unnea states unice ot Air uuainy tKA-^ag/a-sz-uuia
Environmental Protection Planning and Standards May 1992
Agency Research Triangle Park NC 27711
SEPA VOC/HAP DRAFT
Emissions from E'S
Marine Vessel
Loading Operations
Technical Support
Document for
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EPA-450/3-92-00la
TECHNICAL SUPPORT DOCUMENT
FOR THE DEVELOPMENT OF A VOC RULE
FOR MARINE VESSEL LOADING OPERATIONS
EMISSION STANDARDS DIVISION
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Draft
Environmental Impact Statement
for Tank Vessel Loading Operations
ission
Prepared by:
ijiohj
(Date)
ission Standards Division
U. S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
1. The proposed standards would significantly reduce emissions
from marine tank vessel loading operations. Under Section
183(f) of the Clean Air Act Amendments, EPA is obligated to
promulgate standards applicable to VOC's and any other air
pollutant which causes, or contributes to, or may be
reasonably 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
from the date of publication of the proposed standard in the
Federal Register! Mr. David Markwordt may be contacted at
(919) 541-0837 regarding the date of the comment period.
4. For additional information contact:
Mr. David Markwordt
Chemicals and Petroleum Branch
U. S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
Telephone: (919) 541-0837
5. Copies of this document may be obtained from:
U. S. EPA Library (MD-35)
Research Triangle Park, N.C. 27711
National Technical Information Service
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DISCLAIMER
This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication. Mention of trade names or commercial
products is not intended to constitute endorsement or
recommendation for use. Copies of this report are available
through the Library Services Office (MD-35), U.S. Environmental
Protection Agency, Research Triangle Park, NC 27711, or from
National Technical Information Services, 5285 Port Royal Road,
Springfield, Virginia 22161.
1
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TABLE OF CONTENTS
Page
LIST OF FIGURES viii
LIST OF TABLES ix
1.0 INDUSTRY DESCRIPTION 1-1
1.1 BACKGROUND 1-1
1.2 STATE REGULATIONS 1-2
1.3 WCUS DATA BASE 1-3
1.3.1 Commodity Categories 1-7
1.3.2 Terminals 1-7
1.4 REFERENCES 1-11
2.0 EMISSIONS AND EMISSIONS CONTROL 2-1
2.1 EMISSION SOURCES 2-1
2.2 CARGO LOADING EMISSIONS AND EMISSION FACTORS . . 2-3
2.2.1 Cargo Loading Emissions Factors 2-3
2.2.1.1 VOC Emission Factors 2-3
2.2.1.2 HAP Emission Factors 2-7
2.2.2 Cargo Loading Emissions 2-10
2.2.2.1 VOC Emissions 2-10
2.2.2.2 HAP Emissions 2-11
2.3 TANKSHIP BALLASTING 2-15
2.4 EMISSION CONTROLS 2-17
2.4.1 Closed Loading of Vessels 2-18
2.4.2 Combustion Processes 2-18
2.4.2.1 Flares 2-19
2.4.2:2 Incinerators 2-19
2.4.3 Recovery Devices 2-21
2.4.3.1 Lean Oil Adsorption 2-21
2.4.3.2 Refrigeration 2-22
2.4.3.3 Carbon Adsorption 2-23
2.5 CURRENT PRACTICES AND SAFETY PROCEDURES 2-24
2.6 REFERENCES 2-25
3.0 COSTS 3-1
3.1 DEVELOPMENT OF MODEL TERMINALS AND VESSELS ... 3-1
3.1.1 Background 3-1
3.1.2 New Models 3-2
3.2 MODEL VESSELS 3-3
3.3 MODEL TERMINAL COSTS 3-4
3.3.1 Capital Costs 3-4
3.3.1.1 Incineration 3-5
3.3.1.2 Recovery 3-7
3.3.2 Annual Costs 3-8
3.4 NATIONWIDE COSTS AND COST EFFECTIVENESS 3-10
3.5 REFERENCES 3-47
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TABLE OF CONTENTS (continued)
Page
4.0 REGULATORY ALTERNATIVES 4-1
4.1 INTRODUCTION 4-1
4.2 REGULATORY ALTERNATIVES 4-1
5.0 ECONOMIC IMPACT ANALYSIS 5-1
5.1 SUMMARY OF ECONOMIC IMPACT ANALYSIS 5-1
5.2 METHODOLOGY FOR ESTIMATING ECONOMIC IMPACTS . . 5-5
5.3 GROUNDRULE FOR ECONOMIC IMPACT OF THIS
REGULATION 5-7
5.4 POTENTIAL PRICE INCREASES 5-8
5.4.1 Crude Oil 5-8
5.4.2 Potential Price Increases for Marine
Transport of Crude 5-12
5.4.3 Potential Price Increases for Final
Products from Crude Oil 5-13
5.4.4 Potential Product Price Increases .... 5-16
5.4.5 Combined Potential Product Price
Increases 5-16
5.4.6 Potential Price Increases in the Costs
for Marine Transport of Products ... 5-19
5.5 MARKET IMPACTS 5-22
5.5.1 Marine Transport Versus Pipeline .... 5-22
5.5.2 Marine Terminals 5-24
5.5.2.1 Crude Oil Terminals Impact
Analysis 5-30
5.5.2.2 Product Terminal Impact
Analysis 5-32
5.5.3 Marine Vessels 5-36
5.5.3.1 Tanker Impacts 5-39
5.5.3.2 Barge Impacts 5-44
5.5.4 Producers of the Regulated Products ... 5-44
5.6 SMALL BUSINESS IMPACTS 5-51
5.7 EMPLOYMENT IMPACTS 5-52
5.8 CONCURRENT LEGISLATION AND REGULATIONS 5-54
5.8.1 Budget Reconciliation Act of 1989 .... 5-54
5.8.2 The Oil Pollution Act of 1990 5-55
5.8.3 Clean Air Act Amendments of 1990 .... 5-56
5.8.4 Benzene NESHAP Handling Regulations ... 5-56
5.9 FIFTH-YEAR PROJECTIONS 5-56
5.9.1 Crude Oil 5-57
5.9.2 Gasoline 5-57
5.9.3 Other Products 5-57
5.9.4 Fifth-Year Demand Conclusions -5-57
5.9.5 Fifth-Year Supply Conditions 5-58
5.9.6 New Terminals and Vessels 5-58
5.10 REFERENCES 5-58
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TABLE OF CONTENTS (continued)
Appendix A. Detailed Description of Model Vessels and Terminals
Appendix B. Documentation of Costs for an Incineration-Based
Technology
Appendix C. Carbon Adsorber Design Characteristics and Adsorber
Capital Costs
Appendix D. Documentation of Costs for Model 5A for a Carbon
Adsorption-Based Technology
Appendix E. Printout of Terminals Represented in Data Base
f
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LIST OF FIGURES
Paae
Figure 1-1. Pie chart of facilities and 1-6
Figure 2-1. Emissions from cargo loading 2-2
Figure 5-1. Petroleum products pipeline capacities .... 5-47
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LIST OF TABLES
Page
TABLE 1-1. COMPARISON OF STATE AND LOCAL REGULATIONS
GOVERNING MARINE LOADING 1-4
TABLE 1-2. COMMODITIES BY ANNUAL THROUGHPUT 1-8
TABLE 1-3. NUMBER OF TERMINALS BY THROUGHPUT 1-10
TABLE 2-1. VOC EMISSION FACTORS FOR CARGO LOADING .... 2-4
TABLE 2-2. HAP EMISSION FACTORS 2-8
TABLE 2-3. ANNUAL EMISSIONS BY COMMODITY (CONTROLLED
EMISSIONS EXCLUDED) 2-12
TABLE 2-4. ANNUAL EMISSIONS BY COMMODITY (CONTROLLED
EMISSIONS INCLUDED) 2-13
TABLE 2-5. HAP EMISSIONS ESTIMATES 2-14
TABLE 3-1. DESCRIPTION OF MODEL TERMINALS 3-13
TABLE 3-2. MODEL VESSELS 3-14
TABLE 3-3. MODEL VESSEL CAPITAL AND ANNUAL COSTS .... 3-15
TABLE 3-4. CAPITAL AND ANNUAL COSTS: MODEL 5A
(INCINERATION) 3-16
TABLE 3-5. CAPITAL AND ANNUAL COSTS: MODEL 5B
(INCINERATION) 3-18
TABLE 3-6. CAPITAL AND ANNUAL COSTS: MODEL 5C
(INCINERATION) 3-20
TABLE 3-7. CAPITAL AND ANNUAL COSTS: MODEL 6A
(INCINERATION) 3-22
TABLE 3-8. CAPITAL AND ANNUAL COSTS: MODEL 6B
(INCINERATION) 3-24
TABLE 3-9. CAPITAL AND ANNUAL COSTS: MODEL 6C
(INCINERATION) 3-26
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LIST OF TABLES (continued)
Page
TABLE 3-10. CAPITAL AND ANNUAL COSTS: MODEL 7A
(INCINERATION) 3-28
TABLE 3-11. CAPITAL AND ANNUAL COSTS: MODEL 7B
(INCINERATION) 3-30
TABLE 3-12. CAPITAL AND ANNUAL COSTS: MODEL 5A
(CARBON ADSORPTION) 3-32
TABLE 3-13. CAPITAL AND ANNUAL COSTS: MODEL 5B (CARBON
ADSORPTION) 3-34
TABLE 3-14. CAPITAL AND ANNUAL COSTS: MODEL 5C (CARBON
ADSORPTION) 3-36
TABLE 3-15. CAPITAL AND ANNUAL COSTS: MODEL 7A (CARBON
ADSORPTION) 3-38
TABLE 3-16. CAPITAL AND ANNUAL COSTS: MODEL 7B (CARBON
ADSORPTION) 3-40
TABLE 3-17. CAPITAL COSTS COMPARISON (MODEL TERMINAL 5A):
INCINERATION VS. CARBON ADSORPTION 3-42
TABLE 3-18. TOTAL ANNUALIZED VESSEL RETROFIT COSTS .... 3-43
TABLE 3-19. ANNUAL COSTS COMPARISON (MODEL TERMINAL 5A):
INCINERATION VS. CARBON ADSORPTION 3-44
TABLE 3-20. NATIONWIDE CAPITAL AND ANNUAL COSTS AND COST
EFFECTIVENESS 3-45
TABLE 3-21. NATIONWIDE ANNUAL COSTS TO CONTROL EMISSIONS . 3-46
TABLE 4-1. REGULATORY ALTERNATIVES VOC's (ALASKA
CONTROLLED) 4-4
TABLE 4-2. REGULATORY ALTERNATIVES VOC'S (ALASKA
UNCONTROLLED) 4-5
TABLE 4-3. REGULATORY ALTERNATIVES HAP'3 (ALASKA
CONTROLLED) 4-6
TABLE 4-4. REGULATORY ALTERNATIVES HAP's (ALASKA
UNCONTROLLED) 4-7
TABLE 4-5. SECONDARY AIR IMPACTS BY REGULATORY
ALTERNATIVE 4-8
«
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LIST OF TABLES (continued)
Page
TABLE 5-1. SUMMARY OF IMPACTS BY REGULATORY ALTERNATIVE . 5-2
TABLE 5-2. CONTROL COSTS AND PRICE INCREASE PER BARREL
CALCULATIONS FOR CRUDE OIL REGULATORY
ALTERNATIVES 5-9
TABLE '5-3. CONTROL COST PER BARREL CALCULATIONS FOR
CRUDE OIL MODEL FACILITIES AND REGULATORY
ALTERNATIVES 5-11
TABLE 5-4. POTENTIAL PERCENTAGE PRICE INCREASES IN
MARINE TRANSPORT FOR CRUDE OIL 5-14
TABLE 5-5. POTENTIAL PRICE INCREASES FOR PRODUCTS .
PRODUCED FROM CRUDE OIL 5-15
TABLE 5-6. POTENTIAL PRODUCT PRICE INCREASES FOR THE
VARIOUS REGULATORY ALTERNATIVES 5-17
TABLE 5-7. POTENTIAL PRICE INCREASES FOR PRODUCTS .... 5-18
TABLE 5-8. COMBINED POTENTIAL PRICE INCREASES FOR
SELECTED PRODUCTS 5-20
TABLE 5-9. POTENTIAL PRICE INCREASES FOR MARINE
TRANSPORT OF PRODUCTS 5-21
TABLE 5-10. 1988 COUNTY BUSINESS PATTERNS BY STATE FOR
SIC 4491 5-28
TABLE 5-11. SMALL ENTITY ANALYSIS 5-30
TABLE 5-12. FINANCIAL ANALYSES OF SMALL PRODUCT TERMINALS 5-34
TABLE 5-13. PERCENTAGE OF TOTAL MARINE TRANSPORT OF
PETROLEUM PRODUCTS AND CRUDE OIL AFFECTED BY
THE REGULATORY ALTERNATIVES 5-40
TABLE 5-14. TANK SHIP FLEET BY AGE 5-43
TABLE 5-15. U.S. BARGE FLEET BY AGE, 1989 5-45
TABLE 5-16. PORTIONS OF TOTAL MARKETS AFFECTED BY
REGULATORY ALTERNATIVE A 5-49
TABLE 5-17 POTENTIAL CHANGE IN EMPLOYMENT IN THE
PETROLEUM REFINING INDUSTRY 5-53
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1.0 INDUSTRY DESCRIPTION
1.1 BACKGROUND
When tankships and barges are loaded with volatile liquids,
volatile organic compound (VOC) vapors are expelled from the
cargo tanks and, if uncontrolled, emitted to the atmosphere.
These vapors, primarily hydrocarbons, form ozone in the presence
of sunlight; ozone contributes to smog, which exacerbates
respiratory problems in the general populace. In addition,
hazardous air pollutants (HAP's) may comprise some or all of the
VOC's emitted during marine vessel loading operations. Several
State and local governments have enacted regulations to control
VOC emissions from the loading of tankships and barges. The
earliest compliance date associated with these regulations is in
1991. The primary purpose of these State and local regulations
is to help these areas reduce ambient air concentrations of ozone
under the National Ambient Air Quality Standards administered by
the Environmental Protection Agency (EPA) and limit human
exposure to HAP's.
Benzene emissions from marine vessel loading are also
controlled, primarily to reduce occupational exposure to benzene
vapors. A national emission standard for benzene emissions
promulgated in 1990 (the benzene NESHAP) requires facilities
loading more than 1.3 million liters per year (1/yr)
(8,200 barrels per year [bbl/yr]) of at least 70 percent by
weight benzene to control emissions.1 Terminals subject to this
regulation are required to reduce benzene emissions by
98 percent.
The addition of improperly designed vapor-handling systems
could present a safety hazard to marine vessel loading operations «
-------
by increasing the operational complexity of loading operations
and in particular by requiring additional handling of potentially
explosive vapors. Unsafe design or operation of vapor control
systems could result in fires and explosions, tank ruptures, and
spills.2 However, a well-designed control system can advance
safety by properly handling vapors throughout the loading
process. Therefore, the Coast Guard, which is responsible for
the safety of waterborne commerce, requested in 1986 that the
National Research Council (NRC) conduct a study to assess the
technical, safety, and economic aspects of controlling
hydrocarbon emissions from marine vessel loading operations.
Participants in the NRC study included the Coast Guard, EPA, the
Maritime Administration, the States of Texas, Louisiana, and
New Jersey, the Bay Area Air Quality Management District
(BAAQMD), and industry representatives. The result of this study
is the document Controlling Hydrocarbon Emissions From Tank
Vessel Loading (referred to elsewhere in this report as "the
Marine Board document"). Much of the information contained in
this report was. taken from the Marine Board document.3
The committee concluded in January 1987 that controls were
technically feasible but that there was a need for the Coast
Guard to promulgate safety requirements and a need for EPA to set
uniform emission standards to mitigate some of the safety issues
that could arise from varied State regulations and eliminate the
possibility of State regulations disrupting interstate commerce.3
The Coast Guard has subsequently adopted new regulations for the
safe design, installation, and operation of marine vapor control
systems.2 These regulations became effective on July 23, 1990.
The Clean Air Act Amendments (CAAA) of 1990 require EPA to
promulgate a national tank vessel loading rule by the fall of
1992.
1.2 STATS REGULATIONS
The States of Louisiana, Pennsylvania, and New Jersey and
authorities in the San Francisco Bay Area and South Coast Air
Basin have enacted regulations to control VOC emissions from
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marine vessel loading operations. The State of Alaska has
proposed a similar regulation.4,5 Table 1-1 provides a
comparison of the State and local regulations governing marine
vessel loading.4 The regulations presented in Table 1-1 have
different requirements with respect to the types of terminals
affected, the required emission reductions, the affected
hydrocarbons (VOC's), and compliance dates. The most stringent
regulation is the BAAQMD's Rule 44, which affects all terminals
regardless of throughput or types of commodities loaded. Because
of the differing requirements, tank vessels compatible with an
emission control system accepted in one area might not be
compatible with the regulations or equipment in another.4
Therefore, EPA is developing a rule for marine vessel loading
operations to promote nationwide installation of comparable
emission control systems on vessels and at marine terminals.
1.3 WCUS DATA BASE
A primary source of information for developing VOC emissions
estimates for marine vessel loading operations is the Army Corps
of Engineers' Waterborne Commerce of the United States (WCUS)
data base. The WCUS data base contains .detailed information on
the types and quantities of commodities loaded and unloaded at
U.S. ports, harbors, waterways, and canals. The portion of the
1988 WCUS data base containing information about commodities
loaded in bulk that emit VOC's and/or HAP's was extracted and is
referred to elsewhere in this report as "the data base."
In its original form, the data base contained information
about 1,800 terminals loading commodities in 13 different
categories. Of the 1,800, 133 terminals had throughputs of
1,000 bbl/yr or less. These 133 terminals were removed from the
data base because loadings at a terminal that constitute the
1,000 bbl/yr or less do not represent bulk loadings (i.e., the
liquids are likely carried in containers). Of the remaining
1,667 terminals, 119 are affected by promulgated State
regulations (CA, NJ, LA, PA). There are two locally regulated
areas in California, the San Francisco Bay area, and the South
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TABLE 1-1. COMPARISON OF STATE AND LOCAL REGULATIONS GOVERNING MARINE LOADING3
San FraiK.ij.co Bay Atea
South Coast Air Basin (California)
1 sOtiiMana
RcgllUttoil iUllHC
Rule 44
Rule 1142
Rule 2108
(ioveiiiing hotly
Bay Aien Air Quality Management District
(BAAQMD)
South Coast Air Basi
Louisiana Department of Environmental
Quality (LA DEQ)
G«Miline eniiH^iunit
5 7 mg/L or 95% reduction
95% reduction
70 mg/L for barges
30 mg/L for ships
Cnule oil emissions
5.7 tng/L or 95% reduction
95% reduction
30 mg/L for barges
12 tng/L for ships
Oilier VOC* emissions'1
5.7 mg'L or 95% reduction
95% reduction
30 mg/L for barges
12 mg/L for ships
Affected facilities
All terminals
All terminals that have a loding event greater
than 1.000 bbl
All with uncoiUrolled emissions > 100 tons/yr
Compliaiice dates
July 1, 1991, for all facilities that loaded more
than 1 million bbl/yr in any calendar year after
1985
December 3|, 1991, for gasoline and other
VOC
May E, 1992, for crude oil
Specinl mites
Small terminal is one loading less than 1
milium bbl/yr
Loading events include loading and unloading,
ballasting no nontegregated ballast tanks, and
housekeeping operations
90% reduction in emissions is allowable
instead of mg/L limits
Allows the use of open flares if they are
designed and operated per EPA guidelines
Regulation name
NJAC-7-27 16.3
18 AAC 50, 105, 500, and 900 (proposed
regulation)
29 PA, CODE CHS, 121, 129 and 139
Governing Intdy
New Jersey Department of Environmental
Protection (NJ DEP)
Alaska Department of Environmental
Conservation (AK DFC)
Environmental Quality Board (EQB)
(involute omissions
9555 reduction
95% reduction or 2 lb/1,000 bbl
90% reduction
Crude oil emissions
Exempt
95% reduction oi 2 lli/J ,000 Ithl
Exempt
Other VOC emissions
Exempt
95% reduction or 2 lb/1.000 bbl
Exempt
Affected facilities
All loading im>re than 6 million gal/yr of
gasoline
All terminals with thioughputs greater than S
million bbl/yr or with uncontrolled VOC
emissions greater than or equal to 250 ton*
All terminals
Compliance dales
June 2), 1991
June 1992
September, 1996
¦Special notes
Any facility that loads 60,000 gal/d between
May 1 and September 15 i& affected
Facilities emitting 250 tons (or greater) of
VOC's per year are considered "major"
facilities
Alaska's proposed regulation was patterned
after the rules developed by the BAAQMD
The proposed amendments require control of
ballasting emissions
"SOURCE. Cheinjcal Engineering, May 1990
'in Shu Hmiicisco, VOC's include gasoline blending stocks and aviation fuel; m Louimhiiu, (hey include any VOC thai boosts a terminal to 100 tons/yr and has a (rue vapor pressure greater
limn I 5 psia (e.g.. JP-4 (jet fuel). aviation gas, gasoline blending slocks). at (he loading temperature; in (he Smith Coast Air Basin. an emissions limit of 2.0 Ih per 1,000 bbl loaded is in
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Becaifse terminals in the data base are identified only by
State, the exact locations of terminals in California are not
known. Therefore, terminals in California cannot be separated or
further distinguished. Consequently, all terminals in California
are assumed to be controlled under promulgated regulations and a
composite of the two local regulations was applied.
State regulations tend to target (regulate) the more
volatile compounds. Therefore, part of the total throughput at a
terminal subject to State regulations may remain uncontrolled.
For example, terminals in New Jersey that load both gasoline and
jet fuel are only required to control the vapors from gasoline;
they are not required to control vapors associated with the
loading of jet fuel. In this example, the throughput of jet fuel
represents the terminal's "residual" or remaining uncontrolled
throughput. Approximately 100 of the 119 terminals affected by
State or local regulations have residual throughputs. To
determine the true impact of a Federal rule to control VOC and
HAP emissions from marine vessel loading operations, the
throughputs and emissions already controlled under state
regulations were removed from the data base. Uncontrolled or
"residual" emissions are considered in the data base. Costs to
control these emissions were developed based on the worst-case
assumption that the residual emissions constituted a separate
facility.
Three terminals in Alaska would be affected by the proposed
State regulation. It is possible that a national rule could take
effect before this proposed regulation were promulgated.
Therefore, the 3 terminals affected by proposed State
regulations, the 100 facilities subject to promulgated State
regulations with "residual" emissions, and the remaining
1,545 terminals now form the "current" data base. Only those
emissions that are already controlled under existing regulations
were removed from the data base. Figure 1-1 depicts how the
original WCUS data base of 1,800 terminals was pared down to the
current data base of 1,648 terminals.
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The current data base includes information on 1,648 U.S.
terminals that load liquids in at least one of 13 VOC-emitting
commodity categories. The amount of each liquid loaded into
tankships and barges is provided for each terminal; the total
annual throughput for a terminal is equal to the sum of the
tankship and barge loadings of each liquid loaded at that
terminal. Table 1-2 presents a summary of the commodity
categories, the number of terminals that load liquids in each
commodity category, and the national annual throughput of liquids
in each commodity category.
1.3.1 Commodity Categories
The following 13 commodity categories were identified that
contain liquids that emit VOC's and/or HAP's: gasoline, crude
oil, jet fuel, naphtha/solvents, alcohols, toluene, distillate
fuel, basic chemicals, miscellaneous chemicals, petroleum and
coal products, crude products, gum and wood chemicals, and
kerosene. Several of the commodity categories represent a wide
range of liquids. For example, the basic chemicals category
includes over 303 different liquids. The alcohols category
includes 16 different alcohols and alcohol mixtures. The gum and
wood category represents 12 chemicals (e.g., gum and wood rosins,
tall oil, turpentine, etc.). Because the quantity of the
individual liquids loaded within a given commodity category was
not known, assumptions were made in order to estimate emissions
associated with those categories. Therefore, some uncertainty is
associated with the VOC and HAP emissions estimates presented in
Chapter 2 for those commodity categories that cover a range of
possible compounds.
1.3.2 Terminals
There are 1,648 U.S. terminals where liquids in at least one
of the 13 VOC and HAP-emitting commodity categories are loaded.
The majority of these commodity categories refer to petroleum
products. As shown in Table 1-2, 354 terminals (21 percent) in
the data base load crude oil, and 469 terminals (28 percent) load
gasoline; 76 terminals load both crude oil and gasoline. The
remaining 901 terminals load neither crude oil nor gasoline but
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TABLE 1-2. COMMODITIES BY ANNUAL THROUGHPUT3
Commodity
Commodity
No b
No. of
terminals
loading
Throughput, 1,000 bbl/yr
Throughput, 1,000 gal/yr
Tankships
Barges
Total national
Tankships
Barges
Total national
Gasoline
2911
493
106,000
281.000
387,000
4,463.000
11,811.000
16.274.000
Crude oil
1311
354
1,138,000
247,000
1,385.000
47,763,000
10,388,000
58.I5I.00CP
Jet fuel
2912
IK6
28,900
62,000
91,000
1,213,000
2,589,000
3,802,000
Naphtha, solvents
2917
203
13,700
59,500
73,200
576.000
2,497,000
3,073,000
Alcohols
2813
212
10,600
36,700
47,300
447,000
1,540,000
1,987.000
Toluene
2817
169
2,760
14,300
17,000
112,000
600,000
712.000
Distillate fuel
2914
694
169,000
346,000
515,000
7,083,000
14,532,000
21,615,000
Chemicals''
578
127,000
159,000
287,000
5,353,000
6,686,000
12,309,000
Others*
378
10,000
49,800
59,800
419.000
2.092.000
2,511.000
Kerosene
2913
116
3,830
9,710
13,500
161.000
408,000
569,000
TOTAL
1,609,000
1,265,000
2.875,000
67,590,000
53,143,000
120,733,000
'Numbers have been rounded.
^Commodity number as assigned by the Army Corps of Engineers' Water Resources Support Center.
cAppmximately 47 percent of the total nationwide throughput of crude oil is attributed to one terminal (Alycska's Valdcz, Alaska, terminal),
''includes basic and miscellaneous chemicals.
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do load liquids in at least one of the other 11 categories.
Because many terminals load liquids in more than one category,
the numbers in the "number of terminals loading" column in
Table 1-2 do not total to 1,648.
The annual quantity of VOC-emitting liquids loaded at each
of the 1,648 terminals varies widely. Table 1-3 shows the
distribution of terminals by throughput. The lowest throughput
of any remaining terminal is 1,006 barrels per year (bbl/yr); the
highest throughput is at a crude oil terminal that loads over
657 million bbl/yr. The total nationwide quantity of
VOC-emitting compounds loaded at U.S. terminals in 1988 was
2.7 billion bbl/yr.
As seen in Table 1-3, the majority of terminals have
throughputs less than l million bbl/yr; approximately 44 percent
of those terminals load gasoline and/or crude oil. Only
300 terminals (18 percent) load more than 1 million bbl/yr, and
the majority (83 percent) of these terminals load gasoline and/or
crude oil. (The annual throughput associated with each terminal
in the data base is provided in Appendix E).
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TABLE 1-3. NUMBER 6f TERMINALS BY THROUGHPUT
Throughput (TP), bbl/yra
No. of terminals
Allb
Gas and crudec
1,000 50,000,000
6
6
TOTAL
1, 648
747
aBarrels per year.
^Includes all terminals in the current base.
cIncludes only those terminals in the data base that load
gasoline and/or crude oil.
-------
1.4 REFERENCES FOR CHAPTER 1
1. Environmental Protection Agency. National Emissions
Standard for Hazardous Air Pollutants; Benzene Emissions
From Chemical Manufacturing Process Vents, Industrial
Solvent Use, Benzene Waste Operations, Benzene Transfer
Operations, and Gasoline Marketing System; Final Rule. Code
of Federal Regulations. 40 CFR Part 61. Washington, D.C.
Office of Federal Register. March 7, 1990.
2. Department of Transportation. U.S. Coast Guard. Marine
Vapor Control Systems; Final Rule. Title 33. Code of
Federal Regulations. Part 154 et al. Washington, DC.
Office of Federal Register. June 21, 1990.
3. Controlling Hydrocarbon Emissions From Tank Vessel Loading.
Marine Board, National Research Council, pp. 1-22. 1987.
4. Hill, J. Controlling Emissions From Marine Loading
Operations. Chemical Engineering. pp. 133-143. May 1990.
5. Proposal to Regulate Emissions of Volatile Organic Compounds
From Loading Crude Oil Tankers. Alaska Department of
Environmental Conservation. Division of Environmental
Quality. Juneau, Alaska. May 30, 1990.
-------
2.0 EMISSIONS AND EMISSION CONTROL
This chapter discusses the estimated volatile organic
compound {VOC) and hazardous air pollutant (HAP) emissions
associated with marine vessel loading operations and the types of
control systems available for reducing these emissions.
Section 2.1 describes emission sources associated with marine
vessel loading. Section 2.2 shows the emission factors used to
estimate cargo loading emissions and describes how nationwide
emissions were estimated. Emissions from ballasting are outlined
in Section 2.3. The different types of emission control
technology available for use during loading at marine terminals
are presented in Section 2.4. Current practices at marine
terminals and potential safety problems are discussed in
Section 2.5.
2.1 EMISSION SOURCES
The following two sources of emissions were considered in
estimating nationwide VOC and HAP emissions from marine vessel
loading operations: (l) emissions discharged during cargo
loading and (2) emissions that occur as a result of tankship
ballasting. Emissions from cargo loading represent the majority
of emissions from marine vessel tanks; ballasting emissions make
up only a small percentage of the total emissions.
Figure 2-1 shows how vapors are emitted during cargo
loading. When liquid cargo is loaded into a tank, some of the
cargo vaporizes; these vapors are then displaced by the incoming
liquid and forced out of the vents as the tank is filled. Cargo
loading emissions may be divided into two categories: arrival
and generated emissions. Arrival emissions are attributed to any
vapors remaining in the otherwise empty cargo tanks prior to
-------
VENT HEADER
1^1
CARGO LOADING HEADER
VAPORS
VAPORS
CARGO OIL
CARGO OIL
-------
loading. Generated emissions refer to the evaporation of cargo
as it is loaded.
Emissions from tankship ballasting also occur as a result of
vapor displacement. After unloading its cargo, a tankship may
travel without cargo; to maintain stability, the tankship pumps
water into some of the empty cargo tanks as ballast. Ballasting
emissions occur as the ballast water enters the cargo tanks and
displaces vapors remaining in the tank from the previous cargo.
These vapors are forced through the tank vents and emitted to the
atmosphere.
Most tankships have segregated ballast tanks (i.e., separate
from the cargo tanks) and, therefore, do not emit vapors during
ballasting.1 New tankships are required to have segregated
ballast tanks. Ballasting emissions will further decline as
older vessals are retired and replaced with new ones.
2.2 CARGO LOADING: EMISSION FACTORS AND EMISSIONS
The estimated emission factors and emissions associated with
cargo loading and tankship ballasting are discussed below.
2.2.1 Cargo Loading Emission Factors
2.2.1.1 VOC Emission Factors. A national estimate cf
annual VOC emissions from cargo loading was developed using the
annual throughputs of each commodity provided in the Waterborne
Commerce of the United States (WCUS) data base and both
theoretically and empirically derived emission factors. Emission
factors from the EPA document "Compilation of Air Pollutant
Emission Factors" (AP-42) were used where possible.^ For several
commodities not listed in AP-42, emission factors available in
Scott Environmental Technology's Inventory of Emissions From
Marine Operations Within the California Coastal Waters were
used.3 These emission factors are based on data from actual
emission tests. Emission factors for petroleum and coal products
ana for crude products were taken from Controlling Hydrocarbon
Emissions From Tank Vessel Loading by the Marine Board of the
National Research Council.1 Table 2-1 lists the emission factors
and their sources for each commodity category.
-------
TABLE 2-1. VOC EMISSIONS FACTORS FOR CARGO LOADING
Commodity category
Commodity, No.(s)
Emission factors (
Tankships,
lb/1,000 gal
Barges, I
lb/1,000 gal
Gasoline
2911
1.802
3 -402
Crude oil
1311
0.612
1. OO2
Crude oil
1311
3.la'1
NA
Jet fuel
2912
0.504
1 .202
Naphtha, solvents
2917
0 .402
1
1
o
OD
©
! tr
i
Alcohols
2813
0.503
1.20°
Toluene
2817
0 .40c
0 . 80b
Distillate fuel
2914
0.0052
0.0053
Chemicalsd
2819, 2891
0.0053
0.0053
Others
2911, 2811, 2861
0.0051
0.0051
| Kerosene
2913
0.0052
0.0132
Note: Numbers by emission factors refer to references in the text.
f*This emission factor ia used solely for the terminal at Valdez, Alaska.
"Barge emission factor = twice the corresponding tankship emission factor.
^Estimated (see Section 2.2.1).
"Includes basic chemicals (Commodity No. 2819) and miscellaneous chemicals (Commodity
No. 2891) .
eIncludes petroleum and coal products, crude products, and gum and wood chemicals
-------
There are two sets of emission factors for crude oil. The
higher emission factors apply solely to the terminal at Valdez,
Alaska. Data provided by the State of Alaska and the terminal
operating company (Alyeska) indicated that emissions associated
with loadings at this facility were approximately four and a half
times higher than originally estimated using emission factors
from AP-42.2,4 Crude oil at the Valdez terminal is loaded at a
temperature near 38°C (100°F). It is thought that the
temperature differential between the hot crude oil and the cool
vessel causes convective cells to form inside the tank. These
convective cells provide constant activity in the atmosphere
inside the tank and may prevent a vapor blanket from forming on
the liquid surface, thus increasing emissions. Because of the
unique physical characteristics associated with crude oil loading
at the Valdez terminal and to avoid a gross underestimation of
emissions, the emissions for the Valdez terminal were estimated
using the actual test data taken at the facility.4
For a few commodities, emission factors were available for
tankship loading but not for barge loading. For those
commodities having both emission factors available, the emission
factors for barge loading are approximately twice the emission
factors for tankship loading. Therefore, for those commodities
where only tankship emission factors were available, the emission
factors for barges were estimated by doubling the emission
factors given for tankships. (The difference in emission factors
between tankships and barges is due to differences in tank
configuration. Tankship tanks are deeper and have less relative
surface area per volume loaded than barges; consequently, a
smaller percentage cargo evaporates.)1
Emission factors were estimated for those commodities that
did not already have emission factors. Emission factors were not
available for toluene and the alcohols category. The emission
factors for toluene were estimated using the following loading
loss equation provided in AP-42:^
-------
Loading loss equation:
r n AC SPM , eff.
L = 12-46 ~t~ (1 " Too*'
where:
S = saturation factor;
P - true vapor pressure, psia;
M » molecular weight;
T = temperature (°R); and
eff = control efficiency, percent.
The equation above was used to compare the loading losses
calculated for toluene with the loading losses calculated for a
commodity for which emission factors were available (i.e.,
benzene). If the variables S, T, and eff are assumed to be the
same for both toluene and benzene, then the loading losses for
these two commodities can be compared using values for molecular
weight (M) and vapor pressure (P) as follows:
P_J4_
R. p^ = 0.29.
where:
R - ratio of toluene loading losses to benzene loading
losses;
PT = vapor pressure of toluene at 60°F = 0.3 psia;
PB = vapor pressure of benzene at 60°F = 1.2 psia;
Hp = molecular weight of toluene = 92; and
Mg « molecular weight of benzene = 78.
Based on the ratio above, the emission factors for toluene were
estimated to be about one quarter to one third those for benzene.
(An emission factor for loading benzene into tankships equal to
1.5 pounds [lb] emitted per 1,000 gallons [gal] loaded was
provided in the Scott document.3 However, emissions from benzene
loading are not included in the nationwide emissions estimate
because they will be covered under a national emission standard
for hazardous air pollutants [NESHAP] that will go into effect on
March 7, 1992 .)
Emission factors for alcohols were obtained by comparing the
vapor pressure of methanol with the vapor pressures of other
-------
commodities for which emission factors were available. The
alcohols category includes 16 different alcohols and alcohol
mixtures; information regarding the annual quantity of each type
of alcohol loaded at marine terminals was not available.
Therefore, methanol was chosen to represent alcohols because it
has a high vapor pressure and represents a worst-case scenario
for VOC emissions from loading alcohol. The vapor pressure of
methanol is close to that of Jet Naphtha (i.e., jet fuel or JP4)
over the temperature range from 10° to 2i°C (50° to 70°F).
Therefore, the emission factors for JP4 were applied as the
emission factors for alcohols. A check on the validity of all
emission factors was performed by comparing vapor pressures with
emission factors.
2.2.1.2 HAP Emission Factors. A national estimate of HAP
emissions was developed for all of the commodity categories in
the WCUS data base except jet fuel and naphtha/solvents. Total
HAP emissions associated with the commodity categories were
estimated as a percentage of corresponding VOC emissions (based
on available speciation data) for all categories. Table 2-2
presents the HAP emission factors used for the commodity
categories.
Individual HAP emissions associated with loading gasoline,
crude oil, distillate fuel, and kerosene was estimated based on
the total quantity loaded (i.e., throughput), the total estimated
VOC emissions, and speciation data showing the relative
quantities of HAP's (e.g., benzene, toluene, hexane, etc.)
present in the vapors of the commodities.^ Toluene is a HAP and
for this reason all emissions associated with the toluene
category are HAP's.
Available speciation data for the jet fuel and
naphtha/solvents categories did not include any HAP's.6
Therefore, HAP emission factors for these two commodity
categories are taken to be zero. Additional data regarding
potential HAP's associated with these commodity categories are
still being sought.
-------
TABLE 2-2. HAP EMISSIONS FACTORS3,
Commodity category
HAP
Emission factor for
tankers, lb/1,000 gal
Emission factor for
barges, lb/1.000 gal
Gasoline
Benzene
Toluene
Hexane
Xylene
Others
Total
0.015
0.026
0.035
0.008
0.0033
0.087
0.029
0.048
0.066
0.015
0.0061
0.164
Crude oil'3
Benzene
Toluene
Hexane
Xylenes
Ethylbenzene
Total
6.4 x 10"3
4.3 x 10'3
0.067
9.6 x 10*7
2.3 x 10"4
0.079
0.010
7 0 x 10'J
0.11
1.6 x 10"3
3.7 x 10"4
0.13
Crude oilc
Benzene
Toluene
Hexane
Xylenes
Ethylbenzene
Total
0.32
0.022
0.34
4.9 x 10'3
1.2 x 10"3
0.40
NA
NA
NA
NA
NA
NA
Jet fuel
0
0
Naptha, solvents
0
0
Alcohols
Methanol
Ethylene glycol
0.15
0.36
Toluene
T oluene
0.40
0.80
Distillate fuel
Xylene
Benzene
Toluene
Ethylbenzene
O-Xylene
Total
7.5 x 10'f
3.9 x 10*|
3.3 x 10-|
2.0 x 10'f
2.5 x 10-f
8.4 x 10'5
1.8 x 10"f
9.2 x 10"|
7.9 x 10-=
4.8 x 10"°
6.0 x 10"6
2.0 x 10"4
Chemicals
Alld
0.005
0.005
Otherse
Xylenes
2.4 x 10-4
1.2 x 10"4
7.0 x 107
4.3 x 10"4
6.1 x 10"4
3.1 x 10'4
1.8x1 0"4
1.1 x 10"3
Kerosene
Hexane
Benzene
Toluene
Total
2.4 x 10'4
1.2 x 107
7.0 x 10"5
4.3 x 10"4
6.1 x 10'4
3.1 x 10"4
1.8 x 10"4
1.1 x 10'3
• *r-\i ii aic yiycii mi lur i ,vwv yai iw aiigvr iui caaici lawn <\J vuu oimiooium ialiui a.
HAP emission factors given are for all terminals except Valdez, Alaska.
^HAP emission factors given are for Valdez, Alaska, only.
"Approximately 60 of the 260 chemicals loaded onto marine vessels are MAP'S. However, the worst-case
assumption was made for this category and all chemicals emissions were presumed to be HAP's.
'Unspecified xylenes may be loaded under the crude products subcategory of "others."
-------
The alcohols and chemicals commodity categories both
represent more than one liquid, so estimating VOC and HAP
emissions associated with these two categories requires that
certain assumptions be made. The alcohols category includes
16 different alcohols and alcohol mixtures. Of these
16 compounds, two are on the list of 190 HAP's provided in
Title III of the Clean Air Act Amendments (CAAA) of 1990.7 These
two compounds are methanol and ethylene glycol. Because the
individual quantities of methanol and ethylene glycol loaded are
not known, quantities loaded are estimated based on the amount of
these two compounds produced relative to the annual production of
the remaining 14 compounds in the alcohols category. The vapor
pressures and molecular weights of methanol and ethylene glycol
are also taken into account when estimating HAP emissions
associated with the alcohols category (the vapor pressure of
methanol is approximately 1,500 times that of ethylene glycol).7
The chemicals category includes over 250 different
chemicals, and, of these 250, approximately 60 also appear on the
list of 190 HAP's provided in Title III of the CAAA of 1990.7
Because the individual quantity of each chemical loaded was not
known, and due to the large number of chemicals, the worst-case
assumption was made and the entire throughput associated with the
chemicals category was used to estimate HAP emissions for the
chemicals category.
The "others" commodity category includes "crude products."
A list of compounds included in the crude products subcategory
revealed that some crude products (e.g., miscellaneous xylenes)
are HAP's.8 Therefore, all emissions associated with the
throughput of crude products are considered HAP's to avoid
underestimating the potential HAP emissions from this category.
Neither of the remaining two subcategories in the others category
include HAP's.
Emissions of HAP's associated with the distillate fuel and
kerosene categories were estimated based on speciation data
obtained from EPA's VOC/PM Speciate data base.6
-------
2.2.2 Cargo Loading Emissions
2.2.2.1 VOC Emissions. Cargo loading VCC emissions were
calculated for each commodity category using the quantity (i.e.,
throughput) of the commodity loaded (in tons), the appropriate
emission factor, and the density of the cargo (in tons per
1,000 gallons). Emissions of VOC's were calculated according to
the following equation:
Ev = (c/d) x f,
where:
Ev = mass of VOC emissions;
c = mass of the cargo (commodity);
d - density of the cargo (mass per unit volume); and
f - commodity-specific emission factor (mass per unit
volume).
Emissions from cargo loading were estimated for each of the
1,648 terminals in the data base based on the quantity
(throughput) of each commodity loaded at each terminal and the
equation above. For a terminal loading more than one commodity,
the emissions associated with each commodity were calculated
separately and then summed to determine the total emissions for
that terminal. The sum of the emissions from the 1,648 terminals
in the data base represents the estimated nationwide annual
emissions from cargo loading.
The cumulative national VOC emissions from cargo loading are
estimated to be 75,200 megagrams per year (Mg/yr)
(1.7 x 108 pounds per year [lb/yr]). Crude oil is the major
source of emissions at 49,300 Mg/yr (1.1 x 108 lb/yr) (66 percent
of all emissions). One facility (at Valdez, Alaska) accounts for
39,000 Mg/yr (8.6 x 107 lb/yr) of total estimated crude oil
emissions (i.e., 79 percent of estimated annual crude oil
emissions and 52 percent of total estimated annual VOC
emissions.) Gasoline is the second largest source of emissions,
contributing 21,900 Mg/yr (4.8 x 107 lb/yr) (29 percent of all
emissions). Nationwide emissions may be overstated because
emissions from some commodity categories (e.g., alcohols) were
-------
estimated based on worst-case assumptions. As stated in
Chapter 1, terminals that are affected by promulgated State or
local regulations requiring control of marine vessel loading
emissions have been identified in the data base. Table 2-3 shows
nationwide emissions for the current data base (i.e., with
controlled emissions removed). However, nationwide emissions
shown in Table 2-4 are estimated based on the assumption that all
emissions are uncontrolled. Approximately 19 percent of the
total estimated VOC emissions shown in Table 2-4 are already
subject to control under promulgated State regulations.
2.2.2.2 HAP Emissions. Cargo loading HAP emissions were
calculated for five commodity categories using the mass quantity
of VOC emissions and the percentage of VOC emissions estimated to
be HAP's. The following equation was used to calculate HAP
emissions.
^h = Ev x P»
where:
Eh = mass of KAP emissions;
Ev = mass of VOC emissions; and
p = mass percent of vapor comprised by HAP's.
Emissions of HAP's from cargo loading were estimated for all
terminals. The sum of these HAP emissions represents the
estimated nationwide annual HAP emissions from cargo loading.
Table 2-5 shows estimated annual HAP emissions from cargo loading
by commodity for terminals in the current data base.
The cumulative national HAP emissions from cargo loading
were estimated to be 7,947 Mg/yr (1.75 x 107 lb/yr). Like the
nationwide VOC emission estimates, the HAP emission estimates do
not include emissions already subject to promulgated State
regulations. Also, HAP emissions may be overstated because the
entire throughput of the chemicals category was used to calculate
HAP emissions from that category and some chemicals may actually
be loaded in containers.
Gasoline and crude oil are the major sources of HAP
emissions at 1,054 Mg/yr (2.3 x 106 lb/yr) and 6,346 Mg/yr
(1.4 x 107 Ib/yri, respectively. Of the 6,346 Mg/yr of HA?
-------
TABLE 2-3. ANNUAL VOC EMISSIONS BY COMMODITY (CONTROLLED EMISSIONS EXCLUDED)
Commodity
Commodity
No.
Emission
factor for
tankers,
lb/1.000 gal
Emit&ion
factors for
barges,
lb/1.000 gal
Density.
Ions/1,000 gal
Tanker
emissions
estimate,
Mg/yr
Percentage of
linker
emissions,
percent
Barge
emissions
estimate,
Mg/yr
Percentage of
barge
emissions,
percent
Total
emissions
estimate.
Mg/yr
Percentage of
total
emissions,
percent
Ballasting
emissions,
Mg/yr
Oasotioe
2911
I 800
3.400
3 125
3.640
7 47
18,200
69.0
21,900
27 08
Crude oil*
1311
0.610
1.000
3.620
44,600
91 44
4,710
17.85
49,300
65.59
950
id Aid
2912
0 500
1.200
3 075
275
0.56
1,409
5 34
1.680
2 24
Naphtha, solvents
2917
0 400
0 800
3 100
105
0 21
906
3 43
1.011
1 34
..
Alcohols
2813
0 S00
1 200
3.305
101
0 21
838
3.18
940
1 25
-
Toluene
2817
0.400
0 800
3.614
20
0 04
218
0.82
238
0 32
-
Dim. fuel
2914
0.005
0.012
2.792
16
0.02
79
0.30
95
0.13
Cheinicala'*
0 005
0 005
3 750
12
0 03
15
0 06
27
004
CXheric
0.003
0005
3 464
1 0
0 00
4 7
002
5 7
0.01
--
Kerosene
2913
0005
0013
3 375
0 4
0.00
2 4
0.01
2.8
0 00
TOTAL
41,800
100
26.400
100
75,200
100
* Approximately 76 percent of annual eclimated crude oil emissions are attributed to one terminal (V«|dcz)
^Includes "Basic Ctiemicala" (Commodity No 2819) mid "Miscellaneous Chemicals" (ComriNKlily No. 2891)
-------
TABLE 2-4. ANNUAL VOC EMISSIONS BY COMMODITY (CONTROLLED EMISSIONS INCLUDED)
< 'iHtlMHNllty
Commodity
N.i
Emission
factor for
tanker*.
Ih'l .000 gal
Emission
factors for
harges.
Ih/1.000 pal
Density,
tons/1,000 £al
Tanker
emissions
estimate,
Mg/yr
Percentage of
tanker
emissions,
percent
Barge
emissions
e.«JitiiHle,
Mg/yr
Percentage of
barge
emissions,
percent
Total
emissions
estimate,
Mg/yr
Percentage of
lutnl
emissions,
percent
Ballasting
emissions,
Mg/yr
(litsnhiic
2911
1 800
3 400
3 125
5.850
113
31.500
7ft 8
37,300
400
Oniile oil*
1311
0 610
1 000
3 620*
45,200
87 4
5,740
14 0
51.500
55 2
950
lei fuel
2912
0 500
1 200
3 075
378
2.98
1,650
4.03
2,030
2.1*
-
NH|i]Mhat solvents
2917
0 400
0 800
3 100
105
0 82
906
2 21
1.010
1 08
Alcohols
2813
0 500
1 200
3 305
109
0 86
868
2 12
978
1 05
Toluene
2817
0.400
0 800
3 614
20
0.16
218
0.53
238
0.26
--
DiU. fuel
2914
0.005
0012
2 792
16
0 13
79
0.19
95
0.10
-
Chemicals'*
0 005
0 005
3 750
12
0 10
15
004
27
0 03
Oihersc
0 005
0 005
3 464
1
0 01
5
001
6
0 006
Keroseite
2913
0.005
0013
3 375
0
000
2
001
3
0.003
TOT At
51.700
100
41.000
100
93,200
100
--
"Approximately ?6 percent of annual estimated erode oil emissions are attributed to one terminal (Vatdez)
''intitule* "Hhsic Chemicals" (Commodity No 2819) ami "Miscellaneous Chemicals" (Commodity No 2891),
-------
TABLE 2-5. HAP EMISSIONS ESTIMATES
Mass percent of
HAP emissions.
Commodity
HAP
HAP's
Mg/yr
Gasoline
Benzene
0.80
184
Toluene
1.17
312
Hexane
1.49
421
Xylene
0.46
97
Others4
0.90
40
Subtotal
4.82
1.054
Crude oil
Benzene
1.05
108
Toluene
0.70
72
Hexane
10.93
1,125
Xylene
0.16
16
Ethylbenzene
0.04
4
Total
12.87
1,325
Crude oil (Valdez)
Benzene .
1.05
408
Toluene
0.70
272
Hexane
10.93
4.264
Xylenes
0.16
62
Ethylbenzene
0.04
15
Total
12.87
5,021
Jet fuel
All
0
0
Naphtha, solvents
All
0
0
Alcohols
Methanol, ethylene glycol
30
282
•
Toluene
Toluene
100.
238
Distillate fuel
Xylene
0.15
0.14
Benzene
0.77
0.73
Toluene
0.66
0.63
Ethylbenzene
0.04
0.04
O-xylene
0.05
0.05
Subtotal
1.67
1.59
Chemicals
All
100
27
Others
All
29.05
1.66
Kerosene
Hexane
4.7
0.13
Benzene
2.4
0.07
Toluene
1.4
0.04
Subtotal
8.5
0.24
Total
All
7,947
aIncludes cumene, naphthalene, ethylbenzene, and isooctane. Source: Reference 5.
-------
emissions associated with crude oil, 5,020 Mg/yr (1.1 x
107 Ib/yr) are attributable to the terminal at Valdez, Alaska,
alone. This is primarily due to the extremely high throughput
and elevated emission factors associated with this facility.
Emissions of HAP's associated with the loading of all of the
commodity categories except gasoline and crude oil comprise less
than one-third of total HAP emissions. Toluene emissions
associated with cargo loading are equal to the VOC estimate of
238 Mg/yr (5.2 x 105 lb/yr). (All vapors from toluene loadings
are HAP's.) The two compounds responsible for HAP emissions
associated with the alcohols category are methanol and ethylene
glycol. The total estimated HAP emissions of methanol and
ethylene glycol are 282 Mg/yr (6.2 x 105 lb/yr) and 0.4 Mg/yr
(882 lb/yr). Approximately 60 of the 250 different chemicals in
the "chemicals" category are HAP's.7 Since the different
throughputs and emission factors were not known for each
chemical, the worst-case assumption was made and the entire
chemicals throughput was assumed to be HAP's. For this reason,
VOC and HAP emissions are the same for the chemicals category at
27 Mg/yr (6 x 105 lb/yr).
Emissions of HAP's associated with loading distillate fuel
and kerosene are very low, due primarily to their low VOC
emission factors. Total HAP emissions associated with distillate
fuel loadings are 1.6 Mg/yr (3.5 x 103 lb/yr). Total HAP
emissions from kerosene cargo loadings are 0.24 Mg/yr
(529 lb/yr).
2.3 TANKSHIP BALLASTING
Tankship ballasting emissions were estimated using the
annual quantities of cargo unloaded, the density of the cargo,
the percentage of ballast water loaded, the fraction of ships
using cargo tanks for ballast, and a ballasting emission factor.
The following equation was used to calculate ballasting
emissions:1
Eg - (c/d) x P x 0.30 x f,
where:
Eg =• mass of VOC emissions from ballasting;
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c = mass of cargo;
d = density of commodity (mass per unit volume);
P =» percentage of tankships without equipment to prevent
ballasting emissions; and
f = commodity-specific emission factor (mass per unit
volume).
The data base contains unloading information only for crude oil;
no information was obtained regarding the unloading of other
commodities. Therefore, nationwide ballasting emissions were
calculated only for crude oil. However, crude oil represents the
majority of VOC-emitting compounds unloaded at marine terminals
(approximately 76 percent of the nationwide ballasting emissions
estimated by the Marine Board for 1984 were attributed to crude
oil). The percentage of tankships without equipment to prevent
ballasting emissions was assumed to be 5.2 percent, based on
information provided by the Marine Board.1 A tankship ballasting
emission factor of 1.2 lb/1,000 gallons of crude oil unloaded was
provided m AP-42. Approximately 3 0 percent of the volume of
the tank was assumed to be filled with ballast water.1 Based on
these assumptions and no clean ballast tanks, the total VOC
emissions from crude oil tankship ballasting were estimated to be
approximately 950 Mg/yr (2.1 x 10s lb/yr). Based on the portion
of HAP'a in crude oil vapor, total HAP emissions from ballasting
are 120 Mg/yr (2.7 x 10^ lb/yr). Benzene accounts for 9.9 Mg/yr
(2.2 x 104 lb/yr) of HAP emissions from crude oil tankship
ballasting, and toluene accounts for 6.6 Mg/yr (1.5 x 104 lb/yr).
Hexane accounts for the largest portion of HAP emissions from
crude oil tankship ballasting 104 Mg/yr (2.3 x 105 lb/yr).
Ballasting emissions will diminish in the future because most
tankships built since 1980 are required by domestic law and
-------
international agreement to use segregated ballast tanks (SBT's)
and, thus, do not emit vapors during ballasting.1
2.4 EMISSION CONTROLS
This section describes the types of emission control systems
available for controlling VOC and HAP emissions from marine
vessel loading operations. The information contained in this
section is taken primarily from Chapter 3 of the Marine Board's
Controlling Hydrocarbon Emissions From Tank Vessel Loading.1
Several emission control processes are applicable to
controlling emissions during marine vessel loading; these
processes fall into two major categories: combustion and
recovery. Combustion processes include flares and incinerators.
Recovery processes include lean oil absorbers, refrigeration
systems, and carbon-bed adsorbers. All of these vapor control
systems are described below. However, incineration was assumed
to be the control method of choice when estimating the costs of
control in Chapter 3 of this document. The primary reason for
selecting incineration is that many marine terminals load more
than one commodity, and recovery processes are best suited to
terminals that load only one commodity. When selecting a vapor
control system for an actual terminal, the decision of whether or
not to recover the commodity also depends on (1) the nature of
the VOC stream (specifically, its expected variability in flow
rate and hydrocarbon content) and (2) locational factors, such as
the availability of utilities and the distance from the tankship
or barge to the vapor control system.1
Compared to recovery processes, flares and incinerators are
inexpensive to install and easy to operate. Combustion systems
tend to be well suited to low-volume terminals that are located
far from existing utility hookups. Combustion processes are more
economic than other control technologies if the VOC vapor vented
from the tankships and tank barges is lean and the potential
value of the recovered VOC is low. Conversely, if the VOC stream
is relatively rich and the terminal has a high throughput,
adequate space, and easily accessible utilities, then it may be
economic to recover the VOC. Recovery systems are more expensive
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to install and operate than combustion systems; however, the
value of the recovered VOC can make recovery cost effective.1
2.4.1 Closed Loading of Vessels
Controlling emissions from tank vessel loading requires that
the compartments on both tankships and barges be closed to the
atmosphere during loading. Closed loading is done with hatches
and ports closed, but it does not necessarily preclude venting
vapors to the atmosphere (tank vents are generally open to the
atmosphere). Most tankships are already equipped for closed
loading as a result of having inert gas systems on beard (closed
loading is necessary to maintain the legally required minimum
inert gas pressure in the cargo tanks).1 Barges generally do not
use inert gas, so they are usually open loaded. Equipment
necessary for closed loading includes (l) devices to protect
tanks from underpressurization and overpressurization, (2) level-
monitoring and alarm systems to prevent overfilling, and
(3) devices for cargo gauging and sampling.1 The types of
equipment included in each of these three categories is explained
in detail in the Marine Board document.1
2.4.2 Combustion Processes
«
The combustion processes described in this section include
flares (both open and enclosed) and incinerators (recuperative
and regenerative). Flares and incinerators combust VOC vapors as
they arrive from the vessel or from intermediate vapor-recovery
equipment. The combustion products are mainly carbon dioxide
(C02) and water; small amounts of nitrous oxides (N0X) and carbon
monoxide (CO) are also produced. Both flares and incinerators
are more than 98 percent efficient if operated properly.
The primary drawback to using combustion processes is that
they do not recover the VOC and use fuel in the process. Also,
incinerating chlorinated compounds may lead to the formation and
emission of acid gases. Another drawback is that combustion
devices are potential ignition sources. However, newly
manufactured combustion devices have flame arresters to guard
against flash back. This concern is especially important if the
displaced vapors are not inerted or enriched. Vapors from
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vessels with inert gas systems have oxygen contents below
8 percent, which is too low to support combustion. The lack of
oxygen greatly reduces the risk of explosion; however, it also
requires the combustion system to draw in additional air (to
raise oxygen levels to the point where the mixture will burn).
Diluting the vapors increases the size of the combustor and the
amount of supplemental fuel needed to maintain minimum combustion
temperatures.1 Enrichment of vapors involves adding fuel
(usually methane or propane) to the VOC mixture to make it too
rich to support combustion.
The primary advantage of using combustion instead of
recovery systems is that combustion devices are generally cheaper
to install and to operate. Combustion processes are also more
efficient than recovery processes in reducing the VOC content of
the vapor stream. In addition, combusting VOC's is more
practical at terminals where several different commodities are
loaded. (For additional information on combustion processes, see
Chapter 3 of the Marine Board document).1
2.4.2.1 Flares. Flares combust VOC's by igniting the
VOC-laden vapors as they pass through one or more burners.
Flares may be either open or enclosed. An enclosed flare is of
the same fundamental design as an open flare but with a
protective cylindrical shroud around the burners. Enclosed
flares allow for control of operating temperature and residence
time as well as emission testing. Flares are the least expensive
control system. Flares require little operator attention and
will burn on their own so long as the incoming vapors contain
enough hydrocarbon. Pilot burners are U9ed to ensure that a
flame is maintained in the event that the main flame goes out;
the pilot burner is much smaller than the primary burners.
Flares are usually more than 98 percent efficient as long as the
combustion zone stays properly lighted. Flares, especially open
ones, need to be located away from people and equipment for
safety reasons.1
2.4.2.2 Incinerators. Incinerators operate by combusting
VOC vapors in a confined chamber under controlled conditions.
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Vapors enter the reaction chamber, combust, and then exit through
an exhaust stack. Supplemental combustion air and fuel are added
to the reaction mixture to maximize combustion efficiency.x
Combustion air is added to maintain an excess of oxygen, and
supplemental fuel is added to maintain the desired operating
temperature.
There are two basic designs of incinerators: recuperative
and regenerative. Regenerative incinerators differ from
recuperative incinerators in that they have heat-exchange media
upstream and downstream of the reaction chamber. By periodically
reversing the flow direction, regenerative incinerators can
recover more energy than a recuperative incinerator equipped with
a heat exchanger.9
. When outfitted with a heat exchanger, recuperative
incinerators can achieve up to 70 percent energy recovery. High
destruction efficiencies (99+ percent) can be achieved by
operating at higher temperatures or by increasing the residence
time (via a larger combustion chamber), both of which result in
increased fuel consumption. Recuperative incinerators are better
suited to lower flows and richer gas streams more capable of
supporting their own combustion.9
Regenerative incinerators operate in much the same way as
recuperative incinerators with heat exchangers. Regenerative
incinerators, however, have direct-contact beds of silica gravel
or ceramic burls that absorb heat from the exhaust gas.
Periodically, the direction of the gas flow through the
incinerator is reversed. The bed that was being heated by the
exhaust gas now preheats the incoming stream. By using this
method of direct-contact heat exchange and reversing flow, energy
recovery can be up to 95 percent efficient. Control efficiencies
of up to 99 percent destruction can be achieved. The high-energy
recovery makes regenerative incinerators well suited to lean,
high-volume gas streams. In many cases, the pilot burner alone
will supply the heat input necessary to maintain combustion.9
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The incinerator costs presented in Chapter 3 of this
document were estimated based on the assumption that regenerative
incinerators will be used to control loading emissions.
Regenerative incinerators were used in the estimates in
order to better utilize the Marine Board costs. The incinerator
and fuel costs in the Marine Board estimate indicated that a
regenerative incinerator was used. Marine Board costs also
assumed that vapors would be inert.ed -prior transport to the
incinerator. However, marine vessel loading is a batch process,
and would require constant startup and shutdown of the
incinerator or idling, which would raise fuel consumption.
Because of this, most combustion systems will likely use a
recuperative incinerator or enclosed flare and an enrichment
system. This system would be slightly less complex and more
streamlined than the one used by EPA for costs estimates.
2.4.3 Recovery Processes
Recovery processes are more complex to design and operate
than are combustion processes; however, the value of the
recovered product can make recovery a feasible alternative in
some cases. Most recovery processes can recover 80. to 95 percent
of the VOC with moderate installation and operating costs.
Achieving higher efficiencies can be very costly because severe
operating conditions are required (e.g., temperatures below
-200°F or pressures above 250 psia). If further reduction of
VOC's is needed, a small flare or incinerator can follow the
recovery unit and polish the outlet stream.1
The recovery processes described in this section include
lean oil absorption, refrigeration, and carbon bed adsorption.
2.4.3.1 Lean Oil Absorption. Lean oil absorbers use
condensation and cooling under pressure to transfer hydrocarbons
(VOC's) from a rich vapor into a lean oil. Any hydrocarbon
liquid with sufficiently low vapor pressure can be used as the
lean oil. Tankship- and barge-loading terminals could use crude,
product, or another specially designated lean oil supply. The
recovered hydrocarbon can be either incorporated and sold as part
of the lean oil or stripped from it and handled separately. When
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possible, the same commodity being loaded should be used as the
lean oil supply because it will work well and saves the added
expense of another material. The commodity can then be returned
to a storage tank or to the vessel being loaded.
Lean oil absorption processes are very efficient at
recovering hydrocarbon from rich streams but much less efficient
at removing hydrocarbon from lean streams that contain little
hydrocarbon. Lean oil absorbers usually operate at pressures of
100 to 200 psia. To further reduce the existing vapor's
hydrocarbon content, some absorption units also cool the lean
oil. Typically, an absorber can remove 80 to 90 percent of a
vapor's hydrocarbon by simply increasing the pressure.
Efficiencies of up to 95 percent can be achieved by lowering the
operating temperature as well. However, at temperatures much
below 60°F, hydrate formation may cause freeze-up problems. If
the system is under pressure, water can freeze, even at
temperatures above 32°F. If necessary, antifreeze {e.g.,
ethylene glycol) can be used to lower the liquid hydrocarbon's
freezing point.1
2.4.3.2 Refrigeration. Direct refrigeration systems remove
hydrocarbons by cooling the vapors through a series of low-
temperature heat exchangers. These systems are best suited to
vapors from non-inerted product carriers, i.e., vapors that do
not contain as much CC>2. light ends, or corrosion-causing
contaminants, such as hydrogen sulfide (I^S). (Inerted vapors
contain about 15 percent C02 by volume; I^S is contained in crude
oil vapors.)1
Most direct refrigeration systems use sea or river water to
cool the vapors to around 60°F. This step removes most of the
water and heavy hydrocarbons from the vapor. Next, as many as
four refrigeration loops cool the remaining vapor to somewhere in
the -100° to -150°F range. The number of loops needed and the
intermediate operating temperatures depend on the hydrocarbon
(VOC) species present and the desired recovery efficiency.
Usually the first heat exchanger removes water from the vapor at
-------
around 32°F, the second heat exchanger cools the vapor to below
0°F to remove intermediate-weight hydrocarbons, and so on.1
To further improve hydrocarbon reduction, it is useful to
compress the vapors, further reducing the equilibrium hydrocarbon
content. Compression is usually done after the first or second
exchanger, at which point most of the water and heavy
hydrocarbons have been removed. After the vapor has passed
through the low-temperature heat exchangers, it expands and
reaches ambient pressure as it is vented to the atmosphere. This
expansion lowers the temperature further and drops out additional
hydrocarbon.
Direct refrigeration can remove up to 99 percent of a
stream's VCC content when very low temperatures are used.
However, below 60°F, hydrates may form and plug heat exchanger
surfaces and lines. Hydrate formation may be avoided by
injecting ethylene glycol or other antifreeze or by operating the
refrigeration unit intermittently to allow periodic thawing.
However, using antifreeze becomes very expensive at lower
operating pressures, and intermittent operation may limit loading
rates on tankships and barges. 1
2.4.3.3' Carbon Bed Adsorption. Carbon bed adsorbers use
activated carbon or a similar adsorptive medium to adsorb
hydrocarbons selectively. Air and very light hydrocarbons pass
through the medium, while heavier hydrocarbons are adsorbed to
the medium's surface. Carbon beds operate effectively regardless
of whether or not the incoming vapors have been inerted.
However, by Coast Guard regulation, vapors routed to a vapor
recovery unit need not be enriched, inerted, or diluted.10 After
the capacity of the adsorptive medium is used up--that is, after
most of the adsorptive sites are already holding hydrocarbons --
hydrocarbons will "break through" and appear in increasing
amounts in the exiting vapor. At this time, the medium needs to
be recharged, or the exiting vapor will eventually contain as
much hydrocarbon as the untreated vapor, and the pressure drop
across the adsorption unit may become unacceptable.1
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Although disposal of spent carbon is an option, most
terminals are large enough for activated carbon regeneration to
be economical. The best method for regenerating the spent carbon
is to use a vacuum pump to desorb the hydrocarbons. Another
alternative, steam stripping, requires a steam source and
generates an oily wastewater stream that requires proper
disposal.1
Carbon bed adsorbers can be more than 99 percent effective
at removing hydrocarbons; however, carbon beds are not as
effective at removing light ends such as ethane and propane.
Such light species tend to adsorb poorly, and slight temperature
increases may drive them off. Alternatively, when heavier, more
strongly attracted species pass through the bed, they may
displace the lighter species from the active sites. Also, H2S
and other contaminants present in crude oil and other "dirty"
commodities permanently poison activated carbon. Poisoning of
the activated carbon can be avoided, however, by treating the
vapor with caustic (sodium hydroxide) prior to routing the vapor
to the adsorber.1
2.5 CURRENT PRACTICES AND SAFETY ASPECTS
The technology for controlling VOC and HAP emissions from
marine vessel loading operations is available and already in use
on vessels and at marine terminals that load highly toxic or
noxious cargoes with volatile vapors, such as ammonia, chlorine,
acrylonitrile, and epichlorohydrin. These and other hazardous
fluids are routinely captured for reuse or disposal.1 Applying
these control technologies to terminals with high throughputs and
loading rates (typical of terminals that load gasoline and crude
oil) will require that terminal operators maintain safe operating
practices due to the increased handling of potentially explosive
vapors.
Loading the tank vessels with hydrocarbon cargoes presents
three main hazards: (1) fire due to the ignition of spilled
liquid or unconfined vapors, (2) explosion due to the ignition of
vapor-air mixtures in confined spaces, and (3) water pollution as
a result of spills. Adding vapor-handling systems could increase
-------
the risks of such events occurring by adding to the operational
complexity of loading operations, and in particular by requiring
additional handling of potentially explosive vapors. An
additional consideration is the possible personnel exposure to
vapors. However, the risks associated with vapor control can be
minimized through proper personnel training and management.
Also, redundant safety systems are required at terminals and on
board vessels to ensure that the temporary failure of one system
would not expose operations to undue risks.1 The U.S. Coast
Guard has addressed these safety issues by adopting new
regulations for the safe design, installation, and operation of
marine vapor control systems; these regulations became effective
on June 21, 1990.10
2.6 REFERENCES FOR CHAPTER 2
1. Controlling Hydrocarbon Emissions From Tank Vessel Loading.
Marine Board, National Research Council. 1987. pp. 2,
11-13, 58-77, 81.
2. Compilation of Air Pollutant Emission Factors. Volume I:
Stationary Point and Area Sources. EPA Publication
No. AP-42. September 1985. pp. 4.3-7 and 4.4-1 through
4.4-17.
3. Inventory of Emissions From Marine Operations Within the
California Coastal Waters. Scott Environmental Technology,
Inc. June 1981. pp. 3-38.
4. Letter and attachments from Verelli, L., State of Alaska
Department of Environmental Conservation to Wyatt, S.
EPA.-CPB. December 7, 1990. Comments on Draft Technical
Support Document.
5. Gasoline Marketing Industry (Stage I) -- Background
Information for Proposed Standards. Preliminary Draft.
U. S. Environmental Protection Agency, Research Triangle
Park, NC. November, 1991. p. 3-7.
6. VOC/PM Speciation Data System Documentation and User's
Guide. Version 1.32a. EPA Publication No. 450/2-91-002.
November 1990. Speciate data base and associated
documentation.
7. Memorandum from Nicholson, R., MRI, to Markwordt, D.,
EPA:CPB. March 14, 1991. Commodities Loaded into marine
vessels that are sources of Hazardous Air Pollutants.
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8. Letter and attachments from Mire, T. U.S. Army Corps of
Engineers, Waterborne Commerce Statistics Center, to
Markwordt, D., EPA:CPB. August 13, 1990. Compounds loaded
in WCUS commodity categories.
9. Renko, R. Clean Up Your Act With Fume Incineration Systems.
Plastics Technology. July 1988.
10. Department of Transportation. U.S. Coast Gue.rd. Marine
Vapor Control Systems; Final Rule. Title 33, Code of
Federal Regulations, Part 154, et al. Washington, DC.
Office of Federal Register. June 21, 1990.
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3.0 COSTS
This chapter presents the estimated capital and annual costs
of controlling emissions from marine vessel loading operations.
These costs include the costs of retrofitting both the marine
terminals and the vessels that load at these terminals.
Section 3.1 discusses the model terminals and vessels that were
developed in order to simplify the cost-estimating procedures.
The capital and annual costs of retrofitting the model vessels is
discussed in Section 3.2; Section 3.3 presents the capital and
annual costs of retrofitting the model terminals with an
incineration system or a carbon adsorption system. Nationwide
costs are discussed in Section 3.4.
3.1 DEVELOPMENT OF MODEL TERMINALS AND VESSELS
3 . x. . i Ss
In April 1987, the Marine Board of the National Council on
Engineering and Technical Systems (Marine Board) contracted with
United Technical Design, Inc. (UTD) to prepare a cost estimate
for marine vapor control systems. The Marine Board provided UTD
with four model vessels and three model terminals. The four
model vessels are (1) a crude oil tankship (70 kilo dead weight
tons [kdwt]), (2) a product tankship (35 kdwt), (3) a crude-oil
ocean barge (19 kdwt), and (4) an inland river barge. The three
model terminals are (5) a product terminal serving inland river
barges, (6) a crude oil terminal, and (7) a product terminal
serving ships and barges. The numbers preceeding the individual
model descriptions correspond to the Marine Board model number.
United Technical Design estimated the cost of installing an
incineration-based emissions control system at each of the three
model terminals, as well as the cost of retrofitting the model
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vessels (i.e., tankships and barges) loaded at those terminals.
Equipment needed for vessel retrofit includes systems aboard
vessels that make closed loading possible: devices to protect
tanks from overpressurization, level monitoring and alarm systems
to prevent overfilling, and devices for final cargo gauging and
sampling. Vessels need piping and manifolds to collect vapors
and carry them ashore for disposition. Tank gauging and alarms,
detonation arrestors, and other safety devices on vessels and at
terminals are needed to prevent overpressurization and prevent
fires and explosions.
3.1.2 New Models
The three Marine Board model terminals are designed for
throughputs of 8 million barrels per year (mm bbl/yr),
70 mm bbl/yr, and 29 mm bbl/yr, respectively (based on loading
one vessel 2,000 hours per year at maximum capacity). However,
the majority (1,348 out of 1,648) of the terminals in the current
data base have throughputs of less than 1 million bbl/yr. To
better represent actual terminals, the existing three model
terminals were modified to create eight model terminals. Most of
the new model terminals are designed with lower throughputs than
the original models and more closely parallel the throughputs of
VOC-emitting commodities at actual terminals. The model vessels
used are the same as those created by the Marine Board.
In order to estimate terminal costs, each terminal
represented in the data base was assigned to one of the eight
model terminals. The actual terminals were assigned to model
terminals based on the commodities loaded (product or crude oil),
vessels loaded (barge or ship), and throughput (bbl/yr).
(Product is defined as any commodity other than crude oil.)
Table 3-1 presents a brief summary of the eight model terminals
and shows the number of actual terminals represented by each
model. The four model vessels are presented in Table 3-2.
Terminals assigned to Models 6A, 6B, and 6C load crude oil
only. Terminals assigned to other models load at least one
product commodity and may or may not also load crude oil.
Models 5A, 5B, and 5C are based on Marine Board Model Terminal 5
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and represent terminals that load product commodities onto barges
only. Models 7A and 7B are baaed on Marine Board Model
Terminal 7 and represent terminals that load product commodities
onto either ships only or both ships and barges. Model 6A is
based on Marine Board Model Terminal 6 and represents terminals
that load crude oil onto ships or ships and barges. Models 63
and 6C are based on Marine Board Model Terminal 5 and represent
terminals that load crude oil onto barges only. A detailed
description of the four model vessels and eight new model
terminals is provided in Appendix A.
3.2 MODEL VESSELS
The Marine Board developed four model vessels for use with
the model terminals.1 The model vessels are (1) a crude oil
tankship (70 kdwt), (2) a product tankship (35 kdwt), (3) a
crude-oil ocean barge (19 kdwt), and (4) an inland river barge.
The characteristics of the four model vessels and associated
retrofit costs are presented in Table 3-2.
The capital costs for the model vessel retrofits are taken
from the UTD cost estimate.2 The UTD model vessel costs differ
from the Marine Board costs only for Model Vessel 2, 35 kdwt
product ships. The Marine Board wholly adopted UTD's cost
estimates with the exception of Model Vessel 2. The Marine Board
estimate includes shipboard inert gas generators while UTD's
estimate does not. The UTD estimate is used for Model Vessel 2,
as dock-mounted inert gas generators are more economical than
those mounted shipboard.
Model Vessel 3 is a 19 kdwt crude oil ocean barge. It is
not used by any of the Marine Board or modified model terminals.
Terminals that load crude oil onto barges and terminals that load
products onto ships are both assumed to use inland river barges.
The capital costs for vessel retrofit range from $168,000 to
$426,000, depending upon vessel size and existing piping.2 The
capital costs to retrofit Model Vessels 1 and 4 are the same
($168,000). Model Vessel 1 has an inert gas system onboard, the
piping of which can be used as a vapor collection header. Model
Vessel 4 requires a complete retrofit (i.e., piping,
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instrumentation, hardware), the cost of which may exceed the
value of the vessel. The capital cost to retrofit Model Vessel 2
(35 kdwt product ship) is highest. It is the largest vessel that
requires a complete retrofit.
Annual costs for vessel retrofit range from $24,500 to
$64,400 per year.2 The annual costs depend upon the amount of
maintenance the vessel retrofit will require and recovery of the
capital invested in the retrofit. The annual costs also are
taken directly from the UTD cost estimate. A complete summary of
vessel retrofit capital and annual costs is presented in
Table 3-3.
3.3 MODEL TERMINAL COSTS
3.3.1 Capital Costs
The capital costs for each of the model terminals are
dictated by the number of berths (number of vessels that can
simultaneously load at the terminal) and the maximum loading
rate. The number of berths at each terminal affects the amount
of equipment and piping necessary for controlling emissions; the
maximum loading rate affects the size of the necessary equipment
and piping. Maximum loading rates for each model terminal may be
calculated by multiplying the number of berths by the loading
rates of the associated model vessels.
Models Terminals 5A, 5B, and 5C are designed to load
four barges, two barges, and one barge, respectively (no
tankships are associated with these models). Each barge has a
loading rate of 4,000 barrels/hour (bbl/hr). Therefore, the
equipment and piping must be sized to handle 22,460 ft3
(4,000 bbl/hr x 5.615 ft3/bbl) of VOC gas stream per barge, plus
the inert gas (if necessary) to inert the VOC stream. A ratio of
1.37 ft3 inert gas to 1 ft3 VOC's is used to determine the gas
flow rate when incineration is used. This ratio, which is higher
than the industry standard 125 percent assumed in the UTD
estimate, is calculated as the amount of inert gas necessary to
dilute gasoline (Reid Vapor Pressure - 7) at 70°F to 8 percent
oxygen. Maximum output from the inert gas generator for Models
Terminals 5A, 5B, and 5C is 30,770 ft3/hr (1.37 x 22,460 ft3) per
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barge. Maximum flow to Che incinerator for these models is then
30,770 ft3/hr + 22,460 ft3/hr, or 53,230 ft3/hr (887 ft3/min) per
barge when incineration is used. No inert gas or dilution air is
assumed for recovery. Model gas stream flows for other terminal
scenarios are calculated similarly.
Gas stream flows are important for determining both capital
and annual costs. Incinerator, inert gas generator, and piping
costs are all flow dependent. Annual costs, such as natural gas
and electricity are also dependent upon vapor flow rates.
3.3.1.1 Incineration. The approach used in original cost
analysis prepared by UTD, "Scoping Quality Cost Estimate for
Marine Vapor Control Systems," is used as the cost basis for
applying an incinerator to the eight model terminals. However,
the methodology for many capital and annual costs has been
changed from the original estimate. Incinerator, equipment,
piping and instrumentation costs have all been changed to reflect
the loading rates and numbers of vessels assigned to the new
model terminals. Additionally, costs were developed for an
independent inert gas generator and scrubber water system because
the system used in the UTD cost estimate is not technically
feasible. The original UTD cost estimate assumed that
incinerator exhaust gas would be used as an inert gas to dilute
vapors as they were displaced during loading. Regenerative
incinerators require large amounts of excess air to achieve high
(98 percent) destruction efficiencies.3 When operating with high
levels of excess air, the exhaust gas contains too much oxygen to
be used as an inert gas. If excess air levels are decreased to
stoichiometric levels (no excess air) in an effort to reduce
exhaust gas oxygen content, destruction efficiency is reduced to
70 to 80 percent.4 Therefore, separate inert gas generators
mounted dockside are included in the cost estimate. The
advantage of a regenerative incinerator is that no auxiliary fuel
is needed due to the high stream concentrations and energy
recovery of the incinerator. The only uses for auxiliary fuel
would be startup, idling, and maintaining the pilot light.
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The inert gas generator must be capable of supplying inert
gas for the loading of all the vessels utilized by a model
terminal. The use of one inert gas generator for Model
Terminals 5A to 5C, 6B, and 6C is practical. However, if a
single inert gas generator were sized to handle the loading of
all vessels associated with models 7A or 7B, its turndown ratio
(i.e., minimum operating capacity divided by maximum operating
capacity) is great enough that it would over-produce inert gas
during the loading of a single barge. For this reason and for
greater reliability, multiple inert gas generators were assumed
in lieu of one full-sized inert gas generator for Model
Terminals 7A and 7B.
A separate inert gas system was assumed for all models
except Model Terminal 6 (the vessels associated with Model
Terminal 6 have their own inert gas systems). The inert gas
generator costs are adjusted for size using EPA costing
methodology.5'6 Inert gas generator costs range from $63,000 to
$684,000 per model.
Incinerator capital costs provided by UTD were changed to
reflect EPA costing methodology.^ New incinerator costs range
from $218,000 to $368,000. An additional 33 percent was added to
the incinerator cost for installation. Installed incinerator
costs range from $290,000 to $490,000. The original UTD
installed incinerator costs ranged from $319,000 to $1,600,000.
The difference between the costs estimated using UTD and EPA
methodologies is greatest between Model Terminal 7A and the
Marine Board's Model Terminal 7.
The UTD costs for other major equipment and instrumentation
are used directly. However, the UTD estimates of some items in
these categories (e.g., trip valves, detonation arrestors, oxygen
probes) were determined based on the number of loading berths
associated with each model. The costs per equipment located at
each berth has been recalculated based on the number of loading
berths associated with the new model terminals. Therefore, the
instrumentation and other major equipment capital costs differ
for Model Terminals 5A, 5B, and 5C because of the different
-------
number of loading berths associated with each model. Costs for
piping, fittings, and associated installation were taken from the
UTD estimate. Piping costs presented on a per-berth basis
(e.g., headers) were adjusted to correspond with the number of
loading berths associated with each model terminal. Piping size
has been adjusted to retain the same stream velocity as in the
original UTD scenario. Engineering, startup, and contingencies
are assumed to total to 25 percent of installed equipment costs
(per UTD).
The estimated capital costs of controlling emissions from
each of the eight model terminals using an incineration based
technology are presented in Tables 3-4 through 3-11. Complete
documentation for these costs is provided in Appendix B.
3.3.1.2 Recovery. Capital and annual costs were also
developed for a carbon adsorption-based emission control system.
Much of the equipment needed to control air emissions from marine
vessel loading operations via incineration is also necessary when
carbon adsorption is used (e.g., piping, booster fans, detonation
arresters, vapor headers, explosionproof alarms, probes, sensors,
etc.). The piping, instrumentation, and other major equipment
costs are calculated using the same bases. When using recovery-
based control systems, inert gas, enrichment, or dilution air .is
no longer necessary. Therefore, an inert gas generator and
cooling water system are not included in the costs for the
recovery system. Piping sizes are also reduced to correspond to
the lower noninerted emission stream flow rates.
The design and costs of the carbon adsorbers were determined
using procedures outlined in the OAQPS Control Cost Manual.5
Tables 3-12 through 3-16 present the capital and annual costs of
carbon adsorption-based controls for each model terminal loading
gasoline (i.e., Models 5A, 5B, 5C, 7A and 7B). Appendix C
presents a summary of the carbon adsorber design characteristics
for each Model Terminal. A detailed description of the
development of the carbon adsorption system design
characteristics for Model Terminal 5A is provided as Appendix D;
Appendix D also provides complete documentation of all capital
-------
and annual costs for Model Terminal 5A using a carbon adsorption-
based control system. Table 3-17 provides a comparison of the
estimated capital costs of incineration versus carbon adsorption
for Model Terminal 5A. The percent difference in the capital
costs indicates that incineration is more costly by 3.8 percent.
Note that because the cost estimates for carbon adsorption
are focused on gasoline recovery, Model Terminals 6A, 6B, and 6C
(which deal exclusively with crude oil) were not used to develop
carbon adsorption costs. Crude oil emissions are not expected to
be controlled by ^carbon adsorption because hydrogen sulfide (H2S)
present in crude oil vapor tends to poison the carbon bed;
however, pretreatment (via a scrubber) could remove H2S from the
vapor prior to the adsorber. In addition, terminal owners are
not expected to invest in carbon adsorption if they are required
to control a.variety of compounds because the design of carbon
adsorbers is usually compound-specific.
3.3.2 Annual Coats
Annual costs from the UTD estimate were incorporated into
this cost estimate where possible. Several annual costs not
included in the original UTD estimate were added: these costs
include labor (operating and maintenance) and overhead. Other
annual costs, such as electrical and natural gas costs, were
taken from the UTD estimate and modified as needed. Costs for
operating labor and maintenance parts and labor are taken from
EPA costing methodology.5
Maintenance parts and labor are added to UTD's preventive
maintenance estimate in order to obtain total maintenance costs.
The natural gas costs for incinerators are taken directly from
the UTD estimate. The amount of natural gas needed for inert gas
generators is based on the size of the inert gas generator.7
Electrical consumption for the emission stream booster fans was
taken from the UTD document for Model Terminals 5A through 5C
and 6A through 6C and adjusted for electrical rate (dollars per
kilowatt hour).8 Electrical consumption for the emissions stream
booster fans was calculated using EPA methodology for Model
Terminals 7A and 7B.5 (The original UTD electricity usage
-------
appeared Co be understated for Model Terminals 7A and 7B and
reasonable for the other models. Therefore, the higher figure
determined using EPA methodology is used for Model Terminals 7A
and 7B.)
Overhead costs, which were not included in UTD's estimate,
are calculated as 60 percent of operating labor and maintenance
costs. Property taxes, insurance, and administration are
calculated as 4 percent of the total capital costs (excluding
vessel capital costs). Capital recovery is based on an interest
rate of 10 percent, an equipment life of 10 years, and a piping
life of 20 years. Vessel annual costs include maintenance and
capital recovery costs (10 percent interest and a 20-year life! .
The primary difference between the annual costs for an
incineration-based system and a carbon adsorption-based system is
that, the gasoline recovered in the carbon adsorber can be sold
for a recovery credit. Also, the carbon adsorber does not
require any natural gas and the incinerator does not require
steam, cooling water, or carbon. In addition, electricity costs
are significantly higher for carbon adsorption than for
incineration due to the fact that electricity is only needed to
run the system fan in the incineration system, whereas the carbon
adsorption system needs electricity to run the system fan, bed
drying and cooling fan, cooling water pump, and solvent pump;
however, the same rate ($/Kwh) is used to calculate electricity
costs for the two systems. Other annual costs are essentially
the same with labor and maintenance being slightly lower for
carbon adsorption (no one is needed to operate and maintain the
inert gas generator). Overhead, property taxes, and insurance
co9ts are based on the same percentage for both carbon adsorption
and incineration.
The total capital and annual costs for Model Terminal 5A for
incineration and carbon adsorption fall within 3 to 5 percent of
each other. The total terminal-only capital costs for Model 5A
are $1,290,000 for incineration and $964,000 for carbon
adsorption. However, these terminal-only costs are minor when
compared to the associated total vessel retrofit costs, which are
-------
estimated to be $7,360,000 for both incineration and carbon
adsorption. Because the vessel retrofit costs represent 80 to
90 percent of the total capital cost (depending upon the model
terminal), the choice of control device has little affect on the
total cost of control. Total annual costs are likewise dominated
by the vessel retrofit costs; vessel retrofit annual costs
represent 70 to 80 percent of the total annual costs depending
upon the model terminal. Table 3-18 shows vessel retrofit costs
attributed to each of the eight model terminals. Although the
carbon adsorption-based control system is slightly less
expensive, a general conclusion that carbon adsorption is less
expensive cannot be made because (1) all costs are estimates and
a 3 to 5 percent difference is not significant, and (2) terminals
that choose to incinerate may also choose to enrich rather than
inert the vapors, and enriching is less expensive than inerting.
Table 3-19 provides a comparison of the annual costs of
incineration to those of carbon adsorption.
Equations for annual cost versus throughput were developed
for each of the eight model terminals, based on incineration
costs. The terminals listed in the data base are represented by
a model terminal based on throughput, commodities loaded, and
vessel types loaded. Appendix E lists each terminal, the model
terminal to which it was assigned, terminal emissions (in
pounds), and the associated annual costs of emission control.
The cost equations were used to develop individual costs for each
terminal. For a summary of the cost equations, see Appendix F.
Annual costs are presented in Tables 3-4 through 3-11 for each
model when using incineration and Tables 3-12 through 3-16 for
Models 5A, 5B, 5C, 7A, and 7B, respectively, when using carbon
adsorption. For complete documentation of all incineration-based
costs and their sources, see Appendix B.
3.4 NATIONWIDE COSTS AND COST EFFECTIVENESS
The annual costs for a range of annual throughputs were
necessary for each model terminal in order to derive costs for
actual terminals. The loading rates were assumed to be fixed, so
throughputs were varied by changing the number of loading hours
-------
per year. Throughputs and costs were calculated at 50-hour
intervals from 50 to 2,000 loading hours per year. A linear
regression was performed on the data and equations generated for
annual cost with respect to throughput. Appendix F shows the
data tables of throughput versus costs and the linear regression
output. The terminal-specific costs are calculated using the
cost equation for the model terminal to which the actual terminal
is assigned and the actual terminal throughput. Vessels are
assigned to the terminals based on fleet factors provided by the
Marine Board.1 (Fleet factors are rough estimates of the average
number of barrels transported per day.) Appendix E lists each
terminal, the model terminal to which it was assigned, terminal
emissions (in pounds), and the associated annual costs of
emission control. Total nationwide annual costs were estimated
by summing the costs for each terminal represented in the data
base.
The estimated capital costs are the same for each terminal
in a given model terminal category, except for the "associated
vessel total capital investment" (e.g., the terminal-only capital
costs are the same for each terminal assigned to Model 5A). The
associated vessel total capital investment was calculated based
on the terminal's throughput (see Section II.H of Appendix B).
Nationwide capital and annual costs are presented in
Table 3-20. Table 3-21 presents the nationwide capital and
annual costs based on incineration associated with the actual
terminals that fit each model terminal. The total capital cost
of retrofitting all of the terminals in the data base ranges from
approximately $1.9 billion to $2.4 billion. The total capital
cost of retrofitting both the terminals and the associated
vessels ranges from $2.3 billion to $2.9 billion. The total
annualized cost of retrofitting all of the terminals represented
in the data base varies from $531 million to $619 million. The
total annualized cost of retrofitting all of the terminals
represented in the data base and the associated vessels ranges
from $602 million to $690 million. The corresponding cost-
effectiveness of retrofitting terminals and associated ships and
-------
barges ranges from $8,000/Mg to $9,200/Mg and is based on an
annual emissions reduction of 75,200 Mg/yr. Because the total
annual costs of control are essentially the same for incineration
and carbon adsorption, the cost effectiveness values are also
about the same. Sample emission reduction calculations are
included in Appendix B.
-------
TABLE 3-1. DESCRIPTION OF MODEL TERMINALS
Model
No. of
terminals
Ships
Size of ships
Barges8
Maximum
loading rate,
bbl/h
Actua loading
rate, bbl/h
Hours per
year
Commodities'*
Throughput
SA
9
0
4
16,000
8,000
2,000
Product
TP> 8 mm bbl/yr
SB
14
0
2
8.000
4,000
2,000
Product
4 mm < TP <8 mm bbl/yr
5C
908
0
1
4,000
4,000
1,000
Product
TP< 4,000.000 bbl/yr
6A
18
I
70 kwdt
0
35,000
35,000
2,000
Crude oil
TP>0
6B
8
0
2
8,000
4.000
2,000
Crude oil
4 nun TP <8 mm bbl/yr
6C
187
0
1
4,000
4,000
1,000
Crude oil
TP <4,000,000 bbl/yr
7A
649
1
15 kdwt
1
29,000
29,000
1,000
Product
TP <29,000,000 bbl/yr
7B
6
2
35 kdwi
4
60,000
33,000
2,000
Product
TP> 29,000,000 bbl/yr
aAll barges referred to here ire inland river barges. Model Vessel 4.
-------
TABLE 3-2. MODEL VESSELS*
Model
Vessel type
Vessel size
Commodity carried
Capacity,
1,000 bbl
Loading rate,
bbl/hr
Fleet factor,
bbl/vessel/d2^
Inert gas
system
present
Total capital
investment, $
Total
annualized
costs, $/yr
J
Ship
70 kdwt
Crude oil
490
35,000
25,000
Y
168,000
24,500
2
Ship
35 kwdt
Product
262.5
25,000
20,000
N
426,000
64,400
3
Barge
19 kwdt
Crude oil
142.5
15,000
10,000
N
266,000
44,000
4
Barge
--
Product, crude oil
25
4,000
1,000
N
168,000
29.300
flA!l costs are in 1987 dollars.
-------
TABLE 3-3. MODEL VESSEL CAPITAL AND ANNUAL COSTSa
Model
lb
2C
3d
4e
Capital costs
Vapor header hardware
63,100
78,000
67,000
50.000
Instrumentation
71.400
161,000
81,000
17.000
Piping
0
102,000
65,000
67,200
SubtotaJ
135,000
341,000
213,000
134,000
Engineering, startup, and
33,600
85,000
53,200
33.600
contingencies
TotaJ capital cost ¦
168.000
426,000
266,000
168,000
Annual costs
Maintenance
48,000
14,400
12,800
9.600
Capital recovery
19,700
50,000
31,200
19.700
Total annual costs
24,500
64,400
44,000
29,300
aAJl costs are in 1987 dollars. Numbers have been rounded.
bo kdwt oil carrier.
c35 kdwt product carrier.
**19 kdwt ocean barge.
eInland river barge.
3-
-------
TABLE 3 - 4. CAPITAL AND ANNUAL COSTS: MODEL 5A^
(1987 Dollars)
=saB^s=s=a^ss=aBEaes====:
Low''
Highb
I. Capita] Costs
Installed eouioment costs. S. 1987
1. Incinerator2
329,000
329,000
2. Inert gas (1G) generator**
167,000
167,000
3. Water systeme
15,800
15.800
4. Other nujor equipment^
241,000
241,000
5. Piping^
171.000
228,000
6. Instrumentation^1
49,800
49,800
Engineering, startup, contingencies'
243,000
257,000
Subtotal (terminal-only capital costs)
1,220.000
1,290,000
Associated vessel total capital investment'
7,360,000
7,360,000
TOTAL CAPITAL INVESTMENT (TCI)
8,580,000
8,650,000
II. Annual Costs. S. 1987
A. Direct
1. Labor*
3,520
3,520
2. Maintenance'
39,500
39,500
3. Natural gasm
56,700
56,700
4. Electricity11
5,300
5,300
B. Indirect Oneratine Costs
1. Overhead0
25,800
25,800
2. Property taxes, insurance, and
administration^
48,700
51,500
3. Capital recovery charged
190,000
199,000
Subtotal (terminal-annual costs)
370,000
382.000
Vessel retrofit total annual costs
1,290,000
1,290,000
TOTAL ANNUAL COSTS
1,660,000
1,670,000
HI. Cost Effectiveness
A. Emission reduction, Mg/yr
1,014
1,014
B. Cost effectiveness (incinerator only), S/Mg
370
380
C. Cost effectiveness (incinerator and retrofitting
vessels), S/Mg
1,600
1,600
-------
TABLE 3-4. (continued)
^osts rounded to three significant figures; cost effectiveness rounded to two significant figures.
^Total capital and annual costs in the "low" column are lower than those in the "high" column due to
shorter assumed piping runs (see Footnote g below).
cIncinerator cost = (220,400 + [l 1.57x3,550])x323.8/342.5; plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for size.6
eCapital cost of brackish water system for inert gas scrubber.
fThis category includes fans, valves, and detonation arrestors.2
§ Piping costs are taken from LTD cost estimate. Costs assumed linear on a per-foot basis. Lengths
varied as follows (shorter distance determined from cost sensitivity analysis; greater distance from
LTD cost document1):
Dock to "incinerator: Model 5A 660 ft to 1,400 ft
I^This category includes alarms, probes, and sensors.
'Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment
cost. ^
JCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.'' Total Capital Investment (TCI) = (TCI per vessel)
x (vessels) (see Table 3-12).
''Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 hr)
(0.5 hr/shift)(S«.96/hr)(323.8/342.5).2^-9
'Maintenance for incinerator and IG generator = (2,000 hr/yr) (1 shift/8 hr)
(0.5 hr/shift)($ 14.26/"hr)(323.8/342.5)(2 [for paits])(2) + 32.8002-5-9
111 Assumed pilot light only for incinerator and natural gas for IG generator; cost of aatural gas
= $3.43/1,000 fir.2
DElectricity to ran incinerator and inert gas blower fans.
°Calculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs.^
''Calculated as (0.16275x[capital costs subtotal - piping]) + (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-5. CAPITAL AND ANNUAL COSTS: MODEL 5Ba
(1987 Dollars)
Lowb
Highb
I. Capital Costs
Installed equipment costs. S. 1987
]. Incinerator0
303,000
303,000
2. Inert gas (1G) generator1*
103,000
103.000
3. Water systeme
15,800
15,800
4. Other major equipment^
159,000
159.000
5. Piping®
143,000
182,000
6. Instrumentation'1
36,200
36,200
Engineering, startup, contingencies'
190,000
200.000
Subtotal (terminal-only capital costs)
949,000
998,000
Associated vessel total capital investment)
3,680,000
3,680,000
TOTAL CAPITAL INVESTMENT (TCI)
4,630,000
4,680,000
II. Annual Costs, $, 1987
A. Direct
1. Labor*
3,520
3,520
2. Maintenance'
39,500
39,500
3. Natural gasm
32,200
32,200
4. Electricity0
2.730
2.730
B. Indirect Ooeratine Costs
1. Overhead0
25,800
25,800
2. Property taxes, insurance, and
38,000
39,900
administration!1
3. Capital recovery charged
148,000
154,000
Subtotal (terminal-annual COSts)
290,000
298,000
Vessel retrofit total annual costs
643,000
643,000
TOTAL ANNUAL COSTS
933,000
941,000
IH. Cost Effectiveness
A. Emission reduction, Mg/yr
507
507
B. Cost effectiveness (incinerator only), $/Mg
507
590
C. Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
1,800
1,900
-------
TABLE 3-5. (continued)
®Costs rounded to three significant figures; cost effectiveness rouDded to rwo significant figures.
''Total capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote g below).
clncinerator cost = (220,400+[ll.57x1,775])x323.8/342.5;plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for size.^
eCapital cost of brackish water system for inert gas scrubber.
^This category includes fans, valves, and detonation arrestors.2
Sfiping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document'):
Dock to incinerator; Model 5B 660 ft to 1,400 ft
^This category includes alarms, probes, and sensors.
jEngineering = 10 percent, startup = 10 perceot, and contingencies = 5 percent of installed equipment cost.2
JCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document." Total Capital Investment (TCI) = (TCI per
vessel)x(vessels) (see Table 3-12).
''Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 hr)
(0.5 hr/shift)(S12.96/hr)(323.8/342.5)(2).2-5'9
'Maintenance for incinerator and IG generator = (2.000 hr/yr) (1 shift/8 hr)
(0.5 hr/shift)($14.26/hr)(323.8/342.5)(2 [for parts])(2) + 32.800.2-5-9
mAssumed pilot light only for incinerator and natural gas for IG generator: cost of natural gas
= $3.43/1,000 fP.2
°Electricity to run incinerator and inert-gas blower fans.
°CaJculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs.'
^Calculated as (0.16275x[capital costs subtotal - piping]) -t- (0.1175x[piping]) based on an interest rate of
10 percent, aa equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-6. CAPITAL AND ANNUAL COSTS: MODEL 5C3
(1987 Dollars)
Lowb
Highb
I. Capital Costs
Installed eauipment costs. $. 1987
1. Incinerator^
2. Inert gas (1C5) generator**
3. Water systeme
4. Other major equipment^
5. Piping^
6. Instrumentation'1
290,000
63.400
15,800
118.000
119,000
29,500
290,000
63.400
15.800
118.000
139.000
29.500
Engineering, startup, contingencies'
Subtotal (terminaJ-onJy capitaJ costs)
Associated vessel totaJ capital investment'
159,000
795.000
1,840,000
164,000
819,000
1,840,000
TOTAL CAPITAL INVESTMENT (TCI)
2,640,000
2,660,000
11. .Annual Costs. $. 1987
A. Direct
1. Labor^
2. Maintenance'
3. Natural gas®
4. Electricity"
1,760
36,200
19,900
2,310
1,760
36,200
19,900
2,310
B. Indirect ODeratine Costs
1. Overhead0
2. Property taxes, insurance, and
administration?
3. CapitaJ recovery charge''
22,800
31,800
124,000
22,800
32,800
127,000
Subtotal (terminal-annual costs)
Vessel retrofit total annual costs
239,000
321,000
243,000
321.000
TOTAL ANNUAL COSTS
560,000
564,000
IH. Cost Effectiveness
A. Emission reduction, Mg/yr
B. Cost effectiveness (incinerator only), $/Mg
C. Cost effectiveness (incinerator and retrofitting
vessels), S/Mg
254
940
2,200
254
960
2,200
-------
TABLE 3-6. (continued)
^osts rounded to three significant figures; cost effectiveness rounded to two significant figures.
''Total capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote g below).
cIncinerator cost = (220,400+{l 1.57x887])x323.8/342.5; plus 33 percent for installation.
^Capital cosls from Richardson's and adjusted for size.^
'Capital cost of brackish water system for inert gas scrubber.
^This category includes fans, valves, and detonation arrestors.2
S Pi ping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document)':
Dock to incinerator: Model SC 660 ft to 1,400 ft
^This category includes alarms, probes, and sensors.
{Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost.-
JCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.'' Total Capital Investment (TCI) = (TCI per
vessel)x(vessels) (see Table 3-12).
''Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 hr)
(0.5 hr/shi ft)(S 12.96/hr)(323. 8/342.5)(2).2-5 -9
'Maintenance for incinerator and IG generator = (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)(S 14.26/hr)
(323.8/342.5)(2 [for parts])(2) + 32,800.2-5-9
mAssumed pilot light only for incinerator and natural gas for IG generator; cost of natural gas =
$3.43/1,000 ft3.2
QElectricity to run incinerator and inert gas blower fans.
°Calculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs. ^
^Calculated as (0.16275x[capitai costs subtotal - piping]) + (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-7. CAPITAL AND ANNUAL COSTS: MODEL 6Aa
(1987 Dollars)
Lowb
Highb
I. Capital Costs
Installed equipment costs. $. 1987
1. Incinerator0
325.000
325,000
1. Inert gas (1G) generator**
0
0
3. Water systeme
0
0
4. Other major equipment^
152,000
152,000
5. Piping®
141,000
1,550.000
6. Instrumentation'1
33,700
33.700
Engineering, startup, contingencies'
163,000
516,000
Subtotal (terminal-only capital costs)
815.000
2,580.000
Associated vessel total capital investment'
1,290.000
1,290,000
TOTAL CAPITAL INVESTMENT (TCI)
2.100.000
3.870.000
II. Annual Costs. S, 1987
A. Direct
1. Labor^
1.760
1.760
2. Maintenance'
31.400
31.400
3. Natural gasm
7,650
7.650
4. Electricity"
1.770
1.770
B. Indirect Ooeratine Costs
1. Overhead0
19.900
19.900
2. Property taxes, insurance, and
32.600
103,000
administration?
3. Capital recovery charge^
126.000
349.000
Subtotal (terminal-annual costs)
221,000
515.000
Vessel retrofit total annual costs
188.000
188.000
TOTAL ANNUAL COSTS
409.000
703.000
III. Cost Effectiveness
A. Emission reduction. Mg/yr
796
796
B. Cost effectiveness (incinerator only). S/Mg
280
650
C. Cost effectiveness (incinerator and retrofitting
vessels). S/Mg
510
880
-------
TABLE 3-7. (continued)
*Costs rounded to three significant Figures; cost effectiveness rounded to two significant figures.
^Tolal capital and annual costs in the "low* column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote g below).
°lncinerator cost = (220,400+{11.57x3,275])x323.8/342.5; plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for slze.^
eCapital cost of brackish water system for inert gas scrubber.
'This category includes fans, valves, and detonation arrestors.2
^Piping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied
as follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document'):
Dock to incinerator: Model 6A 660 ft to 6,000 ft
Natural gas to incinerator: Model 6A 2,640 ft to 31,680 ft
^This category includes alarms, probes, and sensors.
'Engineering = 10 percent, startup » 10 percent, and contingencies = 5 percent of installed equipment cost."
•iCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.1' Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
^Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 hr) (0.5 hr/shift) ($12.96/hr)
(323.8/342.5)(2).2,5'9
'Maintenance for incinerator and 1G generator = (2,000 hr/yr) (1 shift/8 hr)(0.5 hr/shift) {$ 14.26/hr)
(323.8/342.5X2 [for parts])(2) + 32.800.2-5,9
m Assumed pilot light only for incinerator and natural gas for IG generator; cost of natural gas —
$3.43/1,000 ft3.2
nElectricity to run incinerator and inert gas blower fans.
°Calculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs subtotal.^
^Calculated as (0.I6275x(capital costs subtotal - piping])+(0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-8. CAPITAL AND ANNUAL COSTS: MODEL 6Ba
(1987 Dollars)
Lowb
Highb
I. Capital Costs
Installed eauioment costs. S. 1987
1. Incinerator0
303,000
303.000
2. Inert gas (IC5) generator'*
103,000
103,000
3. Water systeme
15,800
15,800
4. Other major equipment^
159,000
159,000
5. Piping^
143,000
182.000
6. Instrumentation'1
36,200
36,200
Engineering, startup, contingencies'
190,000
200.000
Subtotal (terminal-only capital costs)
949.000
998,000
Associated vessel total capital investment
3,680,000
3,680.000
TOTAL CAPITAL INVESTMENT (TCI)
4.630,000
4,680,000
II. Annual Costs. $. 1987
A. Direct
1. Labor^
3.520
3,520
2. Maintenance'
39,500
39,500
3. Natural gasm
32.200
32,200
4. Electricity"
2,730
2,730
B. Indirect Operating Costs
1. Overhead0
25,800
25,800
2. Property taxes, insurance, and
38,000
39,900
administration?
3. Capital recovery charge^
148.000
154,000
Subtotal (terminal-annual costs)
290,000
298.000
Vessel retrofit total annual costs
643.000
643.000
TOTAL ANNUAL COSTS
933.000
941,000
ID. Cost Effectiveness
A. Emission reduction, Mg/yr
149
149
B. Cost effectiveness (incinerator only), $/Mg
1.900
2.000
C. Cost effectiveness (incinerator and retrofitting
vessels), S/Mg
6,300
6,300
-------
TABLE 3-8. (continued)
HTosts rounded to three significant figures; cost effectiveness rounded to two significant figures.
•Total capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote g below).
""Incinerator cost = (220,400+[l 1.57x1,775])x323.8/342.5; plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for size.6
eCapital cost of brackish water system for inert gas scrubber.
*This category includes fans, valves, and detonation arrestors.^
^Piping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document1):
Dock to incinerator: Model 6B 660 ft to 1,400 ft
^This category includes alarms, probes, and sensors.
^Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost."
¦JCost for vessel retrofit taken from the UTD cost estimate." The number of vessels required was calculated
using fleet factors in the Marine Board document.'' Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
''Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 hr) (0.5 hx/shift) ($12.96'hr)
(323.8/342.5)(2).2'5'9
'Maintenance for incinerator and IG generator = (2,000 hr/yr) (1 shift/8 hr)(0.5 hr/shift) ($ 14.26/hr)
(323.8/342.5)(2 [for parts])(2) + 32,800.2-5,9
mAssumed pilot light only for incinerator and natural gas for IG generator; cost of natural gas =
$3.43/1,000 ft3.2
nElectricity to run incinerator and inert gas blower fans.
°Calculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs.'
1 Calculated as (0.16275x[capital costs subtotal - piping]) + (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-9. CAPITAL AND ANNUAL COSTS: MODEL 6Ca
(1987 Dollars)
Lowb
High'5
I. Capital Costs
Installed eauioment costs. J. 1987
1. Incinerator0
290.000
290,000
2. Inert gas (1G) generator4'
63,400
63,400
3. Water systemc
15,800
15,800
4. Other major equipment^
118,000
118,000
5. PipingS
119,000
139,000
6. Instrumentation*1
29,500
29,500
Engineering, startup, contingencies'
159,000
164,000
Subtotal (terminal-only capital costs)
795,000
819,000
Associated vessel total capital investment)
1,840,000
1,840,000
total capital investment (tcd
2,640,000
2,660,000
D. Annual Costs. S. 1987
A. Direct
I. Labor**-
1,760
1,760
2. Maintenance'
36,200
36,200
3. Natural gasm
19,900
19,900
4. Electricity11
2.310
2,310
B. Indirect Ooeratine Costs
1. Overhead0
22,800
22,800
2. Property taxes, insurance, and
31,800
32,800
administration?
3. Capital recovery charged
124,000
127,000
Subtotal (terminal-annual costs)
239,000
243.000
Vessel retrofit total annual costs
321,000
321,000
TOTAL ANNUAL COSTS
560,000
564,000
Ul. Cost Effectiveness
A. Emission reduction, Mg/yr
75
75
B. Cost effectiveness (incinerator only), $/Mg
3,200
3,200
C. Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
7,500
7,500
-------
TABLE 3 - 9.
(continued)
^osts rounded to three significant figures; cost effectiveness rounded to two significant figures.
^Total capital and annual costs in the "low* column are lower than those in the "high* column due to shorter
assumed piping runs (see Footnote g below).
clncinerator cost = (220,400 + [11.57x887])x323.8/342.5; plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for size.'®
eCapital cost of brackish water system for inert gas scrubber.
^This category includes fans, valves, and detonation arrestors.2
^Piping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document1):
Dock to incinerator: Model 6C 660 ft to 1,400 ft
hThis category includes alarms, probes, and sensors.
'Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost.'1-
JCost for vessel retrofit taken from the UTD cost estimate." The number of vessels required was calculated
using fleet factors in the Marine Board document.11 Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
^Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 hr) (0.5 hr/shift) ($ 12.96/hr)
(323.8/342.5)(2).2-5-9
'Maintenance for incinerator and IG generator = (2,000 hr/yr) (1 shift/8 hr) (0.5 hr/shift) (Sl4.26/hr)
(323.8/342.5)(2 [for parts])(2) + 32.800.2-5-9
m Assumed pilot light only for incinerator and natural gas for IG generator; cost of natural gas =
$3.43/1.000 fit3.2
QElectricity to run incinerator and inert gas blower fans.
°Calculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs.^
^Calculated as (0.16275x[capital costs subtotal - piping])+ (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-10. CAPITAL AND ANNUAL COSTS: MODEL 7Aa
(1987 Dollars)
Lowb
Highb
I. Capita] Costs
Installed equipment costs. S. 1987
1. Incinerator0
371,000
371,000
2. Inert gas (TG) generator'*
312,000
312,000
3. Water system®
29,200
29.200
4. Other major equipment^
337,000
337,000
5. Piping®
340,000
1,020,000
6. Instrumentation^
69,600
69,600
Engineering, startup, contingencies'
365,000
535.000
Subtotal (terminal-only capital costs)
1,820,000
2,680,000
Associated vessel total capital investment
3.300.000
3,300.000
TOTAL CAPITAL INVESTMENT (TCI)
5,120.000
5,980.000
11. Annual Costs. $. 1987
A. Direct
1. Labor^
1,760
1,760
2. Maintenance'
68,200
68,200
3. Natural gasm
96,600
96.600
4. Electricity11
10,400
10.400
B. Indirect ODeratine Costs
1. Overhead0
42,000
42,000
2. Property taxes, Insurance, and
72,900
107,000
administration?
3. Capital recovery charged
281,000
389,000
Subtotal (terminal-annual costs)
573,000
715,000
Vessel retrofit total annual costs
542,000
542,000
TOTAL ANNUAL COSTS
1,120,000
1,260,000
m. Cost Effectiveness
A. Emission reduction, Mg/yr
1,093
1,093
B. Cost effectiveness (incinerator only), S/Mg
530
660
C. Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
1,000
1,200
-------
TABLE 3-10. (continued)
*Costs rounded to three significant figures; cost effectiveness rounded to two significant figures.
'Total capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote g below).
clncinerator cost = (220,400+[U.57x6,430])x323.8/342.5; plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for size.^
*Capital cost of brackish water system for inert gas scrubber.
^This category includes fans, valves, and detonation arrestors.2
"Piping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths vaned as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document *):
Dock to incinerator: Model 7 A 660 ft to 6,000 ft
I'This category includes alarms, probes, and sensors.
^Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost.2
JCost for vessel retrofit taken from the UTD cost estimate.^ The number of vessels required was calculated
using fleet factors in the Marine Board document.'' Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
^Operating labor (for incinerator and IG generator) * (2,000 hr/yr) (1 shift/8 hr) (0.5 hr/shift) (S12.96/hr)
(323.8/342.5)(2).2-5'9
'Maintenance for incinerator and IG generator = (2.000 hr/yr) (1 shift/8 hr)(0.5 hr/shift) ($14.26/hr)
(323.8/342.5X2 [for parts])(2) + 64,800.2-5-9
mAssumed pilot light only for incinerator and natural gas for IG generator; cost of natural gas =
$3.43/1,000 ft3.2
DElectricity to run incinerator and inert gas blower fans.
°Calculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs subtotal.^
^Calculated as (0.16275x[capital costs subtotal - piping])-I-(0.1I75x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-11. CAPITAL AND ANNUAL COSTS: MODEL 7Ba
(1987 Dollars)
Lowb
Higbb
I. CaDilal Costs
Installed equipment costs, S, 1987
i. Incinerator0
490,000
490,000
2. Inert gas (IG) generator''
684,000
684.000
3. Water systemc
29,200
29,200
4. Other major equipment^
534,000
534,000
5. Piping^
414,000
1.370,000
6. Instrumentation*1
96,700
96,700
•
Engineering, startup, contingencies'
562,000
801,000
Subtotal (terminal-only capital costs)
2,810,000
4,000,000
Associated vessel total capital investment'
10,300,000
10,300,000
TOTAL CAPITAL INVESTMENT (TCI)
13,100,000
14,300,000
II. Annual Costs, $. 1987
A. Direct
1. Labor^
3,520
3,520
2. Maintenance'
71,500
71,500
3. Natural gasm
210,000
210,000
4. Electricity0
24,700
24,700
B. Indirect ODeratine Costs
1. Overhead0
45,000
45,000
2. Property taxes, insurance, and
112.000
160,000
administration?
3. Capital recovery charged
438,000
590,000
Subtotal (terminal-annual costs)
906,000
1,100,000
Vessel retrofit total annual costs
1,730,000
1,730,000
TOTAL ANNUAL COSTS
2,630,000
2,830,000
ID. Cost Effectiveness
A. Emission reduction, Mg/yr
2,692
2.692
B. Cost effectiveness (incinerator only), $/Mg
340
410
C. Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
980
1,100
-------
TABLE 3-11. (cont inued)
®Costs rounded to throe significant figures; cost effectiveness rounded to two significant figures.
''Total capital and annuaj costs in the "low" column arc lower than those in the "high" column due to shorter
assumed piping runs (see Footnote g below).
cIncinerator cost = (220,400+[l 1.57x14,638])x323.8/342.5; plus 33 percent for installation.
^Capital costs from Richardson's and adjusted for size.^
eCapitaJ cost of brackish water system for inert gas scrubber.
^This category includes fans, valves, and detonation arrestors.2
^Piping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document'):
Dock to incinerator; Model 7B 660 ft to 6,000 ft
h *
"This category includes alarms, probes, and sensors.
|Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost.-
JCost for vessel retrofit taken from the UTD cost estimate2 The number of vessels required was calculated
using fleet factors in the Marine Board document.'' Total Capital Investment (TCI) = (TCI per vessel)
x( vessels) (see Table 3-12).
^Operating labor (for incinerator and IG generator) = (2,000 hr/yr) (1 shift/8 br)(0.5 hr/shift) (Sl2.96/hr)
(323.8/342.5)(2).2-5'9
'Maintenance for incinerator and IG generator = (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)($14.26/hr)
(323.8/342.5)(2 [for parts])(2) + 64.800.2'5'9
mAssumed pilot light only for incinerator and natural gas for IG generator; cost of natural gas =
$3.43/1,000 ft3.2
"Electricity to run incinerator and inert gas blower fans.
°CaJculated as 60 percent of labor and maintenance.^
PFour percent of terminal capital costs.^
^Calculated as (0.16275x[capitaJ costs subtotal - piping]) + (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
-------
TABLE 3-12. CAPITAL AND ANNUAL COSTS: MODEL 5Aa
(1987 Dollars)
Lowb
Highb
1. Capital Costs
Carbon Adsorberc
398,000
398,000
1. Other major equipment^
234,000
234,000
2. Pipinge
50,800
89.700
3. Instrumentation^
49,800
49,800
4. Inert gas system^
0
0
5. Water system'1
0
0
6. Subtotal
733,000
772.000
7. Engineering, startup, contingencies'
183,000
193.000
Subtotal
916,000
964,000
Associated vessel total capital investment)
7,364,000
7.360.000
TOTAL CAPITAL INVESTMENT (TCI)
8,280,000
8.330.000
II. Annual Costs
1. Maintenance'1
36,200
36,200
2. Steam'
43,700
43.700
3. Electricity1"
89,700
89,700
4. Cooling water"
5,000
5,000
5. Carbon replacement0
48,900
48.900
6. LaborP
1,760
1.760
7. Overhead^
22,800
22,800
8 Property taxes, insurance, administrationr
36,600
38,600
9. Capital recovery charges
133,000
139.000
Recovery credit'
(158.000)
(158.000)
Subtotal
260,000
268.000
Vessel retrofit TAC (O&M, CRC. PIT!)
1,290,000
1.290,000
1.560.000
TOTAL
1,550.000
III. Cost Effectiveness
A. Emission reduction. Mg/yr
985
985
B. Cost effectiveness (adsorber only), $/Mg
260
270
C. Cost effectiveness (adsorber and retrofitting
vessels). $/Mg
1.600
1.600
-------
TABLE 3-12. (continued)
^osts rounded to three significant figures; cost effectiveness rounded to two significant figures.
^Total capital and annua] costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote e below).
cCarbon adsorber cost calculated based on procedures outlined in the OAQFS Control Cost Manual.4 Includes
cost of adsorber plus ductwork and other necessary equipment not included with the unit.
^This category includes fans, valves, and detonation arrestors."
ePiping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document'):
Dock to adsorber: Model 5A 660 ft to 1,400 ft
^This category includes alarms, probes, and sensors.
8\ot necessary.
{'Not necessary.
^Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost."
JCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in tbe Marine Board document.'' Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
^Maintenance for carbon adsorber = (2,000 hr/yr) (1 shift/8 hr)
(0.5 hr/shi ft)($ 14.26/hr)(323.8/342.5)(2 [for parts]) + 32.800 2-5'9
'Steam cost for steam used during carbon bed regeneration. Calculated based on procedures in the OAQPS
Control Cost Manual and a steam cost of $6/1,000 lb.
mElectricity to run incinerator and inert gas blower fans.
"Cooling water costs are a function of steam usage = 3.43 gal/lb steam X ($43.72/(56/1.000 lb steam)) x
5.20/1000 gal = 55,000
°Carbon replacement costs are based on procedures in the OAQPS Control Cost Manual, a 2-year life, and a
10-percent interest rate.
POperating labor [for carbon adsorber) = (2,000 hr/yr) (1 shift/8 hr)(0.5 hr/shift) (512.96/hr)
(323.8/342.5).2-5-9
^Calculated as 60 percent of labor and maintenance.^
Tour percent of terminal capital costs.'
Calculated as (0.16275x[capitaJ costs subtotal - piping])+ (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
'Recovery credit = 2285 Ib/hr x 2000 hr/yr x 5.08/lb x 0.95 x (323.3/355.4) x 0.50 = $158.200/yr.^-9
-------
TABLE 3-13. CAPITAL AND ANNUAL COSTS: MODEL 5Ba
(1987 Dollars)
Lowb
Highb
].
Capital Costs
Carbon Adsorber0
264.000
264.000
1.
Other major equipment^
159,000
159,000
2.
Piping®
25,800
45,800
3.
Instrumentation*
35,200
36.200
4.
Inert gas system®
0
0
5.
Water system*1
0
0
6.
SubtotaJ
485,000
505.000
7.
Engineering, startup, contingencies' "
121,000
126,000
Subtotal
606,000
631,000
Associated vessel total capital investment)
3,680,000
3,680,000
TOTAL CAPITAL INVESTMENT (TCI)
4,290,000
4,310,000
n
Annual Costs
J.
Maintenance*1
36,200
36,200
2.
Steam'
21,900
21,900
3.
Electricity™
22,600
22.600
4.
Cooling water*1
2,500
2,500
5.
Carbon replacement0
24,400
24,400
6.
Labor?
1,760
1.760
7.
Overhead^
22,800
22,800
8.
Property taxes, insurance, administration1^
24,200
25,200
9.
Capital recovery charges
90,600
93,700
Recovery credit®
(79,100)
(79,100)
Subtotal
168,000
172,000
Vessel retrofit TAC (O&M, CRC, PITI)
643,000
643,000
TOTAL
811,000
815,000
in.
Cost Effectiveness
A.
Emission reduction, Mg/yr
492
492
B.
Cost effectiveness (incinerator only), $/Mg
340
350
C.
Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
1,600
1,700
-------
TABLE 3-13. (continued)
*Costs rounded to three significant figures; cost effectiveness rounded to two significant figures.
'Total capital and annual costs in the "low" column are lower than those in the 'high" column due to shorter
assumed piping runs (see Footnote e below).
cCarbon adsorber cost calculated based on procedures outlined in the OAQPS Control Cost Manual.4 Includes
cost of adsorber plus ductwork and other necessary equipment not included with the unit.
^This category includes fans, valves, and detonation arrestors.~
^ping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document'):
Dock to adsorber: Model 5B 660 ft to 1,400 ft
fThis category includes alarms, probes, and sensors.
®Not necessary.
hNot necessary.
'Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost.'
¦ICost for vessel retrofit taken from the LTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.' * Total Capital Investment (TCI) = (TCI per vessel)
xfvessels) (see Table 3-12).
^Maintenance for carbon adsorber = (2,000 hr/yr)( I shift/8 hr)(0.5 hr/shift)($14.26/hr)(323.8/342.5)(2 [for
parts]) + 32.800.2-5'9
'steam cost for steam used during carbon bed regeneration. Calculated based on procedures in the OAQPS
Control Cost Manual and a steam cost of $6/1,000 lb.
mElectricity to run incinerator and inert gas blower fans.
nCooling water costs are a function of steam usage = 3.43 gal/lb steam X ($2l.86/($6/|,000 lb steam)) x
$.20/1000 gal = S5.000
°Carbon replacement costs are based on procedures in the OAQPS Control Cost Manual, a 2-year life, and a
10-percent interest rate.
POperating labor (for carbon adsorber)= (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)($ 12.96/hr)(323.8/342.5).-'^
^Calculated as 60 percent of labor and maintenance.^
rFour percent of terminal capital costs.^
sCalculated as (0.1627Sx[capitai costs subtotal - piping]) + (0.1175x(piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 yean.
'Recovery credit = 1143 lb/hr x 2000 hr/yr x $.08/lb x 0.95 x (323.8/355.4) x 0.50 =• $79,100/yr.9
-------
TABLE 3-14. CAPITAL AND ANNUAL COSTS: MODEL 5Ca
(1987 Dollars)
Lowb
Highb
I. CaoitaJ Costs
Carbon Adsorberc
183,000
183,000
1. Other major equipment^
118,000
118,000
2. Pipinge
16,900
31,400
3. Instrumentation^
29,500
29,500
4. Inert gas system®
0
0
5. Water system'1
0
0
6. Subtotal
347,000
362,000
7. Engineering, startup, contingencies1
86,800
90,500
Subtotal
434,000
453.000
Associated vessel total capital investment'
1,840,000
1,840,000
TOTAL CAPITAL INVESTMENT (TCI)
2,270,000
2,290,000
~ . Annual Costs
1. Maintenance^
34,500
34,500
2. Steam'
5,460
5,460
3. Electricity"
2,880
2,880
4. Cooling water11
625
625
5. Carbon replacement0
12,200
12,200
6. LaborP
881
881
7. Overhead^
21,200
21.200
8. Property taxes, insurance, administration1-
17,400
18,100
9. Capital recovery charge5
66,400
68.700
Recovery credit1
(19,800)
(19,800)
Subtotal
142.000
145.000
Vessel retrofit TAC (O&M, CRC, PITI)
321,000
321.000
TOTAL
463,000
466.000
10. Cost Effecti veness
A. Emission reduction, Mg/yr
246
246
B. Cost effectiveness (incinerator only), $/Mg
580
590
C. Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
1,900
1,900
-------
TABLE 3-14. (continued)
^osls rounded to three significant figures; cost effectiveness rounded to two significant figures.
''Total capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote e below).
cCarbon adsorber cost calculated based on procedures outlined in the OAQPS Control Cost Manual.4 Includes
cost of adsorber plus ductwork and other necessary equipment not included with the unit.
^This category includes fans, valves, and detonation arrestore.2
ePiping costs are taken from LTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from LTD cost
document*):
Dock to adsorber: Model 5C 660 ft to 1,400 ft
'This category includes alarms, probes, and sensors.
SNot necessary.
^Not necessary.
'Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of
installed equipment cost.2
JCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.*' Total Capital Investment (TCI) — (TCI per
vessel)x(vessels) (see Table 3-12).
^Maintenance for carbon adsorber = (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)(S14.26/hr)(323.8/342.5)
(2 [for parts])(2) + 32,800.2-5'9
'Steam cost for steam used during carbon bed regeneration. Calculated based on procedures in the OAQPS
Control Cost Manual and a steam cost of $6/1,000 lb.
mE!ectricity to run incinerator and inert gas blower fans.
"Cooling water costs are a function of steam usage = 3.43 gal/lb steam X ($5.90/(56/1,000 lb steam)) x
$.20/1000 gal = $675
0Carbon replacement costs are based on procedures in the OAQPS Control Cost Manual, a 2-year life, and a
10-percent interest rate.
POperating labor (for carbon adsorber) ¦ (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)($12.96''hr)
(323.8/342.5).2-5-9
^Calculated as 60 percent of labor and maintenance.'
rFour percent of terminal capital costs.^
Calculated as (0.16275x[capital costs subtotal - piping]) + (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
'Recovery credit = 1143 lb/hr x 1000 hr/yr x 5.08/lb x 0.95 x (323.8/355.4) x 0.50 = $19,800/yr.9
-------
TABLE 3-15. CAPITAL AND ANNUAL COSTS: MODEL 7Aa
(1987 Dollars)
Lowb
Highb
I. CaDitaJ Costsc
Carbon Adsorber
452,000
452.000
1. Other major equipment''
337,000
337,000
2. PipiDge
144,000
499,000
3. Instrumentation^
69,600
69,600
4. Inert gas system^
0
0
5. Water system'1
0
0
6. Subtotal
1,000,000
1,360,000
7. Engineering, startup, contingencies'
250,000
340.000
Subtotal
1,250,000
1,700,000
Associated vessel total capital investment'
3,300,000
3,300,000
TOTAL CAPITAL INVESTMENT (TCI)
4.550,000
5,000,000
II. Annual Costs
1. Maintenance'5
34,500
34,500
2. Steam'
23,500
23,500
3. Electricity®
37,100
37,100
4. Cooling water0
2,690
2.690
5. Carbon replacement0
46,900
46,900
6. LaborP
881
881
7. Overhead^
21,200
21,200
8. Property taxes, insurance, administration1"
50,000
68,000
9. Capital recovery charges
184,000
241,000
Recovery credit'
(85,200)
(85.200)
Subtotal
316.000
390.000
Vessel retrofit TAC (O&M, CRC, PITI)
1,290,000
1.290,000
TOTAL
1,601,000
1,680,000
ID. Cost Effectiveness
A. Emission reduction, Mg/yr
1,061
1.061
B. Cost effectiveness (incinerator only), $/Mg
300
370
C. Cost effectiveness (incinerator and retrofitting
vessels), S/Mg
1,500
1,600
-------
TABLE 3-15. (continued)
^osts rounded to three significant figures; cost effectiveness rounded to two significant figures.
^TotaJ capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (see Footnote e below).
cCarbon adsorber cost calculated based on procedures outlined in the OAQPS Control Cost Manual.1* Includes
cost of adsorber plus ductwork and other necessary equipment not included with the unit.
''This category includes fans, valves, and detonation arrestors.^
ePiping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document1):
Dock to adsorber: Model 7 A 660 ft to 6,000 ft
*This category includes alarms, probes, and sensors.
^Not necessary.
^Not necessary.
'Engineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost."-
-ICost for vessel retrofit taken from the UTT> cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.'' Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
^Maintenance for carbon adsorber = (2.000 hr/yr)(l shifl/8 hr)(0.5 hr/sbift)($14.26/hr)(323.8/342.5)
(2 [for parts]) + 64,800.2'^'9
'steam cost for steam used during carbon bed regeneration. Calculated based on procedures in the OAQPS
Control Cost Manual and a steam cost of $6/1,000 lb.
^Electricity to run incinerator and inert gas blower fans.
°Cooling water costs are a function of steam usage = 3.43 gal/lb steam X ($23.52/(S6/l ,000 lb steam))
* $.20/1000 gal =¦ $5,000
0Carbon replacement costs are based on procedures in the OAQPS Control Cost Manual, a 2-year life, and a
10-percent interest rate.
POperating labor (for carbon adsorber) = (2,000 hr/yr) (1 shift/8 hr)(0.5 hr/shift) ($12.96/hr)
(323.8/342.5).2^'9
^Calculated as 60 percent of labor and maintenance.^
rFour percent of terminal capital costs.'
Calculated as (0.16275x [capital costs subtotal - piping]) + (0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
'Recovery credit » 1230 lb/hr x 2000 hr/yr x $.08/lb x 0.95 x (323.8/355.4) x 0.50 = $85,200/yr.9
-------
TABLE 3-16. CAPITAL AND ANNUAL COSTS: MODEL 7Ba
(1987 Dollars)
Lowb
Highb
1. CaDital Costs
Carbon Adsorber0
783,000
783,000
. 1. Other major equipment^
534,000
534,000
2. Pipinge
174,000
582,000
3. Instrumentation^
96,700
96,700
4. Inert gas system®
0
0
5. Water system'1
0
0
6. Subtotal
1,590,000
2,000.000
7. Engineering, startup, contingencies'
397,000
500.000
Subtotal
1,990,000
2.500.000
Associated vessel total capital investment)
10,300.000
10,300,000
TOTAL CAPITAL INVESTMENT (TCI)
12.300,000
12.800,000
II. Annual Costs
1. Maintenance^
36,200
36,200
2. Steam'
43,700
116,000
3. Electricity01
479,000
479,000
4. Cooling water11
13,300
13,300
5. Carbon replacement0
116,000
116,000
6. Labor?
1,760
1,760
7. Overhead^ •
22,800
22,800
8. Property taxes, insurance, administrationr
76,600
100,000
9. Capital recovery charges
283,000
348,000
Recovery credit'
(420,000)
(420,000)
Subtotal
728,000
812,000
Vessel retrofit TAC (O&M, CRC, PIT!)
643,000
643,000
TOTAL
1,370,000
1,460,000
ID. Cost Effectiveness
A. Emission reduction, Mg/yr
2,613
2,613
B. Cost effectiveness (incinerator only), $/Mg
280
310
C. Cost effectiveness (incinerator and retrofitting
vessels), $/Mg
520
560
-------
TABLE 3-16. (continued)
' '¦
^osls rounded to three significant figures; cost effectiveness rounded to two significant figures.
''Total capital and annual costs in the "low" column are lower than those in the "high" column due to shorter
assumed piping runs (sec Footnote e below).
cCarbon adsorber cost calculated based on procedures outlined in the OAQPS Control Cost Manual.** Includes
cost of adsorber plus ductwork and other necessary equipment not included with the unit.
^This category includes fans, valves, and detonation arrestors.2
ePiping costs are taken from UTD cost estimate. Costs assumed linear on a per-foot basis. Lengths varied as
follows (shorter distance determined from cost sensitivity analysis; greater distance from UTD cost
document1):
Dock to adsorber; Model 7B 660 ft to 6,000 ft
%hjs category includes alarms, probes, and sensors.
^Not necessary.
''Not oecessarv.
i " ^
jEngineering = 10 percent, startup = 10 percent, and contingencies = 5 percent of installed equipment cost.i
JCost for vessel retrofit taken from the UTD cost estimate.2 The number of vessels required was calculated
using fleet factors in the Marine Board document.11 Total Capital Investment (TCI) = (TCI per vessel)
x(vessels) (see Table 3-12).
''Maintenance for carbon adsorber = (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)($14.26/hr)(323.8/342.5)
(2 [for parts]) + 64.800.2-5 9
'Steam cost for steam used during carbon bed regeneration. Calculated based on procedures in the OAQPS
Control Cost Manual and a steam cost of $6/1,000 lb.
mElectricity to run incinerator and inert gas blower fans.
"Cooling water costs are a function of steam usage = 3.43 gal/lb steani X ($116.30'($6/1,000 lb steam)) x
$.20/1000 gal = $13,300
°Carbon replacement costs are based on procedures in the OAQPS Control Cost Manual, a 2-year life, and a
10-percent interest rate.
POperating labor (for carbon adsorber) = (2,000 hr/yr)(l shift/8 hr)(0.5 hr/shift)(S12.96/hr)
(323.8/342.5).2-5-9
^Calculated as 60 percent of labor and maintenance.^
rFour percent of terminal capital costs.^
Calculated as (0.16275x[capitaJ costs subtotal - piping])+(0.1175x[piping]) based on an interest rate of
10 percent, an equipment life of 10 years, and a piping life of 20 years.
'Recovery credit = 6066 lb/hr x 2000 hr/yr x $.08/lb x 0.95 x (323.8/355.4) x 0.50 = $420,000/yr.9
-------
TABLE 3-17. CAPITAL COSTS COMPARISON (MODEL TERMINAL 5A):
INCINERATION VS. CARBON ADSORPTION
Capital cost components
Incineration,
$000a
Carbon
adsorption, $000b
• Incinerator/adsorber
329
398
• Inert gas generator
167
0
• Water system
16
0
• Other major equipment
241
234
• Piping
228
90
• Instrumentation
50
50
• Engineering, startup,
contingencies
257
193
Subtotal (terminal onlv
capital costs)
1, 290
964
• Vessel retrofit TCI
7, 360
7,360
Total Caoital Investment
8, 650
8,330
documentation of capital costs for incineration-based system
is provided in Attachment 4.
^Documentation of capital costs for carbon adsorption-based
system is provided in Attachment 3.
-------
TABLE 3-18. TOTAL ANNUALIZED VESSEL RETROFIT COSTS
Throughput,
mm bbl/yr
Model
vessels, No.
Fleet factors'
No. of vessels^
Total annual cost per vessel
thousands of dollarsc
Total annualized
cost, thousands of
dollars
1 Model
Ship
Barge
Ship
Barge
Ship
Barge
I SA
16
4
—
1,000
--
43.84
-
29.3
1,286
I 58
8
4
—
1.000
21.92
-
29.3
643
J 5C
4
4
-
1,000
--
10.96
-
29.3
321
| 6A
70
1
25,000
--
7.67
-
24.5
-
188
| 6B
8
4
—
1,000
--
21.92
--
29.3
643
1 6C
4
4
-
1.000
--
10.96
--
29.3
321
| 7 A
29
2, 4'
20.000
1.000
3 42
10.96
64.4
29.3
542
1 7B
66
2. 4
20.000
1,000
6 85
43 84
64.4
29 3
1,727
aFleet factors tie rough estimates of the average vessel throughput of cargo per day.
^Number of vessels = throughput/fleet factor/365.
-------
TABLE 3-19. ANNUAL COSTS COMPARISON (MODEL TERMINAL 5A):
INCINERATION VS. CARBON ADSORPTION
rs ¦ .n——
Annual cost components
Incineration,
$000a
Carbon
adsorption, $000b
Labor
3.5
1.8
Maintenance
39.5
36.2
Natural gas
56.7
0
Electricity
5.3
89 .7
Steam
0
43 . 7
Cooling water
0
5 . 0
Carbon replacement
0
48.9
Overhead
25.8
22 . 8
Property taxes,
insurance
51. 5
38 . 6
Capital recovery charge
199
139
Recovery credit
0
(158)
Subtotal (terminal only
annual costs)
382 *
267
Vessel retrofit TAC
1,290
1, 290
Total Annual Costs
1,670
1, 550
documentation of capital costs for incineration-based system
is provided in Attachment 4.
^Documentation of capital costs for carbon adsorption-based
system is provided in Attachment 3.
-------
TABLE 3-20. NATIONWIDE CAPITAL AND ANNUAL COSTS AND
COST EFFECTIVENESS
Capital cost, mm $/yr
Annual cost, m $/yr
Cost effectiveness. $/\1ga
Terminals only
2,120-2,740
565-669
10,700-12,700
Vessels only
493
84.2
—
Total (terminals and vessels)
2.610-3.230
649-753
12,300-14.300
aBased on an annual emission reduction of 52,600 Mg/yr: cost effectiveness =
annual cost/emission reduction.
-------
TABLE 3-21. NATIONWIDE ANNUAL COSTS TO CONTROL EMISSIONS3
Model
No. of terminals
assigned to
model
No. of vessels to retrofit
Capital cost of
retrofitting
terminals only,
mm $
Capital cost to
retrofit
associated
vessels, mm $
Capital cost to
retrofit both
terminals and
associated
vessels, mm $
Annual cost of
retrofitting
terminals only,
mm $
Annual cost to
retrofit
associated
vessels, mm $
Annual cost to
retrofit both
terminals and
associated
vessels, mm $
Ships
Barges
5A
9
0
617
11.0-11.6
104
114.6-115.3
3.68-3.79
18.1
21.8-21.9
SB
14
0
214
13.3-14.0
36.0
49.3049.9
3.88 3.99
6.28
10.2-10.3
5C
908
0
690
721-744
116
837-860
199-203
20.2
219.223
6A
18
51
0
14.7-46 4
8.62
23.3-55 0
3.89-9 17
1.26
5.15-10 4
6B
6
0
124
7.60-7.98
20.8
28.4-28.8
2 21-2.28
3.64
5 86-5.92
6C
187
0
170
149-153
28.6
177-182
41.0-41.8
4.99
46.0-46.8
7A
649
146
467
1,183-1,736
141
1,324-1,877
307-399
23.1
330-422
7B
6
26
167
16 9-24.0
39.1
56.0-63.1
4.90-6.09
6.57
11.5-12.7
TOTAL
1,799
223
2,449
2,120-2,740
493
2,610-3,230
565-669
84.2
649-753 1
-------
3.5 REFERENCES FOR CHAPTER 3
1. Controlling Hydrocarbon Emissions from Tank Vessel
Loading. Marine Board, National Research Council. 1987.
p. 108-130, 243-254.
2. Scoping Quality Cost Estimate for Marine Vapor Control
Systems. United Technical Design. April 1987. pp. 3-11,
21-77.
3. Telecon. Kapella, D., MRI, with Elsman, R., Huntington
Energy Systems, Inc. April 5, 1990. Discussion of
regenerative incinerator operations.
4. Telecon. Kapella, D., MRI, with Yundt, G., Regenerative
Environmental Equipment Company, Inc. May 2, 1990.
Discussion of regenerative incinerator operations.
5. Vatavuk, W. OAQPS Control Cost Manual, Fourth Edition.
Publication No. EPA-450/3-90-006. U. S. Environmental
Protection Agency. January 1990. pp. 3.43-3.46.
6. Process Plant Construction Estimating Standards, 1984 ed.
San Marcos, California. Richardson Engineering Services,
Inc. 1984. Account 15-43. pp. 1-23, Account 100-245,
p*. 6.
7. Brochure. Industrial Gas Systems. Inert Gas Generators.
Brochure of design and operating parameters of inert gas
generators. Undated.
8. Industrial News Series. Monthly Energy Review. October
1988. Publication No. DOE/EIA-0035 (88/10). Energy
Information Agency, Division of United States Department
of Energy.
9. Chemical Engineering. Economic Indicators. June 1989.
p. 224. 1984, 1987, and 1989 Annual Indices.
10. Perry, R. H., and D. Green, eds. Perry's Chemical
Engineers' Handbook, 6th ed. McGraw-Hill Book Company.
1984. p. 6-7.
-------
4.0 REGULATORY ALTERNATIVES
4.1 INTRODUCTION
The purpose of this chapter is to present the regulatory
options that have been developed by EPA. The regulatory
alternatives in this chapter represent the various courses of
action that EPA could take in regulating air emissions from
marine vessel loading operations. The environmental, cost, ana
economic impacts associated with the application of these
alternatives to marine vessel loading operations are based on
data presented in previous chapters. The EPA has developed cost
and emissions estimates for each facility based on the models
discussed in previous chapters. Therefore, the impacts of the
regulatory alternatives are based on the models' approximating
actual terminals.
Data in the EPA marine vessels data base includes
information on 1,648 marine terminals that load liquids in one of
thirteen commodity categories determined to emit volatile organic
compounds (VOC's) and/or hazardous air pollutants (HAP's). The
current data base is a portion of the 1988 Waterborne Commerce of
the United States (WCUS) data base that is maintained by the Army
Corps of Engineers' Statistics Center. The data base has
information on commodity, annual barge throughput, annual tanker
throughput, state, and amount of crude oil unloaded annually.
Annual costs and emissions were estimated based on commodity and
barge throughput.
4.2 REGULATORY ALTERNATIVES
Table 4-1 presents the regulatory alternatives developed by
EPA to evaluate the environmental and cost impacts of potential
emissions controls on marine vessel loading operations. The
-------
regulatory alternatives represent incremental increases in the
commmodity throughput cutoffs that are applicable to marine
vessel loading operations when moving from Regulatory
Alternative A to Regulatory Alternative E. The control level for
the regulatory alternatives is 98 percent removal efficiency.
The cutoff levels refer to a terminal's total annual throughput
of the stated commodity categories. Any terminal annually
loading greater than the cutoff for a given commodity category
will be subject to the regulation. Cutoffs have been grouped in
the regulatory alternatives such that the economic impacts on the
terminals loading the affected commodities are similar.
The regulatory alternatives are presented in decreasing
order of stringency. Regulatory alternative A represents the
maximum level of nationwide control. At this control level, an
estimated 98 percent of air emissions from marine vessel loading
operations would be captured and controlled; there are no cutoffs
and all commodity categories are controlled. All facilities in
the current data base would be subject to the regulation.
Regulatory Alternative B limits the commodity categories to be
controlled and has annual throughput cutoffs. The commodity
categories to be controlled are the four with the highest
emission factors. Regulatory Alternatives C, D, and S would
control only gasoline and crude oil loadings. The only
difference between Regulatory Alternatives C, D, and E is that
the cutoffs become less stringent when moving from Regulatory
Alternative C to Regulatory Alternative E. Under Regulatory
Alternative S, an estimated 70 percent of air emissions would be
controlled. Table 4-1 presents all the regulatory alternatives
and expected VOC emissions reductions. Tables 4-2 to 4-4 present
the same regulatory alternatives for VOC and HAP emissions along
with different scenarios for the control of the Alyeska facility.
The emissions reduction estimates presented in Table 4-1 are
based on the assumption that vapors are thermally destroyed. If
a recovery technology were used, the emissions reductions would
decrease slightly.
-------
The Alyeska facility represents 53 percent of the nationwide
uncontrolled emissions and 27 million dollars in annual costs if
vapors are to be incinerated. If Alyeska is included as a
controlled facility, Regulatory Alternatives A and B would
constitute major rules (annual costs of 100 million dollars or
greater). If Alyeska remains uncontrolled, only Regulatory
Alternative A would be a major rule.
The average terminal affected by Regulatory Alternative E
has annual emissions in excess of 100 megagrams [Mg]. For
Regulatory Alternatives D and C, the average terminal affected by
moving to a more stringent regulatory alternative has annual
emissions in excess of 100 Mg. The average terminal affected by
moving to Regulatory Alternative B or A does not have annual
emissions in excess of 100 Mg.
-------
TABLE 4-1. REGULATORY ALTERNATIVES VOC'aa
Alyeska: Incineration
Other terminals: Incineration
Alaska terminals: Controlled
Alternatives
VOC
emissions
reduction,
Mg/yrc
Percent VOC
emissions
reduction0
No. of
affected
terminals
Costs, $ millions'5
Cost
effective-
ness, $/Mg
Incremental
cost effectiveness,
$/Mg
Capital''
Annual"
A. All terminals
73,500
98
1.780
3.200
750
10,000
82.000
B. Gasoline >0.5 MM bbl/yr
Tolueoe >0.5 MM bbl/yr
Alcohols >1.5 MM bbl/yr
Crude oil >5 MM bbl/yr
65,600
87
104
560
99
1,500
8,400
C. Gasoline > 1 MM bbl/yr
Crude oil > 10 MM bbl/yr
63,100
84
60
470
78
1,200
4,500
D. Gasoline >5MMhbl/yr
Cmde oil > 100 MM bbl/yr
57,100
76
25
340
51
890
2,100
E. Gasoline > 10 MM bbl/yr
Crude oil >100 MM bbl/yr
52.400
70
13
290
41
780
N/A
'Terminals affected by proposed or promulgated state regulations are not included in the above cosl and emission estimates, with the exception of
terminals located in'Alaska. Assumes Alyeska uses incineration.
''Capital and annual costs were developed for both carbon adsorption and incineration. Because the difference in costs between incineration and
carbon adsorption is only 3 percent, only the incineration costs arc presented here,
tables show 98 percent control efficiency, standard for incineration and achievable with carbon adsorption.
-------
TABLE 4-2. REGULATORY ALTERNATIVES VOC'sa
Alyeska: Uncontrolled
Other terminals: Incineration
Alaska terminals: Uncontrolled
N Alternatives
VOC
emissions
reduction,
Mg/yr
Percent VOC
emissions
reduction
No. of
affected
terminals
Costs, $ millions''
Cost
effective-
ness, $/Mg
Incremental
cost effectiveness,
$/Mg
Capital
Annual
DA. All terminals
32,600
98
1.777
3,000
720
22,000
82,000
|B. Gasoline >0.5 MM bbl/yr
1 Toluene >0.5 MM bbl/yr
I Alcohols >1.5 MM bbl/yr
Crude oil >5 MM bbl/yr
24,700
74
101
340
70
2,800
8,400
C. Gasoline > 1 MM bbl/yr
Crude oil > 10 MM bbl/yr
22,300
67
58
240
49
2,200
4,500
D. Gasoline >5 MM bbl/yr
Crude oil > 100 MM bbl/yr
16,300
43
23
110
22
1,500
2,100
E. Gasoline > 10 MM bbl/yr
Crude oil > 100 MM bbl/yr
11,600
29
II
58
12
1,200
N/A
aTerminals affected by proposed or promulgated state regulations are not included in the above cost and emission estimates.
''Capital and annual costs were developed for both carbon adsorption and incineration. Because the difference in costs between incineration and
carbon adsorption is only 3 percent, only the incineration costs are presented here.
-------
TABLE 4-3. REGULATORY ALTERNATIVES TOXICSa
Alyeska: Incineration
Other terminals: Incineration
Alaska terminals: Controlled
Alternatives
HAP emissions
reduction, Mg/yr
Percent HAP
emissions
reduction0
No. of affected
terminals
Costs, $ millions**
Cost effectiveness,
S/Mg
Capital''
Annual^
A. All terminals
7,770
98
1,780
3,200
750
97,000
B. Gasoline >0.5 MM bbl/yr
Toluene >0.5 MM bbl/yr
Alcohols >1.5 MM bbl/yr
Crude oil >5 MM bbl/yr
7,040
79
104
560
99
14,000
C. Gasoline > 1 MM bbl/yr
Crude oil > 10 MM bbl/yr
6,660
64
60
470
78
12,000
D. Gasoline >5 MM bbl/yr
Crude oil > 100 MM bbl/yr
6,200
57
25
340
51
8,200
E. Gasoline > 10 MM bbl/yr
Crude oil > 100 MM bbl/yr
6,000
51
13
240
41
6,900
"Terminals affected by proposed or promulgated state regulations are not included in the above cost and emission estimates,
with the exception of terminals located in Alaska. Assumes Alyeska uses incineration.
''Capital and annual costs were developed for both carbon adsorption and incineration. Because the difference in costs
between incineration and carbon adsorption is only 3 percent, only the incineration costs are presented here.
cTables show 98 percent control efficiency, standard for incineration and achievable with carbon adsorption.
-------
TABLE 4-4. REGULATORY ALTERNATIVES TOXICSa
Alyeska: Uncontrolled
Other terminals: Incineration
Alaska terminals: Uncontrolled
I
-J
Alternatives
HAP emissions
reduction,
Mg/yr
Percent HAP
emissions
reduction0
No. of affected
terminals
Costs, $ millions'3
Cost effectiveness,
$/Mg
Capital
Annual
A. All terminals j
2,850
98
1,777
3,000
720
250,000
B. Gasoline , >0.5 MM bbl/yr
Toluene >0.5 MM bbl/yr
Alcohols >1.5 MM bbl/yr
Crude oil | >5 MM bbl/yr
2,120
64
101
340
70
33,000
1
C. Gasoline | > 1 MM bbl/yr
Crude oil 1 > 10 MM bbl/yr
1,740
38
58
240
49
28,000
D. Gasoline >5 MM bbl/yr
Crude oil > 100 MM bbl/yr
1,280
26
23
110
22
17,000
E. Gasoline > 10 MM bbl/yr
Crude oil > 100 MM bbl/yr
1,060
16
II
58
12
11,000
"Terminals affected by proposed or promulgated state regulations are not included in the above cost and emission estimates.
^Capital and annual costs were developed for both carbon adsorption and incineration. Because the difference in costs
between incineration and carbon adsorption is only 3 percent, only the incineration costs are presented here.
-------
TABLE 4-5. SECONDARY AIR IMPACTS BY REGULATORY ALTERNATIVES'1
Alyeska; Incineration
Other terminals: Incineration
Alaska terminals: Controlled
I
QD
:
1
1
Alternatives j
Annual
sox
emissions
Mg/yr
Annual
NOx
emissions
Mg/yr
Annual
CO
emissions
Mg/yr
Total Annual
SOx> NOx, and CO
emissions
Mg/yr
Annual
co2
emissions
Mg/yr
A.
All terminals
69
265
250
584
229.000
B.
Gasoline :
Toluene
Alcohols
Crude oil
>0.5 MM bbl/yr
>0.S MM bbl/yr
> 1.5 MM bbl/yr
>5 MM bbl/yr
65
132
125
322
204,000
C.
Gasoline
("rude oil
> 1 MM bbl/yr
> 10 MM bbl/yr
64
124
117
305
196.000
D.
Gasoline
Crude oil
> 5 MM bbl/yr
> 100 MM bbl/yr
61
105
99
265
177,000
E.
Gasoline
Crude oil
> 10 MM bbl/yr
> 100 MM bbl/yr
61
96
91
248
«
163,000
aTcrminaIs affected by proposed or promulgated state regulations are not included in the above emission estimates, with the exception of terminals
located
in Alaska. Assumes Alyeska uses incineration.
-------
5.0 ECONOMIC IMPACT ANALYSIS
This chapter contains estimates of the economic impact of
five regulatory alternatives for controlling emissions from
loading operations at marine terminals. The analysis is
performed in conformity with Executive Order 12291, the
Regulatory Flexibility Act and within an economic analysis
framework explained in the methodology section. Economic impacts
of the proposed regulatory alternatives estimated in this
analysis include: price changes, output and market shifts, and
potential small business and employment impacts.
This chapter is organized as follows. Section 5.1 is a
summary of the impacts. Section 5.2 is a description of the
methodology utilized in estimating impacts. Section 5.3 defines
the coverage of the industry regarding economic impacts.
Sections 5.4 through 5.7 cover the impact categories in the order
of prices, market impacts, small business and employment.
Section 5.8 describes concurrent legislation and regulations
affecting the marine industry. Section 5.9 considers fifth-year
projections.
5.1 SUMMARY OF ECONOMIC IMPACT ANALYSIS
This analysis estimated the economic impacts of air emission
controls on marine vessel loading operations. Price, output and
employment effects for affected products and for the marine
transport industry were examined. Potential small business
impacts were also isolated. Since these impacts differ
considerably from one regulatory alternative (RA) to another,
-------
Table 5-1 was constructed to facilitate the discussion of these
differences. Table 5-1 reports impact information for the
scenario with all terminals impacted except those covered by
present regulations in California, Louisiana, New Jersey, and
Pennsylvania.
Maximum price increase levels summarized in Table 5-1 for
the affected products would not be significant across all
regulatory alternatives. Under RA A the increases average
1 percent (ranging to 1.8 percent) but decrease quickly to 0.2 to
0.6 percent under the other four RA's.
Corresponding with small price changes are small output and
employment changes. Most of the affected products have
moderately inelastic to very inelastic demand which permits
control costs to be passed on to consumers without much change in
their buying behavior.
Although pipeline transport has taken market share from
affected products over the past years, it is expected that this
regulation will only cause very small additional shifts to
pipeline transport. Maximum increases in marine loading and
transport prices are estimated in the range of 15 to 37 percent
for crude oil and products under RA A and 2 to 14 percent under
RA B through RA E. The cost of marine transport compared to the
final product price is relatively small which accounts for the
larger percentage increases for the marine transport sector.
Increases associated with RA B through RA E are not likely
to be high enough to cause the building of new pipelines. In
addition, the marine transport price increases at the higher end
of the price increase range are for small quantities which are
not economical for pipeline transport unless the firm already has
unused pipeline capacity. The increases under RA A would cause
more significant shifts of shipments by pipelines or other
transport modes.
The most noteworthy potential impact of the most stringent
regulatory alternatives considered concerns the smallest
terminals that could be required to control, since control costs
per unit of throughput for small terminals are very high compared
-------
TABLE 5-1. SUMMARY OF IMPACTS BY REGULATORY ALTERNATIVE
Reg. Alt.
Terminals
covered/
throughput, MM
(BBLVyr)
Total cost,
MM
Maximum
percent price
increases
Percent output
reductions
Employment
reductions
No. of
terminals under
competitive
pressure
Impact on vessels
Displacement
potential by
pipeline
A
All
750
0.3-1.8
0.07-0.26
924
> 1,000
High level of dedica-
tion to regulated
products
Some in long run
B
Gasoline >0.5
Crude >5.0
Alcohols > 1.5
Toluene > 10.0
100
0.36
0.32
0.60
0.41
0.03
ND
0.04
165
0-65
Significant level of
dedication
Minimal
C
Gasoline > 1.0
Crude oil > 10.0
79
0.29
0.31
0.02
ND
119
0-30
Moderate level of
dedication
Minimal
D
Gasoline >5.0
Ciude oil > 100
51
0.21
0.18
0.02
ND
<50
0-5
Low level of dedica-
tion
Minimal
E
Gasoline > 10.0
Crude oil > 100
41
0.19
0.18
0.02
ND
<50
0
Low level of dedica-
tion
Minimal
-------
to larger terminals. This could cause some of these terminals to
lose the business of storage and loading these regulated
products. The terminals would not necessarily go out of busi-
ness, but would have to seek other business at perhaps lower
profitability levels. If RA A were chosen, greater than 1,000
terminals would face such competitive pressure and most of those
terminals are small.
For RA B through RA D the analysis showed 65, 30, and
5 terminals that have high average control costs compared to the
other terminals that would be controlled. Under perfectly
competitive markets where there were substitute terminals
available, those 65, 30, and 5 terminals in RA B through D would
be under competitive pressure to switch loading operations to
uncontrolled products, reduce throughput below the cutoffs, or
shift business to other less costly terminals that either exist
nearby or could theoretically be built nearby.
However, several factors exist which make this a market with
less than perfect substitution of terminals. The majority of
terminals in RA B through RA D are likely part of much larger
integrated petroleum companies which may choose to absorb the
higher than average control costs rather than transfer loading to
an independent terminal. Second, some or all of those higher
than average control costs will be offset by the added costs to
transfer the product to what would invariably be a further
terminal. Third, some substitute terminals would either have to
be very large to have significantly lower control costs or there
would have to be one or more nearby small unregulated terminals.
For these reasons the actual number of terminals expected to stop
loading the controlled products is smaller than what the
competitive market analysis shows.
The primary impact on marine vessels will likely be that the
low-retrofit cost vintages of tankers and barges will be
dedicated to transporting the regulated products. Other vessels
will lose the business of transporting the regulated products and
will need to obtain the business in nonregulated products
formerly carried on the dedicated vessels.
-------
Under RA D, small business impacts are not expected to be
significant. The terminals affected by RA D will primarily be
owned by integrated petroleum facilities which tend to be large.
Similarly, RA D will only affect a moderate portion of the vessel
fleet that will transport regulated crude oil and petroleum
products. The portion affected will likely be large, lower-cost
retrofit vessels and the retrofit costs of $0,002 per barrel for
crude and $0,030 for products should not cause a significant
impact.
In terms of total control costs, RA A would be far more
costly (estimated at $750 million) than any of the other RA's.
Regulatory Alternative D has an estimated total cost of
$51 million.
If these three facilities become eligible for exemption the
total cost under RA D would reduce from $51 million to
$22 million. The reduction of $29 million equates to $0.03 per
barrel or $0.0007 per gallon. Thus while total costs would
reduce significantly if such exemptions occur, the percent price
increases for final products will not change significantly.
5.2 METHODOLOGY FOR ESTIMATING ECONOMIC IMPACTS
The purpose of estimating economic impacts is to provide EPA
decision-makers with information as to who bears the costs and
impacts of the proposed regulatory alternatives and in what
magnitude or with what consequences. The imposition of costs on
one industrial sector may cause that sector to change behavior
with regard to the prices it charges, its level of supply to the
market or the makeup of the resources it utilizes to provide the
supply. These behavioral changes may cause impacts on other
sectors as well as on consumers of the output of that sector.
The objective of the analysis is to trace significant changes
through the impacted sections to the consumers, and to measure
the magnitude and consequences of the impact.
The general methodology for this analysis is to first derive
the increase in price that petroleum and chemical producers will
face to transport their products by marine facilities subject to
the regulation. This derivation of price increase will include
-------
factors for the control costs incurred by the marine terminals
and the control costs incurred by the marine vessels. Separate
calculations will be performed for crude oil and products; the
latter defined as refined petroleum products or chemicals. Since
marine transport faces competition from pipelines and to some
extent railroads and trucks, the analysis then focused on whether
or not the cost increases of this regulation would cause an
erosion of the transport market share held by the marine sector.
The next step in the analysis is to determine if certain
terminals or vessels are not expected to retrofit with the
control options because either the impacts on their profits are
prohibitive or because their customers refrain from shipping by
marine because of the control costs. This situation primarily
arises because of the significant control cost differentials per
terminal by size of throughput and for marine vessels because of
the higher annualized costs for older vessels.
Next, the likely price increases for the product consumptive
markets will be calculated and an analysis performed of the
economic impact of these increases. Output changes will be
calculated from assumed or derived price elasticity coefficients.
Employment effects from these output changes will also be
estimated.
Potential small business impacts will then be isolated from
the above impact analysis. Impacts on small businesses depend on
decisions by EPA regarding the threshold level of terminal
throughput or products controlled by the regulation, i.e., which
regulatory alternative is chosen.
Concurrent legislation impacting the regulated products will
be examined. The influence that those regulations have on the
baseline or the impacts of this analysis will be considered.
Finally, consideration will be given to how impacts might
change as a function of what is expected to occur five years from
now in the affected sectors.
The five regulatory alternatives considered in this analysis
consist of combinations of crude oil, gasoline and products that
emit volatile organic compounds and hazardous air pollutants at
-------
facilities of varying size throughput. The alternatives are as
follows:
A. All Terminals
B. Gasoline >500K bbl/yr, Crude Oil >5MM bbl/yr, Toluene
0.5MM bbl/yr and Alcohols >1.5 MM bbl/yr
C. Gasoline >1MM bbl/yr, Crude Oil >10MM bbl/yr
D. Gasoline >5MM bbl/yr, Crude Oil >100MM bbl/yr
E. Gasoline >10MM bbl/yr, Crude Oil >100MM bbl/yr
Regulatory Alternatives A and B are the only alternatives
that directly cover chemicals and products other than gasoline
and crude oil.
5.3 GROUNDRULE FOR ECONOMIC IMPACT OF THIS REGULATION
Economic impact of a regulation is defined as that impact
arising from the incremental expenditures that are attributable
to the regulation and which would not have been undertaken were
it not for the presence of the regulation. Incremental
expenditures are those expenses above and beyond what the
regulated members incur due to their own economic choices or due
to that required by other regulations.
In this instance several States have already promulgated or
proposed regulations to control VOC emissions from marine
terminal loading of petroleum products and other VOC emitting
products. These states include California, Louisiana, New
Jersey, Alaska, and Pennsylvania. Alaska's regulations however
might not require controls before this regulation takes effect.
This analysis will therefore treat the Alaska terminals as being
uncontrolled.
The presence of these state regulations, from an economic
viewpoint, means that the impact of national regulations consists
of the impacts in states where such regulations do not exist and
the impact where the national regulations are more stringent or
more comprehensive than the existing state marine terminal VOC
control requirements. Thus if these state regulations are
assumed to take effect before the forthcoming national regulation
and are as stringent as the national regulation, the economic
impact of the national regulation will consist primarily of the
-------
impact created in states other than California, Louisiana, New
Jersey, and Pennsylvania. The baseline for this analysis is
significantly affected by these state regulations since a
significant amount of marine-loaded crude oil and products are
loaded in these four states.
With regard to specific economic impacts the definition
means that the total costs of the regulation are lessened
considerably because of existing regulations in these states.
However, this operational definition does not always reduce the
impacts on price and output of those products impacted by this
regulation. For example, the price increases for the crude oil
or gasoline controlled at marine facilities in a state such as
Ohio may still be the same even though the already-regulated
states listed above are not being counted. Thus there will be
fewer marine terminal loadings counted as being affected by this
regulation but for those that are counted, the relative size of
impact may be the same as if all loadings are counted.
5.4 POTENTIAL PRICE INCREASES
The initial impact of consideration is by how much will the
prices of the controlled products increase as the marine terminal
and vessel owners pass portions or all of the control cost onto
the product producers who, if market conditions allow, pass those
costs onto consumers. Separate potential price increase
calculations are presented for each of the regulated products or
groups of products under each regulatory alternative. Later on,
market reactions to such price increases are estimated.
For the products subject to this analysis we are assuming
full control cost pass through in the long run. This is
equivalent to assuming a perfectly competitive market
environment. For these products, barriers to entry are not
insurmountable, and domestic and foreign competition is present
in sufficient amounts to support this assumption. To the extent
that imperfect competition exists in the industries affected by
this regulation, not all of the control costs will be passed
through in the form of higher consumer prices.
-------
5.4.1 Crude Oil
Table 5-2 is constructed to show what the potential price
increases might be for barrels of crude oil sold to petroleum
refineries. These price increase estimates are based upon the
average control cost for each regulatory alternative (RA) under
full-cost pass through conditions. Table 5-2 shows that RA A has
average control costs of $0.12 per barrel whereas RA B is
$0.04 per barrel, RA's C, D, and E are $0.03 per barrel. On this
basis the costs of RA A are four times greater than RA's D and E.
With respect to the percent price increases for crude oil
represented by these control costs per barrel, Table 5-2 also
shows percentage increases based upon two crude oil prices per
barrel. Just prior to the Iraq invasion of Kuwait the price per
barrel of oil was $17 to $18.1 Price ranges for crude oil since
then have been from $20 to $39 with more recent prices in the
lower $20's. Table 5-2 shows the percent price increase for two
price levels, $17 and $30.
Regulatory Alternative A would produce a 0.7 percent price
increase when crude oil is $17 per barrel and a 0.4 percent
increase at $30 per barrel. The corresponding increases for RA B
are 0.2 percent and 0.1 percent. For RA C the percent price
increases are 0.2 and 0.1. For RA's D and E the percent price
increases also 0.02 and 0.01, respectively. As will be shown
later it is the high per unit control costs for all the small
terminals in RA A that causes the average cost increases to be
several times higher than the costs for the larger terminals
covered by RA's B thru E.
In absolute terms, even a price increase of 0.7 percent for
RA A may not initially appear to be an increase that would cause
much of an economic impact for petroleum refineries and their
customers. However, what is expected to happen under RA A is
that small terminals would lose business to larger terminals
because of the significant control cost differential by size of
terminal. Thus actual cost increases would not be 0.7 percent
but a lower number somewhat higher than for RA B which is
0.2 percent.
-------
TABLE 5-2. CONTROL COSTS AND PRICK INCREASE PER BARREL CALCULATIONS FOR CRUDE
OIL REGULATORY ALTERNATIVES
Reg. Alt.
Size throughout
tenniruUa
Throughput
volumes, bbl/yr
Annualized control
costs
Average control
cost/bbl throughput
s is . m =_I
Percent potential price increase
$l7/bbl, %
$30/bbl, %
1 A
All
1,384,201.353
163,291,710
0.1180
0.694
0.393
1 B
>5 MM bbl/yr
1,229,557,464
43,034,290
0.0350
0.206
0.116
1 C
> 10 MM bbl/yr
1,199,270,954
39,919,760
00333
0.196
0.110
1 D
>100 MM bbl/yr
883,329,116
29,300,000
0.0301
0.1*77
0.100
I E
> 100 MM bbl/yr
883,329,116
29,300,000
0 0301
0.177
-------
Using individual terminal data for the Case 6 series model
facilities it can be shown how economics of scale for control
cause small plants to have large control costs per barrel vis-a-
vis large plants. Table 5-3 shows the large range in control
cost per barrel for terminals. The range in RA A is far broader
than within the other RA's. Terminal owners who would have to
charge $1.00 per barrel under RA A will lose business to terminal
owners who only need to charge $0.14 per barrel to recover their
costs, (maximum under B) or $0.06 or less per barrel (under RA C,
D and E) as long as either excess capacity exists in the large
terminals or new large terminals are built. The other economic
variable that would prevent many crude oil producers from passing
on the differential control costs under RA A is the presence of
crude oil import potentials. In 1989 the U.S. imported
2.217 billion barrels of crude oil according to the Petroleum
Supply Annual report. The incremental crude oil throughput of RA
A over RA B is 1,384,201,353 barrels less 1,229,557,464 or
154,643 barrels per year (from Table 5-2). This amount is about
7 percent of the 1989 level of imports; an amount within the
capacity of foreign producers and transporters to readily supply.
The present cost to transport crude oil from the middle east
to the U.S. averages $2.65/barrel with a range of $0.88 to $5.30
depending on the availability of vessels.^ In theory it can be
expected that increases in crude oil shipments of 7 percent will
bear a slight increase in marginal costs of perhaps 1 or
2 percent for refinery owners. At $20 per barrel plus $2.65 for
shipping, a 2 percent increase is 0.02 x $22.65 or $0.05 per
barrel. This incremental cost of marginally imported crude oil
is greater than the vapor control cost of RA B ($0.04 per
barrel), RA's C, D and E ($0.03 per barrel} but well less than
the average increase of $0.12 under RA A. Thus petroleum
refiners would find it less costly to import more crude oil than
to pay the control costs of RA A.
-------
TABLE 5-3. CONTROL COST PER BARREL CALCULATIONS FOR CRUDE OIL MODEL FACILITIES AND
REGULATORY ALTERNATIVES
Reg. Alt.
Size throughput
terminals
Range of control cost, $/bbl
throughput
volumes, bbl/yr
No. terminals
6
6B
6C
A
All
0.005-16.433
0.121-0 148
0.158-114,935
1,384,201,353
201 +
B
>5 MM bbl/yr
0.005-0.272
0.121-0.137
NA
1,229,557,464
8
C
> 10 MM bbl/yr
0.005-0.056
NA
NA
1,199,270,954
5
D
> 100 MM bbl//yr
0.006-0.056
NA
NA
883,329,116
3
E
> 100 MM bbl/yr
0.006-0.056
NA
NA
883.329,116
3
Case 6
Case 6B
V Case 6C
H
= All terminals loading cmde oil lo ship s
= Terminals with crude oil throughput of greater than 4 MM bbl/yr but less than 8 MM bbl/yr.
-------
5.4.2 Potential Price Increases for Marine Transport of Crude
Oil
The cost of storage, loading, transporting and unloading
crude oil in the U.S. ranges from $1.10 to $2.30 per barrel
depending on the type of crude oil, length of trip, size of
vessel, etc.3 From Valdez, Alaska to the lower west coast the
transportation cost averages $1.25 per barrel with a range of
$1.10 to $1.50 per barrel.3 The storage and loading cost is
another $0.25 to $0.50 per barrel with an average of $0.30.3
From the Gulf Coast (Louisiana and Texas) to the east coast the
transportation cost is $0.80 to $0.90 per barrel south of Cape
Hatteras and $1.20 per barrel north of Cape Hatteras.3 From
Panama to the east coast the cost is $2.00 per barrel.3 Again
the storage and loading costs of $0.25 to $0.50 per barrel needs
to be added to obtain total marine costs.3
The data in Table 5-4 shows that average marine transport
costs for crude oil, when all terminals are controlled under RA A
will increase 6.54 percent to 10.73 percent. Producers using
large terminals handling more than 5MML bbl/yr will face
increases from 1.94 percent to 3.18 percent. Producers using
terminals handling more than 10 MML bbls/yr will face increases
from 1.85 to 3.03 percent and the largest terminals face a 1.67
to 2.74 percent increase.
Oil
The next part of the analysis examines how these potential
control costs for crude oil will be allocated to the products
derived from crude oil. Table 5-5 shows that when any
combination of control cost per barrel of crude oil is spread
over all the products that a barrel of crude oil yields, the
price increases per gallon are all very small, i.e., well less
than l cent per gallon. Table 5-5 was calculated using the
average control cost for each RA. For example, the 11.80 per
barrel increase for RA A equates to $0.0028 per gallon
(42 gallons per barrel). Since gasoline is 44.67 percent of the
yield from crude oil its proportionate share of the $0.0028 per
-------
TABLE 5-4. POTENTIAL PERCENTAGE PRICE INCREASES IN MARINE
TRANSPORT FOR CRUDE OIL
Reg. Alt.
Average
control cost
per barrel
Percent price increase
$1.10
$1.80
A
$0.1180
10. 73
6.56
B
$0.0350
3 .18
1.94
C
$0.0333
3.03
1.85
D
$0.0301
2.74
1.67
1 .
$0.0301
2.74
1.67
-------
TABLE 5-5. POTENTIAL PRICE INCREASES FOR PRODUCTS PRODUCED FROM CRUDE OIL
Commodity
Yield
in
gallons
Percent o£
total
Regulatory alternatives
A
B
C
D & E
(Average cost increase$/bbl)
0.1180
0.0350
0.0333
0.0001
(Average cost increase $/gln)
Gasoline
19.7
44.67
0 .0013
0.0004
0.0004
0.0003
Distillate
9.0
20 .41
0 .0006
0.0002
0.0002
0.0002
Jet Fuel
3.0
8.62
0 .0002
0.0001
0.0001
0.0001
Residual
3.0
6 .80
0.0002
0.0001
0.0001
0.0001
Still Gas
1.9
4 . 31
0.0001
0.0000
0.0000
0.0000
Coke
1.5
3 .40
0.0001
0.0000
0.0000
0.0000
Feedstocks
1.2
2.72
0.0001
0.0000
0.0000
0.0000
Asphalt
1.3
2 .95
0.0001
0.0000
0.0000
0.0000
LP Gas
1.2
2 .72
0.0001
0.0000
0.0000
0.0000
Lubricants
0.6
1.36
0.0000
0.0000
0.0000
0.0000
Kerosene
0.4
0.91
0.0000
0.0000
0.0000
0.0000
Miscellaneous
0.5
1.13
0.0000
0.0000
0.0000
0.0000
Total
44 . la
100.00
0.0028
0.0008
0.0008
0.007
aCrude oil per barrel is 42 gallons; gain to 44.1 gallons from hydrogen processing gains.
-------
gallon is $0.0013. Similar to earlier analyses RA A induces
larger cost increases for crude oil products than RA's B thru E.
However in all cases potential price increases are all less than
one cent per gallon.
Later-on these price increases will be added to those of the
petroleum products directly controlled to eventually estimate
market impacts.
5.4.4 Potential Product Price Increases
In line with the analysis performed on crude oil, Table 5-6
presents potential price increase estimates for the regulatory
alternatives affecting gasoline, chemicals and other noncrude oil
products covered by the potential regulations. The data in
Table 5-6 shows how, in the far right column, the average control
cost per gallon reduces significantly from RA A to RA E. The
cost in RA A averages 1$ per gallon ($0.0098) whereas the cost
for RA D and RA E is 0.2C per gallon. The throughput and total
control cost for RA A is also much more than for the other
regulatory alternatives. Toluene and methanol would be
controlled under RA A at all size terminals and under RA B at
terminals with throughput of greater than 500,000 barrels per
year. Under RA A the average control cost for toluene is l cent
per gallon and 0.6 cent per gallon under RA B. The corresponding
control cost averages for alcohols, as represented by methanol,
are $0.0098 per gallon for RA A and $0.0031 per gallon under
RA B.
Table 5-7 converts the average control cost per gallon into
percentage price increases for the various products, excluding
the control costs passed-on from the direct control of crude oil.
Gasoline is the only product covered under all the regulatory
alternatives. Under the most comprehensive regulatory
alternative, A, the percent increase for gasoline is 0.9 percent
whereas for RA B through RA E the estimated increasese are
0.3 percent to 0.2 percent.
For toluene the estimated price increases are 0.7 percent
for RA A and 0.4 percent for RA B. The price increases for
methanol are 1.78 percent for RA A and 0.60 percent for RA B.
-------
TABLE 5-6. POTENTIAL PRODUCT PRICE INCREASES
FOR THE VARIOUS REGULATORY ALTERNATIVES
Reg. Alt.
Products
covered
Barrels product
throughput
Total annualized cost
Average
control
cost/BB!
Average
control
cost/Gin
A
All
1,409,182,523
578,731,577
0.4107
0.0098
B
Gasoline
353,254,896
51,888,245
0.1469
0.0035
Toluene
7,984,381
1,963,286
0.2459
0.0059
Alcohols
22,784,510
3,192,820
0.1401
0.0033
C
Gasoline
331,614,783
39,525,863
0.1192
0.0028
D
Gasoline
256,324,426
22,000,000
0.0858
0.0020
E
Gasoline
162,905,309
12,300,000
0.0755
0.0018
All = Gasoline, alcohols, naptha, jet fuel distillate, toluene.
-------
TABLE 5-7. POTENTIAL PRICE INCREASES FOR PRODUCTS
Gasoline
Price/gal, $
Average control cost/gallon
Potential percentage price increase
A
B
C
D
1i
A
B
C
D
E
Gasoline
1.10 (July 1990)
0.0098
0.0035
0.0028
0.0020
0.0018
0.89
0.32
0.25
0.18
0.16
Jet fuel/
kerosene
0.59 (1989)
0.0098
--
--
--
--
1.66
--
-
--
-
Naphtha
1.40(1990)
0.0098
--
--
--
--
0.70
--
-
-
--
Distillate
0.87 (1989)
0.0098
-
-
--
--
1.13
--
--
--
--
Toluene
1.42 (1990)
0.0098
0.0059
-
--
--
0.69
0.41
--
--
Ethylene glycol
3.34(1990)
0.0098
-
--
-
--
0.29
--
~
--
--
Methyl ethyl
ketone
2.14(1990)
0.0098
--
--
--
-
0.46
--
--
--
-
Methanol
0.55 (1990)
0.0098
0 0033
-
--
--
1.78
0.60
-
--
--
Source: (Gasoline) JACA estimates; (Jet Fuel/Kerosene) - U.S. Department of Energy, Energy Information Administration, Annual Outlook for Oil and
Gas. 1990, p. 29; (Naphtha) - Chemical Marketing Reporter, October 26, 1990, p. 34; (Distillate) - U.S. Department of Energy, Energy
Information Administration, Annual Outlook for Oil and Gas. 1990, p. 29; (Toluene) - Chemical Marketing Reporter. October 26, 1990, p. 46;
(Ethylene Glycol) - Chemical Marketing Reporter. October 26, 1990, p. 41; and (Methyl ethyl ketone) - Chemical Marketing Reporter.
-------
For the other products covered by RA A the estimated increases
range from a low of 0.3 percent for ethylene glycol to a high of
1.7 percent for jet fuel and kerosene.
5.4.5 Combined Potential Product Price Increases
To determine the true market price increase for the various
petroleum and chemical products, it is necessary to combine the
derived price increases from crude oil plus the direct control
cost price increases for the products. Because of the very small
increases associated with crude oil it is only meaningful to show
the combined effect for gasoline, distillate, methanol and
toluene in Table 5-8. For gasoline, the crude oil costs add a
0.12 percent price (up to 1.01 percent) under RA A and
0.04 percent or less for RA B through RA E. For distillate the
price increase under RA A from adding crude costs is a plus 0.07
to 1.20 percent and a plus 0.02 percent for RA D. For methanol
the increases from crude oil are 0.02 and less. For toluene the
increases from crude oil are 0.01 percent or less.
5.4.6 Potential Price Increases in the Costs for Marine
Transport of Products
Petroleum products are primarily moved from refineries to
markets by pipeline or by marine vessels. As the petroleum
products get closer to their final destination the shipments
become smaller and are moved primarily by rail or by truck.
Marine transport of products is conducted along all the
coastal routes, i.e., west coast, gulf coast and east coast.
This movement can be by ship or by large-sized barges. Petroleum
products moved on inland waterways are usually performed by
barges. Ships can go up the Hudson River to Albany but that is
one of the few inland waterways that ships can travel.
Marine transport of products is generally performed by ships
or barges that are dedicated to carrying "clean" products. The
cost to transport and unload clean products on the ocean or on
inland waterways ranges from $0.80 to $1.30 per barrel.-* The
storage and loading costs average $0.30 per barrel with a range
of $0.25 to $0.50.3 The loading costs alone only range from
-------
TABLE 5-8. COMBINED POTENTIAL PRICE INCREASES FOR SELECTED PRODUCTS
—¦ ¦ - — — ¦ —=
|Reg. Alt.
A
B
C
D
E
Gasoline
Product control only, %
0.89
0.32
0.25
0.18
0.16
Combined with crude oil, %
1.01
0.36
0.29
0.21
0.19
Distillate ;
Product control only, %
1.13
- -
Combined with crude oil, %
1.20
0.02
0.02
0.02
0.02
Toluene
Product control only, %
0.69
0.41
Combined with crude oil, %
0.70
0.41
0.00
0.00
0.00
Methanol (alcohols)
Product control only, %
1.78
0.60
Combined with crude oil, %
1.80
0 .60
0 .00
0.00
-------
$0.05 to $0.07 per barrel; however, storage costs for a month
range from $0.25 to $0.30 . 3
The potential price increase percentages for marine
transport of product caused by the control requirements is shown
in Table 5-9. The price increases for marine transport
(including loading, transport, unloading and storage) range from
27.4 to 37.4 percent under RA A. For RA B the increases range
from 9.9 percent to 13.6 percent. For RA C the range is 7.9 to
10.8 percent. For RA D and RA E the price increase percentages
range between 5 to 8 percent.
5.5 MARKET IMPACTS
Based upon the average control cost per gallon and
percentage price increase figures derived above, estimates will
be made in this section of any reductions in output in the
affected sectors that could result from increased control costs
for marine-loading of regulated products. The concern about
output changes are with shifts in resources caused by plant
closures and reductions in employment associated with the reduced
output as well as with reduced value of production. Output
reductions will occur to the extent that firms cannot pass
control cost increases on to consumers or because consumers react
to higher product prices by buying less. Output changes among
members of a sector will also be considered, i.e., the distri-
butive effects.
In this economic impact analysis there are three sectors
where market impacts are possible: marine terminals, marine
vessels, and regulated product producers.
5.5.1 Marine Transport Versus Pipeline
The major competition to marine transport of petroleum
products is from pipeline transport. Over the years the share of
the market occupied by pipeline has increased significantly. The
question in this analysis is whether these control costs will
cause a further shift from marine to pipeline. Short run versus
long run considerations are involved.
In the short run it is not expected that shifts to new
pipelines will occur. There is recent empirical evidence for
-------
TABLE 5-9. POTENTIAL PRICE INCREASES FOR MARINE
TRANSPORT OF PRODUCTS
Reg. Alt.
Costs
per barrel3
Percentag
re price
$1.10
$1.50
A
$0,411
37.36
27.40
B
$0,149
13.55
9.93
C
$0.119
10.82
7.93
D
$0,086
7.82
5 . 73
E
$0,076
6.91
5.07
aAverage control cost per size throughput range.
-------
this. Marine transport costs increased significantly during the
Kuwait invasion because diesel costs had increased. Since it
takes less energy per unit to transport by pipeline than marine,
the cost of marine transport relative to pipeline had increased.
The relative increase associated with the diesel fuel increase
was probably larger than the projected relative increase for
these control costs. During this time period all of the surveyed
petroleum companies and marine transport companies indicated that
no shift to pipeline had taken place. The reasons for the lack
of shift are essentially that pipelines have reached equilibrium
with routes that are fixed and they are increasingly difficult to
build. Not only is there high capital cost required for pipeline
construction but the process to obtain the necessary permits is
becoming more difficult due to heightened awareness over
environmental concerns and right of way problems.
In the long run it is not likely that further shifts to
pipeline will occur as an impact of the vapor control costs of RA
B thru RA E. In this case, long run means greater than 8 years,
i.e., the time to obtain approval for and build new pipelines.3
The pipeline building trend seems to have peaked.3 Newer
pipelines will cost more to build because of environmental
concerns, siting resistance, and hillier terrains.3 Another
reason is that pipelines require large volumes of product to be
shipped in order to pay for the large initial capital outlays.
Increases in marine transport costs for the larger volumes of
transported products are around 5 to 14 percent under RA B thru
RA E. At such a relative price increase level pipelines will not
likely be built to try and capture that market.
It is likely however, that the 27.4 to 37.4 percent increase
under RA A for buying marine transported products could be
significant enough to cause some displacement by pipeline
provided enough volume is being transported at those price
increase levels over a long period of time to warrant building a
pipeline. The increases for RA B through RA E are considerably
smaller and far less likely to cause such displacement.
-------
This question is also intertwined for crude oil and products
with the impact of the Oil Pollution Act of 1990 on marine
transport (see Section 5.7.2) and transport insurance
requirements. On the one hand the combined effect of vapor
controls, spill liability and double-hull requirements may be
enough to cause a further shift to pipeline. On the other hand,
for the small number of crude oil loading terminals likely to be
installing controls most of them probably do not compete with
pipelines because the cost of establishing a pipeline is
prohibitively high, e.g., from Valdez, Alaska to Washington,
Oregon, or California and requires large volumes of throughput.
5.5.2 Marine Terminals
Marine terminal output reductions could occur in two ways.
The first is through reductions in final demand for the products
(see Section 5.5.4). Second, the large differential control
costs per terminal under some of the regulatory alternatives
could cause some terminals to not install control systems and
therefore not take business loading crude oil, petroleum products
and regulated chemicals. This impact will be explored in this
section.
Normally, if one firm gives up business to another firm
there is no output change. However, if the control cost
differential is so large in places where multiple terminals do
not readily exist, it could lead to some producers of petroleum
products not being able to economically bring their product to
market. In the meantime, demand would be met through increases
in supply from other sources> domestic and foreign.
According to 1988 preliminary data from the Waterborne
Commerce of the United States, throughput at terminals ranged
from a high of 228,014,897 bbl/yr to as little as 6 bbl/yr,
realizing a total of 1.9 billion bbl/yr for 1988.
Currently, terminal facilities located in the Santa Barbara
channel, the San Francisco Bay area, and the States of Louisiana,
New Jersey, and Pennsylvania are required, or are proposed to be
required, to recover or dispose vapors when loading tankers with
crude oil and gasoline by 1991 and 1992, respectively.
-------
At each port, there can be a number of terminals competing
for business. Utilization of terminal capacity ranges from 20 to
85 percent with no meaningful average.4 This industry is so
competitive that even those companies who are well entrenched
with one facility call around regularly for quotes on storage and
loading costs. However, there is some evidence shown by both
customers and terminallers that they want to enter into longer
term contracts, usually a minimum of 1 year.^ For purposes of
choosing the most appropriate terminal, a commodity owner needs
to consider if a pipeline is nearby or if a ship can be rerouted
to another terminal.
Marine terminals, even though primarily privately owned, are
called either private and public. Private terminals are owned by
major oil companies who are vertically-integrated in the
distribution of their products. A significant portion of these
companies also own liquid bulk terminal facilities not only at
the marine terminals but at points closer to the final refined
product destination. Public terminals are for-hire facilities
where terminallers do not take ownership of the material. They
provide storage for a third party, who typically handles the
movement of the product to and from the terminal as well as the
specifics of the marine or pipeline transport. The supply and
demand of these facilities directly depend on the supply and
demand experienced in the oil business.
In an effort to widen margins, a number of services are
offered by terminallers, for example, storage capacity, transfer
responsibilities for moving the product in and out, cleaning
services performed on the tank after product removal, filtration
of product such as jet fuel and waste handling services. The
number of employees at terminals depends on capacity, amount of
inventory moving in and out, and the type of product. Typically,
petroleum storage is less labor intensive.
Special services like breakbulk repacking might be offered
for products like glycol for the antifreeze market. Special
equipment is available like chillers, nitrogen blankets to keep
«
-------
moisture out, and special linings for tanks or pipelines to
maintain product integrity.
In addition, demurrage rates are charged if they are needed.
They are assessed if a vessel or terminal exceeds the allotted
time for a loading or unloading operation. It is a preagreed
rate that i9 charged for the amount of time in excess to the
preagreed allowed time.
As just analyzed pipeline competition is not expected to
take away marine terminal business. However, the large
differences in control costs among terminals are expected to
cause some small terminal owners to not install control systems
and to lose this business. This potential impact on small
entities will be examined below.
The EPA Regulatory Flexibility Act Guidelines describe steps
for determining whether a regulatory flexibility analysis (RFA)
needs to be performed. The test is if a significant economic
impact is expected to occur on a substantial number of small
entities. The affected sectors for which this will be performed
in this analysis will be marine terminals and marine vessels.
The SBA definition of small marine cargo handling entities is
$12.5 million sales or less. Terminals perform business
transferring many commodities including others that are not
regulated herein and are often part of much larger companies.
Nevertheless this standard will be used in the analysis.
The size distribution of terminals handling petroleum
products and chemicals is as follows. As the data shows
73.8 percent of the terminals (i.e., those less than
500,000 barrels throughput) would only be subject to control
under RA A.
t
-------
Terminals loading petroleum products
Barrels/yr
Percent of total
>10,000,000
3.0
8-9,999,999
0.7
6-7,999,999
1.4
4,5,999,999
2.5
2-3,999,999
5.0
1-1,999,999
6.1
0.5-999,999
7.5
<500,000
73 .8
100
For illustrative purposes, we have chosen level of
4,000,000, 2,000,000, 1,000,000, and 500,000 barrels per year to
determine the relationship of size facility to impacts.
To obtain further insight into the question of size
businesses, data was examined for SIC 4491, Marine Cargo
Handling. This SIC includes public terminals doing business with
many producers as opposed to just the producer who owns them.
1988 County Business Patterns data (Table 5-10) shows
834 establishments in this SIC. Of this number, some will be
owned by large businesses and some will already be subject to
emission controls under state regulations. Some will also not be
transferrers of petroleum and chemical products. It is also
unclear how many of these terminals would be controlled under
each RA. Of the 1,777 terminals subject to RA A the SIC 4491
data would indicate that less than one-half of the terminals are
public terminals.
Table 5-10 shows the distribution of the SIC 4491 terminals
by state. Louisiana, Texas, Florida, and California have the
most terminals, respectively. The table also shows the number of
employees per establishment. The U.S. average for SIC 4491 is
68 employees per establishment.
-------
TABLE 5-10. 1988 COUNTY BUSINESS PATTERNS BY STATE FOR SIC 4491
Toul No. of
Toul
employee* (mid-
Employee* per
Total annual
Pay per employee,
establishments
March)
establishment
payroll, J1,000's
SI.000']
Alabama
19
693
36.5
1.231
16 21
AUsfca
10
388
38.8
15,153
39 05
Arizona
0.0
0 00
Arkaiuaa
11
100*
9.1
0a
0.00
California
eo
9.104
151.7
437.617
48.07
Colorado
00
0.00
Connecticut
3
230*
83 3
0*
0.00
Delaware
6
230"
41.7
0*
000
District of Columbia
0.0
0 00
Florida
78
5,144
65.9
84.377
16 40
Georgia
19
1.862
98.0
22.208
11.93
Hawaii
0.0
0.00
Idaho
0.0
0.00
Illinois
40
968
24 2
23.408
24 IS
Indiana
8
108
13 5
3,781
35 01
Iowa
4
20*
5.0
0*
0 00
Kuui
0.0
0.00
Kentucky
22
436
19.8
11,622
26 66
Lou u Una
104
6,031
58.0
112.500
18 65
Maine
0.0
0 00
Maryland
23
2,907
116.3
91,396
31 44
Massachusctu
11
810
73.6
15,387
19.00
Michigan
7
67
9.6
3,412
50 93
Minnesota
12
20*
1.7
0*
000
Mississippi
9
494
54.9
8.469
17.14
Miaaouri
13
272
20.9
6,603
24.28
Montana
00
0 00
Nebraska
0.0
0.00
Nevada
0.0
ooo
New Hsmpshir*
0.0
000
New Jeraey
32
3,507
109.6
122,860
35 03
New Mexico
00
0 00
New York
40
1,864
46.6
49,158
26 37
North Carolina
12
1,006
83.8
12.055
11 98
North Dakota
0.0
0.00
Ohio
31
1,097
35.4
35,947
32.77
Oklahoma
3
20*
6.7
0®
000
Oregon
19
1,000*
52.6
0a
0 00
Pennsylvania
21
1,692
80.6
46,411
27 43
Puerto Rico
00
000
Rhode [aland
0.0
0 00
South Carolina
23
2.363
111.4
50,935
19.87
South Dakota
0.0
000
Tennenee
11
97
8 8
l,7|4
17 67
Texaa
93
6.125
65.9
81,422
13 29
Utah
0 0
000
Vermont
0.0
0.00
Virginia
17
2,720
160.0
66,721
24.53
Washington
39
3,054
78.3
147,249
48 22
Wisconsin
11
147
13.4
6,557
44 61
West Virginia
8
129
16.1
3.077
23.65
Wyoming
8
0.0
000
TOTAL (Above):
821
S4,94i
66.9
1,471,270
26.78
TOTAL (Dialog):
834
56,741
68.0
1,618,041
28.32
Difference:
13
1,796
146.771
28.52
NOTE: These figures exclude government employes*, except self-employed employ***
*Wh«n ther* are oaly t few eeUblishmenU in * county for tn industry, total annual payroll figure* and the toul number of mid-March
•mployeee *re sometimee withheld to avoid the disclosure of information about individual esublishmenu. Withheld payroll figures are
indicated by an 0. However, the employment lize clau it shown in nibatituaoo for the toul number of mid-March employeea
Reference: 1988 County Buaineaa Pattern*, Bureau of Catuus, printed January 16, 1991, in CenData Databaae, Dialog Information
Service*, April 5 and 8, 1991.
-------
For tankers we have chosen an illustrative small entity
threshold of 20,000 dead-weight tons DWT which encompasses 86 of
the 266 tankers that transport the regulated products or
32.3 percent.
For barges we have chosen an illustrative threshold of
1,000 DWT which encompasses 1,069 of 1,609 or 66.4 percent of all
barges that transport the regulated products.
The EPA RFA guidelines contain four criteria for determining
significant economic impacts on small entities.
1. Product price increases;
2. Control cost differentials between small and larger
plants;
3. Capital problems for small plants; and
4. Economic impacts such as closures.
The first step for determining significant impact was to
calculate annual compliance costs of small entities as a percent
of sales. Since price pass-through potentials have been
calculated in this analysis, the RFA criteria is employed with
price pass-through assumed. However, only average industry costs
are assumed to be passed-through in the form of higher prices.
In areas where limited competition exists, smaller terminals with
higher than industry average cost increases, may be able to
increase prices by a greater amount in the short run. Thus, the
financial impact on the small facilities examined below may be
overstated in the shortrun. In the long-run new terminals may be
able to locate in areas that would suppress the ability to pass-
on more than market average price increases.
For terminals the following calculations show the results of
the step-one tests. A 500,000 barrel per year facility can
experience compliance costs ranging from $0.46 per barrel
(models 5C and 6C) to $1.23 per barrel (model 7A). Under RA A
and RA B (the only alternatives containing a terminal of this
size), Table 5-11 shows that the absorbed compliance costs for
any combination of costs or RA's will always yield impacts
greater than 40 percent of sales and thus are significantly
impacted under Step one.
-------
TABLE 5-11. SMALL ENTITY ANALYSIS
Terminal throughput, barrels/yr
500,000
1,000,000
2,000,000
Revenue/barrel, $
0.30
, 0.30
0.30
After-tax profits/barrel
0.012
0.012
0.012
Pretax, preprice Increase terminal only
compliance costs
0.46 (5C)
1.07 (6 A)
0.46 (6C)
1.23 (7 A)
0.23 (5C)
0.21 (6C)
0.62 (7A)
0.12 (5C)
0.27 (6A)
0.12 (6C)
0.31 (7 A)
Average
average
RA A
RA B
RA C
RA D
RA E
costs per barrel per RA i.e.,
>ricc increase:
0.34
0 06
0 05
0.05
0.04
0.34
0.06
0.05
0.05
0.04
0.34
006
0.05
0.05
0.04
Absorbed costs (average price
increase/RA less terminal compl. costs
per barrel)
5C
6
6C
7A
5C
6C
7A
5C
6
6 C
7A
RA A
0.12
0.73
0.12
0.89
(0.11)
(0.11)
0.26
(0.22)
(0-07)
(0.22)
(0.03)
RA B
0.40
NA
NA
1.16
0.17
NA
0.56
0.06
NA
NA
0.25
RAC
NA
NA
NA
NA
0.18
NA
0.57
0.07
NA
NA
NA
RA D
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
RA E
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Absorbed control costs + sales,
percent
RA A
40.0
100
40.0
> 100
Neg.
Neg.
93.3
Neg.
Neg.
Neg.
^eg.
RA B
> 100
NA
NA
> 100
73.9
NA
>100
16.7
NA
NA
83.3
RA C
NA
NA
NA
NA
60.0
NA
> 100
3 3
NA
NA
86.7
RA D
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
RA E
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
-------
A 1,000,000 barrel per year facility would be controlled
under RA's A, B and C depending on the commodities loaded. Under
RA's B and C the 1,000,000 barrel per year product facility will
generally absorb control costs greater than 63 percent of sales.
(Crude oil terminals of that size would not be affected).
The 2,000,000 barrel per year Model 7A gasoline terminal is
also significantly impacted under RA B and C. The Model 5A
2,000,000 barrel per year facility is also significantly impacted
under RA B.
The same data in Table 5-11 also shows that small plants
control costs as a percent of sales are much higher than those of
larger plants. For RA A, B and C control costs for larger plants
are 20 to 30 percent of sales. The costs for small plants are
typically 40 percent and more.
Thus the following analyses of crude oil and product
terminal impacts focuses largely on small entity impacts since
the price increase analysis and control cost differential
analysis just performed above show potentially significant
impacts. The analysis includes additional tests for small
business impacts.
5.5.2.1 Crude Oil Terminals Impact Analysis. Most, if not
all, crude oil loaded in this country is eventually purchased and
processed by domestic petroleum refineries. Most petroleum
refineries can purchase crude oil from multiple domestic sources
or can import the crude oil.
Although the average control cost under RA A is $0.12 per
barrel, the vast majority of the crude oil terminals would face
control costs of more than $1.00 per barrel.
Table 5-11, shows that 500,000 barrel per year crude oil
terminals controlled under RA A would not be able to pass forward
all of its control costs in the form of price increases and would
have to absorb costs amounting to 40.0 percent to over
100 percent of sales. The vast majority of small terminals only
account for a modest percentage of total crude oil throughput at
terminals. Most of these small terminals with high per barrel
control costs will be by-passed by crude oil owners in favor of
-------
other larger, lower cost terminals assuming the incremental costs
to reach those substitute terminals is not prohibitive. The by-
passed terminal owners will therefore be impacted by a loss of
business. If crude oil owners did incur high terminal contract
costs and if they did try to pass them on to refineries, the
refineries would seek other crude oil suppliers, domestic or
foreign. In theory terminal owners should be able to anticipate
that they would be by-passed and would decide not to install the
control systems at all.
The terminal business for crude oil handling of small
amounts is a mixture of transshipments, periodic imbalances in
location of supplies and deliveries from small oil fields.
Facing high control costs under RA A, transshipments at small
terminals will disappear in favor of alternative routes.
Imbalances will be handled via other transportation modes. The
owners of small oil fields will find other ways to get the oil to
a refinery or will no longer pump the oil. Terminal owners could
also not afford to absorb the control costs since the profits on
even the highest loading costs of $0.50 per barrel would not
permit an absorption of $0.12 per barrel.
The profit loss for a terminal owner earning 7.5 percent
before taxes on the loading of 100,000 barrels of crude oil at a
high level of $0.50 per barrel is $3,750.
For RA B and RA C the differentials are small enough that
shifts of crude oil from terminal to terminal are not expected.
Also under RA's D and E, no small crude oil terminals will be
subject to control.
5.5.2.2 Product Terminal Impact Analysis. For reasons
similar to the above it is expected that many product terminals
covered by some of the RA's will be under competitive pressure
when facing control costs in the high end of the range. These
terminal owners may not be able to pass control costs onto
product owners because the product owners can pay smaller
incremental transportation costs to get product to a market.
This assumes that substitute terminals are nearby or that new
terminals with lower per unit control costs could be located to
-------
serve as a substitute. In reality substitution is not perfect
and even some small terminals with higher than average per unit
control costs will be able to pass on those costs. Or, the cost
to transport product to a nearby terminal exceeds the cost
savings and the company may decide to absorb the costs. The
quantitative analysis performed below assumes, as a starting
point, that substitution is possible and therefore overstates the
impact. Thus, some of the qualitative market factors will also
be discussed.
The impact on terminals will be examined through a small
entity impact analysis. What follows below is additional
analysis which examines closure potential or other significant
impacts. In this case closure potential means that a terminal
owner would not purchase the control system and would therefore
forego the business of loading the regulated products at the
controlled quantity. However the terminal would still be able to
remain in business to load and provide services for other
products. In fact the terminal owner could even load regulated
products as long as the quantities involved are less than the
specified threshold of control. For example, under RA C, a
terminal owner could load up to 999,999 barrels of gasoline per
year without incurring a control requirement. Since these
terminals may not be closure candidates they will be referred to
as terminals under competitive pressure.
To analyze impacts by size of terminal, four financial
ratios were selected to examine the before and after impact from
the vapor control requirements. The ratios are: current assets
to current liabilities (should exceed 1.0) long term debt to
equity (should not exceed 1.5) cash flow to current maturities of
long-term debt (should be 2.0 or greater), and earnings before
interest and taxes (EBIT) divided by interest (should be 3.0 or
greater).
The procedures used to calculate before and after ratios
were to assemble the before ratios from Robert Morris Associates
data for the Marine Cargo Handling Industry. Next an average
cost per RA was determined. It was then assumed that the entity
-------
could raise its prices by the RA's average cost and if the
entity's per barrel cost was greater than the RA's average, the
greater cost would have to be absorbed by the entity. The cost
absorption would then begin to erode the financial ratios. If
the ratios are eroded beyond the threshold criteria listed above
then at risk potential exists.
Table 5-12 shows these calculations. The results show that
for RA A, B, and C model facilities 5C and 7A incur high control
per unit control costs. For RA D model facility 7A also has some
competitive pressure. Model facility 7A appears to possess the
greatest economies of scale since the minimum capital cost for
any size terminal is $2,675 million excluding vessel retrofits.
To illustrate this effect even the annualized costs for a
5,000,000 barrels per year terminal are $626,059 or $0,125 per
barrel, compared to industry averages under RA's B-D of $0.05 to
$0.06 per barrel.
-------
TABLE 5-12. FINANCIAL ANALYSES OF SMALL PRODUCT TERMINALS
Throughput, barrels/yr
500.000
1,000,000
2,000,000
4,000,000
Revenue @ $0.40/bbl
150,000
300,000
600,000
1,200,000
Profits ® 4% AT
6,000
12,000
24.000
48,000
Depr @ 5 %
7,500
15,000
30,000
60.000
Cash flow
13,500
27,000
54.000
108,000
Total assets (TA)
78,947
157,895
315,790
631,579
Current assets (CA) (43.4% of TA)
34,263
68,526
137.052
274,105
Current liabilities (CL) (71.492 of CA)
24,464
48,928
97,856
195,711
LT/debt (22.8* of TA)
18,000
36,000
72,000
144,000
Equity
36,483
72,966
145,932
291,860
Current matur. LT D
3,600
7,200
14.400
28,800
Interest
3,000
6,000
12,000
24,800
Ratios. Drecontrol
1.4
1.4
CA: CL
1.4
1.4
0.5
0.5
Debt: equity
0.5
0.5
1.75
3.75
Cash flow + CMLTD
3.75
3.75
3.9
3.9
BBIT/interest
3.9
3.9
Compliance costs
Annual
Annual
Annual
Annual
5C
228,782
232,643
239,658
250,000
7A
616,583
618,578
622,497
628,000
Comoliance costs
Capital
Capital
Capital
Capital
5 C
819,482
819,482
819,482
819,482
7A
2,675,508
2,675,508
2,675,508
2,675,508
Absorbed comoliance costs
RA A 5C
60,000
0
0
0
RA B SC
200,000
170,000
120,000
50,000
Ratios (post-control) RA A 5C
CA: CL
0.3
1.4
1.4
1.4
Debt: Equity
>20.1
0.5
0.5
0.5
Cash flow -r CMLTD
Neg.
3.75
3.75
1.75
EBIT/interest
Neg.
3.9
3.75
3.9
RA B SC
CA: CL
0.3
0.5
0.8
1.3
Debt: Equity
>20.1
11.8:1
6.0:1
1.0
Cash flow -r CMLTD
Neg.
<1
<1
1.3
EBIT/interest
Neg.
<1
<1
0.8
-------
The number of terminals under competitive pressure is as
follows:
No. of terminals
No. of terminals
under competitive
pressure
Million barrels/yr,
gasoline volume
5C
7A
5C
7Aa
0.5
RA B
29
46
29
36
1.0
RA C
6
34
6
24
5.0
RA D
0
15
0
+
5
10.0
RA E
0
6
0
+
0
aThe calculations in Table 5-12 are not shown for Model 7A
because the ratios for 5C show potential for competitive
pressure and the costs for 7A are higher and will automatically
also show competitive pressure.
The above analyses of terminal impacts indicates that a
number of terminals are under competitive pressure with respect
to the continuance of the business of loading the affected
products; the size of the number depends on which RA is chosen.
To the extent that this would happen, the actual nationwide
control costs for each RA would substantially decrease for all
regulated terminals. In effect the high per barrel control costs
of small regulated terminals would be replaced by the low per
barrel control costs of large terminals or by unregulated
terminals.
Being under competitive pressure means that the terminal's
control costs are significantly above the average for all
regulated terminals. In a market with full competition from
substitute terminals, such terminals face difficult choices of
either trying to pass-on the higher costs, absorb the higher cost
or discontinue loading controlled products. There are however,
some factors which make this market less than fully competitive.
Most of the terminals in RA B thru RA E are most likely part
of integrated petroleum refinery operations which on the surface
can absorb the above average control costs. However, this
-------
analysis treats those integrated facilities as being cost
minimizers/profit maximizers and that they would consider
abandoning their own terminal if another less cost terminal were
accessible.
Nevertheless some integrated refineries are likely to choose
to continue their terminal operations rather than be reliant on
an independent company or another petroleum company. In remote
areas the likelihood is that competition is also not perfect and
that above average control costs may be absorbed. In more
competitive areas, the extra cost to pump to a further terminal
will sometimes be higher than the lower control cost of the
accessible terminal. In addition, loading at another facility
would either require a larger terminal than the one being
replaced, which would require a cluster of producers to support
the larger terminal, or may require multiple terminals with
throughput less than the controlled amounts. The combination of
these factors make the market for terminals less than perfect and
serve to illustrate that the actual number of terminals under
competitive pressure will be less than the quantities shown
above.
Under RA D the estimate is that up to five terminals could
be under competitive pressure. These terminals would most likely
not be small. Under RA C the number jumps to 24 whereas under
RA E the estimate is for no terminals under competitive pressure.
5.5.3 Marine Vessels
Vessels provide transportation of products from point A to
point B. Movements can be from refinery to terminal, terminal to
terminal (product can not be moved by large ship down shallow
waters), and terminal to refinery (an imbalance of product).
This is usually called transship which is when cargo is
transferred from one vessel to another for reshipment.
The industry is highly competitive with 80 to 90 percent of
the available vessels operating during 1989. There are
130 companies involved in this industry including both major oil
companies and independent vessel owners. Business is much like a
commodity where bids go in for every movement if it is not
-------
covered by a long-term contract. Typically long-term contracts
state a lower rate than spot movements, but if market conditions
are such that many vessels are available, spot rates could be
lower. Rates are highly dependent upon supply and demand.3
Construction of new barges and tankers are on the rebound.
Almost all are being built with double hulls but usually not with
manifolds for vapor recovery.3 Typically, those vessels being
built with manifolds are being done for the large vessel
companies, for transporting benzene and for loading product in
regulated States.
The aim of vessel companies is to maximize profit which
means that vessels need to stay in operation as much as possible.
Each movement that is not covered by a long-term contract will go
out to bid much like a commodity product. Rate setting is a very
competitive business, rates change continually.
There are two major groups of product - clean and dirty.
The products considered clean are gasoline, naphtha, and diesel
fuels. The products considered dirty are crude oil and fuel oil.
Distillate fuel can be considered clean or dirty depending on
whom is evaluating. Typically, a vessel that carries dirty
products will be dedicated to dirty service. The reason is that
to carry a clean product after carrying a dirty product means
that the vessel needs to go through a vigorous and expensive
cleaning procedure. The extent of this warrants or highly
suggests dedicated service by a vessel owner to one type of
product moved as opposed to moving both.
Another way to maximize profit for a commodity owner with
vessels is to charter in and charter out. A commodity owner can
charter in when more product needs to move than the number of
vessels available to the owner. Charter out occurs when more
vessels are available than there is product to move. Charter out
is handled cautiously by vessel owners due to liability issues on
spills and other accidental occurrences (see Section 5.7.2).
There are a number of different charter types: long-term
contract, spot contract, MSC - military service charter, and
Exxon charter. They tend to vary from a few hours to over
-------
20 years. Long-term contracts are written for 1 year or more and
are written specifically according to the needs of both parties.
Spot contracts are used when product moves right away for a
period of usually less than 6 months and written for one voyage
only.
Rates for transportation are similar for all types of
products. However, rates do vary according to the distance
travelled, the size of vessel used, and market conditions of the
region in which the vessel is moved. Rates are highly sensitive
according to the region of the country where they occur because
of the interplay between supply and demand. Rates can be stated
in a long-term contract or in a spot contract. Domestic rates
are quoted as an index published by the Association of Ship
Brokers and Agents called the AR Scale. The book is published
each year and contains a base AR for each product moved by a
prototype ship of 27,800 dwt. International rates are quoted on
the World Scale index.
Vessels carrying petroleum products are specialized because
the Coast Guard certifies according to subchapter 0 and D, only
those vessels appropriate for such movements. Of the U.S. flag
vessels operating or available in 1989, 1,609 barges and
266 tankers were certified to carry subchapter 0 and D cargoes.
Barges move products and are typically unmanned except
during loading and unloading when a Coast Guard certified
tankerman is present. In addition, one person is needed for
towing the non-propelled barge. Services provided by the barge
owner include: cleaning of vessel according to product needs,
amount of voyage time dictated by either spot or long-term
contact, loading and unloading of product at dock (which can vary
from 12 hours to 24 hours), and handling the maintenance
requirements of the barge.
Furthermore if the barge is nonself-propelled, a tug is
supplied. A barge towing service is used at or between points
where the carrier does not have a tug available. Charges will be
assessed according to hourly boat rates from where the tow
-------
originates to the final destination and back to the original
location of the tug.
Tankers move crude and have dedicated crews which are
skilled to supervise loading and unloading. Services provided by
the tanker owner include: cleaning of the tanker according to
product needs, voyage time, loading and unloading time for
product at dock, and handling the maintenance requirements of the
tanker.
Because this industry is not regulated, rates are determined
according to the market flow and are not required to be published
or posted in any way. Rates are generally based on quality and
service, amount of storage provided, length of time to load and
unload, and the number of crew provided.
5.5.3.1 Tanker Impacts. The vapor control costs are not
expected to cause tankers to loose business to pipelines or other
modes of nonmarine transport. Thus the impact analysis must
focus on what happens within the tanker industry. Domestic
loading of petroleum products totaled 439 million short tons per
year (1988). Presently tankers carry 51.7 percent of that total
or 227 million short tons. The total amount of regulated
products under each RA is presented in Table 5-13. Although the
51.7 percent share for tankers may be a good estimate under RA A,
the percentage of regulated products carried by tankers increases
as the RA's approach E. As shown in Table 5-13, a very large
volume of crude oil (129.85 MM short tons) is handled by the
three largest crude oil terminals and these terminals may need to
install controls even under RA E.
Table 5-13 shows that not all of the tankers need to be
retrofitted to accomodate the volume of controlled products.
Therefore it is necessary to examine which types of vessels will
retrofit, which will not, and the impacts on both categories.
The conclusion drawn herein is that enough tankers will be
retrofitted under each RA to match the controlled volume, plus a
reserve factor, and that those who do retrofit will be able to
pass those control costs onto the producers. Owners of fleets of
vessels will tend to retrofit those that are the least costly to
-------
TABLE 5-13. PERCENTAGE OF TOTAL MARINE TRANSPORT OF
PETROLEUM PRODUCTS AND CRUDE OIL AFFECTED BY THE
REGULATORY ALTERNATIVES
Throughput affected,
millions of short tons
Percent of total marine
transported petroleum
With
Without3
With
Without
RA A
410.6
280.8
93.5
64.0
RA B
237.2
107.3
54.0
24.4
RA C
225.0
95.1
51.3
21.7
RA D
167.5
37.6
38.2
8.6
RA E
153.8
23 .9
35.0
5.4
aWithout crude oil terminals with throughput >100MM bbl/yr .
-------
retrofit. Those vessels that are not retrofitted will be
dedicated to transporting uncontrolled products or controlled
products from uncontrolled terminals. The impact of dedication
on transporters is unknown with respect to profit rates on
controlled and uncontrolled products. It is not known whether
fleet owners who once transported controlled and uncontrolled
products and who would only transport uncontrolled products will
earn the same or less profits.
To determine which vessels will be retrofitted it is
necessary to examine the retrofit costs and the distribution of
tankers by age, size and the presence of single or double skins.
For the combined capacity of tankers and barges, 93.5 percent of
the 1988 volume of 439 million short tons would require
retrofitted vessels. Under RA B that figure drops to 54 percent
and 38 percent with RA D and 3 5 percent under RA E. These
percentages drop sharply if the three large crude oil terminals
are exempted. For example, under RA D only 8.6 percent of
throughput would require retrofitted vessels. (These estimates
exclude retrofitted capacity for transporting products controlled
by State regulation or for transporting benzene).
Under RA A more than 94 percent of tanker capacity would
have to be retrofitted to transport controlled products. This
level of retrofit could be costly for some of the older or
smaller tankers. Retrofit systems are estimated to have a useful
life of 20 years. Exact useful lives of vessels are difficult to
estimate but few vessels last past 50 years. This means that
retrofits on vessels already older than 30 years are likely to
last longer than the vessel. Or, in other words the cost would
have to be recovered over a shorter period of time.
For RA B and RA C the 54 percent and 51 percent of capacity
that requires retrofitting will consists to some extent of the
already doubleskinned tankers which comprise 20.3 percent of all
tankers. For RA D (38 percent) and RA E (35 percent) double-hull
vessels would be the primary target of retrofits.
The model facilities that load crude oil or products into
tankers are 6, 7A, and 7B. At these facilities the incremental
-------
control cost per barrel for the vessel retrofit control costs
(excluding terminal costs) is $0,002 for crude oil (6) and $0,019
and $0,026 for gasoline and chemical products (models 7A, 7B).
These costs are constant over all sizes and ages of vessels. At
a transport cost increase of $0,002 per barrel for crude oil and
$0.0019 to $0,026 for products, it is not likely under any of the
regulatory alternatives that there will be any significant
adverse impact on the tankers.
However, there is some likelihood under each of the RA's
that some of the smaller and the older tankers {>30 years) will
not be retrofitted and would be cleaned and used to ship
uncontrolled products. This type of impact can be described as
one of efficiency where the retrofitted tankers would require
special scheduling to be available when needed. Table 5-14 shows
the age distribution of the U.S. tank ship fleet in 1989.
Twenty-nine percent of tankers are older than 30 years. The
older tankers also tend to be the smaller tankers. Twenty-nine
of the 36 tankers over 40 years age are less than 10,000 dwt.
Only one tanker over 30 years age is larger than 60", 000 dwt.
Double-skinned tankers will most likely be retrofitted since
they are also more insurable than single-skinned tankers.
Fifty-four, or 20.3 percent of the tanker fleet is already
double-skinned. Smaller tankers of less than 20,000 dwt comprise
32.3 percent of the fleet and are candidates for not being
retrofitted.
Recent oil spill legislation (see Section 5.7.2) setting
forth liability requirements for oil spills will act in concert
with these regulations to affect single-skinned and older crude
oil tankers. The cost to retrofit those tankers to prevent oil
spills is likely to far exceed the cost impact of these
regulations.
For gasoline and chemicals this increased transport cost for
marine vessel retrofits is also likely to produce dedicated
gasoline vessels as tankers older than 30 years would not be
retrofitted.
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TABLE 5-14. TANK SHIP FLEET BY AGE, 1989
Age
No.
Percent
of
fleet
Double skinned
Less than
20,000 DWT
No.
Percent
No.
Percent
0-10
49
18.4
18
36.7
12
24.5
- 11-20
107
40.2
34
31.8
20
18.7
21-30
33
12 .4
1
3.0
11
33.3
31-40
41
15.4
1
2.4
14
34.1
>40
Total
36
13 . 6
0
0.0
29
80.6
266
100.0
54
20.3
86
32.3
Source: U.S. Coast Guard.
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5.5.3.2 Barae Impacts. It is expected that certain
percentages of the 1,609 barges currently in use will not be
retrofitted under each RA because the volumes of regulated
product fall short of the total barge capacity. The most likely
barges to be retrofitted are ones that already have double-skins
which amount to 57.9 percent of the barge fleet. This would
represent substantially more than the percentage of products
covered for RA B through RA E. The incremental control costs for
retrofitted barges is $0.08 per barrel for crude oil and products
for Cases 5A, 5B, 5C, 6BB, and 6BC. The incremental costs for
products under model 7A are $0,019 per barrel and $0.0269 for 7B.
It is highly likely that barges older than 30 years and
which transport products will not be retrofitted and would be
assigned to carrying unregulated products such as asphalts, lube
oils, and No. 6 oil or to carrying shipments from uncontrolled
terminals. Table 5-15 shows the average age distribution of U.S.
owned barges carrying subchapter 0 and D products in 1989. At a
rate of 5.5 percent, barges older than 30 years amount to 89 of
the 1,609 barges. The remaining barges plus new barges
should be able to handle the necessary volume requirements for
the transport routes for the regulated products under RA B thru
E. Many of the older barges that will not be retrofitted are
also typically smaller than the newer barges.
To the extent that the costs for retrofitting barges show a
differential in favor of size, age or some other factor, those
vessels favored by the bias will be retrofitted first.
5.5.4 Producers of the Regulated Products
Once the marine terminal and vessel owners pass some or all
of their control costs onto the producers of the products, those
producers will first consider raising the prices of the products
in the market place. In this instance, the producers will first
have to take into consideration the demand elasticity for each
product. Demand elasticity will be sensitive to the fact that
some products will reach markets without having been shipped by
marine routes and will not have the VOC control costs in their
price.
-------
TABLE 5-15. U.S. BARGE FLEET BY AGE, 1989
Double skinned
Percent of fleet
Double skinned
Less than 1,000 DWT
Age
No.
No.
Percent
No.
Percent
0-10
356
22.1
260
73.0
247
69.4
11-20
799
49.7
470
58.8
512
64.1
21-30
365
22.7
184
50.4
251
68.8
31-40
58
3.6
17
29.3
32
55.2
>40
31
1.9
0
0.0
27
87.1
Total
1,609
100.0
931
57.9
1069
66.4
Source: U.S. Coast Guard.
-------
In order to determine the market price increase two pricing
questions have to be answered:
1. How will refineries that load products into pipelines
and onto marine vessels allocate the costs of VOC control?
2. Will refineries, wholesalers, and retailers be able to
increase product prices if they compete with pipeline transported
product?
With respect to the first question, petroleum refiners and
petroleum-owned shipping companies have indicated that marine-
loading costs are generally allocated to the refinery and marine
vessel costs are allocated to the transportation costs of
product. Further, the loading costs allocated to the refinery
are treated as a generalized plant cost along with pipeline
loading costs. (Most refineries can ship product by both,
pipeline and marine while also shipping to some nearby markets by
truck). This would seem to suggest that the marine VOC control
costs would increase the prices of all refined products exiting
the refinery. However, when the refinery product pricers try to
regain their margins that would otherwise be reduced by the
increased loading costs they will realize that they can only
increase prices in the markets where marine products are being-
shipped and not the markets where the pipeline products are being
shipped. Thus the increased control costs end up being re-
allocated to the marine transported products. The premise that
this conclusion rests on is that the markets for the two sets of
shipped products are distinct. This appears to be substantiated.
Petroleum product geographic markets are for the largest part
either served by pipelines or by vessels, as at least the initial
bulk means of conveyance into areas. Of course where these
markets touch there would be a mixture but for the most part the
markets are separate. Thus when product prices are increased for
the marine-loaded products the demand will be influenced in that
market by traditional demand elasticity factors.
Figure 5-1 shows a map of pipeline locations in the United
States. These are pipelines that ship petroleum products to
markets. Notice that the pipelines are highly concentrated in
-------
in
i
CD
PETROLEUM PRODUCTS PIPELINE CAPACITIES'
AS Of DECEMBER 31.1967
(THOUSANDS OF BAiWElS OMLV)
Source: NftttOMi FttroUw Council. Petroleua Storagg I Tr»nsportitloi>. Vol. S. Washington, Of Afrfl I98t, P.0-1.
-------
the mid-west, central southern, and middle atlantic States areas.
The major marine shipments of petroleum products on the other
hand are along the coastal waterways to coastal markets. The
Mississippi system vessels carried over here. There are 300,000
tons of loaded petroleum products as compared to those coastal
vessels which carried over 530,000 tons in 1988.^
To place the market reaction in perspective, Table 5-16 was
constructed to accompany a product-by-product description.
Gasoline transported by marine faces a 1.01 percent price
increase under RA A for the 14.54 percent portion of the entire
U.S. market that will receive regulated gasoline which has been
transported by marine. Demand for gasoline is generally regarded
to be relatively inelastic. Even in the long term, it is
difficult for motorists to reduce their dependence on gasoline.
Many motorists, for example, are limited to their ability to
purchase a more fuel-efficient motor vehicle or change their
driving habits. Demand for motor gasoline is shaped by
consumers' real disposable income, overall economic well being,
and the price of gasoline. The Department of Energy has
estimated that the long-term price elasticity of demand for
gasoline is -0.55.7
The 14.54 percent of natural gasoline consumption affected
by this regulation amounts to 16.274 x 10® gallons (see
Table 5-16.) The long run reduction in output for gasoline is
estimated at -0.55 x 1.01 percent x 16.274 x 109 gallons or
90.40 x 10® gallons. This equates to a 0.08 percent total output
reduction based on the total consumption of 111.9 x 10® gallons
shown in Table 5-16.
For RA B the output change for gasoline would only be
0.03 percent since the average price increase for gasoline is
only 0.36 percent versus the 1.01 percent of RA A. The output
changes for RA C thru RA E are even smaller.
Jet fuel and kerosene face a 1.66 percent price increase
(RA A) for the 17.32 percent of total U.S. consumption that is
transported by marine. Demand for jet fuel and kerosene reflects
the number of air miles flown but has been influenced due to
-------
TABLE 5-16. PORTIONS OF TOTAL MARKETS AFFECTED BY REGULATORY ALTERNATIVE A
Product
Percent
price
increase
Affected
throughput,
000 gallonsa
National
consumption.
000 gallons15
1989 market
percent
affected
Gasoline
1.01
16,273,632
111,909,000
14.54
Jet fuel/kerosene
1.66
4,175,833
24,114,090
17.32
Naphtha
0 .70
1,;245, 893
3,970,470
63.73
Distillate
1.20
19,324,624
49,056,000
39.39
Toluene
0.70
646,836
805,000
80.35
Methanol
1.82
1,990,766
5,292,000
37 .62
NA = Not available.
aSource: Memorandum, Nicholson, R. and Kapella, D.f Midwest Research Institute, to D.
Markwordt, EPA, July 13, 1990, National Profile for the Development of a VOC Rule for
Marine Vessel Loading Operations. Table 1.
Source: U.S. Department of Energy, Energy Information Administration. Petroleum Supply
Annual, 1989, p. xiixiii (for gasoline, jet fuel/kerosene, and distillate). Facts and
Figures, C&E News June 18, 1990 p. 39 (for naphtha, toluene and methanol).
-------
improvements in aircraft efficiency, higher fuel prices, and an
easing in passenger and freight travel. Higher airline ticket
prices will also most likely contribute to a slower jet fuel
demand growth. Demand for naphtha-type jet fuel, which is used
principally for military purposes, is expected to remain near
current levels through the year 2010. According to EPA
estimates, demand elasticity for jet fuel is considered fairly
inelastic perhaps less than that of gasoline at -0.30. At this
level the reduced output under RA A would be 0.09 percent of
total consumption (-0.30 x 1.66 percent x 17.32 percent of total
consumption). These products would not be directly affected
under the other RA's except for very small price increases
(0.01 percent from crude oil control).
Distillate affected fuel oil faces a price increase of about
1.20 percent under RA A for the 39.39 percent of regulated U.S.
consumption that is marine transported. Distillate fuel oil
demand depends on the transportation and residential sectors.
Distillate fuel oil .is used in the transportation sector.
Distillate fuel oil demand in the residential sector depends on
conservation efforts, and competition from natural gas and
electricity. According to EPA estimates, elasticity for
distillate fuel oil is -0.5. At an assumed elasticity of -0.5
the reduction in output under RA A would be 0.24 percent
(-0.5 x 1.20 percent x 39.39 percent). Distillate would not be
controlled under the other RA's except for the 0.02 percent
increase or less from crude oil control.
Naphtha faces price increases of 0.70 percent for the
63.7 percent of consumption that is marine transported. Demand
for naphtha as a petrochemical feedstock is highly inelastic.
According to EPA estimates, the demand for naphtha is not
affected by income level and does not have close substitutes as a
petroleum feedstock; therefore the elasticity of naphtha is
estimated at -0.15. At a demand elasticity of -0.15 the output
reduction is estimated at 0.07 percent (-0.15 x 0.70 percent
x 63.7 percent). Again, naphtha is not directly affected under
-------
the other RA's except for very small passed on crude oil control
coats.
Toluene faces a 0.70 percent price increase under RA A which
is not expected to cause reductions in output. Under RA B the
estimated price increase is 0.41 percent. Toluene is an aromatic
organic chemical primarily derived from petroleum refineries.
Toluene and other aromatics are commonly used to increase the
octane rating of unleaded gasoline. As a result, the market for
toluene is closely related to the gasoline market. Recently, the
demand for reformulated gasoline is pushing up toluene demand.
Toluene is a good additive not only because it can be used as an
octane enhancer, but also because it improves driveability and is
a good method for reducing required vapor pressure. The expected
increase in testing and marketing of reformulated gasoline will
increase refiners' need for this aromatic and will most likely
result in an increase in toluene demand over the long run.
The price increase for alcohols .under RA A as represented by
methanol is- 1.80 percent. The percent of alcohols marine
transported is 37.62. The assumed demand elasticity is -0.3.
Therefore, the estimated output reduction under RA A is 0.20
(-0.3 x 1.80 percent x 37.62 percent). Under RA, B the estimated
output change is 0.07 percent and 0.00 percent under RA D.
Demand for chemical products like ethylene glycol and methyl
ethyl ketone are not expected to be significantly impacted. The
price increase calculations show increases of less than one-half
of 1 percent.
5.6 SMALL BUSINESS IMPACTS
For reasons explained earlier the SBA size definition of
$12.5 million in sales was selected as being applicable in this
analysis. Small business impacts utilizing the above
specification, depend on the final decisions by EPA regarding the
threshold level of terminal throughput controlled by the
regulation. If all terminals are controlled under RA A then more
than a thousand of the 1,749 terminal owners under competitive
pressure may discontinue the business of loading crude oil or
products. Many of these are small entities.
-------
Under RA B thru RA E only the largest terminals in the
industry are controlled; the totals being 104, 60, 25, and 13,
compared to the 1749 terminals under RA A. The business from
petroleum and crude oil products plus the other business from
integrated operations most likely make these terminals large
businesses (i.e., sales greater than $12.5 million). Therefore
RA B thru RA E are not likely to involve a substantial (i.e.,
greater than 20 percent of affected terminals) number of small
business impacts. This implies that a full Regulatory
Flexibility Analysis need not be undertaken.
It should also be noted that under RA B thru RA E, the
uncontrolled terminals (i.e., those that fall below the
throughput cutoffs) may benefit from the regulation since they
may obtain additional business if unregulated shipments increase
at these terminals. In addition to the increased business, those-
terminals may also have some ability to raise prices unless new
uncontrolled terminals enter the market.
Small vessel impacts are not expected to be. significant
because they will typically not be retrofitted under RA B thru
RA E. Earlier we chose 1,000 Dwt as the definition of a small
barge. On the basis of that definition, larger barges will be
retrofitted before smaller barges. The volumes of product
covered under RA B thru RA E will be manageable without small
barges being retrofitted. Thus a full Regulatory Flexibility
Analysis for them need not be undertaken.
5.7 EMPLOYMENT IMPACTS
According to the 1989 Bureau of Labor Statistics Employment
and Earnings Report, 846,000 employees were involved in the
petroleum industry, SIC 2911, SIC 5171 and SIC 5540.8 As shown
in Table 5-17, the potential change in employment at refineries
as a result of output changes under RA A could total 807 workers
(or 0.10 percent) due to this regulation. Under RA B about
165 workers could be affected. Under RA C, RA D, and RA E, 119,
38, and 38 workers would be affected.
Within the marine terminal sector there might be a shift of
workers from the small controlled terminals to larger controlled
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TABLE 5-17. POTENTIAL CHANGE IN EMPLOYMENT IN THE PETROLEUM REFINING INDUSTRY
Product
Employment
estimate*
RA A
RA B
RA C
RA D
RA E
Output
change, %
Potential
change in
employment
Output
change, %
Potential
change in
employment
Output
change, %
Potential
change in
employment
Output
change, %
Potential
change in
employment
Output
clwnge, %
Potential
change in
employment
Oa bo line
377,908
-0 08
303
-0 03
113
-0.02
76
4.0|
38
-0.01
38
Distillate
172,669
-0.24
415
-0.02
35
-0.02
35
0
0
0
0
Jet ill el/
kerosene
80,624
-0.09
73
-0.01
8
-0.01
8
0
0
0
0
Residual
57,528
NA
NA
0
0
0
0
0
0
0
0
Still ga«
36,463
NA
NA
0
0
0
0
0
0
0
0
Coka
28,764
NA
NA
0
0
0
0
0
0
0
0
Feeditocka
23,011
-0.07
16
-0.04
9
0
0
0
0
0
0
Aaphall
24,957
NA
NA
0
0
0
0
0
0
0
0
LP gn
23,011
NA
NA
0
0
0
0
0
0
0
0
Lubricants
11,506
NA
NA
0
0
0
0
0
0
0
0
Miscellaneous
9,559
NA
NA
0
0
0
0
0
0
0
0
TOTAL
846,000
807
165
119
38
38
NA = Not available.
-------
terminals or to uncontrolled terminals. This follows a
corresponding shift in business due to the impact of these
regulations.
5.8 CONCURRENT LEGISLATION AND REGULATIONS
The economic impact analysis of any regulation is performed
upon a baseline economic status in the regulated sector. The
baseline economic status is a snapshot of the current economic
condition of the sector. Naturally, economic baselines rarely
remain static and are constantly being changed by new
technological, political, social, and legislative events. All of
these events have the potential of making the relative impact of
VOC regulations appear greater or smaller. For example, as was
shown above, if international events cause the price of crude oil
to double as a a new baseline condition, then the potential price
increase percentage is cut in half. Since a percentage
calculation is relative, the impact appears to become smaller;
although the absolute price increase per unit of output remains
the same.
In this analysis it is important to present information on
recent events that will have significant impacts on petroleum
products and on marine vessels. These events are:
1. Budget Reconciliation Act of 1989 (PL101-239);
2. The Oil Pollution Act of 1990 (PL101-380);
3. The Clean Air Act Amendments of 1990 (PL101-549); and
4. Benzene handling regulations.
The nature of the impacts for the Oil Pollution Act (OPA)
and the Clean Air Act Amendments (CAAA) are as yet unestimated.
However, their impacts will intertwine with the impacts of VOC
control.
5.8.1 Budget Reconciliation Act of 1989
Under this act Congress enacted a five-cent per barrel tax
on oil that became effective January l, 1990. This is equivalent
to the control cost on a 10,000,000 barrel per year marine
terminal handling crude oil. For the four U.S. terminals in
Case 6 that handle crude oil at rates greater than
10,000,000 barrels per year, their volume handled is
-------
443,830,189 barrels or 77.5 percent of the 572,457,028 barrels
per year handled at all crude oil terminals in Cases 6, 6B, and
6C.
The perspective that this comparison provides is that the
impact of this regulation for approximately 78 percent of crude
oil loaded in the United States will be similar to the impact of
the Budget Reconciliation Act.
5.8.2 The Oil Pollution Act of 1990
The Oil Pollution Act of 1990 (PL 101-3 80) was signed into
law after the Senate and House of Representatives agreed on
similar reform bills. The Act addresses double hulls, ship
building capacity, spill liability, and related issues.
The package requires double hulls on all new oil tankers and
barges operating in waters subject to U.S. jurisdiction.
Existing vessels without double hulls need to be retrofitted or
retire from service, according to a complex schedule based on
vessel size and age; however, an outside date of 2015 applied in
most cases. The legislation also contains a related provision
which authorizes the Secretary of Transportation to provide loan
guarantees under Title XII of the Merchant Marine Act of 193 6 to
help finance construction for double hulls.
Various exemptions and exceptions exist in the legislation.
For example, oil response vessels are exempt from the double hull
mandate. In addition, vessels unloading oil at deepwater ports
and vessels engaged in lightering practices 60 miles or more
offshore are exempt until 2015.
With regards to ship building capacity, new vessels of less
than 5,000 gross tons, such as inland barges, must have some form
of double containment system - though not necessarily double
hulls. Existing vessels under 5,000 gross tons need to be
retrofitted with double hulls or containment systems by 2015.
In addition, the act contains major liability and insurance
provisions that require vessel owners to pay for oil spill
cleanup costs and natural resource damages and to have liability
insurance.
-------
No economic impact assessments were performed by or for
Congress and the appropriate committees in the process of passing
the Oil Pollution Act of 1990. However, it has been assumed here
that the following types of impacts are likely.
1. The cost of marine transport of crude oil will increase
as a result of the liability requirements and the double hull
construction requirements. These increases will occur
simultaneously with the VOC control costs and together will raise
the price of marine transport vis-a-vis pipeline transport costs.
2. Some older marine vessels will be made obsolete
prematurely by the OPA of 1990 because of spill risk
considerations. Some of these vessels will overlap with those
that will become obsolesent prematurely due to the VOC vessel
retrofit requirements. Thus the above estimates of marine vessel
impacts are overstated by the unknown amount which is
attributable to the OPA of 1990.
5.8.3 Clean Air Act Amendments of 1990
The price of gasoline and other VOC emitting petroleum and
air toxic emitting chemicals will increase as a result of
provisions of the CAAA. Tailpipe emission requirements in
nonattainment areas, Reid Vapor Pressure (RVP) limitations, SOCMI
air toxic emission controls and other provisions will all act to
increase these product prices by unspecified amounts. On the
other hand, incentives for reformulated and alternative fuels may
in the long run cause gasoline prices to decrease. At this time
it is quite speculative as to the magnitude and direction of
these impacts.
5.8.4 Benzene NESHAP Handling Regulations
Some tankers and barges have already been retrofitted to
collect fumes during benzene loading. To the extent that these
vessels are also used to transport petroleum products, the cost
of this regulation will decrease. It is unlikely that these
vessels would carry crude oil.
5.9 FIFTH-YEAR PROJECTIONS
Nationwide control costs were estimated in this report on
the basis of 1989 petroleum products throughput. Economic
-------
impacts were estimated on the basis of 1990 and 1991 prices and
market conditions. Expected conditions in the affected source
category will be examined for fifth-year impacts in this section.
This will be accomplished by obtaining estimates of demand
changes and by examining any expected changes in production.
5.9.1 Crude Oil
The crude oil loading figures are directly associated with
domestic production of crude oil. Domestic crude oil production
is expected to drop from 7.6 million barrels per day in 1989 to
6.3 million barrels per day in 1995.9 Meanwhile real prices are
expected to rise from $18.07 in 1989 to $20.40 in 1995.10
5.9.2 Gasoline
Motor gasoline consumption is expected to increase from
7.33 million barrels per day in 1989 to 7.52 million barrels per
day in 1995.9 Gasoline prices are also expected to stay
relatively flat.10
5.9.3 Other Products
Estimated projections for other products are as follows:
Consumption, million
barrels per day
Prices/gallon
1989
1995
1989
1995
Distillate
3.2
3.35
0.87
0.97
Jet fuel
1.49
1.63
0.59
0.71
Methanol
0.10
0.12 (1993)
0.55 (1990)
0.644 (1991)
Toluene
0.05
>0.05
1.42 (1990)
NA
Projections for methanol were only available to 1993 and no
projections for toluene were readily available. However demand
is expected to increase for reformulated gasolines that will find
toluene to be an octane enhancer with the capability to lower
reid vapor pressure.
5.9.4 Fifth-Year Demand Conclusions
In summary crude oil loadings will likely decrease while
petroleum refinery loadings for the potentially regulated
commodities will increase by amounts that are less than normal
5-58
-------
economic growth rates. Thus fifth-year costs will be only
slightly higher than the first-year control costs shown
throughout this report.
5.9.5 Fifth-Year SuppIv Conditions
No supply restrictions or technological advances are
expected among these products that would raise or lower product
prices.
5.9.6 New Terminals and Vessels
The significant economies of scale for control costs will
have the effect of favoring the construction of new large
terminals versus small terminal for throughputs above the
regulatory cutoff. The size of the capital control cost as a
percent of the total cost of a terminal is also likely to affect
the location of the control system to be nearer to the docks;
perhaps giving a cost advantage to new terminals over retrofitted
terminals. Exemptions from control for the smaller terminals may
induce the construction of those size terminals.
Just as new double skin vessels have become commonplace, the
vessel building industry will be able to manufacture new vessels
with vapor collection systems already installed which may provide
them with a cost advantage over retrofitted vessels.
5.10 REFERENCES
1. Dow Jones and Company. Commodities: CRB Future Index. The
Wall Street Journal. 1990. Various issues. CI.
2. Ocean transport. APS review Downstream Trends.
November 12, 1990. Arab Press Service Organisation.
3. Interviews held with the following people: Thomas
Allegretti (American Waterways Operators); Jack Blake and
Glenn Sandor (GATX Terminals); Sean T. Connaugton (American
Petroleum Institute); Nelson Hebert (Texaco); Cindy Hughes
(Independent Liquid Terminals Association); Barry Gipson
(Ashland Oil); Chris Young (Dietze - Broker); and three
confidential sources. - .-
4. Moore, John A. Terminals: Business is Wonderful, but Could
be Better. The Oil Daily. April 27, 1990. p. B-l.
5. Naude, Alice. Storage Operators Feeling the Squeeze.
Chemical Marketing Reporter. October 15, 1989. p. SR12.
-------
6. U.S. Department of the Army, Corps of Engineers, Waterborne
Commerce of the United States, 1990, Volume 5, p. 93.
7. U. S. Environmental Protection Agency, Office of Air and
Radiation. Evaluation of Air Pollution Regulatory
Strategies for Gasoline Marketing Industry. Washington, DC.
July 1984, p. 8-22.
8. U.S. Department of Commerce, Bureau of Census. 1987 Census
of Manufactures. MC87-1-29A Industry Series: Petroleum and
Coal Products. Washington, DC. p. 29A-6.
9. U.S. Department of Energy, Energy Information
Administration. Petroleum Supply Annual, 1989. p. 6. and
Annual Outlook for Oil and Gas, 1990. p. 20.
10. U.S. Department of Energy, Energy Information
Administration. Annual Outlook for Oil and Gas, 1990.
pp. 18, 26.
-------
-------
MODEL VESSEL 1: Crude Oil Carrier (70.000 dwt)
Vessel characteristics;
Vessel dimensions, lxwxh:
Draft, ft;
Cargo:
No. of cargo tanks:
Gauging and alarm system:
Normal loading rate, bbl/h:
Inert gas (IG) system:
Other:
800 ftxl25 ftx55 ft
42
Crude oil
15
Yes, one system services all tanks
35,000
Yes; boiler flue gas at 5 to 7 percent oxygen
2 pressure/vacuum (PV) valves on inert gas
system are set at 2 psi, each sized for full
flow; loading manifold is without header from IG
system main.
DeBicm assumptions:
1. Inert gas system and supply header will be used as the hydrocarbon vapor
header; also, detonation arresters will be added.
2. An additional gauging and alarm system will be installed to provide
redundant tank gauging capability.
MODEL VESSEL 2: Product Carrier (35,000 dwt)
Vessel characteristics:
Vessel dimensions, lxwxh:
Draft, ft:
Cargo:
No. of cargo tanks:
Gauging and alarm system:
Normal loading rate, bbl/h:
IG system:
Other:
Design assumptions:
1.
700 ftx90 ftxSO ft
39
Motor and aviation gasoline; distillate diesel
and jet fuels
24
No automatic system
Up to 25,000
None
Individual PV valves on each tank, set at
1.5 psi; loading manifold at midship.
Inert gas system and supply header will be used as the hydrocarbon vapor
header; also, detonation arresters -will be added.
2. Install a redundant tank gauging and alarm system.
-------
MODEL VESSEL 3: Ocean Barge (19.000 dwt)
Vessel characteristics:
Vessel dimensions, lxwxh:
Draft, ft:
Cargo:
No. of cargo tanks:
Gauging and alarm system:
Normal loading rate, bbi/h:
IG system:
Other:
Design assumptions:
450 ftx75 ftx30 ft
24
Motor and aviation gasoline; distillate
diesel and jet fuels
12
No automatic system
Up to 15,000
None
Individual PV valves on each tank, set at
1 psi; loading manifold at midship; diesel-
driven pumps in the rear (aft) with no
electric generator
1. Install complete vapor header.
2. Install redundant tank gauging and alarm system.
MODEL VESSEL 4: Inland River Barge
Vessel characteristics:
Vessel dimensions, lxwxh:
Draft, ft:
Cargo:
No. of cargo tanks:
Gauging and alarm system:
Normal loading rate, bbl/h:
IG system:
Other:
Design assumptions:
265 ftx54 ftxl2 ft
9
Motor and aviation gasoline; distillate
diesel and jet fuels
10
No automatic system
4,000
None
Individual PV valves on each tank set at
1 psi; loading manifold in the rear; diesel
driven cargo pump (in the rear), with no
electric generator
1. Install a complete vapor header.
2. Install redundant tank gauging and alarm system.
-------
MODEL 5A: Product Terminal for Barges
Terminal characteristics
• Two docks, designed to load two barges at each side from two loading
stations at each dock
• Loading rate of 4,000 bbl/h per barge
• Maximum loading rate of 16,000 bbl/h
• inert gas generator located 200 feet away
• All gasoline storage tanks have floating roofs
• Transfer pumps located 300 yards from dock
• Loadings handled by one person at waterfront and one at tank farm
• Annual throughput of greater than 8 million bbl/yr
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency * 98 percent
• Install four complete vapor transfer lines and associated incinerator
feed headers
• Install two full-capacity booster fans arranged in parallel
• Install terminal alarm system and vapor control system instruments
MODSL SB: Product Terminal for Barges
Terminal characteristics:
• One dock, designed to load one barge at each side from two loading
stations
• Loading rate of 4,000 bbl/h per barge
• Maximum loading rate of 8,000 bbl/h
• Incinerator located 1/4 mile away
• Inert gas generator located 200 feet away
• All gasoline storage tanks have floating roofs
• Transfer pumps located 300 yards from dock
• Loadings handled by one person at waterfront and one at tank farm
• Annual throughput of greater than 4 million bbl/yr and less than
8 million bbl/yr
Design assumptions:
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency * 98 percent
• Install two complete vapor transfer lines and associated incinerator feed
headers.
• Install two full-capacity booster fans arranged in parallel
• Install terminal alarm system and vapor control system instruments
-------
MODEL 5C: Product Terminal for Barges
• One dock, designed to load one barge from one loading station
• Loading rate of 4,000 bbl/h per barge
• Maximum loading rate of 4,000 bbl/h
• Incinerator located 1/4 mile away
• Inert gas generator located 200 feet away
• All gasoline storage tanks have floating roofs
• Transfer pumps located 300 yards from dock
• Loadings handled toy one person at waterfront and one at tank farm
• Annual throughput of greater than 4 million bbl/yr
Design assumptions
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency = 98 percent
• Install one complete vapor transfer line and associated incinerator feed
headers
• Install two full-capacity booster fans arranged in parallel
• Install terminal alarm system and vapor control system instruments
frTOPSL 6A; Qi?- Terminal fqr Ships
Terminal characteristics:
• One dock, designed to load one ship of up to 75,000 dwt at a time
• Loading rate of 35,000 bbl/h (loads only one type of crude oil)
• Incinerator located 1 mile from dock
• 220-volt AC electricity available at tank farm (located 1 mile away)
• Natural gas service located 6 miles away
• Storage tanks have floating roofs
• Terminal operated by one person at tank farm and one at the dock
• Minimal 110-volt AC electric power available at dock
Design assumptions:
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency - 98 percent
• Install one complete hydrocarbon vapor transfer line and incinerator feed
header
• Vessels have own inert gas systems; therefore, inert gas generator is not
necessary
• Incinerator located 1 mile from dock area
- Natural gas service available 6 miles from incinerator
-------
MODEL 6B: Crude Oil Terminal for Barges
Terminal characteristics:
• One dock, designed to load one barge at each side from two loading
stations
• Loading rate of 4,000 bbl/h per barge
• Maximum loading rate of 8,000 bbl/h
• Incinerator located 1/4 mile away
• Inert gas generator located 200 feet away
• All crude oil storage tanks have floating roofs
• Transfer pumps located 3 00 yards from dock
• Loadings handled by one person at waterfront and one at tank farm
• Annual throughput of greater than 4 million bbl/yr and less than
8 million bbl/yr
Desicrn assumptions:
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency ¦ 98 percent
• Install two complete vapor transfer lines and associated incinerator feed
headers.
• Install two full-capacity booster fans arranged in parallel
• Install terminal alarm system and vapor control system instruments
MODEL 6C: Crude Oil Terminal for Barges
• One dock, designed to load one barge from one loading station
• Loading rate of 4,000 bbl/h per barge
• Maximum loading rate of 4,000 bbl/h
• Incinerator located 1/4 mile away
• Inert gas generator located 200 feet away
• All crude oil storage tanks have floating roofs
• Transfer pumps located 300 yards from dock
• Loadings handled by one person at waterfront and one at tank farm
• Annual throughput of greater than 4 million bbl/yr
Design assumptions
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency = 98 percent
• Install one complete vapor transfer line and associated incinerator feed
headers
• Install two full-capacity booster fans arranged in parallel
• Install terminal alarm system and vapor control system instruments
-------
MODEL 7A: Product Terminal Serving Ships and Barges
Terminal characteristics
• One pier for loading one ship of up to 35,000 dwt
• One dock for loading one inland barge
• Tankship loading station can supply 25,000 bbl/h
• Barge loading station can load 4,000 bbl/h
• Maximum loading rate of 29,000 bbl/h
• Incinerator located 1 mile away
• Inert gas generator located 200 feet away
• 220-volt AC electricity and natural gas service available 100 yards from
potential incinerator location
• All gasoline storage tanks have floating roofs
• Terminal operated by one person at each dock or pier and two at the tank
farm
• Annual throughput of less than 29 million bbl/yr
Design assumptions:
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency » 98 percent
• Install one complete barge hydrocarbon vapor transfer line
• Install one complete ship hydrocarbon vapor transfer line
• Natural gas available 900 ft from incinerator
• Install terminal alarm system and vapor control system instruments
• Install two parallel sets of full capacity boosters for incinerator feed
to dock area
MODEL 7B: Product Terminal Serving Ships and Baroaa
• One pier for loading two ships of up to 35,000 dwt
• Two docks for loading four inland barges at each dock
• Two tankship loading stations can supply 25,000 bbl/h each
• Four barge loading stations can load 4,000 bbl/h each
• Maximum loading rate of 66,000 bbl/h
• Incinerator located 1 mile away
• Inert gas generator located 200 feet away
• 220-volt AC electricity and natural gas service available 100 yards from
potential incinerator location
• All gasoline storage tanks have floating roofs
• Terminal operated by one person at each dock or pier and two at the tank
farm
• Annual throughput of greater than 29 million bbl/yr
-------
Design assumptions:
• Hydrocarbon vapors destroyed via incineration
• Incinerator destruction efficiency * 98 percent
• Install four complete barge hydrocarbon vapor transfer lines
• Install two complete ship hydrocarbon vapor transfer lines
• Natural gae available 900 ft from incinerator
• Install terminal alarm system and vapor control system instruments
• Install two parallel sets of full capacity boosters for incinerator feed
to dock area
-------
APPENDIX B.
Documentation of Costs for an Incineration-Based Technology
«
-------
Cost Methodology Documentation (Model 5A)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 5 A
Incinerator capital cost
(220,400 + 111.57 x 3,550 scfm]) x 323.8/342.5 =
Installation
Total installed cost (rounded)
Inert Gas Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 1987 dollars using Chemical
Engineering indices. An additional 20 percent was
added for installation.
Example:
Richardson's XG size
Richardson's IG cost
Total:
Model 5A ZG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model 5A this maximum loading rate is 16,000 bbl/hr
(4 barges ® 4,000 bbl/hr/barge).
VOC gas stream flow is calculated as:
16,000 bbl/hr x 5.615 ft3/bbl - 89,840 ft3/hr
Inert gas required is calculated as:
89,840 ft3/hr x 1.37 ft3 IG/ft3 VOC's a 123,080 ft3/hr IG
Model 5A IG cost: 84,010 {123,080/60,000)0'7 x (323.8/322.7) x 1.2
- 167,270
Model 5A IG cost (rounded): 167,000
247,197
81,575
329,000
: 60,000 ft3/hr
(explosionproof) 79,900
(automatic flow control) 4,110
84,010
-------
C. Water System
A water system to provide brackish water to the inert gas
generator scrubber is costed for. The water system consists
of a pump and piping to and from the inert gas generator.
Pump costs from Perry's are multiplied by a factor of
1.4 for stainless construction. 0 Pipe costs from
Richardson's are multiplied, by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example:
Model SA
As sums 6 in. pipe
Flow • 8 gal/min/1,000 ft /min x 123,000 ft3/min
Average velocity
Reynolds No.:
Fricton factor:
Pressure drop
Pun?) cost a $6,000 x 1.4 x (323.8/355.4)
Pipe cost = $1,200/100 ft x 200 ft x 1.7 x (323.8/322.7)
Total
-1,000 gal/min
11.71 ft/sec
595
0 . 1
43 pai
7, 653
x 2 8.iaa
15,841
Total (rounded)
15,800
D. Other Maior Equipment
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
Example:
Model 5A
Incinerator booster £an
Incinerator detonation arrestor
Incinerator trip valve
3-way inert gas valve
Eductors
Detonation arrestors
Barge hydrocarbon vapor headers
Sack pressure valves
Total Other Major Equipment
25,000
34,960
10,680
6,500
4 x 6,250 - 25,000
4 x 24,076 - 96,304
4 x 5,280 a 21,120
* * 5-280 - 21.120
240,684
-------
E. Piping
The installed, capital costs of piping are taken from the UTD
estimate. The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 5A - IG generator to dock 200 ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 5A - low piping cost
IG eductor feed 4 x 1,311 = 5,244
IG water line 1,311
Hydrocarbon vapor feed 4 x 1,346.5 ¦ 5,386
Eductor discharge 4 x 2,683 * 10,732
IG feed header 36,456
Natural gas to incinerator 54,120
IG generator to dock 51.045 x (20Q ft/1,400 ft) = 7,292
Dock to incinerator 107,051 x (660 ft/1,400 ft) = 50.467
Total piping cost 171,088
Total piping cost (rounded) 171,000
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 5. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
Example:
Model 5A
Explosionproof alarm 16,800
Vapor line oxygen probe 5, 880
Barge header oxygen probes 4 x 5,880 = 23,520
Pressure - vaccum sensors 4 x 900 - 3' 600
Total instrumentation 49,800
-------
G. engineering, Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.
Engineering = 10 percent
Startup - 10 percent
Contingencies ¦ 5 percent
25 percent
H. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.
Example:
Modal 5A
Throughput = 2,000 hr/yr x 8,000 bbl/hr = 16,000,000 bbl/yr
Humber vessels = 16,000,000 bbl/yr|365 d/yr|1,000 bbl/vessel/d
¦ 43.84 vessels
TCI - $168,000/vessel x 43.84 vessels = 7,3 65,120
TCI (rounded) - 7,360,000
II. Annual Costs
Direct operating costs
A. Labor
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year.^ Assumed 2,000 operating hours per year.
Example:
Model SA
2,000 hr/yr|8 hr/shift ¦ 250 shi£ts/yr
250 shifts/yr x 0.5 hr/shift x $l2.96/hr x 1.15 - $l,863/yr
For operating both incinerator and IG generator x 2
From 1988 dollars to 1987 dollars x (323.8/342.5)
$3,523/yr
Labor (rounded) $3,520/yr
b. Maintenance
The costs of maintenance parts and. labor-are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance costs in the UTD document.2'5 Maintenance labor
is multiplied by 2 to compensate for the inert gas
generator. This number is again multiplied by 2 to
compensate for parts.
-------
Example:
Model 5A
$40,800/yr From UTD, annual preventive maintenance costs
¦ 8.000/vt Incinerator scrubber maintenance
$32,800/yr
Maintenance parts and labor
250 shifts/yr x 0.5 hr/shift x $14.26/hr
For maintaining both incinerator and IG generator
For parts
From 1989 dollars to 1987 dollars
Total maintenance = $32,800 + $6,741 a $39,541/yr
Total maintenance (rounded) » $39,500/yr
C. Natural Gag
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerator pilot light fuel costs from the UTD cost
estimate. ' The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.
IG generator fuel usage (ft3/hr - size (ft3/hr)/8.6 ft3
Example
Model 5A
o.s
49,090
7.650
56,740
56,700
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual.2,5 The usage agreed for
model 5. Electricity costs for incinerator feed fans was
taken from the UTD estimate for model 5A and adjusted to a
rate of $0.0472/kWh.2'8
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.7
Electrical usage for large generators was calculated as
um/u- _ IG size ft3/hr) x 45S , ,,
fcW/hr - T 505,500 } 16
$X,782/yr
x 2
x 2
(323.8/342.5
$6,741/yr
Percent of operating capacity « 8,000 bbl/hr|16,000 bbl/hr
IG fuel = 123,080 ft3/hr|8.6 x 2,000 hr/yr x
$3.43/1,000 ft3 x 0.5 «
Incinerator pilot light a
Total natural gas cost ¦
Total natural gas -
D.
The electricity usage of the incinerator feed fans as
f
-------
Example:
Model 5A
Electrical coats
[$o3oa/£wh + <{ 123'080 5oa^soox 455 " 16} x 2,000 hr'/yr)1 x 50.0472/kwh x
0.5 = $5,327/yr
Electrical costs (rounded) « $5,330/yr
Overhead is taken £o be 60 percent of the sum of labor and
maintenance costs.-
F. Property Taxes. Insurance, and Administration
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
G. Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Model 5A (low end)
CRC * [171,008 X 0.1175) + £(1,216.695 - 171,018) X 0.1627] = $190,267
CRC (rounded) * $190,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
«
-------
Example
The capital recovery charge and maintenance coats per vessel are shown
in rounded form on Table 3-3.
Model 5A
I. Emission Reduction
The emissions are calculated a9 follows:
(Emission factor, lb/1,000 gal) x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 9 8 percent.
Example
Model 5A (gasoline)
{3.4/1,000 gal) x (16,000,000 bbl/yr) x (42 gal/bbl) x 0.000453 Mg/lb) x
0.98 s 1,014 Mg/yr
J. Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model 5A (terminal only)
Capital recovery
Maintenance
Vessel retrofit TAC
$19,750/vessel x 43.84 vessels ¦ $866,000
$9,600/vessel x 43.84 vessels ¦ 420,000
1,286,000
369,900 ($/yr)
1,014 (Mg/yr)
365 (5/Mg)
Model 5A (terminal and ships)
1,655,739 ($/yr)
1,014 (Mg/yr)
- 1,632 ($/Mg)
t'
-------
Cost Methodology Documentation (Model 5B)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 5B
Incinerator capital cost
(220,400 + [11.57 x 3,550 scfm]) x 323.8/342.5 = 227,782
Installation 75,168
Total installed cost (rounded) 303,000
B. Inert Gas Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 1987 dollars using Chemical
Engineering indices.5'6'9 An additional 20 percent was
added for installation.
Example1:
Richardson's IG size: 60,000 ft3/hr
Richardson's IG cost: (explosionproof}
(automatic flow control) 79,900
Total: 84,010
Model 5B IG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model 5B this maximum loading rate is 8,000 bbl/hr
(2 barges <3 4,000 bbl/hr/barge) .
VOC gas stream flow is calculated as:
8,000 bbl/hr x 5.615 ft3/bbl = 44,920 ft3/hr
Inert gas required is calculated as:
44,920 ft3/hr x 1.37 ft3 IG/ft3 VOC's = 61,540 ft3/hr IG
Model 5B IG cost: 84,010(61,546/60,000)0•7 x (323.8/322.7) x
1.2 - 102,967
Model SB IG cost (rounded): 103,000
-------
C. Water System
A water system to provide brackish water to the inert gas
generator scrubber is costed for. The water system consists
of a pump and piping to and from the inert gas generator.
Puiuip costs from Perry's are multiplied by a factor of
1.4 for stainless construction. Q Pipe costs from
Richardson's are multiplied by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example:
Model 5B
Assume 6 in. pipe
Flow ¦ 8 gal/min/1,000 fc3/min x 123,000 ft3/min
(oversized) -1,000 gal/min
Average velocity 11.71 ft/sec
Reynolds No.: 595
Fricton factor: 0.1
Pressure drop 43 psi
Pump cost ¦ $6,000 x 1.4 x (323.3/355.4) 7,653
Pipe cost - $1,200/100 ft x 200 ft x 1.7 x (323.8/322.7) x 2 8,198
Total 15,841
Total (rounded) 15,800
D. Other Major Equipment
•
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
Example:
Model SB
Incinerator booster fan 25,000
Incinerator detonation arrestor 34,960
Incinerator trip valve 10,680
3-way inert gas valve 6,500
Eductors 2 x 6,250 - 12,500
Detonation arrestors 2 x 24,076 » • 48,152
Barge hydrocarbon vapor headers 2 x 5,280 « 10,560
Back pressure valves 2 x 5,280 - 10.560
Total Other Major Equipment 158,912
-------
E. Piping
The installed capital costs of piping are taken from the UTD
estimate. The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 5B - IG generator to dock 200 ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 5B - low piping cost
IG eductor feed 2 x 1,311 = 2,622
IG water line 1,311
Hydrocarbon vapor feed 2 x 1,346.S - 2,693
Eductor discharge 2 x 2,683 = 5,366
IG feed header 36,456
Natural gas to incinerator 54,120
IG generator to dock $26.93/ft x 200 ft 5,386
Dock to incinerator $52.55/ft x 660 ft 34.683
Total piping cost 142,637
Total piping cost (rounded) 143,000
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 5. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
Example:
Model 5B
Explosionproof alarm 16,800 \
Vapor line oxygen probe 5,880
Barge header oxygen probes 2 x 5,880 » 11,760
Pressure - vac cum sensors 2 x 900 = l. 800
Total instrumentation 36,240
-------
G. Engineering. Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.
Engineering - 10 percent
Startup - 10 percent
Contingencies - 5 percent
25 percent
H. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.2
Example:
Model 5B
Throughput
Number vessels
TCI
TCI (rounded)
II. Annual Costs
Direct operating costs
A. T.ahor
» 2,000 hr/yr x 4,000 bbl/hr * 8,000,000 bbl/yr
¦ 8,000,000 bbl/yr|365 d/yr|l,000 bbl/vessel/d
a 21.92 vessels
» $168,000/vessel x 21.92 vessels * 3,632,000
- 3,682,000
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year. Assumed 2,000 operating hours per year.
Example:
Model 5B
2,000 hr/yr|8 hr/shift » 250 shifts/yr
250 shifts/yr x 0.5 hr/shift x $12.96/hr x 1.15
For operating both incinerator and IG generator
Prom 1988 dollars to 1987 dollars
Labor (rounded)
B. Maintenance
$1,863/yr
x 2
X (323.3/342.5)
$3,523/yr
$3,520/yr
The costs of maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance costs in the UTD document.2,5 Maintenance labor
is multiplied by 2 to compensate for the inert gas
generator. This number is again multiplied by 2 to
compensate for parts.
-------
Example:
Model 5B
540,800/yr From DTD, annual preventive maintenance costs
- 8.000/vr Incinerator scrubber maintenance
$32,800/yr
Maintenance parts and labor $l,7 82/yr
For maintaining both incinerator and IG generator x 2
For parts x 2
From 1989 dollars to 1987 dollars (323.8/342 .5
$6,741/yr
Total maintenance = $32,800 + $6,741 * $39,541/yr
Total maintenance (rounded) = $39,500/yr
C. Natural Gas
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerator pilot light fuel costs from the UTD cost
estimate. ' The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.
IG generator fuel usage (ft3/hr) » size (ft3/hr)/8.6 ft3
• Example
Model SB
Percent of operating capacity ¦ 8,000 bbl/hr|16,000 bbl/hr * 0.5
IG fuel = 61,540 ft3/hr|8.6 x 2,000 hr/yx x
$3.43/1,000 ft3 X 0.5 - 24,545
Incinerator pilot light ¦ 7. 650
Total natural gas cost a 32,195
Total natural gas cost (rounded) « 32,200
. D. Electricity
The electricity usage of the incinerator feed fans as
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual.2'5 Electricity costs for
incinerator feed fans were taken from the UTD estimate for
model 5B and adjusted to a rate of $0.0472/kWh,
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.7
Electrical usage for large generators was calculated as
w.,/u size ft3/hr) x 455 , , ^
it** / IXX » V — - ""jj" Q ^ gQQ ¦" — ) "lb
-------
Example:
Model sb
Electrical costs-
^O^fl/kWh + <{-61,S4Q ^soflbgflQ 4~5- " 1S) x 2,000 hr/yr)] x $0.Q472/)cWh x
0.S * $2,728/yr
Electrical costs (rounded) = $2,730/yr
E. Overhead
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.
F. Property Taxes, Insurance, and Administration
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
G. Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Modal 5B (low end)
CRC a [142,637 X 0.1175] f [(932,722 - 142,637) x 0.1627] a $148,055
CRC (rounded) » $148,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
-------
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded form on Table 3-3.
Model 5B
Capital recovery= 519,750/vessel x 21.92 vessels = $433,000
Maintenance* $9,600/vessel x 21.92 vessels - 210.000
Vessel retrofit TAC = 643,000
I.' Emission Reduction
The emissions are calculated as follows:
(Emission factor, lb/1,000 gal) x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 98 percent.
Example
Model 5B (gasoline)
(3.4/1,000 gal) x (16,000,000 bbl/yr) x (42 gal/bbl) x 0.0004S3 Mg/lb) x
0.98 - 507 Mg/yr
J. Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model 5B (terminal only)
289, 853 {$/yr) e *9 ^ te /u^\
507 (Mg/yr) « 572 ($/M9}
Model 5B (terminal and ships)
932,772 (5/yr) , ,
507 (Mg/yr) ' 1,839 <5/M9>
-------
Cost Methodology Documentation (Model 5C)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 5C
Incinerator capital cost
(220,400 + [11.57 x 887.5 scfml)
Installation
Total installed cost (rounded)
323.8/342.5 « 218.074
71,964
290,000
B. Inert Gas Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 1987 dollars ysing Chemical
Engineering indices by EPA methodology. '°• 9 An additional
2 0 percent was added for installation.
Example.-
Richardson's IG size: 60,000 ft3/hr
Richardson's IG cost: (explosionproof) 79,900
(automatic flow control) 4,110
Total: 84,010
Model 5C IG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model 5C this maximum loading rate is 4,000 bbl/hr
(1 barge ® 4,000 bbl/hr/barge).
voc gas stream flow is calculated as:
4,000 bbl/hr x 5.615 ft3/bbl - 22,460 ft3/hr
Inert gas required is calculated as:
22,460 ft3/hr x 1.37 ft3 IG/ft3 VOC's ¦» 30,770 ft3/hr IG
Model 5C IG cost: 84,010 (30,770/60,000)°-7 x (323.8/322.7) x
1.2 - 63,383
Model SC IG cost (rounded): 63,400
-------
C. Water System
A water system to provide brackish water to the inert gas
generator scrubber is coated for. The water system consists
of a pump and piping to and from the inert gas generator.
Pump costs from Perry's are multiplied by a factor of
1.4 for stainless construction.10 Pipe costs from
Richardson's are multiplied by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example:
Model SC
Assume 6 in. pipe
Flo* a 8 gal/min/1,000 ft3/min x 123,000 ft3/min -1,000 gal/min
(oversized)
Average velocity 11.71 ft/sec
Reynolds No.: 595
Fricton factor: o.i
Pressure drop 4 3 psi
Pump cost • $6,000 x 1.4 x (323.8/355.4) 7,653
Pipe cost = $1,200/100 ft x 200 ft x 1.7 x (323.8/352.7) x 2 8.1S8
Total 15,841
Total (rounded) 15,300
D. Other Maior Equipment
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
Example:
Model 5C
Incinerator booster fan
Incinerator detonation arrestor
Incinerator trip valve
3-way inert gas valve
Eductors
Detonation arrestors
Barge hydrocarbon vapor headers
Back pressure valves
Total Other M&jor Equipment
25,000
34,960
10,680
6,500
X
6,250 -
6,250
X
24,076 a
24,076
x
5,280 -
5, 280
x
5,280 a
5.280
118,026
-------
B. Piping
The installed capital costs of piping are taken from the UTD
estimate. The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 5C - IG generator to dock200
ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 5C - low piping cost
IG eductor feed 1,311
IG water line 1,311
Hydrocarbon vapor feed 1,346.5
Eductor discharge 2,683
IG feed header 36,456
Natural gas to incinerator 54,120
ZG generator to dock $19.56/ft x 200 ft 3,912
Dock to incinerator $26.93/ft x 660 ft 17,774
Total piping cost 118,913
Total piping cost (rounded) 119,000
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 5. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
Sxample:
Model 5C
Explosionproof alarm 16,800
Vapor line oxygen probe 5,880
Barge header oxygen probes 1 x 5,880 - 5,880
Pressure - vac cum sensors 1 x 900 ¦ 900
Total instrumentation 29,460
«
-------
H.
Engineering. Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.
Engineering = 10 percent
Startup » 10 percent
Contingencies =» 5 percent
25 percent
Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.
Example:
Model 5C
Throughput
Number vessels
TCI
TCI (rounded)
ii. Amuai cpgta
1,000 hr/yr x 4,000 bbl/hr = 4,000,000 bbl/yr
4,000,000 bbl/yr|365 d/yr|l,000 bbl/vessel/d
10.96 vessels
$168,000/vessel x 43.84 vessels * 1,841,000
1,840,000
Direct operating costs
A. Labor
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year. Assumed 1,000 operating hours per year.5
Example:
Model 5C
1,000 hr/yr|8 hr/shift - 125 shifts/yx
125 shifts/yr x 0.5 hr/shift x $l2.96/hr x 1.15
For operating both incinerator and IG generator
Front 1989 dollars to 1987 dollars
Labor (rounded)
B. Maintenance
$932/yr
x 2
^ (32j.8/j42.$)
$1,761/yr
$1,761/yr
The costs of maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance costs in the UTD document.2'5 Maintenance labor
is multiplied by 2 to compensate for the inert gas
generator. This number is again multiplied by 2 to
compensate for parts.
«
-------
Model 5C
$40,800/yr From DTD, annual preventive maintenance costs
- 8.000/vr Incinerator scrubber maintenance
$32,800/yr
Maintenance parts and labor
125 shifts/yr x 0.5 hr/shift x $14.26 hr $891/yr
For maintaining both incinerator and IG generator x 2
For parts x 2
From 1989 dollars to 1987 dollars (323 .8/342 .5
Total maintenance ¦ $32,800 ~ $3,369 = $36,169/yr
Total maintenance (rounded) = $39,200/yr
$3,369/yr
C. Natural Gas
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerato-r pilot light fuel costs from the UTD cost
estimate. 1 The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.
IG generator fuel usage {ft3/hr - size (ft3/hr)/8.6 ft3"
Example
Model 5C
Percent of operating capacity « 4,000 bbl/hr|4,000 bbl/hr » 1.0
IG fuel = 30,770 ft3/hr|8.6 x 1,000 hr/yr x
$3.43/1,000 ft3 x 1.0 - 12,272
Incinerator pilot light a 7. 650
Total natural gas cost = 19,922
Total natural gas cost Crounded) * 19,900
D. Electricity
The electricity usage of the incinerator feed fans as
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual. The usage agreed for
model 5. Electricity costs for incinerator feed fans was
taken from the UTD estimate for models 5 and 6 and adjusted
to a rate of $0.0472/kWh. »8
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.7
Electrical usage for large generators was calculated as
KW/hr . *G *izei,ua!tuu' x 455
-------
Example:
Model 5C
Electrical costs
+ ({—!¦¦?' 272 goa'-gQ0X 455 - IS} x 2,000 hr/yr)] x S0.0472/kWh x
1.0 - $2,314
Electrical costs (rounded) = $2,300/yr
S. Overhead
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.
F. Property Taxes. Insurance, and Administration
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
G. Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year lif$ expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Model SC (low.end)
CRC - U18,026 x 0.1175) + [(794,572 - 118,026) x 0.1627} = $123,928
CRC (rounded) « $124,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
-------
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded form on Table 3-3.
Model 5C
I. Emission Reduction
The emissions are calculated as follows:
(Emission factor, lb/1,000 gal) x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 98 percent.
Example
Model 5C (gasoline)
(3.4/1,000 gal) x (4,000,000 bbl/yx) x (42 gal/bbl) x 0.000453 Mg/lb) x
0.98 = 254 Mg/yr
J. Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model SC (terminal only)
Capital recovery-
Maintenance
Vessel retrofit TAC *
$19,700/vessel x 10.96 vessels = $216,000
$9,600/vessel x 10.96 vessels = 105.000
321,000
238,636 ($/yr)
254 (Mg/yr)
Model 5C (terminal and ships)
= 941 ($/Mg)
254 (Mg/yx)
• 2..209 ($/Mg)
-------
Cost Methodology Documentation (Model 6A)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost. -
Example:
Model 6A
Incinerator capital cost
<220,400 + [XX.57 x 3,275 scfm]) x 323.3/342.5
Installation
Total installed cost (rounded}
B. Other Major Equipment
The capital costs for major equipment other than the
incinerator and inert gas generator are taken from the UTD
cost estimate.
Example:
Model 6A
Other major equipment 152,000
C. Piping
The installed capital costs of piping are taken from the UTD
estimate. The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 6A - low piping cost
Natural gas to incinerator 1,105,949 x (2,640 ft/31,680 ft} - 92,162
Dock to incinerator 445,650 x (660 ft/6,000 ft) * 49,022
Total piping coat 141,184
Total piping cost (rounded) 141,000
244,189
80,582
325,000
-------
D. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate.
Example:
Model 6A
Total instrumentation 33,700
B. Engineering. Startup, and Contingencies
Engineering, startup, and contingencies - per the UTD cost
estimate, engineering, startup, and contingencies are
assumed to be 25 percent of the total installed equipment
cost. 1
Engineering * 10 percent
Startup - 10 percent
Contingencies - 5 percent
25 percent
F. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.
Example:
Model 6A
Throughput > 2,000 hr/yr x 35,000 bbl/hr ¦ 70,000,000 bbl/yr
Number vessels = 70,000,000 bbl/yr|365 d/yr|25,000 bbl/vessel/d
s 7 67 V6S86I9
TCI a $168,000/vessel x 7.67 vessels a 1,238,767
TCI (rounded) » 1,290,000
II. Annual Costs
Direct operating costs
A. Labor
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year. Assumed 2,000 operating hours per year.
Example:
Model 6A
2,000 hr/yr|8 hr/shift ¦ 250 shifts/yx
250 shifts/yr x 0.5 hr/shift x $12.96/hr x 1.15 « $l,863/yr
From 1989 dollars to 1987 dollars x (323.3/342.5)
$l,76i/yr
. Labor (rounded) $l,760/yr
-------
B. Maintenance
The costs of maintenance are taken from the OAQFS control
cost manual, 4th §d., and added to the maintenance costs in
the UTD document. '5 Maintenance labor is multiplied by two
to compensate for parts.
Example:
Model 6a
$28,000/yr From DTD, annual preventive maintenance costs
Maintenance parts and labor
250 shifts/yr x 0.5 hr/shift x $14.26/hr $l,782/yr
For parts x 2
From 1989 dollars to 1987 dollars f323.8/342.5
$3,369/yr
Total maintenance s $28,800 + $3,369 = $31,369/yr
Total maintenance
-------
F. Property Taxes. Insurance, and Administration
Property taxes, insurance, and administration are calculated
a9 4 percent of terminal capital costs.5
G. Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Model 6A (low end)
CRC - [141,184 X 0.1175] + [815,049 - 141,184) X 0.1627] = $126,252
CRC (rounded) » $125,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded form on Table 3-3.
Model SA
Capital recovery = $19,700/vessel x 7.67 vessels a $151,000
Maintenance a $4,800/vessel x 7.67 vessels = 3 6.800
Vessel retrofit TAC (rounded) = 188,000
I. Emission Reduction
The emissions are calculated as follows:
(Emission factor, lb/1,000 gal) x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 98 percent.
-------
Example
Model 6A (crude oil)
(0.61 lb/1,000 gal) x (70,000,000 bbl/yr) x (42 gal/bbl) x
0.000453 (Mg/lb) x 0.98 = 796 Mg/yr
J. Cost Effectivenesg
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model 6A (terminal only)
221,283 ($/yr) /e/ltol
(Mg/yr) * 278 (9/Mg>
Model 6A (terminal and ships)
409,483 (S/yr) _ c,„ /M„4
795 (Mg/yr) * 514 ($/Mg)
-------
Cost Methodology Documentation {Model 6B)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 6B
Incinerator capital cost
(220,400 + 111.57 x 1,775 SCfm)) x 323.8/342.5
Installation
Total installed cost (rounded)
B. Inert Gaa Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 1987 dollars using Chemical
Engineering indices. 9 An additional 20 percent was
added for installation.
Example:
Richardson's IG size: 60,000 ft3/hr
Richardson's IG cost: (explosionproof)
(automatic flow control)
Total:
Model 6B IG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model 6B this maximum loading rate is 8,000 bbl/hr
(2 barges <3 4,000 bbl/hr/barge) .
VOC gas stream flow is calculated as:
8,000 bbl/hr x 5.615 ft3/bbl s 44,920 ft3/hr
Inert gas required is calculated as:
44,920 ft3/hr X 1.37 ft3 IG/ft3 VOC's = 61,540 ft3/hr IG
Model SB IG cost: 84,010(61,546/60,000)0•7 x (323.8/322.7) x
1.2 - 102,967
Model SB IG cost (rounded): 103,000
227,782
75,168
303,000
79,900
84,010
f
-------
C. Water System
A water system to provide brackish water to the inert gas
generator scrubber is costed for. The water system consists
of a pump and piping to and from the inert gas generator.
Pump costs from Perry's are multiplied by a factor of
1.4 for stainless construction.10 Pipe costs from
Richardson's are multiplied by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example:
Model 6B
Assume 6 in. pipe
Flow a 8 gal/min/1,000 fc3/min x 123,000 ft3/mia. -1,000 gal/min
Average velocity 11.71 ft/sec
Reynolds No.: 595
Fricton factor: 0.1
Pressure drop 43 psi
Pump cose = $6,000 x 1.4 x (323.8/3S5.4) 7,653
Pipe cost * $1,200/100 ft x 200 ft x 1.7 x (323.8/322.7) x 2 8.188
Total IS,841
Total (rounded) 15,800
D. Other Ma-lor Equipment
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
Example:
Model SB
Incinerator booster fan
Incinerator detonation arrestor
Incinerator trip valve
3-ray inert gas valve
Bductors
Detonation arrestors
Barge hydrocarbon vapor headers
Back pressure valves
Total Other Major Equipment
25,000
34,960
10,680
6,500
2
X
6,250 -
12,500
2
X
24,076 -
48,152
2
X
5,280 =
10,560
2
X
5,280 s
10,5$g
158,912
-------
E. Piping
The installed capital costs of piping are taken from the UTD
estimate.^ The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
2 00 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 6B - IG generator to dock 200 ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 6B - low piping coat
IG eductor feed 2 x 1,311 = 2,622
IG water line 1,311
Hydrocarbon vapor feed 2 x 1,246.5 ¦ 2,693
Eductor discharge 2 x 2,683 ® 5,366
ZG feed header 3 6,456
Natural gas to incinerator 54,120
IG generator to dock $26.93/ft x 200 ft 5,386
Dock to incinerator $52.55/ft x 600 ft 34,683
Total piping coat 142,637
Total piping cost (rounded) 143,000
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 5. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
Example:
Model 6B
Explosionproof alarm 16,800
Vapor line oxygen probe 5,880
Barge header oxygen probes 2 x 5,880 » 11,760
Pressure - vaccum sensors 2 x 900 = i. 800
Total instrumentation 36,240
-------
G. Engineering. Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.
Engineering = 10 percent
Startup » 10 percent
Contingencies « 5 percent
25 percent
H. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.2
Example:
Model 6B
Throughput
Number vessels
TCI
TCI (rounded)
2,000 hr/yr x 4,000 bbl/hr =. 8,000,000 bbl/yr
8,000,000 bbl/yr|365 d/yr|1,000 bbl/vessel/d
21.92 vessels
$168,000/vessel x 21.92 vessels ¦ 3,682,000
3,682,000
II. Annual Costs
Direct operating coats
A. r.ahnT
The costs for operating labor and supervision are taken from
the OAQFS control cost manual, 4th ed. and adjusted for base
year. Assumed 2,000 operating hours per year.
Example:
Modal 6B
2,000 hr/yr|8 hr/shift - 2S0 shifts/yr
250 shifts/yr x 0.5 hr/shift x $12.96/hr x 1.15 = $l,863/yr
For operating both incinerator and 10 generator x 2
From 1988 dollars to 1987 dollars x (323.8/342 . S)
$3,523/yr
Labor (rounded) $3,520/yr
B. Maintenance
The costs of maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance costs in the UTD document.2'5 Maintenance labor
is multiplied by 2 to compensate for the inert gas
generator. This number is again multiplied by 2 to
compensate for parts.
-------
Example:
Model 6B
$40,800/yr From OTD, annual preventive maintenance costs
- S.0 0 0/vr Incinerator scrubber maintenance
$32,800/yr
Maintenance parts and labor $l,782/yr
For maintaining both incinerator and IG generator x 2
For parts x 2
From 1989 dollars to 1987 dollars (323.8/342 .5
56,74l/yx
Total maintenance * §32,800 + $6,741 » $39,54l/yr
Total maintenance (rounded) ¦ $39,500/yr
C. Natural Gas
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerator pilot light fuel costs from the UTD cost
estimate. '7 The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.
IG generator fuel usage (ft3/hr = size (ft3/hr)/8.6 ft3
Example
Model 6B
Percent of operating capacity - 8,000 bbl/hr|16,000 bbl/hr * 0.5
IG fuel a 61,540 ft3/hr|8.6 x 2,000 hr/yx x
$3.43/1,000 ft3 x 0.5 a . 24,545
Incinerator pilot light = 7.650
Total natural gas cost - 32,195
Total natural gas cost (rounded) = 32,200
D. Elqqpyjgity
The electricity usage of the incinerator feed fans as
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual.2,5 The usage agreed for
model 5. Electricity costs for incinerator feed fans was
taken from the UTD estimate for model 5A and adjusted to a
rate of $0.0472/kWh.2'8
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.7
Electrical usage for large generators was calculated as
vm/w _ size ft3/hr) x 455 s „
XIX m 509 500 "AO
-------
Example:
Model 68
Electrical costs
t$0306/k«h + ({ 61'540 £|a^|0g 455 - 16} x 2,000 hr/yr)} x $0.0472/kWh x
0.5 a $2,728/yr
Electrical costs (rounded) - $2,730/yr
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.5
F. Property Taxes, Insurance, and Administration
Property taxes, insurance, and administration are calculate
as 4 percent of terminal capital costs.
G. Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment.is assumed to
have a 10-year'life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Model 6B (low end)
CRC » [142,637 x 0.1175] + [(932,722 - 142,637) x 0.1627] = $148,055
CRC (rounded) . $148,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annua
costs represent capital recovery charges plus maintenance.
-------
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded form on Table 3-3.
Model 6B
Capital recovery $19,750/vessel x 21.92 vessels * $433,000
Maintenance $9,600/vessel x 21.92 vessels e 210.000
Vessel retrofit TAC - 643,000
I. Emission Reduction
The emissions are calculated as follows:
{Emission factor, lb/1,000 gal) x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 98 percent.
Example
Model SB (crude oil)
(1.0/1,000 gal) x (8,000.000 bbl/yr) x (42 gal/bbl) x 0.000453 Mg/lb) x
0.98 ¦ 149 Mg/yr
J. Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model 6B (terminal only)
289 , 853 ($/yr5 , \
149 (Mg/yr) 1,945
Model 6B (terminal and ships)
932,772 ($/yr) _ ,
145 IHg/yr) = 6'260 ($/M9)
-------
Cost Methodology Documentation (Model SC)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 6C
Incinerator capital cost installation
(220,400 + [11.57 x 3,550 scfitv] ) x 323.8/342.5 = 218.074
Installation 71,964
Total installed cost (rounded) * 290,000
B. Inert Gas Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 19 87 dollars using Chemical
Engineering indices.5'6'9 An additional 2 0 percent was
added for installation.
Example:
Richardson's IG size: 60,000 ft3/hr
Richardson's IG cost: (explosionproof) 79,900
(automatic flow control) 4,110
Total: 84,010
Model €C IG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model SC this maximum loading rate is 4,000 bbl/hr
(l barge <9 4,000 bbl/hr/barge) .
VOC gas stream flow is calculated as:
4,000 bbl/hr x 5.615 ft3/bbl - 22,460 ft3/hr
Inert gas required is calculated as:
22,460 ft3/hr x 1.37 ft3 IG/ft3 VOC's * 30,770 ft3/hr IG
Model 6C IG cost: 84,010(30,770/60,000)0•7 x (323.8/322.7) x
1.2 - 63,383
Model 6C IG cost (rounded): 63,400
-------
C. Water System
A water system to provide brackish water to the inert gas
generator scrubber is costed for. The water system consists
of a pump and piping to and from the inert gas generator.
Pump costs from Perry's are multiplied by a factor of
1.4 for stainless construction. 0 Pipe costs from
Richardson's are multiplied by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example;
Modal 6C
Assume 6 in. pipe
Flow m 8 gal/min/1,000 fr/min x 123,000 ft^/min
(oversized) -1,000 gal/min
Average velocity 11.71 fe/sec
Reynolds No.: 595
Fricton factor: 0.1
Pressure drop 4 3 pai
Pump cost a $6,000 x 1.4 x (323.8/355.4) 7,653
Pipe cost - $1,200/100 ft x 200 ft x 1.7 x (323.8/322.7) x 2 8.188
Total 15,841
Total (rounded) 15,800
Other Manor Equipment
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
Example:
Model 6C
Incinerator booster fan 25,000
Incinerator detonation arrestor 34,960
Incinerator trip valve 10,680
3-way inert gas valve 6,500
Sductors 1 x 6,250 » 6,250
Detonation arrestors l x 24,076 « 24,076
Barge hydrocarbon vapor headers 1x5,280s 5,280
Back pressure valves 1 x 5,280 ¦ S.280
Total Other Major Bquipment 113,026
-------
E. Piping
The installed capital costs of piping are taken from the UTD
estimate. The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 6C - IG generator to dock200
ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 6C - low piping cost
IG eductor feed 1,311
IG water line 1,311
Hydrocarbon vapor feed 1,346.5
Eductor discharge 2,683
IG feed header 36,456
Natural gas to incinerator 54,120
15 generator to dock $19.56/ft x 200 ft 3,912
Dock to incinerator $26.93/ft x 660 ft 17.774
Total piping cost 118,913
Total piping cost (rounded) 119,000
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 5. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
Example:
Model 6C
Explosionproof alarm 16,800
Vapor line oxygen probe 5,830
Barge header oxygen probes 1 x 5,880 = 5,880
Pressure - vaccum sensors 1 x 900 ¦ 900
Total instrumentation 29,460
-------
G. Engineering. Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.
Engineering = 10 percent
Startup = 10 percent
Contingencies - 5 percent
25 percent
H. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.2
Example:
Modal 6C
Throughput
Number vessels
TCI
TCI (rounded)
1,000 hr/yr x 4,000 bbl/hr * 4,000,000 bbl/yr
4,000,000 bbl/yr|3S5 d/yr|l,000 bbl/vessel/d
10.96 vessels
$168,000/vessel x 43.84 vessels ¦ 1,841,000
1,840,000
Annual Costs
Direct operating costs
A. MkSE
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year. Assumed 1,000 operating hours per year.
Example:
Model 6C
B.
1,000 hr/yr|8 hr/shift - 12S shifts/yr
125 shifts/yr x 0.5 hr/shift x $12.96/hr x 1.15
For operating both incinerator and IG generator
From 1989 dollars to 1987 dollars
Labor (rounded)
Maintenance
$932/yr
x 2
x (323.8/342.5)
$1,761/yr
$1,761/yr
The cost-s of maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance co9ts in the UTD document.2'5 Maintenance labor
is multiplied by 2 to compensate for the inert gas
generator. This number is again multiplied by 2 to
compensate for parts.
-------
Example:
Model 6C
$40,800/yx From UTD, annual preventive maintenance costs
- a.000/vr Incinerator scrubber maintenance
$32,800/yr
Maintenance parts and labor $891/yr
For maintaining both incinerator and ZG generator x 2
For parts x 2
From 1989 dollars to 1987 dollars (323,8/342.5
$3,369/yr
Total maintenance = $32,800 + $3,369 = $36,169/yx
Total maintenance (rounded) « $36,200/yr
0. Pfatural Gas
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerator pilot light fuel costs from the UTD cost
estimate. ' The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.7
IG generator fuel usage (ft3/hr = size (ft3/hr)/8.6 ft3
Example
Model ec
Percent of operating capacity ¦ 4,000 bbl/hr|4,000 bbl/hr * 1.0
IG fuel ¦ 30,770 ft3/hr18.6 x 1,000 hr/yr x
$3.43/1,000 ft3 X 1.0 = 12,272
Incinerator pilot light - 7.650
Total natural gas cost = 19,922
Total natural gas cost (rounded) s 19,900
D. Electricity
The electricity usage of the incinerator feed fans as
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual.2,5 The usage agreed for
model 5. Electricity costs for incinerator feed fans was
taken from the UTD estimate for model 5A and adjusted to a
rate of $0.0472/kWh.2,8
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.7
Electrical usage for large generators was calculated as
w/i IG size ft3/hr) x 455 ,
jtw/ni ¦ 508 500 J-o
-------
Example:
Model 6C
Electrical costs
^O^e/kWh + ({ 30'770 gaa(gQ0X 455 - 16} X 1,000 hr/yr)] x $0.0472/kWh x
1.0 3 $2,311/yr
Electrical costs (rounded) - $2,300/yr
e. overhead
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.
F. Property Taxes. Insurance, and Administration
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
G. CfrplCfrl Recovery ghaygg
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Model 6C (low end)
CRC a [118,026 X 0.1175] +¦ 1(794,572 - 118,026) X 0.1627] a $123,928
CRC (rounded) * $124,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping, instrumentation, and
associated hardware. For this reason, vessel retrofits are assumed to
have a 20-year life. Annual costs represent capital recovery charges
plus maintenance.
-------
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded form on Table 3-3.
Model 6C
Capital recovery $19,700/vessel x 10.96 vessels ¦ $216,000
Maintenance $9,600/vessel x 10.95 vessels - 105.000
Vessel retrofit TAC = 321,000
*• Emission Reduction
The emissions are calculated as follows:
(Emission factor, lb/1,000 gal) x (throughput, bt>l/yr) x
{42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 98 percent.
Example
Model 6C (crude oil)
(1.0/1,000 gal) x (4,000,000 bbl/yr) x (42 gal/bbl) x 0.000453•Mg/lb) x
0.98 » 75 Mg/yr
iT* Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model 6C (terminal only)
"yfoffr= 3,182 ($/Mg)
Model 6C (terminal and ships)
560,096 ($/yr) _ n lCa
75 (Mg/yr) " 7'468
-------
Cost Methodology Documentation (Model 7A)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 7a
Incinerator capital cost
{220,400 + [11.57 X 6,432 scfm]) x 323.8/342.5 =
Installation
Total installed cost (rounded)
B. Inert Gas Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 1987 dollars using Chemical
Engineering indices.5'6'9 An additional 20 percent was
addecj for installation. Model 7A is assumed to have two
similarly sized units for reasons explained in the text.
Example:
Richardson's IG size: 60,000 ft3/hr
Richardson's IG cost: (explosionproof)
(automatic flow control)
Total:
Model 7A IG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model 7A this maximum loading rate is 29,000 bbl/hr.
VOC gas stream flow is calculated as:
29,000 bbl/hr x 5.615 ft3/bbl * 162,835 ft3/hr
Inert gas required is calculated as:
162,835 ft3/hr x 1.37 ft3 IG/ft3 VOC's = 223,084 ft3/hr IG
Model 7A IG cost: 84,000(223,084/60,000)0•7 x 2 x (323.8/322.7)
x 1.2 - 312,226
Model 7A IG cost (rounded): 312,000
B-42
279,000
92-000
371,000
79,900
4-110
-------
c. Water System
A water system to provide brackish water to the inert gas
generator scrubber is costed for. The water system consists
of a pump and piping to and from the inert gas generator.
Pump costs from Perry's are multiplied by a factor of
1.4 for stainless construction.10 Pipe costs from
Richardson's are multiplied by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example:
Model 7a
Assume 10 in. pipe
Flow s 8 gal/min/1,000 ft3/min x 632,000 ft3/min
(oversized) -5,000 gal/min
Average velocity 21.1 ft/sec
Reynolds No.: 1,785
Fricton factor: 0.035
Pressure drop 25 psi
Pump cost - $12,500 x 1.4 x (323.8/35S.4) 15,944
Pipe cost = 51,950/100 ft x 200 ft x 1.7 x (323.8/322.7) x 2 13.305
Total 29,249
Total (rounded) 29.2J30
D. Other Maior Equipment
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
-------
Sxample:
Model 7A
Incinerator booster fan 112,680
Incinerator trip valve 26,000
3-way inert gaB valve 7,800
Incinerator booster fans 75,000
Eductor (barge) 6,250
Eductor (ship) 18,750
Detonation arreator (barge) 24,076
Detonation arrestor (ship) 33,460
Trip valve (barge) 5,280
Trip valve (ship) 10,680
Back pressure valve (barge) 5,280
Back preBBure valves (ship) 11.600
Total Other Major Equipment 336,856
e. Piping
The installed capital costs of piping are taken from the UTD
estimate. The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance. ~
Model 7A - IG generator to dock 200 ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 7A - low piping cost
IG eductor feed (barge)
IG eductor feed (ship)
Hydrocarbon vapor feed (barge)
Hydrocarbon vapor feed (ship)
Eductor discharge (barge)
Eductor discharge (ship)
Barge dock infeed header
IG recirculating line
Barge IG/hydrocarbon header
Dock to incinerator ($127.7i/ft x 660 ft) =
Natural gas line ($45/ft x 900 ft) »
Inert gas to dock ($76.465/ft x 200 ft) =
Piping (total)
Piping (rounded)
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 7. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
1, 311
2, 683
1, 342
3 , 712
2, 683
7,423
84,705
6,417
89,488
84,289
40,500
15.293
339,846
340,000
-------
Example:
Model ?A
Explosionproof alarm (barge) 35,000
Explosionproof alarm (ship) 21,000
Header oxygen probe (barge) 5,880
Header oxygen probe (ship) 5,800
Pressure - vaccum sensor 900
Pressure - vaccum senBor (ship) 900
Total instrumentation 69,560
G. Engineering. Startup, and Contingencies
Per the UTD cost estimate, engineering, startup, and
contingencies are assumed to be 25 percent of the total
installed equipment cost.
Engineering = 10 percent
Startup = 10 percent
Contingencies = 5 percent
25 percent
H. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.
Example:
Barges
Barges throughput * 1,000 hr/yr x 4,000 bbl/hr x l * 4,000,000 bbl/yr
No. barges = 4,000,000 bbl/yr|365 d/yr|1,000 bbl/vessel/d
= 10.96 barges
Ships
Ships throughput = 1,000 hr/yr x 25,000 bbl/hr = 25,000,000 bbl/yr
No. ships ¦ 25,000,000 bbl/yr|365 d/yr|20,000 bbl/vessel/d
= 3.42 ships
TCI a $168,000/barge x 10.96 barges + $426,000/ship x 3.42 ships =
TCI (rounded) = 3,300,000
II. Annual Costs
Direct operating costs
A. Labor
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year. Assumed 2,000 operating hours per year.
-------
Example:
Model 7A
1,000 hr/yr|8 hr/shift - 125 shifts/yr
125 shifts/yr x 0.5 hr/shift x $12.96/hr x 1.15 = $931.5/yr
For operating both incinerator and IG generator x 2
From 1989 dollars to 1987 dollars x (323.8/342.5)
$1,762/yr
Labor (rounded) $l,760/yr
B. Maintenance
The costs of maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance costs in the UTD document.2,5 Maintenance labor
is multiplied by two to compensate for the inert gas
generator. This number is again multiplied by two to
compensate for parts.
Example:
Model 7a
$64,800/yr From OTD, annual preventive maintenance costs
Maintenance parts and labor
125 shifts/yr x 0.5 hr/shift x $14.26/hr
For maintaining both incinerator and IG generator
For parts
From 1989 dollars to 1987 dollars
$891/yr
x 2
x 2
(323.6/342.5
$3,369/yr
Total maintenance » $64,800 + $3,369 = $68,169/yr
Total maintenance (rounded) - $68,200/yr
C. Natural Gas
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerator pilot light fuel costs from the UTD cost
estimate.2,7 The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.
IG generator fuel usage {ft3/hr » size (ft3/hr)/8.6 ft3
Example
Model 7A
Percent of operating capacity * 29,000 bbl/hr|29,000 bbl/hr = 1.0
IG fuel = 223,084 ft^/hr|8.6 x 1,000 hr/yr x
$3.43/1,000 ft3 x 1.0 » 88,974
Incinerator pilot light - i. 650
Total natural gas cost - 96,624
Total natural gas cost (rounded) = 96,600
-------
The electricity usage of the incinerator feed fans as
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual. '5 The usage appeared to
be understated for Model 7a. The incinerator fan
electricity usage was subsequently recalculated for
Model 7A.
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.7
Electrical usage for large generators was calculated as
, u/, IG size ft3/hr) x 455 >
Kw/nr c i y ** xt>
Example:
Incinerator booster fan consumption
0.0017 x 6,432 x 30/6 = 37.6 kw
Electrical costs
137.6 + 223'5Q8<50Q55 " x hr/yr)] x S0.0472/kWh x 1.0 - $10,441 yr
Electrical costs (rounded) = $10,400/yr
E. Overhead
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.
F. Property Taxes. Insurance, and Administration
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
G- Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
t
-------
Example:
Model 7A (low and)
CRC - [339,846 x 0.1175] + [(1,823,044 - 339,846) x 0.1627] = $281,302
CRC (rounded) * $281,000
H. Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded £orm on Table 3-11.
Model 7A
Capital recovery = $19,750/vessel x 10.96 barges = $216,460
$50,O38/ship x 3.42 ships = $171,130
Maintenance $9,600/vessel x 10.96 barges = 105,216
$14,400/ship x 3.42 ships = 49.248
Vessel retrofit TAC (rounded) ¦ 542,000
The emissions are calculated as follows:
(Emission factor, lb/1,000 gal} x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 9 8 percent.
Example
Model 7A (gasoline)
([3.4/1,000 gal x 4,000,000 bbl/yr] + [1.8 lb/1,000 gal x
25,000,000 bbl/yr] x 42 gal/bbl x 0.000453 Mg/lb) x 0.98 ¦ 1,093 Mg/yr
J. Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
-------
Example
Model 7 A (terminal only)
¦ 525
-------
Cost Methodology Documentation (Model 7B)
I. Capital Costs
A. Incinerator
The incinerator capital costs are taken from the OAQPS
Control Cost Manual. The installed incinerator cost was
calculated by adding 33 percent to the capital cost.
Example:
Model 7B
Incinerator capital coat
(220,400 + [11.57 x 14,638 scfm]>
Installation
Total installed cost (rounded)
x 323.8/342.5 = 338,481
121,599
490,000
B. Inert Gas Generators
The capital costs for inert gas were taken from
Richardson's, adjusted for increased size by EPA
methodology, and converted to 1987 dollars using Chemical
Engineering indices.5'6'9 An additional 2 0 percent was
added for installation. Model 7B is assumed to have four
similarly sized units for reasons explained in the text.
Example:
Richardson's IG size: 60,000 ft3/hr
Richardson's IG cost: (explosionproof) 79,900
(automatic flow control) 4.110
Total: 84,010
Model 7B IG size:
The size of the IG generator is based upon the terminal's maximum
loading rate. For model 7B this maximum loading rate is 66,000 bbl/hr.
VOC gas stream flow is calculated as:
66,000 bbl/hr x 5.615 ft3/bbl = 370,590 ft3/hr
Inert gas required is calculated as:
370,590 ft3/hr x 1.37 ft3 IG/ft3 VOC's a 507,708 ft3/hr IG
Model 7B IG cost: 84,000(507,708/4/60,000)0¦7 x 4 x (323.8/322.7)
x 1.2 * 683,566
Model 7B IG cost (rounded): 684,000
-------
C. Water System
A water system to provide brackish water to the inert gas
generator scrubber is costed for. The water system consists
of a pump and piping to and from the inert gas generator.
Pump costs from Perry's are multiplied by a factor of
1.4 for stainless construction. ^ Pipe costs from
Richardson's are multiplied by 1.7 to account for fittings
and installation. All costs are corrected to 1987 dollars.
Example:
Model 7B
Assume 10 in. pipe
Flow a 9 gal/min/l,000 ft3/min x 632,000 ft3/min -5,000 gal/min
(oversized)
Average velocity 21.l ft/sec
Reynolds No.: 1,785
Fricton factor: 0.035
Pressure drop 25 psi
Pump cost = $12,500 x 1.4 x (323.8/355.4) 15,944
Pipe cost * $1,950/100 ft x 200 ft x 1.7 x (323.8/322.7) x 2 13.30S
Total 29,249
Total (rounded) 29,200
D. Other Maior Equipment
The installed capital costs for major equipment other than
the incinerator and inert gas generator are taken from the
UTD cost estimate. Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the incinerator
booster fan, detonation arrestor, incinerator trip valve,
and three-way inert gas valve. Vessel based equipment
includes eductors, barge detonation arrestors, hydrocarbon
vapor headers, and backpressure valves. Cost for an
incinerator scrubber and inert gas booster fans have been
deleted as these items are no longer necessary when an inert
gas generator is used.
Example:
Model 7B
Incinerator detonation arrestor
112,680
Incinerator trip valve
26,000
3-way inert gas valve
7, 800
Incinerator booster fans
75,000
Eductors (barge)
4
X
6,250
25,000
Sductor (ship)
2
X
18,750
37,500
Detonation arrestor (barge)
4
X
24,076
96,304
Detonation arrestor (ship)
2
X
33,460
66,920
Trip valve (barge)
4
X
5,280
21,120
Trip valve (ship)
2
X
10,680
21,360
Back pressure valve (barge)
4
X
5,280
21,120
-------
Back pressure valves (ship) 2 x 11,600 23.200
Total Other Major Equipment 534,004
E. Piping
The installed capital costs of piping are taken from the UTD
estimate.2 The lengths of certain runs of pipe are varied
as follows. The IG generator was assumed to be mounted
200 ft from the dock. The pipe carrying the inert gas is of
the same specifications as in the UTD estimate, with the
cost adjusted linearly for the shorter distance.
Model 7B - IG generator to dock200 ft (constant)
Dock to incinerator 660 ft to 1,400 ft
Example:
Model 7B - low piping cost
IG eductor feed (barge) 4 x 1,311 » 5,244
IG educator feed (ship) ' 2 x 2,683 * 5,366
Hydrocarbon vapor feed (barge) 4x1,324= 5,368
Hydrocarbon vapor feed (ship) 2 x 3,712 - 7,424
Eductor discharge (barge) 4 x 2,683 = 10,732
Eductor discharge (ship) 2 x 7,423 = 14,846
Barge dock infeed header 84,705
IG recirculating line 6,417
Barge IG/hydrcarbon header 89,488
Dock to incinerator ($178,975/ft x 660 ft) > 118,124
Natural gas line ($45/ft x 900 ft) = 40,500
Inert gas to dock ($127.71/ft x 200 ft) 25.542
Piping (total) 413,756
Piping (rounded) 414,000
F. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate. The number costs of the vapor line oxygen
probe and explosionproof alarm are the same as those for the
original Marine Board Model Terminal 7. The required number
of vessel-associated oxygen probes and pressure-vacuum
sensors is based on the maximum number of loading vessels.
However, the per item costs are the same as those provided
in the UTD estimate.
Example:
Model 7b
Explosionproof alarm (barge)
Explosionproof alalrm" (ship)
Header oxygen probe (barge)
Header oxygen probe (ship)
Pressure - vaccum sensor
Pressure - vaccum sensor (ship)
Total instrumentation
35,000
21,000
4
X
5,880 -
23,520
2
X
5,880 =
11,760
4
X
900 =
3, 600
2
X
900 »
1.800
96,680
-------
G. Engineering. Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.
Engineering » 10 percent
Startup = 10 percent
Contingencies = 5 percent
25 percent
H- Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.
Example:
Barges
Barges throughput » 2,000 hr/yx x 4,000 bbl/hr x 2 * 16,000,000 bbl/yr
No. barges = 16,000,000 bbl/yr|365 d/yr|1,000 bbl/veasel/d
* 43.84 barges
Ships
Ships throughput ¦ 2,000 hr/yx x 25,000. bbl/hr = 50,000,000 bbl/yr
No. ships a 50,000,000 bbl/yr|365 d/yr|20,000 bbl/vessel/d
= 6.85 ships
TCI = $168,000/barge x 43.84 barges + 5426,000/ship x 6.85 ships a
TCI (rounded) » 10,300,000
II. Annual Costs
Direct operating costs
a. ha&sz.
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year. Assumed 2,000 operating hours per year.
Example:
Model 7B
2,000 hr/yr|8 hr/shift a 250 shifts/yr
250 shifts/yr x 0.5 hr/shift x $12.96/hr x 1.15 a $l,863/yr
For operating both incinerator and 13 generator x 2
From 1989 dollars to 1987 dollars x (323.8/342.5)
$3,523/yr
Labor (rounded) $3,520/yr
B- Maintenance
The costs of maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance cogts in the UTD document.5 Maintenance labor
-------
is multiplied by 2 to compensate for the inert gas
generator. This number is again multiplied by 2 to
compensate for parts.
Example:
Model 7B
$64,B00/yr From DTD, annual preventive maintenance costs
Maintenance parte and labor
250 shifts/yr x 0.5 shift x $14.26/hr $l,782/yr
For maintaining both incinerator and IG generator x 2
For parts x 2
From 1989 dollars to 1987 dollars (323.8/342.5)
$6,739/yr
Total maintenance = $64,800 * $6,739 = $7l,539/yr
Total maintenance (rounded) ¦ $7i,500/yr
C. Natural Gas
The natural gas costs were developed by estimating the
amount of natural gas necessary for the IG generator and
adding incinerator pilot light fuel costs from the UTD cost
estimate.2,7 The equation relating natural gas usage to
inert gas generated was derived from data provided by
Industrial Gas Systems.7
IG generator fuel usage (ft3/hr - size (ft3/hr}/8.6 ft3
Example
Model 7B
0.5
202,493
7. 650
210,143
210,000
Percent of operating capacity ¦ 33,000 bbl/hr|66,000 bbl/hr =
IG fuel - 507,700 ft3/hr|8.6 x 2,000 hr/yr x
$3.43/1,000 ft3 x 0.5 =
Incinerator pilot light »
Total natural gas coat ®
Total natural gas cost (rounded) =
O. Electricity
The electricity usage of the incinerator feed fans as
specified in the UTD estimate was checked using methodology
in the OAQPS control cost manual. '5 The usage appeared to
be understanded for Model 7B. The incinerator fam
electricity usage was subsequently recalculated for
Model 7B.
An equation for IG generator electrical usage was
extrapolated from data provided by Industrial Gas Systems.
Electrical usage for large generators was calculated as
*„/hr. fG3l'e^u5' x 455 >-"
-------
Example:
Incinerator booster fan consumption
0.00117 x 14,638 x 30/6 * 05.6 kw
Electrical costs
[85.6 * {5°7gofl°gQQ455 " 16}] * 2,000 hr/yr)] x $0.0472/kWh x 0.5 - $24,725 yr
Electrical costs (rounded) = $24,700/yr
E. Overhead
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.
F. Property Taxes. Insurance, and Administration
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
G. Capital Recovery Charge
The capital recovery charge is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life.
Capital recovery factors
0.1175 - piping
0.1627 - all other equipment
Example:
Model 7B (low end)
CRC = [414,000 x 0.1175] + [{2,809,173 - 414,000) X 0.1627] . $438,443
CRC (rounded) = $438,000
H- Vessel Retrofit Total Annual Cost (TAC)
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
-------
Example
The capital recovery charge and maintenance costs per vessel are shown
in rounded form on Table 3-11.
Model 7B
Capital recovery * $19,750/barge x 43.84 barges ¦ $865,040
$50,038/ship x 6.85 ships = 342,760
Maintenance $9,600/barge x 43.84 barges = 420.864
$14,400/ship x 6.85 ships = 98,640
Vessel retrofit TAC (rounded) ¦ 1,730,000
I. Emission Reduction
The emissions are calculated as follows:
(Emission factor, lb/1,000 gal) x (throughput, bbl/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 98 percent.
Example
Model 7B (gasoline)
((3.4/1,000 gal) x 16,000,000 bbl/yr] + ' [1.8 lb/1,000 gal x
50,000,000 bbl/yr]) x 42 gal/bbl x 0.000453 Mg/lb) x 0.98 - 2,692 Mg/yr
J. Cost Effectiveness
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example
Model 7B (terminal only)
905,776 ($/yr)
2,592 (Mg/yr) * 336 <$/Mg)
Model 7B (terminal and ships)
2,632,970 ($/yr) a„„
2,692 (Mg/yr) " 9 8
-------
APPENDIX C. Carbon Adsorber
Design Characteristics and
Adsorber Capital Costs
-------
CARBON ADSORBER DESIGN CHARACTERISTICS AND ADSORBER CAPITAL COSTSa
Model terminal
Total waste gal
flow rate, Q
(ft3/min>
Inlet gasoline man
flowrate,
flb/hr)
Density of gasoline
v*P°r- 'gasoline
(lb/ft )
Volumetric flowrate
of gasoline
Valine (fti/tTUn)
Inlet concentration
of gasoline,
cgaaoline
Equilibrium
capacity, (lb
VOC/lb carbon)
Working capacity,
wc (lb VOC/lb
caitoon)
5a
1,497
2,285
0 1706
223.2
149,000
2 19
0.31
0.1085
SB
749
1.142
0.1706
111.6
149,000
2 19
0.31
0.1085
5C
374
571
0 1706
55.79
149,000
2 19
0.31
0 I08S
7a
2,714
2,461
0.1706
240.4
88,600
1 30
0.29
0.10
7B
6,177
6,085
0.1706
592.3
95,900
1.41
0.29
0.10
-------
CARBON ADSORBER DESIGN CHARACTERISTICS AND ADSORBER CAPITAL COSTSa
(continued)
Model terminal
Deaorptioa time,
(boun)
Adsorption time, 9^
(hour*
No. of adsorbing
beds, Na
No. of desorbing
beds, Nf)
Curixjn
requirement, Mc
(lb)
Carbon requirement
per bed, M'c (lb)
Total waste flow
per bed, Q'
(fl'/min)
Vessel diameter, D
(ft)
5A
1.00
1
I
1 ¦
42.120
21.060
1,497
8.73
SB
I 00
1
I
1
21,060
10,500
749
6.17
5C
1.00
1
1
1
10,500
5,250
374
4.37
7A
0.67
1
3
2
40,410
8,080
905
6.79
7B
j 0.67
1
3
3
99,500
19,920
2,059
10.24
'Complete documentation of all of the design variable* above la provided in Appendix D.
O
-------
CARBON ADSORBER DESIGN CHARACTERISTICS AND ADSORBER CAPITAL COSTSa
(continued)
Mode! terminal
Cartxw bed tbicknesi,
•n. <")
Vessel length, L (ft)
Superficial bed
velocity, v^ (tl/rnm)
Surface area, S (ft^)
Cost of carbon, Cc
(J1987)
Coat per vessel Cy
($1987)
Cod of adsorbed and
cartoon ($1987)
5A
11.72
15.72
25
551
76,740
33,510
316,400
5B
11 72
15.72
25
365
38,370
24,310
210,000
SC
11.72
15.72
25
246
19,190
17,870
145.400
7A
7.45
10 45
25
295
73,640
20.620
359,400
7B
1 8.06
116
25
521
181,500
32,060
623.000
-------
APPENDIX D.
Documentation of Costs for a Carbon Adsorption-Based Technology
-------
GLOSSARY OF SYMBOLS AND ABBREVIATIONS
CA total adsorber equipment cost, $1,987
Cc cost of carbon, $1,987
Cc]_ labor cost of replacing carbon, $/lb x Mc
Ccw cost of cooling water
cfm cubic feet per minute (ft3/min)
cgasoline inlet concentration of gasoline
Cp cost of piping
Cr cost of carbon replacement
CRC capital recovery charge, $1,9 87
CRFc capital recovery factor for carbon {based on 2-yr
life and 10 percent interest rate)
CRFp capital recovery factor for piping {based on 20-yr
life and 10 percent interest rate)
CRFg system capital recovery factor {based on 10-yr
equipment life and 10 percent interest rate)
Cs steam cost, $1,987
Cy. cost per vessel, $1,987
D adsorber diameter, ft
carbon bulk density, lb/ft3
Pgagoiine density of gasoline vapor, lb/ft3
APb pressure drop through the bed, inches of water
APg total system pressure drop, inches of water
E adsorber control efficiency, assumed to be
95 percent
eff combined pump-motor efficiency, percent
fj ratio of 1987 to 1989 cost indices
f2 terminal annual operating capacity, percent
H required head, ft
hp horsepower
hpcf horsepower needed to run the cooling fan, hp
h?cwp horsepower needed to run the cooling water pump, hp
kWh kilowatt-hours
kWhCf electricity needed to run the cooling fan, kilowatt -
hours/yr
-------
kWhCWp electricity needed to run the cooling water pump,
kWh/yr
kWhgf electricity needed to run the system fan, kWh/hr
L adsorber length, ft
M molecular weight, lb/lb-mole
Mc carbon requirement, lb
M'c carbon requirement per bed, lb
MG megagram
gasoline mass flow rate to the adsorber, lb/hr
Na number of adsorbing beds
Nd number of desorbing beds
P pressure, atm
Pgasoline partial pressure of gasoline, psia
pg steam price, dollars per thousand lb of steam
pvoc value of recovered product, $/lb
ppm parts per million
psia lb/in.2
Q total waste gas flow, ft3/min
Q' total waste gas flow per bed, ft3/min
qcw cooling water flow, gallons/yr (gal/yr)
^gasoline volumetric flowrate of gasoline, ft3/min
R gas constant, 0.7302 ft^ atm/lb-mole °R
Rc ratio of total adsorber equipment cost to the cost
of the adsorber vessels
RC recovery credit, $1,987
°R degrees Rankin, °F + 459.57
S surface area of each adsorber vessel, ft2
T temperature, °R
ta g access/gas distribution allowance, ft
TAC total annual cost
t^ carbon bed thickness, ft
TCI total capital investment
0A adsorption time, hours
©C£ annual operating time of the cooling fan, hours
0CWp annual operating time of the cooling water pump,
hours
-------
Bp desorption time, hours
0g total annual terminal operating time, hr/yr
TkWh total annual electricity consumption, kWh/yr
UTD document document that presents costs of controlling vapor
using incineration
vb superficial bed velocity, ft/min
wc working capacity of the carbon, lb VOC/lb carbon
we equilibrium capacity of the carbon, lb VOC/lb carbon
ygag mole fraction of gasoline vapor in total waste gas
flow
-------
DOCUMENTATION FOR CARBON ADSORPTION COSTS: MODEL TERMINAL 5A
I. CAPITAL COSTS
A. Carbon Adsorber
l. Gasoline mass flow rate to adsorber (n^^) , lb/hr:
ravoc = (4 fa*****) x <4'000 bbl/hr) x 1^So1gal x
mvoc =2.284.8 lb/hr
2. Total waste gas flow (Q), ft3/m:
Q = (4 barges) x (4,'
Q = 1,497.33 ft3/min
Q = (4 barges) x (4,000 bbl/hr) x (5.615 ft3/bbl) x (^ j^n)
3. Volumetric flowrate of gasoline (<3gasoline^ '
gasoline = x
pgasoline hr
First, calculate density of gasoline vapor, Pgasoiine
lb/ft3:
MP
"gasoline * RT li
-------
C ... = q9a8°line x 10s = X 106 = 149,030 ppm
gasoline Q 1,497.33 ^
5. Partial pressure of gasoline (Pgasoline^' Ps^a:
Pgasoline ™ ^gas x ^
ygag = mole fraction of gasoline in total flow
P » total pressure (atmospheric)
" ~i9'°l° PPmx 14 . 696 psia
^gasoline x x 1Q6 ppm
Pgasoline = 2*19 psia
6. Equilibrium capacity (wfi) of the carbon, lb VOC/lb
carbon:
we ¦ 31 percent - 31 lb VOC/100 lb carbon
lb VOC
» 0.31
lb carbon
[As determined from the n-pentane isotherm (capacity weight
percent vs. partial pressure, psia) for n-pentane adsorption
on Calgon's BPL activated carbon]. Note: the n-pentane
isotherm was used to represent gasoline vapor since
n-pentane is a major constituent in gasoline vapor.
7. Working capacity (wc) of the carbon, lb VOC/lb carbon:
Because gasoline contains relatively high vapor-pressure
constituents and the desorption cycles are very short,
assume that the working capacity is about 35 percent of the
equilibrium capacity.
-------
• ~ rt ^ 31 10.85 lb VOC A inQC lb VOC _ u
c~ ' 100= 100 lb carbon* ' lb carbon c
8. Number of adsorbing and desorbing beds and adsorption
time:
The number of adsorbing and desorbing beds (NA and ND,
respectively) and the adsorption time (0A) were determined
by trial and error. Due to shipping restrictions, vessel
diameters rarely exceed 12 feet, while their length is
generally limited to 50 feet.1 The number of adsorbing and
desorbing vessels and adsorption time directly affect vessel
dimensions. To obtain "reasonable" vessel dimensions, very
short adsorption and desorption times were necessary (i.e.,
l-hour adsorption and desorption cycles). At longer
adsorption times, the bed thictaiess and the pressure drop
through the bed increased sharply. At higher pressure
drops, electricity costs rapidly increased due to the
enormous amount of electricity needed to run the cooling
water pump. For model terminal 5A, the nuiqber °f adsorbing
beds = l, and the number of desorbing beds = l; the
adsorption and desorption times both equal 1 hour. Ideally,
the optimum regeneration frequently for fixed bed adsorbers
treating streams with moderate to high VOC inlet loadings is
once every 8 to 12 hours.1 However, at adsorptions times in
this range the lengths of the vessels were very high
(greater than 300 feet) and the diameters very small (less
than a foot).
The desorption time, ©D, is set once the number of adsorbing
and desorbing units and the adsorption time are determined,
as follows:
-------
where:
where:
0A = adsorption time
Nd - number of desorbing units
Na = number of adsorbing units
'• eD ^ 1(T>
0D a 1 hour
Carbon requirement (Mc), lb
M mvoc a ND.
C = "IT" A (1 +
- gasoline vapor flowrate (2,284.8 Ib/hr)
wc - working capacity of carbon (0.1085 1Jj1carSon>
0A = adsorption time (1 hour)
Nd = number of desorbing units (l)
Na = number of adsorbing units (l hour)
m 2,284.8 lb/hr . 1,
M aBr 1 W -irAri ^ -L hour X (X + T")
C n ,nnr- lb VQC 1
°*1085 lb carbon
Mc = 42,116 lb of carbon
10. Cost of carbon (Cc):1
The cost of carbon in 1989 was approximately $2.QQ/lb.1
Therefore, the cost of the carbon is calculated as
follows:
Cc - $2. QQ/lb x Mc xf^
where:
f1 = ratio of 1987 to 1989 cost indices = 323.8/355.4
-------
Cc = 2.00 X 42,116 x 323.8/355.4 > $76,743
11. Carbon requirement per bed (M'c), lb:
M
42,116 lb of carbon
— - 21,058 5i5
12. Total waste gas flow per bed (Q'), ft3/min:
0 1,497 ft3/min
N, 1
A
= 1,497 ft3/min = Q'
13. Superficial bed velocity (vb), ft/min:
A superficial bed velocity of 25 ft/min was chosen by a
"trial and error" basis. The superficial bed velocity, v^,
directly affected the pressure drop through the bed. At
higher velocities (e.g., 50 to 100 ft/min) the pressure drop
rose dramatically, which greatly increased annual
electricity costs.
14. Adsorber vessel dimensions--diameter (D) and length
{L), feet:
Because of the relatively low gas flowrate
(Q' <9,000 ft^/min), it was more economical to design
vertical rather than horizontal adsorber vessels.
For a vertical vessel, the diameter is calculated as
follows:
.4 x 1,497 ft3/minQ1/2
7r x 25 ft/min
8.73 feet = D
-------
The length (height) of the vessel is calculated using the
following equation:
L = fcb + ca,g
where:
t^ * carbon bed thickness in feet; and
t_ _ = access/gas distribution allowance
® * y
a 2 to 6 ft (depending on vertical vessel
diameter)
The carbon bed thickness is calculated as follows:
M' / o
volume of carbon c'Hb
b cross-sectional area normal to flow Q'/v^
where:
= carbon bulk density = 3 0 lb/ft^
• r _ (21,058/30) _ ¦ - r
. . tb - (1,497/25) ~ = b
Assume that t, _ = 4 feet; then
A i y
L = 11.72 + 4 = 15.72 feet — L
15. Surface area of each vessel (S), ft2:
S - 7rD (L + D/2)
- tt x 8.73 x (15.72 + 8.73/2) = 550.85 ft2
S » 551 ft2
16. Cost per vessel (Cy.) r1
Cy. = 271 x s0-778 x fx
-------
where:
f1 = ratio of 1987 to 1989 cost indices - 323.8/355.4;
and
97 < S < 2,110 ft2
.-. Cy = 271 x (551)0-778 x (323.8/355.45 = $33,510
Note: The costs are based on the assumption that the
adsorber vessels will be made of 304 stainless
steel.
17. Total adsorber equipment cost, (CA), 1987 $:
CA - Rc fCc + NA + ND}
where:
Rc = ratio of the total adsorber equipment cost to the
cost of the vessels
Cc cost of the carbon = $76,743
Na = number of adsorbing units = l
Nd = number of desorbing units = l
Cv = cost of each unit = $33,510
Rc is calculated using the following formular1
Rc = 5.82 x q-0.133
= 5.82 x (1,497 ft3/min)"°-133
Rc = 2.201
CA = 2.201 x [76,743 + (2 x 33,510)]
CA - $316,411
-------
B. Other Maior Equipment
The installed capital costs for major equipment other than
the carbon adsorber are taken from the UTD cost estimate for
incineration-based controls.2 Certain equipment is required
regardless of the number of loading vessels while other
equipment is costed for based on maximum number of loading
vessels. Required equipment includes the booster fan,
detonation arrestor, and carbon adsorber trip valve.
Vessel-based equipment includes eductors, barge detonation
arrestors, hydrocarbon vapor headers, and backpressure
valves. Cost for an incinerator scrubber and inert gas
booster fans have been deleted as these items are no longer
necessary when carbon adsorption is used.
Example:
Model 5A
Carbon adsorber booster fan 25,000
Carbon adsorber detonation arrestor 34,960
Carbon adsorber trip valve 10,680
Eductors 4 x 6,250 = 25,000
Detonation arrestors 4 x 24,076 = 96,304
Barge hydrocarbon vapor headers 4 x 5,280= 21,120
Back pressure valves 4 x 5,280 = 21.120
Total other major equipment 234,184
C. piping
The installed capital costs of piping are taken from the UTD
estimate for incineration-based controls.2 The piping costs
are adjusted linearly as follows:
Model 5A - Dock to carbon adsorber: 660 ft to 1,400 ft
Example:
Model 5A - low piping cost
Hydrocarbon vapor feed 4 x 1,346.5 = 5,386
Eductor discharge 4 x 2,683 = 10,732
-------
Dock to carbon adsorber $52.55/ft x 660 ft 34.683
Total piping cost 50,800
D. Instrumentation
The capital costs for instrumentation are taken from the UTD
cost estimate for incineration-based controls.2 The costs
of the vapor line oxygen probe and explosionproof alarm are
the same as those for the original Marine Board Model
Terminal 5. The required numbers of vessel-associated
oxygen probes and pressure-vacuum sensors are based on the
maximum number of loading vessels. However, the per-item
costs are the same as those provided in the UTD estimate.
Example:
Model 5A
Explosionproof alarm 16,800
Vapor line oxygen probe 5,880
Barge header oxygen probes 4 x 5,880 = 23,52 0
Pressure - vacuum sensors 4 x 900 = 3,600
Total Instrumentation 49,800
E. Engineering. Startup, and Contingencies
Engineering, startup, and contingencies are assumed to be
25 percent of the total installed equipment cost.2
Engineering = 10 percent
Startup = 10 percent
Contingencies = 5 percent
25 percent
F. Associated Vessel Total Capital Investment (TCI)
The capital costs associated with vessel retrofit are based
on estimates in the UTD document.2
-------
Example:
Model 5A
Throughput » 2,000 hr/yr x 8,000 bbl/hr =
16,000,000 bbl/yr
Number vessels - 16,000,000 bbl/yr|365 d/yr!l,000
bbl/vessel/d
= 43.84 vessels
TCI - $168,000/vessel x 43.84 vessels - 7,365,120
TCI (rounded) - $7,360,000
ANNUAL COSTS
A. Labor
The costs for operating labor and supervision are taken from
the OAQPS control cost manual, 4th ed. and adjusted for base
year.4 Assumed 2,000 operating hours per year.^
Example:
Model 5A
2,000 hr/yr|8 hr/shift * 250 shifts/yr
250 shifts/yrxO.5 hr/shiftx$l2.96/hxl.15
From 1988 dollars to 1987 dollars
$1,762/yr
Labor (rounded)
B. Maintenance
The costs for maintenance parts and labor are taken from the
OAQPS control cost manual, 4th ed., and added to the
maintenance costs in the UTD document.^'® Maintenance labor
is multiplied by 2 to allow for parts.
Example:
Model 5A
$40,800/yr From UTD, annoal preventive maintenance costs
- 8.000/yr Incinerator scrubber maintenance
$32,800/yr
= $1,863/yr
x (323.8/342.5)
$1,762/yr
-------
Maintenance parts and labor
250 shifts/yr x 0.5 hr/shift x $14.26/hr $l,782/yr
For parts x 2
From 1988 dollars to 1987 dollars (323.8/342.5)
$3,370/yr
Total maintenance = $32,800 + $3,370 » $36,170/yr
Total maintenance (rounded) = $3 6,2 00/yr
C. Electricity Costs
In fixed-bed adsorbers, electricity is consumed by the
system fan, bed drying/cooling fan, cooling water pump, and
solvent pump(s).1 Because the solvent pump horsepower (hp)
is usually very small (<0.1 hp), its electricity consumption
is assumed to be negligible.^ The electricity requirements
associated with the fans and the cooling water pump are
detailed below and were calculated using equations presented
in the OAQPS Control Cost Manual. Note that a factor of
0.50 was added to these equations so that annual costs
(unlike capital costs) are based on actual terminal
throughput rather than on the maximum throughput. The
0.5 factor represents the percent of terminal operating
capacity.
1. System fan, kWhgf
The following equation was used to calculate the annual
amount of electricity consumed by the system fan in kilowatt
hours per year (kWh/yr)i1
kWhsf - 0.746 kW/hp x (2.50 x 10"4) x Q x aPb x 0g x f2
where:
hp - horsepower
2.50 x 10"4 = conversion factor with units of hp
min/ft-* in.
Q = total waste gas flow (1,497 ft^/min)
aPs - total system pressure drop (in inches of
water)
0S - total operating time (2,000 hr/yr)
-------
£2 » percent of terminal operating capacity
(0.50)
The system pressure drop, APgl is equal to the pressure drop
through the carbon bed, aP^, plus any miscellaneous pressure
losses through the external ductwork and other parts of the
system.1 Assuming that these miscellaneous pressure losses
amount to 1 additional inch, Apg is equal to aP^ + 1.
The pressure drop through the carbon bed, APb, is calculated
as follows:
aP^ (inches water) - t^(0.03679v^ + 1.107 x 10"2v^2) + 1
where:
t^ = carbon bed thickness (11.72 ft)
= superficial bed velocity (25 ft/min)
aP^ = 11.59 inches of water
and APg = 11.59 + 1 = 12.6 inches of water
The amount of electricity consumed by the system fan.(kWhgf)
is then calculated as follows:
fcWh . . kw X [2.50 x 10"4 "P "ln 1 x 1'497.tt3
sf hp £c3 in; min
x 12.6 in. x 2,000 hr x 0.50
kWhsf - 3,516 kWh
2. Cooling fan, kWhcf
The following equation was used to calculate the annual
amount of. electricity consumed by the cooling fan, kWh^:1
kWh - °-746 kW x hr) v »
kWlcf hp x hpcf cf
where:
hpcf = horsepower needed to run cooling fan
0cj = annual operating time of cooling fan
-------
The horsepower needed to run the cooling fan is calculated
first, using the following equation:1
2.50 x 10"4 x AP. x m x M'
. _ b voc c
*cf ~ 0.4 x 0D x 60 min/hr
where:
Apg = pressure drop through the system {12.59 in. of
water)
mvoc = total mass flow rate of gasoline vapor (2,284.8
lb/hr)
M'c = carbon requirement per bed (21,058 lb)
0D - desorption time (1 hour)
.¦. hpcf « 6,310 hp
The operating time of the cooling fan, 0Cf, is calculated
according to the following formula-.1
0.4 x 0-. x N,. x 0_ x f_
n D A s 2
cf ~ ea
A
where:
Na = number of adsorbing beds (1)
eg = total annual terminal operating hours (2,000 hr)
f2 = percent of terminal operating capacity (0.50)
0A = adsorption time (1 hour)
.•. 0C£ = 400 hr/yr
The annual amount of electricity consumed by the cooling
fan, k.Whcf, is then calculated as follows:
kwhcf - °,7hp kW * 6'310 hP x 400 hr
kWhcf = 1,882,885 kWh
-------
3. Cooling water pump, kWhCWp:
The annual amount of electricity consumed by the cooling
water pump is calculated using the following equation:
,.r.^ 0.746 kWh
kWh = r— x hp„ x 8
cwp hp *cwp cwp
where:
hpcwp - horsepower needed to run cooling water pump
9cwp = annual operating time of cooling water pump
The horsepower needed to run the cooling water pump, hpcwp
is calculated first, as follows:1
hp „ 2.52 X 10"4 X H x qcw
cwp p 9cwp x 60 min/yr
where:
H « required head (assumed 100 feet)
B =• combined pump-motor efficiency (assumed
63 percent)
^cw « cooling water flow, gal/yr
The cooling water flow, Sew, is calculated as follows:1
3.43 gal water 3.5 lb steam - -
cw " lb steam x lb VOC x voc x s x z2
where:
mvoc = 2,284.8 lb/hr
6g = 2,000 hr/yr
f2 = percent of terminal operating capacity - 0.50
»cw
27,429,024 gal/yr
The annual operating time of the cooling water pump, 9CWp,
is calculated as follows:1
-------
0.6 x 9_ x N- x 8„ x f _
q _ D A S 2
cwp " eA
where:
0D - 1 hour
NA = 1 bed
0g = 2,000 hr/yr
0A = 1 hour
f2 - 0.5
.*. 9cwp = 600 hr/yr
The horsepower needed to run the cooling water pump, hpCWp,
is then calculated as follows:
. 2.52 x 10"4 x 100 27.43 x 106
Pcwp - 0.63 600 x 60
hpcwp - 30.48 hp
Finally, the annual amount of electricity needed to run the
cooling water pump, kWhCWp, is calculated:
kWti - °'746 kWh x 30.48 hp X 600 hr/yr
cwp hp
= 13,641 kWh
4. Total Electricity Consumption {TkWh)
The total annual consumption of electricity, TkWh, is equal
to the sum of the electricity consumption for the system
fan, bed drying/cooling fan, and the cooling water pump.
.*. TkWh = kWHsf + kWhcf + KWhcwp
= 3,516 + 1,882,885 + 13,641
= 1,900,042 kWh
-------
5. Total Annual Cost of Electricity
The total annual cost of electricity is equal to the total
estimated kilowatt hours multiplied by the electricity rate
($/kWh). The same rate ($0.0472/kWh) that was used in
determining annual costs for incinerator operation is used
here.
TAC of electricity - 1,900,042 3cWh x $0.0472/kWh
- $89,682
D. Annual Steam Coat C3) :
The annual cost of steam, CgI is calculated using the
following equation from the OAQPS Control Cost Manual:1
„ 3.5 lb steam „ .
Cg = lb VQC x mvQC x 0g x pg x fx x f2
where:
niy.Qj, « gasoline mass flow rate {2,284.8* lb/hr)
6g = operating hours per year (2,000 hr/yr)
pg = steam price ($6/1,000 lb)
f^ = ratio of 1987 to 1989 cost indices = 323.8/355.4
f2 = percent of terminal operating capacity = 0.50
Note: The factors, f^_ and f2/ were added to this
equation to convert from 1989 to 1987 dollars and to base the
steam costs on actual (rather than maximum) throughput.
_ 3.5 lb steam 2,284.8 lb 2,000 hr . $6
cs " lb VOC hr yr x 1,000 lb x
323.8
355.4
- $43,715
E. Cooling Water Costs (C-w):
The cost of cooling water is a function of steam usage.1
Cooling water cost is given as:
-------
n 3.43 gal Cs
C = X y D
cw lb steam p rcw
rs
where:
Cg - steam cost ($43,715/yr)
pg = steam price {$6/1,000 lb)
pcw = cooling water price ($0.20/1,000 gal)
• r _ 3-43 gal , $43,715 , $0.20
• • ucw " lb steam x *$6/1,000 lb' 1,000 gal
= $4,998
F. Carbon Replacement Cost (CpJ :
The economic life of the carbon is less than that of the
rest of the recovery system. The carbon replacement cost is
calculated based on a 2 year life and a 10 percent interest
rate.4
Carbon replacement - CRFc[(1.08 x Cc! + Ccj_] x f 1
CRFc - capital recovery factor, 0.5762 for a 2 year
life at 10 percent interest
1.08 - taxes and freight factor
Cc - initial cost of carbon, $76,743
Cc^ - labor cost for carbon replacement, $0.05/lb x
42,116 lb
fj^ = ratio of 1987 to 1989 cost indices, 323.8/355.4
Cr = 0.5762 [{1.08 x $76,743) + ($0.05/lb x
42,116 lb)J x 323.8/355.4 = $48,862
-------
G. Overhead:
Overhead is taken to be 60 percent of the sum of labor and
maintenance costs.
H. Property Taxes, iflgyraflcg, and Administration:
Property taxes, insurance, and administration are calculated
as 4 percent of terminal capital costs.
I. Capital Recovery Charcre (CRC) :
The capital recovery charge, CRC, is calculated based on an
interest rate of 10 percent. Piping is assumed to have a
20-year life expectancy; all other equipment is assumed to
have a 10-year life. The following equation was used to
calculate the capital recovery charge:1
CRC - [TCI - (1.08 Cc + Ccl) - Cp] x CRFg + (Cp x CRFp)
where:
TCI » total terminal capital investment (does not
include terminal's associated vessels) = $915,794
Cc » initial cost of carbon, $76,743
Cc^ - labor cost for carbon replacement, $0.05/lb x
CFR - [915,794-((1.08 x 76,743) + (0.05 x 42,116))
- 50,801] X 0.1627 + (50,801 x 0.1175)
= $132,940
J. Recovery Credit (RC):
The recovery credit, RC, is based upon the control
efficiency, product value, and operating hours per year as
follows:1
42,116 lb
cost of piping, $50,801
system capital recovery factor, 0.1627
piping capital recovery factor, 0.1175
-------
RC = "Voc x 0S x Pvoc X E X fx X f2
where:
RC = recovery credit
niyQj, - mass inlet loading rate, 2,284.8 lb/hr
0S ¦ operating hours per year, 2,000 hr/yr
pvoc " value of recovered product, $0.08/lb
E = adsorber control efficiency, 0.95
fx = ratio of 1987 to 1989 cost indices, 323.8/355.4
f2 = percent of terminal operating capacity, 0.50
.'. RC = 2,294.8 lb/hr x 2,000 hr/yr x $0.08/lb x 0.95 x
(323.8/355.4) x 0.50 = $158,205/yr
K. Vessel Retrofit Total Annual Cost (TAC):
The vessel retrofit costs are mainly for piping,
instrumentation, and associated hardware. For this reason,
vessel retrofits are assumed to have a 20-year life. Annual
costs represent capital recovery charges plus maintenance.
EXfjfnplg:
The capital recovery charge and maintenance costs per vessel
are shown in rounded form on Table 3-3 of the Technical
Support Document.
Model 5A
Capital recovery $19,750/vessel x 43.84 vessels - $866,000
Maintenance $ 9,600/vessel x 43.84 vessels = 420.000
Vessel retrofit TAC = 1,286,000
L. Emission Reduction:
The emissions are calculated as follows:
(Emission factor, lb/l,0C0 gal) x (throughput, bb'l/yr) x
(42 gal/bbl) x 0.000453 Mg/lb
Emission reduction is assumed to be 95 percent.
-------
Example:
Model 5A (gasoline)
(3.4 lb/1,000 gal) x (16,000,000 bbl/yr) x (42 gal/bbl) x
0.000453 Mg/lb) x 0.95 = 985 Mg/yr
M. Cost Effectiveness:
Cost effectiveness is calculated by dividing the total
annual cost by the emission reduction.
Example:
Model 5A {terminal only)
259,312 ($/yr) _ 263 {S /Ma)
985 (Mg/yr) " ^/M9)
Model 5A (terminal and ships)
' 1.545,152 ($/yr) = ;
985 (Mg/yr) ,s i=?/^g;
-------
FID
MODEL
Throughput
Cbbl/yr)
Emissions
C Ib/yr)
High Cost
to retrofit
terminals
(S/yr)
High cost to
retrofit
terminal &
vessels ($/yr)
low cost to
retrofit
terminal
Low cost to
retrofi t
terminal &
vessels C$/yr)
260
5A
89076446
3724616
701152
7859726
689375
7847949
1077
5A
46249669
3906453
513922
4230748
502144
4218970
1236
5A
20685147
1601552
402159
2064508
390381
2052730
341
5A
17648179
1275193
388882
1807167
377104
1795389
676
5A
15230723
1455029
378313
1602321
366536
1590544
690
5A
10323124
2168
356858
1186469
345081
1174692
847
5A
9304141
1132996
352404
1100126
340626
1088348
1022
5A
8662187
902288
349597
1045728
337819
1033950
599
5A
8080073
679645
347052
996402
335275
984625
752
58
7476481
844119
295145
895988
287051
887894
490
5B
6906788
278460
292097
847157
284003
839063
1039
5B
6674286
1402
290853
827228
282759
819134
505
5B
6337037
469443
289048
798320
280954
790226
1306
5B
5970201
672815
287085
766877
278991
758783
119
5b
5965614
142078
287061
766484
278967
758390
1245
5B
5770085
151315
286015
749724
277921
741630
1010
5B
5641708
427660
285328
738720
277234
730626
1250
5B
5469227
348849
284405
723936
276311
715842
1233
5B
4958918
155066
281674
680194
273580
672100
966
5B
4498815
412341
279212
640756
271118
632662
702
5B
4269478
4604
277985
621099
269891
613005
1267
SB
4165206
875
277427
612161
269333
604067
776
5B
4041624
171898
276766
601569
268672
593475
1007
5C
3919821
261675
242363
557377
238215
553229
709
5C
3872705
813
242115
553343
237967
549195
1009
5C
3844107
436722
241965
550894
237817
546 746
1531
5C
3792840
199632
241695
546504
237547
542356
921
5c
3769444
132144
241572
544501
237424
540353
141
5c
3676375
431561
241083
536533
236935
532385
680
5C
3538844
743
240360
524757
236212
520609
722
5C
3536030
124323
240345
524516
236197
520368
972
5C
3502314
290596
240168
521629
236020
517481
729
5c
3304322
17293
239127
504677
234979
500529
689
5c
3277151
117973
238985
502351
234837
498203
938
5C
3209742
322123
238630
496579
234482
492431
237
5C
3162664
81803
238383
492549
234235
488401
863
5C
2861770
155348
236801
466785
232653
462637
334
5c
2733240
54398
236126
455781
231978
451633
299
5C
2543158
160910
235126
439505
230978
435357
398
5C
2477460
520
234781
433881
230633
429733
945
5C
2464979
103256
234716
432813
230568
428665
1526
5C
2362741
118232
234178
424058
230030
419910
1222
5C
2348425
493
234103
422833
229955
418685
887
5c
2223449
96057
233446
412132
229298
407984
1296
5c
2158993
24378
233107
406613
228959
402465
1271
5C
2119369
1483
232899
403221
228751
399073
1815
5C
2077089
43679
232677
399601
228529
395453
717
5C
2025305
226418
232404
395166
228256
391018
1282
5C
1979848
416
232166
391275
228018
387127
1568
5C
1976359
60558
232147
390976
227999
38682|
-------
FID
MOOEL
Throughput
Emissions
High Cost
Nigh cost to
Low cost to
Lou cost to
Cbbl/yr)
< Ib/yr)
to retrofit
terminals
retrofit
terminal S
vessels ($/yr)
retrof i t
terminal
-------
F10
HOOEl
Throughput
Emissions
High Cost
High cost to
Lom cost to
Lou cost to
(bbl/yr)
(Ib/yr)
to retrofit
retrofit
retrofit
retrofit
terminals
terminal &
terminal
terminal &
(S/yr)
vessels ($/yr)
(S/yr)
vessels CS/yr)
879
5C
931036
105920
226653
301475
222505
297327
990
5C
906571
100702
226524
299380
222376
295232
788
5C
905867
129358
226520
299319
222372
295171
30
5C
894331
64753
226460
298332
222312
294184
52
5C
865943
63726
226310
295901
222162
291753
188
5C
856831
2401
226263
295122
222115
290974
291
5C
832808
45538
226136
293064
221988
288916
1063
5C
827030
41682
226106
292570
221958
288422
570
5C
809891
408
226016
291102
221868
286954
1294
5C
807113
19572
226001
290864
221853
286716
1533
5c
789416
166
225908
289349
221760
285201
1002
5C
781628
81028
225867
288682
221719
284534
18S1
5C
781585
164
225867
288679
221719
284531
1746
5C
780896
22272
225863
288619
221715
284471
1099
5C
779782
14269
225858
288525
221710
284377
1519
5C
779713
39298
225857
288518
221709
284370
1530
5C
776081
60392
225838
288207
221690
284059
1899
5C
735717
50200
225626
284751
221478
280603
679
5C
733511
154
225614
284562
221466
280414
643
5C
731937
154
225606
284428
221458
280280
937
5C
731655
58701
225605
284404
221457
280256
517
5c
723733
152
225563
283725
221415
279577
428
5C
715407
53659
225519
283012
221371
278864
556
5C
701880
65838
225448
281854
221300
277706
1322
5C
686317
144
225366
280521
221218
276373
242
5C
682194
33605
225345
280169
221197
276021
307
5C
669728
338
225279
279101
221131
274953
1462
5C
667925
31730
225270
278947
221122
274799
133
5c
663535
7789
225246
278571
221098
274423
351
5C
663148
5119
225244
278537
221096
274389
936
5C
649328
13820
225172
277355
221024
273207
S61
5C
642852
21550
225138
276800
220990
272652
1244
5C
638160
31538
22113
276398
220965
272250
1972
5C
637588
12843
225110
276349
220962
272201
1104
5c
630274
52628
225072
275724
220924
271576
1824
5C
625648
315
225047
275327
220899
271179
274
5C
625647
56893
225047
275327
220899
271179
449
5C
611890
29972
224975
274149
220827
270001
1215
5C
603479
26834
224931
273429
220783
269281
575
5C
602568
27458
224926
273351
220778
269203
1061
5C
593545
14917
224879
272579
220731
268431
746
5C
587937
123
224849
272098
220701
267950
1085
5C
586327
171
224841
271961
220693
267813
20
5C
585442
40338
224836
271885
220688
267737
31
5C
583011
35124
224823
271676
220675
267528
1309
5C
582358
76675
224820
271621
220672
267473
1273
5C
581600
122
224816
271556
220668
267408
1018
5C
581349
29300
224814
271534
220666
267386
324
5C
580903
14902
224812
271496
220664
267348
27
5C
574727
291
2247B0
270968
220632
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
LOW COSt to
Low cost to
(bbl/yr)
(tb/yr)
to retrofit
terminals
(S/yr)
retrofit
terminal &
vessels (S/yr)
retrofit
terminal
CS/yr)
retrofi t
terminal £
vessels <$/y)
10^0
5C
571223
31983
224761
270667
220613
266519
1070
5C
565748
2577
224732
270198
220584
266050
1545
5C
558076
5696
224692
269541
220544
265393
1938
5C
554990
26242
224676
269277
220528
265129
987
5C
552099
49031
224661
269030
220513
264882
1561
5C
549185
115
224645
268780
220497
264632
694
5C
543235
4199
224614
268271
220466
264123
1249
5C
538133
113
224587
267834
220439
263686
1939
5C
533804
17260
224565
267464
220417
263316
330
5C
530726
6148
224548
267199
220400
263051
1368
5C
509935
21406
224439
265420
220291
261272
407
5C
507102
4665
224424
265177
220276
261029
950
5C
500876
22391
224391
264644
220243
260496
513
5C
491649
19036
224343
263854
220195
259706
1020
5C
487949
102
224324
263538
220176
259390
1821
5C
487557
66807
224321
263503
220173
259355
1762
5C
483870
1550
224302
263188
220154
259040
724
5C
475424
63463
224258
262465
220110
258317
295
5C
474621
5559
224255
262414
220107
258266
1817
5C
474645
56687
224254
262399
220106
258251
239
5C
469587
18145
224227
261965
220079
257817
1164
5C
465777
19551
224207
261639
220059
257491
28
5C
461181
35660
224183
261246
220035
257098
1050
5C
460299
97
224178
261170
220030
257022
1216
5C
459877
23526
224176
261134
220028
256986
34
5C
459135
231
224172
261070
220024
256922
164
5C
455417
5815
224153
260752
220005
256604
1574
5C
451678
6146
224133
260432
219985
256284
377
5C
441416
9717
224079
259553
219931
255405
1231
5C
440271
3426
224073
259455
219925
255307
747
5C
435274
2278
224047
259028
219899
254880
530
5C
425194
89
223994
258164
219846
254016
125
5C
422005
217
223977
257891
219829
253743
1254
5C
418473
6103
223958
257588
219810
253440
1328
5C
414546
87
223938
257253
219790
253105
771
5C
414176
58891
223936
257221
219788
253073
509
5C
408432
86
223906
256729
219758
252581
606
5C
403320
48257
223879
256292
219731
252144
1032
5C
401778
84
223871
256160
219723
252012
1160
5C
398618
13394
223854
255889
219706
251741
446
5C
397040
158
223846
255754
219698
251606
908
5C
388655
20056
223802
255036
219654
250888
1319
5C
388295
13047
223800
255005
219652
250857
1891
sc
387016
195
223793
254895
219645
250747
1491
5C
386154
195
223788
254821
219640
250673
1811
SC
3847B0
22856
223781
254704
219633
250556
914
5C
384546
45669
223780
254684
219632
250536
1011
5C
381428
19224
223764
254417
219616
250269
25
5C
375486
17015
223732
253908
219584
249760
43
5C
372132
6590
223715
253621
219567
-------
FID
MODEL
Throughput
(bbl/yr)
Erai ss i ons
(Ib/yr)
High Cost
to retrofit
terminals
<$/yr)
High cost to
retrofit
terminal S
vessels ($/yr)
Low cost to
ret rof i t
terminal
-------
FID
MODEL
Throughput
(bbl/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
C*/yr)
High cost to
retrofit
terminal t
vessels CS/yr)
low cost to
retrofi t
terminal
(S/yr)
Low cost to
retrofi t
terminal &
vessels (J/yr)
1056
5C
237183
50
223005
242066
218857
237918
1200
5C
236306
7684
223001
241992
218853
237844
33
5C
235726
29819
222998
241942
218850
237794
1430
5C
235583
8234
222997
241929
218849
237781
1778
5C
230210
48
222969
241470
218821
237322
1207
5C
224726
8542
222940
241000
218792
236852
1276
5C
221748
5615
222924
240745
218776
236597
632
5C
214912
948
222888
240159
218740
236011
1476
5C
214865
45
222888
240155
218740
236007
158
5C
213221
25836
222879
240014
218731
235866
1145
5C
212584
452
222876
239960
218728
235812
743
5C
211222
103
222869
239844
218721
235696
409
5C
210694
44
222866
239798
218718
235650
1745
5C
210057
44
222863
239744
218715
235596
996
5C
208961
11767
222857
239650
218709
235502
406
5C
207393
82
222849
239516
218701
235368
1529
5C
207291
10447
222848
239507
218700
235359
403
5C
207262
96
222848
239504
218700
235356
1820
5C
204273
43
222832
239248
218684
235100
946
5C
202470
43
222823
239094
218.675
234946
977
5C
200483
1185
222813
238925
218665
234777
53
5C
2Q0338
16766
222812
238916
218664
234768
992
5C
199302
100
222806
238823
218658
234675
920
5C
193050
58
222773
238287
218625
234139
1892
5C
188933
95
222752
237935
218604
233787
1816
5C
187204
7926
222743
237788
218595
233640
521
5C
187036
39
222742
237773
218594
233625
951
5C
186402
11455
222738
237718
218590
233570
63
5C
185223
93
222732
237617
218584
233469
430
5C
181533
9149
222713
237302
218565
233154
332
5C
179757
91
222704
237150
218556
233002
1410
5C
175824
5149
222683
236813
218535
232665
712
5C
175181
37
222680
236758
218532
232610
57
5C
174623
88
222677
236710
218529
232562
1286
5C
172353
1931
222665
236516
218517
232368
1283
5C
171251
36
222659
236421
218511
232273
410
5C
169736
36
222651
236292
218503
232144
759
5C
167078
5383
222637
236064
218489
231916
60
5C
166837
84
222636
236044
218488
231896
1066
5C
166448
10683
222634
236010
218486
231862
1763
5C
165852
7784
222630
235959
218482
231811
993
5C
163571
82
222618
235763
218470
231615
488
5C
160437
5485
222602. _
235-495_
218454
231347
595
5C
160406
34
222602
235493
218454
231345
2017
5C
158001
33
222589
235287
218441
231139
485
5C
157955
33
222589
235283
218441
231135
1197
5C
157229
7924
222585
235221
218437
231073
706
5C
157003
33
222584
235201
218436
231053
6
SC
155154
78
222574
235043
218426
230895
318
SC
153613
18453
222566
234911
218418
230763
-------
F10
MODEL
Throughput
(bbl/yr)
Emissions
(lb/yr)
High Cost
to retrofit
terminals
(t/yr>
High cost to
retrofit
terminal t
vessels ($/yr)
Low cost to
retrofi t
terminal
<$/yr>
Low cost to
retrofi t
terminal &
vessels ($/yr)
1112
5C
151387
7630
222554
234720
218406
230572
1563
5C
150952
32
222552
234683
218404
230535
1175
5C
149842
7697
222546
234588
218398
230440
1511
5C
148667
31
222540
234488
218392
230340
1052
5C
146712
20951
222530
234320
218382
230172
1866
5C
146026
31
222526
234261
218378
230113
1422
5C
144692
7292
222519
234147
218371
229999
1543
5C
143984
1581
222516
234087
218368
229939
1331
5C
142470
7180
222508
233958
218360
229810
1110
5C
140368
29
222497
233778
218349
229630
329
5C
139764
6579
222493
233725
218345
229577
941
5C
136127
1741
222474
233414
218326
229266
916
5C
135947
19413
222473
233398
218325
229250
1019
5C
135149
28
222469
233330
218321
229182
1075
5C
135010
28
222468
233318
218320
229170
61
5C
134432
68
222465
233269
218317
229121
648
5C
132127
28
222453
233071
218305
228923
35
5C
131568
6631
222450
233023
218302
228875
1888
5C
129622
65
222440
232857
218292
228709
958
5C
129620
3698
222440
232857
218292
228709
484
5C
128413
12973
222434
232754
218286
228606
685
5C
126254
27
222422
232568
218274
228420
750
5C
125620
3805
222419
232514
218271
228366
439
5C
125483
14426
222418
232502
218270
228354
1119
5C
124444
26
222413
232414
218265
228266
710
5C
124241
26
222412
232397
218264
228249
559
5C
123030
62
222405
232292
218257
228144
1367
5C
122698
62
222404
232265
218256
228117
2041
5C
120851
15718
222394
232106
218246
227958
469
5C
119213
7442
222385
231965
218237
227817
441
5C
119213
7442
222385
231965
218237
227817
1073
5C
118921
25
222384
231941
218236
227793
1095
5C
117661
25
222377
231833
218229
227685
1926
5C
117073
5900
222374
231782
218226
227634
1459
5C
113986
5483
222358
231518
218210
227370
415
5C
113539
7088
222356
231480
218208
227332
1049
5C
113536
24
222355
231479
218207
227331
1234
5C
112508
6487
222350
231392
218202
227244
1111
5€
112204
1343
222348
231365
218200
227217
533
5C
111363
24
222344
231294
218196
227146
1015
5C
110965
5593
222342
231260
218194
227112
719
5C
110730
23
222341
231240
218193
227092
739
5C
110063
866
222337
231182
218189
227034
944
5C
107847
7039
222326
230993
218178
226845
413
5C
107209
5403
222322
230938
218174
226790
909
5C
106582
3663
222319
230884
218171
226736
1096
5C
106495
54
222318
230876
218170
226728
1728
5C
106302
2660
222317
230860
218169
226712
479
5C
105804
53
222315
230818
218167
226670
487
5c
104793
3565
222310
230732
218162
226584
-------
FID
MOO EL
Throughput
(bbl/yr)
Emissions
(tb/yr)
High Cost
to retrofit
terminals
C*/yr)
High cost to
retrofi t
terminal &
vessels (S/yr)
Low cost to
retrofit
terminal
(S/yr)
tow cost to
retrofit
terminal S
vessels ($/yr)
824
5C
103665
4341
222304
230635
218156
226487
725
5C
103291
14750
222302
230603
218154
226455
591
5C
103191
3997
222301
230594
218153
226446
1612
5C
103024
52
222300
230579
218152
226431
963
5C
101740
21
. 222293
230469
218145
226321
282
5C
101173
51
222291
230422
218143
226274
1887
5C
99714
21
222283
230296
218135
226148
1537
5C
98684
21
222277
230208
218129
22606C
594
5C
98321
21
222276
230178
218128
226030
444
5C
97294
11270
222270
230089
218122
225941
1114
5C
95044
629
222258
229896
218110
225748
745
5C
93643
47
222251
229777
218103
225629
1041
5C
93391
10564
222250
229755
218102
225607
1787
5C
92970
3829
222247
229718
218099
225570
266
5C
92159
19
222243
229649
218095
225501
15
5C
91642
48
222240
229605
218092
225457
389
5C
89080
755
222227
229386
218079
225238
1126
5C
88927
19
222226
229373
218078
225225
1770
5C
88546
19
222224
229340
218076
225192
11
5C
88499
7974
222224
229336
218076
225188
1884
5C
87802
44
222220
229276
218072
225128
48
5C
87324
44
222218
229236
218070
225088
306
5C
86844
629
222215
229194
218067
225046
1837
5C
86815
18
222215
229192
218067
225044
221
5C
85471
44
222208
229077
218060
224929
948
5C
85435
2547
222208
229074
218060
224926
1180
5C
85011
978
222206
229038
218058
224850
159
5C
83920
6524
222200
228944
218052
224796
1852
5C
83223
8149
222196
228884
218048
224736
1105
5C
82912
36
222195
228858
218047
224710
1840
5C
82576
17
222193
228829
218045
224681
162
5C
82557
42
222193
228828
218045
224680
577
5C
82088
11722
222190
228787
218042
224639
355
5C
82019
17
222190
228781
218042
224633
1831
5C
81752
11674
222188
228758
218040
224610
1927
5C
81619
17
222188
228747
218040
224599
1417
5C
81409
4103
222187
228729
218039
224581
185
5C
80954
41
222184
228690
218036
224542
942
5C
80686
4067
222183
228667
218035
224519
1577
5C
79368
40
222176
228554
218028
2244C6
621
5 C
79204
36
222175
228540
218027
224392
86
5C
78760
7411
222173
228502
218025
224354
67
5C
77910
39
222168
228429
218020
224281
627
5C
77214
1498
222165
228370
218017
224222
1910
5 C
77143
16
222164
228364
218016
224216
217
5C
76656
39
222162
228322
218014
224174
2030
5C
76161
38
222159
228280
218011
224132
1832
5C
76019
'6
222158
228267
218010
224119
276
5C
75503
590
222156
228224
218008
224076
1330
5C
74874
3774
222-52
228169
213004
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
Lou cost to
Low cost to
(bbl/yr)
-------
no
MOOEl
Throughput
Emissions
High Cost
High cost to
low cost to
Low cost to
(bbl/yr)
(Ib/yr)
to retrofit
retrofit
retrofi t
retrof i t
terminals
terminal &
terminal
terminal &
(S/yr)
vessels (S/yr)
(S/yr)
vessels (S/yr)
1973
5c
56264
1770
222054
226576
217906
222428
1535
5C
55778
12
222052
226535
217904
222387
1813
5C
54626
2753
222046
226436
217898
222288
1869
5C
53196
27
222038
226313
217890
222165
1986
5C
52855
1293
222037
226285
217889
222137
186
5C
52412
26
222034
226246
217886
222098
1839
. 5C
51954
11
222032
226207
217884
222059
305
5C
51655
28
222030
226181
217882
222033
106
5C
51413
1727
222029
226161
217881
222013
110
5C
51343
16
222029
226155
217881
222007
961
5C
50993
1386
222027
226125
217879
221977
1230
5C
50438
7203
222024
226077
217876
221929
1421
5C
50075
25
222022
226046
217874
221898
672
5C
49160
10
222017
225968
217869
221820
379
5C
49047
1454
222017
225959
217869
221811
466
5C
48813
25
222015
225938
217867
221790
2002
5C
48723
3976
222015
225931
217867
221783
1497
5C
48404
4386
222013
225903
217865
221755
1003
5C
47755
24
222010
225848
217862
221700
1012
5C
47619
10
222009
225836
217861
221688
1546
5C
46742
839
222004
225760
217856
221612
1525
5C
46488
2343
222003
225739
217855
221591
1029
5C
46476
23
222003
225738
217855
221590
994
5C
45741
1537
221999
225675
217851
221527
1036
5C
45714
10
221999
225673
217851
221525
1071
5C
44032
9
221990
225529
217842
221381
1564
5C
43625
314
221988
225494
217840
221346
1082
5C
43538
1268
221988
225487
217840
221339
72
5C
43482
6209
221987
225481
217839
221333
1176
5C
42581
1388
221983
225405
217835
221257
1658
5C
42366
21
221981
225386
217833
221238
1773
5C
42197
9
221981
225372
217833
221224
325
5C
41784
9
221978
225336
217830
221188
971
5C
41723
2932
221978
225331
217830
221183
693
5C
41505
1395
221977
225313
217829
221165
609
5C
41384
8
221976
225302
217828
221154
1349
5C
40916
21
221974
225262
217826
221114
32
5C
40585
22
221972
225234
217824
221086
1038
5C
40526
5787
221972
225229
217824
221081
227
5C
40015
5714
221969
225185
217821
221037
1780
5C
39969
2014
221969
225181
217821
221033
1620
5C
39873
8
221968
225172
217820
221024
525
5C
39543
5647
221967
225145
217819
220997
1635
5C
39365
8
221966
225130
217818
220982
1678
5C
38787
8
221963
225080
217815
220932
437
5C
38733
20
221962
225075
217814
220927
331
5c
38708
20
221962
225073
217814
220925
309
5C
38692
8
221962
225071
217814
220923
1592
5C
38377
5480
221960
225044
217812
220896
1107
5C
38273
19
221960
225036
217812
220888
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
(bbl/yr)
(Ib/yr)
to retrofit
terminals
CS/yr)
retrofit
terminal &
vessels ($/yr)
retrofit
terminal
-------
FID
MOOEL
Throughput
(bbt/yr)
Emissi ons
(Ib/yr)
High Cost
to retrofit
terminals
(J/yr)
High cost to
retrofit
terminal &
vessels (J/yr)
Lou cost to
retrofit
terminal
C*/yr)
Lou cost to
retrofit
terminal S
vessels ($/yr)
238
5C
31519
16
221924
224457
217776
220309
1461
5C
31493
16
221924
224455
217776
220307
414
5C
31150
1570
221922
224425
217774
220277
537
5C
31007
16
221922
224414
217774
220266
554
5C
30825
6
221921
224398
217773
220250
1118
5C
30700
15
221920
224387
217772
220239
968
5C
30635
1872
221920
224382
217772
220234
91
5C
30504
15
221919
224370
217771
220222
1014
5C
30476
6
221919
224368
217771
220220
1201
5C
30257
1525
221918
224350
217770
220202
1520
5C
30120
1518
221917
224338
217769
220190
121
5C
30110
4300
221917
224337
217769
220189
1783
5C
30089
6
221917
224335
217769
220187
163
5C
29881
87
221916
224317
217768
220169
1357
5C
29851
1227
221916
224315
217768
220167
1528
5C
29666
1495
221915
224299
217767
220151
96
5C
29646
4233
221915
224297
217767
220149
959
5C
29646
4233
221915
224297
217767
220149
404
5C
29390
6
221913
224275
217765
220127
1172
5C
29389
521
221913
224275
217765
220127
335
5C
29370
15
221913
224273
217765
220125
1523
5C
29297
1140
221913
224267
217765
220119
348
5C
29234
4175
221912
224261
217764
220113
1108
5C
29073
2210
221912
224248
217764
220100
1977
5C
28798
15
221910
224224
217762
220076
192
5C
28764
1785
221910
224222
217762
220074
1781
5C
28734
1448
221910
224219
217762
220071
1033
5C
28705
6
221910
224217
217762
220069
1779
5C
28672
1445
221909
224213
217761
220065
1106
5C
28387
1167
221908
224189
217760
220041
1321
5C
28114
4015
221906
224165
217758
220017
1918
5C
26837
6
221900
224057
217752
219909
1810
5C
26727
2708
221899
224047
217751
219899
955
5C
26658
13
221899
224041
217751
219893
402
5C
26396
1330
221897
224018
217749
219870
956
5C
26175
522
221896
224000
217748
219852
191
5C
26112
13
221896
223994
217748
219846
1034
5C
26000
2131
221895
223984
217747
219836
243
5C
25907
13
221895
223977
217747
219829
1162
5C
25841
2053
221895
223972
217747
219824
991
5C
25772
583
221894
223965
217746
219817
127
5C
25646
3662
221894
223955
217746
219807
212
5C
25583
13
221893
223949
217745
219801
270
5C
25250
3606
221891
223920
217743
219772
1300
5C
25234
3603
221891
223919
217743
219771
566
5C
25214
1271
221891
223917
217743
219769
1845
5C
25191
13
221891
223915
217743
219767
1570
5C
25170
479
221891
223914
217743
219766
252
5C
24709
3528
221889
223875
217741
219727
1 157
5C
24709
3528
221889
223875
217741
219727
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
low cost to
Low cost to
(bbl/yr)
CIb/yr)
to retrofit
terminals
CS/yr)
retrofit
terminal i
vessels (S/yr)
retrofit
terminal
(i/yr)
retrofit
terminal &
vessels ($/yr)
114
5C
24628
12
221888
223867
217740
219719
87
5C
24437
13
221887
223851
217739
219703
1324
5C
24425
1324
221887
223850
217739
219702
602
5C
24017
456
221885
223815
217737
219667
965
5?
23588
12
221883
223779
217735
219631
1362
5c
23178
12
221881
223744
217733
219596
506
5C
22857
3264
221879
223716
217731
219568
1031
5C
22857
3264
221879
223716
217731
219568
1042
5C
22857
3264
221879
223716
217731
219568
1307
5C
22857
3264
221879
223716
217731
219568
1804
5C
22666
5
221878
223700
217730
219552
980
5C
22457
5
221877
223682
217729
219534
597
5C
22438
5
221877
223680
217729
219532
2015
5C
22210
5
221875
223660
217727
219512
118
5C
22201
12
221875
223659
217727
219511
1485
5C
22000
5
221874
223642
217726
219494
1955
5C
21966
230
221874
223639
217726
219491
1789
5C
21941
520
221874
223637
217726
219489
592
5C
21702
4
221873
223617
217725
219469
1522
5C
21612
1089
221872
223609
217724
219461
1457
5C
21340
1076
221871
223586
217723
219438
1557
5C
21310
2386
221871
223584
217723
219436
497
5C
21232
4
221870
223576
217722
219428
1475
5C
21084
4
221870
223564
217722
219416
1524
5C
21058
1061
221869
223561
217721
219413
1318
5C
20783
698
221868
223538
217720
219390
661
5C
20660
4
221867
223527
217719
219379
2040
5C
20535
10
221867
223517
217719
219369
1987
5C
20375
252
221866
223503
217718
219355
1997
5C
20121
10
221864
223481
217716
219333
1132
5C
19886
4
221863
Z23461
217715
219313
639
5C
19841
4
221863
223458
217715
219310
303
5C
19793
10
221863
223454
217715
219306
75
5C
19764
2822
221863
223451
217715
219303
107
5C
19764
2822
221863
223451
217715
219303
245
5C
19761
2551
221863
223451
217715
219303
301
5C
19642
2805
221862
223441
217714
219293
730
5C
19622
10
221862
223439
217714
219291
924
5C
19608
659
221862
223438
217714
219290
1310
5C
19589
2797
221862
223436
217714
219288
1121
5C
19522
4
221861
223430
217713
219282
1487
5C
19247
10
221860
223407
217712
219259
1130
5C
19048
4
221859
223390
217711
219242
740
5C
19010
4
221859
223387
217711
219239
1051
5C
18914
4
221858
223378
217710
219230
1006
5C
18846
9
221858
223373
217710
219225
1134
5C
18824
949
221858
223371
217710
219223
9
5C
18795
9
221857
223367
217709
219219
1470
5C
18736
9
221857
223363
217709
219215
526
5C
18715
943
221857
223361
217709
219213
-------
FID
HOOEl
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
(bbl/yr)
(Ib/yr)
to retrofit
retrofit
retrofit
retrof i t
terminals
terminal &
terminal
terminal &
(Vyr)
vessels (S/yr)
(S/yr)
vessels (Vyr)
1844
5C
18434
10
221856
223337
217708
219189
T521
5C
18198
917
221854
223316
217706
219168
564
5C
17900
9
221853
223292
217705
219144
229
5 C
17790
2540
221852
223282
217704
219134
540
5C
17775
2538
221852
223280
217704
219132
536
5C
17718
551
221852
223276
217704
219128
695
5C
17714
4
221852
223276
21 7704
219128
721
5C
17695
4
221852
223274
217704
219126
338
5C
17693
892
221852
223274
217704
219126
115
5C
17474
10
221851
223255
217703
219107
616
5C
17470
880
221851
223255
217703
219107
211
5C
17455
2493
221850
223253
217702
219105
80
5C
17326
2474
221850
223242
217702
219094
976
5C
17260
9
221849
223236
217701
219088
1999
5C
17049
494
. 221848
223218
217700
219070
933
5C
16800
2399
221847
223197
217699
219049
1224
5C
16692
4
221846
223187
217698
219039
1198
5C
16681
838
221846
223187
217698
219039
1235
5C
16422
417
221845
223165
217697
219017
701
5c
16152
2307
221844
223142
217696
218994
1603
5C
16152
3
221844
223142
217696
218994
2010
5C
16133
3
221844
223141
217696
218993
177
5C
16044
3
221843
223132
217695
218584
612
5C
16025
3
221843
223131
217695
218983
1873
5C
15998
197
221843
223129
217695
218981
741
5C
15878
aoo
221842
223118
217694
218970
1843
5C
15810
2258
221842
223113
217694
218965
434
5C
15750
1862
221841
223107
217693
218959
210
5C
15555
8
221840
223090
217692
218942
1274
5C
15232
3
221839
223063
217691
218915
675
5C
15054
3
221838
223048
217690
218900
1536
5C
15054
3
221838
223048
217690
218900
1871
5C
15044
3
221838
223047
217690
216899
1076
5C
14838
7
221837
223029
217689
218881
297
5C
14719
7
221836
223019
217688
218871
1001
5C
14692
3
221836
223017
21 7688
218869
1045
5C
14510
731
221835
223001
217687
218853
1556
5C
14400
2056
221834
222991
217686
218843
969
5C
13954
703
221832
222953
217684
218805
928
5C
13905
3
221832
222949
217684
218801
756
5C
13669
1952
221831
222930
217683
218782
248
5C
13184
7
221828
222888
217680
218740
1127
5C
12996
3
221827
222871
217679
218723
696
5C
12760
124
221826
222851
217678
218703
1258
5C
12691
640
221325
222845
217677
218697
1990
5C
12613
168
221825
222839
217677
218691
1299
5C
12287
413
221823
222810
217675
218662
998
5C
12190
1741
221823
222803
217675
218655
600
5C
12169
6
221823
222801
217675
218653
727
5C
11943
3
221821
222781
217673
218633
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
-------
FID
MOOEl
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
Cbbl/yr)
-------
FID
MODEL
Throughput
(bbl/yr)
Emissions
Clb/yr)
High Cost
to retrofit
terminals
(»/yr)
High cost to
retrofit
terminal &
vessels (S/yr)
Low cost to
retrofi t
terminal
(*/yr)
low cost to
retrofi t
terminal &
vessels (i/yr)
2026
5c
6660
3
221794
222329
217646
218181
1566
5C
6614
222
221793
222325
217645
218177
49
5C
6350
549
221792
222302
217644
218154
1865
5C
6349
1
221792
222302
217644
218154
605
5C
6343
1
221792
222302
217644
218154
1828
5C
6302
3
221792
222298
217644
218150
618
5C
6275
316
221792
222296
217644
218148
44
5C
6137
189
221791
2222B4
217643
218136
731
5C
6123
309
221791
222283
217643
218135
47
5C
5979
332
221790
222270
217642
218122
2008
5C
5915
88
221790
222265
217642
218117
1769
5C
5708
1
221789
222248
217641
218100
1998
5C
5681
276
221789
222246
217641
218098
2025
5C
5659
38
221788
222243
217640
218095
1334
5C
5603
3
221788
222238
217640
218090
940
5C
5441
1
221787
222224
217639
218076
1989
5C
5297
526
221787
222213
217639
218065
1196
5C
5276
1
221786
222210
217638
218062
320
5C
5257
177
221786
222208
217638
218060
2035
5C
5031
3
221785
222189
217637
218041
419
5C
5014
3
221785
222188
217637
218040
369
5C
4724
2
221784
222164
217636
218016
925
5C
4699
1
221783
222161
217635
218013
635
5C
4690
2
221783
222160
217635
218012
642
5C
4648
1
221783
222157
217635
218009
2014
5C
4356
1
221782
222132
217634
2 1 7984
372
5C
4255
2
221781
222123
217633
217975
634
5C
4247
143
221781
222122
217633
217974
59
5C
4196
2
221781
222118
217633
217970
768
5C
4153
2
221781
222115
217633
217967
45
5C
4114
274
221780
222111
217632
217963
658
5C
4076
1
221780
222108
217632
217960
1419
5C
3815
128
221779
222086
217631
217938
778
5C
3810
1
221779
222085
217631
217937
1069
5C
3810
1
221779
222085
217631
217937
380
5C
3641
2
221778
222071
217630
217923
1877
5C
3505
1
221777
222059
217629
217911
1572
5C
3479
117
221777
222057
217629
217909
1016
5C
3459
116
221777
222055
217629
217907
1552
5C
3347
112
221776
222045
217628
217897
1163
5C
3333
1
221776
222044
217628
217896
207
5C
3291
470
221776
222040
217628
217892
1414
5C
3156
1
221775
222029
217627
217881
94
5C
3101
443
221775
222024
217627
217876
1000
5C
3096
2
221775
222024
217627
217876
1373
5C
3002
2
221774
222015
217626
217867
2016
5C
2946
1
221774
222011
217626
217863
1830
5C
2940
1
221774
222010
217626
217862
2029
5C
2868
323
221774
222004
217626
217856
1996
5C
2729
1
221773
E- 17
221992
217625
-------
FID
MODEL
Throughput
Cbt>l/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
Ct/yr)
High cost to
retrofi t
terminal &
vessels (I/yr)
Lou cost to
retrofi t
terminal
(S/yr)
Lom cost to
retrofit
terminal &
vessels (S/yr)
2039
2003
1924
598
659
755
225
1588
1332
1707
1994
749
1901
311
2011
1320
1966
646
1576
1984
392
303
1922
2032
2036
1733
1982
527
2007
802
326
861
1177
46
263
1792
182
1983
2012
1995
2037
1875
2038
2028
2013
1874
1598
1937
1950
1949
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5C
5 C
5C
5C
5C
5C
5C
5C
5C
5C
5C
SC
5C
5C
5C
5C
2706
2644
2602
2470
2470
2470
2413
2362
2222
2102
2089
1990
1951
1944
1924
1917
1816
1782
1623
1582
1510
1467
1213
1135
1109
1098
1095
1029
1013
1006
921
819
794
782
759
750
742
716
711
705
682
651
640
635
635
481
476
381
369
366
158
1
131
1
1
1
1
337
0
0
1
67
75
1
0
0
1
1
1
47
76
49
0
11
1
0
37
0
145
1
0
0
0
39
0
0
0
0
0
54
0
14
0
0
0
10
0
0
0
3
221773
221773
221772
221772
221772
221772
221771
221771
221770
22177.0
221770
221769
221769
221769
221769
221769
221768
221768
221767
221767
221767
221766
221765
221765
221765
221764
221764
221764
221764
221764
221764
221763
221763
221763
221763
221763
221763
221762
221762
221762
221762
221762
221762
221762
221762
221761
221761
221761
221761
221761
221990
221985
221981
221970
221970
221970
221965
221961
221949
221939
221938
221929
221926
221925
221924
221923
221914
221911
221897
221894
221888
221884
221862
221856
221854
221852
221852
221847
221845
221845
221838
221829
221827
221826
221824
221823
221823
221820
221819
221819
221817
221814
221813
221813
221813
221800
221799
221792
221791
221790
217625
217625
217624
217624
217624
217624
217623
217623
217622
217622
217622
217621
217621
217621
217621
217621
217620
217620
217619
217619
217619
217618
217617
217617
217617
217616
217616
217616
217616
217616
217616
217615
217615
217615
217615
217615
217615
217614
217614
217614
217614
217614
217614
217614
217614
217613
217613
217613
217613
217613
217842
217837
217833
217822
217822
217822
217817
217813
217801
217791
217790
217781
217778
217777
217776
217775
217766
217763
217749
217746
217740
217736
217714
217708
217706
217704
217704
217699
217697
217697
217690
217681
217679
217678
217676
217675
217675
217672
217671
217671
217669
217666
217665
217665
217665
217652
217651
217644
217643
217642
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
(bbl/yr)
-------
FID
MOOEl
Throughput
Emissions
High Cost
High cost to
Low cost to
I DM COSt tO
(bbl/yr)
(Ib/yr)
to retrofit
terminals
(i/yr)
retrofit
terminal &
vessels (t/yr)
retrof i t
terminal
-------
FID
MOTEL
Throughput
Emissions
High Cost
High cost to
Lou cost to
Low cost to
(bbl/yr)
(lb/yr>
to retrofit
retrofit
retrofi t
retrofi t
terminals
terminal &
terminal
terminal &
(Vyr)
vessels (S/yr)
-------
ID
MOOEL
Throughput
Emissions
High Cost
High cost to
Low cost to
ICK COSt tO
(bbt/yr)
(Ib/yr)
to retrofit
terminals
($/yr)
retrofit
terminal S
vessels ($/yr)
retrofit
terminal
($/yr)
retrofit
terminal &
vessels <$/yr)
az9
6C
84622
3554
222204
229005
218056
224857
504
6C
83307
3499
222197
228892
218049
224744
1354
6C
82610
3470
222193
228832
218045
224684
790
6C
82182
3452
222191
228796
218043
224648
830
6C
81775
3435
222189
228761
218041
224613
1057
6C
79749
3349
222178
228587
218030
224439
486
6C
79269
3329
222175
228545
218027
224397
844
6C
78598
3301
222172
228488
218024
224340
849
6C
78598
3301
222172
228438
218024
224340
915
6C
76960
3232
222163
228348
218015
224200
785
6C
76598
3217
222161
228317
218013
224169
1266
6C
73375
3082
222144
228041
217996
223893
805
6C
71100
2986
222132
227846
217984
223698
582
6C
66417
2790
222108
227446
217960
223298
910
6C
65509
2751
222103
227368
217955
223220
500
6C
61273
2573
222081
227005
2 1 7933
222857
816
6C
58432
2454
222066
226762
217918
222614
1335
6C
57985
2435
222063
226723
217915
222575
1369
6C
57419
2412
222061
226675
217913
222527
834
6C
54420
2286
222045
226418
217897
222270
1446
6C
52828
2219
222036
226281
217888
222133
822
6C
52789
2217
222036
226278
217888
222130
838
6C
50737
2131
222025
226102
217877
221954
828
6C
48586
2041
222014
225919
217866
221771
669
6C
43627
1632
221988
225494
217840
221346
1375
6C
43489
1827
221987
225482
217839
221334
895
6C
43298
1819
221986
225466
217838
221318
760
6C
42318
1777
221981
225382
217833
221234
1454
6C
40430
1698
221971
225220
217823
221072
105
6C
40331
1694
221971
225212
217823
221064
947
6C
40233
1690
221970
225203
217822
221055
1383
6C
36273
1523
221949
224864
217801
220716
683
6C
35267
1481
221944
224778
217796
220630
516
6C
35267
1481
221944
224778
217796
220630
843
6C
35267
1481
221944
224778
217796
220630
852
6C
35267
1481
221944
224778
217796
220630
1428
6C
35267
1481
221944
224778
217796
220630
911
6C
33860
1422
221937
224658
217789
220510
1142
6C
32255
1355
221928
224520
217780
220372
1381
6C
31413
1319
221924
224448
217776
220300
766
6C
29755
1250
221915
224306
217767
220158
858
6C
28992
1218
221911
224241
217763
220093
1450
6C
28223
1185
221907
224175
217759
220027
1340
6C
27789
1167
221905
224138
217757
219990
923
6C
27236
1144
221902
224091
217754
219943
1143
6C
26703
1122
221899
224045
217751
219897
893
6C
25664
1078
221894
223956
217746
219808
1341
6C
25572
1074
221B93
223948
217745
219800
853
6C
24711
1038
221889
223875
217741
219727
786
6C
23698
995
221883
223787
217735
219639
-------
FID
MODEL
Throughput
(bbl/yr)
Emissions
(tb/yr)
Nigh Cost
to retrofit
terminals
(S/yr)
High cost to
retrofi t
terminal S
vessels (t/yr)
Low cost to
retrofi t
terminal
-------
FID
HOOEL
Throughput
(bbl/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
<*/yr>
High cost to
retrofit
terminal &
vessels (J/yr)
Low cost to
retrof i t
terminal
(S/yr)
Low cost to
retrofit
terminal £
vessels (S/yr)
120
7A
23554699
1725748
694919
1135258
552969
993308
1765
7A
21446453
536450
687095
1088022
545145
946072
665
7A
20642380
2057909
684111
1070006
542161
928056
1711
7A
20048325
514115
681906
1056696
539956
914746
161
7A
19770016
79754
680873
1050460
538924
908511
1297
7A
19447690
1442868
679677
1043239
537777
901289
1291
7A
19338172
1104782
679270
1040784
537321
898835
193
7A
18400878
1525032
675792
1019784
533842
877834
604
7A
16309117
1433074
668029
972917
526080
830968
1305
7A
16020574
1349343
666958
966452
525009
824503
298
7A
15721090
1178990
665847
959742
523897
817792
939
7A
15631527
1266256
665514
957735
523565
8*5786
1183
7A
15614839
1085181
665453
957362
523503
815412
1418
7A
15569278
862665
665283
956340
523334
814391
552
7A
14933378
346498
662924
942094
520974
800144
1181
7A
14625134
527460
661780
935187
519830
793237
148
7A
13633094
1202916
658098
912960
516148
771010
1754
7A
12836360
395576
655141
895108
513192
753159
142
7A
12410387
1133533
653560
885564
511611
743615
269
7A
12376246
1459216
653434
884800
511484
742850
1913
7A
12296678
655552
653138
883016
511189
741067
1758
7a
11558794
826487
650400
866484
508450
724534
1148
7A
11546124
1012566
650353
' 866200
508403
724250
140
7A
11517697
878321
650247
865563
508298
723614
651
7a
11455077
259812
650015
864160
508065
722210
139
7A
11414429
680809
649864
863249
507915
721300
1648
7k
10570510
22068
646732
844341
504783
702392
1281
7A
10532456
381894
646591
843488
504641
701538
132
7A
10522973
1347675
646556
843276
504606
701326
1420
7A
10445915
508181
646270
841549
504320
699599
1237
7A
10333826
726482
645854
839038
503904
697088
1290
7A
9277837
55428
641935
815378
499985
673428
1166
7A
9232904
166022
641768
814371
499818
672421
588
7A
9155916
425197
641482
812646
499533
670697
578
7A
8420289
345825
638752
796164
496803
654215
1154
7k
8363576
316549
638542
794893
496592
652943
173
7k
8222845
7211
638020
791741
496070
649791
271
7k
8040595
468132
637343
787657
495394
645708
128
7k
7814208
424603
636503
762584
494553
640634
1240
7k
7505014
533323
635356
775657
493406
633707
1311
7k
7340841
497232
634746
771978
492797
630029
1741
7k
7320408
283318
634670
771520
492721
629571
246
7k
7217421
364435
634288
769213
492339
627264
1157
7k
7179584
330161
634148
768366
492198
626416
1174
7k
7147313
342219
634028
767642
492079
625693
232
7k
7110069
401410
633890
766808
491940
624858
1256
7k
6949378
19052
633294
763208
491344
621258
1366
7k
6937281
1457
633249
762937
491299
620987
131
7k
6899140
22786
633107
762082
491157
620132
1715
7k
6808544
467601
632771
760052
490821
618102
-------
FID
MODEL
Throughput
Emissions
High Cost
High cost to
low cost to
low cost to
(bbl/yr)
(Ib/yr)
to retrofit
terminals
(i/yr)
retrofit
terminal &
vessels
-------
FID
HOOEL
Throughput
(bbt/yr)
Emissions
(tb/yr)
High Cost
to retrofit
terminals
-------
FID
NODIL
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
(bbl/yr)
(Ib/yr)
to retrofit
terminals
CS/yrJ
retrofit
terminal £
vessels ($/yr)
retrofit
terminal
(Vyr)
retrofit
terminal &
vessels ($/yr)
1753
7A
1659585
349
613662
644687
471713
502738
1359
7A
1623697
63445
613529
643883
471579
501933
1293
7A
1619012
31425
613512
643778
471562
501828
833
7A
1618026
56219
613508
643756
471558
501806
319
7A
1602691
2739
613451
643412
471501
501462
1919
7A
1546666
325
613243
642157
471294
500208
935
7A
1526315
7031
613168
641701
471218
499751
1156
7A
1476936
38885
612984
640594
471035
498645
136
7A
1461111
166216
612926
640240
470976
498290
491
7A
1448744
16379
612880
639963
470930
498013
772
7A
1448280
60619
612878
639953
470928
498003
66
7A
1387775
75362
612653
638597
470704
496648
1732
7A
1384939
1028
612643
638534
470693
496584
1823
7A
1379036
56023
612621
638401
470671
496451
1621
7A
1354231
30787
612529
637845
470579
495895
1659
7A
1344328
49852
612492
637623
470543
495674
1184
7A
1342734
115801
612486
637588
470537
495639
361
7A
1340899
51660
612480
637547
470530
495597
670
7A
1333661
3203
612453
637385
470503
495435
1740
7A
1312908
276
612376
636920
470426
494970
1374
7A
1309768
53871
612364
636849
470414
494899
1165
7A
1286412
32398
612277
636326
470328
494377
769
7A
12/2053
7979
612224
636004
470274
494054
758
7A
1251606
31709
612148
635546
470199
493597
317
7A
1215932
97703
612016
634747
470066
492797
1146
7A
1205068
7790
611975
634503
470026
492554
1975
7A
1203710
9050
611970
634473
470021
492524
1246
7A
1198683
15079
611952
634361
470002
492411
1149
7A
1195308
44486
611939
634284
469990
492335
1970
7A
1178146
247
611876
633901
469926
491951
894
7A
1159273
48684
611805
633477
469856
491528
1931
7A
1154410
9619
611787
633368
469838
491419
390
7A
1151054
2890
611775
633293
469825
491343
178
7A
1141690
4612
611740
633083
469791
491134
572
7A
1105043
13380
611604
632262
469655
490313
1714
7a
1100651
22015
611588
632164
469638
490214
560
7A
1042374
98154
611372
630858
469422
488908
1861
7A
1002992
7695
611225
629975
469276
488026
773
7A
1001535
41730
611220
629943
469270
487993
1178
7A
996264
38066
611201
629825
469251
487875
553
7A
995291
4541
611197
629803
469247
487853
1285
7A
988525
61945
611172
629652
469222
487702
1153
7A
975583
27739
611124
629362
469174
487412
408
7A
964231
390
611082
629108
469132
487158
382
7A
955858
1844
611051
628920
469101
486970
1748
7A
928062
14519
610947
628297
468998
436348
1971
7A
868787
9727
610727
626968
468778
485019
875
7A
856605
35971
610682
626696
468733
484747
1611
7A
856373
11835
610681
626690
468732
484741
1886
7A
850050
28057
610658
626549
468708
484599
-------
FID
MOOEl
Throughput
(bfal/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
(S/yr)
High coat to
retrofit
terminal &
vessels (S/yr)
Low cost to
retrofi t
tertiinal
(S/yr)
Low cost to
retrofit
terminal &
vessels (S/yr)
109
7k
846081
64650
610643
626460
468694
484511
448
7A
763841
1397
610338
624617
468388
482667
1651
7k
733390
6389
610225
623935
468275
481985
1638
7k
722790
16408
610186
623698
468236
481748
723
7k
707110
2410
610127
623346
468178
481397
780
7k
667272
415
609980
622454
468030
480504
1716
7*
645093
135
609897
621957
467948
480008
1681
7k
644828
194
609896
621951
467947
480002
1615
7*
643684
177
609892
621925
467942
479975
42
7*
640920
31298
609882
621864
46 7932
479914
363
7*
627016
15089
609830
621552
467881
479603
1700
7A
621597
131
609810
621430
467860
475480
314
7k
618894
215
609801
621370
467350
479420
1683
7k
612497
8575
609776
621226
467827
479277
247
7k
610923
7406
609770
621191
467821
479242
253
7k
610598
50961
609769
621184
467820
479235
36
7k
603496
57012
609743
621025
467793
4790 75
194
7k
599709
48065
609729
620940
467779
478990
1742
7k
596455
15791
609717
620867
467767
478917
1469
7k
587161
25940
609682
620659
467733
478710
85
7k
535454
6306
609676
620621
467726
478671
562
7k
577237
21824
60964S
620436
467696
478487
89
¦ 7k
561773
213
609588
620090
46 7638
478140
653
7k
550264
2907
609545
619832
467596
477883
230
7k
546146
59131
609530
619740
467580
477790
71
7k
544396
221
609524
619701
467574
477751
1920
7k
540214
5006
609508
619607
467558
477657
180
7k
537139
27147
609497
619538
467547
477588
70
7k
525645
29072
609454
619281
467504
477331
753
7k
518491
3684
609427
619120
467478
477171
56
7k
516660
49568
609421
619080
46 7471
477130
279
7k
513099
2938
659407
618999
467458
477050
171
7k
502172
67908
609367
618755
467417
476805
1548
7k
483055
101
609296
618326
467346
476376
50
7k
483031
891
609296
618326
467346
476376
736
7k
472508
1163
609257
618090
467307
476140
122
7k
461154
805
609215
617836
467265
475886
732
7k
459821
875
609210
617806
467260
475856
1889
7k
456739
907
609198
617736
467249
475787
1858
7k
436866
2974
609124
617291
467175
4753 42
1460
7k
434279
91
609115
617234
467165
475284
54
7k
429594
24543
609097
617128
467148
475179
1480
7k
423291
32001
609074
616987
467125
475038
1493
7k
421928
166
609069
616957
467119
475007
1447
7k
421354
17678
609067
616944
467117
474994
234
7k
416350
87
609048
616831
467099
474882
215
7k
412878
26054
609035
616753
467086
474804
195
7k
406928
4851
609013
616620.
467064
474671
1724
7k
396244
211
608974
616382
467024
474432
286
7k
395736
484
608972
616370
467022
474420
-------
HO
HOOEl
Throughput
(bbl/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
(S/yr)
High cost to
retrofit
terminal &
vessels (S/yr)
Low cost to
retrofit
terminal
(S/yr)
Lo« cost to
retrofi t
terminal &
vessels (S/yr)
1682
7a
393330
20006
608963
616316
467013
474366
1755
7fl
390505
661
608952
616252
467003
474303
1185
7A
383446
18420
608926
616094
466977
474145
1693
7A
381559
23724
608919
616052
466970
474103
789
7A
378247
14886
608907
615978
466957
474028
666
7A
371106
2885
608880
615818
466931
473869
1204
7A
355282
25738
608822
615464
466872
473514
26B
7a
352788
717
608812
615407
466863
473458
687
7A
350127
74
608803
615348
466853
473398
1777
7a
346304
640
608788
615262
466839
473313
1665
7A
340871
4874
608768
615140
466819
473191
1242
7A
332212
16412
608736
614946
466786
472996
181
7A
321725
662
608697
614711
466748
472762
463
7A
313706
419
608667
614532
466718
472583
1933
7a
310198
65
608654
614453
466705
472504
1512
7a
301974
17379
608624
614269
466674
472319
502
7a
287150
18932
608569
613937
466619
471987
200
7A
274298
202
608521
613649
466572
471700
1394
7A
270722
137
608508
613569
466558
471619
447
7A
270364
33063
608507
613561
466557
471611
1851
7A
268420
56
608499
613517
466550
471568
544
7a
259036
151
608465
613308
466515
471358
799
7A
257382
9488
608458
613270
466509
47132*
167
7A
253412
497
608444
613181
466494
471231
1238
7A
251315
15733
608436
613134
466486
471184
1756
7A
248800
27612
608427
613078
466477
471128
1159
7A
247150
3138
608420
613040
466471
471091
1496
?A
247137
52
608420
613040
466471
471091
703
7A
243556
51
608407
612960
466457
471010
1313
7A
241175
6729
608398
612907
466449
470958
884
7A
239791
6513
608393
612876
466444
470927
90
7A
239366
109
608392
612867
466442
470917
360
7A
238521
1515
608388
612847
466439
470898
300
7A
237433
9225
608384
612823
466435
470874
1312
7A
229497
11372
608355
612645
466405
470695
890
7A
225978
7949
608342
612567
466392
470617
366
7A
225199
17366
608339
612549
466389
470599
137
7A
222567
3018
608329
612490
466380
470541
1717
7a
217622
5682
608311
612379
466361
470429
1371
7A
214943
2381
608301
612319
466351
470369
558
7a
204551
508
608262
612086
466313
470137
681
7A
203778
43
608259
612068
466310
470119
1864
7A
203048
43
608257
612053
466307
470103
313
7A
202042
259
608253
612030
466303
470080
102
7A
199850
248
608245
611981
466295
470031
1358
7A
199413
606
608243
611971
466294
470022
172
7A
198475
42
608240
611950
466290
470000
1507
7A
191942
1166
638216
611804
466266
469854
154
7A
18357'
15605
608184
611616
466235
469667
368
7a
182306
86
608180
E- 29
611588
466230
-------
FID
M00EI
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
(bbl/yr)
Clb/yr)
to retrofit
retrofit
retrofi t
retrofi t
terminals
terminal &
terminal
terminal &
(i/yr)
vessels CS/yr)
(S/yr)
vessels (S/yr)
244
7A
182141
39
608179
611584
466230
469635
1516
7A
179759
8558
608170
611530
466221
469581
1855
7A
178878
43
608167
611511
466217
469561
470
7A
176458
41
608158
611457
466208
469507
1506
7A
175302
50
608154
611431
466204
469481
150
7A
174802
37
608152
611420
466202
469470
65
7A
174789
12568
608152
611420
466202
469470
1468
7A
170473
36
608136
611323
466186
469373
383
7A
166590
60
608121
611235
466172
469286
1152
7A
165503
4262
608117
611211
466168
469262
1
7A
158275
33
608091
611050
466141
469100
12
7A
158210
7699
608090
611048
466141
469099
1649
7A
152318
595
608068
610915
466119
468966
728
7*
147651
31
608051
610811
466102
468862
4
7A
146703
31
608048
610791
466098
468841
1140
7A
145817
456
608044
610770
466095
468821
1883
7A
144798
2296
608041
610748
466091
468798
782
7A
144340
1081
608039
610737
466089
468787
1304
7A
142576
30
608032
610697
466033
4 68748
1929
7A
142295
43
608031
610691
466082
468742
1757
7A
141966
30
608030
610684
466080
468734
641
7A
141047
30
608027
610664
466077
468714
166
7A
140946
6997
608026
610661
466077
468712
1696
7A
140307
29
608024
610647
466074
468697
294
7a
140289
31
608024
610647
466074
468697
356
7A
137622
6176
608014
610587
466064
468637
272
7A
136632
29
608010
610564
466061
468615
350
7A
135240
154
608005
610533
466055
468583
1515
7A
132368
28
607994
610469
466045
468520
1610
7A
127993
47
607978
610371
466029
468422
589
7A
125760
177
607970
610321
466020
468371
88
7A
123388
61
607961
610268
466012
468319
455
7k
120547
167
607951
610205
466001
468255
1471
7A
119939
5247
607948
610190
465999
468241
153
7A
119584
11516
607947
610183
465997
468233
130
7A
117023
33
607937
610125
465988
468176
458
7k
115814
180
607933
610098
465983
468148
1151
7A
113853
2391
607926
610054
465976
468104
1613
7A
113653
8592
607925
610050
465975
468100
69
7A
113437
46
607924
610045
465975
468096
1860
7*
113343
42
607924
610043
465974
468093
1666
7A
113289
698
607924
610042
465974
468092
146
7A
113152
14118
607923
610038
465974
468089
576
7A
113092
24
607923
610037
465973
468087
445
7A
112012
300
607919
610013
465969
468063
593
7A
111997
158
607919
610013
465969
468063
450
7A
111746
2347
607918
610007
465968
468057
1809
7k
111299
37
607916
609997
465967
468048
1795
7A
110758
43
607914
609985
465965
468036
891
7A
110562
109
607914
609981
465964
468031
-------
FID
MOOEl
Throughput
Emissions
High Cost
High cost to
Low cost to
Low cost to
(bbl/yr)
CLb/yr)
to retrofit
terminals
(t/yr>
retrofit
terminal <
vessels ($/yr)
retrofit
terminal
t5/yr)
retrofi t
terminal S
vessels (J/yr)
1214
7A
106032
4958
607897
609879
465947
467929
23
7A
104325
30
607890
609840
465941
467891
1885
7A
101760
21
607881
609783
465931
467833
1617
7A
101693
42
607881
609782
465931
467832
1805
7A
96463
20
607861
609664
465912
467715
550
7A
95679
20
607858
609647
465909
467698
B08
7A
95343
109
607857
609639
465907
467689
10
7A
94488
4573
607854
609620
465904
467670
1532
7A
94437
102
607854
609619
465904
467669
183
7A
92358
426
607846
609573
465896
467623
1147
7A
92267
3134
607846
609571
465896
467621
1466
7A
92107
6846
607845
609567
465895
467617
2009
7A
91215
278
607842
609547
465892
467597
465
7A
87958
137
607830
609474
465880
467524
399
7A
87805
1857
607829
609470
465879
467520
1735
7A
87271
18
607827
609458
465877
467508
1590
7A
86480
18
607824
609441
465875
467492
1834
7A
85907
18
607822
609428
465872
467478
1915
7A
85135
2711
607819
609411
465870
467462
1863
7A
84629
18
607817
609399
465868
467450
1645
7A
83042
18
607811
609363
465862
467414
644
7A
81378
17
607805
609326
465856
467377
1798
7A
80746
17
607803
609312
465853
467362
762
7A
80524
1491
607802
609307
465852
467357
811
7A
78259
3254
607794
609257
465844
467307
1894
7A
77304
16
607790
609235
465840
467285
1270
7A
77245
19
607790
609234
465840
467284
1686
7A
76814
28
607788
609224
465839
467275
1167
7A
75896
3038
607785
609204
465835
467254
1389
7A
75578
3174
607784
609197
465834
467247
779
7a
71423
362
607768
609103
465819
467154
1432
' 7A
70955
15
607767
609093
465817
467143
1766
7A
70918
1489
607766
609092
465817
467143
1896
7A
67418
300
607753
609013
465804
467064
1722
7A
64241
13
607742
608943
465792
466993
1481
7A
63040
4766
607737
608915
465788
466966
596
7A
59094
1344
607723
608828
465773
466878
528
7A
59035
20
607722
608826
465773
466877
1636
7A
57791
583
607718
608798
465768
466848
1247
7A
57780
162
607718
608798
465768
466848
251
7a
57225
12
607716
608786
465766
466836
804
7A
57162
13
607715
608784
465766
466835
1849
7A
57132
1667
607715
608783
465766
466834
1582
7A
56797
12
607714
608776
465764
466826
1479
7A
56686
4Z85
607714
608774
465764
466824
275
7A
56626
48
607713
608772
465764
466823
1797
7A
56487
15
607713
608769
465763
466819
417
7a
55882
15
607711
608756
465761
466806
18
7A
55575
12
607709
608748
465760
466799
1618
7A
55515
24
607709
608747
465760
466798
-------
FID
MODEL
Throughput
Lou cost to
¦¦etrof i t
terminal &
vessels ($/yr)
250 7A
54923
15
607707
608734
465 757
466784
5 7A
54863
1430
607707
608733
465757
466783
542 7*
53766
23
607703
608708
465753
466758
29 7A
52572
1104
607698
608681
465749
466732
1914 7A
51947
1091
607696
608667
465746
466717
1586 7A
49633
111
607687
608615
465738
466666
534 7A
48724
10
607684
608595
465734
466645
1483 7A
48501
10
607683
608590
465734
466641
254 7A
46657
115
607676
608548
465727
466599
1836 7A
46240
. 9
607675
608539
465725
466589
418 7A
46023
9
607674
608534
465724
466584
827 7A
45841
356
607673
608530
465724
466581
435 7A
45657
10
607673
608527
465723
466577
199 7A
45171
17
607671
608515
465721
466565
1387 7A
43939
1824
607666
608487
465717
466538
1856 7A
43576
40
607665
608480
465715
466530
674 7A
42279
9
607660
608450
465711
466501
1547 7A
41948
9
607659
608443
465709
466493
713 7A
41695
9
607658
608437
465708
466487
1991 7A
41502
9
607657
608433
465708
466484
1429 7A
41055
1693
607656
608423
465706
466473
302 7A
40972
9
607655
608421
465706
466472
1853 7A
40866
663
607655
608419
465705
< 466469
1594 7A
40432
8
607653
608409
465704
466460
529 7A
38921
8
607648
608376
465698
466426
1501 7A
38072
8
607644
608356
465695
466407
376 7A
37687
2629
607643
608348
465693
466398
1439 7A
37531
8
607642
608344
465693
466395
459 7A
36913
35
607640
608330
465691
466381
1854 7A
33127
2197
607626
608245
465677
466296
222 7A
32167
7
607623
608224
465673
466274
111 7A
32099
7
607622
608222
465673
466273
541 7A
31294
39
607619
608204
465670
466255
384 7A
31029
374
607618
608198
465669
466249
520 7A
30861
9
607618
608195
465668
466245
436 7A
27652
8
607606
608123
465656
466173
860 7A
27351
222
607605
608116
465655
466166
1890 7A
26825
9
607603
608104
465653
466154
97 7A
26502
1832
607602
608097
465652
466147
1901 7A
25995
6
607600
608086
465650
466136
1812 7A
25847
5
607599
608082
465650
466133
349 7A
25580
9
607598
608076
465649
466127
1584 7A
25385
5
607597
608072
465648
466123
569 7A
25383
401
607597
608072
465648
466123
345 7A
25353
5
607597
608071
465648
466122
1279 7A
25268
5
6075 97
608069
465647
466119
95 7A
24861
1879
607595
608060
465646
466111
1514 7A
24823
95
607595
608059
465646
466110
396 7A
24321
12
607593
608048
465644
466099
793 7A
24038
10
607592
608041
465643
466092
-------
FID
MODEL
Throughput
(bbl/yrJ
Emissions
(lb/yr)
High Cost
to retrofit
terminals
(S/yr)
High cost to
retrofit
terminal &
vessels
Low cost to
retrofi t
terminal &
vessels CVyr)
1398
7A
23639
496
607591
608033
465641
466083
1138
7A
23428
492
607590
608028
465641
466079
1808
7A
22571
5
607587
608009
465637
466059
664
7A
22145
140
607585
607999
465636
466050
460
7A
21932
50
607585
607995
465635
466045
358
7A
21012
10
607581
607974
465632
466025
477
7a
20497
4
607579
607962
465630
466013
1633
7A
20282
4
607578
607957
465629
466008
138
7A
18563
4
607572
607919
465622
465969
1277
7A
18082
404
607570
607908
465621
465959
365
7A
17942
4
607570
607905
465620
465955
1391
7A
16646
3
607565
607876
465615
465926
7
7a
16572
202
607565
607875
465615
465925
175
7A
16371
21
607564
607B70
465614
465920
1535
7A
15268
578
607560
607845
465610
465895
691
7A
14884
313
607558
607836
465609
465887
149
7A
14745
3
607558
607834
465608
465884
586
7A
14468
3
607557
607827
465607
465877
1935
7A
14438
3
607557
607827
465607
465877
206
7A
14403
3
607557
607826
465607
465876
1739
7A
14132
237
607556
607820
465606
465870
1701
7A
12621
3
607550
607786
465600
465836
563
7A
12433
3
607549
607781
465600
465832
1850
7A
12216
3
607549
607777
465599
465827
1436
7A
11930
3
607547
607770
465598
465821
1738
7A
11245
2
607545
607755
465595
465805
872
7A
11242
466
607545
607755
465595
465805
1847
7a
10984
2
607544
607749
465594
465799
807
7A
10845
2
607543
607746
465594
465797
1718
7A
10711
2
607543
607743
465593
465 793
1897
7A
10625
5
607543
607742
465593
465792
453
7a
10194
3
607541
607732
465591
465782
370
7a
9893
3
607540
607725
465590
465775
1472
7a
9849
336
607540
607724
465590
465774
1365
7A
9474
2
607538
607715
465589
465766
64
7k
9341
706
607538
607713
465588
465763
549
7k
9043
4
607537
607706
465587
465756
546
7k
8497
237
607535
607694
465585
465744
1504
7k
8095
2
607533
607684
465584
465735
1540
7A
7802
590
607532
607678
465583
465729
1862
7a
7663
2
607532
607675
465582
465725
1435
7A
7532
3
607531
607672
465582
465723
113
7A
7078
535
607529
607661
465580
465712
2042
7k
6990
1
607529
607660
465580
465711
421
7k
6971
1
607529
607659
465579
465709
1505
7k
6771
30
607528
607655
465579
465706
1442
7k
6598
1
607528
607651
465578
465701
196
7k
6507
1
607527
607649
465578
465700
1502
7k
6353
1
607527
607646
465577
465696
79
7k
6336
2
607527
607645
, 465577
-------
f ID
MOOEL
Throughput
(btol/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
<$/yr)
High cost to
retro-fit
terminal &
vessels (I/yr)
Low cost to
retrofit
terminal
(S/yr>
Low cost to
retrof •' t
terminal £
vessels (S/yr)
1954
7a
5883
1
607525
607635
465575
465685
204
7A
5812
1
607525
607634
465575
465684
220
7A
5722
1
607524
607631
465575
465682
152
7A
5656
1
607524
607630
465575
465681
1438
7A
5225
1
607523
607621
465573
465671
1627
7A
5206
6
607523
607620
465573
465670
476
7a
4900
1
607521
607613
465572
465664
323
7a
4888
82
607521
607612
465572
465663
482
7A
4690
1
607521
607609
465571
465659
1280
7A
4673
1
607521
607608
465571
465658
264
7A
4397
7
607520
607602
465570
465652
1646
7A
4274
0
607519
607599
465569
465649
1317
7A
4235
148
607519
607598
465569
465648
1448
7A
4196
1
607519
607597
465569
465647
1513
7A
3895
52
607518
607591
465568
465641
1191
7A
3591
3
607517
607584
465567
465634
1908
7A
3496
1
607516
607581
465567
465632
1551
7A
3302
1
607515
607577
465566
465628
1444
7a
3275
1
607515
607576
465566
465627
1589
7A
3249
66
607515
607576
465566
465627
346
7a
3147
1
607515
607574
465565
465624
1372
7a
3096
1
60 75 1 5
607573
465565
465623
354
7A
3035
1
607514
607571
465565
465622
574
7A
3010
1
607514
607570
465565
465621
1453
7A
3010
1
607514
607570
465565
465621
228
7A
3007
3
607514
607570
465565
465621
472
7A
2958
0
607514
607569
465565
465620
1692
7A
2736
1
607513
607564
465564
465615
1370
7A
2720
1
607513
607564
465564
465615
375
7A
2661
1
607513
607563
465563
465613
1807
7A
2578
1
607513
607561
465563
465611
394
7A
2575
1
607513
607561
465563
465611
647
7A
2571
1
607513
607561
465563
465611
1587
7A
2474
6
607512
607558
465563
465609
1503
7A
2311
0
607512
607555
465562
465605
342
7A
2158
0
607511
607551
465562
465602
1595
7A
2152
0
607511
607551
465562
465602
499
7A
2021
0
607511
607549
465561
465599
1396
7A
2013
0
607511
607549
465561
465599
1708
7A
1962
0
607510
607547
465561
465598
8
7A
1802
0
607510
607544
465560
465594
1948
7A
1688
0
607509
607541
465560
465592
1398
7A
1579
0
607509
607539
465559
465589
1393
7A
1578
0
607509
607538
465559
465588
892
7A
1567
0
607509
607538
465559
465588
1895
7A
1458
0
607509
607536
465559
465586
1712
7A
1422
0
607508
607535
465559
465586
387
7A
1364
0
607508
607533
465559
465584
1499
7A
1359
0
607508
607533
465559
465584
1474
7A
1346
0
607508
E- 34
f 607533
465559
-------
FID
MOTEL
Throughput
Emissions
High Cost
High cost to
(bbl/yr)
(Ib/yr)
to retrofit
retrofit
terminals
terminal &
vessels (S/yr>
Low cost TO
retrofit
terminal
(t/yr)
Lou cost to
retrofi t
terminal &
vessels ($/yr)
385
7A
1288
0
607508
607532
465558
465582
510
7A
1238
0
607508
607531
465558
465581
3 44
7A
1237
0
607508
607531
465558
465581
1734
7A
1194
0
607508
607530
465558
4655B0
101
7A
1177
0
607508
607530
465558
465580
767
7A
1160
0
607508
607530
465558
465580
117
7A
1136
0
607507
607528
465558
465579
257
7A
1111
0
607507
607528
465S58
465579
400
7A
1060
0
607507
607527
465558
465578
333
7A
1041
0
607507
607526
465557
465576
1882
7A
1031
19
607507
607526
465557
465576
467
7A
978
0
607507
607525
465557
465575
1397
7A
945
0
607507
607525
465557
465575
231
7A
914
0
607507
607524
465557
465574
1925
7A
895
0
607507
607524
465557
465574
203
7A
844
3
607506
607522
465557
465573
1591
7A
819
0
607506
607521
465557
465572
1392
7A
812
0
607506
607521
465557
465572
1644
7A
781
0
607506
607521
465556
465571
391
7A
733
0
607506
607520
465556
465570
259
7A
698
0
607506
607519
465556
465569
1395
7A
648
0
607506
607518
465556
465568
108
7A
619
0
607505 •
607517
465556
465568
1974
7A
601
0
607505
607516
465556
465567
806
7A
597
0
607505
607516
465556
465567
1962
7A
585
0
607505
607516
465556
465567
1923
7A
571
0
607505
607516
465556
465567
233
7A
520
0
607505
607515
465556
465566
1880
7A
502
0
607505
607514
465555
465564
112
7A
457
35
607505
607514
465555
465564
292
7A
438
0
607505
607513
465555
465563
1719
7A
438
0
607505
607513
465555
465563
818
7A
435
0
607505
607513
465555
465563
1706
7A
425
0
607505
607513
465555
465563
587
7a
400
0
607505
607512
465555
465562
103
7A
387
0
607505
607512
465555
465562
2018
7A
368
0
607505
607512
465555
465562
545
7A
359
0
607505
607512
465555
465562
116
7A
333
7
607504
607510
465555
465561
1902
7A
298
0
607504
607510
465555
465561
1946
7a
292
0
607504
607509
465555
465560
1257
7A
290
0
607504
607509
465555
465560
17
7A
264
0
607504
- 607509
-465555
465560
1278
7A
256
0
607504
607509
465555
465560
841
7A
254
0
607504
607509
465555
465560
1261
7A
254
0
607504
607509
"465555
465560
1876
7A
247
0
607504
607509
445555
465560
1B42
7A
213
3
607504
607508
465554
465558
14
7A
210
0
607504
607508
465554
465558
1361
7A
210
0
607504
607508
465554
465558
-------
FID
HOTEL
Throughput
(btol/yr)
Emissions
(Ib/yr)
High Cost
to retrofit
terminals
Ct/yr)
High cost to
retrofi t
terminal &
vessels ($/yr)
Lou cost to
retrofit
terminal
(S/yr)
Lew cost to
retrofit
terminal &
vessels ($/yr)
224
7A
203
0
607504
607508
465554
465558
1736
7A
203
0
607504
607508
465554
465558
1607
7A
172
0
607504
607507
465554
465557
1951
7a
165
0
607504
607507
465554
465557
1945
7A
165
0
607504
607507
465554
465557
1947
7A
162
0
607504
607507
465554
465557
480
7A
158
0
607504
607507
465554
465557
1903
7A
153
0
607504
607507
465554
465557
1554
7A
152
0
607504
607507
465554
465557
1465
7A
140
0
607504
607507
465554
465557
1721
7A
127
0
607504
607506
465554
465556
1796
7a
127
0
607504
607506
465554
465556
1477
7a
121
0
607504
607506
465554
465556
218
7a
114
0
607504
607506
465554
465556
656
7a
114
0
607504
607506
465554
465556
160
7A
113
0
607504
607506
465554
465556
1835
7A
108
0
607504
607506
465554
465556
310
7A
102
0
607504
607506
465554
465556
567
7A
95
0
607504
607506
465554
465556
1704
7A
68
0
607503
607504
465554
465555
1500
7A
63
0
607503
607504
465554
465555
1727
7a
63
0
607503
607504
465554
465555
1581
7A
57
0
607503
607504
465554
465555
290
7A
51
0
607503
607504
465554
465555
359
7A
51
0
607503
607504
465554
465555
885
7A
51
0
607503
607504
465554
465555
1960
7A
51
0
607503
607504
465554
465555
538
7A
45
0
607503
607504
465554
465555
126
7A
38
0
607503
607504
465554
465555
1833
7A
38
0
607503
607504
465554
465555
432
7A
32
0
607503
607504
465554
465555
1263
7A
32
0
607503
607504
465554
465555
1702
7a
26
0
607503
607503
465554
465554
1848
7a
25
0
607503
607503
465554
' 465554
1593
7A
21
1
607503
607503
465554
465554
711
7A
19
0
607503
607503
465554
465554
568
7A
14
0
607503
607503
465554
465554
1703
7A
13
0
607503
607503
465554
465554
261
7A
6
0
607503
607503
465554
465554
339
7A
6
0
607503
607503
465554
465554
1768
7A
6
0
607503
607503
465554
465554
1542
7A
6
0
607503
607503
465554
465554
831
7A
6
0
607503..
_ 607503
465554
465554
522
78
56400943
4674898
1069272
2545256
870341
2346325
571
78
52989912
1284498
1056680
2443399
857750
2244469
1193
7B
40968480
371377
1012304
2084428
813373
1885497
744
7B
37321375
2162549
998840
1975521
799910
1776591
170
7B
33644250
4141572
985267
1865720
786336
1666789
156
7B
29657459
2459738
970549
1746670
771619
1547740
WW
"""""""
'iftnnnnnfl
-------
|