eleven of the systems tested by EPA utilized
a vapor holder.
4-4
-------
4.5 VAPOR PROCESSING SYSTEMS
EPA-sponsored testing was performed at 22 gasoline terminals
using 6 different vapor processing approaches. The results of the
tests are summarized in Table 4-1. Daily average results are pre-
sented for the three-day tests to allow inspection of the variation of
individual control systems. Additional information on the tests,
including referenced test reports, can be found in Appendix C. The
vapor processing techniques tested during the EPA program are discussed
in the following section.
4.5.1 Description of Control Technologies
4.5.1.1 Carbon Adsorption (CA). The carbon adsorption (CA)
vapor recovery system uses beds of activated carbon to remove VOC from
the air-vapor mixture. These units generally consist of two vertically
positioned carbon beds and a carbon regeneration system. During
gasoline tank truck loading activity, one carbon bed is in the adsorbing
mode while the other bed is being regenerated. Approximately 70
g
carbon adsorption units are currently in operation at terminals.
Air-vapor mixture from the loading racks enters the base of one
of the adsorption columns and the VOC components are adsorbed onto the
activated carbon as the gases ascend. Adsorption in one carbon bed
occurs for a specific timed cycle before switch-over to desorption
occurs. The nearly saturated carbon bed is then subjected to vacuum,
steam, or thermal regeneration, or a combination of these methods, and
the VOC are stripped from the bed. Vacuum regenerated units recover
VOC by absorption in a gasoline stream which circulates between the
control unit and gasoline storage. The air and any remaining VOC
exiting from the absorber are passed again through the adsorbing bed,
and exhausted to the atmosphere. Steam-regenerated units condense the
VOC-water mixture and return the separated product to storage. Some
vacuum regenerated systems remain in operation for up to two hours
after loading activity ceases, in order to collect any residual vapors
in the system and to assure complete regeneration of the carbon beds.
Figure 4-1 shows a simplified schematic diagram of an activated carbon
vapor processor.
4-5
-------
Table 4-1. VOC EMISSION TEST DATA SUMMARY
en
Test Test
Number Date
1
2
3
4
5
6
7
8
5/25/77
5/26/77
5/27/77
3/1/78
3/2/78
3/3/78
10/24/78
10/25/78
10/26/78
11/73*
1/25/78
1/26/78
1/27/78
1/30/78
1/10/78
1/11/78
1/12/78
2/23/78
2/24/78
2/27/78
12/17/74
12/19/74
Control
Unit"
CA
CAd
CA
T0d
TO
TO
T0d
REF
Terminal
Throughput
(liters/day)
284,000
190,000
303,000
1,100,000
757,000
950,000
1,514,000
380,000
Inlet VOC
Concentration
(Percent)0
56.2
60.4
48.8
20.5
13.5
15.4
45.0
40.1
43.8
29. 2f
36.9
39.6
23.1
24.1
33.9
27.8
31.1
18.6
27.3
28.3
17.0
18.8
Outlet VOC
Concentration
( Percent) b
6.0
2.2
0.14
0.18
0.30
0.33
0.83
0.83
3.7
0.002f
0.06
0.03
0.02
0.02
0.004
0.005
0.008
1.7
0.7
0.8
3.4
3.6
Processor
VOC
Emissions
(mg/mer)
64.2
5.4
2.7
1.2
2.1
2.5
10.8
9.6
63.4
1.0
77.6
36.7
32.8
24.2
21.4
22.4
39.8
23.7
7.5
10.3
33.3
39.4
Total
System
Emissions
(mg/1 Iter)
374
378
285
133
74.4
129
26.6
17.7
63.4
176
297
205
103
97.3
78.9
91.7
154.9
93.3
110
133
134
174
Adjusted0
Processor
Emissions
(mg/1 Iter)
92.6
8.5
3.9
1.8
2.8
3.9
11.0
9.7
63.4
1.4
107
47.3
39.0
28.6
24.7
27.0
50.9
29.4
9.3
13.2
44.0
54.4
Control
Efficiency
(Percent)
90.9
99.2
99.6
99.5
99.0
98.9
98.6
98.8
92.6
99.8
86.6
93.7
91.1
94.0
93.6
93.2
90.3
90.0
98.2
97.7
89.4
88.9
-------
Table 4-1. VOC EMISSION TEST DATA SUMMARY (Continued)
Test Test Control
Number Date Unit0
9/20/76
9 9/21/76 REF
9/22/74
11/10/76
10 11/11/76 REF
11/12/76
8/22/78
11 8/23/78 REF
8/24/78
9/26/78
12 9/27/78 REF
9/28/78
10/10/78
13 10/11/78 REF
10/12/78
14 12/11/74 rRAd
14 12/12/74 LKW
9/23/77 A
15 9/24/77 CRA°
9/25/77
2/20/78 .
16 2/21/78 CRAa
3/8/78
3/9/78
Terminal
Throughput
(liters/day)
1 ,430,000
810,000
9
1,514.000
1.514,000
600,000
1,190,000
9
Inlet VOC
Concentration
(Percent)0
35.6
50.6
50.9
23.7
17.8
13.3
NAh
88.2
75.2
31.7
30.0
39.8
47.9
52.4
51.8
18.2
21.5
48.8
38,9
NAh
29.3
31.2
28.7
27.1
Outlet VOC
Concentration
(Percent)0
4.8
4.7
3.6
3.6
3.3
3.3
56.8
29.8
38.4
5.3
6.2
4.9
3.2
3.1
3.5
4.7
4.3
3.9
3.4
3.2
5.3
6.1
5.3
5.3
Processor
VOC
Emissions
(mg/Hter)
51.6
52.3
29.9
49.1
57.1
54.2
1318
841
794
67.2
103
61.9
J
j
j
31.0
31.6
30.7
30.5
NAh
61.2
59.5
57.2
Total
System
Emissions,
(mg/Hter)
254
107
52.1
173
67.3
87.4
1318
841
794
142
103
134
j
j
j
141
141
314
214
NAR
NAh
225
NA"
NAh
Adjusted0
Processor
Emissions
(mg/Hter)
72.2
58.1
31.1
61.9
58.8
61.8
1318
841
794
75.9
103
68.1
j
j
j
73.5
57.2
44.5
47..0
NAh
NA*
88.1
NAP
NAh
Control
Efficiency
(Percent)
89.8
89.4
94.6
86.7
83.2
77.1
44.3
63.3
62.2
88.3
86.1
90.6
j
j
j
61.4
76.7
95.1
91.0
NA"
NAh
83.5
NAh
NAh
-------
Table 4-1. VOC EMISSION TEST DATA SUMMARY (Concluded)
00
Processor Total
Terminal Inlet VOC Outlet VOC VOC System
Test Test Control Throughput Concentration Concentration Emissions Emissions
Number Date U«1ta (liters/day) (Percent)0 (Percent)6 (rag/liter) (mg/llter)
17
18
19
20
21
22
5/2/78 d
5/3/78 CRA° 1,000.000
5/4/78
8/2/78 rt
8/3/78 CRA 1,514,000
8/4/78
9/21/78 CRAd 9
3/6/78 r,fd fi 1
3/7/78 LKC 5,6/8,000
8/16/78 .
8/17/78 CRC° 9
8/18/78
4/11/78
4/12/78 LOA 1,514.000
4/13/78
17.0
30.6
23.2
35.5
37.6
45.0
56.6
22.1
38.4
64.8
75.6
59.7
29.3
29.0
28.3
2.5
2.5
2.5
3.6
3.8
4.1
3.6
3.4
3.8
11.9
12.9
13.6
9.2
5.3
9.2
40.9
45.1
35.9
32.2
43.1
43.0
85.9
41.0
44.4
j
j
j
97.0
52.9
86.7
255
179
138
180
371
232
149
108
180
j
j
j
225
195
225
Adjusted0
Processor
Emissions
(mg/llter)
78.5
58.2
52.1
41.5
65.1
52.9
91.0
48.4
55.9
j
j
j
130
73.0
119
Control
Efficiency
(Percent)
82.4
90.2
84.2
93.7
93.3
94.8
91.8
89.0
91.5
j
j
j
74.1
85.9
76.7
-------
NOTES —Table 4-1
a CA - Carbon Adsorption
TO - Thermal Oxidation
REF - Refrigeration
CRA - Compression-Refrigeration-Absorption
CRC - Compression-Refrigeration-Condensation
LOA - Lean Oil Absorption
Volume percent as propane, except as noted.
cTotal VOC emissions from processor (control unit) adjusted to account
for tank truck leakage.
Vapor holder used.
eTesting performed for nearly six months; no daily averages reported
(see Section C.2 of Appendix C).
Volume percent as methane.
Requested to be kept confidential.
Parameter not calculated due to lack of necessary test data.
Four terminals combined in complex.
Not calculated due to unknown quantity of leakage from vapor collection
system.
4-9
-------
o
Air
Exhaust
Air-Vapor.*.
Mixture
Cooler
Thermal
Purge
t .Water
Steam Supply
or
Vacuum Pump
Separator
Air-Vapor Recycle
•Recovered
Product
Figure 4-1. Schematic Diagram of a Carbon Adsorption System (CA)
-------
Vapor processor outlet daily average mass emissions, adjusted for
collection system leakage, ranged from 1.8 mg/liter to 92.6 mg/liter,
for an average mass emission level in the three tests of 22.0 mg/liter.
Two days of system operation have been omitted in the evaluation of
the performance of the carbon adsorption system. On the first day of
Test No. 1, the bed switching timer was incorrectly set, leading to
breakthrough on one bed. On the third day of Test No. 3, two tank
trucks were purposely loaded simultaneously, a departure from the
terminal's standard practice and over the design capacity for this
particular unit, in order to determine the effect of this on mass
emissions. Both of these instances are deviations from the normal
operation of the system, and so the measured emissions on these
days are not considered representative of the system's performance.
Daily average adjusted mass emissions on the remaining seven days of
testing ranged from 1.8 to 11.0 mg/liter, for an average of 5.9 mg/liter.
These tests were performed on the vacuum-regenerated type of CA unit,
which is the only type currently in commercial operation at bulk
gasoline terminals. Section C.I.2 of Appendix C discusses the tests
further.
4.5.1.2 Thermal Oxidation (TO). The thermal oxidation (TO)
control unit relies on burning VOC vapors (using a pilot flame) to
produce non-polluting combustion products. In this system no gasoline
is recovered. Approximately 40 thermal oxidizer units are currently
being used at terminals.10'11'12
Vapors from the loading racks are piped either to a vapor holder
or directly to the oxidizer unit. When a vapor holder is used, opera-
tion of the oxidizer begins when the holder reaches a preset level,
and ends when the holder is empty. With no vapor holder in the system,
the oxidizer is energized by means of pressure in a vapor line, indi-
cating that tank truck loading is in progress, or by an electrical
signal produced by a manual activation at the loading rack. In some
cases propane is injected into the vapor stream to keep the VOC level
above the explosive range.
When gasoline dispensing equipment at the racks is activated, the
combustion air fan starts and purges the combustion chamber of any
remaining combustible vapors. After the purge period the pilot fuel
4-11
-------
(usually propane) is admitted and a spark igniter lights the pilot
flame. Approximately one minute after fan activation the vapors are
admitted to the oxidizer chamber. On some units the pilot flame is
activated only long enough to ignite the combustible vapors, while on
others the pilot flame burns continuously during the vapor combustion
process. Combustion air is admitted to the unit by means of an adjustable
damper which is controlled by temperature. As the temperature in the
combustion chamber rises, the damper is opened to admit more air.
Normal operating temperature in the chamber is approximately 760°C
(1400°F).
Other equipment included in TO systems are flame arresters to
prevent flashback from the unit to the loading area, and in some later
models an isolating valve to prevent vapor flow under low pressure
conditions. Figure 4-2 shows a simplified schematic diagram.
Thermal oxidizer units have the advantages of low capital cost,
simplicity of design, and high processing efficiency. A disadvantage
is that they do not recover gasoline vapors as liquid product. Processor
outlet daily average mass emissions in four tests, adjusted for system
leakage, ranged from 1.4 mg/liter to 107 mg/liter, for an average of
34.3 mg/liter. Daily average adjusted mass emissions measured in
systems with no vapor holder ranged from 24.7 to 107 mg/liter, for an
average of 46.4mg/l. Adjusted emissions from systems incorporating a
vapor holder ranged from 1.4 to 29.4 mg/liter, averaging 13.3 mg/liter.
Section C.I.2 of Appendix C discusses the thermal oxidation tests
further.
Some recently developed control systems consist of a
compression-aftercooler stage to recover most of the displaced vapors
as liquid gasoline, followed by a thermal oxidation stage to reduce
VOC emissions to within the required level. Test data are not available
to permit an evaluation of this control technology; however, a small
number of these systems are operating at bulk terminals. They provide
one option for recovering some product while achieving the high control
efficiency of the thermal oxidation approach.
4.5.1.3 Refrigeration (REF). Refrigeration type recovery units
(REF) remove VOC from an air-vapor mixture by straight refrigeration
4-12
-------
Air-Vapor _>.
Mixture
A
Vapor
Holder
I
I
I
Air
Exhaust
Combustion
Chamber
Pilot
Fuel
Damper
Air
Figure 4-2. Schematic Diagram of a Thermal Oxidizer System (TO)
(Dotted Lines Indicate Optional Equipment)
-------
at atmospheric pressure. It is estimated that there are 130 units
of this type in commercial operation at gasoline terminals. '
In older units, vapors displaced from tank trucks enter a condenser
section where methylene chloride "brine" is pumped through the finned-
tube sections of a heat exchanger. Brine temperature in this section
ranges from -62°C to -82°C (-80°F to -115°F). Some units contain a
precooler section (glycol and water solution circulating at 1.1°C
(34°F)) to remove most of the water from the gases prior to the main
condenser. There are no compression stages in this type of unit. The
condensed product is collected and pumped to one of the product storage
tanks. The cold collection surfaces are periodically defrosted by
pumping warm.(32°C or 90°F) trichlorethylene through the condenser.
This defrost fluid is kept warm by heat salvaged from the refrigeration
equipment. Recovered water passes to a waste storage tank or gasoline-
water separator. The defrost cycle takes from 15 to 60 minutes,
depending on the amount of ice accumulated on the finned tubes.
On many refrigeration units the defrost cycle is performed during
periods of no loading activity since the unit cannot collect VOC
during the defrost cycle. Some units, however, contain a double set
of heat recovery and low temperature coils over which the vapor is
alternately passed. This is accomplished using a switch-over damper
to divert the flow to one or the other set of coils. Thus one set is
collecting VOC while the other set is defrosting. This means that the
unit can operate continuously with no downtime for defrosting. Newer
refrigeration units use direct expansion to refrigerate the condenser
coil collection surfaces, thus eliminating the chilled brine. Figure 4-3
shows a simplified schematic diagram of the refrigeration control unit
tested by EPA.
Acceptable recovery efficiencies for the refrigeration system are
dependent on the unit maintaining the necessary -68°C to -84°C (-90°F
to -120°F) brine temperature in the condenser recovery section. This
in turn depends on assuring that the fluid levels remain at proper
operating capacities by maintaining the system in a leak-free condition.
In addition, defrost cycles must be coordinated with tank truck loading
activities so that the condenser elements are always at or near the
4-14
-------
Air-Vapor_>.
Mixture
en
Precooler
Waste
Water
Condenser
Section
Air
Exhaust
Chilled
Brine
Defrost
Fluid
.Recovered
Product
Cold
Refrigeration
Unit
Warm
Figure 4-3. Schematic Diagram of a Refrigeration System (REF)
-------
design temperature during vapor collection. The units employing a
switch-over damper, when operating properly, are not subject to concern
over defrost scheduling.
In one of the six EPA-sponsored tests involving refrigeration
type vapor recovery units (Test No. 11), the measured emissions were
unusually high compared to those from other REF tests, as a result of
problems with the test equipment and the recovery unit itself. In
another REF test (Test No. 13), serious leakage of air-vapor mixture
from the vapor collection system caused almost half of the mixture to
escape to the atmosphere before reaching the recovery unit. Data from
these two tests were not included in the REF system performance evaluation.
Daily average VOC emissions in the four remaining tests (Test Nos. 8,
9, 10, and 12), adjusted for tank truck leakage, ranged from 31.1 to
103 mg/liter. The control efficiency of the processor in these four
tests ranged from 77.1 to 94.6 percent. During two tests (Test Nos. 8
and 9), the refrigeration equipment was not maintaining the low temperatures
required for efficient vapor collection because of system refrigerant loss.
In one test on a refrigeration type vapor processor performed by a local
regulatory agency in California, adjusted mass emissions were 14 mg/liter.
Three additional California tests on direct expansion type systems measured
outlet mass emissions of 5 mg/liter, 36 mg/liter, and 48 mg/liter.
Sections C.I.2 and C.I.3 of Appendix C discuss these tests further.
These test results reflect the ability of properly maintained and
operated refrigeration type vapor processors to achieve 80 mg/liter,
and the data indicate that the newer models can achieve emission rates
considerably lower than 80 mg/liter.
4.5.1.4 Compression-Refrigeration-Absorption (CRA). In a
compression-refrigeration-absorption (CRA) vapor recovery unit,
the vapors from the loading racks are first passed through a
saturator which sprays liquid gasoline into the air-vapor gas stream. '
This ensures that the VOC concentration is above the explosive range.
The saturated gas mixture is stored in a vapor holder, until at a pre-
set level it is released to the control unit. The vapor holder is
usually a special tank containing a bladder with variable volume and
constant pressure. A gasoline storage tank with a lifter roof can
4-16
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also function in this capacity. Approximately 100 CRA units are
15
currently being used in gasoline terminals.
The first stage of processing is a compression-refrigeration
cycle in which water and heavy VOC are compressed, cooled, and condensed,
The uncondensed vapors move into a packed absorber column where they
are contacted by chilled gasoline (4°C or 39°F) drawn from product
storage, and absorbed. The fresh gasoline stream is used first in the
saturator, then it passes through an economizing heat exchanger as it
enters the absorber. The rich absorbent also passes through the heat
exchanger before being pumped back to storage. The operation of the
control system is intermittent, starting when the vapor holder is
filled and stopping when it has emptied. Cleaned gases are vented
from the absorber column to atmosphere. A simplified schematic diagram
of a typical CRA control unit is shown in Figure 4-4.
The results of EPA-sponsored tests on CRA units at bulk terminals
indicate that these units are capable of achieving a VOC emission
level below 80 mg/liter. Daily average mass emissions, adjusted for
system leakage, in six tests ranged from 41.5 mg/liter to 91.0 mg/liter,
for an average of 62.5 mg/liter. No test data were omitted in the
evaluation of this control technique because there were no serious
testing irregularities or equipment malfunctions reported during the
tests. Section C.I.2 of Appendix C discusses these tests further.
4.5.1.5 Compression-Refrigeration-Condensation (CRC). A vapor
recovery system employing a compression-refrigeration-condensation
(CRC) unit makes use of a vapor holder to store accumulated air-vapor
mixture, and a saturator for ensuring that the VOC concentration is
above the explosive range. The unit is activated and begins processing
vapors when the vapor holder has filled to a preset level.
Incoming saturated air-vapor mixture is first compressed in a
two-stage compressor with an intercooler. Condensate is withdrawn
from the intercooler prior to compression in the second stage. The
compressed vapors then pass through a refrigeration-condenser section
where they are returned along with the intercooler condensate to a
gasoline storage tank. Cleaned gases are exhausted from the top of
the condenser. Figure 4-5 shows a simplified schematic diagram of a
4-17
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Air-Vapor —
Mixture from
Vapor Holder
I
_j
00
Compression
Stages
Heat ^<
Exchanger
Air
Exhaust
Absorber
->_ Recovered
Product
I r-
Lh
Ll.
Refrigeration
Unit
Heat
Exchanger
<__ Gasoline
Supply
Figure 4-4. Schematic Diagram of a Compression-Refrigeration-Absorption System (CRA)
-------
Air
Exhaust
Air-Vapor —>
Mixture from
Vapor Holder
Compression
Stages
Condenser/ \\
Separator ||
Saturator
1
Refrigeration
Unit
Recovered
Product
Gasoline
Supply
Figure 4-5. Schematic Diagram of a Compression-Refrigeration-Condensation System (CRC)
-------
CRC control unit. Based upon 114 letter responses, it was estimated
that there were approximately 40 CRC units currently used to control
VOC emissions at terminals.
Two EPA-sponsored tests were performed at terminals employing CRC
units. At one terminal, air-vapor leakage from the vapor holder could
not be determined; therefore, the adjusted emissions could not be
calculated (Test No. 21). The daily average adjusted VOC emissions
for Test No. 20 were 48.4 and 55.9 mg/liter, for an average of 52.2 mg/
liter. Section C.I.2 of Appendix C discusses these tests further.
4.5.1.6 Lean Oil Absorption (LOA). The lean oil absorption unit
(LOA) relies on the absorption of the vapors released by tank truck
loading-("light ends") in lean oil, which may be No. 2 diesel oil
or gasoline from which the light ends have been previously removed.
In this unit, vapors enter the base of an absorber column and create
a pressure differential (AP) across an orifice mounted at the inlet.
The AP creates a signal proportional to the vapor flow rate, which
starts a lean oil pump and controls the amount of lean oil pumped from
storage to the column. Cooled lean oil absorbs VOC vapors in the
packed absorber column. In one type of unit the enriched gasoline
(used lean oil) is returned directly to a gasoline storage tank.
Another LOA unit uses heat and pressure to regenerate and re-use
the lean oil, returning the removed gasoline vapors to storage.
Cleaned air-vapor mixture is exhausted from the LOA control unit
to atmosphere.
Lean oil for one type of unit is produced independently by heating
gasoline in order to evaporate off the light ends. This lean oil is
then cooled and stored in an insulated tank. Figure 4-6 shows a simplified
schematic diagram of this type of LOA control unit.
Adjusted daily average mass emissions in the single efficiency
test performed by EPA on a lean oil absorption control unit range from
73.0 mg/liter to 130 mg/liter, for an average of 107 mg/liter.
Section C.I.2 of Appendix C discusses this test further.
The lean oil absorption type unit is not in widespread use at
bulk terminals, and oil companies have indicated a tendency toward
replacing these units with other types of control systems. Generally,
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Air
Exhaust
Air-Vapor
Mixture
Absorbej
Lean Oil
Storage
Cooler
Lean Oil
Production
Gasoline
Supply
Light ends
to Storage
Recovered
Product
Figure 4-6. Schematic Diagram of a Lean Oil Absorption System (LOA)
-------
unsatisfactory performance has been given as the reason for the move
away from LOA units.
4.5.2 Operation and Maintenance Practices
The vapor processors designed for VOC control at bulk gasoline
terminals require regular maintenance attention in order to consis-
tently achieve the emission limit for which they are designed. Proper
maintenance for these units generally includes frequent (at least
daily) visual inspections in order to monitor component operation,
fluid levels, warning lights, pressures, temperatures, presence of
leaks, and other miscellaneous items. Manufacturers frequently supply
inspection checklists to facilitate these routine checks, and some
terminals have developed individual lists for their own use. Most
terminals incorporate such inspections into the normal duties of their
maintenance personnel, which include routine checks of loading racks,
storage tanks, pumps, and other terminal equipment. Of course, the
inspections themselves do not maintain the proper operation of vapor
processors, but any necessary repairs indicated through atypical
readings, sounds, etc., can be implemented rapidly to minimize
downtime.
Each type of vapor processor has different maintenance
requirements due to varying system size and complexity, types of
components, and operating time and sequencing. Refrigeration systems
require daily checks of several subsystems and components. Defrost
system pump pressure, as well as fluid levels and temperatures, should
be checked regularly. Oil levels, pressures, and temperatures in the
precooler and refrigeration systems require regular inspection.
Liquid recovery meters and condenser coil temperature records on some
units indicate the level of performance of the units. Maintenance on
carbon adsorption sytems includes checks of cycle timing and bed
vacuum and temperatures. Elapsed system operation time meters on some
systems provide an indication of proper system operation and can
indicate maintenance intervals. Maintenance of thermal oxidation
systems may include daily observation of the activation sequence and
inspection of pilots and burners. Sight ports are generally provided
so that the condition of the flame can be observed. Vapor holders in
4-22
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these systems should be frequently inspected for leaks, and the high
and low level switches checked for proper operation. All vapor
processors are provided with indicator panels to warn of malfunctions,
and most have automatic shutdown or interlock systems. These systems
provide automatic indication that maintenance attention may be required.
The annual costs to maintain vapor processing systems, including
routine inspections and the expected typical repair costs, have been
considered in determining the cost impact on affected terminals
(Section 8.2.2.2 of Chapter 8).
4.6 EMISSIONS DUE TO GASOHOL LOADING
The single most important problem confronting control of VOC when
gasohol is used as fuel instead of gasoline is increased vapor pressure.
An RVP increase from 8.7 psia to 9.8 psia by the addition of 10 percent
by volume of ethanol to gasoline is a vapor pressure increase of
12.5 percent. Assuming ideal saturated vapors at 100°F, the VOC
content would be 59 volume percent in the vapor space of a gasoline
tank and 67 volume percent in a tank containing gasohol. Thus, VOC
concentrations entering vapor control systems would be higher for
gasohol because of the increased vapor pressure of the fuel. To
maintain the status quo with respect to VOC emissions from gasoline
marketing, maintenance activities could be increased to minimize leaks
from vapor handling and transfer equipment.
Ethanol is known to increase the rate of gum formation in blends
during storage, so that these blends may loosen existing gum-bound
deposits of rust and other sediment. When existing fuel handling
systems are first converted from gasoline to an alcohol blend, certain
operational problems may arise. These problems are expected to diminish
with continued use of gasohol.
The specific effects of gasohol on the operation and efficiency
of either a carbon adsorption or a refrigeration system have not been
ascertained. Some factors which may have an effect on the performance
of these control systems include:
The heat of vaporization is substantially higher for
ethanol than for the other hydrocarbons. This may result
4-23
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in some localized heating when ethanol is adsorbed,
serving to desorb some of the hydrocarbons prematurely.
• If some water is present in the gasohol, phase separation
may occur. In a refrigeration system this ethanol/water
phase may be subject to freezing.
• Over twice as much heat removal is required to condense
ethanol as compared to other gasoline components.
At best, there is presently only scattered data in the literature.
Pilot testing by control equipment manufacturers has not yet been
initiated. However, several manufacturers have stated that gasohol
vapors should not have a significant impact on the operating efficiency
17 18 1Q 20 21 22
of the vapor processing systems. /'i°'iy'<;u'1"i
4-24
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4.7 REFERENCES
1. 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. 76-6AS-17. September 1976. p. 2.
2. Norton, R.L. Evaluation of Vapor Leaks and Development of Monitoring
Procedures for Gasoline Tank Trucks and Vapor Piping. U.S.
Environmental Protection Agency. Research Triangle Park, N.C.
Publication No. EPA-450/3-79-018. April 1979. 94 p.
3. Scott Environmental Technology. Leak Testing of Gasoline Tank Trucks.
U.S. Environmental Protection Agency. Research Triangle Park, N.C.
Contract No. 68-02-2813. August 1978 (Draft).
4. Shedd, S.A., and N.D. McLaughlin. Control of Volatile Organic
Compound Leaks from Gasoline Tank Trucks and Vapor Collection
Systems. U.S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-450/2-78-051. December 1978.
30 p.
5. Ref. 2, p. 3-10.
6. Ref. 3, p. 6.
7- Ref. 2, p. 3-12.
8. Hang, J.C., and R.R. Sakaida. Survey of Gasoline Tank Trucks and
Rail Cars. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/3-79-004. March
1979. 41 p.
9. Letter and attachments from Anderson, S. L., Anderson & Zirkle,
representing McGill, Inc., to Farmer, J.R., Environmental Protection
Agency. December 4, 1979. Comments on Draft BID dated February 1980.
10. Telecon. Kirkland, John, Hirt Combustion Engineers, with LaFlam,
Greg, Pacific Environmental Services, Inc. October 18, 1979.
Thermal oxidizer unit operating information.
11. Telecon. Guischard, Chuck, AER Corporation, with LaFlam, Greg,
Pacific Environmental Services, Inc. October 8, 1979. Thermal
oxidizer unit operating information.
12. Telecon. Bitterlich, Gordon, National AirOil Burner Company, Inc.,
with LaFlam, Greg, Pacific Environmental Services, Inc. October
18,-1979. Thermal oxidizer unit operating information.
4-25
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13. Telecon. Edwards, Ray, Edwards Engineering Corporation, with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
July 2, 1979. Refrigeration unit equipment costs and operating
information.
14. Telecon. Gardner, Frank, Tenney Engineering, Incorporated with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
July 2, 1979. Refrigeration unit equipment costs and operating
information.
15. Telecon. Sasseen, Ken, Trico-Superior, with LaFlam, Greg, Pacific
Environmental Services, Inc. January 18, 1980. Information on
compression-refrigeration-absorption systems.
16. Keller, J.L. Alcohols as Motor Fuel. Hydrocarbon Processing.
58(5). May 1979.
17. Telecon. Beall, F.J., Texaco Oil Company, with LaFlam, Greg,
'Pacific Environmental Services, Inc. April 7, 1980. Gasohol
marketing information.
18. Telecon. Buxton, Doug, HydroTech Engineering (McGill), Inc.,
with LaFlam, Greg, Pacific Environmental Services, Inc.
March 11, 1980. Effect of gasohol on HydroTech unit.
19. Telecon. Guischard, Chuck, AER Corporation, with LaFlam, Greg,
Pacific Environmental Services, Inc. February 27, 1980. Effect
of gasohol on AER thermal oxidizer.
20. Telecon. Gardner, Frank, Tenney Engineering, Inc., with
LaFlam, Greg, Pacific Environmental Services, Inc. February 26,
1980. Effect of gasohol on Tenney refrigeration unit.
21. Telecon. Bitterlich, Gordon, National Air Oil Burner Company,
with LaFlam, Greg, Pacific Environmental Services, Incorporated.
March 5, 1980. Effect of gasohol on NAOB oxidizer.
22. Telecon. Edwards, Ray, Edwards Engineering Corporation, with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
March 10, 1980. Effect of gasohol on Edwards refrigeration
unit.
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5.0 MODIFICATION AND RECONSTRUCTION
In accordance with Section 111 of the Clean Air Act, as amended
in 1977, standards of performance must be established for new sources
within a stationary source category which "... may contribute signifi-
cantly to air pollution ...." Standards apply to operations or
apparatus (facilities) within a stationary source, selected as
"affected facilities;" that is, facilities for which applicable
standards of performance have been promulgated and the construction or
modification of which commenced after the proposal of the standards.
On December 16, 1975, the Agency promulgated amendments to the
general provisions of 40 CFR Part 60, which included revisions to
clarify the terms "modification" and "reconstruction." Under the
provisions of 40 CFR 60.14 and 60.15, an "existing facility" may
become subject to standards of performance if deemed modified or
reconstructed. An "existing facility," defined in 40 CFR 60.2, is an
apparatus of the type for which a standard of performance is promul-
gated and the construction or modification of which was commenced
before the date of proposal of that standard. The following
discussion examines the applicability of these provisions to bulk
gasoline terminals and details conditions under which existing
facilities could become subject to standards of performance. It is
important to stress that since standards of performance apply to
affected facilities which, combined with existing and other
facilities, comprise a stationary source, the addition of an affected
facility to a stationary source through any mechanism (new construc-
tion, modification, or reconstruction) does not make the entire
stationary source subject to standards of performance, only the added
affected facility.
5-1
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5,1 40 CFR PART 60 PROVISIONS FOR MODIFICATION AND RECONSTRUCTION
5.1.1 Modification
It is important that these provisions be fully understood prior
to investigating their applicability.
Modification is defined in §60.14 as follows:
Except as provided under paragraphs (e) and (f) of this
section, any physical or operational change to an existing
facility which results in an increase in emission rate to
the atmosphere of any pollutant to which a standard applies
shall be considered a modification within the meaning of
Section 111 of the Act. Upon modification, an existing
facility shall become an affected facility for each pollutant
to which a standard applies and for which there is an increase
in the emission rate to the atmosphere.
Paragraph (e) lists certain physical or operational changes which
will not be considered modifications, irrespective of any change in
the emission rate. These changes include:
1. Routine maintenance, repair, and replacement,
2. An increase in the production rate not requiring a capital
expenditure as defined in §60.2,
3. An increase in the hours of operation,
4. Use of an alternative fuel or raw material if, prior to the
standard, the existing facility was designed to accommodate that
alternate fuel or raw material,
5. The addition or use of any system or device whose primary
furction is the reduction of air pollutants, except when an emission
control system is removed or replaced by a system considered to be
less environmentally beneficial.
Paragraph (b) clarifies what constitutes an increase in emissions
in kilograms per hour and the methods for determining the increase,
including the use of emission factors, material balances, continuous
monitoring systems, and manual emission tests. Paragraph (c) affirms
that the addition of an affected facility to a stationary source does
not make any other facility within that source subject to standards of
performance. Paragraph (f) simply provides for superseding any con-
flicting provisions. Paragraph (g) stipulates that compliance with
al"1 applicable standards will be achieved within 180 days of the
coi pletion of any modification.
5-2
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5.1.2 Reconstruction
Reconstruction is defined in §60.15 as follows:
"Reconstruction" means the replacement of components of
an existing facility to such an extent that: (1) the fixed
capital cost of the new component exceeds 50 percent of the
fixed capital cost that would be required to construct a
comparable entirely new facility, and (2) it is technologi-
cally and economically feasible to meet the applicable
standards set forth in this part.
When the replacement of components has reached the 50 percent
level, the source is identified for consideration as a reconstructed
source. The Administrator determines whether the replacement con-
stitutes reconstruction. If so, the source becomes an affected
facility irrespective of any change in emissions.
As stated in §60.15(f), the Administrator's determination of
reconstruction will be based on:
(1) The fixed capital cost that would be required to
construct a comparable new facility; (2) the estimated life
of the facility after the replacements compared to the life
of a comparable entirely new facility; (3) the extent to
which the components being replaced cause or contribute to
the emissions from the facility; and (4) any economic or
technical limitations on compliance with applicable stan-
dards of performance which are inherent in the proposed
replacements.
The purpose of the reconstruction provision is to ensure that an
owner or operator does not perpetuate an existing facility by replacing
all but minor components, support structures, frames, housing, etc.,
rather than totally replacing it in order to avoid being subject to
applicable standards of performance.
5.2 APPLICABILITY TO BULK GASOLINE TERMINALS
5.2.1 Modification
Investigation of the bulk gasoline terminal industry has shown
that there are several changes, either physical or operational, appli-
cable to the affected facility which might qualify as a modification.
There are, also, potential actions which may result in an increase in
emissions from the bulk gasoline loading operations but might not be
considered modification to existing gasoline loading racks.
5-3
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5.2.1.1 Equipment Relocation and Change in Ownership. The
relocation of an existing loading facility within the terminal would
not constitute a modification. This would require the use of essentially
all the same components of the existing rack at the new location.
Change in ownership of an existing bulk gasoline terminal would not
cause the facility to become an affected facility under the NSPS.
5.2.1.2 Removal or Disabling of a Control Device. The intentional
removal or disabling of an emission control device servicing an existing
gasoline loading operation would be considered a modification. This
includes the replacement of an existing control device with one that
is less environmentally beneficial (§60.14(e)(5)).
5.2.1.3 Addition of a Vapor Recovery System. The addition or
use of any system or device whose primary function is the reduction of
air pollutants is not, by itself, considered a modification under
§60.14. For example, the addition of a vapor processing unit to
control VOC emissions from gasoline loading operations at a terminal
would not be considered a modification under §60.14(e)(5).
5.2.1.4 Addition or Expansion of Loading Racks. An increase in
throughput without a capital expenditure does not constitute a modification
under §60.14(e)(2). A capital expenditure, as defined in §60.2, means
an expenditure for a physical or operational change to an existing
facility which exceeds the product of the applicable "annual asset
guideline repair allowable percentage" specified in the latest edition
of Internal Revenue Service Publication 534 and the existing facility's
basis, as defined by Section 1012 of the Internal Revenue Code.
The addition or expansion of loading racks is normally done at
the terminal to accommodate new products, to allow for greater through-
put of existing products, or to ease traffic delays during peak loading
periods. The accommodation of new products and the increase in
throughput of existing products could increase emissions at the loading
racks. Since the additions and expansions to the loading racks would
most likely be considered a capital expenditure, the additions and
expansions might constitute a modification.
In some cases, the overall daily throughput may not change due to
rack expansions. However, the peak hourly loading rate may increase
because more trucks are able to load at one time. In these cases, the
5-4
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hourly emissions would increase. Since this throughput and emissions
increase would be coupled with a capital expenditure, these additions or
expansions might constitute a modification.
5.2.1.5 Loading Rack Conversions. Gasoline loading rack conversions
might be considered a modification if emissions increased. This type
of conversion could include top-to-bottom loading conversions if the
throughput were to increase enough to offset the emission reduction
expected from the change to bottom loading. The top-to-bottom loading
conversion would be considered a capital expenditure; therefore, the
increase in throughput coupled with an increase in emissions would not
be exempt from modification under §60.14(e)(2).
5.2.2 Reconstruction
A facility is considered, under §60.15, for reconstruction
determination when the fixed capital cost of the alteration exceeds
50 percent of the fixed capital cost required to construct an entirely
new facility. Once the facility has been identified for consideration,
it is up to the Administrator to review the information and determine
if the facility alteration constitutes a reconstruction (§60.15(e)).
An existing facility, upon reconstruction, becomes an affected facility
regardless of any change in the emission rate.
5.2.2.1 Top-to-Bottom Loading Conversions. Top loading to
bottom loading conversions will normally exceed the 50 percent cost to
construct an entirely new loading rack; therefore, the facility would
become eligible for reconstruction assessment. Top loading to bottom
loading conversions have been performed both with and without accompanying
vapor recovery installations. Projects have also included top loading
vapor recovery system conversions to bottom loading vapor recovery
1 2
systems. ' The Administrator would determine on a case-by-case basis
whether these conversions would constitute a reconstruction. The
extent to which the components being replaced contribute to the facility
emissions is taken into account by the Administrator in the determination
of reconstruction (§60.15(f)(3)).
The 50 percent capital cost figure for reconstruction is considered
on a cumulative basis. This is independent of the time span required
to complete the reconstruction projects.
5-5
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5.2.2.2 Replacement and Repair of Loading Rack Equipment. A
facility is identified for reconstruction determination when the fixed
capital cost of the replacement items or required repairs exceed 50
percent of the fixed capital cost of constructing an entirely new
facility.
Replacement or unscheduled major repairs of loading rack equipment,
such as loading arms, pumps, or meters, may not by themselves exceed
the 50 percent replacement cost of a new facility. However, since the
50 percent replacement cost is a cumulative figure, these unscheduled
major repairs and replacements would be included in reaching the 50
percent criterion.
Normal maintenance items, however, are not included in the
determination of the 50 percent replacement cost criterion. Items
which would require normal scheduled repairs would include pump seals,
meter calibrations, loading arm gaskets and swivels, coupler gaskets,
and overfill sensors. Items which typically require scheduled
replacement under a normal maintenance program would include vapor
3 4
hoses and grounding cables at the loading rack. '
5-6
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5.3 REFERENCES
1. Letter and attachments from Ada, A.E., Exxon Company, U.S.A.,
to Goodwin, D.R., EPA. September 5, 1979. Response to Section 114
letter on bulk gasoline terminal industry trends.
2. Letter and attachments from Bond, F.K., ARCO Petroleum Products
Company, to Goodwin, D.R., EPA. July 6, 1979. Response to
Section 114 letter on bulk gasoline terminal industry trends.
3. Letter and attachments from Crane, R.E., Triangle Refineries,
Inc., to Goodwin, D.R., EPA. June 18, 1979. Response to
Section 114 letter on bulk gasoline terminals.
4. Letter and attachments from Hooper, L.R., Marathon Oil Company,
to Goodwin, D.R., EPA. July 13, 1979. Response to Section 114
letter on bulk gasoline terminals.
5-7
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6.0 MODEL PLANT PARAMETERS AND REGULATORY ALTERNATIVES
6.1 INTRODUCTION
This chapter defines model bulk gasoline terminals and alternative
approaches considered for regulating VOC emissions from bulk gasoline
terminals. The model plant parameters were selected to represent the
range of new and existing bulk gasoline terminals and provide a basis
for comparison of environmental and economic impacts of the regulatory
alternatives. The selected alternatives provide for varying limits of
control for VOC emissions from the gasoline loading operations.
In order to characterize the for-hire tank truck industry and to
determine the economic impact of the regulatory alternatives on this
vital segment of the gasoline distribution system, model firm param-
eters were also developed for the motor carrier companies delivering
gasoline from bulk terminals. These parameters were selected to
represent the existing range of company sizes.
6.2 MODEL PLANT PARAMETERS
The process for selecting the model plant parameters for bulk
terminals involved defining a bulk gasoline terminal, designating an
affected facility, and finally selecting the model plant parameters.
The data base for determination of the model plant parameters was
derived from operating data on 40 terminals of various sizes and ages.
Parameters for the for-hire motor carrier company model firms were
determined using the most recent industry reports and census data.
6.2.1 Definition of a Bulk Gasoline Terminal
A bulk terminal is generally any wholesale marketing facility
which receives refined petroleum products from an outside source,
stores them in aboveground tanks, and delivers them in tank trucks to
customers. Two criteria were considered in arriving at the definition
of bulk gasoline terminal utilized in this report. The first involves
the terminal's gasoline throughput, and the second involves the mode
6-1
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of delivery of gasoline to the terminal. Throughput is variable for a
given facility and could lead, in the case of smaller facilities, to a
shifting definition status based on business volume. The mode of
delivery criterion would define a terminal as any wholesale marketing
outlet which receives product by pipeline, ship, or barge. This
definition would distinguish terminals from bulk plants since the bulk
plants receive product almost exclusively by truck. Rail car deliveries
were not included in the mode of delivery definition for the terminals.
Rail car deliveries are made to bulk plants more often than to terminals
and, therefore, would not distinguish the wholesale facility as a
terminal. Therefore, a terminal is defined as a wholesale petroleum
marketing outlet which receives product by pipeline, ship, or barge.
6.2.2 Designation of Affected Facility
Loading rack facilities in the bulk terminal industry can vary
widely in types and quantities of products handled. In addition to
gasoline, large quantities of fuel oil, diesel, and jet fuel may be
handled by a terminal. This variation in products handled is due to
the demand for each product in the vicinity of the terminal. Due to
low vapor pressures, the emissions from fuel oil, diesel, and jet fuel
are considered low when compared to gasoline, and so these products
would not be regulated by the proposed standards.
At many terminals, "switch loading" takes place (Section 3.2.3.1).
Switch loading is the practice of carrying various products in the
delivery tank on successive deliveries. Switch loading can cause
uncontrolled VOC emissions to be displaced to the atmosphere. For
example, fuel oil loaded into a delivery tank which had carried a
previous load of gasoline would displace gasoline vapors to the atmosphere.
To control these emissions, switch loading was taken into account in
designating the affected facility. Consequently, the proposed standards
would affect both the loading of gasoline into delivery tank trucks
and the loading of any liquid product into tank trucks which contain
gasoline vapors (defined as gasoline tank trucks).
Because vapor leakage from tank trucks can contribute significantly
to the total VOC emissions which occur during liquid product loading
(Section 3.2.3.3.1), three alternative approaches to designating the
6-2
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affected facility which would take into account these leakage emissions
were considered.
Under the first approach, the standards would apply only to the
bulk terminal. The terminal owner or operator would be required to
use vapor collection equipment on loading racks servicing gasoline
tank trucks, and to restrict loadings to vapor-tight tank trucks. The
affected facility under this approach would include only the loading
racks servicing gasoline tank trucks. Operators of gasoline tank
trucks wishing to load at the terminal would need compatible loading
and vapor recovery equipment, and vapor-tight delivery tanks. This
approach would consolidate responsibility for controlling emissions
without resulting in an excessive burden for the terminal owner or
operator.
Under the second approach, standards would apply directly to both
the terminal and the tank trucks. The standards would require the
terminal owner or operator to install vapor collection equipment and
the tank truck operator to have compatible equipment and vapor-tight
tank trucks. Under this approach, the affected facility would consist
of the combination of the loading rack and the truck-mounted tank,
with a single standard covering the hybrid loading rack/tank facility.
The second approach could result in several owners or operators (of
the terminal and of the tank trucks) at the same terminal being regulated
under a single standard. This could create enforcement difficulties
and problems in determining liability.
The third approach would involve designating two affected facilities,
one consisting of the loading racks servicing gasoline tank trucks and
the other consisting of the truck-mounted tanks, and applying a separate
standard to each facility. It would not be practical to directly
regulate gasoline tank trucks under a separate standard because the
VOC emissions being regulated occur only during product loading at the
terminal, and a situation of two standards regulating the same source
of emissions would result. Furthermore, in the case of new tank
trucks loading at an existing uncontrolled bulk terminal, only the
tank trucks would be regulated, and VOC emissions would be displaced
6-3
-------
to the atmosphere uncontrolled since the terminal would have no vapor
collection or control equipment to process the vapors. Thus, separate
standards would not be effective in these circumstances.
After consideration of the issues involved with each of these
approaches to designating the affected facility, the first approach
was selected as the most practical of the three possibilities. This
would place direct responsibility under the proposed standards on the
owner or operator of the bulk terminal only, would eliminate the
potential for enforcement problems associated with an impermanent
affected facility under the second approach, and would eliminate the
situation of regulating the same operation with two standards under
the third approach.
Two potential affected facility designations under the first
approach were examined. These were: (1) each individual loading rack,
and (2) the combination of all the loading racks at the terminal which
service gasoline tank trucks. Both of these designations would exclude
loading racks which load only non-gasoline products into tank trucks
which do not handle gasoline. Since 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), there is a
presumption that a narrower designation of the affected facility is
proper. This ensures that new emission sources within plants will be
brought under the coverage of .the standards as they are installed.
While selection of a narrower designation of affected facility
generally results in greater emissions reduction by earlier coverage
of replacement equipment, it appears that a broader designation could
result in greater emissions reduction in the bulk gasoline terminal
industry. Replacement of existing racks is not expected to occur to
any great extent, because properly maintained racks do not generally
require replacement. In other words, the isolated replacement of a
single rack due to deterioration of that rack is expected to occur
only rarely. Information from industry indicates that terminals will
concentrate on additions of new racks to sets of existing racks rather
than replacement of existing racks. It further appears that if replacement
6-4
-------
does occur, it will involve a major change in the rack system (such as
conversion from top to bottom loading) and will involve most or all of
the racks at the terminal rather than just one rack. The reasons that
a total racks affected facility designation is expected to result in
greater emission reduction than a single rack affected facility designation,
in the situations described above, are explained below.
Under modification (Section 5.1.1 of Chapter 5), if a new rack were
added to a terminal it would be an affected facility under a single
rack designation, and only that rack would be covered. Under a total
racks designation, the addition of a single new rack could result in a
modification, in which case all of the racks would become an affected
facility, resulting in greater emission reduction under this designation.
Even if the addition of the new rack did not result in a modification
because there was no increase in emissions (due to partial control,
for example), the total racks designation would still result in less
emissions. This is because the single rack designation would still
result in a small incremental emissions increase even if the rack were
controlled.
In addition to modification, an existing facility could become
reconstructed (Section 5.1.2 of Chapter 5) if the fixed capital cost
of replacing components at that facility exceeded 50 percent of the
cost of a comparable entirely new facility. Under a single rack
designation, this cost figure could be attained sooner for a given
rack than it would under a total racks designation, since total
replacement cost for parts for a single rack would be less than for
all the racks, and 50 percent of the cost for a single new rack would
be less than 50 percent of the total cost for all new racks. However,
under a total racks designation, all the racks at a terminal could
become affected facilities if the conversion cost exceeded 50 percent
of the cost needed to build all new racks; although more racks would
have to be converted to attain this cost, more racks could eventually
be covered sooner than they would be under a single rack designation.
Multiple-rack conversion projects are the most likely type of replacement
at bulk terminals, and often take from 1 to 2 years to complete.
Therefore, considering that work on several racks is expected to be
6-5
-------
more frequent than single rack replacement, and that more racks would
be affected under the total racks designation, it is projected that
the total racks designation would result in more emission reduction
than would the single rack designation.
An examination of the control costs presented in Sections 8.2.2
and 8.2.3 of Chapter 8 indicates that the cost to a terminal owner or
operator would most often be less under a total racks designation of
the affected facility. For existing terminals which do not already
have control systems installed due to SIP regulations, the net annualized
cost of operating a system controlling all the racks would be lower
than for a system controlling just one rack. This is due to the
increased product recovery cost credits resulting from controls on all
racks. Terminals installing thermal oxidation systems would not enjoy
this cost benefit, however, because no product is recovered in these
systems. For terminals which already have control systems under SIP
regulations, under a single rack designation a separate control system
may have to be installed to control a single new rack. However, under
a total racks designation, an owner or operator would have several
options for control, including replacing, adding onto, or upgrading
the existing system in order to control all racks and meet the emission
limit of the standards. The cost tables in Section 8.2.3 indicate
that any of the options under the total racks designation would be
less expensive than installing a separate control system to control a
single rack under the single rack designation.
In addition to the emission reduction and cost considerations
discussed above, the single rack designation has technical complications.
Performance testing of this affected facility would be difficult at
terminals which already have some means of vapor control installed
(estimated to include about 70 percent of the existing terminals). If
one rack were newly installed or altered in such a way as to become an
affected facility under modification or reconstruction provisions and
were required to meet a more stringent emission limit, the new rack
could require controls different from the remainder of the loading
equipment. Since the emissions from all of the racks are typically
routed to the single vapor processor, it would be impossible to
6-6
-------
distinguish the vapor processor outlet emissions originating from only
the new loading rack. If an existing control device were unable to
meet a more stringent emission limit, a bulk terminal operator could
either install a separate vapor collection system and processor for
the new rack, or replace or upgrade the existing control device. The
latter approach is identical to what a total racks designation of the
affected facility would accomplish.
The foregoing discussion indicates that the total racks designation
would result in the greatest emission reduction and the lowest cost to
the owner or operator of a bulk terminal. Performance testing of this
facility would be straightforward because all loading racks would be
subject to the same standards. Consequently, due to the considerations
outlined above, the designation which includes the combination of all
the loading racks servicing gasoline tank trucks was selected as the
affected facility for regulation under the proposed standards.
6.2.3 Data Base for Model Plant Parameters
Data presented in reports of EPA-sponsored terminal source tests,
data from plant visits, and data from information requests submitted
under authority of Section 114 of the Clean Air Act were used as input
2 3fi
for the selection of the terminal model plant parameters. The
data are summarized in Table 6-1. Information in Table 6-1 is given
for the type of facility (either new or existing), gasoline throughput,
gasoline storage, and gasoline loading rates. Additional sources were
37 38 39
consulted for tank truck capacity data and method of loading. ' '
Model firm parameters for the gasoline motor carrier industry
relied primarily on tank truck population data from the Bureau of the
Census.
6.2.4 Model Plant Parameters for Bulk Gasoline Terminals
Since terminal gasoline throughputs are distributed over a wide
range, several model plant sizes were considered in order to best
represent the industry. A recent EPA-sponsored report discussed the
distribution of gasoline terminals by throughput within the industry.
It was estimated that the size distribution of new and proposed terminals
would closely resemble the distribution of existing facilities.
Almost 50 percent of the existing terminals are less than 757,000
6-7
-------
Table 6-1. DESIGN PARAMETERS FOR BULK GASOLINE TERMINALS'
00
Facility
1
2
3
4
5
6
7
fi
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Terminal
Type
Nb
Ed
E
E
E
N
E
E
E
E
E
E
E
E
E
E
E
E
E
E
N
N
— N
Throughput
(liters/Day)
318,000
757,000
1,900,000
606,000
1,817,000
1,514,000
1,514,000
303,000
606,000
341 ,000
1,419,000
1,101,000
814,000
—
1,514,000
927,000
189,000
___
1,514,000
757,000
1,571,000
5,045,000
2,330,000
Gasoline
Total
Capacity
(103 m3)
__c
—
—
—
36
—
--
—
«
—
—
—
—
—
—
__
6
—
.-
27
70
144
.-
Storage
Number
of
Tanks
2
3
4
4
6
..
__
4
—
—
—
—
—
—
--
6
4
5
--
4
6
15
..
Gasoline
Number of
Positions
2
2
3
2
4
4
2
2
3
1
2
3
3
3
3
3
1
2
6
2
3
4
—
Loading
Number
of
Arms
4
6
9
6
11
12
6
6
9
3
6
6
6
9
9
8
3
8
18
8
9
—
—
Gasoline
Pumping.
Rate
(LPM)
2,270
1,700
2,460
2,650
1,890
2,460
3.400
1,800
--
—
--
2,270
2,080
2,650
2,270
2,270
2,080
—
2,270
2,650
--
—
—
Maximum
Instantaneous
Pumping
Rate
(LPM)
9,100
11,400
14,800
15,900
—
19,700
20,400
7,570
—
--
—
—
--
—
—
20,400
4,160
—
—
—
—
—
—
-------
Table 6-1. DESIGN PARAMETERS FOR BULK GASOLINE TERMINALS3 (Concluded)
en
i
10
Facility
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Terminal
Type
E
E
E
E
E
N
E
E
E
N
E
E
E
E
E
E
Throughput
(liters/Day)
1,190,000
870,000
870,000
814,000
--
2,040,000
1,980,000
—
2,270,000
1,514,000
1,514,000
1,514,000
757,000
606,000
1,003,000
280,000
Gasoline
Total
Capacity
(103 m3)
__
9
28
29
29
68
53
—
—
23
—
..
--
16
25
8
Storage
Number
of
Tanks
—
3
--
5
4
—
5
—
—
3
—
—
—
3
3
3
Gasoline Loading
Number of
Positions
4
2
—
2
2
2
5
2
2
4
3
5
5
2
2
1
Number
of
Arms
—
5
—
—
6
--
—
6
6
10
9
—
15
6
12
3
Gasoline
Pumping
Rate
(LPM)
--
2,650
--
--
2,080
--
2,080
1,890
3,410
2,840
2,460
--
2,270
1,890
2,270
2,840
Maximum
Instantaneous
Pumping
Rate
(LPH)
—
4,540
5,680
5,680
--
—
--
3,790
20,400
--
22,100
—
—
—
68,100
--
References: 2-36.
bN - New terminal (includes terminals less than 2 years old).
cNo data.
dE - Existing terminal.
-------
liters per day (LPD) so a model plant size of 380,000 LPD was selected
to represent this subset. Approximately 30 percent of the gasoline
terminals have throughputs between 757,000 and 1,514,000 LPD. A model
plant with a throughput of 950,000 LPD was selected to cover plants in
the range of 660,000 to 1,420,000 LPD. An additional 20 percent of
the terminals have throughputs between 1,514,000 and 2,270,000 LPD. A
model plant size of 1,900,000 LPD was selected to represent these
facilities.
Although the report indicates that less than 5 percent of the
existing terminals are greater than 2,270,000 LPD, information gathered
on new or proposed terminals indicates that a significant percentage
of new terminals will be larger than 2,270,000 LPD. Data on proposed
terminals in Florida indicate one over 2,270,000 LPD and one over
4,900,000 LPD.36 A model plant size of 3,800,000 LPD was selected to
represent these terminals. Existing terminals can be best represented
by the three lower size ranges (380,000 LPD, 950,000 LPD, and 1,900,000 LPD)
while new or proposed terminals are best represented by the three
larger categories (950,000 LPD, 1,900,000 LPD, and 3,800,000 LPD).
Model plant parameters for the four selected size categories of 380,000 LPD,
950,000 LPD, 1,900,000 LPD, and 3,800,000 LPD, are presented in Table 6-2.
The model plant parameters present data for several design factors,
many of which were derived from Table 6-1. The data for gasoline
storage, gasoline loading configurations, and pumping rates were
grouped by size ranges and an average was calculated. Where data were
lacking for the largest terminal size, parameters were extrapolated
from the other categories. For example, the data on the number of
loading arms and racks for the 3,800,000 LPD terminal was not complete;
however, a value was extrapolated from the other size ranges and also
from previous visits to terminals of this size in California.
The average gasoline pumping rate was the same for each of the
three lower categories and was independent of throughput. Therefore,
the same average pumping rate (2,270 liters per minute) was assumed
for the 3,800,000 liters per day plant. The maximum instantaneous
pumping rate was calculated by assuming three loading arms operating
simultaneously from each of the loading positions or racks.
6-10
-------
Table 6-2. BULK GASOLINE TERMINAL MODEL PLANT PARAMETERS
cr»
a.
b.
c.
d.
e.
f.
9-
h.
i.
j-
k.
1.
m.
Design Factor
Gallons per Day
//Day
Number of Rack Positions for Gasoline
Number of Loading Arms for Gasoline
Loading Method
Pumping Rate/Loading Arm
Tank Truck Capacity
Tank Truck Loading Time
Maximum Instantaneous
Loading
Operating Schedule
Gasoline Storage Capacity
Number of Storage Tanks for Gasoline
Number of Terminal -Opera ted Trucks
1 2
100,000 250,000
380,000 950,000
2 3
6 9
Submerged Submerged
(Top or Bottom) (Top or Bottom)
600 GPM 600 GPM
(2,270 LPM) (2,270 LPM)
8,500 Gallons 8,500 Gallons
(32,200 Liters) (32,200 Liters)
20 minutes 20 minutes
3,600 GPM 5,400 GPM
(13,600 LPM) (20,400 LPM)
340 Days/Year 340 Days/Year
65,000 Bbl 150,000 Bbl
(10,340 m3) (23,880 m3)
3 4
3 6
3
500,000
1,900,000
3
9
4
1,000,000
3,800,000
4
12
Submerged Submerged
(Top or Bottom) (Top or Bottom)
600 GPM
(2,270 LPM)
8,500 Gallons
(32,200 Liters)
20 minutes
5,400 GPM
(20,400 LPM)
340 Days/Year
275,000 Bbl
(43,670 m3)
5
9
600 GPM
(2,270 LPM)
8,500 Gallons
(32,200 Liters)
20 minutes
7,200 GPM
(27,300 LPM)
340 Days/ Year
600,000 Bbl
(95,400 m3)
6
20
-------
The method of loading was derived from operator interviews,
Section 114 letter responses, and the literature. The industry trend
is toward bottom loading, and it is expected that all new terminals
will be bottom loaded. There are a number of top loading systems
still in operation at existing terminals, and it was assumed for the
model plants that these would be submerged loaded. The trend is
toward submerged loading as a minimum emission control and cost-saving
measure at terminals where top loading is still in operation.
The average tank truck capacity was determined by consulting the
EPA tank truck and rail car survey. The capacities of over 1,000
tank trucks were considered to obtain an average of 32,200 liters
(8,500 gallons). The average number of tank trucks per terminal was
determined from plant visits and Section 114 letter responses. A
number of terminal operators stated that they do not operate any
terminal-owned tank trucks. However, a majority of the respondents
indicated that the terminals do operate their own tank vehicles.
The operating schedule for the terminals was also based upon
operator interviews and Section 114 letter responses. Of those responding,
there were equal numbers operating six days per week and seven days
per week. A value of 6.5 days per week was used to establish an
average work year of 340 days per year.
6.2.5 Model Firm Parameters for For-Hire Tank Truck Companies
The independent trucking companies which own or lease tank trucks
used for transporting gasoline from bulk terminals will be affected by
some of the regulatory alternatives discussed in Section 6.3. The
tank trucks operating at an affected facility will be required to be
compatible with the loading method (usually bottom loading) and vapor
collection equipment which the terminal has installed to limit VOC
emissions. In order to take into account the economic impact of the
regulatory alternatives on these companies, model firm parameters
have been developed. These parameters are intended to characterize
the existing range of company sizes as determined from the most recent
available information. They are further meant to be similar to and
serve the same purpose as the model plant parameters for bulk terminals.
6-12
-------
The primary source of data used to derive the parameters was the
1977 Census of Transportation, Truck Inventory and Use Survey, conducted
41
by the Bureau of the Census. This survey is based on a stratified
probability sample of about 117,000 trucks, drawn from an estimated
28 million registrations on file in the 50 States and the District of
Columbia during 1977. The data file was acquired in the form of a
machine-readable tape, and a printout containing the desired data
format was generated. The data analysis was limited to tank vehicles
carrying petroleum or petroleum products listed under the wholesale
and for-hire use categories. In addition, only tanks of greater than
15,100 liter (4,000-gallon) capacity were considered, in order to
avoid the inclusion of small tank vehicles operating only at bulk
plants. These limitations provided a population sample of 500 tanks.
It is important to note that since information specific to gasoline
tank trucks at terminals is not available, the assumption that petroleum
tank vehicles of greater than 15,100 liter capacity are representative
of terminal gasoline tank trucks was necessary. It is believed that
this assumption provides a reasonably accurate profile of the industry
of interest.
For each tank vehicle listed in the census survey, information
was provided by respondents concerning the number of trailers, tractors,
and other trucks at the same operational base. The model year and
number of annual miles was shown for each vehicle listed, and these
provided a breakdown by age category as well as an average number of
miles driven. The number of tank vehicles assigned to each firm
represents the approximate midpoint of a range of values. The smallest
model firm represents companies with from one to three tanks at a
single base of operations, and this firm is considered to operate two
tank vehicles. The next model firm operates from 4 to 10, or 7
tanks, the third firm operates from 11 to 50, or 30 tanks, and the
largest model firm operates more than 50, or 100, tank vehicles.
The average number of employees for each model firm size was
determined from a recent Motor Carrier Annual Report. Average tank
capacity wa's assumed to be the sanfe as that derived for terminal-owned
tank trucks (Table 6-2). The model firm parameters for the for-hire
6-13
-------
motor carrier companies operating at bulk terminals are summarized in
Table 6-3. Industry characterization, costs, and economic impact are
discussed in Sections 8.1.3, 8.2.5, and 8.4.2, respectively, of
Chapter 8.
6.3 REGULATORY ALTERNATIVES
Four regulatory alternatives were selected for consideration in
controlling VOC emissions from bulk gasoline loading facilities at
terminals. The units of the regulatory alternatives, milligrams per
liter, were chosen to be consistent with the existing Control Tech-
niques Guideline (CTG) document on bulk gasoline terminals. These
units indicate milligrams of VOC emitted to the atmosphere per liter
of gasoline dispensed. These units are for comparison purposes and do
not necessarily reflect the units of the final proposed standard.
6.3.1 Vapor Leakage from Tank Trucks
Tank truck vapor leakage can vary significantly from terminal to
terminal and from truck to truck. EPA test data indicate that leakage
varied from 0 percent to 100 percent for individual truck loadings and
averaged 30 percent leakage for all EPA tests. The potential quantity
of emissions and the variability in this vapor tightness from terminal
to terminal prompted EPA to consider controlling tank truck leakage to
make terminal controls more effective. A CTG for tank trucks was
43
published in December 1978. EPA also considered controlling tank
truck leakage in the development of new source standards for terminals.
Testing on tank trucks in areas with vapor tightness regulations has
demonstrated an average of 10 percent vapor leakage from the trucks.
Section C.I.4 of Appendix C contains details on these tests. Tank
truck leakage could be reduced by requiring the terminal operator to
restrict loadings of gasoline tank trucks to those which have passed
an annual vapor-tight test. Such a regulation would require that
written verification of a tank's vapor-tight condition be carried on
the vehicle at all times, and that a copy be on file at the affected
terminal office.
The owner or operator of a bulk terminal would be legally responsible
for reducing emissions from that terminal. However, he might not have
direct control or financial responsibility over all tank trucks that
6-14
-------
Table 6-3. TANK TRUCK COMPANY MODEL FIRM PARAMETERS
a.
b.
c.
d.
e.
f.
g.
Firm Parameter
Number of Tank Vehicles3
Vehicle Age Distribution
Pre-1967
1967-1975
1976-1978
Number of Tractors
Number of Other Trucks
Annual Tank Vehicle Miles
(Kilometers)
Tank Capacity in Gallons
(Liters)
Number of Employees
1
2
0
1
1
2
5
65,000
(104,000)
8,500
(32,200)
10
2
7
1
5
1
7
10
65,000
(104,000)
8,500
(32,200)
25
3
30
3
22
5
24
12
65,000
(104,000)
8,500
(32,200)
50
4
100
9
74
17
75
15
65,000
(104,000)
8,500
(32,200)
120
Number of straight truck or trailer tank vehicles at a single operational base.
Quantities approximate. Further discussion in Section 8.1.3 of Chapter 8.
6-15
-------
load there. Consequently, it would be unfair to require the owner or
operator to maintain all tank trucks free from emission leakage.
Therefore, in order to avoid such a situation, the regulatory alternatives
would only require the terminal owner or operator to load gasoline
tank trucks which had demonstrated compliance with a vapor-tight
requirement, as opposed to requiring him to maintain all gasoline tank
trucks loading at the terminal in a vapor-tight condition.
6.3.2 Selection of Emission Limits
The VOC emission test results discussed in this section are
adjusted values which take into account tank truck vapor leakage. The
results were adjusted to allow the evaluation of all vapor processors
on an equivalent leak-free basis. The test method used in the EPA
testing program required that the volume of vapors returned to the
system be measured. The tank trucks are also checked to see if they
fit the definition of vapor-tight (no leak greater than 100 percent of
the lower explosive limit). The volume of vapors returned or captured
per volume of gasoline dispensed was then compared for vapor-tight and
leaking tank trucks. Using this method, the average amount of vapor
leakage could be determined. The mass concentration, measured at the
vapor processor outlet, was then adjusted to take into account vapor
leakage. This adjustment assumed the vapors which leaked would pass
through the processor and be controlled at the same efficiency as the
rest of the vapors. This approach was used to compare results from
numerous tests on a common, no-leak basis.
Test results from 22 EPA-sponsored source tests are summarized in
Section 4.5. A more detailed presentation of calculated test parameters
is contained in Section C.I.2 of Appendix C.
6.3.3 Description of Regulatory Alternatives
Four alternative regulatory approaches were selected for the bulk
gasoline terminal industry. The regulatory alternatives represent
feasible methods of controlling VOC emissions from the gasoline loading
operations at terminals. All emission limits represent actual mass
emissions as measured at the outlet of the vapor processor. The
control methods used as the basis for these alternatives are described
in Section 4.5. Table 6-4 summarizes the regulatory alternatives
6-16
-------
Table 6-4. REGULATORY ALTERNATIVES FOR
BULK GASOLINE TERMINALS
Alternative Description
I No additional controls over
those included in the State
(Baseline) Implementation Plans (SIP),
which limit emissions to
80 mg/liter from tank truck
loading and require tank
truck leakage controls in
regulated areas.
II Controls to limit gasoline
loading emissions to 80 mg/liter
and to require tank truck
leakage controls at affected
facilities.
Ill Controls to limit gasoline
loading emissions to 35 mg/liter
with no tank truck leakage
controls beyond the SIP
coverage.
IV Controls to limit gasoline
loading emissions to 35 mg/liter
and to require tank truck leakage
controls at affected facilities.
6-17
-------
developed 'for the bulk gasoline terminal industry. The four regulatory
alternatives are described in detail in the following subsections.
6.3.3.1 Alternative I (Baseline Case). Under Alternative I, no
NSPS would be developed. Instead, the State Implementation Plans
(SIPs) would be relied upon to control VOC emissions from bulk gasoline
terminals. SIP regulations generally require controls only in non-
attainment areas. The SIP regulations would require controls for most
areas of the United States equivalent to the CT6 recommended level of
80 ing/liter from the loading operations. This would regulate approximately
70 percent of the existing facilities. This alternative also assumes
that the recently published CTG recommended limits on tank truck
leakage would be implemented in the same areas where the terminal CTG
recommendations were adopted. This assumption was based upon the best
estimate available to EPA's Control Programs Development Division
(CPDD). Those areas not covered by CTG equivalent regulations were
divided into areas where no regulations apply and areas where just
submerged fill applies. A discussion of these regulatory coverage
areas is given in greater detail in the section on Baseline Emissions
(Section 3.3).
6.3.3.2 Alternative II. This alternative would require controls
on new, modified, or reconstructed sources that would limit VOC emis-
sions from the vapor processor outlet to 80 mg/liter. It would also
require that terminal operators restrict loadings of gasoline tank
trucks to those which have passed an annual vapor-tight test. The
test data indicate an average vapor collection efficiency of 70 percent
(range from 50 to 99 percent) for tank trucks in areas that have no
vapor-tight regulations (30 percent truck leakage). Tank trucks in
vapor-tight regulated areas have been found to average 10 percent
leakage (Section 6.3.1). This alternative, in effect, does not impose
additional controls on new sources in the areas where SIP regulations
exist. The alternative would require the terminal to have verification
that tank trucks handling gasoline have passed a vapor-tight test
identical to that adopted in the SIPs. The areas that would be affected
would be those which were previously not controlled at the SIP level.
6-18
-------
This would regulate modifications and reconstructions for approximately
30 percent of the existing sources and would regulate all new sources.
Because of the small number of new facilities expected to be built
over the next ten years (approximately ten), the major effect of this
and all other alternatives would be on modified or reconstructed
sources.
All of the control systems tested would be considered applicable
under this standard. The possible exception would be the lean oil
absorption (LOA) system. Test data indicate that any of the other
control systems could meet an emission limit of 80 mg/liter.
6.3.3.3 Alternative III. This alternative would require controls
for all new, modified, or reconstructed sources to limit VOC emissions
from the vapor processor outlet to 35 mg/liter. The carbon adsorption
systems and thermal oxidation systems with vapor holders gave the most
consistent results in reducing VOC emissions in EPA tests. The carbon
adsorption average emissions were slightly lower, but the cost analysis
indicated that the thermal oxidation system was the most cost-effective
system for small terminals. This is important since about half of the
affected facilities are expected to be in the smallest model plant
size. The average adjusted daily emission rate from the carbon adsorption
systems and the thermal oxidation systems which used a vapor holder
were 5.9 and 13.3 mg/liter, respectively. The highest emission rate
from either type of system was 29.4 mg/liter. This parameter represents
the calculated rate which would have occurred in a vapor-tight collection
system, based on actual measured emissions and an adjustment factor
representing the quantity of tank truck vapor leakage measured during
testing. In order to allow a small margin above the highest measured
emission level from these two types of systems, a level of 35 mg/liter
was selected as the emission limit for this regulatory alternative.
The test data indicate that the carbon adsorption and thermal
oxidation with vapor holder systems tested can achieve 35 mg/liter.
In the two tests on thermal oxidation systems without a vapor holder,
the systems achieved this emission limit on three of six test days,
indicating the potential of such a system to achieve the limit. Newer
6-19
-------
refrigeration type control units, not tested in the EPA test program,
have shown the ability to meet a limit of 35 mg/liter (Section C.I.3
of Appendix C). Information from control unit manufacturers indicates
that older refrigeration units may be capable of meeting this limit if
operational or design modifications are made. Existing compression-
refrigeration-absorption systems and compression-refrigeration-condensation
systems may be able to meet the 35 mg/liter standard with the use of
add-on controls.
6.3.3.4 Alternative IV. Alternative IV is similar to Alternative III
in that it would limit emissions at all new, modified,.or reconstructed
sources to 35 mg/liter. This emission limit is based on the same
control technologies discussed in the previous section. This alternative
would also require the terminal owner or operator to restrict loadings
of gasoline tank trucks to those which had passed an annual vapor-tight
test. These additional controls over those in Alternative III would
affect only those terminals in areas where tank trucks were not already
regulated by SIP limitations, and are the same vapor-tight controls which
would be required in Alternative II.
6-20
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6.4 REFERENCES
1. Polglase, W., W. Kelly, and J. Pratapas. Control of Hydrocarbons
from Tank Truck Gasoline Loading Terminals. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Publication
No. EPA-450/2-77-026. October 1977. 60 p.
2. 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.
3. 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.
4. Amoco Oil Company. Demonstration of Reduced Hydrocarbon Emissions
from Gasoline Loading Terminals. U.S. Environmental Protection
Agency. Washington, D.C. Publication No. EPA-650/2-75-042.
June 1975. 51 p.
5. 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.
6. 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. Draft EMB No. 78-BEZ-5. May 1978. 166 p.
7. 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.
8. 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.
9. 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.
6-21
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10. 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. 77-6AS-18. November 1976. 87 p.
11. 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.
12. 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.
13. 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.
14. 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.
15. 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.
16. 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.
17. 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.
18. 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.
6-22
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19. 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.
20. 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.
21. 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.
22. 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.
23. 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.
24. 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.
25. Letter and attachments from McGirr, J.J., F.L. Roberts & Company,
Incorporated, to Goodwin, D.R., Environmental Protection Agency.
June 21, 1979. Response to Section 114 letter on terminals.
26. 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.
27. 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 terminals.
28. Letter and attachments from Richardson, O.K., Mobil Oil Corporation,
to Goodwin, D.R., Environmental Protection Agency. August 14, 1979.
Response to Section 114 letter on terminals.
29. Memorandum from Norton, R., and LaFlam, G., Pacific Environmental
Services, Incorporated (PES), to Durham, J., and Shedd, S.,
Environmental Protection Agency. May 1, 1979. Report on
April 27, 1979, visit to Exxon terminal in Chesapeake, Virginia.
6-23
-------
30. Memorandum from Norton, R. and LaFlam, 6., Pacific Environmental
Services (PES), to Durham, J. and Shedd, S., Environmental
Protection Agency. May 1, 1979. Report on April 23, 1979,
visit to ARCO terminal, Revere, Massachusetts.
31. Memorandum from Norton, R. and LaFlam, G., Pacific Environmental
Services (PES), to Durham, J. and Shedd, S., Environmental
Protection Agency. May 1, 1979. Report on April 25, 1979,
visit to Buckeye Pipeline Company terminal in Coraopolis,
Pennsylvania.
32. Memorandum from Norton, R. and LaFlam, 6., Pacific Environmental
Services (PES), to Durham, J. and Shedd, S., Environmental
Protection Agency. May 1, 1979. Report on April 24, 1979,
visit to Texaco terminal in Chelsea, Massachusetts.
33. Memorandum from Norton, R. and LaFlam, G., Pacific Environmental
Services (PES), to Durham, J. and Shedd, S., Environmental
Protection Agency. May 1, 1979. Report on April 25, 1979,
visit to Sunmark terminal in Blawnox, Pennsylvania.
34. Memorandum from Norton, R. and LaFlam, G., Pacific Environmental
Services (PES), to Durham, J. and Shedd, S., Environmental
Protection Agency. May 1, 1979. Report on April 26, 1979,
visit to Exxon terminal in Pittsburgh, Pennsylvania.
35. Process Information and Permitting Data Report for the Kissimmee
Terminal of Transgulf Pipeline Company. Tipton Associates,
Incorporated. Orlando, Florida. July 1978. 29 p.
36. Letter and attachments from Collins, F.A., Environmental
Protection Agency, to Norton, R., Pacific Environmental Services
(PES). February 21, 1979. Information on proposed terminals
in Florida.
37. Bulk Liquid Terminals and Storage Facilities, 1979 Directory.
Independent Liquid Terminals Association. Washington, D.C.
1979 Edition. 83 p.
38. National Petroleum News Factbook Issue. Vol. 71. No. 6A. Mid-
June 1979.
39. Hang, J.C., and R.R. Sakaida. Survey of Gasoline Tank Trucks
and Rail Cars. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/3-79-004. March
1979. 41 p.
40. Arthur D. Little, Incorporated. The Economic Impact of Vapor
Control Regulations on the Bulk Storage Industry. U.S. Environ-
mental Protection Agency. Research Triangle Park, N.C.
EPA-450/5-80-001. January 1980. 240 p.
6-24
-------
41. U.S. Department of Commerce, Bureau of the Census. Census of
Transportion, 1977, Truck Inventory and Use Survey.
Washington, D.C. 1979.
42. American Trucking Associations, Inc. 1978 Motor Carrier Annual
Report — Financial & Operating Statistics. Washington, D.C.
1979. 812 p.
43. Shedd, S.A., and N.D. Mclaughlin. Control of Volatile Organic
Compound Leaks from Gasoline Tank Trucks and Vapor Collection
Systems. U.S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-450/2-78-051. December 1978. 30 p,
6-25
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7.0 ENVIRONMENTAL IMPACT
This chapter presents an assessment of the environmental impacts
on the bulk gasoline terminal industry associated with the regulatory
alternatives described in Chapter 6. The impacts associated with air,
water, solid waste, energy consumption, and other environmental concerns
will be discussed in the following sections.
7.1 AIR POLLUTION IMPACTS
The air pollution impacts of regulatory alternatives for the bulk
gasoline terminal industry are obtained by applying the alternative
limits on new, modified, and reconstructed terminals. These emission
estimates are then compared with the emissions from the terminals that
would occur without the controlling standard (baseline emissions).
The amount of control applied to terminals in the absence of the
standard is specified by the level of control required in the State
Implementation Plans (SIPs), which will cover most terminals (Section 3.3
of Chapter 3). The air pollution impact is then estimated for the
bulk gasoline terminal model plants and for emissions from terminals
on a national scale. For reference, the bulk terminal model plant
parameters are presented in Table 6-2, and the regulatory alternatives
are presented in Table 6-3 of Chapter 6.
7.1.1 Air Pollution Impact on Model Plants
The air pollution impacts on the model plants are presented in
Table 7-1. Data are presented for Regulatory Alternatives II, III,
and IV, and the emissions associated with each alternative. The base-
line emissions (Alternative I) are also presented along with the
emission reduction from the baseline for each alternative.
Three categories, which apply to each model plant, are presented
in Table 7-1. These categories include terminals in non-attainment
areas, and splash filled and submerged filled terminals in attainment
areas. The category of terminals in the non-attainment areas
7-1
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Table 7-1. BASELINE AND ALTERNATIVE VOC EMISSIONS FROM
BULK GASOLINE TERMINAL MODEL PLANTS (Mg/yr)
Model Plant
(liters/day)
Non- Attainment
380,000
950,000
1,900,000
3,800,000
Attainment Area-
Submerged Fill
380,000
950,000
1,900,000
3,800,000
Attainment Area-
Splash Fill
380,000
950,000
1,900,000
3,800,000
Baseline
Emission
23
57
114
227
78
194
388
775
186
465
930
1860
Alternative II
Emissions
23
57
114
227
23
57
114
227
23
57
114
227
VOC
Reduction9
0
0
0
0
55
137
269
548
163
408
816
1,633
Alternative III
Emissions
17
38
78
153
42
107
213
428
42
107
213
428
VOC
Reduction
6
19
36
74
36
87
175
347
144
358
717
1,432
Alternative IV
Emissions
17
38
78
153
17
38
78
153
17
38
78
153
VOC a
Reduction
6
19
36
74
61
156
310
622
169
427
852
1,707 -
ro
VOC Reduction = Emissions Reduction from Baseline Emissions in Mg/yr.
-------
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 regu-
lations (see Section 3.3, Baseline Emissions). The category for
submerged fill in attainment areas shown in Table 7-1 represents new
terminals and modified or reconstructed existing terminals in attainment
areas that incorporate submerged fill. However, the category for
splash fill in attainment areas represents modified or reconstructed
existing terminals only, since it is assumed that no new terminals
will use splash filling. The air pollution impact is greatest in the
splash fill category because the baseline VOC emissions are highest
for this category of uncontrolled sources.
The emissions from terminals incorporating Alternative II are the
same for all three categories, as is shown in Table 7-1. Under this
alternative, all terminals would be required to restrict loadings of
gasoline tank trucks to those passing an annual vapor-tight test and
to limit vapor processor outlet emissions to 80 mg/liter. Since the
requirements of Alternative II are identical to those imposed by the
SIPs on terminals in non-attainment areas, there is no reduction in
emissions from those terminals that were controlled under the baseline
SIP regulations. Alternative III would require terminals to limit
vapor processor outlet emissions to 35 mg/liter but would not require
tank truck controls beyond those specified in the SIP regulations.
Tank truck leakage would therefore continue to be uncontrolled for
new, modified, and reconstructed terminals in areas where no SIP
regulations exist (most attainment areas). Tank truck leakage in
these areas has been estimated at 30 percent (see Section 4.3.1). By
including this tank truck leakage in the emission calculations, the
emissions associated with Alternative III, from terminals in the
attainment area category, are higher than those associated with
Alternative II. The emissions from terminals incorporating limits
from Alternative IV are again identical for all categories. All
terminals under Alternative IV would be required to restrict loadings
of gasoline tank trucks as under Alternative II and to limit vapor
processor outlet VOC emissions to 35 mg/liter. As indicated in Table 7-1,
7-3
-------
Alternative IV results in the greatest emission reductions for terminals
in attainment areas.
7.1.2 National Air Pollution Impacts
The national air pollution impacts are presented in Table 7-2.
The data represent total VOC emissions from terminals, in megagrams
per year (Mg/yr), for the expected proposal year — 1980 (or early 1981),
the SIP completion year — 1982, and the projection years — 1985 and
1990. In these estimates, 1985 is assumed to be the fifth year, and
1990 the tenth year, of the standards. Also presented are the estimated
emission reductions achieved for each of the regulatory alternatives,
and the percent reduction as compared to the baseline emissions.
The available data for industry growth projections are presented
in Section 8.1 of Chapter 8. Data indicate that the consumption of
gasoline will probably not increase significantly over the next 10
years. The growth in gasoline demand will be offset by energy con-
servation trends and the increased gasoline efficiency for automobiles.
Since it is assumed that all gasoline goes through terminals, gasoline
consumption, and therefore terminal throughput, will remain fairly
constant over the next 10 years. Data indicate that only approximately
10 new terminals will be built in the next 10 years. Since total
throughput is not expected to increase, it is assumed that these new
terminals will replace existing terminals that will close. The baseline
emissions for 1982 shown in Table 7-2 are expected to remain fairly
constant throughout the 1980's, because of the expected constant
gasoline throughput during this period. Thus, the emission reductions
indicated for 1985 and 1990 are calculated differences between total
emissions in those years and a constant baseline level.
From information supplied by the industry, it is estimated that
approximately 100 terminals will be modified or reconstructed over the
next 10 years. It is further estimated, based upon the type of modi-
fication or reconstruction planned, that approximately 56 of these
terminals will be in attainment areas and 44 will be in non-attainment
areas. It is also assumed that these modifications will be performed
evenly throughout the 10-year period. By using these assumptions for
terminals and the emission factors found in Table 3-5 of Chapter 3,
the national emission impacts have been calculated.
7-4
-------
Table 7-2. NATIONAL AIR QUALITY IMPACTS OF REGULATORY
ALTERNATIVES ON BULK GASOLINE TERMINAL INDUSTRY
Total emissions
from bulk
gasoline terminals
Emission reductions
from baseline
emissions
Percent reduction
from baseline
emissions
Percent Reduction
For new, modified
or reconstructed
terminals
VOC Emissions, Mg/yr
1980
Emissions
341,900
1982
Baseline
Emissions
140,000
1985 Alternatives
II III IV
134,250 135,490 133,380
5,750 4,510 6,620
435
60 50 70
1990 Alternatives
II III IV
129,200 130,900 127,500
10,800 8,500 12,500
879
60 50 70
-vj
tn
-------
As discussed in the model plant section of this chapter (Section 7.1.1),
the emission reduction from terminals is lowest under Alternative III.
This is because tank truck leakage, not controlled in most attainment
areas, is included in the emissions estimate. Alternative IV yields
the greatest reduction in VOC emissions. As is presented in Table 7-2,
it is estimated that by 1990 Alternative IV would reduce VOC emissions
from bulk gasoline terminals by 12,500 Mg/year, or 9 percent. This
reduction corresponds to an overall 70 percent reduction of VOC emissions
from the 110 new, modified, or reconstructed terminals expected in the
next 10 years.
The adverse air pollution impacts due to carbon monoxide (CO) and
oxides of nitrogen (NO ) emissions associated with thermal oxidation
/»
systems were also calculated. Based upon industry surveys and economic
data (see Section 8.2 of Chapter 8), it was assumed that the thermal
oxidation system was used as a control concept for only the small terminal
model plant sizes. Hence, air pollution impacts were derived for only
the two smallest model plants. Emissions were estimated using measured
2
NO and CO concentrations from an EPA sponsored test. The NO emissions
X A
would be 0.1 Mg/yr from a thermal oxidation system serving a
380,000 liter/day terminal, and would be 0.2 Mg/yr from a thermal
oxidation system serving a 950,000 liter/day facility. The CO emissions
would be 0.3 Mg/yr from the 380,000 liter/day terminal, and would be
0.8 Mg/yr for the 950,000 liter/day terminal. If half of the small
new, modified, or reconstructed terminals (about 12 sources) were to
install thermal oxidation systems (and, for worst case purposes, it
was assumed that all of these terminals were in the 950,000 liter/day
model plant size), the nationwide NO emissions would increase by
A
about 3 Mg/yr and the nationwide CO emissions would increase by about
11 Mg/yr. For both of these pollutants, the emission increases represent
a negligible adverse nationwide air pollution impact.
7.2 WATER POLLUTION IMPACT
Water is not used as a direct control medium in any of the proposed
regulatory alternatives. One carbon system being developed for gasoline
3
terminals would use a steam stripping process. The water-gasoline
mixture obtained in the carbon regeneration process passes into a
7-6
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gasoline-water separator, and the water is then discharged. The
amount of steam used or water treated from this process is not known
since this system is still in developmental stages.
Other systems, which cool and condense the vapors from the loading
operation for liquid recovery, will also generate a gasoline-water
mixture. The amount of water generated is dependent upon the relative
humidity of the atmosphere. The mixture passes through a gasoline-water
separator, with the gasoline returning to storage and the water being
discharged. It is estimated that this will produce only a negligible
negative impact on water quality.
7.3 SOLID WASTE DISPOSAL IMPACT
The disposal of discarded carbon from the carbon adsorption
control systems would be the only significant source of solid waste
from the control techniques considered. The worst case could be
represented by all 110 new, modified, or reconstructed sources in 1990
employing carbon adsorption systems, with the carbon being discarded
after its useful life at the terminal. Using an average carbon life
4
of 10 years and an average carbon bed capacity of about 4,500 kg, the
total quantity of solid waste to be handled from all the terminals
would be 50,000 kg per year. To put this in perspective, this is
roughly equivalent to the quantity of solid waste generated each year
by 1 industrial facility with 160 manufacturing employees, or the
residential solid waste generated by 1,340 people. Even this worst
case can be considered to represent a small negative solid waste
impact.
7.4 ENERGY CONSUMPTION IMPACT
The energy consumption impacts of the control equipment discussed
in Chapter 4 are presented in Table 7-3. The impacts are shown for
operation of the control equipment considered for the regulatory
alternatives. These include carbon adsorption (CA), compression-
refrigeration-absorption (CRA), refrigeration (REF), and thermal
oxidizer (TO) systems.
Energy consumption information was obtained from manufacturers,
and energy recovered was based upon liquid recovery credits for each
of the control systems. Recovery credits for the CRA system are lower
than the CA and REF systems because of the higher average control
7-7
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Table 7-3. ENERGY CONSUMPTION IMPACTS OF CONTROL
EQUIPMENT ON THE BULK GASOLINE TERMINAL MODEL PLANTS
Model Plant
380,000 liters /day
CAd
CRAe
REFf
TO9
950,000 liters/day
CA
CRA
REF
TO
1,900,000 liters/day
CA
CRA
REF
TO
3,800,000 liters/day
CA
CRA
REF
TO
Energy ,
Consumed '
11,200
2,600
25,000
2,600
16,800
6,400
35,000
6,000
22,600
12,800
39,000
11,800
28,600
26,800
55,600
22,000
Energy
Recovered '
160,000
151,000
160,000
0
399,000
377,000
399,000
0
798,000
755,000
798,000
0
1,600,000
1,537,000
1,600,000
0
Energy
Impact
+ 149,000
+ 148,000
+ 135,000
2,600
+ 382,000
+ 371 ,000
+ 364,000
6,000
+ 775,000
+ 742,000
+ 759.000
11,800
+ 1,571,000
+ 1,510,000
+ 1,544,000
22,000
Energy units in liters of gasoline per year.
Energy consumed by the equipment per year.
cGasoline recovered by equipment per year. Gasoline =0.67 kg/liter,
35.6 MegaJoules/liter
CA = Carbon Adsorption.
eCRA = Compression-Refrigeration-Absorption.
fREF = Refrigeration.
9TO = Thermal Oxidation.
7-8
-------
efficiency of the CA system and the REF system. No energy recovery is
indicated for the TO system since no gasoline is recovered. No other
heat or energy recovery is associated with the current TO systems.
The energy impacts are positive (net energy is recovered) for the
CA, CRA, and REF systems. The net energy recovered, defined in liters
of gasoline per year, ranges from 135,000 liters/yr (36,000 gal/yr)
for the smaller terminals to 1,571,000 liters/yr (415,000 gal/yr) for
the larger terminals. This represents about 0.12 percent of the
gasoline throughput for the terminals.
The TO system yields a small negative energy impact since no
gasoline is recovered. Energy consumption ranges from the equivalent
of 2,600 liters/yr (690 gal/yr) of gasoline for the smaller terminals
to 22,000 liters/yr (5,800 gal/yr) of gasoline for the larger terminals.
The nationwide energy impacts of the regulatory alternatives,
shown in Table 7-4, were derived by assuming that all VOC emissions
reduction, as reported in Table 7-2, was recovered as liquid product,
and that one gallon of this liquid product was equivalent to one
gallon of gasoline. This assumption is considered reasonable in a
vapor-tight collection and processing system; although the recovered
product may not have the exact composition of gasoline, it would mix
with a large quantity of gasoline in a storage tank and be available
for loading into tank trucks. By subtracting the energy required to
operate the vapor processing equipment necessary to recover the liquid,
the net energy impact was determined. For purposes of the calculations,
it was assumed that half of the small affected facilities (one quarter
of all affected facilities) used thermal oxidation systems and that
the remainder used either the carbon adsorption, refrigeration, or
compression-refrigeration-absorption system (for Alternative II only).
A net energy savings would result from each of the alternatives
evaluated. A net energy savings for each alternative is projected
even though it is assumed that as many as half of the small new,
modified, or reconstructed terminals may install thermal oxidizer
systems, which do not recover energy and have a small negative energy
impact. As shown in Table 7-4, Alternative II would accomplish a net
fuel savings of 8 million liters (2.1 million gallons) of gasoline per
7-9
-------
TABLE 7-4. NATIONWIDE NET ENERGY IMPACTS
OF THE REGULATORY ALTERNATIVES*
Regulatory
Alternative 1985 1990
I 0 0
II + 8 million +14 million
III + 6 million +10 million
IV +9 million +16 million
aEnergy unit in net liters of gasoline recovered per year (energy
recovered minus energy consumed).
7-10
-------
year by 1985. Alternative III would recover a net 6 million liters
(1.6 million gallons) of gasoline per year by 1985. Because it results
in the greatest recovery of VOC, Alternative IV would result in the
greatest net energy savings. Alternative IV would recover a net
9 million liters (2.4 million gallons) of gasoline per year by 1985.
By 1990, Alternative IV would result in a net fuel savings of 16 million
liters (4.2 million gallons) of gasoline per year.
7.5 OTHER ENVIRONMENTAL IMPACTS
Other potential environmental impacts include noise, space
requirements, and availability of resources. The relative impacts of
the regulatory alternatives on these environmental concerns is expected
to be insignificant. An EPA test showed that the noise level from a
CRA unit, which created significantly more noise to the unprotected
ear than any other system encountered, was less than 70 db at 7 meters
5
from the noise source. The alternatives cause only minimum impacts
due to space requirements and resources availability.
7-11
-------
7.6 REFERENCES
1. U.S. Department of Energy. Annual Report to Congress 1978.
Volume Three, Supplement One. Midterm Energy Projections for the
United States. Washington, D.C. Publication No. DOE/EIA-0173/3-S1.
July 9, 1979.
2. Amoco Oil Company. Demonstration of Reduced Hydrocarbon Emissions
from Gasoline Loading Terminals. U.S. Environmental Protection
Agency. Washington, D.C. Publication No. EPA-650/2-75-042. June
1975. 51 p.
3. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Teasley, Glenn, Baker-Perkins. October 12, 1979. Information
on carbon adsorption system.
4. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Schmidt, Ed, HydroTech Engineering, Incorporated. November 7,
1979. Information on carbon adsorption system.
5. 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, NC. Contract No. 68-02-1407. Project
No. 76-GAS-17. September 1976. 97 p.
7-12
-------
8.0 ECONOMIC IMPACT
8.1 INDUSTRY CHARACTERIZATION
8.1.1 General Profile
8.1.1.1 Gasoline Distribution System. The gasoline marketing
network consists of all the storage and transfer elements which move
gasoline from its production stages to its end consumption. The
network includes tanker ships and barges, pipelines, tank trucks and
railcars, and storage tanks. Almost all of the gasoline consumed in
the U.S. is produced in domestic refineries, with less than 3 percent
being imported. Crude petroleum is shipped to refineries, which
manufacture the wide range of liquid petroleum products. Finished
gasoline is then distributed in a complex system comprised of whole-
sale and retail outlets. Figure 8-1 depicts the main elements in the
marketing network.
Gasoline is delivered to bulk terminals from refineries by way of
pipeline, tanker, or barge. Large transport trucks (15,000 to 38,000
liter, or 4,000 to 10,000 gallon capacity) deliver the gasoline to
service stations or to intermediate bulk storage areas known as bulk
stations, or bulk plants. Generally, a terminal is defined as any
bulk wholesale gasoline marketing outlet which receives product by
pipeline, ship, or barge, and delivers it in tank trucks to customers.
A bulk plant typically receives product by truck and has a smaller
storage capacity than a terminal. In addition, daily product throughput
at a typical terminal is much greater, averaging about 950,000 liters
(250,000 gallons), in contrast to about 15,000 liters (4,000 gallons)
for a typical bulk plant.
Both bulk terminals and bulk plants deliver gasoline to private,
commercial, and retail accounts. Bulk plants, using 5,700 to 11,000
liter (1,500 £o 2,900 gallon) capacity delivery trucks, service
8-1
-------
Imported
Gasoline
Bulk
Terminal
Imported
or
Domestic
Crude
Wholesale
Distribution
Level
Commercial,
Rural
Consumer
Figure 8-1. Gasoline Distribution in the U.S.
I I = Storage
= Transport
8-2
-------
primarily agricultural accounts and service stations that are either
long distances from terminals or inaccessible to the large transports.
In 1978, approximately 60 percent of gasoline delivered to service
stations came from terminals and 40 percent came from bulk plants.
The trend in recent years has been toward more terminal deliveries at
the expense of bulk plant deliveries. Retail and commercial level
businesses include the familiar service stations, as well as commercial
accounts such as fleet services (rental car agencies, private companies,
governmental agencies), parking garages, and large agricultural accounts.
Another important consumer category is about 2.7 million small farms.
8.1.1.2 Bulk Terminal Population. There are presently (1978) an
estimated 1,751 bulk terminals in the United States, representing a
total storage capacity for petroleum products of 123 million m
o
(771 million barrels). This represents a decline of 9 percent from
the 1,925 terminals identified by the Bureau of the Census in 1972.
Approximately 45 percent of these terminals receive products from
refineries by pipeline, while the remaining 55 percent receive by
tanker or barge. An estimated 1,511 bulk terminals, or 86 percent of
the total population, store gasoline and have a combined gasoline
storage capacity of 47 million m (296 million barrels), or 38 percent
A
of the storage capacity of all bulk terminals. Marine (tanker or
3
barge delivery) terminals store approximately 30 million m (187 million
barrels), or 63 percent of the stored gasoline, with the remaining
37 percent handled by pipeline terminals. Terminals not storing
gasoline may specialize in distillate, residual, or bunker fuel.
Several terminals located in the northern states distribute only home
heating oil. Table 8-1 shows the terminal population and storage
capacity distribution by Petroleum Administration for Defense District
(PADD). Figure 8-2 illustrates the locations of the PADDs.
Most terminals are located in PADDs I and II; i.e., along the
east coast and in the Midwest. PADD I contains 43 percent of all bulk
terminals and 43 percent of the gasoline terminals. PADD II has
24 percent of all terminals and 23 percent of the gasoline terminals.
PADD I received 85 percent of all petroleum products imported into the
U.S. in 1978'and 82 percent of all imported gasoline. By contrast,
8-3
-------
Table 8-1. 1978 BULK TERMINAL POPULATION6
PADD
I
II
III
IV
V
All Petroleum Terminals
Number of
Termi nal s
745
429
276
39
262
TOTAL 1,751
Percent
of Total
43
24
16
2
15
100
Total
Storage Capacity
1,000 m3
64,166
25,152
20,066
1,151
11,987
122,522
(1,000 Bbl)
(403,633)
(158,219)
(126,223)
( 7,238)
( 75,403)
(770,716)
Percent
of Total
52
21
16
1
10
100
Terminals Storing Gasoline
Number of
Terminals
657
343
234
39
238
1,511
Percent
of Total
43
23
15
3
16
100
Gasoline
Storage Capacity
1,000 m3
23,812
9,874
8,227
674
4,516
47,103
(1,000 Bbl)
(149,792)
( 62,115)
( 51,753)
( 4,240)
( 28,408)
(296,308)
Percent
of Total
51
21
17
1
10
100
00
1,000 m3 = 106 liters
-------
(Inc/. Alaska
and Hawaii)
oo
i
in
Figure 8-2. Petroleum Administration for Defense Districts
-------
PADD I was responsible for only 12 percent of the total refinery
production and for 11 percent of the total gasoline production.
Together, PADDs I and II received almost all of the inter-PADD shipments
originating in PADD III. Table 8-2 shows the regional total petroleum
product supply and demand figures for 1978.
8.1.1.3 Terminal Size. While the total number of terminals in
the U.S. has decreased since 1972, total storage capacity increased
approximately 30 percent to 123 million m in 1978. This growth in
storage capacity has resulted from expansion of large terminals in
order to handle increasing product demand, and consolidation or closure
of smaller and less efficient facilities.
Due to the large number of terminals in PADDs I and II, they
account for most of the total product and gasoline storage. PADD I
has 52 percent of all storage and 51 percent of the gasoline storage;
PADD II has 21 percent of total and 21 percent of gasoline storage.
The largest segment of the bulk terminal population is composed
of smaller facilities. Almost half of all terminals have less than
30,000 m (200,000 barrels) of storage capacity; about 30 percent have
3
capacities between 30,000 and 95,000 m ; and 22 percent have capacities
over 95,000 m3 (600,000 barrels). For gasoline terminals, the figures
3
are 50 percent less than 30,000 m , 28 percent between 30,000 and
3 3
95,000 m , and 22 percent greater than 95,000 m . Table 8-3 shows the
distribution of terminals by storage capacity.
Another measure of a bulk terminal's size is its product through-
put volume, or the average volume of product delivered over a given
time period. The distribution of terminals by total product throughput
is fairly even across the selected throughput ranges (Table 8-4).
Approximately 36 percent of all terminals have a total product throughput
less than 640,000 liters/day, 27 percent have a throughput between
640,000 and 2,540,000 liters/day, and 37 percent have a throughput
greater than 2,540,000 liters/day. Almost half of the gasoline terminals,
48 percent, have a gasoline throughput less than 750,000 liters/day,
27 percent have a throughput between 750,000 and 1,510,000 liters/day,
and 25 percent have a throughput greater than 1,510,000 liters/day.
8-6
-------
Table 8-2. 1978 REGIONAL PRODUCT SUPPLY/DEMAND'
1,000 m3/day (1,000 Bbl/day)
CO
PADD
I
II
III
IV
V
Total
Demand
1,033 (6,498)
830 (5,219)
627 (3,942)
87 (547)
417 (2,621)
2,994 (18,835)
Inter-PADD Shipments
Ketinery
Output From I From II From III From IV
289 (1,815) — 10 (66) 493 (3,100) —
628 (3,950) 35 (220) -- 126 (791) 7 (42)
1,050 (6,602) -- 20 (126)
79 (498) -- 11 (68)
380 (2,392) — -- 13 (83) 11 (71)
2,426 (15,257)
From V Imports
266 (1,671)
21 (129)
0.5 (3) 3 (22)
2 (14) 2 (13)
19 (120)
311 (1,955)
Other
10 (66)
55 (347)
185 (1,163)
11 (67)
4 (28)
265 (1,671)
1,000 m3 = 106 liters
-------
Table 8-3. PETROLEUM BULK TERMINAL STORAGE DISTRIBUTION8
Total Storage Capacity
1,000 m3 (1,000 Bbl)
<30 (200)
30 (200) — 95 (600)
95 (600) — 160 (1,000)
>160 (1,000)
TOTAL
All Terminals
Number of Percent
Terminals of Total
834 48
534 30
215 12
168 10
1,751 100
Terminals Storing
Gasoline
Number of Percent
Terminals of Total
764 50
423 28
192 13
132 9
1,511 100
1,000 m3 = 106 liters
8-8
-------
Table 8-4. PETROLEUM BULK TERMINAL THROUGHPUT DISTRIBUTION9
00
I
10
All Terminals
Average Product
1,000 4/day (1,
<640 (170)
640 (170) - 2,
2,540 (670) -
>7,000 (1,850)
Throughput
000 gal /day)
540 (670)
7,000 (1,850)
TOTAL
Number of
Terminals
626
475
375
275
1,751
Percent
of
Total
36
27
21
16
100
Terminals Storing
Average Gasoline Throughput
1,000 4 /day (1,000 gal /day)
<750 (200)
750 (200) —
1,510 (400)
>2,270 (600)
1,510
— 2,270
TOTAL
(400)
(600)
Gasoline
Number of
Terminals
728
401
312
70
1,511
Percent
of
Total
48
27
21
4
100
-------
8.1.1.4 Ownership. Major oil companies* own most of the bulk
terminals. Their ownership share includes 67 percent of all terminals
and 72 percent of the gasoline terminals (Table 8-5). Independents,
which includes wholesale/marketers, jobbers** and bulk liquid ware-
housers,*** own 33 percent of all facilities and 28 percent of those
handling gasoline.
The majors own the greatest number of bulk terminals within each
gasoline throughput range (Table 8-6). The majors also own a dispro-
portionately greater number of the largest bulk terminals. While the
majors own 72 percent of all gasoline terminals, they own 77 percent
3
of the terminals having a storage capacity between 95,000 and 159,000 m
and 78 percent of the facilities with greater than 159,000 m of
storage capacity, but only 60 percent of the smallest terminals having
less than 32,000 m . The independents, which own 28 percent of all
gasoline bulk terminals, own 42 percent of the smallest terminals,
3
i.e., total storage less than 32,000 m , and only 22 percent of the
3
largest facilities; i.e., storage greater than 95,000 m .
8.1.1.5 Employment. Bulk terminal employment declined from
40,220 in 1972 to 35,700 in 1978, a decrease of 11 percent. Employ-
ment at terminals storing gasoline was estimated to be 30,830, or
86 percent of the total employment, in 1978. PADDs I and II account
for 77 percent of the total employment at all terminals and 76 percent
of the employment at gasoline terminals. Table 8-7 shows regional
employment figures for bulk terminals.
*Includes regional refiner/marketers. Majors are defined as a
fully-integrated company which markets in at least 21 states. A
regional refiner/marketer is a semi-integrated company, with at
least one refinery, which generally markets in fewer than 21 states.
**A jobber is a petroleum distributor who purchases refined product
from a refiner or terminal operator for the purpose of reselling to
retail outlets, commercial accounts or reselling through his own
retail outlets.
***Bulk liquid warehousers only store products at their facilities for
a fee ($/gallon) and do not engage in any marketing activity.
8-10
-------
Table 8-5. PETROLEUM BULK TERMINAL OWNERSHIP10
Ownership
Segment
Majors
Independents
Total
All
Terminals
Number of Percent
Terminals of Total
1,170
581
1,751
67
33
100
Terminals
Gasol
Number of
Terminals
1,086
425
1,511
Storing
ine
Percent
of Total
72
28
100
8-11
-------
Table 8-6. GASOLINE TERMINAL DISTRIBUTION BY SIZE AND OWNERSHIP11
Percent of Total Terminals
Storing Gasoline
Total Number
Total Storage Capacity percent
o of Storing
1,000m (1,000 Bbl) Majors Independents Total Gasoline
<30 (200) 30 21 50 764
30 (200)— 95 (600) 25 3 28 423
95 (600) — 160 (1,000) 10 3 13 192
>160 (1,000) J_ 2 9 132
TOTAL 72 28 100
Total Number of
Gasoline Terminals 1,086 425 1,511
1,000 m3 = 106 liters
8-12
-------
Table 8-7. PETROLEUM BULK TERMINAL EMPLOYMENT
•12
PADD
I
II
III
IV
V
Total
All
Employment
19,280
7,850
4,460
440
3,670
35,700
Terminals
Percent
of Total
55
22
12
1
10
100
Terminals Storing
Employment
17,000
6,280
3,770
440
3,340
30,830
Gasoline
Percent
of Total
56
20
12
1
11
100
8-13
-------
8.1.2 Trends
8.1.2.1 Gasoline Supply and Demand. The demand for the services
of gasoline bulk terminals is linked directly to the demand for gasoline
in the U.S. economy; i.e., to gasoline consumption. Gasoline consumption
is part of a complex equation involving such elements as vehicle
population, suburbanization, recreational trends, gasoline costs, and
the general state of the economy. Currently these elements are in a
state of rapid change.
Gasoline is used almost entirely for motor vehicles, and is by
far the most important energy input to transportation, accounting for
13
over 69 percent of the total in 1977. Domestic demand for gasoline,
as may be expected, has increased continuously since the end of World
War II and the beginning of the "car culture." Consumption went from
410 million liters per day (Ml/day) in 1950, to 650 Ml/day in 1960, to
920 Ml/day in 1970, and reached more than 1,170 Ml/day in 1978.14'15
Forecasts of total domestic gasoline demand for the years 1985
and 1990 have been made by the U.S. Department of Energy (DOE).
Several scenarios, with different supply, demand, and pricing assump-
tions, have been analyzed by DOE and tabulated for each of the DOE
demand regions shown in Figure 8-3. Three of these DOE projection
series were judged as most likely and averaged to obtain forecasts of
gasoline demand for the years 1985 and 1990. Table 8-8 lists the
three projection series and indicates the major assumptions used in
the analysis. Table 8-9 presents the actual gasoline consumption in
the U.S. for 1978 and the calculated demand forecasts. These fore-
casts indicate a gradual decrease in demand in the 1980's, with the
projected demand for 1985 being quite close to its 1974 value of
1,030 Ml/day. This similarity is due almost entirely to the assumption
of a possible 26 miles per gallon (mpg) standard for the average new
automobile by 1985. This would create an average consumption rate for
all cars of 19.8 mpg. Another factor influencing the expected decline
in the rate of growth of gasoline demand is the shift toward greater
usage of diesel engines in cars and small trucks. In the absence of
the 26 mpg standard, demand for gasoline in 1985 could be somewhat
higher than in 1974. Table 8-10 shows the various components affecting
highway gasoline use.
8-14
-------
00
en
Regions
1. New England
2. New York/New Jersey
3. Mid Atlantic
4. South Atlantic
5. Midwest
6. Southwest
7. Central
8. North Central
9. West
10. Northwest
Figure 8-3. DOE Demand Regions
-------
Table 8-8. DOE PROJECTION SERIES
Series Oil
Designation Supply Demand Import Price
Low High Higha
C-High Medium Medium Higha
Low Low Medium
a!985 - $21.50 per barrel
1990 — $23.50 per barrel
}1985 — $17.00 per barrel
1990 — $21.00 per barrel
8-16
-------
Table 8-9. REGIONAL GASOLINE CONSUMPTION AND DEMAND FORECASTS
1,000 m3/day (1,000 Bbl/day)
DOE
Demand
Region
Demand Forecast
1978 Gasoline Consumption
15
1985
1990
1
2
3
4
5
6
7
8
9
10
TOTAL
58.2 ( 366)
101 ( 634)
120 ( 755)
218 (1,374)
251 (1,576)
156 ( 982)
74.5 ( 469)
44.1 ( 277)
143 ( 901)
47.2 ( 297)
1,213 (7,630)
49.8 ( 313)
81.7 ( 514)
102.1 ( 642)
195.8 (1,232)
204.2 (1,285)
133.5 ( 840)
61.5 ( 387)
36.7 ( 231)
123.7 ( 778)
37.2 ( 234)
1,026 (6,456)
48.6 ( 306)
78.0 ( 491)
100.2 ( 630)
199.3 (1,254)
197.6 (1,243)
182.1 (1,145)
59.4 ( 374)
36.6 ( 230)
122.3 ( 769)
37.2 ( 234)
1,061 (6,676)
1,000 m3 = 106 liters
8-17
-------
Table 8-10. COMPONENTS OF HIGHWAY GASOLINE USE17
Passenger Cars 1960 1972 1974 1985a
Number of Vehicles
(Thousands) 62,300 96,900 104,900 131,100
Average Annual
Kilometers-Driven 15,208 16,383 15,272 18,153
(Miles) (9,450) (10,180) (9,490) (11,280)
Kilometers Per Liter 6.08 5.74 5.74 8.42
(Miles Per Gallon) (14.3) (13.5) (13.5) (19.8)
Total Fuel Used —
Million m3 155.9 276.6 279.3 282.8
(Million Barrels) (981.0) (1,740) (1,757) (1,779)
Projection
Million m3 = 109 liters
8-18
-------
Total U.S. demand for petroleum products topped 3.34 million
3
m /day (21.0 million barrels/day) in the early part of 1979. By
August 1979, this figure had dropped nearly 14 percent to 2.88 million
3
m /day (18.1 million barrels/day). At the same time, total refinery
3
capacity stood at 2.81 million m /day (17.7 million barrels/day), with
18
an operating ratio of 86.5 percent. These figures indicate a disparity
between petroleum product demand and actual domestic production.
Refiners have expressed hesitation concerning expansion of their
facilities because of the expected stabilization in gasoline demand in
the 1980's. In addition, environmental costs and the uncertain economic
outlook have been cited as reasons to forego expansion and new con-
struction plans.
Petroleum imports declined 6 percent from 1978 to early 1979, and
this trend could continue as OPEC and other countries continue restrictive
export and pricing policies. The increase in petroleum product consumption
during the same period was met by inventory drawdowns and by higher
North Slope (Alaska) production.
The demand for gasoline in the U.S. has been historically relatively
unresponsive to price. In 1973, with the average regular leaded
gasoline retail price at 10.2
-------
Table 8-11. REGIONAL GASOLINE PRODUCTION AND SUPPLY FORECASTS
1,000 m3/day (1,000 Bbl/day)
PADD
I
II
III
IV
V
Total
Domestic
Supply
Imports
OA
1978 Gasoline Production u
117 (733)
312 (1,962)
402 (2,529)
35.0 (220)
157 (989)
1,023 (6,433)
31.2 (196)
Supply Forecast (Domestic Refineries/
1985
109 (689)
322 (2,024)
386 (2,427)
36.8 (231)
161 (1,012)
1,015 (6,383)
72.6 (457)
1990
131 (822)
312 (1,960)
364 (2,288)
36.6 (231)
160 (1,003)
1,004 (6,304)
73.0 (459)
00
no
o
1,000 m3 = 106 liters
-------
8.1.2.2 Terminal Recent Trends. Beginning about 1970, oil
companies began to view their refining and marketing operations as
separate profit centers to be judged on "stand alone" economics.
Terminals are now expected to recover all operating expenses as well
as to provide an acceptable return on capital. The former practice of
subsidizing market activities by means of other operations gave way to
this new economic outlook. This trend was accelerated by the Oil
Embargo of 1973-74.
"Stand alone" economics has caused petroleum marketers, both
majors and independents, to review their marketing strengths and
reconsider their overall distribution strategies. As a result, many
uneconomical storage facilities have been closed or consolidated into
larger and more profitable facilities. When several terminals compete
for business within the same area of distribution, the largest, and
presumably most efficient installations have a competitive edge over
their smaller neighbors. In addition, terminals receiving product by
pipeline gain an advantage by eliminating the costs associated with
barge or tanker docking and unloading facilities.
The terminal population decreased by 9 percent from 1972 to 1978
(Section 8.1.1.2). The primary reasons are based on profitability
considerations, or "stand alone" economics. At the same time, total
storage capacity has increased by 30 percent during the same time
period, due to consolidation and expansion of existing terminals.
Employment at bulk terminals declined 11 percent, as the efficiency of
terminals was increased by expansion and the installation of modernized
equipment.
Loading racks have been converted at many facilities from top
loading to bottom loading. Accompanying this change, vapor recovery
systems have been installed or modernized. This trend is continuing
as states revise their VOC emission regulations.
8.1.2.3 Terminal Future Trends. Future trends in the bulk
terminal industry are toward further consolidation of existing facil-
ities, as economic considerations continue to dictate the necessity of
-• >
increasing efficiency. The relatively small number of new terminals
and new distribution markets expected to open up in the next 10 years
8-21
-------
is in keeping with the gasoline demand projections cited earlier. The
estimated number of new facilities, as well as the number which will
be affected due to modification or reconstruction, for the years 1982,
1985, and 1990 are presented in Table 8-12. The expected sizes of
these terminals are expressed in terms of the daily gasoline throughputs
used to define the model plants. These estimates are based primarily
on information obtained from oil companies through Section 114 letter
requests. Examples of modifications and reconstructions to terminals
which will make them subject to affected facility determination are
discussed in Section 5.2 of Chapter 5. Some of the new terminals will
be erected to replace existing facilities or groups of facilities. The
only DOE demand region showing a projected demand increase between 1978
and 1990 (16.7 percent) is Region No. 6 (Southwest), so new facilities
are likely to be erected in that Region. The smallest decrease in demand
(8.6 percent) is projected for Region No. 4 (South Atlantic).
8.1.3 Tank Truck Industry
8.1.3.1 Industry Structure. The trucking industry generally
consists of two major groups, for-hire and private. Private carriers
are firms which transport their own goods in their own trucks. Examples
of private carriers are the oil companies which utilize their own tank
trucks to deliver gasoline from their terminals. For-hire carriers
transport freight which belongs to others, renting out the hauling
services of their trucks.
8.1.3.2 Vehicle Population. The tank vehicles used for transporting
gasoline from bulk terminals are classified into three types: straight
truck, semi-trailer, and full trailer. It is estimated that of the
100,000 tank vehicles in flammable liquid service, 85,000 are used for
21
the delivery of gasoline. About 31 percent of the gasoline tank
vehicles, or 26,300 vehicles, are used at bulk terminals. Of these,
approximately 2,630 are straight trucks and 23,670 are one of the
22
trailer types. The remainder are smaller tank trucks used primarily
to transport gasoline from bulk plants. All types of tank vehicles
are referred to as tank trucks throughout the balance of this document.
Due to differences in construction, gasoline tank trucks can be
divided into three age categories. The establishment of motor carrier
23
regulations in 1967 by the Department of Transportation made retrofit
8-22
-------
Table 8-12. ESTIMATED NUMBER OF AFFECTED TERMINAL
FACILITIES IN VARIOUS YEARS9
Year
1982
1985
1990
Facility
Category
New
Modified/
Reconstructed
New
Modified/
Reconstructed
New
Modified/
Reconstructed
GASOLINE THROUGHPUT (//day)
380,000
0
10
0
25
0
50
950,000
1
5
2
13
3
25
1 ,900,000
1
5
2
12
4
25
3,800,000
0
0
1
0
3
0
Total
2
20
5
50
10
100
Totals represent cumulative number of affected facilities through the
years indicated.
8-23
-------
of newer tank trucks to a bottom loading or vapor recovery configuration
more practicable. The cost of retrofitting the older vehicles is
higher than the cost for newer vehicles, because provisions for conversion
have been incorporated in vehicles of recent construction. An estimated
breakdown of vehicles by date of construction is presented in Table 8-13.
Table 8-14 shows trends of tank truck age distribution by PADD as
measured by the census surveys of 1972 and 1977. This table demonstrates
the expected decrease in the number of older vehicles over this time
period. Since the average vehicle lifespan is about 13 years for tank
24
trailers, and 8 years for straight trucks, the number of pre-1967
vehicles is expected to be negligible by 1985.
Since tank trucks in non-attainment areas will already be bottom
loaded and contain vapor recovery provisions in order to comply with
SIP regulations, only those tank trucks operating in attainment areas
would be affected by the regulatory alternatives. It is conservatively
estimated that 7,360, or 28 percent, of the 26,300 tank trucks at bulk
terminals would be affected. This assumes that none of the gasoline
tank trucks at terminals in attainment areas would already contain
bottom loading and vapor recovery provisions, and that SIP regulations
would not apply in any attainment areas. While neither assumption is
entirely true, they are considered sufficiently accurate approximations.
Their effect is to magnify slightly the cost impact of converting tank
trucks.
There are approximately 423 bulk gasoline terminals (28 percent
of the 1,511 total) in attainment areas. It is estimated that there
will be 32 affected facilities (30 existing, 2 new) in attainment
areas by 1985. Therefore, 7.6 percent of the terminals in attainment
areas would come under the new regulations and the tank trucks operating
at these terminals would require retrofitting. The total number of
tank trucks thus affected would be about 7.6 percent of 7,360, or
558 tank trucks. Based on the number of terminal-operated tank trucks
assumed for the bulk terminal model plants (Table 6-2 of Chapter 6),
approximately 390 of the affected tank trucks would be operated by
for-hire tank truck firms. Table 8-15 shows the estimated number of
affected tank truck firms and tank truck conversions for each model
8-24
-------
Table 8-13. ESTIMATED AGE DISTRIBUTION OF GASOLINE
TANK TRUCKS AT BULK TERMINALS
Age
1976-1978
1967-1975
Pre-1967
Total
Straight
Trucks
500
1,870
260
2,630
Trailers
4,000
17,830
1,840
23,670
Total
4,500
19,700
2,100
26,300
8-25
-------
Table 8-14.
REGIONAL TRENDS IN GASOLINE DELIVERY TANK9 DISTRIBUTION
BY YEAR OF MANUFACTURE22'25
(Percent of Total)
00
w
en
Pre-1967
PADO
I
II
III
IV
V
Total
1972 Censusb
14.0
8.4
3.7
4.0
4.0
sd 34.2
1977 Census0
3.4
0.6
1.1
1.4
2.7
9.3
1967-1972
1972 Census6
28.2
19.2
8.5
5.2
4.7
65.8
1977 Census0
16.4
9.8
6.1
1.9
3.4
37.6
1973-75
1977 Census0
16.7
7.4
7.9
1.6
2.9
36.5
1976-78
1977 Census0
7.4
3.1
3.7
1.1
1.3
16.6
Overall Distribution
1972 Census6
42.3
27.6
12.2
9.2
8.7
100.0
1977 Census0
43.9
20.9
18.8
6.1
10.3
100.0
Includes straight truck and trailer delivery tanks of greater than 15,000 liter (4,000 gallon) capacity.
}Sample size = 1,161.
^Sample size = 622.
Sum of regional percentages not always equal to totals due to rounding.
-------
Table 8-15. ESTIMATED NUMBER OF AFFECTED TANK TRUCK
COMPANIES AND TANK TRUCKS IN VARIOUS YEARS3
YEAR
1982
1985
1990
CATEGORY
Companies
Tank Trucks
Companies
Tank Trucks
Companies
Tank Trucks
MODEL FIRM
1
6
10
16
35
32
70
2
3
20
7
50
14
100
3
3
40
7
105
14
210
4
2
80
4
200
8
400
TOTAL
14
150
34
390
68
780
Totals represent cumulative number of affected companies and tank truck
conversions to bottom loading and/or vapor recovery through the years
indicated.
8-27
-------
firm developed in Section 6.2.5 of Chapter 6. Section 8.2.3.1 discusses
tank truck conversion costs. The cost analysis for the for-hire tank
truck industry is contained in Section 8.2.5, and the economic impact
on this industry is assessed in Section 8.4.2.
8.1.3.3 Loading Methods and Vapor Recovery. A survey report to
21
EPA indicates that approximately 77.2 percent of tank trucks have
bottom loading capability, and 22.8 percent can only be top loaded
(see Section 3.2.2.3). The survey further reports that 70 percent of
those tanks for which data were available contain vapor collection
equipment. This percentage drops to 52 percent if it is conservatively
assumed that tanks for which data were not provided do not have vapor
recovery capability. This limited survey was based upon data on
approximately 1,900 tank trucks. Table 8-16 shows the percentage of
tanks with bottom loading and vapor recovery as a function of company
size.
8.2 COST ANALYSIS OF REGULATORY ALTERNATIVES
8.2.1 Introduction
Capital expenditures and annualized costs for the control of VOC
emissions from bulk gasoline terminal loading operations have been
estimated for 140 control options (combinations of facility classi-
fication, regulatory alternative, model plant size, and vapor control
unit type). Costs for new facilities are presented in Section 8.2.2.1,
and costs for existing facilities which undergo modification or recon-
struction are presented in Section 8.2.3.1. Five classifications of
affected facilities have been analyzed and are representative of all
the situations expected to be encountered under the new standard.
Cost tables are provided for the four model plant sizes with
gasoline throughputs of 380,000, 950,000, 1,900,000, and 3,800,000
liters per day (100,000, 250,000, 500,000, and 1,000,000 gallons per
day, respectively). The complete list of model plant parameters is
presented in Table 6-2; Section 6.2 of Chapter 6 explains in detail
the basis for the choice of model plant parameters. Costs have been
developed for Regulatory Alternatives II, III, and IV in areas where
the SIP emission control regulations are not in effect, since these
8-28
-------
Table 8-16. TANKS WITH BOTTOM LOADING AND VAPOR RECOVERY
AS A FUNCTION OF COMPANY SIZE?5
Number of
Tanks in
Company
1-4
5-10
11-49
>50
Total
Total
Tanks
43
79
316
1,501
1,939
Bottom Loading
With
27
57
208
1,182
1,474
Without
15
22
90
319
446
Total Tank Basis3
Percent
With
64
72
70
79
77
76
Vapor Recovery
With
19
69
177
746
1,011
Without
18
5
135
278
436
Percent
With
51
93
57
73
70
52
00
I
PO
Percentages assuming that tanks for which data were not available do not have bottom
loading or vapor recovery capabilities.
-------
situations would involve differential costs for an affected facility.
In addition, differential costs could accrue to a terminal in a non-
attainment area, which underwent modification or reconstruction.
Under Alternatives III and IV, which require an emission limit of 35
nig/liter, an existing vapor control unit that was capable of achieving
only the SIP control level of 80 mg/liter may have to be replaced with
a more efficient unit or supplemented with a secondary, or "add-on"
unit. For this analysis, the cases where a compression-refrigeration-
absorption (CRA) type control unit has been replaced with a carbon
adsorption (CA), thermal oxidizer (TO), or refrigeration (REF) type
unit, or has been supplemented with a CA or TO unit, have been examined.
The regulatory alternatives are presented in Table 6-4 and explained
in Section 6.3. of Chapter 6.
In developing costs for controlling VOC emissions at terminals,
specific cost information was obtained through plant visits, Section 114
letter responses, and telephone contacts with terminal operators,
equipment manufacturers, and contractors. Also, existing EPA and
other background information and reports were consulted. All costs
are provided in terms of mid-1979 dollars, having been adjusted for
inflationary effects, where appropriate. Costs were adjusted to a
common base by applying the June 1979 Chemical Engineering Plant Cost
Index.27
Most of the cost information received applies to existing facilities
and control installations. As discussed in Section 7.1, most affected
facilities (as defined in Chapter 5 and developed in Chapter 6) will
be so designated as a result of modification or reconstruction of
existing facilities, instead of the construction of new facilities.
Capital investment includes the purchase price of the vapor
control unit, the cost of installing the system, and the cost of
converting tank trucks or loading racks, as appropriate, to a vapor
recovery configuration. The costs involved in converting tank trucks
and racks from top loading to bottom loading are also included, because
there is no existing top loading vapor recovery system considered
capable of achieving the level of control required under the regulatory
alternatives. Also, a salvage cost credit is applied for the case
where an existing control unit is replaced with a more efficient unit.
8-30
-------
Annualized costs include the amortization of capital investment
and the incremental operating expenses associated with vapor control.
Additional items in the tables include gasoline recovery cost credits,
total yearly VOC controlled, and cost-effectiveness of each option (in
dollars expended per kilogram of VOC controlled). The costs involved
with complying with the regulations (performance testing and continuous
monitoring) are presented in Section 8.2.2.7.
8.2.2 New Facilities
8.2.2.1 Capital Investment. New facility differential costs
incurred in complying with the regulatory alternatives depend on
whether SIP regulations are already applicable to that facility. New
facilities constructed in previously regulated (generally non-attainment)
areas will undergo no additional costs as a result of any of the
regulatory alternatives. This is because the CA, TO, and REF systems
being installed to meet 80 mg/liter are essentially identical to those
systems which would be considered for a 35 mg/liter limit. Cost
estimates for new facilities in previously unregulated (attainment)
areas are presented in Tables 8-17 through 8-19. Notes for these
tables are contained on page 8-35. The following subsections describe
in detail the development of the capital investment costs.
8.2.2.1.1 Control equipment purchase cost. Equipment manufacturers
were contacted to obtain price quotations on vapor control units for
application at each of the model plants. The purchase costs of CA and
CRA type units represent information provided by a single source for
each type of unit, because only one manufacturer is known to be actively
28 29
marketing each of these types at this time. ' Costs of the TO and
REF type units represent the average of price quotations provided by
-in 31 3? 33 34
several makers of the units. *'31""'J'3"3* The cost of a suitable
vapor holder is included in the CRA unit cost because this device is
29
always included in a CRA system installation. Since the vapor
holder is only occasionally used with the other types of units, its
cost is not included for those systems. The CRA unit is not costed
under Regulatory Alternatives III and IV because test data indicate
that the 35 milligrams per liter emission limit cannot be achieved by
this unit. All equipment costs include the complete unit with all
8-31
-------
Table 8-17.
ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE II
(Thousands of Mid-1979 Dollars)
NEW FACILITY IN ATTAINMENT AREA
oo
i
co
Gasoline Throughput:
Vapor Processlnq Unit:
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Truck Vapor Recovery Cost
Annual Ooeratlng Cost
Electr1dtyf
Propane (Pilot)9
Ka1 ntenince
Operating Labor"
Carbon Replacement^
Subtotal (Direct Operating Cost}
Truck Maintenance1^
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($Ag)
380.000'f/day
CAa CRAb TOC REFd
160 140 90.0 143
136 119 76.5 122
6.0 6.0 6.0 6.0
6.6 1.5 1.5 14.7
2.0
7.0 11.8 4.2 12.0
3.4 3.4 3.4 3.4
1.0
18.0 16.7 11.1 30.1
0,5 0.5 0.5 0.5
60.4 53.0 34.5 54.2
25.5 25.5 - 25.5
53.4 44.7 46.1 59.3
101 101 101 101
0,53 0.44 0.46 0.59
950,000 //day
CAa CRAb TOC REFd
185 140 100 170
157 119 85.0 145
12.0 12.0 '12.0 12.0
9.9 3.8 3.7 20.3
3.6 --
8.2 12.0 4.8 14.4
3.4 3.4 3,4 3.4
1.5
23.0 ig,2 15.5 38.1
0.9 0.9 0.9 0.9
70.8 54.2 39.4 65.4
63.8 63.8 - 63.8
30.9 10.5 55.8 40.6
252 252 252 252
0.12 0.04 0.22 0.16
1,900,000 I/day
CAa ' CRAb TOC REF'
185 172 100 175
157 146 85.0 149
18.0 18.0 18.0 18.0
13.3 7.5 6,9 22.8
6.6
8.2 14.6 4.8 14.8
3.4 3.4 3.4 3.4
1.5
26.4 25. 5 21.7 41,0
1.4 1.4 1.4 1.4
72.0 67.2 40.6 63.4
128 128 — 128
-28.2 -33.9 63.7 -17.2
505 505 505 505
(k) (k) 0.33 !k)
3,800.000 f/djy_
1 CA8 CRAb TO0 REFd
225 200 115 220
191 170 97. S 187
40.0 40.0 '40.0 40.0
16.8 15.7 12.9 32.6
8.7 —
10.0 17.0 5.6 18.6
3.4 3.4 3,4 3.4
1.3
32.0 36.1 30.6 54.6
3.0 3.0 3.0 3.0
91.2 82.0 50.6 89.4
255 255 - 255
129 -134 84.2 -108
1,010 1,010 1,010 1,010
(k) (k) o.OS
-------
Table 8-18.
ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE III
(Thousands of Mid-1979 Dollars)
NEW FACILITY IN ATTAINMENT AREA
00
CO
CO
Gasoline Throughput:
Vapor Processing Unit:
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Truck Vapor Recovery Cost6
Annual Operating Costs
Electricity'
Propane (Pi lot) 9
Maintenance
'Operating Labor h
Carbon Replacement
Subtotal (Direct Operating Cost)
Truck Maintenance
Capital Charges
Gasoline Recovery (Credit)
Net Annual i zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380.000 I/day
CAa TOC REFd
160 90.0 143
136 76.5 122
6.0 6.0 6 0
6.6 1.5 14.7
2.0
7.0 4.2 12,0
3.4 3.4 3.4
1.0
18.0 "-I 30'1
*• *• --
60.4 34.5 54.2
20.7 « 20.7
57.7 45.6 63.6
82 32 82
0.70 0,56 0.78
950,000 f/day
CAa TOC REFd
185 100 170
157 05.0 145
12.0 12.0 12.0
9.9 3.7 20.3
3.6
8.2 4.8 14.4
3.4 3.4 3.4
1 .5
23.0 15.5 38.1
..
70.8 39.4 65,4
51.8 - 51.8
.42.0 54.9 51.7
205 205 205
0.20 0.27 0.25
1.900.000 f/day
CAa TOC REFd
185 100 175
157 85.0 149
18.0 18.0 18.0
13.3 6.9 22.8
6.6
8.2 4.8 14.8
3.4 3.4 3.4
1.5
26.4 21.7 41.0
72.0 40.6 63.4
104 - 104
.5.6 62.3 5.4
410 410 410
(k) 0.15 0.01
3.800.000 f/day
CAa TOC REFd
225 115 220
191 97.8 137
40.0 40.0 40.0
16.8 12.9 32.6
8.7
10,0 5.6 18.6
3.4 3.4 3.4
1.8
32.0 30.6 54.6
•• -» -»
91.2 50.6 89.4
207 - 207
-83.8 81.2 -63.0
820 820 820
(k) 0.10 (k)
-------
Table 8-19.
ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE
(Thousands of Mid-1979 Dollars)
NEW FACILITY IN ATTAINMENT AREA
IV
00
I
GO
Gasoline Throughput:
Vapor Processing Unit:
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Truck Vapor Recovery Cost6
Annual Operating Costs
Electricityf
Propane (Pilot)9
Maintenance
Operating Labor h
Carbon Replacement
Subtotal (Direct Operating Cost)
Truck Maintenance''
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380,000 f/day
CAa TOC REFd
160 90.0 143
136 76.5 122
6.0 6.0 6.0
6.6 1.5 14.7
2.0
7.0 4.2 12.0
3.4 3.4 3.4
1 .0
18.0 11.1 30.1
0.5 0.5 0.5
60.4 34.5 54.2
27.0 -- 27.0
51.9 46.1 57.8
107 107 107
0.49 0.43 0.'54
950.000 I/day
CAa TOC REFd
185 100 170
157 35.0 145
12.0 12.0 12.0
9.9 3.7 20.3
3.6
8.2 4.8 14.4
3.4 3.4 3.4
1.5
23.0 15.5 38.1
0.9 0.9 0.9
70.8 39.4 65.4
67.4 -- 67.4
27.3 55.8 37.0
267 267 267
0.10 0.21 0.4
1.900.000 '/day
CAa TOC REFd
185 100 175
157 85.0 149
18.0 18.0 18.0
13.3 6.9 22.3
6.6
8.2 4.8 14.8
3.4 3.4 3.4
1.5
26.4 21.7 41.0
1.4 1.4 1.4
72.0 40.6 68.4
135 -- 135
-35.2 63.7 -38.0
535 535 535
(k) 0.12 (k)
3,800,000 f/day
CAa TOC REFd
fiftf lie 99A
225 115 «Q
191 97,8 187
40.0 40.0 40.0
16.8 12.9 32.6
8.7
10.0 5.6 18.6
3.4 3.< 3.4
1.8
32.0 30.6 54.8
3.0 3.0 3.0
91.2 50.6 89.4
270 -- 270
-172 84.2 -151
i ,070 i ,070 i ,cro
(k) 0.08 (K)
-------
NOTES FOR TABLES 8-17 THROUGH 8-19
aCA = Carbon Adsorption Unit.
CRA = Compression-Refrigeration-Absorption Unit.
CTO = Thermal Oxidizer Unit.
i
dREF = Refrigeration Unit.
Additional cost required for vapor collection equipment on new tank
tank trucks.
Electricity costs are based on average consumption rates reported
by manufacturers.
^Propane for pilot estimated at 12.5 liters per hour based on
manufacturers' reported consumption.
Daily inspections at one hour per day, plus a monthly visual inspection
for liquid or vapor leaks in the vapor collection and processing
systems.
Estimated carbon replacement period is 10 years.
JCost to perform annual vapor-tight testing.
Average number of terminal-owned trucks:
380,000 liters/day 3
950,000 liters/day 6
1,900,000 liters/day 9
3,800,000 liters/day 20
L
Cost-effectiveness not calculated because net annualized cost is
a negative quantity (cost credit).
8-35
-------
controls, and generally a start-up service. Some REF units contain a
meter to monitor recovered product, and some TO units include vapor
stream saturators and aftercoolers in the system cost. Equipment
costs can be considered to represent the average cost for each type of
control system. Generally, piping runs, condensate tanks, and all
installation and service charges, including taxes, are separate expenses
and are included under installation costs. Figure 8-4 shows the
equipment purchase costs used in the cost tables. The exact figures
are shown in Tables 8-17 through 8-19. It should be noted that in
increasing the throughput by a factor of ten (from model plant 1 to
model plant 4), the average increase in the equipment purchase cost is
only about 42 percent.
8.2.2.1.2. Control equipment installation cost. The costs involved
in engineering, shipping, and installing a vapor control system account
for a major percentage of the total system cost. Most of the information
concerning these costs was obtained through Section 114 letter responses.
Due to the varying requirements of individual terminals, the costs of
installing control systems at different terminals cover a wide range.
Only cost information for which a breakdown by cost element was available
was used for determining the relative contribution of each element to
the total installation cost. The elements common to most installations
include engineering approvals, site preparation and concrete pad,
piping, electrical service, condensate tank, and a final category
which includes optional or variable equipment plus taxes, freight, and
contingencies. Best estimates of the contribution of each of these
cost elements are presented in Table 8-20. The range of values occur-
ing in the data received from terminal operators is also shown.
Just as the individual cost elements can vary widely, so also
does the total installation cost vary in actual installations. An
examination of the data received from terminal operators indicates
that the installation cost can be estimated as 85 percent of the
equipment purchase cost. The data used in this calculation represent
installation of CA, CRA, TO, and REF control units at terminals ranging
in size from 380,000 liters per day to 3,800,000 liters per day.
While these data represent the installation of new control units at
8-36
-------
00
to
CO
4-> r—
to i—
o o
O) C^
to r-
(0 cr.
.G i—
u i
s- -o
ex 'i
4-> 4-
C O
O)
tW
TJ
•r- C.
3 (O
cr to
UJ =3
o
250
200
150
100
50
0
380
O = GRA
O
A
TO
REF
I
950
1,900
250
200
150
100
50
0
3,800
Model Plant Size (Thousands of liters per day)
Figure 8-4. Control Equipment Purchase Costs
(Thousands of mid-1979 Dollars)
-------
Table 8-20. INSTALLATION COST ELEMENTS
Best Estimate
Contribution
to Total
Installation
Cost Element (Percent)
Engineering and approvals
Concrete Pad
Piping
Electrical Service
Condensate Tank
Other:
Flame Arresters and Check
Valves
Setting Unit
Freight
Taxes
Contingency Fund
TOTAL
20
15
15
15
10
5
5
3
4
8
100
Range
in Actual
Installations
(Percent)
17 to 28
5 to 30
3 to 39
8 to 27
1 to 25
a
a
a
a
a
Data range not available.
8-38
-------
existing terminals, it is assumed that the same cost elements also
represent installation costs at new terminals. Figure 8-5 illustrates
14 control system installations at terminals. These data do not
include the additional cost of purchasing new tank trucks with vapor
recovery provisions. This cost is discussed in the next subsection.
8.2.2.1.3 Tank truck vapor recovery. It is assumed that all new
terminals will purchase new, bottom loading tank trucks. Under Regulatory
Alternatives II, III, and IV these trucks will require vapor recovery
provisions. The added cost for a new tank truck with vapor recovery
provisions over one without these provisions is estimated from several
sources to be $400 per compartment, or $1,600 per four-compartment
35 36
truck. ' The additional equipment on a converted truck consists of
vapor collection hoods, P-V vents, and vapor collection lines for each
compartment, as well as an adapter for connection to a vapor return
line at the loading rack.
8.2.2.2 Annualized Costs. The annualized cost of a vapor control
installation is the total annual expenditure required to operate and
maintain the installation and is the sum of operating costs and capital
charges. Operating costs are the day-to-day expenses required to keep
the system in operation and include utilities, raw materials, maintenance
and repairs, and routine operating labor (such as daily inspections).
Another component of the operating cost is the cost of the annual tank
truck vapor-tight test (Regulatory Alternatives II and IV). Capital
charges include depreciation, taxes, insurance, and interest on borrowed
capital. Table 8-21 summarizes the cost factors used to produce the
annualized costs. Table 8-22 presents the calculation methods used in
determining the annualized costs.
All of the control units considered in this analysis consume
electric power in the course of their operation. Electricity is used
to power fans, dampers, pumps, compressors, relays, and timers. The
electrical consumption rate of each type of unit during operation was
obtained from control unit manufacturers. The actual hours-per-day
operating schedules of the units were determined from likely average
terminal loading schedules and fronv a limited amount of actual opera-
ting data. Some CA units remain in operation for up to two hours
8-39
-------
i en
1 DU
G
\ O)
-M (J
V) S-
co o *-> 85
1 'I- V)
4* ->->O
o «o o
1e c.
4->
-------
Table 8-21. COST FACTORS USED IN DEVELOPING ANNUALIZED COSTS
Utilities and Materials
Electricity
Propane
Replacement Carbon
Operating Labor
$0-06/kw-hr
$0.12/1 Her
$3.30/kg
$10/1abor hour
Maintenance (Percent of Equipment Cost)
Refrigeration 8 percent
CRA Vapor Recovery 8 percent
CA Vapor Recovery 4 percent
Thermal Oxidizer 4 percent
Capital Charges (Percent of Total Capital Cost)
Interest and Depreciation 16 percent
Property Taxes, Insurance, and Administration 4 percent
Recovered Gasoline Value
$0.17/1 Her
8-41
-------
Table 8-22. CALCULATION OF ANNUALIZED
COSTS OF VAPOR CONTROL UNITS
Cost Component
Method of Calculation
Direct Operating Costs
Utilities and Materials
Electricity
Propane (pilot)
Activated Carbon
Operating Labor
Maintenance
CA and TO Units
CRA and REF Units
Capital Charges
Gasoline Recovery (Credit)
Amount used per year x $0.06/kw-hr
Amount used per year x $0.12/liter
Amount replaced x $3.30/kg * 10 yrs
1 hr/day x 340 days/yr x $10.OO/
labor hour
4 percent of equipment purchase cost
8 percent of equipment purchase cost
Capital investment x (capital
recovery factor + 0.04)a
Amount recovered per year x $0.17/
liter
Capital recovery factor =
i (1 + T)"
_ ,
where i = interest rate = 0.10 (10 percent)
n = equipment economic life = 10 years
8-42
-------
after loading activity ceases, so they are likely to be in operation
the majority of the time at most terminals. The TO unit operates only
during actual loading activity. This time schedule was conservatively
estimated, based on the model plant parameters. For example, the
smallest model plant may operate up to
380,000 liters/day = 4 h /d
(32,200 liters/truck) (3 trucks/hr) H nrs/aay.
The REF unit operates on demand in order to maintain a low heat
exchanger temperature, and thus activates even when no loading is in
progress. This time period was estimated to be 12 hours per day for
all model plants. A value of $0.06 per kilowatt-hour was used, based
on values reported to EPA. Table 8-23 summarizes the operating parameters
used to calculate annual electrical costs.
Thermal oxidizer units require a pilot fuel source, generally
propane, with some units using natural gas or No. 2 fuel oil. Infor-
mation from manufacturers indicates that an average of 12.5 liters
(3.3 gallons) per hour of propane are consumed by TO units during
their operation. ' The propane wholesale cost, in mid-1979 dollars,
is approximately $0.12 per liter in transport load (34,600 liters)
quantities.
The working life of the activated carbon used in CA units has not
been determined. It is assumed in this analysis that an accumulated
"heel" will develop in the carbon beds and require that the carbon be
removed for recycling or disposal. One manufacturer has conducted
rapid cycle tests and has concluded the useful carbon life will be 20
years. However, since CA units have been operating commercially at
bulk terminals only since 1976, a conservative estimate of 10 years
carbon useful life has been used in preparing the cost analysis.
Carbon weights in each unit were supplied by the same manufacturer, as
was the price of $3.30 per kilogram for activated carbon. '
Operating labor for a vapor control unit consists of the labor
required to perform routine daily inspections of the unit, including
checking mejter readings, fluid levels, and the proper operation of
system components and making necessary adjustments or minor repairs.
8-43
-------
Table 8-23. ELECTRICAL CONSUMPTION AND
OPERATING SCHEDULES OF VAPOR CONTROL UNITS
Model
Plant
1
2
3
4
CA
23.2
32.5
32.5
37.4
Operating
Kilowatts
CRA TO
— 18.6
— '26.0
— 26.0
— 37.2
REF
60
83
93
133
CA
14
15
20
22
Operating
Schedule
(Hr/day)b
CRA TO
.__ 4
— 7
— 13
... 17
REF
12
12
12
12
Energy
Consumption
( kw-hr/day )c
CA CRA TO
325 74 74
487 185 182
650 370 338
823 770 632
REF
720
996
1,116
1,596
a • 28
CA unit: Data provided by single manufacturer -
CRA unit: Data provided as kw-hr/day.3'
TO and REF units: Average from several manufacturers .3^*31,33,34
CA unit: Data from actual operating experience and engineering judgment.
CRA unit: Data provided as kw-hr/day. 37
TO unit: Based on engineering judgment.
REF unit: Data from single manufacturer and engineering judgments"
CCRA unit: Data provided by single manufacturer.^
8-44
-------
Information obtained from terminal operators on plant visits indicates
that a routine checklist can be followed in 30-45 minutes, so an
estimate of one hour per day was used. Labor charges were provided
from the same sources as $10.00 per hour. Also included in this cost
is a monthly visual inspection of the vapor collection and processing
systems for liquid or vapor leaks.
Annual maintenance costs include major adjustment, repair, and
replacement items not covered in the category of operating labor.
Maintenance items include pump seal and compressor replacement,
replenishment of fluids, and burner, valve, relay, and timer replace-
ment. Some terminals contract an outside firm to perform all major
maintenance on a periodic or as-needed basis, while others perform
essentially all maintenance work in-house. Maintenance contracts on
refrigeration units have been reported to cost about $4,000 per year,
labor only, or $7,000 to $10,000, including labor and parts.31'42
Costs depend on whether a control unit is within the service area of
the contractor. Information from Section 114 letter responses indicates
that maintenance costs for the REF unit average about 8 percent of the
equipment purchase cost. Costs for the CRA type units are assumed to
also average 8 percent. Maintenance on the CA and TO type units have
been found to be lower, averaging about 4 percent of equipment cost.
These figures are variable, depending on the equipment manufacturer,
age, and quality of routine care. Other items affecting these figures
can include the level of activity of the terminal (unit operating
time) and the climate to which the unit is exposed.
In addition to maintenance costs attributable to the control
unit, a new facility will incur additional costs in maintaining the
vapor recovery equipment installed at the loading racks. The vapor
return line requires periodic replacement due to wear. These costs
are estimated to average $200 per rack annually, plus $200 per facility
for parts such as couplers.
Regulatory Alternatives II and IV require the owner or operator
of an affected terminal to restrict product loadings of gasoline tank
trucks to those which have passed an annual vapor-tight test. The
annual testing plus average repair cost has been estimated to total
8-45
-------
approximately $134 per tank truck (4 labor hours at $21 per hour, plus
$50 for materials). An estimate of $150/yr for each truck was
assumed in the cost analysis. Table 8-24 shows the cost for each
model plant to perform annual vapor-tight testing.
8.2.2.3 Gasoline Recovery Cost Credits. The CA, CRA, and REF
type vapor control units recover and liquify VOC vapors and return the
recovered product to storage. Cost credits for this recovered product
are calculated from the gasoline throughput, system leakage, and
degree of emission control achieved by the recovery unit.
As indicated in Section 6.3 of Chapter 6, the vapor-tight criteria,
as defined in the tank truck CTG, are expected to limit truck leakage
to an average of 10 percent. Alternative III, which does not restrict
loading to vapor-tight gasoline tank trucks, will result in 30 percent
leakage for the average delivery tank. The uncontrolled emission rate
is assumed to be 960 mg/liter (submerged loading, balance service).
All VOC vapors which are not exhausted from the control unit or lost
to the atmosphere through tank truck leakage are assumed to be recovered
as liquid product. For example, under Alternative II, the gasoline
recovery rate would be:
960 mg/liter - (0.10)(960 mg/liter) - 80 mg/liter = 784 mg/liter.
Calculations for Alternatives III and IV are performed in the same
manner. Recovery cost credits are calculated for each model plant by
using a density factor of 0.67 kg/liter for gasoline. The nationwide
average wholesale price for all grades of gasoline in mid-1979 was
45
approximately $0.17/liter. Table 8-25 presents the calculated
recovery cost credits for new facilities under Alternatives II, III,
and IV, for the four model plant sizes.
8.2.2.4 Total VOC Controlled. The rates at which VOC is controlled
during loading are calculated for each regulatory alternative and
model plant, and expressed in mg/liter and Mg/year. This quantity is
equivalent to the gasoline recovery rate, the calculation of which was
described in Section 8.2.2.3. Table 8-26 presents these data, which
are used in the calculation of cost-effectiveness.
8-46
-------
Table 8-24. ANNUALIZED TANK TRUCK VAPOR-TIGHT MAINTENANCE COSTS
(Thousands of Mid-1979 Dollars)
Number
Model Plant of Trucks3
380,000 £/day
950,000 4/day
1,900,000 £/day
3,800,000 £/day
3
6
9
20
Annual i zed Cost
0.5
0.9
1.4
3.0
aAverage from Section 114 letter responses, number of
tank trucks owned by terminal.
8-47
-------
Table 8-25. GASOLINE RECOVERY CREDITS
(Thousands of Mid-1979 Dollars)
00
I
00
Regulatory
Alternative
II
III
IV
Controlled
Emissions
(mg/l )
80
35
35
Tank Truck
Leakage
(Percent)
10
30
10
Gasoline
Recovered
(mg/f)
784
637
829
Recovery Credit ($000)
Model Plant
la 2b 3C 4d
25.5
20.7
27.0
63.8
51.8
67.4
128
104
135
255
207
270
^Throughput = 380,000 -0/day ( 100,000 gal/day)
throughput = 950,000 £/day ( 250,000 gal/day)
Throughput = 1,900,000 H/day ( 500,000 gal/day)
^Throughput = 3,800,000 t/day (1,000,000 gal /day)
-------
Table 8-26. INCREMENTAL VOC CONTROLLED
Model Plant
la
KGyiiiutory
Alternative mg/£ Mg/yr
II 784 101
III 637 82
IV 829 107
III and IV 45.0 5.8
(Replacement
or add-on
control unit
only)
2b
mg/£ Mg/yr
784 252
637 205
829 267
45.0 14.5
3C
mg/e Mg/yr
784 505
637 410
829 535
45.0 29.0
4d
mg/2 Mg/yr
784 1,010
637 820
829 1,070
45.0 57.9
throughput = 380,000 £/day ( 100,000 gal/day)
throughput = 950,000 9. /day ( 250,000 gal/day)
throughput = 1,900,000 I/day ( 500,000 gal/day)
throughput = 3,800,000 2/day (1,000,000 gal/day)
8-49
-------
8.2.2.5 Cost-Effectiveness. The cost-effectiveness of a control
option is the quotient derived by division of the annualized cost of
the option by the annual amount of emission reduction realized by
exercise of the option. The calculated cost-effectiveness for each
control option is presented in Table 8-27. In several cases, due to
the effect of the gasoline recovery cost credit, a net positive cost
benefit accrues to a terminal. Generally, Regulatory Alternative IV
has the best cost-effectiveness (lowest expenditure per unit of control),
as a result of having the largest recovery credit.
8.2.2.6 Base Cost of Facility. Section 114 letter responses
provided most of the information for this cost analysis concerning the
base cost of a new facility and the operating and maintenance costs of
such a facility. The largest single cost component involved in the
construction of a terminal facility is the cost of storage tanks. The
cost of tanks ranges from 25 to 50 percent of the total cost. Other
principal cost components include land, tank trucks, loading racks,
spill containment, and fire protection. Table 8-28 presents the range
of contributions to the total base cost of each cost component, as
well as the best estimate of the average percentage value. The total
base cost estimates for the model plants are as follows:
1. 380,000 I/day - $2.6 million
2. 950,000 1/day - $4.0 million
3. 1,900,000 I/day - $5.9 million
4. 3,800,000 1/day - $9.7 million
Due to the limited amount of data available concerning the cost
of new terminals, these costs are considered estimates only and can be
affected significantly by geographical location and the nature of the
equipment installed at the terminal.
Annual operating expenses at a terminal depend on product supply
method, geographical location, location in a distribution network, and
other factors. Cost elements typically include salaries and benefits,
utilities, maintenance (14 to 17 percent) and taxes and insurance.
Annual operating expenses for the model plants are estimated to be:
1. 380,000 I/day - $120,000
2. 950,000 I/day - $300,000
8-50
-------
Table 8-27. COST-EFFECTIVENESS OF CONTROL OPTIONS — NEW FACILITIES
(Dollars/Kg VOC Controlled)
00
I
en
Alternative
II
III
IV
Model Plants and Control Unit Types
380,000 f/day
CA CRA TO REF
0,53 0.44 0.46 0.59
0.71 t 0.56 0.78
0.49 b 0.43 0.54
950,000 f/day
CA CRA TO REF
0.12 0.04 0.22 0.16
0.21 b 0.27 0.25
0.10 t 0.21 0.14
1,900,000 P/day
CA CRA TO REF
a a 0.13 a
a b 0.15 0.01
a b 0.12 a
3,800,000 f/day
CA CRA TO REF
a a 0.08 a
a b 0.10 a
a b 0.08 a
Indicates a negative net annuallzed cost, or cost credit,
bNot applicable to the CRA type control unit,
-------
Table 8-28. FACILITY BASE COST COMPONENTS
(Thousands of Mid-1979 Dollars)
Cost
Component
Land
Storage Tanks
Loading Racks
Buildings
Spill Containment
Tank Trucks
General
Relative Contribution
Range (percent)
8 to 24
25 to 50
2 to 6
1 to 10
2 to 3
0 to 20
22 - 69
Best Estimate
Average (percent)
12
37
5
3
3
16
24
a
fencing, etc.
8-52
-------
3. 1,900,000 I/day - $600,000
4. 3,800,000 I/day - $1,200,000
Data were obtained for model plants 2 and 3 and were extrapolated to
model plants 1 and 4 based on the throughput ratio.
Loading rack operating expenses include these principal items:
Meter calibration and repair, loading arm repairs and replacement of
couplers, fittings, gaskets, and seals. These items apply to loading
racks without vapor recovery provisions, and include both top and
bottom loading racks. The average reported cost to maintain a loading
rack is $7,500 per year.
8.2.3 Modi fied/Reconstructed Faci1ities
8.2.3.1 Capital Investment. Most applications of additional
standards for bulk gasoline terminals are expected to involve modified
or reconstructed facilities instead of newly constructed facilities.
Differential costs will be incurred in complying with Regulatory
Alternatives II, III, or IV. Alternative I is the baseline of control,
which represents compliance with SIP regulations, so no differential
costs are involved. Tables 8-29 through 8-36 present tabular costs
similar to those presented for new facilities in Section 8.2.2.
The control unit purchase costs are the same as those quoted for
new facilities, because the same units are used in both situations.
Table 8-36 presents an exception for the case of add-on control units.
The CA type add-on unit has a lower cost than the primary CA unit.
The cost of a TO add-on unit suitable for achieving the emission
limits under Alternatives III and IV is assumed to be equivalent to
46 47
the cost of a primary TO unit, based on information from manufacturers. *
The installation cost averages about 85 percent of the equipment
purchase cost (Section 8.2.2.1.2).
A top loaded terminal requires conversion of loading racks to
bottom loading and vapor recovery in order to achieve the required
emission limits. Section 114 letter responses indicate this cost to
average $160,000 per rack position. The tank trucks owned by a bottom
loading terminal will require retrofit to install provisions for vapor
recovery. The cost of these truck, conversions varies with the age of
the truck, due to the different types of construction used (see
8-53
-------
Table 8-29. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE II
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, BOTTOM LOADED —ATTAINMENT AREA
Gasoline Throughput;
Vapor Processing Unit:
Caoital Investment
Unit Purchase Cost
Unit Installation Cost
Truck Vapor Recovery Cost111
Annual Operating Cost
Electricityf
Propane (Pilot)9
Maintenance
Operating Labor*1
Carbon Replacement*
Subtotal (Direct Operating Cost)
Truck Maintenance1'
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380,000 i/day
CAa CRA6 TOC REFd
160 140 90.0 143
136 119 76.6 122
7.2 7.2 7.2 7.2
6.6 1.5 1.5 14.7
2.0
7.0 11.8 4.2 12.0
3.4 3.4 3.4 3.4
1.0
18.0 16.7 11. 1 30.1
0.5 0.5 0.5 0.5
60.6 53.2 34.7 54.4
25.5 25.5 -. 25.5
53.6 44.9 46.3 59.5
101 101 101 101
0.53 0.44 0.46 0.59
950,000 £/day
CAa CRAb TOC REFd
185 140 100 170
157 119 85.0 145
14.4 14.4 '14.4 14.4
9.9 3.8 3.7 20.3
3.6
8.2 12.0 4.8 14.4
3.4 3.4 3.4 3.4
1.5 --
23.0 19.2 15.5 38.1
0.9 0.9 0.9 0.9
71.3 54.7 39.9 65,9
63.8 63.8 - 63.8
31.4 11.0 56.3 41.1
252 252 252 252
0.12 0.04 0.22 0.16
1,900,000 e/day
CAa CRAb TOC 8EFd
185 172 100 175
157 146 85.0 149
21.6 21.6 21.6 21.6
13.3 7,5 6.9 22.8
6.6
8.2 14.6 4.8 14.8
1.5
26.4 25.5 21.7 41.0
1.4' 1.4 1.4 1.4
72.7 67.9 41.3 69.1
28 128 -- 128
27^5 -33.2 64.2 -17.8
05 505 505 505
P)- (P> 0.13 "(p)
3.800,000 //day
CAa CRAb TOC REFd
225 200 115 220
191 170 97.8 187
43.0 48.0 '48.0 48.0
16.8 15.7 12.9 32.6
8.7
10.0 17.0 5.6 18.6
1.8
32.0 36.1 30.6 54.6
3,0 3.0 3.0 3.0
92.8 83.6 52.2 91.0
255 255 « 255
127 -132 85.8 -106
,010 1,010 1,010 1,010
(?) (p) 0.03 (p)
00
01
•f*
-------
Table 8-30. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE III
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, BOTTOM LOADED —ATTAINMENT AREA
Gasoline Throughput:
Vapor Processing Unlti
Capital Investment
Unit Purchase Cost
Unit Installation Cost
k
Truck Vapor Recovery Cost
Annual Operating Costs
Elcctr1dtyf
Propane (Pilot)9
t
Maintenance
Operating Labor
Carbon Replacement
Subtotal (Direct Operating Cost)
Truck Maintenance1'
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380,000 f/day
CAa TOC REFd
160 90.0 143
136 76.5 122
7.2 7.2 7.2
6.6 1.5 14.7
2.0
7.0 4.2 12.0
3.4 3.4 3.4
1.0
18.0 14.6 30.1
.. ..
60.6 34.7 54.4
20.7 -- 20.7
57.9 49.3 63.8
82 32 82
0.71 0.61 0.78
950,000 //day
CAa TOC REFd
185 100 170
157 85.0 145
14.4 14.4 14.4
9.9 3.7 20.3
3.6
8.2 4.8 14.4
3.4 3.4 3.4
1.5
23.0 15.5 38.1
..
71.3 39.9 65.9
51.8 -- 51.8
42.5 55.4 52.2
205 205 205
0.21 0.27 0.25
1.900.000 f/day
CAa TOC REFd
185 100 175
157 85.0 149
21.6 21.6 21.6
13.3 6.9 22.8
6.6
8.2 4.8 14.8
3.4 3.4 3.4
1.5
26.4 21.7 41.0
..
72.7 41.3 69.1
104 -- 104
.4.9 63.0 6.1
410 410 410
(p) 0.15 0.01
3.800.000. f/day
CA* TOC REFd
225 115 220
191 97.8 187
48.0 48.0 48.0
16.8 12.9 32.6
8.7
10.0 5.6 18.6
3.4 3.4 3.4
1.8
32.0 52.2 54.6
..
92.8 52.2 91.0
207 -- 207
82.2 104 -61.4
820 820 820
(p) 0.13 (p)
00
en
en
-------
Table 8-31. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE IV
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, BOTTOM LOADED —ATTAINMENT AREA
Gasoline Throughput:
Vapor Processing Unit!
Capital Investment
Unit Purchase Cost
Unit Installation Cost
L
Truck Vapor Recovery Cost
Annual Operating Costs
Electric1tyf
Propane (P1lot}9
Maintenance
Operating Labor
Carbon Replacement
Subtotal (Direct Operating Cost)
Truck Maintenance^
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380 ,000 f/dav
CAa TOC REFd
160 90.0 143
136 76.5 122
7.2 7.2 7.2
6.6 1.5 14.7
2.0
7.0 4.2 12.0
3.4 3.4 3.4
1.0
18.0 11.1 30.1
0.5 0.5 0.5
60.6 34.7 54.4
27.0 — 27.0
52.1 46.3 58.0
107 107 107
0.49 0.43 0.54
950,000 f/day
CAa TOC REFd
185 100 170
157 85.0 145
14.4 14.4 14.4
9.9 3.7 20.3
3.6
8.2 4.8 14.4
3.4 3.4 3.4
1.5
23.0 15.5 38.1
0.9 0.9 0.9
71.3 39.9 65.9
67.4 -- 67.4
27.8 56.3 37.5
267 267 267
0.10 0.21 0.14
•1,900.000 f/day
CAa TOC REFd
185 100 175
157 '85.0 149
21.6 21.6 21.6
13.3 6.9 22.8
6.6
8.2 4.8 14.8
3'.4 3.4 3.4
1.5
26.4 21.7 41.0
1.4 1.4 1.4
72.7 41.3 69.1
135 « 135
-34.5 64.4 -23.5
535 535 535
(p) 0.1 (p)
3 ,800,000 //day
CAa TOC REFd
225 115 220
191 97.8 187
48.0 48.0 48.0
16.8 12.9 32.6
8.7
10.0 5.6 18.6
3.4 3.4 3.4
1.8
32.0 30.6 54.6
3.0 3.0 3.0
92.8 52.2 91.0
270 -- 270
-142 85.8 -121
1P70 1070 1/370
(p) 0.08 (p)
00
tn
-------
Table 8-32. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE II
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, TOP LOADED —ATTAINMENT AREA
Gasoline Throughput:
Vapor Processing Unit:
Capital Investment
linit Purchase Cost
Unit Installation Cost
Rack Conversion Cost'
Truck Conversion Cost
Annual Operatinq Cost
Electricity f
Propane (Pilot)9
Maintenance
Operating Labor*1
Carbon Replacement1
Subtotal (Direct Operating Cost]
Truck Maintenance''
Capital Charges
Gasoline Recovery (Credit)
Net Annuali zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380.000 e/day
CAa CRAb TOC REFd
160 140 90.0 143
136 119 76.5 122
320 320 320 320
14.4 14.4 14.4 14.4
6.6 1.5 1.5 14.7
2.0
7.0 11.8 4.2 12.0.
3.4 3.4 3.4 3.4
1.0
18.0 16.7 11.1 30.1
0.5 0.5 0.5 0.5
126 119 100 120
25.5 25.5 .. 25.5
119 111 112 125
101 101 101 101
1.18 1.10 1.11 1.24
950,000 2/day
CAa. CRAb TOC REFd
185 140 100 170
157 119 85 145
480 480 480 480
28.8 28.8 28.8 28.8
9.9 3.8 3.7 20.3
3.6
8.2 12.0 4.8 14.4
3.4 3.4 3.4 3.4
1.5
23.0 19.2 15.5 38.1
0.9 0.9 0.9 0.9
170 154 139 165
63.8 63.8 .- 63.8
130 110 156 no
252 252 252 252
0.52 0.44 0.62 0.56
1,950,000 f/day
CAa CRAb TOC REFd
185 172 100 175
157 146 85 149
480 480 480 480
43.2 43.2 43.2 96.0
13.3 7.5 6.9 22.8
6.6
8.2 14.6 4.8 14.8
3,4 3.4 3.4 3.4
1.5
26.4 25.5 21.7 41.0
1.4 1.4 1.4 1.4
173 168 142 169
128 128 -- 128
72.8 66.9 165 83.4
505 505 505 505
0.14 0.13 0.33 0.17
3,800,000 f/day
CAa. CRAb TOC REFd
225 200 115 220
191 170 97.8 187
640 640 640 640
96.0 96.0 96.0 96.0
16.8 15.7 12.9 32.6
8.7
10.0 17.0 5.6 18.6
3.4 3.4 3.4 3.4
1.8
32.0 36.1 30.6 54.6
3.0 3.0 3.0 3.0
230 221 190 229
255 255 — 255
10.0 5.1 224 31.6
1,010 1,010 1,010 1,0)0
0.01 0.01 0.22 0.03
00
en
-------
Table 8-33. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE III
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, TOP LOADED —ATTAINMENT AREA
00
01
CO
Gasoline Throughput:
Vapor Processing Unit:
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Rack Conversion Cost^
Truck Conversion Cost1"
Annual Operating Costs
ElectHc1tyf
Propane (Pilot) 9
Maintenance
Operating Labor*1
Carbon Replacement
Subtotal (Direct Operating Cost)
Truck Maintenance^
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Hg/yr)
Cost Effectiveness ($/kg)
380,000 f/dav
CAa TOC REFd
160 90.0 143
136 76.5 122
320 320 320
14.4 14.4 14.4
6.6 1.5 14.7
2.0
7.0 4.2 12.0
3.4 3.4 3.4
1.0
18.0 11.1 30.1
*I26 100 120
20.7 -- 20.7
123 111 129
82 82 82
1.50 1.35 1.57
950,000 l/<\ay
CAa TOC REFd
185 100 170
157 85.0 145
480 480 430
28.8 28.8 28.8
9.9 3.7 20.3
3.6
8.2 4.8 14.4
3.4 3.4 3.4
1.5 -
23.0 15.5 38.1
170 139 165
51.8 -- 51.8
141 155 151
205 205 205
0.69 0.75 0.74
1,900.000 //day
CAa TOC REFd
135 100 175
157 85.0 149
480 430 400
43.2 43.2 43.2
13.3 6.9 22.8
6.6
3.2 4.8 14.8
3.4 3.4 3,4
1.5
26,4 21.7 41.0
173 142 169
104 — 104
95.4 164 106
410 410 410
0.23 0.40 0.26
3.800.000 I /day
CAa TOC REFd
225 115 220
191 97.8 187
640 640 640
96.0 96.0 96.0
16.8 12.9 32.6
3.7 --
10.0 5.6 18.6
3.4 3.4 3.4
1.8
32.0 30.6 54.6
.. •• •-
230 190 229
207 •- 207
55,0 221 76.6
820 820 820
0.07 0.27 0.09
-------
Table 8-34. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVE
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, TOP LOADED — ATTAINMENT AREA
IV
Gasoline Throughput:
Vapor Processing Unit;
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Rack Conversion Cost!
. Truck Conversion Cost"1
Annual Operating Costs
Electr1cityf
Propane (Pilot)9
Maintenance
Operating Labor
Carbon Replacement
Subtotal (Direct Operating Cost)
Truck Maintenance
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness ($/kg)
380,000 f/day
CAa TOC REFd
160 90.0 143
136 76.5 122
320 320 320
14.4 14.4 14.4
6.6 1.5 14.7
2.0 --
7.4 4.6 12.4
3.4 3.4 3.4
1.0
18.0 11.1 30.1
0.5 0.5 0.5'
126 100 120
27.Q -- 27.0
118 112 124
187 107 107
1.10 1.05 1.16
950,000 j/day
CAa TOC R£Fd
185 100 170
157 85.0 145
430 480 480
28.8 28.8 28.8
9.9 3.7 20.3
3.6
8.4 5.0 14.6'
3.4 3.4 3.4
1.5 --
23.0 15.5 38.1
0.9 0.9 0.9
170 139 165
67.4 .. 67.4
127 155 137
267 267 267
0.48 0.58 051
1,900,000 f/day
CAa TOC R£Fd
185 100 175
157 35.0 149
480 480 480
43.2 43.2 43.2
13.3 6.9 22.8
6.6 --
8.4 5.0 15.0
3.4 3.4 3.4
1.5
26.4 21.7 41.0
1.4 1.4 1.4
173 142 169
135 — 135
65.8 165 76.4
535 535 535
0,12 0.31 0.14
3.800.000
-------
Table 8-35. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVES III & IV
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, UNIT REPLACED — NON-ATTAINMENT AREA
Gasoline Throughput:
Vapor Processing Unit:
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Salvage Value (Credit)"
Annual Operating Costs
Electr1dtyf
Propane (Pilot) 9
Maintenance
Operating Labor
Carbon Replacement
Subtotal (Direct Operating Cost)
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Mg/yr)
Cost Effectiveness (S/kg)
380,000 I/day
CAa TOC REFd
160 90.0 143
32,0 18.0 23.6
7.0 7.0 7.0
5.1 0 13.2
2.0 --
-4.8 -.7.6 0.2
000
1.0
1.3 -5.6 13.4
37.0 20.2 32.9
1.5 -28, 3' 1.5
36.8 42.9 44.8
5.8 5.8 5.8
6.34 7.40 7.72
950,000 I/Jay
CAa TOC REFd
185 100 170
37.0 20,0 34.0
7.0 7.0 7.0
6.1 -0.1 16.5
3.6
-3.8 -7.2 2.4
000
1.5 --
3.8 -3.7 18.9
43.0 22.6 39.4
3.7 -70.8 3.7
43.1 89.7 54.6
14.5 14.5 14.5
2.97 6.19 3.77
1.900,000 t/fay
CA8 TOC REFd
185 100 175
37.0 20.0 35.0
8.6 8.6 8.6
5.8 -0.6 15.3
6.6 --
-6.4 .-9.8 0.2
000
1.5 --
O.g -3.8 15.5
42.7 22.3 40.3
7.3 -142 7.3
36.3 161 48.5
29.0 29.0 29.0
1.25 5.53 1.67
3,800,000 J/day
CAa TOC REFd
225 115 220
45.0 23.0 44.0
10.0 10.0 10.0
1.1 -2.8 16.9
8.7 --
-7.0 -11.4 1.6
000
1.8
-4.1 -5.5 18.5
52.0 25.6 50.8
14.7 -283 11.7
33.2 303 54.6
57.9 57.9 57.9
0.57 5.23 0.94
00
-------
Table 8-36. ESTIMATED CONTROL COSTS FOR REGULATORY ALTERNATIVES III & IV
(Thousands of Mid-1979 Dollars)
EXISTING FACILITY, SECONDARY UNIT ADDED ON — NON-ATTAINMENT AREA
00
i
Ol
Gasoline Throughput:
Vapor Processing Unit:
Capital Investment
Unit Purchase Cost
Unit Installation Cost
Annual Operating Costs
Electricity*
Propane (P11ot)9
Maintenance
Operating Labor11
Carbon Replacement''
Subtotal (Direct Operating Costs)
Capital Charges
Gasoline Recovery (Credit)
Net Annual 1 zed Cost
Total VOC Controlled (Kg/yr)
Cost Effectiveness ($/kg)
380,000 */day
CAa TOC
50.0 90.0
25.0 45.0
0.1 1.5
2.0
2.0 3.6
3.4 3.4
0.5
6.0 10.5
15.0 27.0
1.5
19.5 37.5
5.8 5.8
3.36 6.47
950,000 «/day
CAa TOC
66.0 100
33.0 50.0
0.1 2.1
3.6
2.6 4.0
3.4 3.4
0.8
6.9 13.1
19.8 30.0
3.7
23.0 43.1
14.5 14.5
1.59 2.97
1,900,000 f/day
CAa TOC
66.0 100
33.0 50.0
0.1 2.1
6.6
2.6 4.0
3.4 3.4
0.8
6.9 16-1
19.8 30.0
7.3
19.4 46.1
29.0 29.0
0.67 1.59
3,800,000 f/day
CAa TOC
81.0 115
40.5 57.5
0.1 3.0
8.7
3.2 4.6
3.4 3.4
0.9
7.6 19.7
24.3 34.5
14.7
17.2 54.2
57.9 57.9
0.30 0.94
-------
NOTES FOR TABLES 8-29 THROUGH 8-36
aCA = Carbon Adsorption Unit.
CRA = Compression-Refrigeration-Absorption Unit.
CTO = Thermal Oxidizer Unit.
REF = Refrigeration Unit.
Additional cost required for vapor collection equipment on new
tank trucks.
Electricity costs are based on average consumption rates reported
by manufacturers.
9Propane for pilot estimated at 12.5 liters per hour based on
manufacturers' reported consumption.
Daily inspections at one hour per day, plus a monthly visual
inspection for liquid or vapor leaks in the vapor collection
and processing systems.
Estimated carbon replacement period is ten years.
j
Cost to perform annual vapor-tight testing.
Average number of terminal-owned trucks:
380,000 I/day 3
950,000 I/day 6
1,900,000 I/day 9
3,800,00 I/day 20
u
Cost of installing vapor collection equipment on existing bottom
loading tank trucks.
Cost of converting top loading racks to bottom loading and
vapor recovery.
mCost of retrofitting existing top loading tank trucks with
bottom loading and vapor collection equipment.
nCost credit for salvage of replaced unit. Estimated at five
percent of the current CRA unit purchase cost.
^Cost-effectiveness not calculated because net annualized cost
is a negative quantity (cost credit).
8-62
-------
Section 8.1.3.2). The average cost of converting to bottom loading
and vapor recovery is $6,400, of which approximately $2,400 is
attributable to vapor recovery.
A terminal in a regulated (non-attainment) area may choose the
option of replacing an existing control unit with a more efficient
unit to comply with additional regulations. Information previously
supplied to EPA indicates that a salvage value cost credit of 5 percent
of equipment cost is a reasonable estimate.
8.2.3.2 Annualized Costs. The annualized operating costs use
the same factors and calculation methods as were used to calculate
operating costs for new facilities (Tables 8-21 and 8-22).
In the case of replacement control units, the costs shown reflect
the differential costs to a terminal which replaces a CRA, CRC, or LOA
type unit with a CA, TO, or REF unit (Table 8-35) to meet the lower
emission levels required by Alternative III. Table 8-36 presents
differential costs due to the addition of a CA or TO unit to an exist-
ing CRA, CRC, or LOA unit. Carbon replacement costs were estimated at
one-half the cost attributable to primary CA units. Gasoline recovery
cost credits result from the change in system emissions from 80 nig/liter
to 35 mg/liter. The total VOC controlled (Mg/yr) similarly reflects a
differential quantity resulting from the change in total system emissions.
Costs to perform annual vapor-tight testing on gasoline tank trucks
are the same as those for new facilities. The cost-effectiveness of
each control option is presented in Table 8-37.
8.2.4 Compliance Costs.
Compliance costs are those costs involved in demonstrating that a
terminal's vapor processing system complies with the applicable standards.
These costs occur as a result of two principal items: performance
testing and continuous monitoring.
Performance tests are required to be performed shortly after
initial startup and at other times as prescribed by the Administrator. '
The required performance test demonstrating a facility's ability to
operate within the limits of applicable standards would involve an
additional'cost to the facility. The test method to be followed is
described in Appendix D. The test cost will vary with the type of
8-63
-------
Table 8-37,
COST-EFFECTIVENESS OF CONTROL OPTIONS
(Dollars/kg VOC Controlled)
— EXISTING FACILITIES
Faci>ity ,
Classification*
A
B
C
0
Regulatory
Alternative
II
III
IV
II
III
IV
III and IV
III and IV
380, 000 I /day
CA
0.53
0.71
0.49
1.18
1.50
1.10
6.34
3.36
CRA TO
0.44 0.46
c 0.61
c 0.43
1.10 1.11
c 1.35
c ' 1.05
c 7.40
c 6.47
REF
0.59
0.78
0.54
1.24
1.57
1.16
7.72
c
CA
0.12
0.21
0.10
0.52
0.69
0.48
2.97
1.59
950
CRA
0.04
c
C
0.44
c
c
c
c
Model Plants and Control
, 000 t /day
TO REF
0.22 0.16
0.27 0.25
0.21 0.14
0.62 0.56
0.75 0.74
0.58 0.51
6.19 3.77
2.97 c
Unit Types
1,900,000 £/day
CA
b
b
b
0.14
0.23
0.12
1.25
0.67
CRA TO REF
0.13 b
c 0.15 0.01
c 0.12 b
0.13 0.33 0.17
c 0.40 0.26
c 0.31 0.14
c 5.53 1.67
C 1.59 c
3,800,000 */day
CA CRA TO
b b 0.08
b c 0.13
b c 0.08
0.01 0.01 0.22
0.07 c 0.27
b c 0.21
0.57 c 5.23
0.30 c 0.94
REF
b
b
b
0.03
0.09
0.02
0.94
c
00
I
'classification A: Bottom loading facility in area unaffected by SIP regulations.
Classification B: Top loading facility in area unaffected by SIP regulations.
Classification C: Facility replacing previous control unit with more efficient unit.
Classification 0: Facility adding on a secondary, or back-up, control unit.
Indicates a negative net annualired cost, or cost credit.
C|o; spplicable to this type of control unit.
-------
vapor control processor in use, but is assumed to be the same for all
of the model plants. Thermal oxidizer units require more field measure-
ments during testing, and thus more test personnel. The other processors
are all considered to involve the same testing costs. In addition, a
requirement for continuous monitoring would involve an annualized cost
for monitor operation as well as the capital charges resulting from
equipment purchase and installation. Monitoring costs vary according
to the type of monitoring system chosen for use, and the auxiliary
equipment necessary to calibrate and operate the system. The type of
data recording equipment and the intended use of the collected data
are also factors affecting costs. Continuous monitors may include a
system to measure and record the VOC concentration at the processor
outlet, or a system to measure some other process variable which
provides an indirect indication of system performance.
Three performance test and continuous monitoring regulatory
options have been costed in this analysis. Option 1 requires only
that a performance test be performed at startup of the new facility.
Option 2 includes the same performance test requirement as Option 1,
plus the installation and operation of a system which monitors a
process parameter of the vapor processor. Examples of such systems
include monitors of temperature in the case of refrigeration or thermal
oxidizer units, and liquid recovery rate for all vapor processors
except the oxidizer. Although this type of equipment may be supplied
as part of some vapor processing systems, it is assumed for this
analysis that the equipment must be purchased and operated independently
from the main processor. Option 3 includes the same performance test
requirement, plus the installation and operation of a continuous VOC
monitoring system. This is by far the most expensive option, because
of the high installed and operating costs of this type of analyzer in
comparision to the simpler parameter monitors required under Option 2.
The following paragraphs present the estimated maximum costs associated
with each of the options.
Option 1. The cost of conducting a performance test includes
planning, travel, calibration, testing, lab analysis, and report
preparation*. These costs are assumed to be the same for all of the
8-65
-------
control unit types, except for the thermal oxidizer, whose testing
costs are higher due to the additional manpower required. Manpower
costs assume the utilization of testing contractors, at a charge of
$30 per hour. Testing may require either one day or three days to
perform.
Option 2. The costs associated with the monitoring of a process
parameter are assumed to be the same for all types of vapor processors.
Annualized costs are calculated by adding the capital charges on
capital investment to the annual operating cost of the system. Capital
charges are based on an assumption of 10 percent interest and a 5-year
monitoring equipment useful life, with a tax rate of 4 percent.
Operating costs include data recording supplies and calibration and
maintenance labor costs. The performance test costs are the same as
those in Option 1.
Option 3. Continuous monitoring of outlet VOC concentration is
assumed to involve the same costs for all of the control unit types,
except for the thermal oxidizer, which requires a C02/C02 analyzer and
additional data recording capability. Annualized costs are calculated
using the same assumptions as in Option 2. The performance test costs
are the same as those in Option 1. Table 8-38 presents the costs
incurred by a facility in complying with the requirements of each of
the three options.
8.2.5 Tank Truck Industry Control Costs
Independent owners and operators of the gasoline tank trucks
transporting liquid petroleum products from bulk terminals will incur
additional costs as a result of the regulatory alternatives. Incremental
costs to the oil companies which operate tank trucks at their own
terminals have been outlined in previous sections, both for new
facilities (Sections 8.2.2.1.3 and 8.2.2.2) and for existing facilities
(Sections 8.2.3.1 and 8.2.3.2). The costs to for-hire tank truck
companies are included as a separate but related impact because the
operations of such companies are intimately related to those of bulk
terminals, and many of these companies are small and may be less able
to afford additional costs. The costs to these companies are expected
to include the capital investment necessary to convert tank trucks to
8-66
-------
Table 8-38. CAPITAL INVESTMENT AND ANNUALIZED COST FOR THREE COMPLIANCE OPTIONS51
(First Quarter 1980 Dollars)
Option
la
2d
39
Vapor
Processor
Thermal Oxidizer
Other Processors
Thermal Oxidizer
Other Processors
Thermal Oxidizer
Other Processors
CAPITAL INVESTMENT
1-day test
10,000b
8,000b
15,000e
13,000e
29,000h
21 ,000h
3-day test
15,000b
12,000b
20,000e
17,000e
34,000h
25,000h
ANNUALIZED COST
1-day test
2,000C
1 ,600C
6,000f
5,600f
20,8001
17J001
3-day test
3,000C
2 ,400°
7,000f
6,400f
22,8001
19J001
00
Performance test only.
Cost per test.
°Assumes one test in the first five years of facility operation.
Performance test and continuous monitoring of process parameter.
elncludes one test plus $5,000 equipment cost.
Includes capital charges on investment plus $2,500 per year operating cost.
^Performance test and continuous monitoring of outlet VOC concentration.
Includes one test plus equipment cost of $19,000 for thermal oxidizer monitors, and $13,000
for all other processors.
•
Includes capital charges on investment plus operating cost of $13,100 per year for thermal
oxidizer monitors, and $12,200 for all other processors.
-------
a bottom loading configuration and to install vapor recovery equipment,
and the annual!zed costs of maintaining the vapor recovery equipment
and performing yearly vapor-tight tests on the delivery tanks.
8.2.5.1 Capital Investment. The costs of retrofitting bottom
loading and vapor recovery equipment on existing tank trucks were
discussed in Section 8.2.3.1. The average cost of converting tank
trucks to bottom loading and adding vapor recovery equipment would be
the same for a for-hire tank truck company as for a bulk terminal.
The different costs in individual situations would depend in part on
whether the company or terminal had its own facilities for performing
conversion work or had the work performed at an outside shop. As
discussed earlier, bottom loading conversions average about $4,000 per
tank truck, and the addition of vapor recovery provisions averages
about $2,400 per tank truck.
As discussed in Section 3.2.2.3 of Chapter 3, about 23 percent of
the gasoline tank trucks do not have bottom loading provisions. The
trend is toward increased use of bottom loading, however, and this
percentage could be considerably lower by 1982. If 23 percent, or 90,
of the 390 affected for-hire tank trucks (Section 8.1.3.2) required
both bottom loading and vapor recovery retrofitting by 1985, the capital
investment required would be:
(90 tank trucks) X ($6,400/tank truck) = $576,000.
The remaining 300 vehicles would already use bottom loading, and would
thus require vapor recovery provisions only. The total capital cost
for these tank trucks would be:
(300 tank trucks) X ($2,400/tank truck) = $720,000.
The total capital cost accruing to the for-hire tank truck industry by
1985 would be the total of these two figures, or $1.3 million. This
cost would be the same under Regulatory Alternative II, III, or IV.
8.2.5.2 Annualized Cost. The annualized cost due to retrofitted
tank trucks includes the cost of maintaining the vapor recovery equipment
(Alternatives II, III, and IV) and of performing annual vapor-tight
testing (Alternatives II and IV). Capital charges on the initial
investment on the equipment are also included. Capital charges are
calculated using the capital recovery factor described in Table 8-21.
8-68
-------
Assuming an interest rate of 10 percent and an equipment life of
12 years, capital charges would total:
($1.3 million) X (19 percent) = $247,000/yr.
Information from trade organizations and oil companies indicates that
the cost to maintain the vapor recovery equipment on a tank truck is
approximately $1,000 per year. *53'5 The cost to perform a vapor-tight
test, including the average necessary repair cost, is about $150 per
year (Section 8.2.2.2). Thus, the total annualized cost in 1985 for
390 tank trucks under Alternatives II and IV would be:
390 X ($l,000/yr + $150/yr) + $247,000/yr = $0.7 million.
Under Alternative III, no vapor-tight testing would be required,
so the total annualized cost in 1985 would be:
390 X ($l,000/yr) + $247,000/yr = $0.6 million.
8.2.5.3 Control Cost Impact on Model Firms. For the purpose of
analyzing the economic impact of the regulatory alternatives on the
tank truck model firms (Section 8.4.2), capital and annualized costs
were developed for the four models developed in Section 6.2.5 of
Chapter 6. Annualized costs were calculated for Alternatives II and
IV, as a worst case, because these costs are slightly higher than
those under Alternative III. Two scenarios of likely control costs
were considered. In Scenario 1, the affected tank trucks at each
model firm are already in the bottom loading configuration and require
only the addition of vapor collection equipment. In Scenario 2, the
affected tank trucks also need conversion from top loading to bottom
loading. An individual tank truck firm is expected to be affected
under one or the other of these two scenarios.
It was assumed for model firms 1 and 2 that all tank trucks would
require controls. For model firms 3 and 4, it was assumed that only
50 percent of a firm's trucks would require controls. This assumption
was made based on the fact that not all of a large firm's trucks would
serve regulated terminals and so be subject to the regulation. A
50 percent participation rate was selected as representative. Conse-
quently, control cost estimates for 15 and 50 trucks were applied to
•f >
these two model firms. However, revenue and expenditure estimates
were based on the operation of 30 and 100 tank trucks for model firms 3
8-69
-------
and 4, respectively (see Section 8.4.2). Table 8-39 presents the
control cost estimates for the model firms.
8.2.6 Nationwide Control Cost Summary
This section summarizes the cost impact of each regulatory
alternative on the bulk gasoline terminal and for-hire tank truck
industries through the years 1985 and 1990. The total capital investment
through these years, as well as the total annualized costs and cost-
effectiveness in these two years, are calculated for all of the affected
facilities and tank trucks expected throughout this time period (see
Table 8-12 and Section 8.2.5.1).
The presented costs are composed of averages based on the estimated
distributions of control processor type and facility size and location,
as well as the estimated number of affected for-hire tank trucks.
Since SIP control regulations are expected in all non-attainment areas
by 1982, the only additional costs accruing to facilities in these
areas will be those resulting from replacement or add-on controls. It
is expected that eight of these situations will occur by 1985, and 16
will occur by 1990. Costs calculated for the two smallest sized
facilities, 380,000 and 950,000 liters per day, are averages for all
types of processors. Costs for the two largest sized facilities,
1,900,000 and 3,800,000 liters per day, are averages for CA, CRA, and
REF type processors. The omission of the costs for a CRA system from
the calculations for Alternatives III and IV (35 mg/liter) does not
affect the cost totals under these alternatives.
Most of the existing facilities expected to be affected by the
regulatory alternatives will use top loading for gasoline. All new
facilities which will incur additional costs as a result of the regu-
latory alternatives will be located in attainment areas, and are
expected to use bottom loading for gasoline. Table 8-40 presents a
summary of the total costs to the bulk terminal and for-hire tank
truck industries and compares the cost-effectiveness of each regulatory
alternative in 1985 and 1990. Compliance costs (Section 8.2.4) are
not included in the table.
8-70
-------
Table 8-39. CONTROL COST ESTIMATES FOR TANK TRUCK
MODEL FIRMS
(Thousands of Mid-1980 Dollars)
No. of Tank Truck Conversions
Scenario la
• Annual i zed Costs
Annual Control Costs
Miscellaneous Costs
Total Annual i zed Control Costs
• Total Annual i zed Control Costs per
Affected Trailer
• Capital Costs
Scenario 2C
• Annual i zed Costs
Annual Control Costs
Miscellaneous Costs
Total Annual i zed Control Costs
• Total Annual i zed Control Costs per
Affected Trailer
• Capital Costs
1
2
2.3
0.9
3.2
1.6
4.8
2.3
2.4
4.7
2.4
12.8
2
7
8.1
3.2
11.3
1.6
16.8
8.1
8.5
16.6
2.4
44.8
3
15
17.3
6.8
24.1
1.6
36.0
17.3
18.2
35.5
2.4
96.0
4
50
57.5
22.8
80.3
1.6
120.0
57.5
60.8
118.3
2.4
320.0
Vapor collection only.
Includes depreciation, property taxes, insurance, and general administrative
costs. Capital costs x CRF (0.19).
cVapor collection plus bottom loading conversion.
8-71
-------
Table 8-40. TOTAL NATIONAL COST ANALYSIS OF REGULATORY ALTERNATIVES'
(Millions of mid-1979 Dollars)
Regulatory
Alternative
I (baseline)
II
III
IV
CAPITAL INVESTMENT
Through 1985
0
24.3
25.3
25.3
Through 1990
0
48.6
50.6
50.6
ANNUALIZED COSTS
In 1985
0
4.0
4.7
4.3
In 1990
0
8.0
9.4
8.6
COST-EFFECTIVENESS ($/Mg)
In 1985
0
696
1,042
650
In 1990
0
741
1,105
688
00
VI
ro
Includes cost impacts on both bulk terminals and for-hire tank truck companies operating
at terminals.
-------
8.3 OTHER COST CONSIDERATIONS
Operations at bulk gasoline terminals are affected by regulations
concerning water pollution and solid waste, as well as by regulations
protecting the health and safety of employees. Information obtained
through Section 114 letter responses indicates that the costs of com-
pliance with these regulations cover a broad range. These costs are
reported to vary from State to State. Since data are limited and no
breakdown by terminal size is available, the costs should be considered
estimates which apply to all model plants, with the lower values
applying to smaller terminals and the higher values applying to larger
terminals. This is a reasonable assumption because there is more
water and solid waste and more employees at the larger terminals.
Costs of compliance with the Water Pollution Control Act are
reported by one major oil company as $30,000 to $672,000 per terminal
since 1972, or approximately $5,000 to $112,000 per year. A second
major company reports $50,000 to $300,000 per terminal annually, and a
third company reports these costs as $100,000 per terminal. Water-
front terminals are expected to incur higher costs due to the requirements
on dock facilities.
The Resource Conservation and Recovery Act has had less effect on
terminals. The main effect has been on the disposal of tank bottoms
and oil-water separator sludge. One major company reports compliance
costs of only a few hundred dollars per year, while a second company
has provided an annual cost range of $25,000 to $100,000 per terminal.
Compliance with Occupational Safety and Health Administration
(OSHA) requirements are reported by one major oil company to have cost
$2,000 to $20,000 per terminal since 1972, or about $350 to $3,500 per
year. Other reported costs are $10,000 to $350,000 per year for one
company, and $15,000 per year for another. A breakdown by individual
cost element was not included with these cost figures.
Costs of complying with air pollution control regulations for a
terminal were reported by two companies as $600,000 per year and
$10,000 to $250,000 per year. These regulations include SIP limitations
on emissions from storage tanks and loading operations, as well as
NSPS limitations on storage tank emissions (Section 3.2.2.1). The
storage tank NSPS has only a slight cost impact on a gasoline terminal.
8-73
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8.4 ECONOMIC IMPACT OF REGULATORY ALTERNATIVES
The purpose of this section is to present the potential economic
effects of the regulatory alternatives on new, modified, and recon-
structed bulk gasoline terminals, and on the for-hire tank truck
companies operating at these terminals. The emphasis of the analysis
is on identifying possible adverse impacts on the growth of these two
industries. Other impacts to be examined are those on energy consumption,
employment, price inflation, foreign trade, and balance of payments.
The section is divided into two principal subsections, one concerned
with the impacts on the bulk terminal industry (Section 8.4.1) and the
other on the for-hire tank truck industry (Section 8.4.2). Each
subsection begins with some relevant supplementary information on the
respective industry, followed by a brief discusssion of the economic
impact analytical methodology. The analysis for each industry is
based on the model plants described in Sections 6.2.4 and 6.2.5 of
Chapter 6.
8.4.1 Impacts on Bulk Gasoline Terminals
8.4.1.1 Industry Profile Data and Economic Impact Assessment
Methodology. Section 8.1 contains information useful in determining
how the bulk gasoline terminal industry will be affected by the regulatory
alternatives. A few additional characteristics must be noted in order
to understand pricing and the ability of a terminal to pass on costs
to customers, elasticity of demand, and the profit-center concept as
it applies to this industry.
8.4.1.1.1 Concentration and integration. In Section 8.1.1.4 it
was pointed out that the major oil companies own most of the bulk
gasoline terminals. In 1979, in fact, eight companies - Amoco, Chevron,
Gulf, Mobil, Exxon, Shell, Atlantic Richfield, and Texaco - owned
683 gasoline terminals, or more than 40 percent of the total. The first
four listed owned 495. Thirteen more companies, the "semi-majors,"
such as Ashland, Getty, and Sun, owned another 438 terminals. The
remainder were owned by 47 independent companies (marketers, wholesalers,
jobbers, and warehousers), 21 of which owned only one terminal apiece.
There were thus 68 firms owning bulk terminals, ranging from one
8-74
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extreme where four firms each owned more than 100 terminals to the
other with 21 firms each owning only one.57
All majors and semi-majors are refiners and are integrated into
terminal operations and retail distribution. However, of approximately
200 independent companies, only 47 are integrated into terminal operations.
The extent of integration is not particularly relevant to the impact
of the alternatives on a particular terminal, however, because bulk
terminals are evaluated as "stand-alone" operations even by owners
which are major oil companies.
Crude oil refined by independents is an important source of
supply for majors' and semi-majors' terminal operations. Major oil
companies' share of total refinery capacity is approximately equal to
their share of the total number of terminals. Semi-major companies'
terminal share is significantly greater than a group's share of refinery
56
capacity. Because, as indicated in Section 8.1, majors' and semi-majors'
terminals also tend to have greater storage and throughput capacities
than do independents', purchasing or transporting oil supplied by the
150 independents not operating terminals, in particular, is a function
in majors' and semi-majors' operations. With regard to distribution
to retail outlets, semi-majors, to a greater extent than independents,
58
act as middlemen in terminal transportation operations.
8.4.1.1.2 Financial profile. Because terminals are increasingly
operated on a stand-alone profitability basis, financial statistics to
be applied in the economic impact analysis must be estimated for both
large terminals, typically owned by majors and semi-majors, and for
medium and small terminals, owned by independents. However, major and
semi-major oil companies are dominant U.S. corporations which neither
analyze nor publish financial information on gasoline industry segments.
Published financial data on independents' operations is limited to
data for companies specializing in petroleum product storage and
distribution at bulk stations, as well as terminals. The financial
profile presented is a composite of available company and storage
specialist information.
All of-the majors for which information was reported had 1978
asset levels greater than $10,000 million, whereas semi-majors' assets
8-75
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fell primarily into the $1,100 to $5,500 million range. Tsble 8-41
lists aggregate sales levels and key ratios for majors and semi-majors.
Since these companies do not compute transfer prices to reflect costs
CO
of terminal operations, the sales data reflect revenue earned primarily
through final product and, to some extent, refinery product sales.
The table is therefore useful only for comparative purposes.
Selected published statistics on the wholesale petroleum products
industry, which would more closely reflect the financial characteristics
of individual terminals, are given in Table 8-42. The statistics are
for firms with asset sizes ranging from $250 thousand to $50 million,
with a mean asset size of approximately $2.9 million and an estimated
mean annual sales level of $17 million.
Profitability statistics are the critical financial statistics
required in the analyses. As shown in the table, the before-tax
profit-to-sales ratio dropped from 2 percent in 1976-1977 to 1 percent
in 1978-1979, indicating an after-tax profit-to-sales ratio shift from
1 percent to 0.5 percent, respectively. According to a trade association
representative, a 1 percent to 2 percent after-tax profit-to-sales
CO
ratio would be a reasonable estimate for terminal operations. In
this analysis, a 1.5 percent profit before taxes will be used to
ensure that, if the estimates are in error, they are on the conservative
side of actual results.
Another profitability measure which can be evaluated is the
return on investment (ROI). A 20.5 percent pre-tax ROI (approximately
11 percent after taxes) has been applied in a previous economic analysis.
58
This rate is, according to a trade association representative, low.
A 30 percent pre-tax ROI — and so a 15 percent after-tax ROI — will,
as suggested, be applied in the analysis. Majors such as Gulf have
testified to the use of a 15 percent after-tax ROI criterion. The
11 percent rate will be considered the absolute minimum acceptable
rate of return.
Capital budgeting decisions can be made on the basis of an ROI or
a payback period criterion. For the terminal industry, they are most
frequently made on the basis of the latter, with a three to four-year
CO
criterion applied.
8-76
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Table 8-41. SALES AND RATIO STATISTICS
MAJORS AND SEMI-MAJORS
57
Majors
Exxon
Mobil
Texaco
Gulf
Atlantic Richfield
Shell
Mean:
Semi -Majors
Continental
Sun
Phillips
Union
Ashland
Cities Service
Marathon
Getty
Tenneco
Kerr-McGee
Murphy
Diamond Shamrock
Sales
(million $)
$64,886
32,806
28,607.5
20,097
12,738.8
11,062.9
$28,366.4
$ 9,535.7
7,428.2
6,997.8
5,955
5,426
4,660.9
4,509.4
3,514.7
2,015
2,072.4
1,191
660
Net Income As
% of Sales
4.3%
3.4%
3.0%
4.0%
2.5%
7.4%
4.1%
4.7%
4.9%
10.2%
6.4%
4.7%
2.5%
5.0%
8.7%
23.9%
5.7%
3.9%
-
Net Income as Percent
of Stockholder Equity
14.0%
7.9%
9.3%
9.8%
15.3%
14.2%
11.8%
15.1%
12.0%
27.1%
15.0%
32.2%
6.0%
6.5%
-
14.5%
-
10.7%
-
Mean:
$ 4,497
7.3%
14.7%
8-77
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Table 8-42. SELECTED FINANCIAL STATISTICS60
PETROLEUM BULK STORAGE SPECIALISTS
2nd Quarter '78 2nd Quarter '76
1st Quarter '79 1st Quarter '77
Gross Profit as % Net Sales 12.9% 15.5*
Profit Before Taxes as % Net Sales 1.0% 2.0%
Profit Before Taxes as % Total Net Assets 1.6% 0.9%
Depreciation, Depletion, Amortization
as % Sales 1.5% 1.7%
Ratio of Sales to Total Assets 3.3% 3.1%
Long-Term Debt as % Total Liabilities
and Net Worth 15.9% 15.4%
8-78
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8.4.1.1.3 Supply and demand. This subject has been discussed in
Section 8.1.2.1. An additional fact to be noted is that while long-run
demand for terminal services depends on gasoline demand, short-run
demand for terminal services depends on domestic refinery supply and,
particularly for independents, the supply of imported petroleum
62
products.
8.4.1.1.4 Economic impact assessment methodology. A preliminary
examination of the model plant control costs in Section 8.2 showed
that under some combinations of regulatory alternative and vapor
processing equipment, the larger model plants would experience increases
in net cash flow because of revenue from resource recovery. Smaller
plants, on the other hand, would not enjoy this benefit. Another
preliminary observation, based on trends in gasoline consumption and
industry behavior, is that growth in terms of new facilities will
probably be small. More facilities would be affected by the alternatives
through modification and reconstruction than through new construction.
A third point, already mentioned, is that bulk terminals tend to be
treated as independent operations, from a financial standpoint, even
when they are owned by a major oil company. In other words, a company
will not open or keep open a terminal which is not economically viable
in and of itself.
These three observations essentially dictated the assessment
techniques to be applied in this analysis. These techniques should be
capable of discriminating among widely varying effects of similar
actions by firms of various sizes. They should be useful for existing
as well as new facilities, and they should be capable of assessing the
impacts of capital requirements and annual operating costs of controls
on relatively small businesses for which many details of financial
operation were not available. Three techniques were selected:
• Debt Service Coverage Analysis, in which cash flow changes
and capital requirements associated with regulatory alternatives
are investigated to determine whether growth by the industry
or by individual firms would be restricted;
§ Cost Pass-Through Analysis, to determine the magnitude and
incidence of potential price increases; and
8-79
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• Return-on-Investment Analysis, an assessment of changes in
profitability which might influence decisions concerning
entry to or exit from the industry.
Each analysis was applied to all four model plant sizes for all regulatory
alternatives, and results are reported separately for new and modified
or reconstructed facilities in Sections 8.4.1.2 and 8.4.1.3, respectively.
From these analyses, it is possible to predict the impacts of the
regulatory alternatives on individual terminals, and on the industry
as a whole, and also to identify any differential impacts which might
be felt by only one or two size classes of terminals and which might,
for example, restrict small business opportunities.
In Section- 8.5, the results of the analysis are applied on a
different level. In compliance with Executive Order 12044, total
annual!zed control costs are examined to ascertain whether they would
exceed $100 million in any calendar year between 1980 and 1985. The
possibility of price increases exceeding 5 percent is considered as a
measure of significant inflationary impact. Total energy consumption
12
by alternative control equipment is compared to a 50 x 10 Btu per
year criterion. Consideration of changes in supply of and demand for
urban scarce materials, a fourth requirement of E.O. 12044, is not
relevant to bulk terminals.
8.4.1.2 Impacts on New Facilities. It is important to preface
this discussion with a reminder that, with gasoline demand expected to
be nearly level, or increasing only slightly, over the 1980-85 period,
few new bulk terminals are anticipated. Approximately one new
terminal per year is the projected growth rate in the absence of
additional controls, with only the three larger model plant sizes
represented - one or two 950,000 liter/day terminals, two 1,900,000
liter/day facilities, and one or two 3,800,000 liter/day operations in the
next five years. Moreover, only those new facilities constructed in
attainment areas would be differentially affected by control costs
associated with the proposed controls. On an industry-wide basis,
then, the expected increment of growth is quite small - five new
facilities added to the more than 1,500 in existence - and the number
which would be affected by the standard is potentially smaller still.
8-80
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From the standpoints of a region with demand exceeding terminal capacity,
and of an individual firm considering entry into the industry, however,
it is still important to devote some attention to possible impacts.
8.4.1.2.1 Cash flow and capital availability. One of the crucial
questions asked by a potential lender is whether a new facility, under
additional controls, will generate sufficient cash flow to enable it
to service the debt incurred in bringing it into existence. This is
examined, in this assessment, through projection of changes in "debt
service coverage ratio," which lenders commonly use for this purpose.
The analysis is presented in Table 8-43.
The upper section of the table shows the baseline condition - the
investment, debt, profit, and cash flow from each of the four model
plants without vapor control equipment. Capital investment was estimated
on the basis of discussions with equipment manufacturers and suppliers
and engineers experienced in designing bulk terminals. Table 8-44
shows the components of the estimates. Long-term debt is assumed to
be 40 percent of the total investment; the normal range for the industry
is 25 to 40 percent, and the high end of the range was selected to
64
permit a worst-case solution. The debt is assumed to be 10-year
maturity, thus the current maturity is one-tenth of the total. Depreciable
assets were estimated by subtracting land, working capital, and those
engineering and site preparation costs which could be identified from
total investment.
The annual amount of depreciation was calculated on a straight-line
basis, considering the useful life of each terminal component: 20 years
for tanks, foundations, oil/water separators, electrical equipment,
paving, buildings, and piping; 10 years for loading racks and associated
equipment and fire protection systems; and five years for pumps, data
systems, and trucks. Aftertax profit was calculated as 0.015 x
sales x (1 - tax rate), assuming a 46 percent tax rate and a profit
before taxes of 1.5 percent of sales (see Section 8.4.1.1.2). Sales
themselves were estimated by multiplying daily throughput by 340 days
of operation and a mid-1979 wholesale price of $0.17* per liter
*As mentioned in Section 8.1.2.1, this corresponds to a retail price
of $.229 per liter or $.869 per gallon of leaded regular.
8-81
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Table 8-43.
DEBT SERVICE COVERAGE RATIO FOR NEW FACILITIES
(Monetary values in $000 1979)
Baseline Facility:
Total Investment
Long-Term Debt (LTD)
Current Maturity LTD
(CHLTO)
Depreciable Assets
After- Tax Profit
Depredation
Cash Flow (CF)
CF*CMLTD
Alternative II
Total Investment
LTD
CMLTD
After-Tax Profit
Depreciation
Cash Flow
CF4CHLTD
Iternative III
Cash Flow
CF+CMLTD
Alternative IV
Cash Flow
CF+CMLTD
380,000 I/day
CA CRA TO REF
2.600
1,000
104
1,680
178
__160
338
3.2
2,902 2,865 2,772 2,871
1,342 1,305 1,212 1,311
134 130 121 131
149 154 153 146
176 174 169 174
325 328 322 320
2.4 2.5 2.7 2.4
323 NA 322 288
2.4 NA 2.7 2.2
326 NA 322 321
2.4 NA 2.7 2.S
950,000 I/day
CA CRA TO REF
4,000
1,600
160
2,620
445
_2S3
698
4.4
4,354 4,271 4,197 4,327
1,954 1,871 .1,797 1,927
195 187 178 193
428 439 415 423
271 267 263 270
699 706 678 693
3.6 3.8 3.8 3.6
693 NA 678 687
3.6 NA 3.8 3.6
701 NA 678 695
3.6 NA 3.8 3.6
1,900,000 I/day
CA CRA TO REF
5,900
2,360
236
3,760
890
—352
1,242
5.3
6,260 6;236 6,103 6,242
2,720 2,696 2,563 2,702
272 270 256 270
905 908 855 899
370 369 362 370
1,275 1,277 1,217 1,269
4.7 4.7 4.8 4.7
1,263 NA 1,217 1,257
4.6 NA 4.8 4.7
1,279 NA 1,217 1,280
4.7 NA 4.8 4.7
3,600,000 I/day
CA CRA TO REF
9,700
3,880
388
6.300
1,779
629
2,408
6.2
10,156 10,110 9,953 10,147
4,336 4,290 4,133 4,327
434 429 413 433
\
1,849 1,851 1,734 1,837
651 649 641 651
2,500 2,500 2.375 2,488
5.8 5.8 5.8 5.7
2.475 NA 2.376 2,464
5.7 NA 5.8 5.7
2,523 NA 2.375 2,512
5.8 NA 5.8 5.8
00
00
-------
Table 8-44. ESTIMATED CAPITAL INVESTMENT FOR NEW FACILITIES ($1979)
1
Gasoline Throughput:
Tanks56-67*68'69
Tank Foundatiogg
and Dike work
Make Dike Impermeable
Cathodic Protection70
Loading Rack Platform
and Superstructure70'7^ >73
Pumps 72»73
Rack Equipment 70'71'72'73
Oil /Water Sep.70
Electrical70'71
Data Automation System
Foam Firt Protection
System 70
Paving70
Buildings70
Piping70
Land70
Trucks74'75'76
Workinq Capital
Approximate Total
380,000
I/day
$405,225
45,000
270,000
30,000
40,000
15,000
120,000
65,000
100,000
60,000
400,000
99,000
55,000
36,000
950,000
I/day
$746,750
80,000
360,000
40,000
60,000
20,000
180,000
65,000
130,000
70,000
500,000
142,000
55,000
48,000
(8 acres) (12 acres)
320,000 480,000
243,000
300,000
$2.6 MM
486,000
500,000
$4.0 MM
1,900,000
I/day
$1,181,250
125,000
450,000
50,000
60,000
25,000
180,000
65,000
150,000
80,000
500,000
142,000
510,000
60,000
(16 acres)
640,000
729,000
1,000,000
$5.9 MM
3,800,000
I/day
$2,326,500
180,000
540,000
60,000
80,000
30,000
240,000
65,000
200,000
100,000
700,000
189,000
510,000
72,000
(20 acres)
800,000
1,620,000
2,000,000
$9.7 MM
8-83
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(see Table 6-2 and Section 8.2.2.3). Annual throughput was not adjusted
by a capacity utilization rate because, as explained in Section 8.1.1.3,
it is already a measure of the average volume of product delivered.
The sum of after-tax profit and depreciation approximates cash flow.
For simplicity, investment tax credit was not considered, since it
would not change significantly for a given model plant from one alternative
to another.
The ratio of cash flow to current maturity of long-term debt
(CMLTD) is the debt service covered ratio. It ranges from 3.2 for the
380,000 liters/day model plant to 6.2 for the 3,800,000 liters/day
plant. A ratio of 2:1 or higher is desirable, but many lenders will
accept 1.5:1. A ratio of 1:1 is considered weak.
The remainder of Table 8-43 is a presentation of changes in debt
service coverage ratio as a result of implementation of the various
regulatory alternatives whose costs are given in Tables 8-17 through
8-19. The first step followed in the methodology was to add the total
investment cost for each vapor control system to the baseline investment.
New long-term debt and CMLTD could then be determined. After-control
depreciations (assuming 10-year, straight-line for the control equipment)
were then calculated by adding 10 percent of the control equipment
cost to baseline depreciation. After-control profit was determined
under the assumption of a tax rate of 46 percent (the maximum federal
corporate income tax rate for 1979 and succeeding years), by deducting
54 percent of the annualized control costs from the baseline profit.
This is a worst case condition, for it assumes no pass-through of
control costs. The sum of depreciation and profit was the new cash
flow. It should be noted that cash flow increases under many alternative
and equipment combinations for the largest two models. New ratios
were then calculated; in no case was the ratio for any combination of
regulatory alternative and control option as low as 2:1.
The ratios in Table 8-43 are somewhat overstated because interest,
which should be included in debt service and thus in the denominator,
is actually deducted from profit, in the numerator, as part of the
annualized control costs. Only in the worst case - the combination of
8-84
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Alternative III and an REF unit for the smallest plant, would correcting
this cause the ratio to fall below 2.0; assuming an interest rate of
10 percent of the full amount of the long-term debt:
288 + .54(0.10 x 1.311) _ , Q
131 + .54(0.10 x 1,311) " ilb
The next worst case, the same combination but with Alternative II,
yields:
320 + .54(0.10 x 1.311) , Q
131 + .54(0.10 x 1,311) " i>y
A loan would probably be granted in both cases. Corrected ratios
exceed 2.0 for all other combinations.
To the extent that it can pass through control costs, a firm may
improve its debt service coverage ratio. For example, under conditions
of full cost pass-through, the ratios for the worst case described
above would become:
352
131
+ .54(0.10 x 1,311) _ 9
+ .54(0.10 x 1,311) ~ *'
To avoid unnecessary complication in calculation and presentation,
neither the interest correction nor the cost pass-through adjustment
was applied to the debt service coverage ratios in Table 8-43.
The conclusion to be drawn from the debt service coverage analysis
is that, all other things being equal, the implementation of any of
the regulatory alternatives would not restrict industry growth through
adverse effects on capital availability. This is true regardless of
model plant size, indicating that opportunity for small businesses
would not be curtailed.
8.4.1.2.2 Price and profitability. The extent to which bulk
terminal operators can pass control costs through to dealers and other
customers in the form of higher prices depends on demand elasticity.
If demand for terminal services is relatively inelastic, as it has
been in the past (see Section 8.1.2.1), control costs can be shifted
forward through price increases. Net earnings would then be largely
unaffected by any of the regulatory alternatives. If, on the other
hand, demand is relatively elastic, as it might become at the price
levels anticipated in 1980 and 1981, control costs could only partially
be passed through, if at all. They would then have a negative impact
on profitability.
8-85
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(see Table 6-2 and Section 8.2.2.3). Annual throughput was not adjusted
by a capacity utilization rate because, as explained in Section 8.1.1.3,
it is already a measure of the average volume of product delivered.
The sum of after-tax profit and depreciation approximates cash flow.
For simplicity, investment tax credit was not considered, since it
would not change significantly for a given model plant from one alternative
to another.
The ratio of cash flow to current maturity of long-term debt
(CMLTD) is the debt service covered ratio. It ranges from 3.2 for the
380,000 liters/day model plant to 6.2 for the 3,800,000 liters/day
plant. A ratio of 2:1 or higher is desirable, but many lenders will
accept 1.5:1.. A ratio of 1:1 is considered weak.
The remainder of Table 8-43 is a presentation of changes in debt
service coverage ratio as a result of implementation of the various
regulatory alternatives whose costs are given in Tables 8-17 through
8-19. The first step followed in the methodology was to add the total
investment cost for each vapor control system to the baseline investment.
New long-term debt and CMLTD could then be determined. After-control
depreciations (assuming 10-year, straight-line for the control equipment)
were then calculated by adding 10 percent of the control equipment
cost to baseline depreciation. After-control profit was determined
under the assumption of a tax rate of 46 percent (the maximum federal
corporate income tax rate for 1979 and succeeding years), by deducting
54 percent of the annualized control costs from the baseline profit.
This is a worst case condition, for it assumes no pass-through of
control costs. The sum of depreciation and profit was the new cash
flow. It should be noted that cash flow increases under many alternative
and equipment combinations for the largest two models. New ratios
were then calculated; in no case was the ratio for any combination of
regulatory alternative and control option as low as 2:1.
The ratios in Table 8-43 are somewhat overstated because interest,
which should be included in debt service and thus in the denominator,
is actually deducted from profit, in the numerator, as part of the
annualized control costs. Only in the worst case - the combination of
8-84
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Table 8-43. MAXIMUM PERCENTAGE PRICE INCREASES, COST PASS-THROUGH:
NEW FACILITIES9
Gasoline Throughput:
Vapor Processing Unit:
Regulatory Alternative
II
III
IV
380.000 I/day
CA CRA TO REF
.24 .2 .21 .27
.26 -- .2 .29
.24 - .21 .26
950,000 I/day
CA CRA TO REF
.06 .02 .1 .07
.08 — .1 .09
.05 — .1 .07
1,900,000 I /day
CA CRA TO REF
(.03) (.03) .06 (.02)
(.01) -- .06 .005
(.03) — .06 (.03)
3,800.000 I /day
CA CRA TO REF
(.06) (.06) .04 (.05)
(.04) — .04 (.03)
(.08) — .04 (.07)
00
I
CO
l( ) indicates control cost savings, which may result in price reductions.
-------
8.4.1.2.2.2 Profitability analysis. Return-on-investment (ROI)
analysis provides the means to determine whether any of the regulatory
alternatives would curtail growth that might otherwise occur by making
investment in new bulk terminals unattractive. In the case of new
facilities, the technique was applied by first calculating pre-control
ROI for each model plant as the ratio of baseline or pre-control
profit to total investment in the baseline facility, expressed as a
percentage. The profit and investment values are the same as those
which appear in Table 8-43. Then after-control profit was calculated
for each alternative, as pre-control profit less 0.54 x the annualized
control costs from Tables 8-17 through 8-19. After-control investment
was determined in the same way as for the debt service coverage analysis
(Section 8.4.1.2.1) and appears in Table 8-43. After-control ROI
could then be determined and compared with pre-control ROI and with
CO
the industry average of 15 percent.
The pre-control ROIs for each model facility size are:
380,000 liters/day 6.8 percent
950,000 liters/day 11.1 percent
1,900,000 liters/day 15.1 percent
3,800,000 liters/day 18.3 percent
Since ROIs for the two smaller facilities fall below the 15 percent
industry criterion, it is unlikely that investment would be made in
new terminals of these sizes. This is generally consistent with the
new facilities projection (Section 7.1.2), prepared in advance of this
analysis, in which most growth is expected to occur in the form of the
larger terminals. After-control ROIs are presented in Table 8-46.
Comparing the results to the pre-control ROIs shows that for the
two smaller model plants, any combination of regulatory alternative
and vapor processing equipment would have a significant negative
impact on profitability in the absence of complete control cost pass-
through. For the largest model plant, there are control options which
would permit compliance with any of the regulatory alternatives and
full cost absorption with virtually no change in ROI. The 1,900,000 liter/
day terminal could keep its decrease in ROI to 0.5 percentage points
under Alternatives II and IV, and to 0.8 percentage points under
8-88
-------
Table 8-46. AFTER-CONTROLS, AFTER-TAX RETURN ON INVESTMENT: NEW FACILITIES
Gasoline Throughput:
Processing Unit
Baseline
Regulatory Alternative
II
III
IV
380,000 I/day
CA CRA TO REF
6.8X
5. IX 5.4X 5.5X 5. IX
5, IX 5.5X 5.0X
5.2X 5.5X 5.1X
950,000 I/day
CA CRA TO REF
11. IX
9.8X 10.3X 9.9X 9.8X
9.7X 9.9X 9.6X
9.9X 9.9X 9.8X
1,900,000 I/day
CA CRA TO REF
15. IX
14. 5X 14. 6X 14. OX 14. 4X
14. 3X 14. OX 14. 2X
14. 5X 14. OX 14. 6X
3,800,000 I/day
CA CRA TO REF
18.3X
18.2X 18. 3X 17. 4X 18.1X
18. OX 17. 4X 17. 9X
18.4X 17. 4X 18. 3X
CD
CO
-------
Alternative III, by careful control equipment selection Its ROI
would fall only slightly below the industry average of 15 percent but
would remain well above the 11 percent minimum. Since some cost
pass-through appears possible, new investment in the form of 1,900,000
liter/day and 3,800,000 liter/day terminals should remain attractive.
The ROI analysis also shows that for the two largest model plants,
operation under Regulatory Alternative IV would not be less profitable
than under II and III and could, in some cases, be more profitable.
For the two smaller models, Alternative II with CRA equipment would be
slightly more profitable than Alternative IV with any control option;
otherwise, all alternatives are approximately equal.
8.4.1.2.3 Impacts of performance testing and monitoring costs.
Performance testing alone requires no capital investment. Depending
on control equipment installed and monitoring option selected, capital
expenditures for monitoring equipment are expected to range from
$8,000 to $34,000. Even in the worst case, a 380,000 liter/day facility
under Alternative III, using a refrigeration unit and conducting
three-day tests, the uncorrected debt-service coverage ratio is only
reduced from 2.2 to 2.1. This indicates that testing and monitoring
costs would not affect industry growth through restriction of access
to investment capital.
The annualized testing and monitoring costs, if fully absorbed by
the model plants, would decrease after-tax profits by a maximum of
$12,300 at thermal oxidizer installations and $10,300 where other
options are used. Because the costs are the same for all four models,
impacts will be most pronounced on the smallest plant, where ROIs will
be reduced by approximately 0.2 percentage points. ROIs for a 950,000
liter/day plant will decline by 0.1 to 0.2 percentage points. For the
two larger plants, reductions will be 0.1 percentage points or less.
Testing and monitoring costs, therefore, do not appear likely to
adversely affect the attractiveness of investment in 1,900,000 liter/
day or 3,800,000 liter/day facilities or to alter the marginal status
of a 950,000 liter/day terminal.
8.4.1.2.4 Conclusions for new facilities. Under any regulatory
option and, in fact, in the absence of any, it does not appear that
8-90
-------
industry growth in the form of 380,000 liter/day bulk terminals will
take place. Capital availability will not be a limiting factor, but
potential pre-control returns are not attractive. 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.
If pass-through were not possible, there would probably be a shift
toward the larger terminal sizes in any expansion of this industry.
The 3,800,000 liter/day bulk terminals would appear to be attractive
investments under any control option, and 1,900,000 liter/day facilities
would certainly remain viable. Consequently, industry growth, in
terms of the terminal sizes most likely to be constructed in the
absence of a standard, would not be adversely affected by its
implementation.
The rapid gasoline price increases which have occurred since
control cost estimates were developed - nearly 50 percent since
mid-1979 - result in reduced annualized control costs for those control
options involving vapor recovery. Assuming a 50 percent increase, the
effect on after-tax profit is an increase of 0.54 x 0.50 x recovery
credit. Under Regulatory Alternative IV, the results would be improvements
in after-tax profits of 4.9, 4.3, 4.0, and 4.0 percent for the four
model plants, respectively. In terms of ROI, this signifies increases
of 0.3 percent for the two smaller models and 0.5 percent for the two
larger ones. The 380,000 liter/day model plant is still an unattractive
investment, and the 950,000 liter/day model still must be considered
marginal. The overall conclusions remain the same.
To this point in the discussion, differences between marine and
pipeline terminals have not been considered. The model facilities
being used in the analysis generally reflect pipeline terminal
characteristics, with the principal difference being the need for a
dock and associated equipment at a marine terminal. A previous study
of 950,000 liter/day and 1,900,000 liter/day facilities has shown that
a marine facility with the same tank capacity would require depreciable
78
assets of from 29 to 47 percent more than a comparable pipeline terminal.
8-91
-------
This means that both CMLTD and depreciation would increase by an
average of approximately 38 percent. The worst case, from an uncorrected
debt service standpoint, would then become:
146 + 1.38(174) 9 ,
1.38(131)" *'L
The change in debt service coverage ratio is not significant.
The cost pass-through analysis would not be affected by the
differences in capital investment. Their effect on profitability of
marine terminals can be determined by increasing the denominator,
total investment, in the ROI expression. Table 8-43 shows that depreciable
assets are 65 percent of total investment, so the correction for
marine terminals becomes:
Total Investment + .38(.65 x Total Investment) = 1.25 x Total Investment
Increasing the denominator by .25 is equivalent to reducing the ROI to
0.8 of the values in Table 8-46. The 380,000 liter/day and 950,000 liter/
day terminals appear even less attractive as investments before controls
and fall clearly below the minimum acceptable ROI after controls, in
the absence of cost pass-through. The minimum ROIs for 1,900,000 liter/
day and 3,800,000 liter/day terminals become 11.2 and 13.9 percent,
respectively.
Few, if any, new marire terminals are expected to be constructed
62
at all, and the impact of the standard should thus be slight.
However, the imposition of controls would tend to cause any new marine
terminals to be in the larger size categories.
8.4.1.3 Impacts on Modified or Reconstructed Facilities.
Approximately 50 bulk terminals are expected to be modified or recon-
structed in the 1980-1985 period covered by this assessment. Roughly half
of these will be in attainment areas and would thus experience the full
economic impact of additional controls (see Section 7.1.2). The other
half will be affected if either Regulatory Alternative III or IV is
selected for the standard. Existing facilities were thus subjected to
the same three analyses applied to new facilities in Section 8.4.1.2.
8-92
-------
8.4.1.3.1 Cash flow and capital availability. In performing
debt service coverage analysis, the four model plants were assumed to
have been constructed five years ago. The total investments for new
facilities were adjusted to reflect 1974 cost levels using the Chemical
Engineering Plant Cost Index, in which September 1979 = 243.4 and 1974
79
= 165.4. The resulting total investment, long-term debt, CMLTD, and
depreciable assets are shown in Table 8-47. For simplicity, depreciation
was assumed to be 10-year straight-line for all plant components. All
other assumptions remain the same as for new facilities. Debt service
coverage ratios range from 4.1 for a 380,000 liter/day terminal to 8.4
for a 3,800,000 liter/day operation.
In Chapter 5, a variety of possible reconstructions and modifications
80
are described. Those to which a specific cost can be assigned are:
Adding or replacing a loading rack $90,000-$160,000
Converting a rack from top to bottom loading $90,000-$160,000
Adding a loading arm to an existing rack $25,000
For simplicity in the debt service coverage analysis, complete replacement
of a loading rack with no salvage value at a cost of $120,000 is
assumed to be the reconstruction which causes the facility to become
subject to controls. A cost of $120,000 is therefore added to total
investment. Then total investment, LTD, CMLTD, profit, and depreciation
are adjusted in the manner described in Section 8.4.1.2.1, using
various control equipment costs in Tables 8-29 through 8-36, and new
debt service coverage ratios are calculated. The results are shown in
Tables 8-48 through 8-51. The lowest coverage ratio is 2.4, indicating
that capital availability for reconstructions and modifications would
not be adversely affected by implementation of any of the regulatory
alternatives. The ratios are slightly overstated as described in
Section 8.4.1.2.1; correction would not cause any combination of
regulatory alternative and control option to fall into the range where
financing would be questionable.
8.4.1.3.2 Cost pass-through analysis. Cost pass-through analysis
identical to that applied to new facilities yielded similar results,
as presented in Table 8-52. The maximum pass-through, if all costs
8-93
-------
Table 8-47. DEBT SERVICE COVERAGE RATIO, EXISTING FACILITY - BASELINE ($000)
Existing Facility:
Total Investment
Long-Term Debt (LTD)
Current Maturity LTD
(CMLTD)
Depreciable Assets
After- Tax Profit
Depreciation
Cash Flow (CF)
CF+CMLTD
380,000 I/day
1,770
710
71
1,140
178
114
292
4.1
950,000 I/day
2,720
1,090
109
1,780
445
178
623
5.7
1,900,000 I/day
4,010
1,600
160
2,560
890
256
1,146
7.2
3,800,000 I/day
6,600
2,640
264
4,280
1,779
428
1
2,207
8.4
00
I
to
-------
Table 8-48.
DEBT SERVICE COVERAGE RATIO, EXISTING FACILITY,
BOTTOM LOADED - ATTAINMENT AREA ($000)
Alternative II
Total Investment
LTD
CMLTD
Depreciable Assets
After-Tax Profit
\* Depreciation
Cash Flow
CF« CMLTD
Alternative III
Cash Flow
CF*CMLTD
Alternative IV
Cash Flow
CF«CMLTO
380,000 I/day
CA CRA TO REF
2,193 2,156 2.064 2,162
877 862 826 865
88 86 83 86
1,300 1,280 1,230 1,283
149 154 153 146
130 128 123 128
279 281 276 274
3.2 3.3 3.3 3.2
277 NA 275 271
3.1 NA 3.3 3.2
280 NA 276 275
3.2 NA 3.2 3.2
950,000 I /day
CA CRA TO REF
3,196 3,113 3,039 3,169
1,278 1,245 1.216 1.267
128 124 122 127
1,965 1,920 1,880 1,950
428 451 414 423
196 192 188 195
624 643 602 617
4.9 5.2 4.9 4.9
618 NA 607 605
4.8 NA 5.0 4.8
626 NA 603 620
4.9 NA 4.9 4.9
1.900,000 I/day
CA CRA TO REF
4,494 4,470 4,337 4.476
1,797 1.788 1,735 1,790
180 179 174 179
2,745 2.732 2,660 2,735
904 907 855 900
274 273 266 274
1,179 1,180 1.121 1.173
6.5 6.5 6.4 6.6
1,167 NA 1,122 1,161
6.5 NA 6.4 6.5
1.183 NA 1,128 1,177
6.6 NA 6.5 6.6
3.800,000 I/day
CA CRA TO REF
7.184 7,138 6.981 7.175
2.874 2.855 2,792 2,870
288 285 279 287
4,505 4,480 4.395 4.500
1.848 1.850 1.732 1.836
450 448 440 450
2,298 2,298 2,173 2,286
8.0 8.0 7.8 8.0
2.273 'HA 2,163 2,262
7.9 NA 7.8 7.9
2,306 NA 2,173 2.294
8.0 NA 7.8 8.0
00
vo
01
-------
Table 8-49. DEBT SERVICE COVERAGE RATIO, EXISTING FACILITY, TOP LOADED
ATTAINMENT AREA ($000)
Alternative II
Total Investment
LTD
CMLTD
Depreciable Assets
After-Tax Profit
Depreciation
Cash Flow
CF«CMLTD
Alternative III
Cash Flow
CFtCKLTD
Alternative IV
Cash Flow
CF+CMLTO
380,000 I/day
CA CRA TO REF
2,520 2,483 2,390 2,489
1,008 993 956 996
101 99 96 100
1,300 1,280 1,230 1,283
114 118 111 375
130 128 123 128
244 246 241 238
2.4 2.5 2.5 2.4
242 NA 241 236
2.4 NA 2.5 2.4
244 NA 241 239
2.4 NA 2.5 2.4
950,000 I/day
CA CRA TO REF
3,691 3,609 3,534 3,664
1,476 1,443 1,414 1,466
148 144 141 147
1,965 1,920 1,880 1,950
386 361 369 851
196 192 188 195
571 578 549 564
3.9 4.0 3.9 4.8
565 NA 549 558
3.8 NA 3.9 3.8
572 NA 549 566
3.9 NA 3.9 3.9
1,900,000 I/day
CA CRA TO REF
4,995 4,971 4,838 4,977
1,998 1,988 1,935 1,991
200 199 194 199
2,745 2,732 2,660 2,735
851 854 801 845
274 273 266 274
1,125 1,127 1,067 1,119
5.6 5.7 5.5 5.6
1,112 NA 1,067 1,107
5.6 NA 5.5 5.6
1,128 NA 1,067 1,123
5.6 NA 5.5 5.6
3,800,000 I/day
CA CRA TO REF
7,872 7,826 7,669 7,863
3,149 3,130 3,068 3,145
315 313 307 314
4,505 4,480 4,395 4,500
1,774 1,776 1,658 1,762
450 448 440 450
2,224 2,224 2,098 2,212
7.1 7.1 6.8 7.0
2,199 'NA 2,100 2,188
6.9 NA 6.8 7.0
2,232 NA 2,098 2,220
7.1 NA 6.8 7.1
00
vo
en
-------
Table 8-50. DEBT SERVICE COVERAGE RATIO
FOR EXISTING FACILITY, UNIT REPLACED —
NON-ATTAINMENT AREA ($000)
Alternatives III & IV
Total Investment
LTD
CMLTD
Depreciable Assets
After- Tax Profit
Depreciation
Cash Flow
CFt CMLTD
380,000 I/day
CA TO REF
2,075 1,991 2,054
830 796 822
83 80 82
1,293 1,223 1,276
158 155 154
129 122 128
287 277 282
3.5 3.5 3.4
950,000 I/day
CA TO REF
3.055 2,953 3,037
1,222 1,181 1,215
122 118 122
1,958 1,873 1,943
422 397 416
196 187 194
618 584 610
5.1 4.9 5.0
1,900,000 I/day
CA TO REF
4,343 4,241 4,331
1,737 1.696 1,732
174 170 173
2,736 2,651 2,726
870 803 866
274 265 273
1,145 1,068 1,139
6.6 6.3 6.6
3,800,000 I/day
CA TO REF
6,980 6,848 6,974
2,792 2,739 2.790
279 274 279
4,495 4,385 4,490
1,761 1,611 1.750
450 438 449
2,211 2,049 2,199
7.9' 7.5 7.9
00
-------
Table 8-51. DEBT SERVICE COVERAGE RATIO,
EXISTING FACILITY,
SECONDARY UNIT ADDED ON
NON ATTAINMENT AREA ($000)
Alternatives II! & IV
Total Investment
LTD
CHLTO
Depreciable Assets
After- Tax Profit
Depreciation
Cash Flow
CF+CMLTD
380, 000 Vday
CA TO
1,965 2,025
786 810
79 81
1,190 1,230
167 158
119 123
286 281
3.6 3.5
950,000 I/day
CA TO
2,939 2,990
1,176 1,196
118 120
1,846 1,880
433 422
185 188
618 610
5.2 5.1
1,900,000 Vday
CA TO
4,229 4,280
1,692 1,712
169 171
2,626 2,660
880 865
263 266
1,143 1,131
6.7 6.6
3,800,000 I/day
CA TO
6,841 6,892
2,736 2,757
274 276
4,361 4,395
1,7,70 1,750
436 440
2,206 2,190
8.1 7.9
00
10
00
-------
Table 8-52. MAXIMUM PERCENTAGE PRICE INCREASES, COST PASS-THROUGH: EXISTING FACILITIES
Gasoline Throughput:
Vapor Processing Unit:
Facility Description 4 Alternatives
Bottom Loaded, Attainment: II
III
IV
Top Loaded, Attainment: II
111
IV
Unit Replaced, Non-Attainment: III, IV
Unit Added, Non-Attainment: III, IV
380,000 I/day
CA CRA TO REF
.24 .2 .21 .27
.26 — .22 .29
.24 — .21 .26
.54 .51 .51 .57
.56 - .51 .59
.54 -- .51 .56
.17 -- .2 .2
.09 - .17 --
950,000 I/day
CA CRA TO REF
.06 .02 .1 .07
.08 — .1 .1
.05 -- .1 .07
.24 .02 .28 .25
.26 — .28 .27
.23 — .28 .25
.08 — ; .16 .1
.04 -- .08 —
1,900,000 I/day
CA CRA TO REF
(.03) (.03) .06 (.02)
(.004) -- .06 .006
(.03) -- .06 (.02)
.07. .06 .15 .08
.09 — .15 .1
.06 — .15 .07
.03 -- .15 .04
.02 — .04 --
3,800,000 I/day
CA CRA TO *EF
(.06) (.06) .04 (.05)
(.04) — .05 (.03)
(.06) - .04 (.06)
.005 .002 .01 .01
.03 — .1 .03
(.002) — .1 .008
.02 -- .14 .02
.008 -- .02 — •
00
I
ID
*( Indicates control cost savings, which may result in price reductions.
-------
were passed on to the customer, would be 0.59 percent, which would
have no significant inflationary or demand-related profitability
impacts. This price increase would be incurred by the customers of
affected terminals, who would in turn pass on the increases in varying
degrees at the retail level. In any case, the resulting nationwide
price increase would be likely to be negligible.
8.4.1.3.3 Profitability analysis. The analysis of ROI was
performed in the same manner as for new facilities, with the exception
of the estimation of the pre-controls asset base. Because an after-tax
ROI of 15 percent is the industry average (Section 8.4.1.1.2), it was
assumed that model existing plants were operating at this level.
Estimated pre-control profits, calculated as for new plants, were
divided by 0.15 to obtain asset base. To this result were added the
capital costs (equipment and installation) for control equipment in
Tables 8-29 through 8-36. Corresponding annualized control costs were
subtracted from profits, and post-control ROIs were calculated.
Table 8-53 shows the results.
One can conclude that under the assumption of no cost pass-through
(which is unduly strict, as most if not all costs will be able to be
passed forward), all models of existing plants would experience a
decrease in profitability. It would be more severe in the case of top
loaded facilities in attainment areas, where post-control ROIs range
from 6.1 percent for the smallest model to 13.7 percent for the largest.
Both the 380,000 liter/day and 950,000 liter/day terminals would
encounter ROIs of less than 11 percent, taken to be the minimum acceptable
return (see Section 8.4.1.2.1). A 380,000 liter/day plant, bottom
loaded in an attainment area, would experience marginal ROIs. In all
other cases and for all plant sizes, ROIs of 11 percent or higher
remain possible.
8.4.1.3.4 Impacts of performance testing and monitoring costs.
As in the case of new facilities, debt service coverage ratio will not
be significantly lowered by the capital costs for testing and monitoring
equipment (see Section 8.4.1.2.3). Consequently, terminals contemplating
actions which would cause them to become affected facilities would not
encounter barriers in the form of capital unavailability.
8-100
-------
Table 8-53. AFTER-CONTROLS, AFTER-TAX RETURN ON INVESTMENT: EXISTING FACILITIES
Gasoline Throughput:
Processing Unit
Bottom Loaded, Altai nnent Area
II
III
IV
Top Loaded, Attalnnent Area
II
III
IV
Unit Replaced, Non-Attainment Area
III A IV
Secondary Unit Added,
Non-Attainment Area
III « IV •
380,000 I/day
CA CRA TO REF
9.7% 10. 2% 10.71 9.6%
9.5% — 10.6* 9.5%
9.7% — 10.7% 9.7%
6.3% 6.6% 7.0% 6.2%
6.1% — 7.0% 6.1%
6.3% — 7.0% 6.2%
11.4% — 11.9% 11.3%
13.3% --- 11.9% —
950,000 1/rtay
CA CRA TO REF
12.9% 13.6% 13.1% 12.8%
12.7% --- 13.1% 12.6%
12.9% --- 13.1% 12.9%
9.8% 10.3% 9.9% 9.7%
9.7% — 9.9% 9.6%
9.9% — 9.9% 9.8%
13.2% — 12.8% 13.1%
14.1% — 13.5% —
1,900,000 I/day
CA CRA TO REF
14.4% 14.5% 13.9% 14.3%
14.2% — - 13.9% 14.1%
14.4% --- 13.9% 14.4%
12.5% 12.6% 12.1% 12.4%
12.3% — 12.1% 12.2%
12.6% — - 12.1% 12.5%
14.1% -- 13.2% 14.0%
14.4% — 14.2% —
3,800,000 I/day
CA CRA TO REF
15.0% 15.1% 14.3% 14.9%
14.8% — - 14.2% 14.7%
15.1% — 14.3% 15.0%
13.6% 13.7% 12.9% 13.6%
13.4% — 13.0% 13.4%
13.7% — - 12.9% 13.6%
14.5% — - 13.5% 14.4%
I
14.8% — 14.5% —
CO
-------
Effects on ROI range from a decrease of as much as 1.0 percentage
point for the 380,000 liter/day model plant under Option 3 to a negligible
change for the 3,800,000 liter/day terminal. The 380,000 liter/day
existing facility, marginal unless top loaded in an attainment area,
appears less viable but still marginal as an affected facility. The
950,000 liter/day model remains slightly better than marginal, except
when top loaded in an attainment area where its ROI falls further
below industry standards. The other models are affected very little
by testing and monitoring costs.
8.4.1.3.5 Conclusions for existing facilities. Existing
380,000 liter/day top or bottom loaded facilities and 950,000 liter/day
facilities, top loaded, in attainment areas, would have to pass on
nearly all of the control costs in order to maintain a reasonable rate
of return under any regulatory alternative. Nearly 80 percent of
existing terminals are in this size range (see Section 3.1.2).
However, only about 30 percent of all existing terminals will not
already be controlled to at least Alternative II levels through SIPs.
Consequently, if all 50 existing facilities expected to be subject to
controls were in this size range, most would still experience post-control
ROIs of between 11.3 and 14.1 percent, depending on the control approach
selected. Only a few would fall into the categories where their
profitabilities would be significantly reduced.
Existing plants in the other circumstances considered in this
section should not encounter situations which would seriously affect
their viability in making reconstructions or modifications under any
of the regulatory alternatives.
As in the case of new facilities, gasoline price increases experienced
to date and foreseeable in the near future will not alter the overall
conclusions for existing facilities.
For marine terminals, the same adjustments must be made as for
new facilities (Section 8.4.1.2.3). The worst case debt service
coverage ratio, 2.4 for Alternative III, REF, top loaded in an attainment
area (Table 8-50) becomes:
111 + 1.38(128) = 2>lj
1.38(100)
8-102
-------
indicating no adverse effects in terms of capital availability. There
is no change in the cost pass-through results. Multiplying all ROIs
by 0.8 moves the 380,000 liter/day and 950,000 liter/day terminals
below 11 percent for all regulatory alternatives, indicating that
control costs would adversely affect profitability for any modified or
reconstructed marine terminals in the lower size ranges. Except for
top loaded, 1,900,000 liter/day facilities in attainment areas (ROI
10 percent), the two larger models would continue to experience ROIs
of 11 percent or higher as marine terminals.
8.4.2 Impacts on the Independent Tank Truck Industry
In this section, the potential economic impacts of the regulatory
alternatives on the independent tank truck industry are examined.
Because tank trucks working directly with bulk terminals which are
subject to the proposed standards would have to install controls
(Section 8.2.5), existing as well as new tank truck firms would be
affected. Estimation of the impact is complex to the extent that it
is difficult to predict not only what proportion of a firm's tank
truck fleet would require controls but how the long-term structure of
the industry would be affected.
8.4.2.1 Financial Profile. Detailed operating and financial
statistics on the independent tank truck industry are published annually.
Information is available for the industry as a whole, for firms grouped
by revenue size, and for a sample of individual firms. As shown in
Table 8-54, operating expenses and revenue levels applied in the
analysis were developed from sample firm data. Large differences
exist in expenses and revenues per trailer among model firms 2, 3, and
4 and can be accounted for, at least in part, by the pattern in the
81
trailer-to-tractor ratios. Smaller firms evidently have fewer
trailers per tractor, which probably results in more intensive use of
their existing trailers. Larger expenses and revenues per trailer can
thus be expected. It is also likely that the smaller firms use their
tractors to pull non-owned trailers more often than do larger firms.
Since revepues and expenses accrued in this manner are not separable
from those attributable to owned trailers in the industry statistics,
8-103
-------
Table 8-54. OPERATING EXPENSES AND REVENUES FOR
TANK TRUCK FIRMS82'83
MODEL FIRM
Sample Firm Statistics9
Revenues/Firm ($000)
Operating Expenses/Firm ($000)
Operating Ratio0*
No. Trailers/ Firm6 f
Operating Revenues/Trailer ($000)
Operating Expenses/Trailer ($000)g
Trailer/Tractor Ratio
880
803
91.3%
N.A.
N.A.
N.A.
N.A.
1370
1238
94.7%
6
218
206
0.84
2064
1958
94.9%
29
71
67.5
1.29
13,024
12,267
94.2%
231.5
56
53
1.47
Model Firm Parameters
No. Trailers/Firm11
Operating Revenues/Firm ($000).
Operating Expenses/Firm ($000)°
Operating Income^ ,
Net Income Before Income Tax (EBIT)
Net Income
2
657.2
600
57.2
46.0
23.0
7
1520.6
1440
80.6
63.9
32.0
30
2136.1
2025
111.1
83.6
43.8
100
5626.3
5300
326.3
258.8
129.4
aThe sample sizes for the model firms were 6 for size 1, 4 for size 2, 62 for
size 3, and 111 for size 4. Statistics for the three larger firm sizes were
obtained from Reference 82, with limited statistics for the small firm obtained
from Reference 83.
n"otal actual revenue * number of firms sampled.
Total actual operating expenses t number of firms sampled.
Operating expenses/firm * revenues/firm.
eThe statistical mean for each sample firm category.
Revenues/firm * no. trailers/firm.
^Operating expenses/firm * no. trailers/firm.
hRefer to Section 6.2.5 of Chapter 6.
1Model firm operating expenses (note j) * sample operating ratio.
JEstimated as sample operating expenses/trailer x number of model firm trailers.
Given limited sample statistics available for model firm 1, average firm
operating expenses were estimated to range from $200,000 to $400,000 (by
extrapolation) with $300,000 selected as the mean.
i,
Operating revenues - operating expenses.
Operating income - interest expense.
mEBIT x (1 - marginal tax rate). An assumed 50 percent marginal tax rate
includes a Federal tax rate of 46 percent and a State and local tax rate of
4 percent.
8-104
-------
they contribute to higher revenue-per-trailer results for smaller
firms. Table 8-55 lists industry statistics applied in the analysis.
8.4.2.2 Economic Impact Analysis. Three types of economic
impact analysis were performed:
1. Return-on-investment analysis,
2. Cost pass-through analysis, and
3. Debt service coverage analysis.
In return-on-investment (ROI) analysis, the impact of control
costs on existing firms' viability and the attractiveness of investment
in new firms is examined. If firms fully absorbed control costs,
ROI would decrease. For this analysis, a more specialized parameter,
the return-on-transportation investment (ROTI), was evaluated.*
This indicator, which does not reflect non-transportation investment,
85
is a commonly-used general measure of trucking industry performance.
In cost pass-through analysis, the maximum price increase which
would take place if firms passed control costs through to customers
in the form of higher prices is examined. It is assumed here that
firms will increase operating income by raising prices in order to
maintain pre-control ROTI after the imposition of controls.
Whether or not firms can meet increased annual debt service
costs under controls is assessed in the debt service coverage analysis.
If the ratio of a firm's cash flow to current maturity long-term
debt (CMLTD) is 2, debt service coverage is considered to be healthy.
A ratio less than 1 indicates that annual debt service costs cannot
be met and that firms will therefore find their access to capital
restricted.
8.4.2.2.1 Return on transportation investment. Table 8-56
contains the appropriate data and calculations necessary for the
ROTI analysis. In order to calculate ROTI, both net income and
transportation investment had to be estimated for the baseline data.
Sample ROTI statistics for the baseline case were available but were
calculated using operating income only. From these data, transportation
*ROTI is equal to net carrier operating income divided by carrier
operating property, net, plus working capital.
8-105
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Table 8-55. FINANCIAL RATIOS AND STATISTICS
Ratio Level
Before-Tax Profit Margin (Net income before taxes *
gross revenues) 4.5%
Return on Transportation Investment (Operating income *
(net property working capital))
Sales less than $1 million 31.10%
Sales $1-5 million 16.87%
Sales $5-10 million 20.26%
82 83
Long-Term Debt/Revenue '
Sales less than $1 million 5.7%
Sales $1-10 million 10.3%
82 83
Interest Payment/Revenue '
Sales less than $1 million 1.7%
Sales $1-5 million 1.1%
Sales $5-10 million 1.2%
Capital Investment/Revenue82'83 33.9%
oo oo
Depreciation/Revenue ' ^ 5.4%
82 83
Current Maturity Long-Term Debt/Depreciation * 69.0%
Average Wholesale Price for Gasolinea $ 0.170/1iter
84
Transportation Rate for Gasoline $ 0.004/1iter
Transportation Rate as a Percent of Gasoline Price 2.3%
aRefer to Section 8.2.2.3.
8-106
-------
Table 8-56. ROTI ANALYSIS
($000)
Baseline
ROTI (Operating Income)
Revenue
Operating Expenses
Operating Income
Interest Expense
EBIT
Taxes (50%) a
Net Income
Transportation Investment0
ROTIC
Scenario 1 (300 Trucks or 1% of
Revenue
Operating Expenses'*
Operating Income
Interest Expense
EBIT
Taxes3
Net Income
Transportation Investment6
ROTIC
1
31.10%
657.20
600.00
57.20
11.20
46.00
23.00
23.00
183.92
12.5%
Total Popula
657.20
603.20
54.00
11.20
42.80
21.40
21.40
188.72
11.3*
Scenario 2 (90 Trucks or 3/10 of 1% of Total
Revenue
Operating Expenses^
Operating Income
Interest Expense
EBIT
Taxes3
. Net Income
Transportation Investment6
ROTIC
657.20
604.70
52.50
11.20
41.30
20. S5
20.55
196.72
10.5%
Model
2
16.90%
1520.60
1440.00
80.60
16.70
63.90
31.95
31.95
476.92
6.7%
tion):
1520.60
1451.30
69.30
16.70
52.60
25.30
25.30
493.72
5.3%
Population):
1520.60
1456.60
64.00
16.70
47.30
23.55
23.65
521.72
4.5%
Firm
3
16.90%
2136.10
2025.00
111.10
23.50
87.60
43.80
43.80
657.40
6.7%
2136.10
2049.10
87.00
23.50
63.50
31.75
31.75
693.40
4.635
2136.10
2060.50
75.60
23.50
52.10
25.05
26.05
753.40
3.4%
4
20.30%
5626.30
5300.00
326.30
67.50
258.80
129.40
129.40
1607.39
8.1%
5626.30
5380.30
246.00
67.50
178.50
89.25
89.25
1727.39
5.2%
5625.30
5418.30
208.00
67.50
140,50
70.25
70.25
1927.39
3.6%
Assumed tax rates are 46 percent for the Federal government and 4 percent
for the State and local governments.
Operating income * ROTI (operating income).
%t income * transportation investment.
Baseline operating expenses + annualized control costs including the addi-
tional interest expense.
Baseline transportation investment + capital control costs.
8-107
-------
investment for each model firm was estimated by dividing operating
income by the original ROTI. This baseline estimate of transportation
investment was then used to calculate net income ROTI for the three
levels of control.
In preparing Table 8-56, demand was assumed to be totally elastic
with no change in price, volume, or revenue. The control costs were
assumed to be totally absorbed by the firm. Additional assumptions
are explained in the footnotes to Table 8-56.
The results of the ROTI analysis suggest a decline in ROTI of 1.2
to 2.9 percentage points, or a relative decline of 9.6 to 35.8 percent
for the four model firms under Scenario 1. A greater impact would
result under Scenario 2, with a 2.0 to 4.5 percentage point decline in
ROTI, or a relative decline of 16.0 to 55.6 percent.
8.4.2.2.2 Cost pass-through analysis. Table 8-57 presents the
results of the cost pass-through analysis. Using the baseline net
profit ROTI developed in Table 8-56, the pro forma income statements
for the four model firms can be developed in reverse, yielding the
revenue levels necessary to maintain the baseline ROTIs. In order for
the model firms to achieve these specific revenue levels, control
costs must be fully passed along. Full cost pass-through assumes
demand to be totally inelastic.
Accordingly, control costs associated with Scenario 1 will
necessitate rate increases of 0.6 percent to 1.8 percent, with the
larger firms requiring the larger rate increases. The rate increase
gradient for Scenario 2 follows a similar pattern, with rate increases
ranging from 1.2 to 3.0 percent.
The unexpected pattern of rate increases over the four model
firms is due to the pattern in the trailer-to-tractor ratio presented
earlier in Table 8-54. The expected rate increase gradient should be
just the opposite since the annual!zed control costs per trailer for
model firms 1 and 2 are twice those for model firms 3 and 4. The
causes both per-trailer revenues and expenses to be larger. The
calculations in Table 8-58 show the absolute control cost per trailer
for firms 1 and 2 is relatively small when compared to their relatively
large expense per trailer.
8-108
-------
Table 8-57. COST PASS-THROUGH ANALYSIS
Model Firm
Original Revenue
Scenario 1
Maintain ROTia
Transportation Investment
Necessary Net Income
+ Taxes (50 percent)
MBIT
+ Interest Costs
Operating Income
+ Operating Expenses
Necessary Revenues
Necessary Rate Increase0
Scenario 2
Maintain ROTIa
Transportation Investment3
Necessary Net Income
+ Taxes (50 percent)
NBIT
+ Interest Costs
Operating Income
+ Operating Expenses
_ Necessary Revenues
Necessary Rate Increase
1
657.20
12.5%
188.72
23.59
23.59
47.18
11.20
58.30
603.20
661.50
0.6%
•
12.5%
196.72
24.59
24.59
49.18
11.20
60.38
604.70
665.08
1.2%
2
1520.60
6.7%
493.72
33.08
33.08
66.16
16.70
82.86
1451.30
1534.16
0.9%
6.7%
521.72
34.95
34.95
69.90
16.70
86.60
1456.60
1543.20
1.5%
3
2136.10
6.7%
693.40
46.46
46.46
92.92
23.50
116.42
2049.10
2165.52
1.4%
6.7%
753.4
50.48
50.48
100.96
23.50
124.46
2060.50
2184.96
2.3%
4
5626.30
8.1%
1727.39
139.92
139.92
279.84
67.50
347.34
5380.30
5727.64
1.8%
8.1%
1927.39
156.12
156.12
312.24
67.50
379.74
5418.30
5798.04
3.0%
aGiven in Table 8-56.
ROI x transportation investment.
(Necessary revenue's * original revenues) - 1.
8-109
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Table 8-58. PER-TRAILER CONTROL COSTS AS A
PERCENT OF PER-TRAILER EXPENSES
Model Firm
Operating Expenses/Trailer
($000)a
300
206
67.5
53
Annualized Control Costs/Owned
Trailer ($000)b
Scenario 1
Scenario 2
1.6
2.4
1.6
2.4
0.8
1.2
0.8
1.2
Control Costs/Operating Expenses
Scenario 1
Scenario 2
0.5%
0.8%
0.8%
1.1%
1.2%
1.8%
1.5%
9 -jo/
£. . O/o
"Given in Table 8-54.
Given in Table 8-39. An adjustment to the values in that table was made for model
firms 3 and 4 because Table 8-58 deals with all owned trailers, whereas Table 8-39
deals with only those requiring conversions.
8-110
-------
The final impact on the wholesale price for gasoline will be
minor since the! transportation rate is such a small component of the
OA
wholesale price (2.3% = $.004/1 iter + $0.17/1 Her). Cost pass-through
will necessitate a range of price increases of 0.01 percent (0.023 x 0.006)
to 0.04 percent (0.023 x 0.018) for Scenario 1. For Scenario 2 the
price increases range from 0.03 percent (0.023 x 0.012) to 0.07 percent
(0.023 x 0.030).
8.4.2.2.3 Debt service coverage analysis. Table 8-59 presents
the results of the debt service coverage analysis. The decline in the
debt service coverage ratio ranges between 4.2 and 14.3 percent for
Scenario 1 and 8.3 to 19.0 percent for Scenario 2. In absolute terms,
the debt service coverage ratio is approximately 2.0 for all the model
firms under the baseline case. Under Scenarios 1 and 2, the ratio
drops minimally to the 1.7 to 1.9 range for model firms 2, 3, and 4.
This decrease does represent a slight increase in lender risk, but not
enough to affect the capital financing capability of the model firms.
8.4.2.3 Conclusion. The extent to which the regulatory alternatives
would have a potentially significant economic impact on the independent
tank truck industry varies by hypothetical firm size. Under both
Scenario 1 (add-on of vapor recovery equipment only) and Scenario 2
(vapor recovery plus conversion from top loading to bottom loading),
the smallest firm size would not be significantly affected by the
regulatory alternatives. Return-on-transportation investment rates
would drop by, at most, 2.0 percentage points if control costs were
fully absorbed. If the control costs were fully passed through to the
consumer in the form of higher prices, prices would increase by a
maximum of 0.01 to 0.03 percent.
In the absence of some control cost pass-through, the viability
of the three largest firms could become threatened with the imposition
of any of the regulatory alternatives, largely because return-on-
transportation investment rates could drop by 1.4 to 4.5 percentage
points, representing a relative decrease of 21 to 56 percent in ROTI.
However, assuming full cost pass-through, maximum percentage price
increases would remain low, approximately 0.02 to 0.07 percent, and
the firms1 ability to meet debt service costs would, as for the smaller
plants, remain healthy.
8-111
-------
Table 8-59. DEBT SERVICE COVERAGE ANALYSIS
(Current Maturity Long-Term Debt)
($000)
MODEL FIRM
Baseline
Net Income After Taxes
Depreciation3
Cash Flowb
CMLTDC
Debt Service Coverage
Scenario 1
Net Income After Taxes
Depreciation6
Cash Flow
CMLTDC
Debt Service Coverage
Scenario 2
Net Income After Taxes
Depreciation6
Cash Flow
CMLTDC
Debt Service Coverage
1
23.00
35.30
58.30
24.50
2.4
21.40
36.30
57.70
25.00
2.3
20.65
37.90
58,55
26.20
2.2
2
31.95
82.10
114.05
56.60
2.0
26.30
85.50
111.80
59.00
1.9
23.65
91.10
114.75
62.90
1.8
3
43.80
115.30
159.10
79.50
2.0
31.75
122.50
154.25
84.50
1.8
26.05
134.50
160.55
92.80
1.7
4
129.40
303.80
433.20
209.60
2.1
89.25
327.80
417.05
226.20
1.8
70.25
367.80
438.05
253.80
1.7
a6ross revenues x .054 (depreciation/revenue ratio).
Net income after taxes + depreciation.
Depreciation x .69 (current maturity long-term debt/depreciation ratio).
dCash flow * CMLTD.
e(0.20 x control capital costs) + baseline depreciation (0.20 assumes a 5
year equipment life consistent with Section 8.4.1.2.1).
8-112
-------
This analysis represents a worst case, since impacts were estimated
for two opposite and extreme situations, full cost absorption and full
cost pass-through. The potential impacts on the three larger model
firms under the full absorption assumption are severe enough, in terms
of ROTI, that these firms would be expected to take some action to
avoid them altogether or to mitigate them. There are four possible
avenues open to them.
1. Avoid loading at bulk terminals subject to the standards.
2. Equip only a portion of the trailer fleet to load at affected
terminals.
3. Purchase new trailers equipped to load at affected terminals
only as needed to replace trailers being taken out of service.
4. Mitigate impacts on ROTI by passing through a portion of
control costs.
The first option would be a viable response to the regulatory
alternatives only where sufficient gasoline-hauling business could be
obtained from other terminals which were not affected facilities. If
widely practiced in a region, affected facilities might have to purchase
additional trailers themselves to serve their customers.
The second option has already been incorporated in the analysis
(Section 8.2.5.3). It would provide a means of reducing the total
control cost incurred by a given firm and would be possible to the
extent that there was a mixture of affected and unaffected facilities
in the firm's operating area.
The third option, which can be combined with the first or the
second, would allow a firm to postpone the full impact of control
costs and to reduce them somewhat by avoiding the additional expense
of retrofit.
The fourth option, which could also be combined with any of the
others, would be viable in areas where competition from smaller firms,
firms not dealing with affected facilities, or firms already operating
tank trucks compatible with affected terminals, did not restrict the
firm's freedom to raise prices. The price impact at the gasoline pump
would not be highly significant relative to increases resulting from
crude oil price rises.
8-113
-------
The most likely response of one of the larger firms would be a
combination of all of the options. Consequently, the regulatory
alternatives can be expected to cause a modest (less than 0.05 percent)
increase in retail gasoline prices and to bring about some changes in
tank truck firm service areas and in the arrangements made by affected
facilities to get their gasoline to the consumer. None of these
impacts is expected to be serious. Additionally, no firm closures are
expected under any regulatory alternative except those occurring from
natural attrition.
8.5 POTENTIAL SOCIOECONOMIC AND INFLATIONARY IMPACTS
The purpose of Section 8.5 is to address the tests of macroeconomic
impact contained in Executive Order 12044 and, more generally, to
assess any other.significant macroeconomic and social impacts that may
result from the regulatory alternatives.
The economic impact assessment is concerned only with the costs
or negative impacts of the alternatives. The regulation would also
result in benefits or positive impacts such as cleaner air and possible
improved health for the population, potential increases in worker
productivity, and increased business for the pollution control equipment
manufacturing industry. However, these potential benefits will not be
discussed here.
Executive Order 12044 provides several criteria for a determination
of major economic impact. Those criteria are:
1. Additional annualized costs of control that, including
capital charges (interest and depreciation), will total $100
million (i) within any one of the first five years of imple-
mentation (normally in the fifth year for NSPS), or (ii) if
applicable, within any calendar year up to the date by which
the law requires attainment of the relevant pollution standard.
2. Total additional cost of production of any major industry
product or service will exceed 5 percent of the selling
price of the product.
3. Net national energy consumption will increase by the equivalent
of 25,000 barrels of oil per day (50 x 1012 Btu or 5 x 109 kWh
per year).
8-114
-------
4. Additional annual demand will increase or annual supply will
decrease by more than 3 percent for any of the following
materials by the attainment date, if applicable, or within
five years of implementation: plate steel, tubular steel,
stainless steel, scrap steel, aluminum, copper, manganese,
magnesium, zinc, ethylene, ethylene glycol, liquified petroleum
gases, ammonia, urea, plastics, synthetic rubber, or pulp.
8.5.1 Additional Control Costs
As described in Section 8.1.2.3, five new terminals are expected
to be constructed during the 1980-85 period, and approximately 50 more
will become affected through modification or reconstruction. Thirty
of the latter are likely to be located in attainment areas and 20 in
non-attainment areas. Only eight of the 20 affected terminals in
non-attainment areas are expected to require control unit replacement
or add-on equipment. The remaining 12 terminals will not incur additional
control costs. Thus, costs are presented below for 43 of the 55 new
and existing bulk terminals expected to be affected in the first
five years. Assuming, as a worst case, that each affected terminal
experiences the highest net annualized cost appropriate to it in
Section 8.2 (Tables 8-17 through 8-19 and 8-29 through 8-36), the
total additional annual cost of control in the fifth year (in mid-1979
dollars) is:
1 950,000 I/day new terminal $ 55,800
2 1,900,000 I/day new terminals 127,400
2 3,800,000 I/day new terminals 168,400
25 Top loaded existing 950,000 I/day
terminals in attainment areas 3»900,000
5 Bottom loated existing 950,000 I/day
terminals in attainment areas 281,500
8 Existing 950,000 I/day terminals
replace control units in non-
atainment areas 717,600
Total net annualized cost $ 5,250,700
8-115
-------
The above costs represent the maximum costs to terminals incurred
under any of the alternatives in the fifth year. The 950,000 liter/day
terminal was selected as representative of the existing terminals
which would be affected under the alternatives; thus, costs are calculated
for this size terminal. It can be seen from the total that the additional
annualized costs of control, even under the most costly alternatives
considered, would be well within the criterion level of $100 million.
The highest net annualized cost to the for-hire tank truck industry
would occur under Alternatives II and IV, at $0.7 million in the
fifth year of the standard.
8.5.2 Excessive Additional Production Costs
The cost pass-through analyses for both new and existing facilities
(Sections 8.4.2.2.1 and 8.4.1.3.2) show that retail gasoline price
increases of even 1 percent are not likely to result from any of the
regulatory alternatives. No major economic impact is indicated.
8.5.3 Net National Energy Consumption
Assuming the same mix of plants as in Section 8.5.1, and referring
to energy consumption and recovery rates shown for control equipment
in Table 7-3 of Chapter 7, net energy impacts are, in the worst case
(i.e., using thermal oxidation which consumes some energy and recovers
none):
Btu,/yr x 106
1 950,000 I/day new terminal 198.1
2 1,900,000 I/day new terminals 779.1
2 3,800,000 I/day new terminals 1,452.6
38 950,000 I/day existing terminals 7,526.9
Total net energy consumption 9,956.7 x 10 Btu/yr
12
This is far below the 50 x 10 Btu criterion for major impact. As
with the costs in Section 8.5.1, the 950,000 liter/day terminal was
selected as representative of existing affected terminals, and no
incremental energy impacts were attributed to 12 of the affected
terminals in non-attainment areas.
If each plant selected the control unit with the best energy
recovery capability, a large net energy savings would result:
8-116
-------
Btu/yr x 109
1 950,000 I/day terminal
2 1,900,000 I/day new terminals
2 3,800,000 I/day new terminals
38 950,000 I/day existing terminals
9
Total net energy recovery 646.7 x 10 Btu/yr
No significant energy impact is expected due to the controls on the
for-hire tank truck industry.
8.5.4 Demand for Scarce Materials
None of the regulatory alternatives would result in a perceptible
change in demand for or supply of the materials listed, since they are
not used in large amounts in controlling VOC vapor emissions from bulk
gasoline terminals. Additionally, controls on the for-hire tank truck
industry would have no significant impact on the demand for scarce
materials.
8.5.5 Other Impacts
The alternatives would not further curtail a small businessman's
opportunities to enter the gasoline terminal industry; they are already
limited by the lower returns from smaller facilities in the existing
situation. There is some concern for an existing small terminal's
ability to continue in operation if it becomes an affected facility.
Low ROIs may make closure a more attractive alternative. However, few
existing facilities will find themselves in this position. Employment
impacts are therefore negligible, as are adverse effects on regional
economies.
Foreign trade and balance of payments should not be influenced
by the proposed standards, since little gasoline is purchased from
overseas refineries.
8-117
-------
8.6 REFERENCES
1. Pacific Environmental Services, Incorporated. Inspection Manual
for Control of Volatile Organic Emissions from Gasoline Marketing
Operations. Report to U.S. Environmental Protection Agency
under Contract 68-01-4140, Task Order 50. Washington, D.C.
October 1979. p. 2-2.
2. U.S. Department of Commerce. 1972 Census of Wholesale Trade,
Petroleum Bulk Stations and Terminals. October 1975.
3. Arthur D. Little, Incorporated. The Economic Impact of Vapor
Control Regulations on the Bulk Storage Industry. Report to U.S.
Environmental Protection Agency. Research Triangle Park, N.C.
ADL Publication No. C-79911-11 (Draft). June 1979. p. 1.3.
4. Ref. 3, p. II.6.
5. Ref. 3, p. A.2.
6. Ref. 3, p. II.7.
7. Ref. 3, p. II.9.
8. Ref. 3, p. 11.12.
9. Ref. 3, p. 11.13.
10. Ref. 3, p. 11.14.
11. Ref. 3, p. 11.16.
12. Ref. 3, p. 11.17.
13. U.S. Department of Energy. Annual Report to Congress 1978.
Volume Three. Forecasts. Washington, D.C. Publication
No. DOE/EIA-0173/3. p. 325.
14. U.S. Federal Energy Administration. Energy in Focus: Basic Data
Advance Copy. 1977.
15. Gasoline Consumption by States. National Petroleum News Factbook
Issue. Mid-June 1979. Vol. 71, No. 6A. p. 82.
16. U.S. Department of Energy. Annual Report to Congress 1978.
Volume Three, Supplement One. Midterm Energy Projections for the
United States. Washington, D.C. Publication No. DOE/EIA-0173/3-S1.
July 9, 1979.
17. U.S. Federal Energy Administration. 1977 National Energy Outlook.
January 15, 1977. p. IV-20.
8-118
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18. Department of Energy, Energy Information Administration. Monthly
Petroleum Statement. Publication No. DOE/EI$-0109/8(79).
August 1979.
19. Ref. 13, p. 186.
20. Ref. 3, p. 11.10.
21. Hang, J.C. and R.R. Sakaida. Survey of Gasoline Tank Trucks and
Rail Cars. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/3-79-004. March
1979. p. 2-12.
22. U.S. Department of Commerce, Bureau of the Census, Census of
Transportation, 1977, Truck Inventory and Use Survey. Washington,
D.C. 1979.
23. Materials Transportation Bureau, U.S. Department of Transportation.
General Design and Construction Requirements Applicable to Specifi-
cations MC 306, MC 307, and MC 312 Cargo Tanks. Order 73, 32 FR 3459,
March 2, 1967. Code of Federal Regulations (CFR), Title 49, Part 178.
Washington, D.C. Office of the Federal Register. 1976.
24. Ref. 21, p. 2-1.
25. U.S. Department of Commerce, Social and Economic Statistics
Administration, Bureau of the Census. 1972 Census of Transportation,
Truck Inventory and Use Survey. Washington, D.C. October 1973.
26. Ref. 21, p. 2-18.
27. Economic Indicators: CE plant cost index. Chemical Engineering.
Vol. 86, No. 20. September 24, 1979.
28. Telecon. Schmidt, Ed, HydroTech Engineering, Incorporated with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
July 3, 1979. CA unit equipment and operating costs.
29. Telecon. Sasseen, Ken, Trico-Superior, Incorporated with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
July 17, 1979. CRA unit equipment costs and operating
information.
30. Telecon. Edwards, Ray, Edwards Engineering Corporation with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
July 2, 1979. Refrigeration unit equipment costs and operating
information.
31. Telecon. Gardner, Frank, Tenney Engineering, Incorporated with
LaFlam, Greg, Pacific Environmental Services, Incorporated.
July 2, 1979. Refrigeration unit equipment costs and operating
information.
8-119
-------
32. Telecon. LaFlam, Greg, Pacific Environmental -Services, Incorporated
with Guischard, Chuck, AER Corporation. July 2, 1979. TO unit
equipment costs and operating information.
33. Telecon. Kirkland, John, Hirt Combustion Engineers with LaFlam,
Greg, Pacific Environmental Services, Incorporated. July 9,
1979. TO unit equipment costs and operating information.
34. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Bitterlich, Gordon, National AirOil Burner Company, Incorporated,
October 18, 1979. TO unit equipment costs and operating information.
35. Ref. 21, p. 4-4.
36. Truck Trailer Manufacturer Association. TTMA Vapor Recovery Study.
May 1979. p. 4.
37. Telecon. Sasseen, Ken, Trico-Superior, Incorporated with LaFlam,
Greg, Pacific Environmental Services, Incorporated. August 1,
1979. CRA unit electrical usage and company marketing plans.
38. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Guischard, Chuck, AER Corporation. July 11, 1979. TO unit
utilities usage.
39. Edwards Engineering Corporation. Air Pollution Control Manual
for Hydrocarbons and Condensible Gases, Vapor Recovery Equipment.
Pompton Plains, N.J. Undated.
40. Edwards Engineering Corporation. A Comparison of Gasoline Vapor
Recovery Systems: Refrigeration Condensation vs. Charcoal
Adsorption (Review is based on April 1979 TRC Report to EPA,
Contract No. 68-01-4145). Pompton Plains, N.J. Undated.
41. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Schmidt, Ed, HydroTech Engineering, Incorporated. November 7,
1979. Activated carbon replacement costs for CA units.
42. Memorandum from Norton, R. and G. LaFlam, Pacific Environmental
Services, Incorporated to Durham, J. and Shedd, S., Environmental
Protection Agency. May 1, 1979. Report on April 23, 1979, visit
to ARCO terminal, Revere, Massachusetts.
43. Norton, Robert L. Evaluation of Vapor Leaks and Development of
Monitoring Procedures for Gasoline Tank Trucks and Vapor Piping.
U.S. Environmental Protection Agency. Research Triangle Park,
N.C. Publication No. EPA-450/3-79-018. April 1979. 94 p.
44. Transportation and Marketing of Petroleum Liquids. In: Compila-
tion of Air Pollutant Emission Factors. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. July 1979.
p. 4.4-9.
8-120
-------
45. Marketplace at a Glance: Average Gasoline Prices in the U.S.
(June). National Petroleum News. Vol. 71, No. 8: p. 12. August
1979.
46. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Guischard, Chuck, AER Corporation. October 8, 1979. TO
units used as secondary control systems.
47. Telecon. LaFlam, Greg, Pacific Environmental Services, Incorporated
with Maxwell, Steve, HydroTech Engineering, Incorporated. October 18,
1979. CA units used as secondary control systems.
48. Ref. 21, p. 4-5.
49. U.S. Environmental Protection Agency. Code of Federal Regulations.
Title 40, Part 60, Subpart A, Section 60.8.
50. United States Congress. Clean Air Act, as amended August 1977.
42 U.S.C. 1414. Washington, D.C. U.S. Government Printing
Office. November 1977.
51. Memorandum from Kelly, Winton, Emission Measurement Branch, U.S.
Environmental Protection Agency, to Files. February 7, 1980.
Compliance Testing and Monitoring Cost Basis for Gasoline Terminals.
52. Letter and enclosure from LaFlam, G.A., Pacific Environmental
Services, Incorporated, to Rosenbaum, A.B., National Tank Truck
Carriers, Incorporated. December 18, 1979. Request for information
on independent tank truck companies.
53. Letter and attachment from Rosenbaum, A.B., National Tank Truck
Carriers, Incorporated, to LaFlam, G.A., Pacific Environmental
Services, Incorporated. January 29, 1980. Response to request
for information on independent tank truck companies.
54. Memorandum from Norton, B. and LaFlam, G., Pacific Environmental
Services, Incorporated, (PES), to Shedd, S., EPA. August 22,
1980. Report on July 30, 1980, visit to ARCO terminal in South Gate,
California.
55. Energy and Environmental Analysis, Incorporated. Financial and
Economic Impacts of Proposed Standards of Performance for New
Sources — Storage Vessels for Petroleum Agency (sic). November 1977.
p. 4.
56. Ref. 15, p. 52-60, 206-209.
57. Ref. 15, p. 52-60.
58. Meeting. Bode, William, Independent Terminal Operators Association,
with Bacon, Abigail, JACA Corp. November 20, 1979. Financial
information on industry.
8-121
-------
59. Ref. 15, p. 22-23.
60. Robert Morris Associates. Annual Statement Studies. 1979.
p. 215.
61. Ref. 3, p. VI. 18.
62. Letter from Prokop, John, President, Independent Liquid Terminals
Association, to Bacon, Abigail, JACA Corp. December 13, 1979.
63. Ref. 3, p. 11.15.
64. Ref. 3, p. VI.9.
65. Telecon. Storb, John, Storb, Inc. with Baist, Harry, JACA Corp.
January 22, 1980. Capital investment for model plants.
66. Telecon. Boshen, Mr., Richmond Engineering Co., with Baist,
Harry, JACA Corp. November 15, 1979. Capital investment for
model plants.
67. Telecon. Werremeyer, Mr., Chicago Bridge and Iron Co., with
Baist, Harry, JACA Corp. November 14, 1979. Capital investment
for model plants.
68. Telecon. Best, Doug, General American Transportation Corp. - Tank
Erection Division, with Baist, Harry, JACA Corp. November 14,
1979. Capital investment for model plants.
69. Telecon. lacona, Frank, Fisher tank Co., with Baist, Harry, JACA
Corp. November 15, 1979. Capital investment for model plants.
70. Telecon and Meeting. Storb, John, Storb, Inc., with Baist, Harry,
JACA Corp. November 21 and November 28, 1979, respectively.
Capital investment for model plants.
71. Meeting. Savage, Brian, Equipment Specialists, Inc., with Baist,
Harry, JACA Corp. November 19, 1979. Capital investment for
model plants.
72. Telecon. Clements, John, Gannon Technical Products, with Baist,
Harry, JACA Corp. November 28, 1979. Capital investment for
model plants.
73. Telecon. Stretch, Louis, Cal1is-Thompson Co., with Baist, Harry,
JACA Corp. December 3, 1979. Capital investment for model plants.
74. Telecon. Lawler, James, Tank Truck Manufacturing, Inc., with
Baist, Harry, JACA Corp. November 14, 1979. Capital investment
for model plants.
8-122
-------
75. Telecon. Scott, Anderson, Newberry Tanks, with Baist, Harry,
JACA Corp. November 14, 1979. Capital investment for model
plants.
76. Telecon. Stretch, Louis, Callis-Thompson, Inc., with Baist,
Harry, JACA Corp. November 15, 1979. Capital investment for
model plants.
77. Hulslander, Richard E. A Better Debt Coverage Ratio. The Journal
of Commercial Bank Lending. August 1979. p. 55.
78. Ref. 3, p. C.2-C.14.
79. Chemical Engineering, 86(28):7. December 31, 1979.
80. Costs determined by analysis of new plant costs, 114 letter
responses, and telecon. Welpe, William, Hunn Corp., with Baist,
Harry, JACA Corp. December 28, 1979.
81. American Trucking Associations, Incorporated. 1978 Motor Carrier
Annual Report—Financial and Operating Statistics. Washington,
D.C. 1979. 812 p.
82. Kohler, 6. Barry, Bank of America. 1978 Financial Analysis of
the Motor Carrier Industry. Washington, D.C. 1978.
83. National Tank Truck Carriers, Incorporated. A Financial Analysis
of the For-Hire Tank Truck Industry, 1978 and First Half of 1979.
Washington, D.C. 1979.
84. Telecon. Harrison, Cliff, National Tank Truck Carriers Association,
with Deardorff, Kevan, JACA Corporation. November 18, 1980.
Transportation rates for gasoline.
85. Telecon. Rosenbaum, A., National Tank Truck Carriers Association,
with Bacon, A., JACA Corporation. August 21, 1980. Performance
indicators for tank truck firms.
8-123
-------
APPENDIX A
EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
A-l
-------
APPENDIX. A - EVOLUTION OF THE BACKGROUND INFORMATION DOCUMENT
In early 1978, the Argonne National Laboratory prepared a list of
156 major source categories and ranked them in order of priority for
NSPS development. The method used to rank the source categories was
based on emissions, public health/welfare, and source mobility, which
were criteria set forth by the Congress in the 1977 Clean Air Act
Amendments. The Petroleum Transportation and Marketing category was
ranked twenty-third in priority on a list of 59 source categories
selected by EPA.
The standards development began when a series of EPA-sponsored
emission tests was initiated in 1973. These efforts were initially
directed toward the regulation of VOC emissions from bulk terminals. A
Control Techniques Guideline for VOC control at terminals was published
in October 1977. A study of benzene emissions from the gasoline
marketing industry was then initiated with the intention of developing
a national hazardous pollutant standard. The information was presented
before the National Air Pollution Control Techniques Advisory Committee
(NAPCTAC), and the issue is currently under review with no set schedule
for completion. NSPS development for the bulk terminal subcategory
was started in November 1978.
Information was gathered through visits to bulk terminals,
Section 114 letters to oil companies, and telephone contacts to industry
representatives, consultants, and equipment manufacturers. In addition,
a literature survey, including examination of test results, was conducted,
The major events relating to this effort are in the chronology below.
A.I CHRONOLOGY
The chronology to follow lists the significant events which have
occurred in the development of the background information document
supporting a New Source Performance Standard for Bulk Gasoline Terminals.
Appendix C contains summaries of the numbered emission tests shown in
the chronology.
A-2
-------
Date
11/18/73 to 5/2/74
12/11-12/74
12/17-19/74
9/20-22/76
9/23-25/76
11/1/76 to 6/1/77
11/10-12/76
4/14/77
5/25-27/77
6/8/77
7/7/77
7/27-29/77
10/77
1/10-12/78
1/25-27/78
2/1,2/78 and 3/6,7/78
2/20,21/78 and 3/8,9/78
2/23,24,27/78,
Activity
Terminal Emission Test No. 4
Terminal Emission Test No. 14
Terminal Emission Test No. 8
Terminal Emission Test No. 9
Terminal Emission Test No. 15
Section 114 letters sent to oil
companies regarding specific terminals
Terminal Emission Test No. 10
Meeting with Texaco in Durham,
North Carolina
Terminal Emission Test No. 1
EPA listing of benzene as a hazardous
pollutant under Section 112 of the
Clean Air Act
Meeting with API, Union, Amoco,
Texaco, Citgo, and Arco in Durham,
North Carolina
Tank truck emission testing in
Aurora, Colorado
Terminal Control Techniques
Guideline issued (Control of Hydro-
carbons from Tank Truck Gasoline
Loading Terminals. EPA Publication
No. EPA-450/2-77-026)
Terminal Emission Test No. 6
Terminal Emission Test No. 5
Terminal Emission Test No. 20
Terminal Emission Test No. 16
Terminal Emission Test No. 7
A-3
-------
Date
3/1-3/78
4/11-13/78
5/2-4/78
6/12-17/78
6/19-23/78
6/19-23/78
7/78
8/2-4/78
8/16-18/78
8/22/78
8/22-24/78
8/31/78
9/12/78
9/19-21/78
9/26-28/78
9/27/78
10/6/78
10/10-12/78
10/13/78
Activity
Terminal Emission Test No. 2
Terminal Emission Test No. 22
Terminal Emission Test No. 17
Tank truck testing at Chevron
terminal in Los Angeles, California
Observed top loading systems at four
terminals in Los Angeles, California
Tank truck testing at Shell terminal
in Los Angeles, California
Mail out draft Standard Support
Environmental Impact Statement
for Control of Benzene from the
Gasoline Marketing Industry,
preamble, and regulation to
industry and environmental groups
Terminal Emission Test No. 18
Terminal Emission Test No. 21
NAPCTAC meeting to review draft
standard package mailed out on
7/78
Terminal Emission Test No. 11
Proposal of source category priority
list in Federal Register
Meeting with HydroTech Engineering,
Inc. in Tulsa, Oklahoma
Terminal Emission Test No. 19
Terminal Emission Test No. 12
Meeting with Fruehauf Corp. in
Omaha, Nebraska
Meeting with HydroTech Engineering,
Inc. in Durham, North Carolina
Terminal Emission Test No. 13
Meeting with Edwards Engineering
Corp. in Durham, North Carolina
A-4
-------
12/78
4/23-27/79
5/31/79
6/18/79
6/26/79
8/21/79
10/26/79
5/5/80
6/5/80
Activity
Terminal Emission Test No. 3
Start of NSPS development for
bulk gasoline terminals
Tank Truck Control Techniques
Guideline issued (Control of
Volatile Organic Compound Leaks
from Gasoline Tank Trucks and
Vapor Collection Systems. EPA
Publication No. EPA-450/2-78-051)
Plant visits to six bulk terminals
Section 114 Letter Questionnaire
sent to oil companies and specific
terminals
Attended meeting with oil companies,
consultants, and equipment manu-
facturers in El Segundo, California
Presentation on VOC controls for the
gasoline marketing industry by
Jim Durham, EPA, before a meeting of
the National Tank Truck Carriers in
Boston, Massachusetts
Final rule on source category
priority list in Federal Register,
Vol. 44, No. 163
Mai lout of draft NSPS Background
Information Document (Chapters
3-6, Appendix C) for comments
from industry and environmental
groups
Mai lout of draft BID, Preamble,
and Regulation to industry, environ-
mental groups, and members of the
National Air Pollution Control
Techniques Advisory Committee
(NAPCTAC)
NAPCTAC meeting in Raleigh, North
Carolina, to review the draft NSPS
standard for bulk gasoline terminals
A-5
-------
Date
6/5/80
7/22/80
7/28/80 to 8/1/80
8/4-5/80
Activity
Meeting with SOHIO in Durham,
North Carolina
Meeting with Emco Wheaton, Inc.,
in Durham, North Carolina
Plant visits to ten bulk terminals
(continuous monitoring testing
site survey)
Meeting with SOHIO in Cleveland,
Ohio
A-6
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
B-l
-------
APPENDIX B - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
This appendix consists of a reference system which is cross-
indexed with the October 21, 1974, Federal Register (39 FR 37419)
containing the Agency guidelines for the preparation of Environmental
Impact Statements. This index can be used to identify sections of
the document which contain data and information germane to any portion
of the Federal Register guidelines.
B-2
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background
Information Document (BID)
1. Background and Description
of Regulatory Action
Summary of the regulatory
alternatives
Statutory basis for
proposing standards
Facility affected
Process affected
Availability of control
technology
Existing regulations
at State or local
level
2. Environmental Impact of
Regulatory Alternatives
Air Pollution
Water Pollution
The regulatory alternatives are
summarized in Chapter 1, Section 1.1.
The statutory basis for proposing
standards is given in Chapter 2.
A description of the facilities to
be affected is given
in Chapter 6, Section 6.2.2.
A description of the processes to be
affected are given in Chapter 3,
Section 3.2.
Information on the availability
of control technology is given
in Chapter 4.
A discussion of existing regulations
on the industry to be affected by
the regulatory action is included
in Chapter 3, Section 3.3.
The air pollution impacts of the
regulatory alternatives are discussed
in Chapter 7, Section 7.1.
The impacts of the regulatory
alternatives on water pollution
are discussed in Chapter 7,
Section 7.2.
(Continued)
B-3
-------
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS (Concluded)
Agency Guidelines for Preparing
Regulatory Action Environmental
Impact Statements (39 FR 37419)
Location Within the Background
Information Document (BID)
Solid waste disposal
Energy consumption
3.
Economic Impact of
Regulatory Alternatives
Costs
Economic analysis
The impacts of the regulatory
alternatives on solid waste
disposal are discussed in
Chapter 7, Section 7.3.
The impacts of the regulatory
alternatives on energy consump-
tion are discussed in Chapter 7,
Section 7.4.
The cost impacts of the regulatory
alternatives are discussed in
Chapter 8, Section 8.2.
Economic analyses of the
regulatory alternatives are
contained in Chapter 8,
Sections 8.4 and 8.5.
B-4
-------
APPENDIX C
EMISSION SOURCE TEST DATA
C-l
-------
APPENDIX C - EMISSION SOURCE TEST DATA
C.I SUMMARY OF TEST ACTIVITY
C.I.I General
The primary means of determining the field performance of various
types of vapor processing units is through an examination of test data
from actual emission tests at bulk terminals. In order to normalize
the test results to account for varying loading volumes, all calculated
parameters are weighted in proportion to the gasoline volumes loaded.
In addition, actual VOC emission levels from the processors as measured
in these tests are adjusted to account for the calculated leakage
rates from tank trucks. Section C.2 explains the data further.
C.I.2 EPA-Conducted Tests
EPA conducted 22 emission tests for VOC emissions at bulk gasoline
terminals throughout the United States between 1973 and 1978. Tests
were performed on the six types of vapor processors whose principles
of operation were described in Chapter 4. These tests followed, with
occasional minor exceptions, the procedure developed by EPA-OAQPS as
described by the CTG for terminals. Section C.3 contains summaries
of each of the tests. Test results are presented in Table C-l.
C.I.3 Other Vapor Processor Tests
The San Francisco Bay Area Air Quality Management District performed
VOC emission tests on 26 vapor recovery installations in California
between 1976 and 1979. Twenty-five of the units tested were compression-
absorption type units, and one was a refrigeration (REF) type unit.
The compression-absorption unit is similar to the CRA unit, except
that the refrigeration section is not included. These units were
produced primarily for use in California and are no longer being
marketed. Details concerning the test procedure and conditions were
not available to the authors of this report.
C-2
-------
Table C-l. WEIGHTED DAILY AVERAGES3 OF CALCULATED EMISSION TEST PARAMETERS
Type
Test Test of .
Number Date Unit
5/25/77
1 5/26/77 CA
5/27/77
3/1/78 ,
2 3/2/78 CAa
3/3/78
10/24/78
3 10/25/78 CA
o 10/26/78
U) f •' j
4 11/73 T0a
1/25/78
, 1/26/78 Tn
b 1/27/78 1U
1/30/78
1/10/78
6 1/11/78 TO
1/12/78
2/23/78 ,
7 2/24/78 T0a
2/27/78
12/17/74
8 12/19/74 Kth
(V/L)r
0.693
0.641
0.685
0.645
0.753
0.643
1.05
1.06
1.03
0.741
0.725
0.775
0.839
0.846
0.866
0.799
0.778
0.804
0.807
0.781
0.758
0.749
(V/L)p
1$
KOC
£
i!oc
1.07
1.07
0.957
1.0C
1$
1$
1.0C
1.0C
0.963
1.0*
i$
i!oc
1.0C
1.03
F
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
factor
.44
.56
.46
.55
.33
.56
.02
'.0^
.35
.38
.29
.19
.18
.15
.21
.28
.24
.24
.28
.32
.38
(M/L)r
(mg/liter)
703
666
613
240
219
225
790
806
853
500.0
577.3
579.0
370.4
405.9
383.0
330.1
411.2
290.0
426.0
439.0
313.6
354.0
(M/L)e (M/L)t
Cr (mg/liter) C£ (mg/liter)
56.2
60.4
48.8
20.5
13.5
15.4
45.0
40.1
43.8
29. 29
36.9
39.6
23.1
24.1
33.9
27.8
31.1
18.6
27.3
28.3
17.0
18.8
64.2
5.4
2.7
1.2
2.1
2.5
10.8
9.6
63.4
1.0
77.6
36.7
32.8
24.2
21.4
22.4
39.8
23.7
7.5
10.3
33.3
39.4
6.0
2.2
0.14
0.18
0.30
0.33
0.83
0.83
3.7
0.0029
0.06
0.03
0.02
0.02
0.004
0.005
0.008
1.7
0.7
0.8
3.4
3.6
374
378
285
133
74.4
129
26.6
17.7
63.4
176.0
296.9
204.6
103.1
97.3
78.9
91.7
154.9
93.3
109.7
133.2
133.7
173.9
(M/L)e*
(mg/liter)
92.6
8.5
3.9
1.8
2.8
3.9
11.0
9.7
63.4
1.4
107.1
47.3
39.0
28.6
24.7
27.0
50.9
29.4
9.3
13.2
44.0
54.4
Ep(«)
90.9
99.2
99.6
99.5
99.0
98.9
98.6
98.8
92.6
99.8
86.6
93.7
91.1
94.0
93.6
93.2
90.3
90.0
98.2
97.7
89.4
88.9
-------
Table C-1. WEIGHTED DAILY AVERAGES3 OF CALCULATED EMISSION TEST PARAMETERS (Continued)
o
I
Type
Test Test of b
Number Date Unit
9
10
11
12
13
14
15
«
9/20/76
9/21/76 REF
9/22/76
11/10/76
11/11/76 REF
11/12/76
8/22/78
8/23/78 REF
8/24/78
9/26/78
9/27/78 REF
9/28/78
10/10/78
10/11/78 REF
10/12/78
12/11/74 .
12/12/74 CRAa
9/23/77 ,
9/24/77 CRAa
9/25/77
2/20/78
2/21/78 CRAd
3/8/78 LKA
3/9/78
(V/L)r
0.751
0.904
0.809
0.825
0.987
0.900
1.55
1.62
1.62
0.808
0.963
0.964
0.565
0.591
0.629
0.422
0.469
0.731
0.681
0.734
0.683
0.696
NAh
NAh
(V/L)p
1.05
1.0C
0.843
1.04
1.02
1.03
1.39
1.63
1.62
0.915
0.953
1.06
!.<£
i!oc
1.0
0.847
1.06
1.05
0.950
1.0=
i!oc
F factor
1.40
1.11
1.04
1.26
1.03
1.14
1.0e
1.00
1.00
1.13
1.00
1.10
1.77
1.69
1.59
2.37
1.81
1.45
1.54
1.29
1.46
1.44
NAh
NAh
(M/L)r
(mg/liter)
505.2
494.0
554.5
369.0
340.8
237.0
2367
-2290
2101
573.0
735.5
723.7
558.9
728.9
602.3
80.3
135.5
628.6
339.6
NA*
375
372
NAh
NAh
Cr
35.6
50.6
50.9
23.7
17.8
13.3
NAh
82.2
75.2
31.7
30.0
39.8
47.9
52.4
51.8
18.2
21.5
4a.8
38R9
NAh
29.3
31.2
28.7
27.1
(M/L)e
(mg/liter)
51.6
52.3
29.9
49.1
57.1
54.2
1318
840.8
794.2
67.2
102.6
61.9 '
i
i
i
31.0
31.6
30.7
30R5
NAh
NA
61.2
59.5
57.2
Ce
4.8
4.7
3.6
3.6
3.3
3.3
56.8
29.8
38.4
5.3
6.2
4.9
3.2
3.1
3.5
4.7
4.3
3.9
3.4
3.2
5.3
6.1
5.3
5.3
(M/L)t
(mg/liter)
253.7
106.6
52.1
172.5
67.3
87.4
1318
840.8
794.2
141.7
102.6
134.3
i
i
141.0 "
141.4
313.6
213,9
NAh
NA
224.9
NAh
NAh
(M/L)e*
(mg/liter)
72.2
58.1
31.1
61.9
58.8
61.8
1318
840.8
794.2
75.9
102.6
68.1
i
i
i
73.5
57.2
44.5
47,0
NAh
NA
88.1
NAh
NAh
E~ (*)
P
89.8
-89.4
94.6
85.7
83.2
77.1
44.3
63.3
62.2
88.3
86.1
90.6
i
i
i
61.4
76.7
95.1
91.0
NAh
NA
83.5
NAh
NAh
-------
Table C-l. WEIGHTED DAILY AVERAGES3 OF CALCULATED EMISSION TEST PARAMETERS (Concluded)
Test Test
Type
of u
Number Date Unit (V/L),
(V/L)n F factor
(M/L)r
(mg/liter)
(M/L)e
(mg/liter)
(M/L)t
(mg/liter)
(M/L)e*
(mg/liter)
o
01
En(*)
17
18
19
20
21
22
5/2/78.
5/3/78
5/4/78
8/2/78
8/3/78
8/4/78
9/21/78
3/6/78
3/7/78
8/16/78
8/17/78
8/18/78
4/11/78
4/12/78
4/13/78
CRAd
CRAd
CRAd
CRCd
CRCd
LOA
0.521
0.775
0.691
0.724
0.887
0.904
0.992
0.850
0.794
0.842
0.924
0.904
0.748
0.725
0.728
K
1.0°
1.0C
0.936
1.34
1.11
1.05
^"c
1.0C
1.0C
0.987
1.07
]-0c
1.0^
1.0C
1.92
1.29
1.45
1.29
1.51
1.23
1.06
1.18
1.26
1.19
1.07
1.18
1.34
1.38
1.37
232.5
462.4
227.2
509.9
642.0
821.7
1047.0
372.5
523.1
1054
1281
1136
375.1
375.1
372.5
17.0
30.6
23.2
35.5
37.6
45.0
56.6
22.1
38.4
64.8
75.6
59.7
29.3
29.0
28.3
40.9
45.1
35.9
32.2
43.1
43.0
85.9
41.0
44.4
i
i
i
97.0
52.9
86.7
2.5
2.5
2.5
3.6
3.8
4.1
3.6
3.4
3.8
11.9
12.9
13.6
9.2
5.3
9.2
254.8
179.2
138.1
180.1
370.5
232.0
149.3
108.1
180.4
1
i
i
224.5
195.4
224.5
78.5
58.2
52.1
41.5
65.1
52.9
91.0
48.4
55.9
i
i
i
130.0
73.0
118.8
82.4
90.2
84.2
93.7
93.3
94.8
91.8
89.0
91.5
i
i
74.1
85.9
76.7
-------
NOTES — TABLE C-l
Parameters are weighted in proportion to the amount of gasoline loaded during each run,
bCA - Carbon Adsorption
TO - Thermal Oxidation
REF - Refrigeration
CRA - Compression-Refrigeration-Absorption
CRC - Compression-Refrigeration-Condensation
LOA - Lean Oil Absorption
cValue assumed to be 1.0 when no truck leakage measurements available.
Vapor holder used.
eAssumed value since calculated F factor is less than unity.
'Testing performed for nearly six months; no daily averages reported (see Section C.2).
Volume percent as methane.
"Parameter not calculated due to lack of measured test data.
calculated due to unknown quantity of leakage from vapor collection system.
DEFINITIONS
!• (V/L)r = Volume of air-VOC mixture returned per volume of liquid dispensed.
2. (V/L) = Potential vapor/liquid volume ratio, assuming no leakage losses.
3. F factor = (V/L) * (V7L~)r, an adjustment factor to account for leakage.
4' (M/L)r = VOC mass returned per volume of liquid dispensed (uncontrolled emissions)
5. C,. = Volume percent of VOC in returned mixture (volume percent as propane).
i
6. (M/L) = VOC mass exhausted from the processor per volume of liquid dispensed
(controlled emissions).
7. Ce = Volume percent of VOC in exhausted mixture (volume percent as propane).
8. (M/L)t = Total system VOC mass emissions, including leakage from tank trucks.
9. (M7T)e* = F x (M/L)e, adjusted mass emissions.
10. E_ = Processing unit VOC control efficiency.
-------
An adjustment factor of 1.10 to account for tank truck leakage
was assumed for all tests. Tank truck leak-tight regulations were in
effect during these tests. The factor was developed from over 100
2
tank truck loadings in an area having similar regulations.
The average processor VOC emission level for all 25 tests involving
compression-absorption units was 75.5 milligrams per liter (0.286 gram
per gallon) of gasoline loaded. Adjusted emissions averaged 83.1
milligrams per liter (mg/1), or 0.315 gram per gallon (gm/gal). If
the three highest processor emission values (which averaged 205 mg/1
or 0.776 gm/gal) are deleted from the calculations, average emissions
were 57.9 mg/1 (0.219 gm/gal), with adjusted emissions of 63.7 mg/1
(0.241 gm/gal). Processor emissions from the REF unit were 13.0 mg/1
(0.049 gm/gal), with adjusted emissions of 14.3 mg/1 (0.054 gm/gal).
Data from these tests are summarized in Table C-2.
The results of four tests on vapor processing systems were received
from the California Air Resources Board. ' * * Three of these tests were
performed on refrigeration units, and one was performed on a carbon
adsorption unit. The VOC emission rates for the refrigeration tests were
5 mg/liter, 36 mg/liter, and 48 mg/liter, for an average emission rate
of 30 mg/liter. The results from the carbon adsorption tests did not
give an exact value for the VOC emissions, but only reported that the
emission rate was less than 12 mg/liter.
C.I.4 Tank Truck Leakage Tests
EPA conducted vapor leak tests on 27 truck tanks in California
2 7
during the month of June 1978. ' These tank trucks were under a
requirement of the California Air Resources Board (CARB) to undergo an
annual leak tightness test. Both top and bottom loading terminals
were selected for inclusion in the test program. Trucks were selected
to provide a representative cross-section of tank age and type of
vapor-containing equipment. Tests were conducted on the truck tanks
before any maintenance was performed. This was done to establish the
truck leakage rate since the last certification. Testing included a
volume leakage test followed by a specified CARB pressure and vacuum
test.
C-7
-------
Table C-2. RESULTS OF VAPOR RECOVERY SYSTEM TESTS
PERFORMED BY SAN FRANCISCO BAY AREA AIR
QUALITY MANAGEMENT DISTRICT
Test
A
B
C
D
E
F
G
H
I
J
K
L
M
Test Date
06/23/76
03/24/77
03/31/77
04/19/77
05/19/77
08/03/77
10/12/77
10/21/77
11/09/77
11/16/77
12/06/77
01/26/78
02/23/78
Control
Unit
COMb
COM
COM
COM
REFC
COM
COM
COM
COM
COM
COM
COM
COM
Vol ume of
Gasoline
Loaded
(10J Liters)
1,830
1,190
460
470
1,040
270
210
470
1,670
310
250
540
1,040
VOC
Emissions
From
Processor
(mg/liter)
86
56
37
332
13
43
46
107
56
46
175
59
56
Adjusted
Processor
Emissions
(mg/liter)
95
62
41
365
14
47
51
118
62
51
193
65
62
Control
Unit
Efficiency
(Percent)
89.2
90.7
90.9
59.4
98.1
95.3
92.1
84.5
93.1
93.7
81.1
'. 92.7
93.8
aAdjusted for tank truck leakage. Adjustment factor of 1.1 used based upon
tank truck testing in an area with similar vapor-tight regulations,
bCOM = Compression-Absorption.
CREF = Refrigeration.
C-8
-------
Table C-2. RESULTS OF VAPOR RECOVERY SYSTEM TESTS
PERFORMED BY SAN FRANCISCO BAY AREA AIR
QUALITY MANAGEMENT DISTRICT
(Concluded)
Test
N
0
P
Q
R
S
T
U
V
w
X
Y
Z
Test Date
03/01/78
04/26.78
05/02/78
06/09/78
06/14/78
06/15/78
06/27/78
07/20/78
09/08/78
09/20/78
10/07/78
12/28/78
04/18/79
Control
Unit
COM
COM
COM
COM
COM
COM
COM
COM
COM
COM
COM
COM
COM
Volume of
Gasoline
Loaded
(10J Liters)
780
560
970
470
990
2,860
700
1,050
790
950
200
200
1,780
VOC
Emissions
From
Processor
(mg/liter)
60
59
71
38
78
75
58
77
46
64
59
47
56
Adjusted3
Processor
Emissions
(mg/liter)
66
65
78
42
86
83
64
85
51
70
65
52
62
Control
Unit
Efficiency
(Percent)
93.8
92.3
89.0
95.9
91.7
90.5
93.5
90.5
94.5
91.7
92.9
93.5
— d
Adjusted for tank truck leakage. Adjustment factor of 1.1 used based upon
tank truck testing in an area with similar vapor-tight regulations.
TOM = Compression-Absorption.
CREF = Refrigeration.
No data.
C-9
-------
Both of these tests are similar in that both tests quantitatively
measured gas volume loss from tanks due to leakage.
Four of the tanks tested had maintained the ability to pass the
leak tests. The time since the last certification date on the tanks
ranged from four months to four days. Of the tanks that failed, the
time frame ranged from one year to two weeks (see Table C-3). Leaks
occurred primarily at dome lids, base rings, and P-V vents. The
leakage rates for the trucks tested varied considerably. High leakage
rates were found within 20 days of certification in several cases,
while one case indicated a relatively low leakage rate at the end of
one year. Table C-4 summarizes the results of the tank testing. This
table includes data for those tanks tested before maintenance was
performed. Several of the 27 trucks included in the study did not
have a test performed prior to maintenance because of time constraints.
The average leakage rate for those tanks included in Table C-4 was
approximately 10 percent, meaning that approximately 10 percent of the
air-vapor mixture exhausted from a regulated gasoline tank truck
during product loading would leak to the atmosphere without reaching
the vapor processor.
The bulk terminal tests described in Section C.I.2 were performed
in areas where no tank truck leak tightness regulations were in effect.
The average leakage from tanks in these tests was determined to be
30 percent.
C.2 TEST RESULTS AND CALCULATIONS
C.2.1 Factors Affecting Test Results
There are many factors which can contribute to the variability of
results among tests on a particular type of vapor processing system.
The efficiency of most processors depends to some degree on the
VOC concentration in the incoming air-vapor mixture; generally, a
higher inlet concentration leads to a higher collection efficiency.
This trend is difficult to discern in the data summary because of the
other factors involved; for example, in some cases the unit was not
operating properly so that the efficiency was lower than expected.
The runs in which a tank truck was vapor-balanced (Stage I service
C-10
-------
Table C-3. TANK TIGHTNESS HISTORY
Tank
Identification
Number
63806
53306
63767
53256
63766
53345
63765
63765 d
53304
63804
53307
63803
53297
63805
53305
67-282
67-392
67-475
68-795
68-795b
68-597
68-597b
68-275
68-275b
68-977
68-977b
67-775
Last
Certification
Date3
2/24/78
2/24/78
2/09/78
2/09/78
2/08/78
2/08/78
2/07/78
6/19/78
2/07/78
2/16/78
2/16/78
2/10/78
2/10/78
2/28/78
2/28/78
5/18/78
5/23/78
5/24/78
5/03/78
5/03/78
6/13/77
6/13/77
6/28/77
6/28/77
5/03/78
5/03/78
No data
Field
Test Date
6/23/78
6/23/78
6/20/78
6/20/78
6/20/78
6/20/78
6/19/78
6/23/78
6/23/78
6/21/78
6/22/78
6/21/78
6/21/78
6/22/78
6/22/78
6/14/78
6/13/78
6/15/78
6/14/78
6/14/78
6/13/78
6/13/78
6/15/78
6/15/78
6/16/78
6/16/78
6/12/78
Pass/6
Fail
F
F
F
P
Fc
Fc
F
P
P
F
F
F
F
F
Fc
F
F
P
F
F
F
F
FC
F0
Fc
Fc
F
Type of
Loading
Top
Top
Top
Top
Top
Top
Top
Top
Top
Top
Top
Top
Top
Top
Top
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
Bottom
aPassed CARB Certification Test.
trailer of Truck/Trailer Unit.
^anks not maintained to pass conditions after field tests, all
other tanks maintained to pass conditions.
Tested twice during the field tests.
ePassed or failed field pressure/vacuum test.
C-ll
-------
Table C-4. RESULTS OF EPA-SPONSORED
TANK TRUCK LEAKAGE TESTS3
Tank Truck Vapor. Leakage
Days Since Certification Test (Percent)
4 0.1
4 0.6
6C 2.0
6C • 2.5
7 2.0
20 16.4
21 0.4
26 22.8
34C 1.9
43 2.2
43 13.6
125 10.0
131 1.0
131 2.4
132 22.4
136 16.0
300 35.8
360 3.6
360 12.4
360 26.8
aThe number of days since the tank last passed a pressure/vacuum
test.
Percent of vapors which would be lost due to leakage during tank
loading.
°Leakage rate from tank loading determined by V/L ratio.
C-12
-------
station control) previous to being loaded generally show a somewhat
higher average efficiency than non-balanced runs (due to higher VOC
concentration in the air-Vapor mixture returned to the processor).
A common deviation from the prescribed test procedure involved
the use of butane (C,H,0) as the reference hydrocarbon in mass calcu-
lations (14 tests). In these cases the values for concentration (as
volume percent as butane) were factored by the ratio of the densities
of butane and propane. As an example, in Test No. 22,
Cr = 21.9% (as butane) x 68.3 grams C4H10/ft3 = 28.9% (as propane).
51.8 grams C3Hg/ft3
In one test (Test No. 4), methane was used as the reference hydrocarbon
in mass calculations. The values of concentration in this test were
not converted to volume percent as propane because of the extremely
small exhaust concentrations.
In some cases, the data presented in this document do not match
those found in the emission test reports. This occurred because some
runs were deleted when the test data were reviewed and recalculated.
In these cases the deleted runs were not considered representative of
typical operation, or data were not complete. In addition, the criteria
for determining when leaks were present in the system were slightly
modified. Section C.2.2 discusses calculations involving system
leakage.
C.2.2 System Leakage Calculations
When air-vapor mixture leakage occurs at dome covers or vent
valves on the tankers during loading, the quantity of VOCs actually
recovered is less than that potentially recoverable. The runs during
which no leaks were detected by combustible gas detector measurements
are separated and the potential volumetric recovery is calculated.
This parameter is weighted in proportion to the amount of gasoline
loaded during each run and reflects the gas volume-to-liquid volume
ratio in a leak-free system. When no combustible gas detector
measurements were available, the potential volumetric recovery was
assumed equal to 1.0.
*
The actual calculated volumetric recoveries are variable, and can
be less than, equal to, or greater than 1.0. Values less than one can
C-13
-------
usually be attributed to system leakage, in which some of the air-vapor
mixture displaced by loaded gasoline is lost to the atmosphere.
Recoveries equal to one represent the ideal case, in which each unit
volume of gasoline causes a unit volume of mixture to be returned to
the vapor processor. Recoveries which exceed one are due to vapor
growth, which depends on temperature and pressure conditions in the
tank trucks and the vapor return lines.
For the purposes of these calculations, a leak was defined as
occurring whenever a reading on the combustible gas detector exceeded
100 percent of the lower explosive limit.
C.3 SUMMARIES OF ERA-CONDUCTED TESTS
This section of Appendix C summarizes 22 emission tests conducted
by EPA at bulk gasoline terminals between November 1973 and October
1978. Results from these tests were the primary source of information
in evaluating the various types of vapor processing systems in use at
bulk terminals.
The types of systems tested are carbpn adsorption (CA), Test Nos.
1 through 3; thermal oxidizer (TO), Test Nos. 4 through 7; refrigeration
(REF), Test Nos. 8 through 13; compression-refrigeration-absorption
(CRA), Test Nos. 14 through 19; compression-refrigeration-condensation
(CRC), Test Nos. 20 and 21; and lean oil absorption (LOA), Test No. 22.
It is suggested that these test summaries, as well as the emission
test reports referenced in this section, be consulted in conjunction
with the test results presented in Table C-l. The summaries contain
descriptions of the facilities tested, as well as information about
test conditions which might have influenced the test results. In
addition, the reasons for disregarding test results in some test
sequences are discussed.
C.3.1 Bulk Terminal Test No. 1
This terminal is a small gasoline loading terminal with a storage
capacity of 3,600,000 liters (950,000 gallons) of gasoline and a daily
gasoline throughput of 284,000 liters (75,000 gallons). Barges deliver
the supply of gasoline to the terminal. Two loading racks employ five
bottom loading positions, with vapor recovery lines leading to an
activated carbon adsorption (CA) type vapor recovery unit, manufactured
by HydroTech Engineering, Inc.
C-14
-------
Testing was performed May 25-27, 1977, during 33 tank truck
loadings to determine actual VOC emissions, potential VOC emissions,
and the vapor recovery efficiency of the system.
VOCs generated during bottom loading of tank trucks at the terminal
are collected by a vapor line collection system and routed to the carbon
adsorption vapor processor. VOCs broke through the carbon beds on the
first two days of testing. Outlet concentrations from the unit were
observed during these breakthroughs to be greater than 10 percent propane,
The problems causing bed breakthrough of VOCs were found and corrected
before the third (final) day of source testing. VOC breakthroughs of
the carbon beds were caused by incorrect settings in electrical timer
switching of the dual bed system. On the first day of testing it was
noted that the same bed was continuously on line to adsorb vapors
whenever a truck started loading. This improper setting of the bed
switching system caused an overload on one bed. The setting of the
bed switching system was corrected midmorning on the second test
day, but some breakthrough was noted on the second day while the
system was catching up. No VOC breakthrough was noted on the third
day. The improper setting was due to the fact that the system was
previously adjusted for processing a low volume lean stream and during
the test had to be readjusted to operate on a high volume rich stream.
Q
Further details are contained in the emission test report. Part of
the runs on the second day and all of the runs on the third day were
included in the data analysis. VOC emissions from the vapor recovery
unit for the runs when it was operating correctly were 2.7 and 5.4 mg/1
(0.010 and 0.020 gm/gal) for the second and third days of testing,
respectively. Emissions adjusted to account for system leakage were
8.5 and 3.9 mg/1 (0.032 and 0.015 gm/gal).
C.3.2 Bulk Terminal Test No. 2
Test No. 2 was performed March 1-3, 1978, at a small bulk terminal
with an average daily gasoline throughput of 189,000 liters (50,000
gallons). Gasoline is dispensed from one loading rack containing
three bottom-load dispensing arms.
Vapors displaced from tank trucks during loading are routed to a
vapor holder (premium gasoline storage tank equipped with lifter
C-15
-------
roof). When a specified capacity is reached, the control system is
manually started and the vapors travel to a HydroTech Engineering
carbon adsorption (CA) vapor recovery unit.
During testing, terminal operations were normal and no instrument
problems were reported. Daily average VOC emissions from the control
unit were 1.2, 2.1, and 2.5 milligrams per liter (0.005, 0.008, and
0.009 gram per gallon) of gasoline loaded. When adjusted for leakage
the emissions were 1.8, 2.8, and 3.9 mg/1 (0.007, 0.011, and 0.015
gm/gal).
Q
Further details are contained in the emission test report.
C.3.3 Bulk Terminal Test No. 3
This test was conducted at a bulk terminal with an average daily
gasoline throughput of approximately 303,000 liters (80,000 gallons).
This terminal is the same one described in Test No. 1. At the start
of each day, gasoline tank trucks are loaded on a staggered time
schedule with half-hour intervals between loadings. Two of the five
loading racks at the terminal dispense gasoline and use vapor recovery.
Testing was performed on October 24-26, 1978.
Air-vapor mixture displaced during loading is piped to a liquid
knockout tank and then passes to a HydroTech Engineering carbon adsorption
(CA) type vapor recovery unit. The data collected on October 26 was
not considered in evaluating this control technique because twice on
that day two trucks were loaded simultaneously, a deviation from
design procedure. This was done purposely to determine the effect on
the unit's collection efficiency. The collection efficiency on that
day was somewhat lower than that on the first two days of testing.
An air-balance analysis was performed on the air-vapor mixture
entering and leaving the control unit during the test. The air-balance
ratio, a measure of the ratio of the air entering to the air exiting
the unit, calculated for the three days of testing was 1.09, 1.01, and
0.99. The overall ratio for the three days was 1.03.
The test method followed the specified procedure except that
total VOC concentrations were measured as volume percent as butane.
Ten trucks out of the forty tested proved to be vapor-tight. Daily
average VOC emissions from the control unit were 10.8, 9.6, and
63.4 milligrams per liter (0.041, 0.036, and 0.240 gram per gallon)
C-16
-------
for the three days of testing. Adjusted for leakage, the emissions
were 11.0, 9.7, and 63.4 mg/1 (0.042, 0.037, and 0.240 gm/gal).
Further details are contained in the emission test report.
C.3.4 Bulk Terminal Test No. 4
Test No. 4 was conducted at a bulk terminal with a throughput of
approximately 1,100,000 liters (291,000 gallons) per day. The terminal
has two bottom-loading racks and one top-loading rack. VOC vapors
from tank trucks are vented through flexible connections to a common
header venting to a vapor holder and to a thermal oxidizer (TO) control
unit, manufactured by the AER Corporation.
Extensive tests on the thermal oxidizer system at this gasoline
loading terminal were performed during the period of November 18,
1973, to May 2, 1974. At this terminal VOC vapors from tank truck
loading operations are routed to a vapor holder, where they are enriched
with propane to ensure they are above the explosive range. The VOC
vapors from the vapor holder are then vented to the thermal oxidizer
for incineration.
The oxidizer is a simple gas furnace which turns on and operates
as needed; however, if it were necessary to shut down the oxidizer
during tank truck loadings or if the vapor holder filled beyond its
capacity of 283 cubic meters (10,000 cubic feet), or about 8 truck
loads, excess vapors would vent to the atmosphere.
Test results indicated that the oxidizer disposed of 99.8 percent
of the VOC vapor collected. However, only about 70 percent of the
air-vapor mixture displaced from the truck loading reached the oxidizer.
Unusually high pressures (39.7 mm of mercury or 21 inches of water)
produced in the truck during loading were responsible for the vapor
loss through poorly adjusted hatch covers and faulty pressure-vacuum
relief valves on the trucks. Also, low vapor transfer and pressure
buildup were caused by blockage of the vapor collection line by a
column of gasoline. These problems were partially corrected and the
overall disposal efficiency of the entire system (from tank truck to
control unit) then exceeded 90 percent. VOC emissions to the
atmosphere from the thermal oxidizer are estimated to be 1.0 milligram
per liter (0.004 gram per gallon) of gasoline loaded into the tank
trucks. The emission rate adjusted to account for system leakage was
C-17
-------
1.4 mg/1 (0.01 gm/gal) of gasoline loaded. Leakage from the trucks
was estimated to be 175.0 mg/1. Further details are contained in the
emission test report.
C.3.5 Bulk Terminal Test No. 5
Test No.- 5 was performed January 25-27 and January 30, 1978, at a
bulk terminal whose average gasoline throughput is 757,000 liters per
day (200,000 gallons per day). Gasoline is dispensed from four bottom-
loading arms at two loading racks. The air-vapor mixture displaced
from tank trucks is directed through a vapor collection system to a
liquid knockout tank, and then to a thermal oxidizer (TO) type vapor
control unit, manufactured by National Airoil Burner Company. An
interlock system shuts down the loading activity if the TO unit should
malfunction.
No problems with the control unit or test instrumentation were
reported during testing. All VOC concentrations were reported as
volume percent as butane. Daily average VOC emissions from the control
unit were 77.6, 36.7, 32.8, and 24.2 milligrams per liter (0.294,
0.139, 0.124, and 0.092 gram per gallon). Adjusted for leakage, the
emissions were 107.1, 47.3, 39.0, and 28.6 mg/1 (0.405, 0.179, 0.148,
and 0.108 gm/gal). Since no combustible gas detector measurements for
leaks were made, a value of 1.0 was assumed for the potential volumetric
recovery factor.
Test results from January 25, the first day of testing, were
12
deleted from the calculations in the emission test report, but no
possible cause which might have explained the high values was provided.
It was stated in the report that the values were not used "due to the
inconsistency with other results." The emission values from the first
test day have been included in the calculations used for evaluation of
this control technique because no operational problems during the test
have been reported. A possible cause could be maladjustment of the
inlet damper which controls the amount of combustion air admitted to
the combustion chamber.
Further details about the test are contained in the emmission
test report.
C-18
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C.3.6 Bulk Terminal Test No. 6
This tank truck gasoline loading terminal was selected for source
testing because the loading facilities are vented directly to an AER
Corporation thermal oxidizer (TO) unit. Two of the other thermal
oxidizer units source tested by EPA were equipped with a vapor holder
that allowed only vapors above the upper explosive limit to be vented
to the unit (Bulk Terminal Test Nos. 4 and 7).
The terminal is equipped with three gasoline loading rack positions.
Regular, premium, and unleaded gasoline are loaded at each of these
racks. At one loading rack, the tank truck vapor vent line was connected
to a turbine meter to measure the volume of vapors vented from the
tank truck to the vapor control system. Integrated bag samples of
vent gases from the trucks were taken at this point and tank truck
loadings were monitored for leaks. A liquid sample for each type of
gasoline loaded was also obtained for analysis. Testing was performed
on January 10-12, 1978.
During the test period the terminal was in normal operation and
the thermal oxidizer appeared to be operating properly. The daily
throughput of gasoline approximated 757,000 to 1,135,500 liters (200,000
to 300,000 gallons).
The test appears to have been conducted according to the prescribed
test procedure. The possibility exists that due to low temperature
conditions, the vapors vented to the thermal oxidizer unit in some
instances may have been below the lower explosive limit and could have
passed through the thermal oxidizer without being incinerated. VOC
emissions to the atmosphere from the thermal oxidizer were determined
to be 21.4, 22.4, and 39.8 milligrams per liter (0.081, 0.085, and
0.151 gram per gallon) of gasoline loaded into the tank trucks.
Emissions adjusted for leakage were 24.7, 27.0, and 50.9 mg/1 (0.093,
0.102, and 0.193 gm/gal).
13
Further details are contained in the emission test report.
C.3.7 Bulk Terminal Test No. 7
Testing was conducted February 23, 24 and 27, 1978, at a bulk
terminal whose daily gasoline throughput is approximately 1,514,000
liters (400,000 gallons). Gasoline is dispensed from six loading
racks through both bottom-loading and top-loading vapor recovery arms.
C-19
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Air-vapor mixture displaced during loading is routed first to a
liquid condensate tank, then to a vapor holder, and finally to an AER
Corporation thermal oxidizer (TO) type vapor control unit. Propane is
introduced into the vapor stream to keep the VOC concentration above
the upper explosive limit. The specified test procedure was followed,
except that VOC concentrations were measured as volume percent as
butane. The control unit and other vapor control equipment at the
terminal were in good condition. The control unit appeared to be
functioning properly, and no problems with instrumentation were reported.
VOC emissions from the TO unit were 23.7, 7.5, and 10.3 milligrams
per liter (0.090, 0.028, and 0.039 gram per gallon). Adjusted for
leakage, the emissions were 29.4, 9.3, and 13.2 mg/1 (0.111, 0.035,
and 0.050 gm/gal).
14
Further details are contained in the emission test report.
C.3.8 Bulk Terminal Test No. 8
Test No. 8 was conducted at a relatively small bulk terminal
having only one gasoline loading rack; however, the throughput of the
bottom-loading rack is approximately 380,000 liters (100,000 gallons)
per day. Three grades of gasoline (premium, regular, and unleaded)
are dispensed at the loading facility.
Vapors displaced from the gasoline tank trucks are vented to a
refrigeration type (REF) vapor recovery unit, manufactured by Edwards
Engineering Corporation. During the testing by EPA, which ran from
December 17-19, 1974, 24 trucks were loaded with gasoline to determine
the potential VOC emissions, actual VOC emissions, and the vapor
recovery efficiency of the control unit.
In the refrigeration type system, VOC vapors and air from the
tank trucks are directly processed and condensed in a double-pass
finned-tube condenser. There are no saturators or vapor holder utilized
in the system. The efficiency of the condenser is directly related to
the temperature of the condensing unit. In normal operation, a condenser
temperature of about -73°C (-100°F) is maintained.
Some operational problems with the control unit were encountered
during the test period. A leak had developed in the high pressure
section of the refrigeration system, resulting in refrigerant loss.
This prevented the condenser from maintaining the design temperature.
C-20
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Testing was resumed when the unit had been repaired, and the condenser
had reached a temperature of -51°C (-60°F). Thus, it does not appear
that design temperatures were reached at any time during testing.
VOC emissions from the recovery unit for the two successful days
of testing were determined to be 33.3 and 39.4 milligrams per liter
(0.126 and 0.149 gram per gallon) of gasoline loaded into the tank
trucks. The emission rates adjusted for leakage were 44.0 and
54.4 mg/1 (0.167 and 0.206 gm/gal). Leakage from the trucks was
estimated to be 83.0 milligrams per liter (0.314 gram per gallon).
15
Further details are contained in the emission test report.
C.3.9 Bulk Terminal Test No. 9
Test No. 9 was conducted at a medium size bulk terminal which
contains two loading racks. The bottom-loading arms are situated on a
concrete island so that the trucks can load concurrently to each
other. Throughput at the terminal is about 1,430,000 liters (378,000
gallons) of gasoline per day.
Air-vapor mixture is displaced during loading and piped to an
Edwards Engineering refrigeration type (REF) contol unit.
The facility and refrigeration unit were tested on September 20-22,
1976. During all three days the refrigeration unit was operating
below capacity due to refrigerant loss caused by a leaking pump seal.
As a result the actual refrigeration temperatures were -44 to -52°C
(-47 to -61°F) rather than the -73°C (-100°F) design temperature.
Daily average VOC emissions from the vapor recovery unit were deter-
mined to be 51.6, 52.3, and 29.9 milligrams per liter (0.195, 0.198,
and 0.113 gram per gallon) of gasoline loaded into the tank trucks.
Adjusted emissions were 72.2, 58.1, and 31.1 mg/liter (0.273, 0.220,
and 0.118 gm/gal).
Further details are contained in the emission test report.
C.3.10 Bulk Terminal Test No. 10
This tank truck gasoline loading terminal contains three
bottom-loading racks. Throughput at the terminal is about 830,000 liters
(220,000 gallons) per day. Testing was conducted on November 10-12,
1976.
The air-vapor mixture displaced from tank trucks during gasoline
loading is routed to an Edwards Engineering refrigeration type (REF)
control unit.
C-21
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The facility and REF unit were tested for three days. During all
three days the refrigeration, unit was operating at capacity. Icing at
the decanter occurred, caused by ambient air leaking into the separator,
but did not cause any problems. VOC emissions from the vapor recovery
unit were determined to be 76.6, 57.1, and 54.2 milligrams per liter
(0.290, 0.216, and 0.205 gram per gallon). Emissions adjusted for
leakage were 96.5, 58.8, and 61.8 mg/1 (0.365, 0.223, and 0.234 gm/gal).
Further details are contained in the emission test report.
C.3.11 Bulk Terminal Test No. 11
This test was performed on August 22-24, 1978 at a bulk terminal
employing five loading racks to dispense fuel oil and three grades of
gasoline. All racks use top splash loading to deliver the products to
tank trucks. Only two of the racks load gasoline, and vapor recovery
is used for both of these racks. The gasoline throughput of the
terminal is considered confidential by the operator. Air-vapor mixture
generated during loading operations is routed to a liquid knockout
tank to remove any liquid gasoline and then to a refrigeration (REF)
type control unit, manufactured by Tenney Engineering, Incorporated.
During testing, the REF unit did not maintain the low temperatures
required for efficient vapor collection. The design temperature of
the fin-tube condenser during operation is approximately -73°C (-100°F).
The level of the methylene chloride cooling fluid (brine) was approxi-
mately 800 gallons below its capacity level during the test. As a
result, the brine temperature ranged between -40°C (-40°F) and -54°C
(-65°F). In addition, problems were encountered in measuring the very
high VOC concentrations (as butane) at the inlet and outlet of the
control unit. Only 20 out of 46 inlet concentration values and 27 out
of 42 exhaust concentration values were successfully recorded during
testing. Most of the successful readings were taken on the third day
of testing, when a system to continuously dilute the inlet and exhaust
streams was used. There are several possible causes for the high
inlet concentrations to the REF unit. Top splash loading generates
increased vapor concentration due to turbulence. Temperatures of
between 38°C (100°F) and 49°C (120°F) were measured at the inlet
volume meter. Also, the placement of the meter at the processor inlet
C-22
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instead of at the rack may have resulted in the concentration measurement
of evaporated liquid gasoline which may have entered the line. Ambient
temperatures were high and the vapors passed through a long, green
metal line from the truck rack to the meter inlet.
18
Further details are contained in the emission test report.
Emissions of VOCs from the control unit were 1318, 841, and
794 milligrams per liter (4.99, 3.18, and 3.01 grams per gallon).
Since the adjustment factor for tank truck leakage is 1.00, the actual
and adjusted emission values are identical.
C.3.12 Bulk Terminal Test No. 12
Test No. 12 was conducted September 26-28, 1978 at a bulk terminal
with a daily average gasoline throughput of 1,514,000 liters (400,000
gallons). Gasoline and distillates are transferred to tank trucks
through five loading racks, three of which use bottom loading and
dispense gasoline.
Air-vapor mixture is piped from the loading racks first to a
liquid knockout tank which removes any liquid gasoline in the line.
The mixture passes from the knockout tank directly to a Tenney
Engineering refrigeration (REF) type control unit.
Due to the mode of operation of the control unit during testing,
a significant amount of air-vapor mixture collected at the loading
racks passed through the unit without vapor recovery. Defrost cycles
were scheduled to occur during the following time intervals:
Start Defrost Finish Defrost
4 a.m. 5 a.m.
10 a.m. 11 a.m.
2 p.m. 3 p.m.
8 p.m. 9 p.m.
Two of these defrost cycles coincide with the daytime scheduling of
the testing. Results were calculated for test runs during which no
defrosting occurred. It is suspected that even these results do not
accurately reflect the performance of the unit which would occur if
the defrost schedule were corrected. Too-frequent defrost intervals
may cause the accumulated frost to ice on the condenser coils, which
C-23
-------
would result in a reduction in heat transfer efficiency. Collection
efficiency would be decreased as a result, even for the non-defrost
runs. A manual defrost for the entire night of September 27 led to a
somewhat improved collection efficiency on the third day of testing,
September 28.
VOC concentrations were calculated as volume percent as butane.
Emissions from the control unit were 67.2, 102.6, and 61.9 milligrams
per liter (0.254, 0.388, and 0.234 gram per gallon). Adjusted for
leakage, these emissions were 75.9, 102.6, and 68.1 mg/1 (0.287,
0.388, and 0.258 gm/gal).
Further details of this test are contained in the emission test
19
report.
C.3.13 Bulk Terminal Test No. 13
This test was performed at a bulk terminal with an average gasoline
throughput of approximately 1,514,000 liters per day (400,000 gallons
per day). The terminal contains 14 racks using top splash loading
which dispense xylene, fuel oil, and three grades of gasoline. Only
the five racks loading gasoline route the displaced vapors to vapor
recovery. The testing was conducted on October 10-12, 1978.
Air-vapor mixture displaced during loading is piped through a
liquid knockout tank to an Edwards Engineering refrigeration (REF)
type vapor recovery unit. During testing, the unit was operating
well, as evidenced by its low brine pump supply temperature (-72°C, or
-97°F). However, serious leakage in the terminal loading equipment
prevented a large portion of the displaced air-vapor mixture from
reaching the unit. Most loading racks leaked liquid gasoline at
swivel joints, and vapors leaked from several locations, including:
1. Loading arm/hatch seal interface,
2. P-V vents and check valves, and
3. Flexible vapor return lines.
An air balance'analysis showed that approximately 48 percent of the
displaced air-vapor mixture leaked from the vapor collection system.
Because of this leakage, the test results were not included in the
evaluation of the REF control technology.
20
Further details are contained in the emission test report.
C-24
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C.3.14 Bulk Terminal Test No. 14
Test No. 14 was conducted at a bulk tenninal that has an average
gasoline throughput of approximately 600,000 liters (160,000 gallons)
per day. The terminal was tested by EPA on December 11-12, 1974. The
tenninal has eight loading racks for various fuels, three of which
dispense gasoline. Each of the gasoline loading racks is equipped for
bottom loading of premium, regular, and unleaded gasoline. Also, on
one of the gasoline racks, two grades of aviation fuel are dispensed
and vapors are vented to the vapor control system.
Vapor hoses at each rack are manifolded to a common header venting
to a saturator. The purpose of the saturator is to ensure that the
vapors vented to the vapor holder are above the upper explosive limit.
Saturated vapors pass to a vapor holder. At a preset volume the vapor
holder automatically discharges to an 8,500 liter per minute (300 cfm)
compression-refrigeration-absorption (CRA) system, manufactured by the
Parker-Hannifin Corporation.
Testing was performed during 39 truck loadings to determine
potential VOC emissions, actual VOC emissions, and vapor recovery
efficiency of the system. Only two loading racks were tested. The
other rack was not used for testing purposes because insufficient test
equipment was available.
VOC emissions from the vapor recovery unit were determined to be
31.0 and 31.6 milligrams per liter (0.117 and 0.120 gram per gallon)
for the two days of testing. When adjusted to account for leakage the
emission rates from the unit were 73.5 and 57.2 mg/liter (0.278 and
0.217 gm/gal).
The only difficulties in testing encountered in the loading of
gasoline were vapor leakage and spillage. Vapor losses occurred at
almost all hatches and pressure vents at the top of the trucks.
Liquid spillage occurred on occasion because of improper seating of
the shut-off valve at the liquid connection to the tanker, and also
from buckets used to catch a small amount of unleaded gasoline left in
the tank truck compartments from the previous load.
pi
Further details are contained in the emission test report.
C-25
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C.3.15 Bulk Terminal Test No. 15
This tank truck gasoline loading terminal contains four
bottom-loading racks delivering 1,190,000 liters (315,000 gallons) of
gasoline per day. The facility is attended for about 10 hours per
day, but drivers have pass keys which permit loading 24 hours per day,
7 days per week. Testing was conducted on September 23-25, 1976.
The vapor recovery unit is a compression-refrigeration-absorption
(CRA) unit, manufactured by the Rheems-Superior Corporation. The
system handles emissions from the loading rack and from storage tank
loading operations (pipeline delivery).
Gasoline vapors, collected from tank truck loading operations,
are first sprayed with gasoline to ensure that they are saturated
(above the explosive range). The vapors are then vented to a regular
gasoline product storage tank equipped with a lifter roof. When the
roof reaches a pre-determined level the vapors are vented to the CRA
unit where the vapors are sprayed with gasoline again (to saturate)
and then compressed and cooled. The vapors are then vented to an
absorber where they are absorbed in fresh gasoline, and the cleaned
gases are exhausted to atmosphere.
Throughout the test period, loading procedures were normal and
the unit operated with no apparent problems. However, liquid buildup
in the sample line on September 25 led to invalid VOC concentration
measurements on that day. In addition to truck and CRA outlets being
monitored, the liquid levels in the storage tanks, the flow to the
pipeline, and the liquid volumes into and out of the CRA unit were
monitored.
One problem seen was that drivers frequently drained trucks of
remaining gasoline into a sump before loading. This caused several
liters of gasoline to evaporate to the atmosphere during the course of
the test period. This loss cannot be quantified. Daily average VOC
emissions from the vapor recovery unit for the first two test days
were determined to be 30.7 and 30.5 milligrams per liter (0.116 and
0.115 gram per gallon) of gasoline loaded into the tank trucks. The
emission rates adjusted for leakage were 44.5 and 47.0 mg/liter (0.168
and 0.178 gm/gal).
C-26
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Trucks loading diesel fuel also hooked up to the vapor return
line and vented emissions to the saturator of the CRA. Further details
22
are contained in the emission test report.
C.3.16 Bulk Terminal Test No. 16
Test No. 16 was conducted at a terminal containing two loading
racks having four bottom-loading dispensing arms each. The gasoline
throughput of the terminal is considered confidential by the operator.
Air-vapor mixture displaced from loading tank trucks is directed
to a liquid knockout tank, a vapor holding tank, and then to a vapor
control unit. The control unit is the compression-refrigeration-absorption
(CRA) type, manufactured by Trico-Superior, incorporated. Testing was
performed on four days, February 20-21, 1978, and March 8-9, 1978.
No control system upsets or instrument malfunctions were reported
during the test. VOC concentrations were measured as volume percent
as butane. No measurements of leaks were made with a combustible gas
detector, so the value of (V/L) was assumed to be 1.0. Data allowing
calculation of V/L were not collected on March 8 and 9, and processor
data (M/L)e were not obtained on February 20. Daily average VOC
emission levels on three days of testing were 61.2, 59.5, and
57.2 milligrams per liter (0.232, 0.225, and 0.217 gram per gallon).
Adjusted for tank truck leakage, emissions on February 21 were 88.1 mg/1
(0.333 gm/gal).
23
Further details are contained in the emission test report.
C.3.17 Bulk Terminal Test No. 17
This tank truck gasoline loading terminal vapor control system
was tested by EPA on May 2-4, 1978. The terminal has a gasoline
throughput that approximates 1,000,000 liters (264,000 gallons) per
day.
The vapor control system uses a Parker-Hannifin
compression-refrigeration-absorption (CRA) unit. The unit was tested
to determine its efficiency in removing VOCs generated during tank
truck gasoline loading.
The total VOC concentration, at both the inlet and outlet of the
vapor recovery unit, was continuously monitored, and the vapor volumes
were determined at these two sampling points.
C-27
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No major problems during testing were reported. Daily average
VOC emissions to the atmosphere from the vapor recovery unit were
40.9, 45.1, and 35.9 milligrams per liter (0.155, 0.171, and 0.136 gram
per gallon) of gasoline loaded. The control unit emissions adjusted
for system leaks were 78.5, 58.2, and 52.1 mg/1 (0.297, 0.220, and
0.197 gm/gal) of gasoline loaded.
24
Further details are contained in the emission test report.
C.3.18 Bulk Terminal Test No. 18
Test No. 18 was conducted at a bulk terminal whose daily gasoline
throughput averages 1,514,000 liters (400,000 gallons). Gasoline and
distillates are dispensed through six loading racks, four of which use
bottom loading and dispense gasoline. Testing was performed on August 2-4,
1978.
Air-vapor mixture displaced during tank truck loading is piped to
a saturator to raise the VOC concentration above the upper explosive
limit. After saturation, the mixture is stored in a bladder-type
vapor holder. At a preset level, the control unit is started auto-
matically to process the vapors. This unit is a Trico-Superior
compression-refrigeration-absorption (CRA) type unit.
No problems were reported during the testing in regard to the
operation of the control unit or test instrumentation. VOC concen-
trations were measured in volume percent as butane. Five tank trucks
were determined to be vapor-tight out of the 59 for which leak
measurements were taken. VOC emissions from the control unit were
32.2, 43.1, and 43.0 milligrams per liter (0.122, 0.163, and 0.163 gram
per gallon). Adjusted for leakage, emissions were 41.5, 65.1, and
52.9 mg/1 (0.157, 0.246, and 0.200 gm/gal).
25
Further details are contained in the emission test report.
C.3.19 Bulk Terminal Test No. 19
Test No. 19 was performed at a bulk terminal containing seven
loading racks which dispense gasoline and distillates. Three of the
racks use bottom loading, and two of these dispense gasoline. The
daily gasoline throughput at the terminal is considered confidential
by the operator. Testing was performed at the terminal on September
19-21, 1978. The results presented are for only one day of testing,
September 21, 1978. Air-vapor leakage at the pressure-vacuum relief
C-28
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valve on one of the unleaded gasoline storage tanks made it necessary
to omit the September 19 test data. A disconnected volume meter at
the control system exhaust on September 20 invalidated the results
from that day.
Air-vapor mixture generated at the three bottom-loading racks is
routed to a vapor holder, and then to a saturator, where gasoline is
sprayed into the mixture. The two unleaded gasoline storage tanks
also act as vapor holders. When the vapor holder reaches a preset
capacity level, the control unit starts automatically and vapors are
sent through the unit. This unit is a Parker-Hannifin compression-
refrigeration-absorption (CRA) type unit.
There were no significant equipment problems reported during the
testing on September 21. Five of the tank trucks were measured to be
vapor-tight out of the 19 loadings tested. Total VOC concentrations
were measured in volume percent as butane. VOC emissions exhausted
from the control unit were 85.9 milligrams per liter (0.325 gram per
gallon). Adjusted for leaks, the emissions from the unit were
91.0 mg/1 (0.344 gm/gal).
26
Further details are contained in the emission test report.
C.3.20 Bulk Terminal Test No. 20
Test No. 20 was performed at a complex consisting of four bulk
terminals whose total average daily throughput of gasoline is approxi-
mately 5.68 million liters (1.5 million gallons). VOC vapors from all
four terminals are routed to a single vapor control unit. The control
unit is a compression-refrigeration-condensation (CRC) type unit,
manufactured by Gulf Environmental Systems Company (GESCO). The
operation of this unit is somewhat similar to that of the CRA unit.
Testing was performed on four days, February 1-2, 1978, and March 6-7,
1978.
VOC vapors displaced from tank trucks during filling are piped to
a vapor holding tank with an internal flexible bladder. When the
vapor volume reaches a preset level, the control unit starts and
processes the collected vapors. Incoming vapors are first contacted
with recovered product in a saturator, where the VOC concentration is
raised above the explosive range. The saturated vapors are then
C-29
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compressed in a two-stage compressor with an intercooler. The compressed
vapors pass through a condenser where they are cooled, condensed and
returned to gasoline recovery with the condensate from the intercooler.
Recovered gasoline is distributed to each terminal in the complex
based on its throughput for a given period.
The control unit was operated with a defective compressor on
February 1 and 2, so the results from these days are not included in
the data. Daily average VOC emission levels from the CRC unit during
the two successful test days were 41.0 and 44.4 milligrams per liter
(0.155 and 0.168 gram per gallon) of gasoline loaded. Adjusted for
leakage, the emission levels were 48.4 and 55.9 mg/1 (0.183 and
0.212 gm/gal).
27
Further details are contained in the emission test report.
C.3.21 Bulk Terminal Test No. 21
Test No. 21 was performed at a bulk terminal containing nine
loading racks, five of which dispense gasoline through bottom-loading
arms. Daily gasoline throughput at the terminal is considered confidential
by the terminal operator. Testing was performed on August 16-18,
1978.
Air-vapor mixture displaced from tank trucks during loading is
routed through a saturator, and then to a vapor holder. The vapor
holder is followed by a GESCO compression-refrigeration-condensation
(CRC) type control unit, which starts automatically when a preset
volume level is reached in the vapor holder.
Major operational problems with the vapor holder made some of the
calculations impossible. During the testing period, the control unit
would operate only when switched on manually because the automatic
start switch was inoperative. The unit was sometimes not started soon
enough and air-vapor mixture would overfill the vapor holder and
exhaust to atmosphere through the pressure relief valve. It is estimated
that approximately 81 percent of the displaced mixture leaked out of
the system before reaching the control unit. VOC emissions from the
control unit, emissions adjusted for leaks, and unit control efficiency
could not be calculated.
Further details of this test are contained in the emission test
28
report.
C-30
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C.3.22 Bulk Terminal Test No. 22
Test No. 22 was conducted at a bulk terminal which has an average
daily throughput of approximately 1,514,000 liters (400,000 gallons).
The terminal contains four loading racks, two of which top load gasoline
with splash type nozzles, and one of which bottom loads gasoline. The
air-vapor mixture in tank trucks being loaded is collected at the
racks and routed to a lean oil absorption (LOA) control unit, manufac-
tured by Southwest Industries (Ingersoll-Rand Corporation). Testing
at this terminal was conducted on April 11-13, 1978.
While the average unit control efficiency for the three-day test
was quite low (78.9 percent), by increasing the lean oil flow to the
absorber column the unit achieved an efficiency of 85.9 percent on one
of the test days (April 12). This indicates that the LOA unit is
capable of improved efficiency when operating conditions are modified.
The maximum benefit achievable by making such changes is not known.
Testing was performed during 36 tank truck loadings. Operations
at the terminal were normal and no instrument problems were reported.
Daily average VOC emissions from the vapor recovery unit were 97.0,
52.9, and 86.7 milligrams per liter (0.367, 0.200, and 0.328 gram per
gallon) of gasoline loaded. Emission levels adjusted for leakage were
130, 73.0, and 119 mg/1 (0.492, 0.276, and 0.450 gm/gal) for the three
days of testing.
2Q
Further details are contained in the emission test report.
C-31
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C.4 REFERENCES-
1. Polglase, W., W. Kelly, and J. Pratapas. Control of Hydrocarbons
from Tank Truck Gasoline Loading Terminals. U.S. Environmental
Protection Agency. Research Triangle Park, N.C. Publication
No. EPA-450/2-77-026. October 1977. 60 p.
2. Norton, Robert L. Evaluation of Vapor Leaks and Development
of Monitoring Procedures for Gasoline Tank Trucks and Vapor
Piping. U.S. Environmental Protection Agency. Research Triangle
Park, N.C. Publication No. EPA-450/3-79-018. April 1979. 94 p.
3. Molenda, Deborah B. ARCO Bulk Terminal, Edwards Engineering Vapor
Recovery Unit, Model DE 3400 (Modified). County of San Diego
Air Pollution Control District. San Diego, CA. Test dates
6-16-79 and 6-18-79 (report undated).
4. State of California Air Resources Board. Edwards Vapor Recovery
System at the Atlantic Richfield Company Gasoline Terminal,
Carson, California. Emission Evaluation Report No. C-9-021.
Sacramento, CA. May 1979. 15 p.
5. State of California Air Resources Board. Edwards Vapor Recovery
System at the Atlantic Richfield Company Vinvale Gasoline
Terminal, Southgate, California. Emission Evaluation Report
No. C-9-020. Sacramento, CA. May 1979. 20 p.
6. State of California Air Resources Board. McGill, Inc., HydroTech
Division, Vapor Recovery Unit at Union Oil Company Gasoline
Terminal, Avila Beach, California. Emission Evaluation Report
No. C-9-022. Sacramento, CA. May 1979. 12 p.
7. Scott Environmental Technology, Incorporated. Leak Testing of
Gasoline Tank Trucks. U.S. Environmental Protection Agency.
Research Triangle Park, N.C. EPA Contract No. 68-02-2813, Work
Assignment No. 19. August 10, 1978. 120 p.
8. 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.
9. 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.
C-32
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10. 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.
11. Amoco Oil Company. Demonstration of Reduced Hydrocarbon Emissions
from Gasoline Loading Terminals. U.S. Environmental Protection
Agency. Washington, D.C. Publication No. EPA-650/2-75-042.
June 1975. 51 p.
12. 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.
13. 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 1978. 166 p.
14. 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.
15. 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.
16. 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.
17. 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.
18. 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.
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19. 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.
20. 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.
21. 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.
22. 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.
23. 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.
24. 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.
25. 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.
26. 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.
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.
C-34
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28. 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.
29. 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.
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APPENDIX D
EMISSION MEASUREMENT AND CONTINUOUS MONITORING
D-l
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APPENDIX D - EMISSION MEASUREMENT AND CONTINUOUS MONITORING
There are three sections of the proposed bulk gasoline terminal
standard that would require performance test procedures to determine
compliance: (1) vapor-tightness of gasoline tank trucks, (2) leaks from
vapor collection and processing equipment, and (3) mass emissions from
the vapor processor outlet. In order to conduct these performance
tests, six new reference test methods were developed: Methods 2A, 2B,
21, 25A, 25B, and 27. Each performance test procedure and its applicable
new reference methods are discussed in the following sections. Also,
the emission testing and test method development conducted for this proposed
regulation are summarized. Finally, various possible monitoring approaches
are discussed.
D.I GASOLINE TANK TRUCKS
D.I.I Performance Test Method
The proposed gasoline terminal regulation would require that all
gasoline tank trucks which are loaded at an affected facility be vapor-
tight. The recommended measurement procedure is Reference Method 27,
"Determination of Vapor Tightness of Gasoline Delivery Tank Using a
Pressure-Vacuum Test." The method uses a static pressure-vacuum test
procedure; the tank is pressurized (or alternately evacuated) to a
predetermined level, and the change in pressure versus time is compared
to the allowable pressure change specified in the regulation.
To conduct this test, a tank must be removed from service, emptied
of all liquid, and protected from direct sunlight. It is recommended
that all volatile vapors be purged from the tank prior to testing. One
acceptable purging method is to carry a load of non-volatile liquid fuel,
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such as diesel or heating oil, immediately prior to the test, thus
flushing out all the volatile gasoline vapors. This is the easiest and
most effective purging procedure; however, the flexibility and opportunity
of carrying a diesel load is not available to all tank owners. A second
purging method is to remove the volatile vapors by blowing ambient air
into each tank compartment for at least 20 minutes. This second method
is usually not as effective. Purging of volatile vapors is needed
because test data show that gasoline vapors in a tank may cause testing
inconsistencies. However, it is possible to test without purging if
there is enough time for the vapors to stabilize prior to testing. To
ensure that the vapors have stabilized, a provision is included in
Method 27 which requires that the test be conducted with the same results
(within the precision of the measuring instruments) on two consecutive
runs. This allows the owner the choice of purging the volatile vapors
prior to testing or waiting for a longer stabilization period during the
actual testing.
The vapor-tightness performance criteria (similar to emission limits)
are not included in Method 27, but instead are specified in each individual
regulation that calls for using Method 27. For the gasoline terminal
regulation, the recommended performance level is that the pressure in
the tank shall not change by more than 75 mm (3 inches) of water in 5
minutes when pressurized to 450 mm (18 inches) of water. Because the
proposed terminal standard would regulate only the loading of product
into a tank truck, (that is, when a tank is under pressure), only the
pressure part of the pressure-vacuum test in Method 27 is applicable.
The procedure in Method 27 requires no special testing instruments
or equipment. The total time needed for this test procedure, including
minor maintenance, is 1 to 4 hours, depending on the purging procedure
D-3
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used. The cost of conducting this test is related to the testing time
period, but averages about $100. (This cost does not include the
additional cost of repair and replacement parts if a leak is found).
Several other test methods and regulatory approaches were considered
during the background study for the gasoline terminal regulation. Eight
other candidate test methods were investigated for their use and acceptabi-
lity as a vapor-tightness test procedure. These alternative methods are
volume leakage rate, "quick" pressure decay, combustible gas detector,
sonic detector, bubble indication, sensory detection, bag capture, and
vapor-to-liquid volume ratio methods. A description, evaluation, and
reason for rejection of each of these methods is presented in detail in
1 2
another EPA document and a published paper.
D.I.2 Emission Testing and Measurement Methods
During the standard support study for the bulk gasoline terminal
regulation, EPA conducted a field testing program to develop a test
procedure for determining vapor-tightness of tank trucks. Tests were
conducted in California because at that time only California required tank
truck fleet operators to maintain all tanks in a vapor-tight condition, as
defined by the California Air Resources Board (CARB) certification
criteria. The delivery tank truck fleet to be tested was selected so that
a representative cross-section of tanks was obtained. Test were conducted
at both bottom and top loading terminals over a 2-week period in which over
200 tank loadings were monitored. Each of the 27 selected tanks was also
removed from service for a half-day for further shop tests.
Seven test methods were included in the field test program:" combustible
gas detector, sonic detector, sensory detection, vapor-to-liquid volume
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ratio, bubble indication, volume leakage, and static pressure-vacuum test
methods. In addition, the bag capture method was observed in the field,
as conducted by San Diego County officials, and the "quick" pressure decay
method was investigated on a bench-scale model tank in the laboratory.
A description of the testing program, the candidate methods, and an
2
evaluation of the results can be found in a previously published paper
and another EPA document.
The static pressure-vacuum testing procedure which was used during
this program is very similar to the recommended performance test procedure.
Two areas of difference concern the allowed amount of pressure drop and
the procedure to ensure stabilization. In the field testing program, the
CARB pressure test criterion was used, which at the time required that
the pressure in a tank not change by more than 2 inches of water in 5
minutes when initially pressurized to 18 inches of water. The vapor-
tightness criterion in the proposed terminal regulation allows a pressure
change of 3 inches. However, this difference in the test procedures does not
affect the usefulness of the field test data because the period for the
pressure test was extended during the field tests until a 3-inch drop
was also attained.
During the field testing, it was discovered that failure to remove all the
volatile vapors caused testing inconsistencies and erroneous results. Some-
times during the pressure test, the pressure in the tank surprisingly
increased with time instead of decreasing as expected. Repeatable results
were difficult to obtain, and long stabilization periods were sometimes
necessary before meaningful or consistent test results occurred. Because
of these problems, a provision to ensure repeatability and accuracy was later
developed and included in Method 27. Although repeat runs were usually not
conducted during the field tests, the usefulness of most of the test data
was not affected. No stabilization problems were encountered at one
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terminal where diesel fuel purging was used. At the other terminal where
air purging was used, the stabilization problems were discovered after the
first few tests, and testing repetitions were conducted on the remaining tanks,
Thus, the overall differences between the test procedures are slight and
should not affect the representativeness or the usefulness of the emission
test data.
D.I.3 Monitoring Systems and Devices
Because the vapor-tightness determination procedure is not a typical
direct emission measurement technique, and because leakage from gasoline
tank truck fittings is hot a typical emission source, there are no
continuous monitoring approaches that are directly applicable. Continual
surveillance is achieved by repeated monitoring or testing of the tank trucks.
The interval between tests could be either monthly, quarterly,
semi annually, or annually, depending on the likelihood of a leak developing
and on the cost-effectiveness of the test. A testing interval of 1 year
is recommended for two reasons. First, it is consistent with the current
California regulation and with the regulation recommended in the Control
3
Techniques Guideline document (which many States are now adopting in the
State Implementation Plans). Second, analysis of test data shows that the
requirement for an annual test results in average tank leakage emissions
of 10 percent; average leakage for a 6-month test would be 7 percent; the
2
leakage at the time of the vapor-tightness test is 1 percent. Tank trucks
rarely remain vapor-tight due to normal daily wear-and-tear. Because a
6-month test interval is only marginally more effective than a 1-year
interval, and because of the cost and inconvenience of the testing, an
annual test was selected.
The recommended monitoring procedure is Method 27; thus, the monitoring
procedure is identical to the performance test. Accordingly, the cost and
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the time for monitoring are the same as those for the initial compliance test.
D.2 VAPOR COLLECTION AND PROCESSING EQUIPMENT
D.2.1 Performance Test Method
The second part of the proposed gasoline terminal regulation that
would require a performance test concerns fugitive emissions from a
terminal's vapor collection and processing equipment. There are several
pieces of equipment at a typical vapor processing unit which are especially
prone to developing leaks, such as pump seals, valves, and vapor holder
diaphragm and relief vents. Field tests have shown that emissions from
these sources may be significant, emitting up to 80 percent of the
collected vapors from the loading racks before the vapors enter the
control unit. Besides being emission sources, large leakage from these
sources would affect the representativeness of emission measurements at
the processor outlet.
The recommended measurement procedure for leaks is Reference Method
21, "Determination of Volatile Organic Compound Leaks", which is applicable
for the detection of VOC leaks from organic liquid and vapor processing
equipment. This method employs a portable analyzer to detect the presence
of organic vapors at the surface of the interface where direct leakage to
atmosphere could occur. The approach of this technique assumes that if
an organic leak exists there will be an increased vapor concentration in
the vicinity of the leak, and that the measured concentration is generally
proportional to the mass emission rate of the organic compound.
Instrument specifications, performance criteria, and calibration
procedures are included in the method to ensure the uniformity and accuracy
of instrument measurements. The sampling probe should be positioned at the
surface of each potential leakage source, essentially 0 centimeter distance.
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The highest instrument reading is recorded and compared to the allowable
reading specified in the applicable regulation.
The definition of a leak (similar to an emission limit) is not included
in Method 21, but instead is specified in each individual regulation that
calls for Method 21. For the proposed terminal regulation, the recommended
leak definition is any reading greater than or equal to 10,000 ppm when
the instrument is calibrated to methane. A leak detection survey is
recommended immediately prior to and after any performance test of
processor outlet emissions. This ensures the validity of the outlet
test results. Periodic leak detection surveys may also be required to
ensure that no major leak has developed since the performance test.
There are several commercially available analyzers that can meet the
specifications in Method 21. The estimated purchase cost for an analyzer
ranges from $1,000 to $5,000 depending on the type and optional equipment.
Because the collection and processing equipment at a terminal is not
extensive, only about 15 minutes would be needed to survey for leaks. An
additional 15 to 30 minutes would be required to prepare and calibrate the
hydrocarbon analyzer.
All the developmental work on Method 21 and on the regulatory approach
for VOC leakage sources was done during the background support studies
for two other EPA standards: (1) New Source Performance Standards (NSPS)
for VOC fugitive emissions from the Synthetic Organic Chemical Manufacturing
Industry (SOCMI), and (2) National Emission Standard for Hazardous Air
Pollutants (NESHAP) for fugitive benzene emissions. The background
4 5
documents for these two standards discuss the development of Reference
Method 21, its selection over other test methods, the emission testing
performed, the interpretation of the resulting data base, the selection of
D-8
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the regulatory approach, and the selection of a leak definition.
The leak definition, performance test, and application of Method 21
for the terminal standard were selected as much as possible to be consistent
with these other two standards. It is assumed that the data base gathered
from emission tests at petroleum refineries and SOCMI facilities and the
rationale for the regulatory approach is directly applicable to gasoline
terminals. This assumption was made because organic processing equipment
and its usage at SOCMI and refinery facilities is similar to that at
terminal facilities.
D.2.2 Emission Testing and Measurement Methods
During the emission testing for bulk gasoline terminals, no formal
lead detection survey of a terminal's vapor collection and processing
equipment was conducted. Extensive testing was done, however, in support
studies for other EPA fugitive emission standards and guideline documents
in related industries (SOCMI, petroleum refineries, and benzene fugitive
emission sources). Details of these testing programs are found in other
EPA documents.4*5'6
Because the organic processing equipment at gasoline terminals is
similar in its design and usage to equipment at these other facilities,
it is assumed that the emission test results are applicable to the
gasoline terminal regulation. Although the amount of equipment at an
individual terminal is not as extensive as that at facilities in these
other industries, the ratio of leaking sources versus potential sources
should be the same.
Even though no Method 21 leak detection surveys were performed during
the terminal test program, sources of leakage were discovered in the
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vapor processing equipment at some terminals. These leaks were discovered
by sensory detection, combustible gas analyzer monitoring (a non-rigorous
procedure similar to Method 21), or analysis of the outlet emission test
results. One common source of extensive leakage was the processor's
vapor holder. Air material-balance calculations showed that 50 to 80
percent of the uncontrolled emissions (prior to processing) were sometimes
emitted from this source.
D.2.3 Monitoring Systems and Devices
Because the leak detection procedure is not a typical emission
measurement technique, and because leakage sources are not typical
emission sources, there are no continuous monitoring approaches that are
directly applicable. Continual surveillance is achieved by repeated
monitoring or screening of all affected potential leak sources. The
monitoring interval could be either monthly, quarterly, or annually,
depending on the likelihood of a leak developing.
The recommended monitoring procedure is Method 21; thus, the monitoring
procedure is identical to the performance test. Accordingly, the cost and
time for monitoring is the same as for the performance test procedure, 15
minutes to survey for leaks and 15 to 30 minutes to prepare and calibrate
the analyzer.
Instead of monitoring for leaks using a Method 21-type procedure, an
alternate approach was considered which required periodic visual and
olfactory inspections by terminal personnel. This serves the same
purpose in that any gross leakage or maintenance problems would be
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discovered during the periodic inspections. The sensory inspection
would take less time and be less expensive because a portable hydrocarbon
analyzer is not needed. However, because of the subjectivity of an
individual's sensory perceptions, it would be difficult to determine if
smaller leaks were in fact violations or not.
D.3 VAPOR PROCESSOR EXHAUST OUTLET
D.3.1 Performance Test Method
The third section of the proposed terminal regulation that would
require a performance test procedure concerns the emissions from a
terminal's vapor control unit. The format of the standard is mass of
VOC emitted per volume of gasoline loaded. To determine this, three
measurements are needed: (1) VOC concentration in the stack, (2) gas
volume exhausted, and (3) gasoline throughput during the test period.
Four new EPA Reference Methods had to be developed; these methods are
combined in a performance test procedure that is contained in the proposed
regulation itself. The performance test procedure defines the test
length and the conditions under which testing is acceptable, as well as
the way the reference method measurements are combined to attain the
final result.
a. Concentration Measurements
Prior to the gasoline terminal standard, the only Reference Method for
measuring VOC concentration was Method 25, "Determination of Total Gaseous
Nonmethane Organic Content (TGNMO)." However, the TGNMO procedure is not
recommended for the terminal standard because it does not continuously measure
concentration and it is awkward to use for long test periods. A
terminal processor operates intermittently, and there may be a significant
variability in the outlet concentration over short periods of time. These
variations would be masked if the testing procedure used an integrated
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sampling approach as in Method 25. Instead, a new continuous VOC measurement
method was developed, because with continuous measurements, the short-
term variations in concentration can be noted. The continuous records
are then averaged or integrated as necessary to obtain an average result
for the measurement period.
The recommended VOC measurement method is Reference Method 25A or
25B. Method 25A, "Determination of Total Gaseous Organic Concentration
Using a Flame lonization Analyzer," applies to the measurement of total
gaseous organic concentration of vapors consisting of alkanes, and/or
arenes (aromatic hydrocarbons). The instrument is calibrated in terms
of propane or another appropriate organic compound. A sample is extracted
from the source through a heated sample line and glass fiber filter and
routed to a flame ionization analyzer (FIA). (Provisions are included
for eliminating the heated sampling line and glass fiber filter under
some sampling conditions.) Results are reported as concentration equiva-
lents of the calibration gas organic constituent or organic carbon.
Method 25B, "Determination of Total Gaseous Organic Concentration
Using a Nondispersive Infrared Analyzer," is identical to Method 25A
except that a different instrument is used. Method 25B applies to the
measurement of total gaseous organic concentration of vapor consisting
primarily of alkanes. The sample is extracted as described in Method
25A and is analyzed with a nondispersive infrared analyzer (NDIR).
In both the FIA and NDIR analysis approaches, instrument calibrations
are based on a single reference compound. For the proposed gasoline terminal
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standard, propane or butane is the recommended calibration compound. As
a result, the sample concentration measurements are on the basis of that
reference and are not necessarily true hydrocarbon concentrations.
Calculation of emissions on a mass basis will not be affected because
the response of the instruments is proportional to carbon content for
similar compounds, in this case gasoline vapors. Mass results would be
equivalent using either the concentration and molecular weight based on
a reference gas or the true concentration and true average molecular
weight of the hydrocarbons. The advantage of using a single component
calibration is that chromatographic techniques are not required to
isolate and quantify the individual compounds present.
The VOC analysis techniques discussed above measure total hydrocarbons
including methane and ethane. Chromatographic analyses during prior
field tests have indicated that significant quantities of methane and
ethane may sometimes be present in the vapors emitted. If it is expected
that methane or ethane is present in significant quantities, appropriate
samples are required for chromatographic analysis to adjust the results
to a nonmethane-nonethane basis.
b. Volume Measurements
Prior to this regulation, the only Reference Method for determining
volumetric flow in stacks was Method 2, which uses a pitot tube velocity
traverse procedure. However, Method 2 is usable only in large stacks (dia-
meter greater than 12 inches) with constant and continuous flow. This method
is not appropriate for gasoline terminal volume measurements because the flow
is intermittent and highly variable, and often the stacks are only 6 to 8
inches in diameter. Thus, during the support study for the terminal
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standard, two new methods were developed to measure exhaust volumes from
vapor processors.
Reference Method 2A or 2B is the recommended procedure for measurement
of total volume of the exit gases from a vapor processor outlet.
Method 2A, "Direct Measurement of Gas Volume Through Pipes and Small Ducts,"
applies to the measurement of gas flow rates in pipes and small ducts, either
in-line or at exhaust positions, within the temperature range of 0 to 50°C.
A totalizing gas volume meter is installed in the pipe duct, and a direct,
continual volume measurement is obtained. Temperature and pressure
measurements are made to correct the volume to standard conditions.
If a terminal's vapor processor is an incinerator, Reference Method 2B
is recommended to determine the exhaust volume. Method 2B, "Determination
of Exhaust Gas Volume Flow Rate from Gasoline Vapor Incinerators," is applicable
for the measurement of exhaust volume flow rate from incinerators that
process gasoline vapors consisting generally of nonmethane alkanes, alkehes,
and/or arenes (aromatic hydrocarbons). It is assumed that the amount of
auxiliary fuel is negligible. The procedure to determine the exhaust flow
is complex, requiring five separate continuous measurements. The inlet
VOC concentration and volume are measured using Methods 25A or 25B, and
Method 2A, respectively. At the outlet, the VOC concentration is obtained
(Method 25A or 25B) as well as the CO and C02 concentrations (Method
10). The exhaust volume is calculated from these five measured values
using a carbon atom material balance.
An alternate procedure to Method 2A would be the use of a flow rate
meter such as an orifice, venturi, or pitot tube device. The continuous
flow rate records could be integrated to determine a total volume displaced
or emitted during the measurement period. In addition to the complication
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caused by variable flow rates, the changes in gas composition must be
known to accurately calculate the metered gas density during each measurement
period. Directly measuring flow rate instead of total volume (as in
Method 2A) is not recommended. However, there are some cases where the
use of a total volume meter is not possible, and some form of rate meter
must be used. These cases occur when the processing unit vent size is
relatively large and pressure drop restrictions prevent reducing the vent
diameter to that of the volume meter.
c. Mass Emissions
The VOC concentration and volume measurements are combined to determine
the processor's mass emissions. To determine the total VOC mass emissions
during the entire test period, the VOC mass emitted is determined for small
incremental periods, each 5-minute interval and increment thereof when
the processor is operating, and each 15-minute interval and increment thereof
during non-operation. These incremental emissions are then summed for the
entire test period. Because VOC concentrations and flow rate may vary
significantly within a brief time period, these short incremental calculation
intervals are needed so that short-term variations in emission rates can
be noted.
d. Gasoline Throughput
The format of the proposed gasoline terminal regulation is mass
emitted per volume of gasoline loaded. The amount of gasoline dispensed
during the testing period is easily determined either from plant records
or by reading all of the gasoline pump meters at the beginning and end
of the test.
e. Test Period
The test period specification is based on a combination of field ex-
perience and minimum data requirements. Flexibility and variability for the
test period are necessary in order to account for the tremendous variability
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among terminals, ensuring a test of adequate length along with a minimum
number of tank loadings and processor operating cycles.
The recommended test period is 6 hours, during which at least 300,000
liters of gasoline are loaded into tank trucks. If a terminal's throughput
is less than 300,000 liters in 6 hours, then the testing must be extended
until 300,000 liters is dispensed. If a terminal closes down overnight
before the minimum throughput requirement is met, then testing must be
continued on the following day.
For terminals which have intermittent vapor processing systems (ones that
employ vapor holders), the test period must also include at least two full
operating cycles of the processing unit.
Most of the emission test data was collected following the test
o
procedure in a draft version of EPA's Control Techniques Guideline document .
The recommended normal test period for these tests was three 8-hour repetitions.
The intent of the testing was to obtain not only outlet emission data, but
also inlet mass flow rates, processor control efficiency, overall terminal
collection and control efficiency, and tank truck leakage emissions. The
representativeness of these results could be affected by uncontrollable
variation in the amount of tank leakage, previous cargo carried, whether
balancing was done during unloading, and weather conditions. A longer
3-day averaging test time was needed to reduce the impact of these variations,
as well as the normal day-to-day variations in loading frequency and
terminal operation. Because the proposed standard for terminals only
regulates outlet emissions, and because outlet emissions are not affected
greatly by the above-mentioned variations, a shorter test period of 6
hours is sufficient.
Review of the emission test data used to support this standard indicates
that the test time period for each day of testing ranged from 3 to 10
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hours. (One terminal, however, had to be tested for 20 hours per day for 3 days,
because the vapors were stored in a large vapor holder in a storage tank
and the processor rarely operated). The specified 8-hour test length was
often shortened due to testing instrument problems, vapor processor
breakdowns, inclement weather, or minimal throughput during terminal
off-hours. Based on this data base, a 6-hour testing period was selected.
f. Terminal Status During Test Period
The recommended test procedure is designed to measure control system
performance under conditions of normal operation. Normal operation will
vary from terminal to terminal and day to day. Because of the large
differences in terminal operations, no specific criteria can be set forth
to define normal operation. Enforcement and terminal personnel must
determine representative normal testing conditions on a case-by-case
basis. The following guidelines are recommended to assist in this.
1. Testing should be conducted during the 6-hour period during which
the highest throughput normally occurs.
2. Switch loading should be minimized as much as possible.
3. All loading racks which are controlled by the system under test
should be open. Simultaneous use of more than one loading rack
should occur to the extent that such use would normally occur.
4. Simultaneous use of more than one dispenser on each loading rack
should occur to the extent that such use would normally occur.
5. Dispensing rates should be set at the normal rate at which the
equipment is designed to be operated. Automatic product
dispensers are to be used according to normal operating practices.
6. Tank'truck leakage should be minimized as much as possible.
7» Backpressure in the vapor collection system should never exceed the
pressure test criteria for tank trucks, in this case 18 inches of water.
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g. Cost
Conducting a performance test using these procedures would cost a facility
between $5,000 and $10,000, depending on the type of vapor processing unit.
D.3.2. Emission Testing and Measurement Methods
During the support study for the proposed terminal standard, EPA conducted
22 emission tests. These tests occurred over a 5-year period (November 1973 to
October 1978). During this time period, the test procedure was changed and
refined as more experience and knowledge were obtained. Most of the testing
o
closely followed a test procedure in a draft version of EPA's Control Techniques
Guideline document. This draft test procedure recommended three 8-hour test runs
and included extra measurements and calculations to determine many other results
besides simply outlet mass emission. Thus, the emission testing procedures
used in the background study were more comprehensive than the recommended test
procedure for the proposed regulation.
The recommended test procedure for the proposed regulation determines out-
let mass emissions over a 6-hour period using Reference Methods 2A, 2B, 25A, and
25B. This is essentially the same as the emission testing procedures used in
the support study to determine outlet mass emissions. Thus, the data base is
applicable for support of the terminal regulation.
Because of the tremendous variability among terminals, and because the
testing was conducted over a 5-year period as the test procedures were being
developed, there are some differences in the test procedures and in the terminal
conditions during the 22 tests. Each test is discussed in Appendix C of this
document, giving reasons for rejecting some of the test results.
D.3.3 Monitoring Systems and Devices
Continuous monitoring of the performance of a vapor control system can
be accomplished by either an emission measurement or process parameter
measurement approach.
D-18
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There are presently no demonstrated continuous monitoring systems
commercially available which monitor vapor processor exhaust VOC emissions
in the units of the standard (mg/liter). This monitoring would require
measuring not only VOC exhaust concentration, but also exhaust gas volume,
volume of product dispensed, temperature, and pressure. An overall cost
for a complete monitoring system is difficult to estimate due to the
number of component combinations possible. The purchase and installation
cost of an entire monitoring system (including VOC concentration monitor,
volume meters, recording devices, and automatic data reduction) is estimated
to be $25,000. Operating costs are estimated at $25,000 per year.
Monitoring equipment is commercially available to monitor the
operational or process variables associated with vapor control system
operation. Monitoring of operations indicates whether the vapor processing
system is being properly operated and maintained, and whether the processor
is continuously reducing VOC emissions to an acceptable level. The
variable which would yield the best indication of system operation is
VOC concentration at the processor outlet. Extremely accurate measurements
would not be required because the purpose of the monitoring is not to determine
the exact outlet emissions but rather to indicate operational and maintenance
practices regarding the vapor processor. Thus the accuracy of FIA and NDIR
type instruments is not needed, and less accurate, less costly instruments
which use different detection principles are acceptable. Monitors for
this type of continuous VOC measurement typically cost about $6,000 to pur-
chase and install, and $6,000 annually to calibrate, operate, maintain,
and reduce the data. To achieve representative VOC concentration measurements
at the processor outlet, the concentration monitoring device should be
installed in the exhaust vent at least two equivalent stack diameters from the
exit point, and protected from any interferences due to wind, weather, or other
processes.
D-19
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For some vapor processing systems, monitoring of a process parameter
may yield as accurate an indication of system operation as the exhaust
VOC concentration. For example, temperature monitoring in the case of
thermal oxidation or refrigeration systems may indicate proper operation
and maintenance of these systems. Parameter monitoring equipment would
typically cost about $3,000 plus $3,000 annually to operate, maintain,
periodically calibrate, and reduce the data into the desired format.
Because control system design is constantly changing and being upgraded
in this industry, all acceptable process parameters for all systems
cannot be specified. Substituting the monitoring of vapor processing
system process parameters for the monitoring of exhaust VOC concentration
is valid if it can be demonstrated that the value of the process parameter
is indicative of proper operation of the processing system and is related
to the exhaust VOC content. Monitoring of any such parameters would
have to be approved by enforcement officials on a case-by-case basis.
If the VOC outlet concentration is monitored or if an operational
parameter is monitored, then continual surveillance is achieved by comparing
the monitored value of the concentration or parameter to the value which
occurred during the last successful performance test.
The performance test period for gasoline terminals is at least 6 hours.
During the performance test, the average VOC outiet ^onuentration or the
average value of the selected operational parameter should be determined.
Excess emissions (for monitoring purposes) are then defined as any 6-hour
period during which the value of the monitored concentration or parameter
exceeds the average value measured during the 6-hour performance test.
D-20
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EPA does not currently have any experience with continuous monitoring
of VOC exhaust concentration or operational parameters of vapor processing
units. Therefore, performance specifications for the sensing instruments
cannot be recommended at this time. Examples of such specifications tnat
were developed for sulfur dioxide and nitrogen oxides instrument systems can
be found in Appendix B of 40 CFR Part 60 (Federal Register September 11, 1974),
D-21
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D.4 REFERENCES
1. Norton, Robert L. Evaluation of Vapor Leaks and Development
of Monitoring Procedures for Gasoline Tank Trucks and Vapor
Piping. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. Publication No. EPA-450/3-79-018. April 1979.
2. Norton, R.L., and N. Mclaughlin. Monitoring Procedures for
Fugitive Hydrocarbon Emissions from Gasoline Tank Truck Loading.
Presented at 73rd Annual Meeting of the Air Pollution Control
Association, Montreal, Quebec. June 22-27, 1980.
3. Shedd, S., and N. Mclaughlin. Control of Volatile Organic
Compound Leaks from Gasoline Tank Trucks and Vapor Collection
Systems. U.S. Environmental Protection Agency. Research
Triangle Park, N.C. OAQPS Guideline Series. Publication No.
EPA-450/2-78-051. December 1978.
4. VOC Fugitive Emissions in Synthetic Organic Chemical Manufacturing
Industry, Background Information for Proposed Standards. U.S.
Environmental Protection Agency. Research Triangle Park, N.C.
March 1980. Draft.
5. Benzene Fugitive Emissions, Background Information for Proposed
Standards. U.S. Environmental-Protection Agency. Research
Triangle Park, N.C. March 1980. Draft.
6. Hustvedt, K.D., R.A. Quaney, and W.E. Kelly. Control of Volatile
Organic Compound Leaks from Petroleum Refinery Equipment. U.S.
Environmental Protection Agency. Research Triangle Park, N.C.
OAQPS Guideline Series. Publication No. EPA-450/2-78-036.
June 1978.
7. Polglase, W., W. Kelly, and J. Pratapas. Control of Hydrocarbons
from Tank Truck Gasoline Loading Terminals. U.S. Environmental
Protection Agency. Research Triangle Park', N.C. OAQPS Guide-
line Series. Publication No. EPA-450/2-77-026. October 1977.
8. Draft version of Reference 7. May 15, 1977.
D-22
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO. IT
EPA-450/3-80-038a_ _ J_
4. TITLE AND SUBTITLE
Bulk Gasoline Terminals - Background Information
for Proposed Standards
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
December 1980
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND. ADDRESS „ , .
Office of Air Quality Planning ana Standards
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3,060
12. SPONSORING AGENCY NAME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Interim Final
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
proposed under the authority of Section 111 of the Clean Air Act. This document
contains background information and enviromental and economic assessments of the
regulatory alternatives considered in developing the proposed standards.
17.
a.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Pollution Control
Standards of Performance
Bulk Gasoline Terminals
VOC
Air Pollution Control
13b
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
321
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
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