Global Trade and Fuels Assessment -
Future Trends and Effects of Requiring
Clean Fuels in the Marine Sector
Protection
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Global Trade and Fuels Assessment -
Future Trends and Effects of Requiring
Clean Fuels in the Marine Sector
Assessment and Standards Division
Office of Transportation and Air Quality
U.S. Environmental Protection Agency
Prepared for EPA by
RTI International
Research Triangle Park, NC
EnSys Energy & Systems, Inc.
Lexington, Ma
Navigistics Counsulting
Boxborough, Ma
EPA Contract No. EP-C-05-040
NOTICE
v>EPA
This technical report does not necessarily represent final EPA decisions or
positions. It is intended to present technical analysis of issues using data
that are currently available. The purpose in the release of such reports is to
facilitate the exchange of technical information and to inform the public of
technical developments.
United States EPA420-R-08-021
Environmental Protection ., , „„„
Agency November 2008
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CONTENTS
Section Page
1 Introduction 1-1
1.1 Regulations and Options for Compliance 1-2
1.2 Summary of the Analysis 1-7
1.3 Organization of this Report 1-10
2 Overview of the Marine Fuels Industry 2-1
2.1 Refining of Petroleum Products (Including Marine Fuels) 2-2
2.1.1 Primary Refinery Inputs 2-4
2.1.1.1 Crude Oil 2-5
2.1.1.2 Blending Stocks and Additives 2-7
2.1.2 Refinery Production Models 2-7
2.1.2.1 Topping Refineries 2-7
2.1.2.2 Hydroskimming Refineries 2-7
2.1.2.3 Cracking Refineries 2-8
2.1.2.4 Coking Refineries 2-9
2.1.3 Refineries Around the World 2-10
2.2 Marine Fuel Types 2-14
2.2.1 Marine Fuel Blending Stocks 2-15
2.2.2 Marine Gas Oil (MGO) 2-16
2.2.3 Marine Distillate Oil (MDO) 2-16
2.2.4 Intermediate Fuel Oil (IFO) 2-16
2.3 Bunker Fuel Suppliers 2-16
2.3.1 Singapore 2-17
2.3.1.1 Refineries 2-17
2.3.1.2 Bunker Traders 2-18
2.3.1.3 Bunker Suppliers 2-19
2.3.1.4 Barge Operators 2-19
2.3.2 Rotterdam 2-19
2.3.2.1 Refineries 2-20
2.3.2.2 Bunker Traders 2-20
2.3.2.3 Bunker Suppliers 2-21
2.3.2.4 Barge Operators 2-21
in
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2.3.3 Fujairah 2-22
2.3.3.1 Refineries 2-22
2.3.3.2 Bunker Traders 2-23
2.3.3.3 Bunker Suppliers 2-23
2.3.3.4 Barge Operators 2-24
2.3.4 Houston 2-24
2.3.4.1 Refineries 2-25
2.3.4.2 Bunker Traders 2-25
2.3.4.3 Bunker Suppliers 2-25
2.3.4.4 Barge Operators 2-25
3 Demand for Bunker Fuels in the Marine Industry 3-1
3.1 Summary of the Modeling Approach 3-1
3.2 Methods of Forecasting Bunker Fuel Consumption 3-2
3.2.1 Composite Commodities and Regions 3-2
3.2.2 Ship Analysis by Vessel Type and Size 3-6
3.2.2.1 Fleet Average Daily Fuel Consumption 3-9
3.2.2.2 Key Assumptions Affecting the Forecast 3-9
3.2.2.3 Changing Fleet Characteristics 3-11
3.2.3 Trade Analysis by Commodity Type and Trade Route 3-11
3.2.3.1 Days at Sea and Days in Port 3-12
3.2.3.2 Number of Voyages 3-15
3.2.3.3 Exceptions: General Cargo and Container Trades 3-16
3.2.4 Calculating Total Estimated Fuel Demand for Cargo Vessels 3-17
3.2.4.1 Total Fuel Demand in Year y, for y = 2005, 2012, 2020 3-17
3.2.5 U.S. Domestic Navigation 3-18
3.2.5.1 Ship Analysis by Vessel Type and Size 3-18
3.2.5.2 Fleet Average Daily Fuel Consumption 3-20
3.2.5.3 Voyage Parameters 3-20
3.2.6 Ship Analysis for Noncargo Vessels 3-21
3.2.7 Bunker Fuel Grades 3-21
3.3 Results of Bunker Fuel Forecasts 3-22
4 Estimating Business-as-Usual Proj ections Using the WORLD Model 4-1
4.1 WORLD Model Enhancements to Accommodate Compliance Alternatives 4-1
4.2 WORLD Model Enhancements to Accommodate Alternate Fuel Demand
Forecasts 4-5
4.3 Enhancements to Ensure Bunker Fuel Stability 4-9
4.4 Enhancements to WORLD Model Reporting 4-11
IV
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4.5 WORLD Model Assumptions and Structural Changes 4-11
4.5.1 AEO 2006 Outlook—Supply/Demand/Price Basis 4-11
4.5.2 Product Quality 4-11
4.5.2.1 Industrialized World 4-14
4.5.2.2 Non-OECD Regions 4-14
4.5.3 Residual Fuel for Industrial/Inland Use 4-14
4.5.4 Biofuels 4-14
4.5.5 Regional Bunker Demands 4-16
4.5.6 Regulatory Outlook for Bunker Fuels 4-17
4.5.6.1 Primary Bunker Quality Regulations 4-17
4.5.6.2 EU SECA Compliance 4-22
4.5.7 IFO Viscosity/Grade Mix 4-22
4.5.8 Refinery Capacity and Projects 4-23
4.5.9 Refinery Technology and Costs 4-24
4.5.10 Transportation 4-26
4.6 Input Prices for the WORLD Model 4-29
4.6.1 Marker Crude Price 4-29
4.6.2 Natural Gas Price 4-29
4.6.3 Miscellaneous Prices 4-30
4.7 Reporting 4-30
5 The WORLD Model's BAU Projections for 2012 and 2020 5-1
5.1 Supply-Demand Balance 5-1
5.2 Refining Capacity Additions 5-4
5.3 Refining Economics and Prices 5-7
5.4 Crude and Product Trade 5-12
5.5 Bunker Fuels' Quality and Blending 5-19
6 Technology Considerations 6-1
6.1 Fuel Switching 6-2
6.1.1 Primer on Bunker Fuel Treatment and Heating Plants 6-3
6.1.2 Burning Low-Sulfur Fuels in Main Engines 6-6
6.1.2.1 Lubricating Oil Systems 6-6
6.1.2.2 Fuel Viscosity and Feed Temperature 6-7
6.1.3 Practicality of Switching to Low-Sulfur Fuels in SECA 6-8
6.1.3.1 Fuel Compatibility 6-8
6.1.3.2 Fuel Feed Temperature 6-9
6.1.3.3 Fuel System Configuration 6-10
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6.1.3.4 Shipboard Fuel Oil Tankage 6-13
6.1.3.5 Maersk Pilot Fuel Switch Initiative 6-14
6.1.4 Other Approaches to Using Low-Sulfur Fuels in SEC As 6-15
6.1.4.1 Full-Time Fuel Switching 6-15
6.1.4.2 Onboard Blending 6-16
6.1.4.3 Installation of a Separate LSFO System 6-17
6.1.5 Emissions Reduction Potential 6-17
6.2 Exhaust Gas Scrubbing 6-18
6.3 Description of Scrubber Technology 6-19
6.4 Scrubber Penetration Scenarios 6-20
6.5 Summary Remarks 6-21
7 SEC A Fuel Consumption Estimates 7-1
7.1 Summary of the SECAFuel Consumption Modeling Approach 7-1
7.2 SECA Scenario Boundaries 7-2
7.3 Estimating Distances Traveled within SECA Boundaries 7-2
7.4 100/50 nm SECA Fuel Consumption Estimates 7-3
7.5 200 nm SECAFuel Consumption Estimates 7-6
7.6 Fuel Consumption Comparison across SECA Scenarios 7-8
8 SECAFuel Impact Assessments 8-1
8.1 Summary 8-1
8.2 Basis of WORLD Model Cases for SECA Fuels' Effects 8-7
8.2.1 Cases Run 8-9
8.2.2 Bunker Quality Premises 8-9
8.2.3 Bunker Demand Projections 8-12
8.2.4 WORLD Model Weight/Volume Features and Bunker
Methodology 8-12
8.2.4.1 Model Reporting Extensions 8-16
8.3 Case Results Details 8-16
8.3.1 Global Refinery Investments and Capacities 8-16
8.3.2 Crude Supply Cost/Price Differentials 8-17
8.3.3 Product/Marine Fuels'Costs 8-17
VI
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8.3.4 Total Fuel Costs (All Products from LPG to Coke, Including
Gasoline, Distillates, and Marine Fuels) 8-18
8.3.5 CO2 Emissions 8-18
8.4 Tabulated Results 8-19
References R-l
Appendix
A Review of Refinery Process Costs A-l
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FIGURES
Number Page
1-1 Sulfur Content in Bunker Fuels 1-3
1-2 Timeline of MARPOL Annex VI and SECA Implementation 1-4
2-1 Basic Refining Process and Product Streams 2-3
2-2 Quality by Crude Type 2-6
2-3 Product Outputs of World Refineries per Day in 2003 2-13
3-1 Method for Estimating Bunker Fuel Demand 3-3
3-2 Specific Fuel Oil Consumption Over Time 3-10
3-3 Worldwide Bunker Fuel Use 3-22
3-4 Annual Growth Rate in Worldwide Bunker Fuel Use 3-23
3-5 Worldwide Trade Flows (Global Insights) 3-24
3-6 Annual Growth Rate in Worldwide Trade Flows 3-25
3-7 Worldwide IFO380 Use 3-26
3-8 Worldwide IFO180 Use 3-26
3-9 Worldwide MDO-MGO Use 3-27
3-10 Bunker Fuel Used by the International Cargo Fleet Importing to and Exporting
from the United States (by Region) 3-27
3-11 Annual Growth Rate in Bunker Fuel Used by the International Cargo Fleet
Importing to and Exporting from the United States (by Region) 3-28
3-12 Bunker Fuel Used by the International Cargo Fleet Importing to and Exporting
from the United States (by Vessel/Cargo Type) 3-28
3-13 Annual Growth Rate in Bunker Fuel Used by the International Cargo Fleet
Importing to and Exporting from the United States (by Vessel/Cargo Type) 3-29
3-14 U.S. Trade Flows—Imports plus Exports (Global Insights) 3-30
3-15 Annual Growth in U.S. Trade Flows—Imports plus Exports (Global Insights) 3-30
4-1 Impact of RTI Bunker Projections on Global Oil Demand in 2020 4-8
4-2 Requirements for Marine Distillate Fuels 4-20
4-3 Requirements for Marine Residual Fuels 4-21
4-4 Nelson Refinery Cost Indices 4-26
Vlll
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4-5 Spot Market Costs 4-28
5-1 Total Crude Delivery 5-13
5-2 Total Crude Export 5-14
5-3 Production in 2012 5-15
5-4 Production in 2020 5-16
5-5 Product Movements 5-17
5-6 Residual Bunker 5-18
6-1 Typical Shipboard Pretreatment and Cleaning Plant 6-5
6-2 Pressurized Fuel Oil System 6-5
6-3 Fuel System with One MDO Settling Tank and One IFO Settling Tank 6-11
6-4 Fuel System with One MDO Settling Tank and Two IFO Settling Tanks 6-12
6-5 Fuel System with One MDO Settling Tank and Two Sets of IFO Settling and
Service Tanks 6-12
6-6 Components of Marine Diesel Engine Exhaust Gas 6-18
6-7 EcoSilencer Exhaust Gas Scrubber 6-20
7-1 Comparison of SEC A Fuel Consumption under Two Mileage Zone Scenarios,
2012 7-9
7-2 Comparison of SECA Fuel Consumption under Two Mileage Zone Scenarios,
2020 7-9
8-1 Makeup of Global Bunker Fuel, 2012 and 2020 8-2
IX
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TABLES
Number Page
2-1 Total U. S. Refinery Input of Crude Oil and Petroleum Products in 2004 2-4
2-2 Crude Oil Types Included in the OPEC Basket 2-6
2-3 Typical Production Yield from a Hydroskimming Refinery 2-8
2-4 Typical Production Yield from a Cracking Refinery 2-9
2-5 Typical Production Yield from Coking Refineries 2-9
2-6 Refinery Presence by World Region in 2004 2-11
2-7 World's Largest Refinery Companies by Capacity in 2004 2-12
2-8 World Refinery Product Outputs of World Refineries per Day for 2003 2-12
2-9 Marine Fuel Types 2-15
3-1 Aggregate Regions and Associated Countries 3-5
3-2 World Trade Estimates for Composite Commodities, 2005, 2012, and 2020 3-7
3-3 Assignment of Commodities to Vessel Types 3-7
3-4 Fleet Characteristics in Clarksons' Data 3-8
3-5 Assumptions Regarding Engine Loads 3-11
3-6 Vessel Speed by Type 3-13
3-7 Length of Voyages for Noncontainer Cargo Ships (approx. average) 3-14
3-8 Length of Voyages for Container-Ship Trade Routes 3-15
3-9 Estimated Utilization Rates for Top 10 Container-Ship Trade Routes 3-17
3-10 Jones Act Fleet 3-19
4-1 Summary of Structural Changes to the WORLD Model 4-2
4-2 Global Oil Demand by Product Category—IEA and RTI Bases for Bunker
Fuels 4-7
4-3 Product Growth Rates 4-8
4-4 AEO 2006 Petroleum Supply Forecast (million barrels per day, unless otherwise
noted) 4-12
4-5 Projected Biofuels Consumption 4-15
4-6 World Regional Bunker Sales 4-18
4-7 Summary of Bunker Sulfur Specifications Used for 2012 and 2020 BAU Cases 4-19
4-8 Major Capacity Additions 4-24
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4-9 Tanker Class 4-27
5-1 WORLD Model Case Results—Supplies 5-2
5-2 WORLD Model Case Results—Demands 5-3
5-3 Capacity Additions and Investment 5-5
5-4 Refinery Capacity Additions 5-6
5-5 Product Prices 5-8
5-6 Product Price Differentials 5-11
6-1 Fuel Tank Capacities for Oil Tankers 6-13
6-2 Fuel Tank Capacities for Containerships 6-14
6-3 Ship Fuel Ranges When Fuel Switched to MDO/MGO 6-14
6-4 Near- and Long-Term Scrubber Penetration Scenarios in the U.S. EEZ 6-21
7-1 2012 SECA Fuel Consumption Estimates at 100/50 nm, International Trading
Ships 7-4
7-2 2012 SECA Fuel Consumption Estimates at 100/50 nm, All Ships 7-4
7-3 2020 SECA Fuel Consumption Estimates at 100/50 nm, International Trading
Ships 7-5
7-4 2020 SECA Fuel Consumption Estimates at 100/50 nm, All Ships 7-5
7-5 2012 SECA Fuel Consumption Estimates at 200 nm, International Trading
Ships 7-6
7-6 2012 SECA Fuel Consumption Estimates at 200 nm, All Ships 7-7
7-7 2020 SECA Fuel Consumption Estimates at 200 nm, International Trading
Ships 7-7
7-8 2020 SECA Fuel Consumption Estimates at 200 nm, All Ships 7-8
8-1 Base Effects and Total Bunker Fuel Volumes 8-2
8-2 Proportion of Affected Bunker Fuel Volumes in the United States and Canada 8-3
8-3 Affected Bunker Fuel—IFO Shifted to Distillate 8-4
8-4 Effects of the Bunker Fuel Standard and Sulfur Level 8-6
8-5 Effect of Mileage Zone and Mexico SECA 8-8
8-6 Effect of Scrubber Penetration 8-8
8-7 Summary of WORLD Cases—Revised 8-9
8-8 DNV Petroleum Services Bunker Quality Report 8-12
8-9 Comparison of Fuel Grade Specifications 8-13
8-10 Affected and Total Fuel Volumes, Million Tons per Year 8-14
XI
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-11 Computation of Heating Values and Weight and Volume Factors for the Same
Energy Content 8-15
-12a WORLD Model Results—Changes vs. 2012/2020 Base Cases 8-20
-12b WORLD Model Results—Changes vs. 2012/2020 Base Cases 8-21
-12c WORLD Model Results—Changes vs. 2012/2020 Base Cases 8-22
-12d WORLD Model Results—Changes vs. 2012/2020 Base Cases 8-23
xn
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SECTION 1
INTRODUCTION
The U.S. Environmental Protection Agency (EPA), along with other regulatory bodies in
the United States and Canada, is considering whether to designate one or more SOX Emission
Control Areas (SECAs) along the North American coastline, as provided for by MARPOL
Annex VI. This addition to the international MARPOL treaty went into effect on May 19, 2005,
and places limits on both NOX and SOX emissions. According to the terms of the treaty, ships
calling on ports in signatory countries must use bunker fuel—the industry vernacular for marine
fuels—with sulfur content by weight at or below 4.5%. Countries participating in the treaty are
also permitted to request designation of SECAs, in which ships must treat their exhaust to a level
not exceeding 6.0 grams of SOX per kilowatt-hour or further reduce the sulfur content of their
fuel to 1.5%. The Baltic and North Sea areas have already been designated as SECAs, and the
effective dates of compliance in these bodies of water were 2006 and 2007, respectively.
To evaluate possible recommendations regarding North American SECAs, EPA requires
a thorough examination of potential responses by the petroleum-refining and ocean-transport
industries to such a designation, along with any resulting economic impacts. EPA contracted
with RTI International to provide a foundation for these recommendations through developing
the knowledge, data, and modeling capabilities needed for such an analysis; assess technology
alternatives for reducing sulfur emissions from ships; and estimate the impact a SECA
designation would have on the petroleum-refining and ocean transport industries. The analytical
team comprising RTI, EnSys Energy & Systems, and Navigistics Consulting has assessed current
and future conditions in global fuels market to provide this foundation.
Accomplishing the goals of this report involved several component tasks:
• Examining the current petroleum-refining industry and bunker fuel markets.
• Developing a model of shipping activities to estimate future demand for marine
bunker fuels.
• Enhancing the EnSys model of petroleum refining (World Oil Refining Logistics and
Demand, or the WORLD model) to include the new information on bunker fuel
markets and then using the model to establish baseline projections of future refining
activities.
• Estimating the volume of bunker fuel consumed within selected distances from the
U.S. coastline.
• Modeling how SECA compliance alternatives impacted fuel products, fuel refining,
and fuel consumption, including prices and product specifications.
1-1
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1.1 Regulations and Options for Compliance
Existing regulations regarding marine bunker fuels provide an important backdrop for the
modeling conducted in this analysis and, thus, are summarized in this section—along with an
initial discussion of how bunker fuel markets may comply with regulations. The International
Maritime Organization's (IMO) "MARPOL Annex VI" sets out a series of regulations impacting
international marine bunker fuels. These new regulations center on limits for emissions of nitrous
oxides (NOX), sulfur oxides (SOX), and volatile organic compounds (VOCs). Fuel quality
regulations in Annex VI have been implemented in the form of the ISO-8217 2005 specification
(see Figure 1-2 for details and discussion). This specification updates selected bunker qualities,
provides protections to prevent the blending of used lubricating oil (ULO) into marine fuels, and
limits the presence of refinery streams that contain high levels of "catalyst fines."
The MARPOL Annex VI sets limits on NOX emissions as a function of ships' engine
speed, which range from a high of 17 grams per kilowatt-hour (g/kWh) for engines running at
less than 130 rpm to a low of 9.8 g/kWh for engines running at or above 2,000 rpm. Since
residual bunker fuels contain nitrogen that is typically at a level equal to around 20% of the
fuel's sulfur content, NOX emissions will be affected in part by fuel quality (as well as by specific
combustion conditions). For example, a bunker fuel containing 3% sulfur will contain around
0.6% nitrogen, which translates into around 3g of NOX per kWh (Hanashima, 2006). This level is
well below the standard set for NOX emissions; however, residuum desulfurization in a refinery
also reduces nitrogen levels and can therefore play into the comparative economics of bunker
fuel sulfur reduction versus other options (e.g., on-board abatement of SOx).1
Through the ISO-8217 specifications, MARPOL Annex VI sets a limit on SOX emissions,
expressed as a maximum 4.5% fuel sulfur content. This compares to a prior maximum limit of
5%. The new level was set based on a survey of residual bunkers' qualities (the intermediate fuel
oil, or "IFO," grades), which showed that essentially all bunkers currently supplied have sulfur
contents below 4.5% (see Figure 1-1). Since the same survey showed global average residual
bunker fuel content is currently around 2.7%, this change has limited practical impact on bunker
fuel's quality. More significant for any potential future SOX regulations is the fact that MARPOL
Annex VI explicitly allows for on-board abatement as an alternative means for meeting SOX
requirements (thus recognizing that the ultimate goal is a reduction in SOX
1 To cover the eventuality that NOX may need to be considered in any future investigations of SECAs, EnSys added
the nitrogen contents of residual streams to the WORLD model, along with impacts on nitrogen content of
desulfurization.
1-2
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Figure 1-1. Sulfur Content in Bunker Fuels
emissions, rather than a reduction of fuel sulfur content per se). The IMO, however, has yet to
set up necessary guidelines for this provision.
Figure 1-2 illustrates the current timeline of the MARPOL Annex VI and other SECA-
related regulations. In addition to establishing emissions limits and considering reductions
achieved through on-board abatement, MARPOL Annex VI and ISO-8217 2005 explicitly allow
for the existence of regional SEC As. In the European Union (EU), these agreements have been
established with a marine fuel sulfur maximum of 1.5%, potentially advancing to 0.2% and 0.1%
on marine distillates. Again, these regulations recognize on-board abatement as an alternative,
with a stated standard of 6g SOx/kWh (to correspond to the initial 1.5% sulfur limit).
Beyond currently announced initiatives, it appears likely that the MARPOL Annex VI
regulations and newly effective EU SECAs are only the first steps in progressively tightening
regulation of marine fuels quality. This is being driven by the fact that, as major steps are being
taken to reduce sulfur in other products, especially in gasoline and nonmarine distillates, bunkers
are becoming an increasingly significant—and unacceptable—source of SOX and other
emissions. Already, there is a review of MARPOL Annex VI underway with international
consultative meetings. Current intentions are for a second round of EVIO/ISO marine fuels
regulations to be established by 2008 and be enforceable by 2011/2012, with potential further
steps beyond. In addition, the EU is expected to tighten the initial SECA regulations beyond
2008. Required residual bunker fuel sulfur levels could move to as low as 0.5% regionally, or
even globally. One current element of uncertainty is the size of the geographic areas of future
1-3
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Legislative overview - IMO and European Union
11 JtUflii* J*H
EU Member SH« towi
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Figure 1-2. Timeline of MARPOL Annex VI and SECA Implementation
SEC As (i.e., how many miles offshore they will apply). This, in turn, affects the proportion of
total bunkers' consumption that will need to comply with SECA regulations. Anticipated policy
decisions on this issue will have significant implications for any analysis conducted in the future
regarding the potential effects of North American SEC As.
The above proposals focus on improving the quality of the current mix of distillate and
residual bunker fuels in the future. More radical alternatives have been put forward as part of the
ongoing review by the IMO of MARPOL Annex VI. One—the group International Association
of Independent Tanker Owners (INTERTANKO)—is proposing that all marine bunker fuels be
converted to marine diesel oil (MDO) (i.e., no more residual bunker fuels) with a maximum
sulfur content of 1% initially, dropping to 0.5% after 2015. Benefits claimed include greater
reductions in SOX, NOX, and particulate matter (PM); elimination of need for onboard scrubbing
and simplification of onboard fuel handling and storage; creation of a single global standard for
marine bunker fuels; and an associated level competitive playing field among shippers. Improved
vessel safety is also cited since the regulation would avoid the need for vessels to change fuel
types when entering or leaving SECA areas, thereby eliminating the associated risk of engine
outage, vessel loss of control, and potential environmental disaster.
1-4
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Other groups, including BIMCO (an owners' organization covering a claimed 65% of the
world merchant fleet), have proposed that all vessels use MDO (not intermediate fuel oil [IFO])
within SECA areas. This would lead to a partial shift in bunker demand from IFO to MDO.
The vigorous debate that has developed among the parties concerned with global
shipping and fuels is ongoing at the time of the writing of this report. As a result, the realm of
potential policy decisions on marine bunkers and hence analytical requirements goes beyond the
immediate Annex VI and SECA regulations and has potentially far-reaching implications for
U.S. and global refining and oil markets.
Marine Environment Protection Committee (MEPC) - 53rd session 18-22 July 2005
Review of Annex VI
The Committee agreed on the need to undertake a review of Annex VI and the NOx
Technical Code with a view to revising the regulations to take account of current
technology and the need to further reduce emissions from ships. MEPC instructed the
Sub-Committee on Bulk Liquids and Gases (BLG) to carry out the review by 2007, and
specifically to:
_ examine available and developing techniques for the reduction of emissions of air
pollutants; review the relevant technologies and the potential for a reduction of
NOx emissions and recommend future limits for NOx emissions;
review technology and the need for a reduction of SOx emissions and justify and
recommend future limits for SOx emissions;
consider the need, justification and possibility of controlling volatile organic
compounds emissions from cargoes;
_ with a view to controlling emissions of particulate matter (PM), study current
emission levels of PM from marine engines, including their size distribution and
quantity, and recommend actions to be taken for the reduction of PM from ships.
Since reduction of NOx and SOx emission is expected to also reduce PM emission,
estimate the level of PM emission reduction through this route;
- consider reducing NOx and PM emission limits for existing engines;
consider whether Annex VI emission reductions or limitations should be extended to
include diesel engines that use alternative fuels and engine systems/power plants
other than diesel engines; and
review the texts of Annex VI, NOx Technical Code and related guidelines and
recommend necessary amendments.
The language in the Annex VI regulations and the economics of the refining and shipping
industries lead to a situation where several, nonexclusive, options can potentially be used to
achieve compliance with SEC As. While some of these options are not fully explored in this
report (they will be evaluated in the next steps of the analysis), it is still important to note the
range of responses. Among these options are the following:
1. Desulfurize refinery fuels and use lower sulfur content fuel.
2. Switch entirely or partially to middle distillates for bunker fuel.
3. Reduce SOX emissions via onboard scrubbers (also helps reduce PM).
4. Reduce NOX emissions by lowering nitrogen content of the fuel.
5. Reduce NOX and PM via onboard emission controls and engine design.
1-5
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6. Undertake custom blending of fuels on board and/or use segregated bunker tanks.
7. Establish emissions trading, which could allow trading of marine and shore-based
credits.
8. Switch to alternative fuel sources (e.g., liquefied natural gas [LNG]).
9. To the extent feasible, some ship owners might also elect noncompliance through
reregi strati on of ships to a country that has not ratified the IMO standards.
There is general industry agreement in principle on the need for SOX emissions reduction.
There are, however, major industry concerns over operational issues, such as custom blending of
fuels onboard because of safety and other concerns (Gregory, 2006). Similarly, there is industry
agreement about a reduction in NOX limits for new engines, but also concerns about the
application of NOX limitations to existing engines because of practicality and cost factors
(Metcalf, 2006) and concerns about a regional approach to NOX controls due to technical
considerations (Gregory, 2006).
With regard to emissions trading and sulfur reduction, the European Commission has
been asked to give particular consideration to proposals for alternative or complementary
measures and to consider submitting proposals on economic instruments in their 2008 review.
For NOX reductions, the Commission studies suggest that, given the range of technologies, there
is a sound basis for a trading environment (Madden, 2006). In addition, SOX emissions trading
and compliance monitoring schemes are being actively promoted.
Initial studies indicate onboard scrubbing is cheaper in terms of cost per ton of SOX
removed than refinery residual desulfurization. However, the technology is only just reaching the
commercial demonstration stage (with initial positive results). Issues have also been raised over
how to ensure compliance and how to dispose onshore of the resulting sludge waste. Scrubbing
requires an extended lead time to achieve widespread utilization and is least costly when built
into new ships, rather than retrofitted onto existing ones (where retrofit costs are estimated on the
order of $1 to $4 million). Current estimates also indicate ships will have to spend appreciable
time in SECA areas for scrubbing to be economic. Conversely, building a refinery residual
desulfurization unit with ancillaries could cost on the order of $500 million and, if done, would
create a feedstock that could be more attractive for upgrading to light clean fuels than for sale as
low-sulfur residual fuel for bunkers or inland use. Within any one SECA, it is not certain what
proportion of compliance will be achieved by scrubbing versus fuel supply and what the impact
on that balance is of complementary regulations on NOX and PM in addition to SOX.
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1.2 Summary of the Analysis
The analytical team developed the information and modeling techniques that enabled the
team and EPA to explore the potential effects of designating North American SECAs as part of
the MARPOL Annex VI. This report details the development of techniques to estimate bunker
demand in the shipping industry and also enhancements that have been made to the EnSys
WORLD model of the petroleum-refining industry. The resulting information from these
processes was used to establish baseline projections of international petroleum markets in the
years 2012 and 2020, against which the effects of SECAs—and other potential regulatory
scenarios—on shipping and bunker fuel demand were evaluated.
RTI and Navigistics Consulting developed a multistep approach for estimating future
bunker demand involving (1) identifying major trade routes, (2) estimating volumes of cargo of
various types on each route, (3) identifying types of ships serving those routes and carrying those
cargoes, (4) characterizing types of engines used by those ships, and (5) identifying the types and
estimated quantities of fuels used by those engines. In general, this approach can be described as
an "activity-based" approach with a focus on the international cargo vessels that represent the
majority of fuel consumption. Similar techniques for combining data on specific vessels with
data on engine characteristics have been used in other analyses (e.g., Corbett and Koehler [2003,
2004]; Koehler [2003]; Corbett and Wang [2005]; and Gregory [2006]). The approach in this
analysis extends these previous works by linking ship data to projections of worldwide trade
flows from Global Insights (2005) to determine the total number of trips undertaken in each year
and hence fuel use.
The methodology gives the following results for historical and forecasted bunker fuel
consumption:
• Worldwide bunker use in 2001 was estimated at 278 million tons, of which around
212 million tons were residual fuels.
• Between 2001 and 2020, total consumption grows at an average annual rate of 3.1%
(from 2006 to 2020, the growth rate is 2.6%).
• Around 47 million tons of bunker fuel were used in 2001 to transport international
cargo flows into and out of the United States (not all of which is purchased in the
United States).
• This fuel consumption related to U.S. trade is forecasted to grow at around 3.7%
between 2001 and 2020 (or 3.4% from 2006 to 2020), which is somewhat higher than
the world average because of high growth in container traffic arriving at U.S. ports.
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The estimates of worldwide bunkers are quite similar to those in the published works
cited above, in spite of differences in techniques. Koehler (2003) uses calculations of average
engine loads, run times, and specific fuel consumption for the existing vessel fleet to come up
with bunker fuel demand of around 281 million tons. Similarly, Corbett and Koehler (2003,
2004) estimate bunker demand at 289 million tons in 2001. These findings on fuel consumption
tend to be significantly higher than data published by the International Energy Agency (IEA),
which places international marine bunkers at around 140 million tons per year, of which around
120 million tons are residual fuels (see the discussion of these points in Section 4.2). Given the
far-reaching implications of these demand estimates for petroleum markets and related potential
effects of future SEC As, this analysis has chosen to evaluate baseline conditions in the refining
industry for both IEA's bunker fuel estimates and the estimates developed in this report (called
the "RTF estimates for clarity).
For this report, these two bunker fuel estimates are incorporated in the EnSys WORLD
model, which is a comprehensive, bottom-up model of the global oil downstream. It
encompasses crude and noncrude supply; refining operations and investment; crude, products,
and intermediates trading/transport; product blending/quality; and demand. It yields as outputs
detailed simulations of how this global system can be expected to operate under a wide range of
different circumstances, with outputs including price effects as well projections of sector
operations and investments. WORLD is not a forecasting tool per se, but rather it uses as a
starting point a global supply-demand world oil price outlook; in this study, the outlook is based
on the Energy Information Administration's (EIA) Annual Energy Outlook 2006 reference case.
To accomplish the goals of this study, WORLD has been expanded to incorporate seven
grades of bunker fuels, covering the major distillate and residual grades used in the marine
shipping industry. The latest international specifications applying to low-sulfur grades of these
fuels were also included because of their applicability for future SEC As. In addition, flexibility
was built in to allow the model user to vary the proportion of SECA compliance that is achieved
through fuel sulfur reduction versus other means such as onboard abatement or emissions
trading. This was necessary since it is feasible that widespread adoption of onboard abatement
could enable shippers to continue using high-sulfur bunker fuels and might even enable refiners
to raise the sulfur level toward the upper limit of 4.5% from today's average global level of 2.7%
and still meet required SOX emission standards. In addition, the model was given the capability
of covering the "extreme" scenario of switching residual bunker fuels entirely to marine diesel.
In addition, since any eventual estimates of bunker fuel production costs in SECA cases will
derive directly from refinery processing costs, a technology review of the WORLD model
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assumptions was undertaken. This involved checking on capital costs for the processes with the
most influence on costs of reducing sulfur in bunkers and on examining and adjusting processing
and blending options to guard against production of unstable bunker fuels. Finally, to ensure that
the model was correctly specified for any future policy scenarios that might be run on
implementation of SEC As, the related regulations were thoroughly reviewed.
Once these processes were complete, business-as-usual (BAU) cases (consistent with the
regional oil supply and demand projections from AEO) were set up in WORLD. The resulting
BAU cases for the years 2012 and 2020 were then executed on both the TEA and RTI bunkers'
estimates; key results from all four cases are included in the body of the report. The full results
are rich in detail; however, the important drivers impacting the SECA analyses revolve around
the outlook for product demand. Since the rigorous analysis of shipping activity and fuel
consumption conducted in this report estimates high bunker demand, the impacts of SEC As or
other marine fuels regulations will be similarly greater than for those estimated using lower
demand forecasts. A second major driver evident in these and other WORLD analyses is that the
ongoing shift toward distillates, especially in Europe and non-Organisation of Economic Co-
operation and Development (OECD) regions, will materially alter gasoline and distillate trade
patterns, their product pricing and refining investments, and economics. These developments
will, in turn, impact the market and supply effects of SEC As and other global marine fuels
regulations.
The overall objective of the refinery modeling was to develop and implement any
modifications to the WORLD model that are needed to accommodate details of bunkers' grades
and other issues such as updated technology costs, for example. These features have been
successfully implemented and applied (the 2012 and 2020 BAU cases were developed and
represent a sound starting basis to examine the impacts of broader SECA regulations and/or
tighter global marine fuels limits). Section 5 provides details of the WORLD model estimates for
the BAU cases.
The modeling foundation is particularly important because the nature of the MARPOL
Annex VI regulations and goals, and the characteristics of the international marine fuels industry,
meaning that there is a much greater potential for variability in future scenarios than is true for
most types of fuels regulations.
Section 6 discusses technology alternatives for compliance available to the ship operators
and to characterize them in terms of technology applicability (for different marine ships and/or
market sectors), emissions reduction, and costs. This section provides technical background
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descriptions, cost information, and emissions reduction potential for onboard emissions
abatement alternatives: fuel switching, in-engine fuel mixing, and exhaust gas scrubbing. A
thorough understanding of the technically feasible alternatives is essential because it bounds the
decision possibilities available to affected stakeholders and influences the burden of potential
SECA requirements.
Section 7 extends the fuel consumption analysis to estimate ship fuel consumption in
2012 and 2020 with the boundaries of two SECA scenarios. The first scenario sets the boundary
at 100 nautical miles (nm) off the Pacific coast and 50 miles off the Gulf and East coasts, or up
to the boundary of the Exclusive Economic Zone (EEZ), whichever was nearest the coastline.
The second scenario sets the SECA boundary at 200 miles off all coasts. Under the 100/50 nm
SECA scenario, a total of 7.5 million tons is consumed in 2012, and a total of 8.9 million tons is
consumed in 2020. Under the 200 nm SECA scenario, a total of 13.5 million tons is consumed
within the boundaries in 2012 and 16.2 million tons in 2020.
Using the BAU cases as a starting point, the WORLD model was used to study the
alternative SECA scenarios and address key uncertainties. Among these issues, as illustrated in
the results in Section 8, for the SECA analyses, are the following:
• the regional make up of bunker fuel demand;
• associated with this, the extent to which consumption of low-sulfur bunker fuel for
SECA compliance will be met by supplies within the SECA or elsewhere;
• the extent of switching, either regionally or globally, to marine distillate fuels;
• the degree to which compliance with the MARPOL regulations will be achieved
through improved fuel quality versus via onboard scrubbing and/or emissions trading;
using the WORLD model, plausible "high" and "low" scenarios were applied and
analyzed; and
• whether bunkers' blend compositions will need to be still further restricted to capture
ship operational limits such as those relating to fuel instability.
1.3 Organization of this Report
The remainder of this report is organized as follows:
• Section 2 presents a profile of marine bunker fuels, their refining processes, and the
overall supply chain used to deliver the fuels to marine vessels.
• Section 3 develops a model of shipping activity and estimates bunker fuel demand.
• Section 4 describes how the analysis of baseline conditions in petroleum markets is
implemented in the WORLD model.
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Section 5 then presents estimated results from the WORLD model regarding B AU
conditions in 2012 and 2020.
Section 6 reviews fuel switching, in-engine fuel mixing, and exhaust gas scrubbing as
well as other technology considerations for SECA compliance.
Section 7 describes the SECA fuel consumption analysis.
Section 8 describes the modeling results for selected SECA regulations.
Appendix A reviews cost assumptions regarding refinery technologies used in the
analysis of the WORLD model.
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SECTION 2
OVERVIEW OF THE MARINE FUELS INDUSTRY
This section provides an overview of the marine fuels industry, which is characterized by
a complex, international network of organizational and trade relationships. Marine distillates
historically come from poorer-quality distillate recycle streams that are unsuitable for upgrading
to diesel fuel or other low-sulfur products. Thus, the supply chain for the marine fuels industry
begins with integrated petroleum refineries, where "bottoms" from atmospheric and vacuum
distillation unit operations are combined to form the bulk of residual fuel stocks (see Section
2.1). The dominant producers of marine fuels are divisions of the major oil companies such as
Shell Trading (STUSCO) and BP Marine. Around the world, these large producers are joined by
hundreds of smaller firms that contract to transport, blend, and sell low-quality fuel stocks to the
shipping industry.
Most of the worldwide bunker fuel volume is sold to firms that operate bunkering
facilities around the world, although some of the major petroleum refiners also contract for and
deliver marine fuels. These large refiners, including the Chemoil Group, O.W. Bunker, and the
Chinese government-owned Chimbusco, purchase blended stocks from the producers and also
blend, transport, and store some products themselves. As much as 25% of the world's marine
fuels are purchased and resold by brokers or other intermediaries that never actually take
physical control of the bunker fuel. Arbitrage activities of these firms help keep the worldwide
market efficient, as excess price differentials are quickly exploited and eliminated.
The final stage of the marine fuel supply chain is the bunkering itself, which can either be
done while the ship is docked or directly from bunker barges while the ship is anchored. There
are hundreds of bunkering ports around the world and thousands of firms that provide the actual
bunkering service.
Logistics and transport cost factors influence the location of bunker ports. In addition to
being located close to supply sources (petroleum refineries) and consumers of transported goods
(major population centers), bunkering ports are often strategically located along high-density
shipping lanes. The largest port of this type is in Singapore and handles more than twice as much
bunker fuel volume as the next biggest provider. Panama and Gibraltar are other examples of
strategically located facilities. In North America, the largest facilities follow the general pattern
suggested by location theory; Los Angeles, San Francisco, New York, Philadelphia, Houston,
and New Orleans are close to both refinery supply and transport destinations.
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The following subsections briefly review the petroleum-refining process(focusing on
distillation and additional downstream treatment processes that further refine crude oil into
higher-value petroleum products), characteristics of marine fuels, and the supply chains that
deliver the refined marine fuels.
2.1 Refining of Petroleum Products (Including Marine Fuels)
Marine fuels' characteristics are determined in part by the quality of the crude oil used to
create them and in part by the refining process. We begin by reviewing petroleum refining to
better illuminate the differences among marine fuels.
The refining processes used to produce petroleum products, including marine fuels,
involve the physical, thermal, and chemical separation of crude oil into its major distillation
fractions, followed by further processing (through a series of separation and conversion steps)
into finished petroleum products. EPA's (1995) sector notebook on the petroleum industry
details the primary products of refineries grouped into three major categories:
• fuels (motor gasoline, diesel and distillate fuel oil, liquefied petroleum gas, jet fuel,
residual fuel oil, kerosene, and coke);
• finished nonfuel products (solvents, lubricating oils, greases, petroleum wax,
petroleum jelly, asphalt, and coke); and
• chemical industry feedstocks (naphtha, ethane, propane, butane, ethylene,
propylene, butylenes, butadiene, benzene, toluene, and xylene).
This discussion focuses on the "fuels" product category and specifically on the distillate and
residual fuels that are blended to form marine fuels.
Refineries are complex operations and often have unique configurations based on the
properties of the crude oil to be refined (which varies significantly depending on the source) and
the variety of products to be produced. Figure 2-1 illustrates general unit operations and product
flows for a typical refinery; the generalized unit operations outlined below are typical of most
refineries.
Refinery operations can be broken down into four major stages: distillation,
desulfurization, refining, and blending. Following an initial desalting process to remove
corrosive salts and excess water, crude oil is fed into an atmospheric distillation column that
separates the feed into the subsequent "distillation fractions." The lightest of the fractions are
called "top gases" and include light gasoline, ethane, propane, and butane. Top gases are further
processed through reforming and isomerization to produce gasoline, but they could also be
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Basic Refining Concepts
Crude Oil
Atmospheric
Distillation
Tower
(Crude Unit)
Refinery Fuel
Gas Processing
Processed Gasoline
Further Processed to Gasoline
Heavy Naphtha for Jet Fuel
Further Processed to Jet Fuel,
Diesel and Fuel Oils
Further Processed to Gasoline,
Diesel and Fuel Oil
Further Processed to Gasoline,
Diesel and Fuel Oil
Further Processed to Gasoline,
Diesel, Fuel Oil, and Lube Stocks
Figure 2-1. Basic Refining Process and Product Streams
Source: Adapted from Marcogliese, Rich. 2005. "Refining Fundamentals & Impact of Changing Fuel
Specifications." Presented on February 17, 2005 at the Lehman Brothers Analyst Teach-in. Valero Energy
Corporation. Obtained on November 30, 2005. Available at:
http://www.valero.com/Investor+Relations/Management+Presentations/.
diverted to lower-value uses such as liquefied petroleum gas (LPG) and petrochemical
feedstocks. The middle-boiling fractions, which include kerosene, gas oil, and spindle oil, make
up most of the aviation fuel, diesel, and heating oil produced. The remaining undistilled liquids
are called "bottoms" and represent the heavier fractions that require vacuum distillation at very
low pressures to facilitate volatilization and separation. Vacuum distillates and residues can be
further processed through catalytic cracking and visbreaking into low-value products such as
residual fuel oil, asphalt, and petroleum coke.
The lower-middle distillates from which marine fuels are made may also require
additional downstream processing. These fractions are treated using one of several techniques:
• "cracking/visbreaking," which breaks apart large hydrocarbon molecules into smaller
ones;
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• "combining" (e.g., alkylation, and isomerization), which joins smaller hydrocarbons
to create larger more useful molecules, or reshaping them into higher-value
molecules; and
• catalytic "hydrocracking" is a downstream processing method used to crack fractions
that cannot be cracked in typical cracking units. These fractions include middle
distillates, cycle oils, residual fuel oils, and reduced crudes. Typically, the feedstock
to a hydrocracking unit is first hydrotreated to eliminate any impurities (e.g., sulfur,
nitrogen, oxygen, halides, and trace metals) that could deactivate the catalyst.
Following the completion of downstream processing stages, several product streams are
blended by the refinery to produce finished products. Generally, these blending operations
include gasoline, middle distillate, and fuel oil blending.
2.1.1 Primary Refinery Inputs
Crude oil is the dominant input in the manufacture of refined petroleum products,
accounting for approximately 79% of total material costs of U.S. refineries, or $132 billion in
2002, according to the latest Economic Census (U.S. Bureau of the Census, 2004). Table 2-1
provides a summary of these inputs. Similarly, crude accounts for over 92% of the volume of
refinery inputs in the United States. Crude oil is likely to have greater representative share of
both material costs and inputs in developing countries due to fewer environmental regulatory
product specifications.
Table 2-1. Total U.S. Refinery Input of Crude Oil and Petroleum Products in 2004
Product
Crude Oil
Natural Gas Liquids
Other Liquids
Other Hydrocarbons/Oxygenates
Other Hydrocarbons-Hydrogen
Oxygenates
Fuel Ethanol
MTBE
All Other Oxygenates
Unfinished Oils (net)
Motor Gasoline Blending Components (net)
Aviation Gasoline Blending Components (net)
Total Input to U.S. Refineries
Year 2004 (1,000s barrels)
5,663,861
154,356
316,838
150,674
28,039
122,635
74,095
47,600
940
186,826
-18,558
-2,104
6,135,055
% of Total
92.3%
2.5%
5.2%
2.5%
0.5%
2.0%
1.2%
0.8%
0.0%
3.0%
-0.3%
0.0%
100.0%
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2005a. Petroleum Supply Annual
2004, Volume 1. Washington, DC: U.S. Department of Energy, Energy Information Administration.
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2.1.1.1 Crude Oil
Characteristics of crude oil—including relative density, sulfur, and acid content—have a
significant influence on the products a refinery is able to produce. The cost of production also
varies significantly depending on the type of crude oil used in the refining process.
Crude-oil density can be measured using the API gravity number, which provides a
measure of relative density. Crude oils are typically classified as light, medium, and heavy oils.
Light crude has the highest API number, equating to low density, which makes this crude type
the easiest to refine into gasoline products. Heavy crudes, with the lowest API number and
higher relative density, require additional processing to obtain the same distribution of refinery
products.
Sulfur content determines whether a specific type of crude is "sweet" (low sulfur) or
"sour" (high sulfur). Sweet crude is defined as crude oil with a sulfur content of less than 0.5%,
and sour crude has sulfur content higher than 0.5%. Sweet crude is less corrosive because of low
levels of sulfur compounds such as hydrogen sulfide (H2S). Sour crude requires additional
equipment and processing to extract the additional sulfur.
Crude oils' relative density and sulfur content vary, depending on the region of the world
that it was extracted from. Light, sweet crude types typically have the highest prices because of
limited availability and high demand. Heavy, sour crude typically sells at a discount relative to
the light sweet crude because of its relative abundance and its high sulfur content. Light sweet
crude includes WTI (West Texas Intermediate) found in the western hemisphere and Brent
(North Sea Crude) found in Europe. Heavy sour crude includes Arabian Heavy (Middle East)
and Maya (Mexico). Figure 2-2 illustrates the spectrum of crude qualities. Density is plotted
along the horizontal axis and sulfur content along the vertical axis.
In Figure 2-2, crude types near the lower right-hand corner of the figure represent the
crude types that require the least amount of processing. As one moves toward the top left-hand
corner of the figure, the crude is more difficult to process. The majority of the world's supply of
crude oil is light to medium sour, which is trending toward heavier and more sour crude as
reserves of light sweet crude are depleted (Marcogliese, 2005).
WTI, Brent, and Dubai Fateh are the most commonly used benchmarks. These
benchmark crude types are used in international trading, and varying qualities of crude are sold
at a discount or premium relative to the benchmark price. OPEC has its own reference known as
the OPEC Basket, which consists of 11 crude types and represents the weighted average of
density and sulfur content for all the member countries' crude types, according to production
levels and export volumes (see Table 2-2).
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3.5 -,
3 -
2.5 -
2 -
1.5 -
1 -
0.5 -
0 -
Maya
20
i Arabian Heavy
• Arabian Medium
_ Mars Blend
AFateh
A OPEC Basket
Urals
Arabian Light
Iran Light
Alaska North Slope
(ANS)
Cabinda •
Brent Blend*
AWTI
• Bonny Light
Tapis Blen
25
30 35
API Gravity
(Heavy => Light)
40
45
50
Figure 2-2. Quality by Crude Type
Source: Adapted from Marcogliese, Rich. 2005. "Refining Fundamentals & Impact of Changing Fuel
Specifications." Presented on February 17, 2005 at the Lehman Brothers Analyst Teach-in. Valero Energy
Corporation. Obtained on November 30, 2005. Available at:
http://www.valero.com/Investor+Relations/Management+Presentations/.
Note: A = Benchmark crude types
Table 2-2. Crude Oil Types Included in the OPEC Basket
Type of Crude
Saharan Blend
Minas
Iran Heavy
Basra Light
Kuwait Export
Es Sider
Country of Origin
Algeria
Indonesia
Islamic Republic of Iran
Iraq
Kuwait
Libya
Type of Crude
Bonny Light
Qatar Marine
Arab Light
Murban
BCF17
Country of Origin
Nigeria
Qatar
Saudi Arabia
UAE
Venezuela
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2005b. "OPEC Brief Washington
DC: DOE/EIA. Obtained on November 29, 2005.Available at:
http://www.eia.doe.gov/emeu/cabs/opec.html.
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2.1.1.2 Blending Stocks and Additives
Following initial atmospheric distillation of crude oil, a variety of specialized inputs may
be added to output product streams (see Figure 2-1) in downstream units to enhance the
refinery's ability to recover a desired mix of products. Among these products might be
unfinished oil, residual fuel oil used as input to a vacuum distillation unit (see Table 2-2 for a list
of additives). Motor gasoline and aviation fuels require blending components that include
oxygenates as well as other hydrocarbons. Although they are counted as "refinery inputs," they
are brought to saleable specifications in terminals and blending facilities, not in conventional
refineries.
2.1.2 Refinery Production Models
Across the globe, refineries are typically concentrated near major consumption areas,
based on the principle that transporting crude oil is cheaper than transporting refined products. In
addition, proximity to consumption areas allows refineries to more quickly respond to seasonal
or weather-related demand shifts (Trench, 2005). Their goal is to meet the regional demand for
petroleum products, hence maximizing the value of product mix produced. For example, in the
United States, as well as other developed countries, refineries strive to maximize gasoline and
low-sulfur diesel fuels, while simultaneously minimizing output of lower value heavy oils such
as residual fuel and petroleum coke.
Building on the basic refinery concepts presented in Figure 2-1, refineries can be grouped
into four basic configurations: topping, hydroskimming, cracking (medium conversion), and
coking (high conversion). Each configuration builds on the previous production model by adding
on additional downstream processing equipment that allows the refinery to further expand its
yield of the desired mix of petroleum products.
2.1.2.1 Topping Refineries
Topping refineries are the simplest example of a refinery production model. Their
primary function is to produce feedstocks for petrochemical manufacturing. Topping refineries
typically consist of storage tanks, an atmospheric distillation unit, and recovery facilities for top
gases and light hydrocarbons such as ethane/propane/butane. These facilities produce naphtha
but do not produce gasoline (Reliance, 2005).
2.1.2.2 Hydroskimming Refineries
Building on the basic topping configuration, hydroskimming refineries incorporate
hydrotreating (distillate desulfurizer) and catalytic-reforming units to improve the output of high-
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value fuels such as distillates and straight-run gasoline. Table 2-3 lists the typical mix of product
yields from hydroskimming refineries. These facilities typically rely primarily on light sweet
crude as their primary input to minimize resulting heavy fuel and residual fuel products because
they have limited upgrading capabilities of distilled fractions.
Table 2-3. Typical Production Yield from a Hydroskimming Refinery
Product % Yield
Propane/butane 4%
Gasoline 30%
Distillate 34%
Heavy fuel oil & other 32%
Total Yield 100%
Note: Gasoline includes reformulated gasoline (RFG), conventional, CARD, and Premium. Distillate includes jet
fuel, diesel, and heating oil.
Source: Marcogliese, Rich. 2005. "Refining Fundamentals & Impact of Changing Fuel Specifications." Presented
on February 17, 2005 at the Lehman Brothers Analyst Teach-in. Valero Energy Corporation. Obtained on
November 30, 2005. Available at: http://www.valero.com/Investor+Relations/Management+Presentations/.
Hydrotreating removes impurities such as sulfur, nitrogen, oxygen, halides and trace
metals. It also upgrades the quality of these fractions by converting olefms and diolefins to
paraffins to reduce gum formation in fuels (EPA, 1995). Catalytic reforming units process
straight-run low-octane gasoline and naphthas into high-octane aromatics through four reactions
that create aromatics by removing hydrogen from the feedstock (see EPA [1995] for details of
these reactions).
2.1.2.3 Cracking Refineries
Cracking refineries build in complexity from the hydroskimming configuration by adding
vacuum distillation, catalytic cracking, and alkylation units. The vacuum distillation unit further
fractionates heavy bottoms from the atmospheric distillation process into gas oil and residual
fuel. Table 2-4 lists the typical mix of product yields from cracking refineries. The total yield of
104% represents a volumetric gain due to the cat cracker's ability to convert large hydrocarbon
molecules into multiple smaller molecules. These facilities typically rely on light sour crude as
the primary input. Moderate upgrading capabilities allow cracking refineries to increase the yield
of higher-value products as well as gain volumetric output per volume of crude oil input
(Marcogliese, 2005).
The catalytic cracking unit (i.e., fluidized and moving-bed) uses heat, pressure, and
catalysts to breakdown heavy complex hydrocarbon molecules (i.e., gas oil) into smaller/lighter
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Table 2-4. Typical Production Yield from a Cracking Refinery
Product % Yield
Propane/butane 8%
Gasoline 45%
Distillate 27%
Heavy fuel oil & other 26%
Total Yield 104%
Note: Gasoline includes RFG, conventional, CARD, and Premium. Distillate includes jet fuel, diesel, and heating
oil.
Source: Marcogliese, Rich. 2005. "Refining Fundamentals & Impact of Changing Fuel Specifications." Presented
on February 17, 2005 at the Lehman Brothers Analyst Teach-in. Valero Energy Corporation. Obtained on
November 30, 2005. Available at: http://www.valero.com/Investor+Relations/Management+Presentations/.
molecules such as light cycle oil (LCO). LCO is then processed with other distillates in a
hydrotreating process. Once the LCO and FCC gasoline are removed, an alkylation unit converts
the remaining iosbutane feedstock into alkylates (i.e., propane/butane liquids), which are widely
used blending additives in high-octane gasoline production.
2.1.2.4 Coking Refineries
Coking refineries extend the cracking refinery by adding hydrogen processing,
hydrocracker, and delayed coking units to increase refineries' capabilities to convert fuel oil into
distillates (Reliance, 2005). Coking refineries are able to use medium to heavy sour crude as
their primary input. These refineries also have the highest light product yields and volume gains,
compared to other refinery configurations, as shown in Table 2-5 (Marcogliese, 2005).
Table 2-5. Typical Production Yield from Coking Refineries
Product % Yield
Propane/butane 7%
Gasoline 58%
Distillate 28%
Heavy fuel oil and other 15%
Total Yield 108%
Note: Gasoline includes RFG, conventional, CARD, and Premium. Distillate includes jet fuel, diesel, and heating
oil.
Source: Marcogliese, Rich. 2005. "Refining Fundamentals & Impact of Changing Fuel Specifications." Presented
on February 17, 2005 at the Lehman Brothers Analyst Teach-in. Valero Energy Corporation. Obtained on
November 30, 2005. Available at: http://www.valero.com/Investor+Relations/Management+Presentations/.
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The hydrogen facility produces hydrogen that is used as a feedstock in the hydrocracker
as well as the hydrotreater units. The hydrocracker units apply hydrogen and significant pressure
in a fixed-bed catalytic cracking reactor. Feedstocks for this unit include low-distillate fractions,
as well as LCO, residual fuel oils. The hydrogen mitigates the formation of residual fuels and
increases the yield of middle-distillate fuels, such as diesel and jet fuels (EPA, 1995). Delayed
coking is a thermal cracking process that upgrades and converts petroleum residuum (heavy fuel
oil) into liquid and gas product streams. The delayed coker unit eliminates residual fuel oil,
leaving behind a solid concentrated carbon material known as petroleum coke (Ellis and Paul,
1998).
2.1.3 Refineries Around the World
There were 674 individual refining installations around the world with 82.4 million
barrels per day of crude oil refining capacity at the end of 2004 (Oil and Gas Journal [OGJ],
2004). The number of operable refineries had fallen by 43 from 717 in 2003, a decline of 6.4%.
Over the last 5 years, the number of refineries worldwide has declined, while the total crude
capacity has continued to rise (Nakamura, 2004).
Table 2-6 summarizes the number, estimated crude capacity, and fuel "processing"
capacity for refineries in seven world regions at the end of 2004. Historically, the mature markets
of the United States and Europe have contained the largest number of refineries. However, recent
dramatic growth in Asian markets has resulted in an increased number of refineries in South
Korea, along with other South Pacific countries.
The concentrations of refineries in Asia, North America, and Western Europe represent
approximately 68% of total refinery capacity. North American and Western European refineries
have invested heavily in processing units that maximize their output of gasoline and other high-
value outputs. This is illustrated by their processing capabilities as a percentage of crude
capacity. In other regions of the world, refineries rely on atmospheric distillation to obtain
straight-run product streams. As a result, residual fuel oil tends to be a greater share of total
refinery output in these regions.
Refineries typically address regional fuel demand, while maintaining only a minimal
stock of additional output for international trade and unexpected supply shocks due to weather.
They are constrained by local demand, as well as the crude types that are proximal to the facility.
Table 2-7 lists the 25 largest refinery companies in the world by total crude capacity. These firms
represent 60% of the world's crude refining capacity. The refinery companies on this list have
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Table 2-6. Refinery Presence by World Region in 2004
Region
Africa
Asia & Oceania
Central & South America
Eastern Europe & Former U.S.S.R.
Middle East
North America
Western Europe
World Total
Refinery
Count
46
161
66
86
45
159
111
674
Crude Capacity"
3,230,362
20,695,031
6,572,359
9,764,712
6,471,615
20,476,228
15,198,594
82,408,901
Fuels Processing
Capacity3'11
506,470
2,052,728
529,190
1,467,693
691,730
5,598,388
2,480,458
13,326,657
Processing
Capacity as
% of Crude
2.4%
10.0%
3.5%
15.0%
10.5%
86.5%
76.8%
16.2%
a barrels per calendar day (b\cd)
b Processing capabilities are defined as conversion capacity (catalytic cracking, and hydrocracking) and fuel
production processes (catalytic reforming and alkylation) divided by crude distillation capacity (% on crude). This
measure represents the presence of downstream processing technology that improves the refinery's ability to
produce high-value refined products such as high octane gasoline.
Source: Oil and Gas Journal (OGJ). 2004. "2004 Worldwide Refining Survey." Oil and Gas Journal 102(47): 1-2.
focused on expanding capacity and reducing the total number of operable refineries over the last
10 years (Nakamura, 2004).
Many of the largest refinery companies have been investing heavily to supply Asian
markets because of anticipated long-term growth in the region. Emerging Asian markets are
growing at 4% annually, compared to the more mature markets of Europe and Japan that are
expected to grow at less than 0.5% annually (Mergent, 2005). This high growth in Asia can
largely be attributed to the transportation sector, including both freight shipping and personal
vehicles.
As discussed, refinery products are diverse in character and functionality, and the specific
mix of products will vary dramatically depending on the refinery's configuration and type of
crude used. Table 2-8 summarizes how different refinery products vary across regions of world
in 2003.
Motor gasoline is the highest-value product in the refinery output mix, and refineries
typically engineer their unit operations to maximize its production. In North America, motor
gasoline is typically the largest share of refined products, representing 45% of refinery output per
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Table 2-7. World's Largest Refinery Companies by Capacity in 2004
Rank
1
2
3
4
5
6
7
8
9
10
11
12
13
Company
ExxonMobil Corp.
Royal Dutch/Shell
BPPLC
Sinopec
Petroles de Venezuela SA
Total SA
ConocoPhillips
ChevronTexaco Corp.
Saudi Aramco
Petroleo Brasileiro
Valero Energy Corp.
Petroleos Mexicanos
China National Petroleum Corp.
Crude
Capacity
(1,000s
b/cda)
5,693
4,934
3,867
2,793
2,641
2,622
2,615
2,063
2,061
1,965
1,930
1,851
1,782
Rank
14
15
16
17
18
19
20
21
22
23
24
25
Crude
Capacity
Company (1,000s b/cd)
National Iranian Oil Corp.
Nippon Oil Co. Ltd.
OAO Lukoil
Respsol YPF SA
Kuwait National Petroleum
Co.
OAO Yukos
Pertamina
Marathon Ashland
Petroleum LLC
Agip Petroli SpA
Sunoco Inc.
SK Corp.
Indian Oil Corp. Ltd.
1,474
1,157
1,150
1,106
1,085
1,048
993
935
906
880
817
111
a b\cd
Source: Nakamura, David N. 2004. "Worldwide Refinery Capacity Creeps ahead in 2004." Oil & Gas Journal
102(47): 46-53.
Table 2-8. World Refinery Product Outputs of World Refineries per Day for 2003
Region
Africa
Asia & Oceania
Central & South America
Eastern Europe & FSU
Middle East
North America
Western Europe
World Total
Motor
Gasoline
0.5
3.8
1.3
1.0
0.9
9.7
3.7
20.8
Distillate Fuel
Oil"
0.7
6.0
1.7
1.5
1.8
4.6
5.7
22.1
Residual Fuel
Oil"
0.7
2.9
1.1
1.5
1.7
1.2
2.2
11.3
Other3
0.8
7.1
1.9
1.5
2.1
5.8
4.7
23.9
Total Refinery
Products
2.7
19.8
5.9
5.6
6.4
21.4
16.3
78.1
a million barrels/day
Source: U.S. Department of Energy, Energy Information Administration (EIA). 2005d. "International Energy
Annual 2003: Table 3.2." Washington DC: DOE/EIA. Obtained on November 20, 2005. Available at
http://www.eia.doe.gov/iea/.
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day, while distillate and residual fuel accounted for 22% and 6%, respectively, in 2003.
However, in all other major regions of the world, motor gasoline represented around 20% of total
refinery output on average. Figure 2-3 illustrates these regional differences in the distribution of
motor gasoline, diesel, and residual fuel production for seven world regions.
12 -,
10
t
xs
1
$$
vS
^
ss
-------
and distillates.. Despite the potential of hydroprocessing to treat high-sulfur residual fuels, the
technology is not yet cost-effective for refiners.
For these reasons, bunker fuels may witness shortages as refineries continue to keep pace
with demand for motor gasoline and other high-value refined products in North America and
Western Europe, where motor gasoline prices are high relative to other refined products. (These
trends are included in the WORLD model and discussed in Sections 4 and 5.) Industry experts
have suggested that North America could witness a shortage of low-sulfur residual fuel of 20
million metric tons per year by 2015 and a surplus of high-sulfur residual oil of 40 million metric
tons per year (Bunkerworld, 2005). To address these shortages, the industry expects an increase
in low-sulfur residual fuel oil imported from South America or other areas of the world with low
conversion capacity (and thus high residual fuel output).
In developing regions such as the African, Middle Eastern, and Asian markets,
availability of sweet crude supplies, coupled with limited conversion capacity in existing
regional refineries, will result in continued production of residual fuels. Over time, as sweet
crude becomes increasingly scarce and the sulfur content of crude feedstocks increases,
refineries in these regions will be forced to upgrade their conversion capacity by adding
additional downstream processing to existing facilities, or the share of heavy distillates and
residual fuel oils of their total refinery outputs will increase.
Finally, as China's market for fuel demand increases, Chinese oil companies are
competing with U.S. and European companies for depleting supplies of the world's crude oil.
The Energy Information Administration (EIA) predicts that China will begin to invest in
petroleum projects in countries around the world, including Canada and South America, which
have traditionally represented over 25% of the United States' energy imports. China signed its
first oil deal with Venezuela in 2004, marking the beginning of a battle for resources with more
mature markets such as the United States. If China continues to increase its presence in the West
through acquiring petroleum resources that traditionally supplied residual fuel oil demand in
North America, any shortages in residual fuel oil could increase exponentially (Mergent, 2005).
2.2 Marine Fuel Types
There are three major types of marine fuel: distillate fuel, residual fuel, and a
combination of the two to create a fuel type known as "intermediate" fuel oil (IFO). In this
section, the various grades of marine fuel are introduced using the colloquial industry names to
group the different fuel types. The purpose of this discussion is to introduce the reader to marine
fuels in general to enable assimilation of more nuanced discussions that are presented in the
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balance of this report. Section 4 provides a technical discussion of marine fuel product
specifications.
Distillate and residual fuels are blended into various combinations to derive the different
grades of marine fuel oil. Table 2-9 lists examples of the major marine fuel grades and their
colloquial industry names. In terms of cost, distillates are more expensive than intermediates, and
residual fuels are the least expensive.
Table 2-9. Marine Fuel Types
Fuel Type
Distillate
Intermediate
Residual
Fuel Grade Colloquial Industry Name
DMX, DMA, DMB, DMC Marine gas oil (MGO) and marine distillate oil
(MDO)
RME/F-25, RMG/H-35 Marine diesel fuel or intermediate fuel oil (IFO180
andIFO380)
RMA- RMH, RMK, and RML Fuel oil or residual fuel oil
Source: Adapted from U.S. Environmental Protection Agency (EPA). 1999. In-Use Marine Diesel Fuel. EPA420-
R-99-027. Washington, DC: U.S. Environmental Protection Agency.
Distillates and/or residual fuel oil stocks are blended with blending components or cutter
stocks to achieve internationally accepted product specifications provided by the 1987 (revised in
1996) international standard, ISO 8217, that defines the requirements for fuel grades for use in
marine diesel engines. Marine fuel grades carry three letters: the first "D" or "R" specifies
"distillate fuel" vs. "residual fuel." The second "M" signifies "marine fuel" use. The third letter
designates the individual grade. Distillate marine (DM) fuels have three grades from A to C.
Residual marine (RM) fuels have 15 grades depicted by letters A through H, K, and L. For
example, RME-35 stands for "residual marine fuel E at a maximum viscosity (at 100° C) of 35
centistokes (EPA, 1999).
2.2.1 Marine Fuel Blending Stocks
As described in Section 2.1, "hydroskimming" type refineries produce straight-run stocks
used in marine fuel blending, including light diesel, heavy diesel, and straight-run residue. More
complex refineries derive similar blending stock components as the output from fluidized bed
catalytic cracking (FCC) units. These stock components include light and heavy diesel, as well as
light cycle gas oil (LCO) and heavy cycle gas oil (HCO). HCO also comes from the residual
output from visbreaker units. These blending stocks are mixed with existing product streams
from a refinery to manufacture a variety of marine fuel grades.
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2.2.2 Marine Gas Oil (MGO)
Marine gas oil is the result of blending LCO with distillate oil to produce one of the
highest marine fuel grades. MGO is more expensive because it is a lighter fraction and better
quality fuel than diesel fuel. MGO is a fuel best suited for faster-moving engines (Spreutels and
Vermeire, 2001).
2.2.3 Marine Distillate Oil (MDO)
MDO is manufactured by combining kerosene, light, and heavy gas oil fractions. DMA
and DMB are typically used in small- to medium-sized marine vessels. DMC is heavier fuel oil
and may sometimes be referred to as an intermediate fuel oil because it can be blended with
residual fuel. MDO is manufactured by blending DMC with 10% to 15% residual fuel (Spreutels
and Vermeire, 2001). MDO is more expensive than the more common intermediate fuel types.
2.2.4 Intermediate Fuel Oil (IFO)
Residual marine fuel grade G (RMG-35) is one of the most common residual fuels used
in transoceanic ships. More commonly known as IFO380, this residual marine fuel is
manufactured at the refinery and contains visbroken residue, HCO, and LCO (Spreutels and
Vermeire, 2001). IFO380 typically has a high sulfur content that approaches 5%. IFO180 is
another common IFO. IFO180 has a lower viscosity and metals content but maintains the same
sulfur content as IFO380.
2.3 Bunker Fuel Suppliers
The bunker fuel supply chain includes traders, suppliers, brokers, bunkering-service
providers or facility operators, and bunkering ports. The information available on different
segments of the bunker fuel supply chain varies dramatically. Therefore, this section is not
intended to be comprehensive but to provide an overview of the industry. We focus on four of
the largest bunkering ports (Singapore, Rotterdam, Fujairah, and Houston).
Around the world, there are approximately 400 major bunkering ports. Logistics and
transport cost factors influence the location of these bunker ports as well as local environmental
regulations. In addition to being located close to supply sources (petroleum refineries) and
consumers of transported goods (major population centers), bunkering ports are often
strategically located along high-density shipping lanes. For example, Singapore handles more
than twice the bunker fuel volume of Rotterdam, the next largest port. In North America, the
largest facilities follow the general pattern suggested by location theory; Los Angeles, San
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Francisco, New York, Philadelphia, Houston, and New Orleans are close to both refinery supply
and transport destinations.
2.3.1 Singapore
Singapore's strategic location on the Strait of Malacca makes it the largest port in the
world in terms of cargo throughput and bunker fuel sales. The total cargo throughput in 2005
equaled 423 million tons. The port of Singapore handles large volumes of petroleum products
and dry bulk cargo. In 2005, Singapore surpassed Hong Kong by almost 1 million twenty-foot
equivalent units (TEUs) and claimed the lead in handling containerized cargo (Sina, 2006). Its
tonnage of containerized, oil, and dry-bulk cargo has steadily increased over the past 5 years.
Although the number of vessel calls has been slowly declining, Singapore still handles more
vessel calls than any other port in the world—almost 173,000 vessel calls in 2005 (MPAS,
2005a).
Singapore is also the largest bunker fuel market in the world. Bunker turnover was
reported at 25.48 mmt (million metric tons) in 2005 (MPAS, 2006b). Turnover at the port grew
at the average rate of 5.6% over the past 6 years, equaling 20.8 mmt in 2003 and 23.6 mmt in
2004. Heavy fuel-oil sales accounted for 71% of total bunker sales by volume in 2004, with
lighter fuel and distillate oils accounting for 19% and others (including lube oils) for the
remaining 2% (MPAS, 2005c). The majority of bunker deliveries to vessels in the port of
Singapore are made by bunker tankers; however, other types of deliveries are available as well.
2.3.1.1 Refineries
Singapore is one of the top three refining centers in the world; the others are Houston and
Rotterdam. Petroleum refining accounted for approximately 16.5% of Singapore's gross
domestic product (GDP) in 2004. Singapore's refineries have a major influence on Asian
markets: their petroleum product exports were valued at $17.5 billion in 2004.l Singapore also
exported $4.7 billion worth of bunker fuels, which equaled 2.6% of national GDP (SMTI, 2005).
Operating at 92% capacity, the top three refineries in Singapore have a combined
production of around 1.3 million barrels per day (bpd) (EIA, 2005e). Out of that quantity, bunker
fuels consumed in the Singapore shipping market comprise approximately 400,000 bpd. Another
400,000 bpd are consumed locally for various purposes, and the remainder (mostly gasoline and
diesel fuels) are exported to Vietnam, China, and Indonesia (Reuters, 2006).
Numbers are reported in U.S. dollars.
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Refineries producing bunker fuel that is sold in the local market are as follows:
• Jurong Island Refinery, owned by ExxonMobil
- Capacity of 605,000 bpd
• Pulau Bukom Island Refinery, owned by Royal Dutch/Shell
- Capacity of 458,000 bpd
• SRC Jurong Island Refinery, partially owned by Singapore Refining Corporation
(SRC), partially owned by ChevronTexaco through its subsidiary Caltex
- Primary plant—a joint venture between SPC and Caltex (ChevronTexaco) with
285,000 bpd capacity
- Owns a bunker storage terminal on the Pulau Sebarok Island with storage capacity
of 1.4 million barrels
These three refineries have a combined storage capacity of 88 million barrels.
Singapore's three largest independent storage operators—Vopak, Oiltanking, and Tankstore—
have been using 90% of their combined total capacity of 22.3 million barrels in the past 5 years.
Production plans are underway that, when complete, will almost triple the storage capacity of
local operators (EIA, 2005e).
Although refining has a strong presence in Singapore, imports of refined petroleum
products equaled $12.6 billion (11.4% of national GDP) (SMTI, 2005). Consumption of
imported oil products reached 750,000 bpd in 2004 (EIA, 2005e). The Singapore bunker fuel
market is very diverse; fuel from all major refineries around the world gets delivered to the port.
Even though no numerical data are readily available, based on qualitative assessments, the
majority of these world imports come from Venezuela, Chile, and Russia (Bunkerworld, 2005d).
2.3.1.2 Bunker Traders
Bunker traders secure bunker volumes for their shipping clients in local supply markets
or in their own refined-products distribution channels. Traders include both major oil companies
as well as independents. Both types perform the functional service in the timely procurement of
bunker fuel orders. Traders act as midway between local customers and refinery suppliers, where
the majority of transactions occur under long-term contracts.
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Twenty-three companies serve as traders in the Singapore shipping market.2 Among them
are smaller local companies such as Bunker House Petroleum, as well as larger international oil
companies such as Lukoil and OW Bunker. Among the leaders are OW Bunker and Hin Leong,
the latter of which recently scheduled construction of the largest petroleum terminal in the area
with total storage capacity of 14.5 million barrels.
2.3.1.3 Bunker Suppliers
Thirty-four companies serve as bunker suppliers, with an additional 18 that perform
functions of suppliers and traders. Three refinery operators are also among the top four suppliers
(British Petroleum, Shell, and ExxonMobil). They are joined by Global Energy Trading, a
smaller company that owns and operates 14 vessels at the port. Other large suppliers include
Consort Bunkers, Singapore Petroleum Company, Chevron Singapore, OW Bunker, and
Chemoil (SMP, 2006).
2.3.1.4 Barge Operators
Singapore has 32 independent barge operators. The bunker barge fleet contained
approximately 120 vessels of various sizes in 2005 (Bunkerworld, 2005e). The largest among the
barge operators is Ocean Tankers, a sister company of Hin Leong, which owns and operates 70
bunker barges.
2.3.2 Rotterdam
Rotterdam is the second largest port in the world with throughput of more than 369
million tons of cargo in 2005 (Port Authority of Rotterdam, 2005). Some 30,000 ocean-going
ships call at the port every year and 110,000 to 120,000 inland vessels. Activities related to the
port contribute around 12% of the Netherlands' GDP (Bunkerworld, 2000). Overall, the port of
Rotterdam has experienced a 5% increase in cargo handling with the majority of growth coming
from container cargo, which had a 12% increase to 9.3 million TEUs between 2004 and 2005.
General cargo was up 7%, or 7 million tons, to a total of 110 million tons in 2005.
Rotterdam is the largest bunker port in Europe. Bunker turnover in 2004 for the port was
12.5 million cubic meters (m3). In 2002 and 2003, bunker turnover was 10.6 and 11.4 million m3,
: Consort Bunkers Pte Ltd, Searights Maritime Services Pte Ltd, Bunker House Petroleum Pte Ltd, Northwest
Resources Pte Ltd, Golden Island Diesel Oil Trading Pte Ltd, Lukoil Asia Pacific Pte Ltd, Alliance Oil Trading
Pte Ltd, Costank (S) Pte Ltd, Sentek Marine & Trading Pte Ltd, Lian Hoe Leong & Brothers Pte Ltd, Standard
Oil & Marine Services Pte Ltd, Panoil Petroleum Pte Ltd, Ocean Bunkering Services Pte Ltd (owned by Hin
Leong Marine International Pte Ltd), O. W. Bunker Far East Pte Ltd, The Barrel Oil Pte Ltd, Fratelli Cosulich
Bunkers (S) Pte Ltd, Prestige Marine Services Pte Ltd, Gas Trade (S) Pte Ltd, Wired Bunkering Pte Ltd, Cockett
Marine Oil (Asia) Pte Ltd, Ignition Point Pte Ltd, Prospeibiz Petroleum (S) Pte Ltd.
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respectively (Port Authority of Rotterdam, 2004a). These volumes include IFO, MGO, MDO,
and lube oils (IFO represents the majority of overall bunker turnover). Russian oil imports
represent a significant share of total refined oil product supply. Between 2002 and 2003, Russian
imports of crude and refined oil products grew by 17% (Port Authority of Rotterdam, 2004b).
2.3.2.1 Refineries
In 2004, oil refineries represented 6.5% of the 58,000 workers directly employed at the
Port. However, because of environmental regulations and European fuel market conditions,
refineries in the region around Rotterdam produce less of the heavy fuel oil that typically
dominates bunker markets (3% to 3.5% sulfur). Consequently, the local refinery output can no
longer cover the Rotterdam bunker demand. This shortage has led to increased reliance on fuel
oil from import sources. Fuel oil imports are estimated to be 300,000 to 400,000 metric tons per
day.
The local refineries that still produce bunkers sold on the Rotterdam market include the
following:
• The Pernis Refinery, owned by Royal Dutch/Shell
— Capacity approximately 416,000 b/d.
• NEREFCO (Netherlands Refining Co.), owned by BP (69%) and Texaco (31%)
- Capacity in excess of 380,000 b/d.
• Q-8 refinery, owned by Kuwait Petroleum Corporation
- Capacity about 75,500 b/d.
• The Esso Refinery (ExxonMobil) does not produce fuel oil, but the company sources
from a plant in Antwerp, Belgium, with capacity of 225,000 b/d.
2.3.2.2 Bunker Traders
Traders in the Rotterdam market include oil majors, such as Shell Marine Products and
Lukoil. Shell Marine Products uses the majority of its Pernis refinery's marine fuel output for its
own clients (Bunkerworld, 2000), while the majority of NEREFCO's output is purchased by
independent traders in the local fuel-barge market.
Independents typically purchase their bunker fuel on the local barge market. In addition,
it is common for traders to import cargos of bunker fuel and store the fuel in rented storage tanks
in the petroleum zones of the port. Vitol, Allround Fuel Trading/Chemoil, and the oil majors,
especially Texaco, BP, and Elf (TotalFinaElf), are the largest bunker traders of imported oil
products (Bunkerworld, 2000).
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2.3.2.3 Bunker Suppliers
Physical supplying of bunker fuel to ships is conducted by barge in the bunkering
designated zones. Europort and Botlek areas are two primary bunkering areas within the port of
Rotterdam. In 2000, over 90% of the bunkers in Rotterdam were delivered by barge
(Bunkerworld, 2000).
Barges are loaded at various fuel-terminal facilities owned by Vopak and the oil majors.
Most suppliers, including the oil majors, do not own or operate their own barges. Most majors
and some independents have specially dedicated barges or barges on exclusive time charter.
Among many independents, it is common practice to pool barge transportation services
(Bunkerworld, 2000).
Because of the nature of physically supplying bunkers, large storage capacity is needed to
enable flexibility in the suppliers' ability to respond to sudden fluctuations in bunker demand.
The most recent example of traders enlarging storage capacity is the partnership of Lukoil and
Fuel Transport Services (FTS)/Hofftrans (a local barge operator) partnering to build a bulk
terminal named the Service Terminal Rotterdam (STR). STR is designed for better bunkering
and ship-ship transhipment. This expansion is estimated to increase total storage capacity to
120,000 m3. Another expansion is currently under way by the Vitol Group, which is constructing
a 278,000 m3 storage tank terminal in the Europort area. The Vitol facility is expected to begin
operations in 2006 and will provide jetties capable of accommodating vessels ranging between
bunker barges and very large crude oil carriers (VLCCs).
2.3.2.4 Barge Operators
The largest barge operator is VT/Unilloyd, which works exclusively in transportation and
owns more than 20 barges. FTS/Hoftrans has around 10 barges of up to 2,000metric tons (mt)
capacity. A group of companies, which includes the suppliers Atlantic/Postoils, operates their
own fleet of 21 barges ranging from 300 to 3,900 mt capacity. These barges also deliver on
behalf of other suppliers (Bunkerworld, 2000).
Additionally, some suppliers own their own fleet of barges. One example is Argos
Bunkers BV, which has its own fleet of six barges ranging from 200 to 1,400 mt capacity, plus
the company charters three more barges ranging from 700 to 2,000 mt. Ceetrans/Ceebunker
Services BV is owned by Argos and has access to the same barges. Frisol Bunkering BV has
three time-chartered barges totaling 4,270 mt in capacity. NIOC (Netherlands Independent Oil
Co.) has access to the 23-strong barge fleet of its Belgian parent company, Wiljo Bunkering NV
(Bunkerworld, 2000).
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2.3.3 Fujairah
Fujairah is the third largest bunkering port in the world, supplying over 12 million mt of
bunker fuel annually (Gulf News, 2006). The Fujairah bunker market comprises three port areas,
which include the United Arab Emirates (UAE) ports of Khor Fakkan, Fujairah, and Kalba.
Fujairah is situated in the middle of these three ports, with Khor Fakkan to the north. The three
ports and their offshore counterpart in the Gulf of Oman constitute "the Fujairah bunker market."
Although there are some local differences, unless otherwise stated, "Fujairah" is seen as
incorporating the entire area (Bunkerworld, 2002). Fujairah is located in the outer Gulf, just
outside the Straits of Hormuz, which are the gateway to the Arabian Gulf. Because of Fujairah's
proximity to Middle Eastern oil production, Fujairah's bunker customers are predominantly
VLCCs, which are often anchored in the Gulf of Oman waiting for cargo in the inner Gulf.
Although official data regarding the turnover of bunker fuel in the Fujairah market are
not available, industry experts have estimated the annual volume to be over 12 million mt in
2002, with an average monthly supply volume of 1 million mt. Because tankers are the major
customers in the Fujairah market, large bunkers rather than numerous small deliveries are the
norm. The average supply volume varies between 2,000 mt to 15,000 mt (Bunkerworld, 2002).
Assuming an average volume per vessel, this implies that approximately 120,000 bunkering
transactions take place in the Fujairah market each year.
Several estimates exist regarding the market share of each bunker fuel grade. IFO 380 is
estimated to account for between 80% and 95% of total bunkers supplied. The remaining 5% to
20% are split between IFO 180 and MGO, but exact shares are not available. Typically, Fujairah
is host to the most competitive pricing of bunker fuel in the Arabian Gulf. However, the price
differences between IFO380 and IFO 180 grades in Fujairah are typically higher than those found
in Singapore or Rotterdam (Bunkerworld, 2002). The significant price difference between
IFO380 and IFO 180 is due to a lack of cheap cutter stock typically used in blending to create
lighter fuel grades in the Arabian Gulf. As a result, Fujairah's bunker suppliers are forced to use
MGO in blending activities, making purchasing lighter grades of residual fuel such as IFO 180
less attractive in the Fujairah market (Bunkerworld, 2002).
2.3.3.1 Refineries
Fujairah itself has only one refinery facility—the Fujairah Refinery Company (FRC)
(Nakamura, 2005). The FRC plays a vital role in supplying straight-run fuel oil to the Fujairah
bunker market. Metro Oil Corporation ran the facility until the late 1990s when it was shutdown.
The FAL Energy Company took over the facility in 2004 to use its 460,000 m3 of storage
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capacity (Nakamura, 2005). The Fujairah government in 2005 announced a desire to revitalize
the facility and update processing technologies. Currently, the FRC refinery does not contribute a
huge amount of bunkers to the local market.
The Abu Dhabi National Oil Company (ADNOC) operates two refineries in the UAE,
including the Umm Al Nar and Ruwais refineries. These two refineries produce over 23 million
mt of products annually, which are sold to both international and local markets (Bunkerworld,
2002). The Umm Al Nar refinery processes 150,000 bpd of crude oil, and the Ruwais refinery
has two units with a total design capacity of 350,000 bpd. The Emirates National Oil Company
Limited (ENOC) operates the 120,000 bpd Jebel Ali plant (Nakamura, 2005).
Other refineries located near Fujairah cover 14 major refineries and include Bahrain
National Oil Company's refinery, Aramco's five Saudi refineries, the National Iranian Oil
Company's (NIOC) six refineries in Iran, and Kuwait Petroleum Corporation's (KPC) three
Kuwaiti plants (Nakamura, 2005; Bunkerworld, 2002).
2.3.3.2 Bunker Traders
Bunker traders arrange supply deliveries in the Fujairah bunker market. These firms
provide services that ensure that bunker supplies are available and delivered in a timely fashion.
The Fujairah bunker market is presently serviced by approximately 11 trading companies,
including FAL Energy Company, GAC Bunkers Co., and FAMM Middle East Ltd.
2.3.3.3 Bunker Suppliers
The offshore terminals in Fujairah make it an ideal bunkering stop-off for both inbound
and outbound tankers leaving the Gulf (Bunkerworld, 2002). Typical bunkering entails bunker
barges loading from storage tankers and supplying bunkers to passing vessel traffic that is
moving through the Straits of Hormuz between the Arabian Gulf and the Gulf of Oman.
Most suppliers import their products and then store bunkers in large tankers that reside in
the Gulf or in shore-based fuel terminals. The majority of companies purchase product from
refineries in the UAE or other regional refineries. The port of Fujairah is serviced by 20
suppliers, representing a mix of local businesses as well as international bunker suppliers such as
German-based Bominflot and BP Marine Middle East located in Dubai, UAE.
EPPCO International, a joint venture between ENOC and Caltex, owns and operates
some of the largest refined-petroleum terminalling facilities in the UAE. The terminals are
spread between Jebel Ali and Fujairah and represent 6.44 million barrels in storage capacity. In
2-23
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2002, Vopak ENOC Fujairah Terminal Company had 30 tanks (10 tanks designed to handle fuel
oil) with a total capacity of 1 million m3 storing fuel oil, gas oil, gasoline, naphtha, and jet
kerosene. The Vopak terminal offers products to the local market via three berths capable of
accommodating vessels up to 175,000 dead weight tons (dwt) (Bluewater, 2002). Additional
capacities are designed to serve the active fuel-oil market offshore, whether for cargo trading or
for bunkering purposes.
Other examples of suppliers in the Fujairah market include FAL and EPPOC. The longest
established bunker company in the UAE is FAL Energy Company, which leases storage capacity
at the FRC and has 24 tanks with a combined capacity of 422,000 cubic meters storing fuel oil,
gas oil, naphtha, and jet kerosene. Finally, the Emirates Petroleum Products Co. (Eppco), a
subsidiary of ENOC, expanded its existing storage capacity from 100,000 m3 to over 150,000 m3
in 2003. These investments in supplier infrastructure indicate the growing importance of this
bunker market.
2.3.3.4 Barge Operators
The Fujairah market is largely served through off-shore deliveries by barge. For this
reason, many suppliers operate their own barge fleet in the Gulf of Oman. In addition, eight
independent barge operators offer service. The FAL Energy Company has a number of
bunkering vessels operating in both the Arabian Gulf and the Gulf of Oman. Larger international
suppliers such as ExxonMobile's Marine Fuels (EMMF) Company often contract with
independent barge operators in the Fujairah market, following detailed certification by EMMF
(EMMF, 2006).
2.3.4 Houston
The Port of Houston ranks second in U.S. foreign waterborne commerce and total
tonnage. In 2004, 6,539 ships called at Houston where traffic is dominated by container ships,
tankers, and bulk carriers.
Houston is a mix of private and public terminals. The areas controlled by the Port of
Houston Authority can be divided into four main areas:
• the City Dock, also called the Turning Basin
• Barbours Cut Terminal, the main terminal for containers ( 940,000 TEUs in 1996)
• Jacintoport Terminal, a general cargo handling port
• Woodhouse Terminal, for ro-ro cargo vessels
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Development of a new container terminal is now in the design stage at the Port. It is intended to
alleviate pressure at the Barbours Cut Terminal, which was forecast to pass one million TEUs by
1998.
2.3.4.1 Refineries
Several refineries are located near the port, including ExxonMobil's Baytown Refinery,
BP's Texas City Refinery, Marathon Ashland's Texas City, and the Valero Refinery. While these
refineries represent a significant share of the U.S. capacity in refined products, they do not
produce marine fuels. Typically, marine fuel is imported from countries in the western
hemisphere where refinery production of heavy fuel oil is greater than in the United States. As
such, most marine fuels imports are sourced from Venezuela, Aruba, and Mexico.
2.3.4.2 Bunker Traders
Iso Industry Fuels and Chemoil Corporation are two bunker traders associated with the
Port of Houston bunker market. In addition, several international trading groups conduct
transactions in Houston.
2.3.4.3 Bunker Suppliers
Between 6 and 15 major suppliers operate in the Houston Port area, though major
suppliers like Shell Marine Products, Valero Marketing and Supply Co., Chemoil Corp., BP
Marine Fuels, and Bominflot Atlantic LLC dominate.
In addition several smaller suppliers have storage terminals in or near the port area and
operate barge delivery services. Houston Marine Services and Midstream Fuel Services operate
storage terminals, bunker supply vessels, and fleets of barges along the Gulf Coast. Matrix
Marine Fuels, Enjet, and Difco Fuel Systems are examples of smaller suppliers in the Houston
bunkering market. Suncoast Resources delivers primarily by truck at local berths, supplied by a
network of fuel terminals in the Houston area (Bunkerworld, 2000).
2.3.4.4 Barge Operators
Currently, only very limited information is available on the barge market in Houston.
Most existing barge operations appear to be conducted by local suppliers.
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SECTION 3
DEMAND FOR BUNKER FUELS IN THE MARINE INDUSTRY
This section discusses the demand side of the marine fuels market. The analysis of
current and expected future shipping activity in this section is used to estimate regional and
worldwide projections of future marine bunkers demand through the year 2020. These
consumption forecasts then provide a baseline for the WORLD model, against which the
shipping industry's possible response to the adoption of a U.S. or North American SECA
regulation could be evaluated.
3.1 Summary of the Modeling Approach
In general, the approach used to estimate marine bunker fuel use can be described as an
"activity-based" approach with a focus on the international cargo vessels that represent the
majority of fuel consumption. Components of the estimation include
• identifying maj or trade routes,
• estimating volumes of cargo of various types on each route,
• identifying types of ships serving those routes and carrying those cargoes,
• characterizing types of engines used by those ships, and
• identifying the types and estimated quantities of fuels used by those engines.
Implementing this approach involves combining information from a variety of sources:
data on the existing fleet of shipping vessels from Clarksons (2005), information from Corbett
and Wang (2005) and various industry sources on engine characteristics, and projections of
future global trade flows from Global Insights (2005). The data on vessels and engines provide a
characterization of fuel use associated with delivering a particular load of cargo, and the data on
trade flows control how many times, and over what distances, these loads have to be delivered.
Estimating fuel consumption through an activity-based methodology that combines data
on specific vessels with data on engine characteristics is similar to the approaches used in
Corbett and Koehler (2003, 2004), Koehler (2003), Corbett and Wang (2005), and Gregory
(2006). The approach in this report extends previous analyses by linking these ship data to
projections of worldwide trade flows to determine the total number of trips undertaken in each
year, and hence fuel use, rather than using estimates of the number of hours a ship/engine
typically runs in a year.
3-1
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Accordingly, the model developed in this section estimates fuel consumption based on an
underlying economic model's projections of international trade by commodity category (Global
Insights, 2005). Demand for marine fuels is derived from the demand for transportation of
various types of cargoes by ship, which, in turn, is derived from the demand for commodities
that are produced in one region of the world and consumed in another. The flow of commodities
is matched with typical vessels for that trade (characterized according to size, engine
horsepower, age, specific fuel oil consumption, and engine load factors). Next, typical voyage
parameters are assigned, including average ship speed, round-trip mileage, tons of cargo shipped,
and days in port. Fuel consumption for each trade route and commodity type thus depends on
commodity projections, ship characteristics, and voyage characteristics.
Figure 3-1 illustrates the broad steps involved in developing baseline projections of
marine fuel consumption. It is a multistep process that relies on data and forecasts from
numerous sources, some of which are listed above, to inform the projections. The flow chart in
the figure illustrates the relationships to be profiled in characterizing baseline marine fuel
consumption by cargo vessels.
Also, although the focus of this analysis of bunker fuel forecasts is on projecting use by
vessels carrying cargo among international ports, it includes other vessel types when estimating
total demand for bunker fuels, as discussed below. These vessel types include passenger vessels
such as ferries and cruise ships, service vessels such as tugs and offshore supply vessels (OSV),
and military vessels.
3.2 Methods of Forecasting Bunker Fuel Consumption
Underlying the projections of bunker fuel consumption by cargo vessels worldwide are
projected flows of commodities between regions of the world. These are commodities produced
in one region of the world and demanded in another.
3.2.1 Composite Commodities and Regions
The first step in analyzing trade flows was examining the relevant composite
commodities and obtaining forecasts for them, which are based on the following categories:
• liquid bulk—crude oil
• liquid bulk—refined petroleum products
• liquid bulk—residual petroleum products
• liquid bulk—chemicals (organic and inorganic)
• liquid bulk—gas (including LNG and LPG)
3-2
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Ship Analysis: by Vessel Type and Size Category
Inputs Outputs
Deadweight for all Vessels of
Given Type & Size3
Horsepower, Year of Build
for all Vessels of Given
Type & Size3
Specific Fuel Consumption
(g/SHP-HR) by Year of Build"
Engine Load Factors0
Average Cargo ^A^l
Carried (Tons) \^^J
Average Daily Fuel
Consumption
(Tons/Day)
Average Daily Fuel
Consumption (Tons/Day) f^~cT\
- Main, Aux. Engine at Sea \^__^J
-Aux. Engine in Port
Trade Analysis: by Commodity and Trade Route
Inputs
Average Ship Speed0
Round Trip Mileaged
Tons of Cargo Shipped6
Average Cargo Camed/^~\
per Ship Voyage \/V/
Outputs
Days at Sea and in
Port, per Voyage
Total Days at f^c^]
Sea and in Port V J
Number of Voyages
Total Estimated Bunker Fuel Demand
f ^\
Average Daily Fuel Consumption
(Tons/Day) Total Days at Sea Bunker Fuel
- Main, Aux. Engine at Sea f~^\ and in Port f^\ Demand
- Aux. Engine in Port \_/ \^^J
Driven by changes in engine efficiency. Driven b* 3mwth in
commodity flows.
a - Clarksons Ship Register Database
b-Engine Manufacturers' Data, Technical Papers
c - Corbett and Wang (2005) "Emission Inventory Review: SECA Inventory Progress Discussion"
d - Combined trade routes and heavy leg analysis
e —Global Insight Inc. (Gil) Trade Flow Projections
Figure 3-1. Method for Estimating Bunker Fuel Demand
dry bulk (e.g., grain, coal, steel, ores, and scrap)
general cargo (including neobulk, lumber/forest products)
containerizable cargo
3-3
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Next, countries of the world were grouped into approximately 20 larger regions. Table
3-1 shows the mapping of countries to regions. From Global Insight, Inc. (Gil) World Trade
Service, a specialized forecast was obtained that reports flows of each commodity among regions
for the period 1995-2024. GIFs forecast of shipments of these commodities among these regions
drives the overall forecast of demand for shipping services and thus for marine fuels.
Gil is a widely recognized macroeconomic forecasting firm. The Gil World Trade
Service provides annual macroeconometric analysis and forecasts of economic activity and trade
for over 200 individual countries and for the global economy. Gil provides integrated analyses
and forecasts for individual countries and regions of the world and for the world economy as a
whole, including an analysis of the relationship of each region's economy to the world economy.
To facilitate integration of the fuel demand analysis with the fuel supply analysis, Gil grouped its
countries and regions into aggregate regions comparable to those used in EnSys Energy's
WORLD model. The aggregate regions and associated source countries/regions are shown in
Table 3-1.
The Gil World Trade Forecasting Model is a nonlinear multistage econometric switch
model (Gil, 2005). It uses several data sources, economic theory, and multistage modeling linked
by top-down control adjustment to capture and project commodity flows in the world. No single
data source provides a complete baseline picture of international trade. Gil bases their model on
UN historical international trade data (published by Statistics Canada). These data are
supplemented with OECD International Trade by Commodity Statistics to reflect more realistic
data for developing countries, and the U.S. Customs and IMF Direction of Trade data to calibrate
and enhance historical commodity trade flows. Additional macroeconomic data (such as
population, GDP, GDP deflators, industrial output, foreign exchange rates, and export prices by
country) and geographical distances are used as exogenous variables.
The general structure of the model for calculating trade flows assumes a country's
imports from another country are driven by the importing country's demand forces (given that
the exporting country possesses enough supply capacity), and affected by the exporting country's
export price and importing country's import cost for the commodity. Gil then estimates demand
forces, country-specific exporting capacities, export prices, and import costs. To arrive at each
country's trade with each of its trading partners, nonlinear multistage switch modeling is
required.
3-4
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Table 3-1. Aggregate Regions and Associated Countries
Aggregate Regions
Containing Gil Base Countries/Regions
U.S. Atlantic Coast
U.S. Great Lakes
U.S. Gulf Coast
E. Canada3
W. Canada3
U.S. Pacific North
U.S. Pacific South
Greater Caribbean
South America
Africa - West
Africa-North/East-
Mediterranean
Africa-East/South
Europe-North
Europe-South
Europe-East
Caspian Region
Russia/FSU
Middle East Gulf
Australia/NZ
Japan
Pacific-High Growth
China
Rest of Asia
U.S. Atlantic Coast
U.S. Great Lakes
U.S. Gulf Coast
Canada3
Canada3
U.S. Pacific North
U.S. Pacific South
Colombia, Mexico, Venezuela, Caribbean Basin, Central America
Argentina, Brazil, Chile, Peru, Other East and West Coast of S. America
Western Africa
Mediterranean Northern Africa, Egypt, Israel
Kenya, Other Eastern Africa, South Africa, Other Southern Africa
Austria, Belgium, Denmark, Finland, France, Germany, Ireland, Netherlands, Norway,
Sweden, Switzerland, United Kingdom
Greece, Italy, Portugal, Spain, Turkey, Other Europe
Bulgaria, Czech Republic, Hungary, Poland, Romania, Slovak Republic
Southeast CIS
The Baltic States, Russia Federation, Other Western CIS
Jordan, Saudi Arabia, UAE, Other Persian Gulf
Australia, New Zealand
Japan
Hong Kong S.A.R., Indonesia, Malaysia, Philippines, Singapore, South Korea, Taiwan,
Thailand
China
Viet Nam, India, Pakistan, Other Indian subcontinent
Canada is treated as a single destination in the Gil base model. Shares of Canadian imports from and
exports to regions of the world in 2004 are used to divide Canada trade into shipments to/from Eastern
Canada ports and shipments to/from Western Canada ports (Transport Canada, 2004).
Switch models are not continuous functions. Thus, they cannot be estimated using
conventional derivative methods; a direct search method is used instead. Although uncommon
for economics, this method is widely used in other scientific fields. A direct search method
3-5
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estimates switch functions, while allowing one to define error minimization functions and set
boundaries for model parameters. GIFs approach to forecasting is unorthodox as well. Gil
contends that the three commonly used approaches—bottom-up, top-down, and manual (hybrid)
approach—fail because of their limitations.1 Gil uses a system that could be referred to as a
controlled top-down approach.
Gil defines four levels, with the bottom level being the most detailed: commodity flows
between each pair of countries/regions. The third level is how much of each commodity each
country exports/imports from the world. The second level is the total commodity flows that each
country exports/imports from the world, and the first level is world trade of total commodities.
The second, third, and fourth levels have their own behavioral equations, but individual forecasts
at the lower levels are forecast under the constraint of their aggregate forecast at the higher level.
Thus, if there is a discrepancy between the sum of individual forecasts and aggregate forecasts,
the program identifies the items that could be adjusted and adjusts them step by step to eliminate
the discrepancy.
GIFs output for this project included detailed annual region-to-region trade flows for
eight composite commodities, for the period 1995 to 2024. The projections for 2012 and 2020
are shown, along with baseline data for 2005, in Table 3-2. In 2005, dry bulk accounted for 41%
of the total trade volume. Crude oil accounted for 28%, and containers accounted for 12%. Dry
bulk and crude oil shipments grow more slowly over the forecast period than do container
shipments; by 2020, dry bulk is 39% of the total, crude oil is 26%, and containers have risen to
17%.
3.2.2 Ship Analysis by Vessel Type and Size
Different types of vessels are required to transport these different commodities to the
various regions of the world. Profiles of these vessels were developed to provide a
characterization of ships assigned to transport commodities of each type along each route. These
profiles analyze data provided by the Clarksons Ship Register (Clarksons, 2005) on size,
horsepower, age, and engine fuel efficiency to identify typical vessels of each overall vessel type
and each size category. The main purpose of the analysis is to determine the average amount of
cargo carried by an average daily fuel consumption of each vessel type.
1 The bottom-up approach forbids forecasted items to be subject to total resource constraints or equilibrium. For
example, this approach would disallow the possibility of a country's import limitations due to an income
constraint. The top-down approach requires forecasted items to have identical dynamic patterns. However, the
historical data reveal it is rare to find that a country's imports of a commodity from two different countries
exhibit identical dynamic patterns. The hybrid method solves the problems of the latter two but is very time
consuming.
3-6
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Table 3-2. World Trade Estimates for Composite Commodities, 2005, 2012, and 2020
Commodity Type
Dry bulk
Grade oil
Container
Refined petroleum
General cargo
Residual petroleum and other liquids
Chemicals
Natural gas
Total international cargo demand
2005
(in million tons)
2,473
1,703
714
416
281
190
122
79
5,979
2012
(in million tons)
3,051
2,011
1,048
471
363
213
175
91
7,426
2020
(in million tons)
3,453
2,243
1,517
510
452
223
228
105
8,737
First, the eight Gil commodity categories were mapped to the type of vessel that would
be used to transport them. These assignments appear in Table 3-3.
Table 3-3. Assignment of Commodities to Vessel Types
Gil Commodity Ship Category "Type" Defined in Clarksons Register"
Liquid bulk—crude oil Grade oil tankers Tanker
Liquid bulk—refined _ , ^ , _ , ^
, , Product tankers Product earner
petroleum products
Liquid bulk—residual _ , , _ ,
? , , „ Product tankers Product earner
petroleum products
Liquid bulk—chemicals „, . ,, , ™ • ,_,-,
, . , . . . Chemical tankers Chemical and oil earner
(organic and inorganic)
T ' 'H h Ik ti LNG carrier, LPG carrier, chemical & LPG carrier, ethylene/LPG,
.. , ,. T11T,, , T „„. Gas carriers ethylene/LPG/chemical, LNG/ethylene/LPG, LNG/regasification,
(including LNG and LPG) T nrv u • i T nrv -i -i P r -^
to LPG/chemical, LPG/oil, oil & liquid gas earner
Dry bulk (e.g. grain, coal, .
. , j I Dry bulk earners Bulk earner
steel, ores and scrap)
„ , ,. , ,. General cargo liner, reefer, general cargo tramp, reefer fish carrier,
General cargo (including ° ' f • ^, f m t i
,„,,.,, ^ „ , ro-ro, reefer/container, ro-ro freight/passenger, reefer/fleet replen.,
neobulk, lumber/forest General cargo . . - ' , ,7 1 ^ , «
, ^ . ro-ro/contamer, reefer/general cargo, ro-ro/lo-lo, reefer/pallets
products) . f i i f i
earner, reefer/pass./ro-ro, reefer/ro-ro cargo
Containerizable cargo Container ships Fully cellular container
a Vessel operators self-report these types to Clarksons Research Services for inclusion in their shipping databases.
3-7
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Each of these vessel types was further classified by size in deadweight tons (DWT).
Appropriate size categories were identified based on both industry definitions and natural size
breaks within the data. Table 3-4 summarizes these subcategories and provides other information
on the general characteristics of vessels represented in the Clarksons' data. The size descriptions
imply the size limitations as defined by canals or straits through which ships of that size can
pass. Crude oil tankers (VLCC) are the largest by DWT; the largest container ships (Suezmax)
are also very large. For each ship type and size category, data on typical ships' capacity in DWT,
speed, and horsepower are used to estimate average daily fuel consumption.
Table 3-4. Fleet Characteristics in Clarksons' Data
Ship Type
Container
General cargo
Dry bulk
Crude oil tanker
Chemical tanker
Size by DWT
Suezmax
PostPanamax
Panamax
Intermediate
Feeder
All
Capesize
Panamax
Handymax
Handy
VLCC
Suezmax
AFRAmax
Panamax
Handymax
Coastal
All
Minimum
Size (DWT)
83,000
56,500
42,100
14,000
0
Maximum
Size
(DWT)
140,000
83,000
56,500
42,100
14,000
All
79,000
54,000
40,000
0
180,000
120,000
75,000
43,000
27,000
0
0
79,000
54,000
40,000
0
180,000
120,000
75,000
43,000
27,000
All
Number
of Ships
101
465
375
1,507
1,100
3,214
715
1,287
991
2,155
470
268
511
164
100
377
2,391
Total DWT
(millions)
9.83
30.96
18.04
39.80
8.84
26.65
114.22
90.17
46.50
58.09
136.75
40.63
51.83
10.32
3.45
3.85
38.80
Total Horse-
power
(millions)
8.56
29.30
15.04
32.38
7.91
27.07
13.81
16.71
10.69
19.58
15.29
5.82
8.58
2.17
1.13
1.98
15.54
(continued)
3-8
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Table 3-4. Fleet Characteristics in Clarksons' Data (continued)
Ship Type
Petroleum product
tanker
Natural gas carrier
Other
Total
Size by DWT
AFRAmax
Panamax
Handy
Coastal
VLGC
LGC
Midsize
All
Minimum
Size (DWT)
68,000
40,000
27,000
0
60,000
35,000
0
Maximum
Size
(DWT)
0
68,000
40,000
27,000
0
60,000
35,000
All
Number
of Ships
226
352
236
349
157
140
863
7,675
26,189
Total DWT
(millions)
19.94
16.92
7.90
3.15
11.57
6.88
4.79
88.51
888.40
Total Horse-
power
(millions)
3.60
4.19
2.56
1.54
5.63
2.55
3.74
53.60
308.96
Source: Authors' calculations based on data from Clarksons Ship Register (2005).
3.2.2.1 Fleet Average Daily Fuel Consumption
Average fuel consumption for each vessel type and size category was estimated in a
multistep process using individual vessel data on engine characteristics. Clarksons' Ship Register
provides each ship's horsepower (HP), type of propulsion (diesel or steam), and year of build.
These characteristics are then matched to information on typical Specific Fuel Oil Consumption
(SFOC) from engine manufacturers and the technical literature. SFOC is measured in grams of
fuel burned per horsepower-hour, so to determine the average daily fuel consumption of the fleet,
the following equation is used:
Fleet AFC =--
SFOC , x HP, x
24
1,000,000
(3.1)
where / denotes an individual ship of vessel type v and size category s. This calculation results in
a fleet average value for daily fuel consumption, measured in metric tons per day.
3.2.2.2 Key Assumptions Affecting the Forecast
The specific SFOC numbers used for this analysis are based on historical data provided
by Wartsila Sulzer, a popular manufacturer of diesel engines for marine vessels. An additional
10% has been added to their "test bed" or "catalogue" numbers to account for the guaranteed
3-9
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tolerance level and an in-service SFOC differential.2 Figure 3-2 shows data used in the model
regarding the evolution of SFOC rates for diesel engines over time. (For steam engines, a fixed
SFOC of 220 g/HP-hr is used.)
200
180
160
140
120
I 100
O
80
o
£
(S 60
'3
8.
vi 40
20
0
1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020
Figure 3-2. Specific Fuel Oil Consumption Over Time
Source: Authors' calculations based on communications with Wartsila Sulzer and other diesel engine manufacturers.
Engine efficiency in terms of SFOC has improved over time, most noticeably in the early
1980s in response to rising fuel prices. However, there is a trade-off between improving fuel
efficiency and reducing emissions. Conversations with engine manufacturers indicate that it is
reasonable to assume SFOC will remain constant for the 15-year time horizon of this study,
particularly as they focus on meeting more stringent NOX emissions requirements, such as those
imposed by MARPOL Annex VI.
! Overall this 10% estimate is consistent with other analyses that show variation between the "test bed" SFOC
values reported in manufacturers' product catalogues and the actual SFOCs observed in service. The difference is
explained by the fact that old, used engines consume more than brand new engines and that fuels used in-service
may be different than the test bed ISO fuels. See Koehler (2003).
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The values for fleet average daily fuel consumption calculated in Equation (3.1) are based
on installed horsepower; therefore, they must be scaled down to reflect true engine loads. Engine
load factors reported by Corbett and Wang (2005) are used to estimate average daily fuel
consumption (tons/day) for the propulsion engine and auxiliary engines, both at sea and in port.
These assumptions are summarized in Table 3-5.
Table 3-5. Assumptions Regarding Engine Loads
Vessel Type
Container vessels
General cargo carriers
Dry bulk carriers
Crude oil tankers
Chemical tankers
Petroleum product tankers
Natural gas carrier
Other
Main Engine
Load Factor
80%
80%
75%
75%
75%
75%
75%
70%
Auxiliary Engine as
Percentage of Main
Engine
22.0 %
19.1%
22.2 %
21.1%
21.1%
21.1%
21.1%
20.0 %
Auxiliary Engine as
of Main Engine
11.0%
9.5 %
11.1%
10.6 %
10.6 %
10.6 %
10.6 %
10.0 %
Percentage
at Sea
Source: Corbett, James and Chengfeng Wang. October 26, 2005. "Emission Inventory Review SECA Inventory
Progress Discussion." page 11.
3.2.2.3 Changing Fleet Characteristics
The population of vessels operating is assumed to change over time as older vessels are
scrapped and new ones are built. In our analysis, vessels built over 25 years ago are retired and
are assumed to be replaced by new ships of the most up-to-date configuration. Specifically, these
ships are assumed to have a new engine (rated at the current SFOC) and are assumed to weigh as
much as the average ship built in 2005. So even though improvements in SFOC over the next
15 years are not assumed, the fuel efficiency of the fleet as a whole is expected to improve over
time through retirement and replacement. In the same way, even though specific increases in the
size of ships being built are not projected, the total deadweight of the fleet will increase over
time as smaller ships retire and are replaced. The analysis also reflects trends on the trade routes
between Asia and North America or Europe for container ships to increase in size over time.
3.2.3 Trade Analysis by Commodity Type and Trade Route
Based on information from Navigistics Consulting, the distribution of ship size categories
deployed on each of the trade routes was identified. For example, to serve the large crude oil
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trade from the Middle East Gulf region to the U.S. Gulf region, 98% of the deadweight tonnage
is carried on very large crude carriers (VLCCs), while the remaining 2% is carried on the smaller
Suezmax vessels. In addition to the volume of trade being moved, the limitations of the canals
through which the vessels must pass determine the size categories deployed on each trade route.
These size category distributions are assumed to remain constant throughout the forecast
horizon, with the exception of two of the largest container trade routes. We introduce Malacamax
containerships (>11,000 TEU) to Trans-Pacific trade per a recent container vessel forecast for the
ports of San Pedro Bay and at a similar rate to Europe-Asia trade (Mercator Transport Group,
2005).
Once a vessel type and size distribution have been assigned to each region pair and
commodity trade type, a set of voyage parameters is estimated. Days at sea and in port are based
primarily on ports called, sea distance, and ship speed. The number of voyages is based on the
cargo volume projected by Gil to move along a given route and the cargo capacity of the vessels
on that route.
3.2.3.1 Days at Sea and Days in Port
Most trades are characterized by voyages that are essentially round trips, moving from a
single region of origin to a single destination region and back.3 For these trades, Navigistics
Consulting identified ports that were either in the middle of the trade region or ports through
which the particular commodity was most likely to travel. For example, the Port of Singapore
was selected as the port of origin for the Pacific High-Growth region for most commodities, but
for dry bulk, Inchon was selected. Then, for each route, information was gathered on the
distances between ports (NGA, 2001; MaritimeChain, 2005).4 Since carriers of crude oil,
chemicals, petroleum products, natural gas, and dry bulk tend to travel full for a delivery and
then return empty, round-trip distances were used to determine the length of the voyage. The
days at sea are calculated by dividing the sea distance by the average vessel speed:
_^ n-n.tr round trip distance route
Days at Sea Per Voyagev „ route =
j j c? v,s,route * ^\ A i i ^/~\o
speedvsx 24x1.1508
3 Vessels may stop at multiple ports within each region, but we assume that, for the most part, they do not string
together trips to multiple regions. Two important exceptions to this are the general cargo and container trades,
which are described in further detail below.
4 http://maritimechain.com/. This calculator provides nautical distances, which account for the particular routes
vessels must take when traveling from port to port (e.g., movement through straights or canals).
3-12
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Table 3-6 presents the values used for speed by vessel type (based on Corbett and Wang [2005]).
These values are the same for all size categories and are assumed to remain constant over the
forecast period.
Table 3-6. Vessel Speed by Type
Vessel Type Speed (knots)
Grade oil tankers 13.2
Petroleum product tankers 13.2
Chemical tankers 13.2
Natural gas carriers 13.2
Dry bulk carriers 14.1
General cargo vessels 12.3
Container vessels 19.9a
Other 12.7
a Length of voyages by container ships estimated from additional sources. See below.
Source: Corbett, James and Chengfeng Wang. October 26, 2005. "Emission Inventory Review SECA Inventory
Progress Discussion." page 11.
In addition to calculating the average days at sea per voyage, the average days in port per
voyage are also estimated. It is assumed that most types of cargo vessels spend 4 days in port per
voyage; however, this can vary somewhat by commodity and by port.5 Tables 3-7 and 3-8 show
the results of these estimates of voyages lengths, focusing on U.S. trade routes. Table 3-7
presents average lengths across types of noncontainer vessels (these times are cargo specific and
vary slightly based on the speed of the vessels—speeds are taken from Dr. Corbett's work). Two
sources are used for noncontainer trades and voyage times in Table 3-7: Worldscale (2002) and
Maritime Chain (2005).
The Worldscale tables, based on underlying BP Shipping Marine Distance Tables, are the
industry standard for measuring port-to-port distances, particularly for tanker traffic. The
reported distances account for common routes through channels, canals, or straits. This distance
information was supplemented by data from Maritime Chain, a Web service that provides port-
to-port distances along with some information about which channels, canals, or straits must be
5 Some ports do not ran as efficiently because of a lack of good shoreside facilities, labor problems, or other
inadequacies. The maximum number of days in port for a noncontainer trade is 8 days.
3-13
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Table 3-7. Length of Voyages for Noncontainer Cargo Ships (approx. average)
Days per Voyage
Global Insights Trade Regions
Africa East-South
Africa North-Mediterranean
Africa West
Australia-New Zealand
Canada East
Canada West
Caspian Region
China
Europe Eastern
Europe Western-North
Europe Western-South
Greater Caribbean
Japan
Middle East Gulf
Pacific High Growth
Rest of Asia
Russia-FSU
Rest of South America
U.S. South
Pacific
68
49
56
48
37
11
95
41
61
53
54
26
35
77
52
68
64
51
U.S. North
Pacific
75
56
63
47
46
5
89
36
68
60
61
o o
55
31
72
48
64
71
30
U.S. East
Coast
57
37
36
65
7
40
41
73
38
24
30
16
65
56
67
66
38
41
U.S. Great
Lakes
62
43
46
81
18
58
46
87
45
32
37
29
81
65
76
64
46
46
U.S. Gulf
54
47
43
63
19
39
48
69
46
34
37
17
62
83
88
73
48
44
passed on the voyage. This distance information was then combined with Dr. Corbett's speed
parameters to determine the length of a voyage in days.
As discussed above, voyage times for container trade in Table 3-8 are based on information
from Containerization International (Degerlund, 2005) and calculations by Navigistics Consulting.
This resource provides voyage information for all major container services. Based on the frequency
of the service, number of vessels assigned to that service, and the number of days in operation per
year, the average length of voyages for the particular bilateral trade routes in the Global Insights
trade forecasts are estimated.
3-14
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Table 3-8. Length of Voyages for Container-Ship Trade Routes
Origin—Destination Regions Days per Voyage
Asia—North America (Pacific) 37
Europe—North America (Atlantic) 37
Mediterranean—North America 41
Australia/New Zealand—North America 61
South America—North America 48
Africa South—North America (Atlantic) 54
Africa West—North America (Atlantic) 43
Asia—North America (Atlantic) 68
Europe—North America (Pacific) 64
Africa South—North America (Pacific) 68
Africa West—North America (Pacific) 38
Caspian Region—North America (Atlantic) 42
Caspian Region—North America (Pacific) 38
Middle East/Gulf Region—North America (Atlantic) 63
Middle East/Gulf Region—North America (Pacific) 80
3.2.3.2 Number of Voyages
The number of voyages along each route for each trade was computed by dividing, for
each vessel type v and size category s serving a given route, the tons of cargo moved by the
estimated amount of cargo per voyage:
(3.3)
, -T7. tons cargo to move
Number of Voyagesv s trade =
Fleet Avg. DWTv s x (utilization rate)
The cargo per voyage is based on the fleet average ship size (in deadweight tons) calculated in
the vessel profile analysis. For most cargo trades, a utilization factor of 0.9 is assumed to account
for the fact that ships do not always run at full capacity. This factor is assumed to be constant
throughout the forecast period. Lowering this utilization factor would increase the estimated
number of voyages required to move the forecasted cargo volumes, which would, in turn,
increase our estimated fuel demand.
3-15
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3.2.3.3 Exceptions: General Cargo and Container Trades
The exceptions to the above approach for calculating voyage parameters are the general
cargo and container trades. These routes tend to have multiple stops, with cargo loaded and
discharged at each stop. Unlike the other types of vessels, these carriers rarely travel empty.
Thus, for each trade route, we focus only on the "heavy" leg of the journey, the direction with
the highest trade volume.
For general cargo, port-to-port round-trip distances and the average vessel speeds are
used to calculate days at sea. Days in port are estimated at 4 days per voyage. The difference is
that the number of voyages is based only on the tons of cargo projected to be moved on the
heavy leg of the journey. The assumption is that the projected trade volume associated with the
"light" leg will be carried on the return trip of these round-trip voyages.
For the container trades, the voyage parameters are determined based on actual ship
routings. Navigistics Consulting first identified major container trade lanes to which the
individual region pairs were assigned. For example, trade volumes from the Pacific High Growth
region to the U.S. South Pacific and from China to the U.S. North Pacific are both included on a
Transpacific trade route. Major shipping lines active on these trade routes are identified and their
individual container services are analyzed, as recorded in the Containerization International (CI)
Yearbook 2005 and other sources. The CI Yearbook provides detailed information about each
container service, including the ports visited, the frequency and length of the voyage, and the
vessels deployed. It is assumed there is 1 day in port for each port visited, and then the days at
sea are calculated by subtracting total days in port from the total length of the voyage.
The number of voyages for the container trade is again calculated by dividing the
projected volume on the heavy leg by the estimated average cargo per voyage (i.e., average ship
size times a utilization factor). We use the information from the CI Yearbook_about the vessels
deployed to determine the average ship size on each major trade route. These sizes are reported
in terms of TEU, a volume measure that we convert using a baseline capacity factor of 14 DWT
per TEU. The utilization factor is calibrated so that the number of voyages implied by 2005
historical Gil trade volume data matches the actual number of voyages recorded in the CI
Yearbook. Table 3-9 reports these estimated factors for some of the major trade routes. These
rates, which average 0.51 across all trade routes, are generally lower than the utilization factor of
0.9 used on all other commodity trades. However, these estimates are consistent with what
3-16
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Table 3-9. Estimated Utilization Rates for Top 10 Container-Ship Trade Routes
Top 10 Container-Ship Trade Routes by Volume" Utilization Rate
Asia—North America (Transpacific) 47%
Northern Europe—Asia 52%
Mediterranean—Asia 40%
North America—Northern Europe (Transatlantic) 66%
South America—North America 85%
South America—Europe 50%
Mediterranean—North America 27%
Australia—Asia 33%
South America—Asia 46%
West Africa—Europe 28%
Average for All Trades 51%
a Based on Gil trade data for 2005.
industry experts predict for capacity utilization.6 The main reason for the lower utilization rate is
that container ships usually reach a maximum volume capacity well before they reach a
maximum weight capacity. A vessel may be only 50% "full" in terms of deadweight, but still be
unable to fit more containers on board.
3.2.4 Calculating Total Estimated Fuel Demand for Cargo Vessels
As described in Figure 3-1, estimates from the vessel analysis and trade analysis are used
to obtain an estimate of total fuel demand related to international cargo trade flows.
3.2.4.1 Total Fuel Demand in Year y, for y = 2005, 2012, 2020
For each year, total marine fuel consumed is computed as the sum of fuel consumed on
each route of each trade (commodity). Fuel consumed in each route of each trade is, in turn,
computed by summing the fuel consumed for each route and trade for that year by propulsion
engines and auxiliary engines, both at sea and in port.
6The utilization factors estimated correspond to approximately 7 to 9 DWTs per TEU, which is the volume measure
most often used to describe a container ship's size. This is consistent with industry reports. Discussions with
experts in the container trade stated that containers coming out of Asia to the United States and Europe weigh
around 6.75 to 7 tons per TEU. Cargoes out of the United States weigh on the order of 9 to 9.5 tons per TEU.
The combination of weight utilization (based on 14 tons per TEU) and a maximum workable slot utilization of
90% to 95% gives credence to our 51% overall utilization value.
3-17
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_ y y pf
— ^ ^ l ^trade.route.year
trade route
trade route
= Z Z [ AFCtrade>route)yatsea x Days at Seatrade)route)y + AFCtradf, route)yatport x Days at Porttrade)route))
where
de route yatsea = 2 (Percentage of trade along route)v, [Fleet AFCV, x (MELF + AE at sea LF)1
'' v,s,t,r ' L v /J
de.^.yatport =v 2 r (Percentage of trade along route)vs [Fleet AFCVS xAEimportLF]
Days at Seatad t = I (Percentage of trade along route) [Days at sea per voyage x Number of voyages 1
'' v,s,t,r ' L- ' ' -1
Days at Port^ route = I (Percentage of trade along route)v s [Days at port per voyage x Number of voyages]
'^ v,s,t,r '
MELF: Main Engine Load Factor
AE at sea LF: Auxiliary Engine at-sea Load Factor
AE in port LF: Auxiliary Engine in-port Load Factor
The parameters used in these last four equations are all derived from the vessel and trade
analyses discussed above. The (Percentage of trade along route)V:S indicates the fraction of trade
volume carried by each vessel size category, as discussed in Section 3.2. Fleet AFCV:S is the fleet
average daily fuel consumption calculated using Equation (3.1). The main propulsion and
auxiliary engine load factors are discussed in Section 3.2.2, and the specific values used are
reported in Table 3-5. Days at sea per voyage and number of voyages are calculated using
Equations (3.2) and (3.3), respectively.
3.2.5 U.S. Domestic Navigation
The Gil forecasts are primarily designed to analyze international trade flows, so they do
not include projected trade volumes for shipments within the United States. In addition, these
domestic shipments are primarily transported by carriers that are governed by the restrictions of
the Jones Act. For these reasons, the methodology for estimating fuel demand by vessels
transporting cargo domestically differs slightly from the methodology for international cargo
vessels presented in Sections 3.2.2 through 3.2.4.
3.2.5.1 Ship Analysis by Vessel Type and Size
This analysis begins with a vessel profile. Navigistics Consulting helped compile a
database listing vessels in the "Jones Act fleet." Four types of trade constitute a vast majority of
the domestic cargo trade flows that are transported by ships through waterways: dry bulk trade
3-18
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on Great Lakes, crude oil trade (primarily from Alaska), petroleum product trade, and container
trade. Accordingly, the four types of vessels that are used in these trades are considered: crude
oil tankers, dry bulk carriers, container ships, and product tankers (which also carry chemicals).
As with international vessel fleets, vessel types of the domestic fleet were further
classified by size in deadweight tons. Table 3-10 illustrates these breaks, along with summaries
of deadweight and horsepower for each vessel type and size. As seen below, the Jones Act fleet
composes only a small fraction of the international fleet. The Great Lakes bulk category makes
up the largest share by the number of vessels, while the container category is the largest in terms
of horsepower, and the crude oil tanker category is the largest in terms of deadweight. These four
categories have a total of 151 vessels, with a combined deadweight of 7.9 million tons and a
combined horsepower of 2.6 million.
Table 3-10. Jones Act Fleet
Vessel Type
Container*
Great Lakes
Bulk**
Crude Oil
Tanker***
Petroleum Product
Tanker***
Size by DWT
Panamax
Intermediate
Feeder
Panamax
Handymax
Handy
VLCC
Suezmax
AFRAmax
Panamax
Panamax
Handy
Coastal
Minimum
Size
(DWT)
42,100
14,000
0
54,000
40,000
0
180,000
120,000
75,000
43,000
40,000
27,000
0
Maximum
Size
(DWT)
56,500
42,100
14,000
79,000
54,000
40,000
0
180,000
120,000
75,000
68,000
40,000
27,000
Total
Number
of Ships
2
35
1
12
3
33
8
10
4
1
24
17
1
151
Total DWT
(thousands)
92.0
924.0
13.9
729.2
367.9
800.1
1,508.0
1,289.4
367.9
57.7
1,112.4
609.8
19.2
7,891.5
Total Horse-
power
(thousands)
47.0
890.4
22.9
187.8
40.2
218.8
219.3
299.1
98.0
17.0
300.4
204.9
7.2
2,553.0
Source: Authors' calculations based on data from Colton and Company (*), Greenwood's Directory (**), and U.S.
Maritime Administration (***)
3-19
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3.2.5.2 Fleet Average Daily Fuel Consumption
Average fuel consumption for each vessel type and size category was estimated using the
same basic approach that was used to estimate fuel consumption for the international vessel fleet.
The main difference lies in how fleet characteristics change over time through retirement and
replacements.
U.S. Jones Act vessels are more costly to build and, therefore, are kept in service longer
than international fleet vessels, making their replacement age above the international fleet
average. Replacement ages for Jones Act vessel categories are listed below:
• Containers—35 years
• Great Lakes Bulk—60 years (these ships are not a subject to salt water and thus last
longer)
• Crude Oil Tanker—35 years or OPA-907 requirement
• Petroleum Product Tanker—35 years or OPA-90 requirement
The replacement ships are assumed to have a new engine (rated at the current SFOC) and are
assumed to weigh as much as the average ship of a similar category and deadweight class (for
example, a Panamax Size Container Vessel) built in 2005, based on the statistics from the
international fleet database.
3.2.5.3 Voyage Parameters
Calculation of the voyage parameters was also slightly different. The average number of
days required for a trip and the average number of days spent in port were estimated based on
actual ship routings and calculated distances between Alaska, Hawaii, Puerto Rico, and the
continental United States.
The number of days the ships will be engaged in trade (activity level) are then estimated
for each ship category. For container, crude oil tanker, and petroleum product tanker categories,
activity levels are estimated at 350 days. The estimate of Great Lakes bulk vessels' activity level
was set at 290 days to account for winter weather conditions when the lakes are frozen over.
Given the activity level and the average number of days required for a trip at sea and in port, the
total number of days at sea and in port per ship per year are calculated as follows:
Voyages per Year Per Ship = Activity Level
Average Number of Trip Days
7 Oil Pollution Act of 1990 (OPA-90) was introduced after the Exxon Valdez incident. OPA-90 requires all single-
hull ships to be replaced by double-hull ships by a certain date, based on deadweight and horsepower.
3-20
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Total Number of Days at Sea per Ship = Average Number of Days at Sea x Voyages Per Year Per Ship
Average Number of Trip Days
Total Number of Days in Port per Ship = Average Number of Days in Port x Voyages Per Year Per Ship
Average Number of Trip Days
s
The total number of days in port and at sea per year per ship is then multiplied by the
number of vessels in each category to get the total number of days ships spend at sea and the
total number of days ships spend in port each year. Given the average fuel consumption, the days
at sea per voyage, and days in port per voyage for an average ship within each vessel category,
the total estimated fuel demand is then calculated in the same way as for international vessel
fleet.
3.2.6 Ship Analysis for Noncargo Vessels
As with domestic U.S. navigation, because the Gil forecasts focus on international trade
flows, they do not cover activities of several remaining types of vessels: passenger ships, fishing
vessels, military vessels, and other support ships such as tugboats or supply ships. Data on fuel
consumption by the ship categories have been based on available literature and information in
the Clarksons database.
Historical fuel consumption by passenger ships, fishing vessels, and military vessels has
been based on data from Corbett and Koehler (2003). Trends in passenger ships are based on a
study by Ocean Shipping Consultants that projects increases in cruise-ship demand through
2020. Trends in fishing are based on data from the United Nation's Food and Agriculture
Organization (FAO) on worldwide fish capture trends between 1997 and 2002. Trends in
military vessel energy use are based on forecasts from the U.S. Energy Information
Administration's Annual Energy Outlook 2006, which provides estimates of trends in future U.S.
military distillate and residual consumption. Historical fuel consumption by other types of ships
are based on data in the Clarksons database (the "Other" category shown in Table 3-4). These
data on vessel characteristics were combined with engine load assumptions from Corbett and
Wang (2005) and activity levels from Corbett and Koehler (2004) to determine fuel use. Trends
in this fuel use were then assumed to follow patterns of economic activity as reflected in GDP
forecasts from EIA.
3.2.7 Bunker Fuel Grades
Fuel consumption by specific grades is evaluated as follows: information from Koehler
(2003) on consumption of IFO, MDO, and MGO by vessel type is used to assign overall fuel
grades; this information is then combined with the main and auxiliary engine factors discussed in
3-21
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Section 3.2.4, where main engines are assumed to use mostly IFO380 and auxiliary engines use
IFO180.
3.3 Results of Bunker Fuel Forecasts
This section presents estimates of bunker fuel consumption based on the methodology
outlined above. The focus of the discussion and associated graphs is on 1) worldwide bunker fuel
consumption estimates that can be compared to those by TEA and in other published works;
2) U.S. regional fuel consumption estimates related to the cargo fleet engaged in international
trade; and 3) on growth rates in bunker fuel demand and the underlying factors.
Figure 3-3 shows estimated worldwide bunker fuel consumption by vessel type. Fuel
consumption in year 2001 is equal to 278 million tons, which can be compared to the estimate in
Corbett and Koehler (2004) of 289 million tons. By 2020, bunker fuel demand reaches 500
million tons per year. Note, the "historical" bunker fuel data shown going back to 1995 are also
model estimates based on historical Global Insights trade flows. (Comparisons of these estimates
to others in the literature are discussed in more detail in Section 4.2, given their importance to
modeling of the petroleum-refining industry in the WORLD model.)
600
soo -
400 -
I
B
o
300
200 -
100
d Military Vessels
D Natural Gas
D Dry Bulk
ClPassenger Ships
DPetroleum
DGeneral Cargo
n Fishing Vessels
DChemicals
D Container
D Other
D Crude Oil
Figure 3-3. Worldwide Bunker Fuel Use
3-22
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Figure 3-4 shows the annual growth rates by vessel-type/cargo that underlie the
projections in Figure 3-3. Total annual growth is generally between 2.5% and 3.5% over the time
period between 2006 and 2020 and generally declines over time, resulting in an average annual
growth of around 2.6%. As shown in the "container" categories in Figures 3-3 and Figure 3-4,
fuel consumption by container ships is the fastest growing component of worldwide bunker fuel
demand; in 2004, consumption by container ships is around 75 million tons, growing to
87 million tons by 2006 and close to 180 million tons by 2020 (the historical estimates can be
compared to Gregory [2006], which places container ship consumption in 2004 at 85 million
tons, based on installed power). While overall growth is less than 3% a year, growth in
container-ship demand remains above 5% a year on an average annual basis for the next
15 years. Across all vessel types, growth in bunker fuel consumption is somewhat lower than
worldwide GDP growth forecasts from EIA (2005c) (International Energy Outlook 2005) of
around 3.9% a year, but higher than IEA estimates of overall fuel consumption growth (around
1.6% in the World Energy Outlook 2005). The estimate of growth in marine bunkers over the
next 15 years, however, is consistent with the historical growth of 2.7% per year shown in IEA
data from 1983 to 2003.
10%
8%
i
.s
c
U
0%
-2%
vo
o
o
r<
30
O
O
r<
-0- Total
-A- Crude Oil
— Other
O fS
o o
r< r<
-•— Container
Chemicals
Fishing Vessels
•
-------
Growth in fuel use by container ships and the overall contribution by these vessels to
worldwide demand is driven by several factors. The first is overall growth in worldwide GDP
mentioned above. This growth leads to increases in international trade flows over time (shown in
Figures 3-5 and 3-6 below). These figures illustrate that, although container trade is smaller in
total volume than other categories, it is the fastest growing component of the trade flows.
Measuring trade flows in tons of goods, as shown in Figure 3-5, also does not provide a good
proxy for the fuel consumption needed to transport the goods. Liquids and dry bulk are much
denser than container goods, for example. As mentioned in Section 3.2.3, it is estimated that
utilization rates for container ships (comparing deadweight tons of capacity to actual cargo
transported) are around 50%. Thus, it takes approximately twice as many ships to transport the
same amount of container tons compared to liquid/dry bulk tons. This relationship tends to
influence total bunker fuel use and weight it toward container trade. In addition, growth rates in
particular trade flows such as Asia to the United States will also influence overall fuel
consumption, especially as related to container ships as discussed in relation to United States
regional trade flows below.
9,000
B Container H General Cargo D Dry Bulk H Crude Oil D Chemicals D Petroleum D Natural Gas
Figure 3-5. Worldwide Trade Flows (Global Insights)
3-24
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10%
-O-Total
-A-Crude Oil
• Container
-X- Chemicals
• General Cargo
-*—Petroleum
•Dry Bulk
•Natural Gas
Figure 3-6. Annual Growth Rate in Worldwide Trade Flows
Figures 3-7 to 3-9 show estimated consumption of specific grades of bunker fuels from
Figure 3-3.
Figures 3-10 to 3-13 present estimates of fuel use by the international cargo fleet engaged
in delivering trade goods to and exporting trade goods from the United States. These estimates
comprise part of the total worldwide bunker fuel use shown in Figure 3-3 and do not include fuel
used for domestic navigation. The results in Figure 3-10 show estimated historical bunker fuel
use in year 2001 of around 47 million tons (note, while this fuel is used to carry trade goods to
and from the United States, it is not necessarily all purchased in the United States and is not all
burned in U.S. waters). This amount grows to over 90 million tons by 2020 with the most growth
occurring on trade routes from the East Coast and the "South Pacific" region of the West Coast.
Figure 3-11 shows the annual growth rate projections for the fuel consumption estimates
in Figure 3-10. The South Pacific and East Coast regions of the United States are growing the
fastest, largely as the result of container ship trade (see Figures 3-12 and 3-13). Overall, the
average annual growth rate in marine bunkers associated with future U.S. trade flows is 3.4%
3-25
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400
D Militagf Vessels D Passe^er Ships DFishi$| Vessels
D Natural Gas D Petroleum D Chemicals
D Dry Bulk D General Cargo D Container
r^
o
r^
D Crude Oil
Figure 3-7. Worldwide IFO380 Use
60
50 -
40 -
o
x
| 30 H
_
20 -
10 -
o\
o\
o
o
o
if)
o
o
o
r^<
o
El Military Vessels E Passenger Ships E Fishing Vessels Bother
D Natural Gas D Petroleum D Chemicals d Crude Oil
D Dry Bulk D General Cargo D Container
Figure 3-8. Worldwide IFO180 Use
3-26
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120
100
80 -
I
s
o
n Military Vessels
D Natural Gas
D Dry Bulk
n Passenger Ships
D Petroleum
D General Cargo
D Fishing Vessels
D Chemicals
D Container
D Other
D Crude Oil
Figure 3-9. Worldwide MDO-MGO Use
B US North Pacific D US Great Lakes D US Gulf EJ US East Coast m US South Pacific
Figure 3-10. Bunker Fuel Used by the International Cargo Fleet Importing to and
Exporting from the United States (by Region)
3-27
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10%
-O- United States -•- US South Pacific -•- US North Pacific
-•- US Great Lakes -*- US Gulf -•- US East Coast
Figure 3-11. Annual Growth Rate in Bunker Fuel Used by the International Cargo Fleet
Importing to and Exporting from the United States (by Region)
B Container 01 General Cargo D Dry Bulk SI Crude Oil D Chemicals D Petroleum D Natural Gas
Figure 3-12. Bunker Fuel Used by the International Cargo Fleet Importing to and
Exporting from the United States (by Vessel/Cargo Type)
3-28
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10%
-4%
§
-O- Total
-*- Crude OH
-•- Container
-*- Chemicals
—•— General Cargo
-*- Petroleum
•Dry Bulk
•Natural Gas
Figure 3-13. Annual Growth Rate in Bunker Fuel Used by the International Cargo Fleet
Importing to and Exporting from the United States (by Vessel/Cargo Type)
between 2005 and 2020. This growth rate is somewhat higher than worldwide totals, but is
similar to estimated GDP growth in the United States of 3.1% between 2005 and 2020 (EIA,
2006) and is influenced by particular components of U.S. trade flows.
The growth rate in bunker fuel consumption related to U.S. imports and exports is driven
by container ship trade (see Figures 3-14 and 3-15), which grows by more than 4% a year. U.S.
trade volumes are also influenced by high worldwide growth in GDP and resulting demand for
U.S. goods. Along with the fact that container ships use a disproportionately large amount of fuel
to move a given number of tons of cargo (as discussed in Section 3.2.3), fuel use by container
ships is also influenced by shifts in trading routes over time. In the future, trade is expected to
shift to the Pacific region (an increase in Asia-U.S. routes), which causes the average distance
per voyage to increase. Thus, while ship efficiency is increasing over time as older ships retire,
this effect to dominated by the increase in voyage distance, leading to higher bunker fuel growth.
3-29
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B Container [B General Cargo D Dry Bulk H Crude Oil D Chemicals D Petroleum D Natural Gas
Figure 3-14. U.S. Trade Flows—Imports plus Exports (Global Insights)
10%
-O- Total
-*-Crude Oil
• Container
Chemicals
• General Cargo
HK- Petroleum
•Dry Bulk
•Natural Gas
Figure 3-15. Annual Growth in U.S. Trade Flows—Imports plus Exports (Global
Insights)
3-30
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SECTION 4
ESTIMATING BUSINESS-AS-USUAL PROJECTIONS USING THE WORLD
MODEL
A key component of Task 1 was to develop BAU projections for bunker fuels. This
required enhancing an analytical tool focused on the petroleum-refining industry (i.e., the EnSys
WORLD model) so it can provide a sound basis and starting point for future analyses of the
effects of potential SECAs in North America and elsewhere, along with other possible global
tightening of marine fuels quality. These enhanced capabilities were required for a time horizon
covering the years 2012 and 2020.
Table 4-1 summarizes these and other changes made to the WORLD model structure and
features for this analysis, followed by additional discussion of the specific premises used as the
basis for the 2012 and 2020 BAU cases.
4.1 WORLD Model Enhancements to Accommodate Compliance Alternatives
WORLD is a comprehensive, bottom-up model of the global oil downstream that
includes crude and noncrude supplies; refining operations and investments; crude, products, and
intermediates trading and transport; and product blending/quality and demand. Its detailed
simulations are capable of estimating how the global system can be expected to operate under a
wide range of different circumstances, generating model outputs such as price effects and
projections of refinery operations and investments. As part of the overall model enhancements,
the refinery data, capacity additions, technology assumptions, and costs were reviewed (see
Section 4.3).
Beyond these enhancements, the relevant regulations were thoroughly reviewed to ensure
that the WORLD model was correctly positioned to undertake future analyses of marine fuels
SECAs. Issues brought to light in this review, as discussed below, raise uncertainty about how
compliance with SECAs and other potential regulations can be achieved within the petroleum-
refining and shipping industries. The issues also tend to create an analytical situation that is less
clear and more complex than, for example, a mandate to move all U.S. gasoline to 30 ppm sulfur.
Among the issues and uncertainties considered are the following:
• the prospective timetable for reducing SECA marine fuel requirements from 1.5% to
1.0% to 0.5% sulfur;
• the possible scenario of part or all bunker fuel demand shifting to marine distillates;
• the costs and effects of shipboard emission reduction strategies;
4-1
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Table 4-1. Summary of Structural Changes to the WORLD Model
Product Grades
The distillate and residual fuel specifications in the model were expanded to fully differentiate international
marine bunker fuel from inland fuels and to enable clear distinctions between "traditional" and low-sulfur bunker
grades. The resulting model bunker grades were
• MGO—marine gas oil
• MDO—marine diesel, high sulfur
• MDO—marine diesel, low sulfur
• IFO 180—high sulfur
• IFO 180—low sulfur
• IFO 380—high sulfur
• IFO 380—low sulfur
Notes:
1. Only one grade of MGO was represented per region on the basis that demand for MGO is small and
mainly restricted to local ship movements; hence, any change in specification would apply to the whole
MGO volume for the region.
2. Separate low- and high-sulfur grades were implemented for the main bunker grades precisely to
correctly capture the processing, blending, and economic effects of regions moving partly or fully to
low-sulfur specifications.
3. In reality, there is a trend in the market for IFO 380 grade to be displaced by IFO 500 and even 700. The
approach was taken to simply tighten the IFO 380 viscosity specification, where appropriate, to
represent this. This approach is adequate since the reduction in distillate cutter stock needed in the blend
when going from 380 to 500 or 500 to 700 centistokes is small as is the associated cost impact.
4. The above grades were used to represent international or "blue water" consumption of bunker fuels.
Domestic uses of marine fuels (primarily distillates) were accounted for under the corresponding inland
diesel or residual fuel categories.
Product Specifications
The following specifications were already active in the model:
• MDO
• IFO
The following were added to these:
• Carbon residue—in order to prevent any inappropriate blends for MDO or IFO grades
• Nitrogen—to cover the possible need to study nitrogen as a component of NOX regulation. Not activated
in B AU cases.
The following were considered but not added:
• Vanadium was not added because (a) it appears to be a rarely limiting specification and (b) adding it in
would have entailed significant model modifications.
Product Transportation
Product transportation matrices covering tanker, interregional pipeline, and minor modes were expanded to
embody the additional distillate and residual bunker grades.
Bunker Fuel Demand
A new model subsystem was built to import the RTI bunker fuel demand projections. Given the differences
between the RTI and IEA levels of demand, the model was set up so that it could be run on both bases. Under the
RTI basis, global residual fuel demand is the same as that based on IEA for the 2000 base year, but for future
years forecasts an increase in total global demand oil demand (i.e., upward adjustments versus the AEO 2006
reference case projections for 2012 and 2020).
Fuel Stability
As detailed above, yield patterns on the residuum desulfurization and visbreaker units were adjusted, and
paraffinic streams were locked out of residual fuel blends.
Model Reports
Reports were added for blend composition of residual fuels and also for reporting of refinery CO2 emissions.
4-2
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• how fast and how effectively abatement technology may mature;
• the costs of refining, including the capital expenditures required to reduce bunker fuel
sulfur content and the potential for process technology improvements;
• likely market reactions to increased bunker fuel costs, such as fuel grade availability,
impacts on the overall transportation fuels balance, and competition with land-based
diesel and residual fuels for feedstocks that can upgrade fuels;
• the effects of emissions trading; and
• the potential for low- and high-sulfur grade bunker sources and consumption to
partially shift location depending on supply volume, potential, and economics.
The analytical system thus had to be set up to allow for alternative compliance scenarios,
particularly with regard to (a) adequately differentiating bunker fuel grades; (b) allowing for
differing degrees to which the SECA or other standards in a region were presumed to be met by
bunker fuel sulfur reductions, rather than by other means such as scrubbing or emissions trading;
and (c) allowing for all residual fuel bunker demand to be reallocated to marine diesel. Beyond
any international specifications, the analytical system needed to be able to accommodate future
consideration of regional, national, and local specifications (e.g., those being promulgated in
California).
The primary approach taken to manage these issues was to
• expand the number of bunker grades in the model to three distillates and four residual
grades,1
• allow for variation where necessary in (regional) sulfur standards on specific bunker
grades, and
• enable residual bunker demand to be switched to marine diesel.
Nonetheless, the approach necessitates estimating—external to the main WORLD
model—the details of compliance in any particular region. For example, as in the existing EU
SEC As, we are required to estimate the percentage of the bunker consumption in the region that
will be met by low-sulfur fuels versus high-sulfur fuels, exhaust gas scrubbing, or emissions
trading (Section 6 provides more detailed background on the options for SECA compliance and
how they are currently viewed in the model).
1 Specifically, the following seven grades were implemented: MGO, plus distinct high- and low-sulfur blends for
MDO and the main residual bunker grades IFO 180 and IFO 380. The latest international specifications applying
to these fuels were used, as were tighter sulfur standards for the low-sulfur grades applicable in SECAs.
4-3
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A main focus to date of debates about SECA regulations has been on the degree to which
the regulations will require refinery production of lower-sulfur residual fuels. However, the SOX
scrubbing option raises the possibility that higher-sulfur bunker fuels could be supplied.
The MARPOL SECA standard states an SOX emission level of 6 g/kWh, which is
equivalent to 1.5% sulfur content bunker fuel. A scrubber operating at 67% efficiency could
enable a ship to burn 4.5% sulfur fuel and still meet the 6 g/kWh standard. Given that
precommercial scrubber tests on European ferries have been reporting efficiencies in the range of
65% to 95%, the technology could enable a supply option whereby refiners continue to supply
high-sulfur IFO bunker fuels at up to 4.5% sulfur. In other words, suppliers could maintain or
increase sulfur levels versus the current worldwide average of 2.7%.
With a scrubber operating at 95% SOX efficiency, a ship could easily surpass the possible
EU 2008 standard of 2 g/kWh using 4.5% sulfur fuel versus otherwise using 0.5% sulfur fuel.
Even the standard of 0.4 g/kWh, which corresponds to 0.1% sulfur fuel for in-port use, can be
met using scrubbing and 2% sulfur fuel. This method of compliance enables refiners to avoid the
costs of desulfurization and shippers to buy lower-priced fuels. The route also potentially plays
into emissions-trading schemes since, provided emissions levels can be verified, a ship with a
scrubber could reduce its emissions below the 6 or 2 g/kWh standards and realize credits (and
any associated economic value). Shipboard scrubbing also helps reduce emissions of particulates
but has limited impact on NOX, partially explaining the interest that has been generated in using
marine diesel in place of residual grades.
[The WORLD analytical process, therefore, needed to be able to capture potential
economic trade-offs of scrubber use in terms of how its impacts might feedback on refinery
bunker quality, supplies, and economics. A scrubber "unit" could be built into the WORLD
model in the future, but additional information will need to be developed to allow accurate
estimates of scrubbers' costs and utilization potential. More operational experience is required to
fully gauge scrubber costs, including such elements as onshore sludge disposal. Estimates to
date, however, put the cost per ton of SOX removal via scrubbing at around one-third or less of
the cost via residual fuel desulfurization (Meech, 2006). Therefore, given this simple degree of
cost difference, the WORLD model would always opt for the scrubber route to the extent it was
allowed. The net effect is that a key scenario variable, developed external to the model (or in
conjunction with cost functions developed for the model), is the proportion of SECA-compliant
regional bunker fuel that needs to be supplied in the form of low-sulfur product versus high-
sulfur product being scrubbed. The WORLD model is readily capable of studying parametric
effects associated with varying this proportion.]
4-4
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4.2 WORLD Model Enhancements to Accommodate Alternate Fuel Demand Forecasts
The WORLD model was also modified to accommodate the bunker demand forecasts
estimated in Section 3. These projections required appreciable rethinking and reworking of the
model since the estimates of recent historical bunker demand are twice the levels used by TEA
and EIA. This has far-reaching implications, leading to reduced current and future demand for
inland residual fuels and increased future total residual demand because bunker demand growth
is projected to be significant, while that of inland residual is declining.
The net implication of the findings in Section 3 is that other forecasters, including IEA,
EIA, and OPEC, are currently underestimating future global residual and total oil demand. In
order to accommodate these differing demand projections, and to enable their implications to be
understood, the WORLD model was modified so that it could be run for each time horizon on
either an IEA fuel demand or an RTI fuel demand basis.
Although the bunker fuel estimates in Section 3 (equal to 278 million tons in 2001) are
higher than IEA estimates of around 140 million tons, these findings are comparable to estimates
from other works (e.g., Koehler [2003] at 281 million tons or Corbett and Koehler [2003, 2004]
at 289 million tons). Industry sources contacted by Navigistics Consulting indicated that there is
no agreement on worldwide bunker demand. Meech (2006) estimated world demand at 255
million tons in 2004, and Madden (2006) placed IFO use at roughly 185 million tons in 2004,
based on data from Meech (2006).
Given the differences between fuel demand projections, it was necessary to incorporate
the RTI bunker estimates carefully into the WORLD model. During this process, when
establishing a historical base within WORLD, the view was taken that total reported global oil
demand and with that total distillates and residual fuels demand are correct. Therefore, there is
no issue of underreporting of total historical demand. Rather, the issues across bunker estimates
represent a misallocation of residual fuels (i.e., fuel that is reported as [inland] residual fuel is, in
fact, used as marine bunker fuel). The potential for such misreporting is evident. For instance,
statistical sources tend to show total bunker demand for the Middle East that is less than that for
the port of Fujairah alone and show essentially no bunker demand in the FSU. In the industry
press, references can be found to the lack of transparent reporting of bunker sales (see the
illustrative text below).
4-5
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Excerpt from the Bunkerworld Library on Bunker Ports
So how big is the Fujairah bunker market? There are no official data available regarding the size of the Fujairah
market, but according to Harbour Master, Captain Tamer Masoud, from the Port of Fujairah, the annual volume of
bunker in the area is approximately 12 million metric tons. The average monthly supply volume of bunker is around
1 million metric tons.
It is unclear whether this volume includes export figures. Some players appear to survive mainly by exporting fuel
cargoes, for example, to nearby countries such as Pakistan for power stations.
In Fujairah, approximately 60% to 80% of the supplied bunker is IFO380, and the rest is divided between IFO180
and MGO, though it is difficult to estimate exact figures.
In the Arab Gulf, if we include sales from ports in Saudi Arabia, Iran, Kuwait, as well as other UAE ports, the
total volume of bunker is well over 1 million mt per month. The Fujairah market is definitely the largest single
bunker market in this area.
Exactly how much the Fujairah bunker market accounts for is, it transpires, a subject of much dispute, with
established players worried that newcomers and relative 'outsiders' have an unrealistic view of the market size and
its potential profit margins.
In terms of simulating the global oil downstream today, a potential misallocation between
bunker and inland fuel is not significant since the ultimate fuel volumes and qualities are not
affected. However, this changes when future years are considered. This is because the growth
rate for inland residual fuel is essentially 0% globally, whereas for marine bunkers it is around
3% per year in RTFs and other projections. (It should be noted that the RTI bunker growth rate
is consistent with a historical growth rate of 2.7% per year, in IEA data from 1983 to 2003).
Petroleum product demand projections are built up sector by sector. What appears to be
happening in current forecasts, on the basis of the bunker estimates from Section 3 and the
related works, is that total inland residual fuel demand is being overestimated, but its demand
growth is flat, and total bunker demand, with its attendant appreciable growth rate, is being
underestimated. The net effect/implication is that today's oil demand projections by EIA, IEA,
and others underestimate total future bunker demand, residual demand, and global oil demand.
Table 4-2 and Figure 4-1 show the impacts on 2003, 2012, and 2020 oil demand
projections, based on the AEO 2006 reference case, of applying IEA and alternatively the RTI
estimates of bunker fuel demand. Both bases have the same growth rates for each product type as
listed in Table 4-3.
As Table 4-2 shows, total demand for other products such as gasoline and naphtha, are
not affected. Total distillate demand is slightly impacted, but there is a significant shift under the
RTI basis to distillate bunker grades with less land-based diesel. The main impacts are on
product quality since on-road and off-road diesel specifications are advancing more rapidly
toward low and ultra-low sulfur levels than are marine distillate fuels. Demand for residual fuel
4-6
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Table 4-2. Global Oil Demand by Product Category—IEA and RTI Bases for Bunker
Fuels
Bunkers Basis
Demand by
product type
Ethane
LPG
Naphtha
Gasoline
Kero/Jet
Gas oil/diesel/NO2
Gas oil/diesel —
BKRS— MGO
Gas oil/diesel —
BKRS— MDO
Residual — Inland
incl RFO
Residual —
BKRS— IFO180
Residual —
BKRS— IFO380
Other
Transport losses
Total oil demand
Total distillates
demand
Total residual
demand
2003
IEA
1.11
6.71
4.63
21.03
6.33
21.19
0.02
0.43
8.20
0.31
2.01
7.49
0.18
79.64
21.63
10.52
2003
RTI
1.11
6.71
4.63
21.03
6.33
20.25
0.18
1.16
6.67
0.55
3.48
7.49
0.18
79.78
21.60
10.70
2003
Impact of
Switch to
RTI Basis
0.00
0.00
0.00
0.00
0.00
(0.94)
0.16
0.74
(1.53)
0.24
1.47
0.00
0.00
0.15
(0.03)
0.18
2012
IEA
1.60
7.82
5.83
23.40
7.43
26.59
0.02
0.53
8.28
0.40
2.67
8.57
0.21
93.35
27.14
11.35
2012
RTI
1.60
7.82
5.83
23.40
7.43
25.36
0.19
1.47
6.83
0.76
4.77
8.57
0.21
94.23
27.01
12.36
2012
Impact of
Switch to
RTI Basis
0.00
0.00
0.00
0.00
0.00
(1.23)
0.17
0.94
(1.46)
0.36
2.10
0.00
0.00
0.88
(0.13)
1.01
2020
IEA
1.82
8.56
6.88
25.20
8.07
30.59
0.02
0.61
8.17
0.47
3.23
9.83
0.24
103.70
31.22
11.87
2020
RTI
1.82
8.56
6.88
25.20
8.07
29.15
0.19
1.73
6.84
0.95
5.92
9.83
0.24
105.38
31.07
13.71
2020
Impact of
Switch to
RTI Basis
0.00
0.00
0.00
0.00
0.00
(1.44)
0.17
1.12
(1.33)
0.48
2.69
0.00
0.00
1.68
(0.15)
1.84
is also significantly modified. Under the RTI basis, it is 1.0 million barrels per day (mmbpd)
higher in 2012 (bunker and inland grades combined) and for 2020, the figure is 1.84 mmbpd.
The implication is that the IEA basis for bunker fuel understates future global oil demand: by 0.9
mmbpd in 2012 and 1.7 mmbpd by 2020 versus the AEO reference case figures.
The increase in residual demand will materially impact total refining investments and
economics as well as increase oil supply requirements. Of further significance is that, with higher
volumes of bunker fuels, the impacts of marine fuels regulations and SEC As will be
4-7
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Impact of RTI Bunkers Projections on Global
•a
a.
J2
E
2 00 -
0.00 -
(2.00) -
nSeriesI
n
°
-0-
•
If
U
=
Oil Demand 2020
CZI
j •
GASOIL BKRS - BKRS -
/DSL MGO MDO
(1.44) 0.17 1.12
RESIDU
AL-
INLAND
(1.33)
BKRS -
IFO180
0.48
BKRS -
IFO380
2.69
TOTAL
OIL
1.68
TOTAL
DISTILL
ATES
(0.15)
TOTAL
RESIDU
AL
1.84
D GASOIL/ DSL
• BKRS - MGO
• BKRS -MDO
• RESIDUAL -INLAND
• BKRS-IFO180
• BKRS-IFO380
O
D TOTAL OIL
D TOTAL DISTILLATES
• TOTAL RESIDUAL
Figure 4-1. Impact of RTI Bunker Projections on Global Oil Demand in 2020
Table 4-3. Product Growth Rates
RTI Basis — Bunkers Projection
Ethane
LPG
Naphtha
Gasoline
Kero/jet
Gas oil/diesel/NO2
Gas oil/diesel— BKRS— MGO
Gas oil/diesel— BKRS— MDO
Residual — Inland incl RFO
Residual— BKRS— IFO 1 80
Residual— BKRS— IFO3 80
Other
Transport losses
Total oil demand
2000ato2012
2.06%
1.99%
2.53%
1.46%
1.25%
2.51%
0.13%
2.73%
0.09%
3.61%
3.59%
1.12%
1.50%
1.82%
2020
1.89%
1.65%
2.36%
1.25%
1.17%
2.21%
0.20%
2.46%
0.06%
3.30%
3.25%
1.42%
1.50%
1.66%
a World base demand year is 2000.
correspondingly greater, in terms of volumes of marine fuels that may have to be produced to
low-sulfur standards and the associated impacts on refining investments and supply economics.
To deal with these bunker demand projections and to accommodate potential SEC A
scenarios including differing assumptions about the degree to which SOX targets are met by fuel
4-8
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sulfur reduction versus abatement and trading, the WORLD model was modified so that it could
(a) work with oil demand projections on both the TEA and RTI bases for bunker fuels and (b)
could accommodate user-specified proportions of low-sulfur MDO and IFO for any horizon and
region. In addition, the model user has the ability to set the sulfur level for each horizon and
region for each high- and low-sulfur fuel (e.g., to capture potential progression under the EU
SEC As from 1.5% to 0.5% sulfur).
Another facet of marine bunker demand is that shippers have flexibility in terms of where
they bunker. Bunker fuel demand can shift to some degree from region to region. This
phenomenon is part and parcel of the daily bunker business, and buyers shift their buying based
on a few dollars per ton price differences. For Task 1, this situation was recognized, but bunker
demand was kept static; no feature was introduced to partially shift demand toward regions
where supply is least expensive.
4.3 Enhancements to Ensure Bunker Fuel Stability
During the early stages of the study, concerns were raised about the potential impact of
quality and compositional changes on the stability of the residual bunker fuel grades. A literature
search was undertaken and knowledgeable individuals contacted in industry to ensure a sound
understanding of fuel stability issues as a basis for ensuring the WORLD model processing and
blending options were consistent with stable IFO blends.
Fuel instability is a serious and not uncommon issue in bunkering. It centers on the
asphaltenes contained in the blend precipitating out, which renders the fuel unusable and, if
already on board, the only remedy is to debunker the ship. The presence in the blend of different
classes of blendstocks acts to either prevent or cause precipitation of asphaltenes.
Conversations with industry experts on bunker fuels confirmed that there is a degree of
"black art" in bunker blending in that refiners and blenders learn what blends work and stick to
these. Further, the blending "art" is highly refinery specific. Although capturing differences
between individual refineries was not possible within the WORLD model, steps were taken to
prevent the model from producing IFO blends that could tend to be unstable. The main factors
reviewed and steps taken were as follows:
• The visbreaker yields in the model were reviewed and adjusted. Data from Maples
states that the propensity for visbreaker vacuum residuum product streams to be
unstable is highly dependent on the feed asphaltene content; hence, to maintain
stability, the heavier, more asphaltic feeds need to be processed at reduced severity
relative to less asphaltic feeds. This view was reinforced by bunker experts. Again,
4-9
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according to Maples, who undertook a specific study of visbreaking and fuel stability,
the typical range of conversion is 8% to 12%, where the objective is to maximize
distillate production and 6% to 10%, where it is to reduce residual viscosity, with an
overall observed conversion range of 4% to 16%. To reflect these ranges and to
establish a conservative set of visbreaker yields across vacuum residuals from low- to
high-sulfur/asphaltene contents, a graduated set of yields was applied. Conversion
was inversely related to residuum quality such that it was limited to 6% for the
poorest quality resid, rising to 10% for the highest quality feed. In addition,
visbreaker utilities' consumption and capital cost were checked.
The vacuum and atmospheric residuum hydro-desulfurizer yields, utilities, and
costs were reviewed. With the prospect of lower IFO sulfur limits, the VRDS and
ARDS units gain additional importance. Feedback from industry contacts and
literature research was that, for purposes of maintaining stability in residual fuel
blends, VRDS/ARDS operating severities should not be so severe as to cause
significant hydro-cracking. Information from Meyers and other sources indicates a
typical percentage desulfurization range from the high 80%s to 95% to 97%. Yields
and desulfurization levels in the model were adjusted to close to 90% in order to stay
in the conservative range.
The physical properties of the potential main IFO blend components were reviewed
with particular attention paid to gravity, sulfur, carbon residue, and viscosity.
Adjustments were made to the viscosities of several vacuum and atmospheric
residuum streams. These had been previously overstated, leading to excessive levels
of distillates and cracked stocks in early case run blends.
Carbon residue specification was added as a control against unstable blends.
The blendstocks allowed into the IFO blends were also reviewed All kerosene type
blendstocks were checked as blocked from residual fuel blends (inland as well as
bunker). Similarly all paraffmic middle distillate and vacuum gas oil stocks were
blocked from residual blending. Cracked stocks, notably FCC cycle and clarified oils,
were allowed into all residual blends but concentrations were limited to a maximum
of 25% based on literature research and industry feedback. Visbroken vacuum
residuum streams were limited to a maximum 10% regional average,2 again based on
feedback. The overall intent here was to prevent the model from producing blends
that could be readily unstable.
Fuel stability additives were considered but were not included in the modeling
analysis. Reputable suppliers do make available additive packages designed to
improve fuel stability. However, they are not universally used for marine bunker
fuels. Major oil company suppliers are known to not use additives. Also, feedback
from industry experts was skeptical in terms of the degree of reliance that could be
placed on such additives to prevent fuel stability issues. Thus, they were excluded
from the analysis. At worst, this may mean the analysis slightly understates the costs
of future bunker fuels by omitting the cost of the additive package.
! The limits on visbroken residuals and also on cracked stocks are regional averages. Therefore, they allow that, in
the real world individual blends/suppliers would have levels either higher or lower.
4-10
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4.4 Enhancements to WORLD Model Reporting
Given the importance attached to fuel stability and the focus of the study on bunker fuels,
the WORLD model reports were extended to directly summarize the regional blend compositions
of each residual grade (inland and bunker). Thus, any anomalous blends could be more easily
identified.
In addition, since greenhouse gas emissions are becoming part of the debate on bunker
fuels, a recently added feature to post-optimally report the CO2 emissions from each world
refining region was activated. This enabled quantitative comparison of the effects of moving to
more intense processing of bunker (or other) fuels to achieve lower sulfur content and/or shift to
distillate grades.
4.5 WORLD Model Assumptions and Structural Changes
4.5.1 AEO 2006 Outlook—Supply/Demand/Price Basis
Overall, oil supply, demand, and price parameters were set in the model based on the
AEO 2006 reference case as summarized in Table 4-4. Detailed supply premises, including
production by crude type by country/region, were based on internal WORLD model data and
projections. Noncrude supply in the model was detailed by major fuel type and region.
Projections were set based on in-house data with reference to detailed EIA data.
Product demand for 2012 and 2020 was set using a year 2000 basis of historical data by
product type with growth rates by region and product. These growth projections are believed to
be in line with those of other current forecasts:
• the strongest growth was for distillates among the major fuel categories, including
continuing dieselization in Europe;
• emphasis on distillates in Asia/China;
• no major shifts in U.S. transport fuels patterns;
• essentially flat growth for inland residual fuel consumption; and
• significant growth for naphtha and LPG.
4.5.2 Product Quality
The 2012 and 2020 BAU cases were on the basis of a "best estimate" of fuel quality,
given implementation of already active regulations and continuation of current product quality
trends. Specific premises built into the cases are discussed below.
4-11
-------
Table 4-4. AEO 2006 Petroleum Supply Forecast (million barrels per day, unless
otherwise noted)
Grade Oil Prices (2004 dollars per barrel)
Imported Low Sulfur Light Grade Oil Price
Imported Grade Oil Price
Production (Conventional)
Mature Market Economics
United States (50 States)
Canada
Mexico
Western Europe
Japan
Australia and New Zealand
Total Mature Market Economies
Transitional Economies
Former Soviet Union
Russia
Caspian Area
Eastern Europe
Total Transitional Economies
Emerging Economies
OPEC
Asia
Middle East
North Africa
West Africa
South America
Non-OPEC
China
Other Asia
Middle East
Africa
South and Central America
Total Emerging Economies
Total Production (Conventional)
Production (Nonconventional)
United States (50 states)
Other North America
2005
55.93
49.70
8.33
2.45
4.13
6.68
0.14
0.64
22.37
9.61
2.36
0.26
12.23
1.44
22.25
3.07
2.01
2.88
3.17
2.59
1.71
3.67
4.36
47.15
81.74
0.25
0.96
2012
47.65
43.59
9.51
1.56
4.06
5.64
0.08
0.86
21.71
9.65
3.47
0.32
13.44
1.45
25.09
3.50
2.44
3.48
3.30
2.50
2.15
3.97
4.62
52.49
87.65
0.63
1.98
2020
50.70
44.99
9.51
1.45
4.48
5.22
0.07
0.84
21.58
10.66
5.16
0.39
16.21
1.26
26.99
3.70
2.61
3.70
3.33
2.61
2.45
5.41
5.83
57.89
95.68
0.94
2.67
2004-2030
1.3%
1.3%
0.2%
-2.0%
0.8%
-1.7%
-2.8%
0.7%
-0.3%
0.7%
4.6%
2.5%
1.9%
-0.9%
1.5%
0.6%
1.7%
1.5%
0.0%
-0.5%
1.9%
3.2%
2.0%
1.4%
1.1%
7.6%
5.4%
(continued)
4-12
-------
Table 4-4. AEO 2006 Petroleum Supply Forecast (million barrels per day, unless
otherwise noted) (continued)
Western Europe
Asia
Middle East
Africa
South and Central America
Total Production (Nonconventional)
Total Production
Consumption
Mature Market Economies
United States (50 states)
United States territories
Canada
Mexico
Western Europe
Japan
Australia and New Zealand
Total Mature Market Economies
Transitional Economies
Former Soviet Union
Eastern Europe
Total Transitional Economies
Emerging Economies
China
India
South Korea
Other Asia
Middle East
Africa
South and Central America
Total Emerging Economies
Total Consumption
OPEC Production
Non-OPEC Production
Net Eurasia Exports
OPEC Market Share
2005
0.04
0.31
0.02
0.13
0.73
2.44
84.18
20.82
0.34
2.17
2.01
13.55
5.17
1.10
45.17
4.16
1.42
5.59
7.35
2.53
2.26
6.37
6.32
3.12
5.49
33.43
84.18
32.15
52.03
6.64
0.38
2012
0.10
0.83
0.57
0.28
1.32
5.71
93.36
22.82
0.34
2.14
2.15
13.38
4.72
1.18
46.74
4.58
1.64
6.22
9.09
3.08
2.44
8.06
7.39
3.78
6.56
40.40
93.36
37.34
56.02
7.22
0.40
2020
0.12
1.25
0.73
0.53
1.78
8.02
103.70
24.81
0.38
2.25
2.24
13.52
4.40
1.28
48.89
4.93
1.87
6.81
11.38
3.81
2.57
9.85
8.34
4.31
7.75
48.01
103.70
40.27
63.43
9.40
0.39
2004-2030
6.4%
9.4%
18.3%
9.4%
6.1%
7.1%
1.4%
1.1%
1.2%
0.3%
0.5%
0.2%
-0.9%
1.2%
0.6%
1.0%
1.6%
1.2%
3.2%
2.7%
0.7%
2.6%
1.7%
1.9%
2.1%
2.3%
1.4%
1.5%
1.3%
2.4%
0.2%
4-13
-------
4.5.2.1 Industrialized World
USA/Canada/Europe/Japan/Australia
• Gasoline, on-road and off-road diesel ultra-low sulfur regulations are fully in place by
the 2010/2011 time frame (i.e., before 2012 with an essentially total phase-out of
nonultra low-sulfur gasolines and diesel fuels).
• Gasoline clear pool octanes remain flat.
• MTBE phase-out is completed in the United States in 2006, and the RFS is in place.
• MTBE is assumed to not be phased out in other world regions.
• Regulations that impact other fuels' quality, such as EPA toxics "anti-backsliding,"
Euro V, and CARBIII, are in place.
• Consumption of high-sulfur inland residual fuel entirely replaced by low-sulfur fuel
(1% or less).
¥.5.2.2 Non-OECD Regions
* Completion of lead phase-out in gasoline.
• An overall gradual upward trend in regional pool octanes such that, by 2020, all non-
OECD regions are within 1 octane or less of U.S. average pool octane. Globally, the
octane rise is moderated by the fact that the large gasoline volumes in OECD regions
are projected to remain at constant, even slightly declining, octane levels.
• Progressive adoption of advanced (generally Euro II/III/IV) fuels standards for
transport fuels such that a moderate proportion of transport fuel demand has reached
advanced standards by 2012 and the majority by 2020.
• A gradual/partial trend toward mandates for low-sulfur residual fuel for inland use.
4.5.3 Residual Fuel for Industrial/Inland Use
As the result of trends across both OECD and non-OECD regions, the global percentage
of low-sulfur industrial/inland residual fuel (less than 1% sulfur content) rises from an estimated
41% in 2000, to 52% in 2012, and to 63% in 2020. Thus, the basis is that these progressive shifts
toward low sulfur residual fuel will be occurring in addition to parallel shifts toward lower-sulfur
residual bunker fuels. The same is true for distillates, where the continuing global trend toward
low and ultra-low sulfur standards for on- and off-road diesels will be occurring over the same
time frame as the shift to tighter sulfur standards for marine fuels.
4.5.4 Biofueh
The AEO 2006 reference case contains large increases in U.S. and global biofuels
production. Initial WORLD case projections were set at total global supply/demand of 1.5
mmbpd of biofuels by 2012 and 1.8 mmbpd by 2020. These were later refined based on more
4-14
-------
detailed analysis and projections contained in the TEA World Energy Outlook, 2006, released in
November 2006 as summarized in Table 4-5. At 1.4 mmbpd for 2012 and 1.94 mmbpd for 2020,
these projections are similar to the original AEO numbers.
Table 4-5. Projected Biofuels Consumption
OECD
North America
United States
Canada
Europe
Pacific
Transition Economies
Russia
Developing Countries
Developing Asia
China
India
Indonesia
Rest of Dev Asia
Middle East
Africa
North Africa
Rest of Africa
Latin America
Brazil
World
Ethanol
2005
274
258
254
4
16
17
5
277
579
Consumption
2012
785
482
465
17
298
5
2
2
0
0
9
2
3
11
1
8
0
7
0
275
1,094
(kbpd)
2020
1,060
608
585
23
444
8
2
2
0
0
26
5
6
22
2
16
2
14
0
382
1,523
Biodiesel Consumption
2005 2012
61 231
5 68
5 66
0 2
56 160
3
1
1
0
0
14
3
5
17
2
12
0
11
0
1 22
62 306
(kbpd)
2020
253
83
78
5
164
6
1
1
0
0
40
8
9
34
o
3
25
3
22
0
39
413
Source: IEA World Energy Outlook 2006, Chapter 14 & Tables 14.1, 14.2, 14.4
Recent oil price rises and energy security concerns have spurred numerous biofuels
projects and legislative incentives in the United States, Europe, and elsewhere. The IEA
projection used was taken from their reference scenario, not the alternative scenario that had
more aggressive biofuels' growth projections.
According to the IEA reference scenario, the United States, Brazil, and Europe will
continue to dominate biofuels' supply and consumption. In both the United States and Brazil, the
IEA projects that the proportion of biodiesel will slowly rise. Conversely, the IEA estimates that,
in Europe, where biodiesel currently comprises 84% of total biofuels supply, the proportion will
4-15
-------
drop steadily because the main growth is expected to lie in ethanol production. Based on IEA
and other data, current biofuels supply and consumption is assessed at approximately 75%
Northern Europe (dominated by Germany and secondarily France), 20% Southern Europe
(mainly Italy and Spain), and 5% Eastern Europe. These proportions were assumed to remain
constant throughout the period to 2020. According to the IEA, Europe's growth in biofuels
supply will result in these fuels constituting around 4.9% of total transport fuel demand by 2010,
versus a declared EU target of 5.75%. The 2020 biofuel volumes correspond to around 7.5% of
European transport fuel demand as projected in the WORLD BAU case. Relatively small
volumes of biofuels are projected by IEA to be forthcoming in Asia (led by China) and Africa. In
the WORLD cases, the majority of these biofuels were projected to be biodiesel.
Total U.S. plus Canada biofuels production was projected to reach 0.69 mmbpd by 2020,
dominated by ethanol. Ethanol was allowed to be used in RFG by adding to RBOBs at either 0%,
5.7%, or 10% ethanol by volume (maximum 5.7% for CARB RFG). Additional ethanol was
allowed to be absorbed in CG at concentrations up to 3.7 percent by weight maximum oxygen
content. In reality, a small but increasing volume of ethanol looks likely to be sold as "E85" type
gasoline. Consideration was initially given to modeling E85 as a distinct grade, but the decision
was made to not model it explicitly.
4.5.5 Regional Bunker Demands
As discussed above, the WORLD model was set up so that it could be run under both
IEA and RTI premises for bunker fuel base demand and growth. A two-step procedure was
adopted. Firstly, the bunker basis was set to "IEA," and overall and regional oil supply and
demand projections were matched to the AEO 2006 reference case for either 2012 or 2020,
respectively, 93.4 and 103.7 mmbpd. Then, the bunker basis was reset to RTFs basis. This led to
an increase in total residual and total oil demand, which was met by rebalancing supply through
raising OPEC production.
The bunker demand projections were taken directly from findings discussed in Section 3.
A primary issue here entailed the regional allocation of bunker consumption, given that the base
2003 IEA bunker demand totaled 145 mmtpa and the RTI demand is estimated at 305 mmtpa.
Table 4-6 summarizes 2003 bunker demand per IEA and the findings in Section 3 and then
projections for 2012 and 2020.
As can be seen, judgment was applied to allocate the 157 million metric tons per year
(mmta) change in demand. All regions were increased versus IEA forecasts, but with the major
increases in non-OECD areas. The regional allocations were driven in large part by the trade
4-16
-------
flows built into the shipping model developed in Section 3. The allocation was also considered
logical on the basis that bunker fuel demand is less likely to be accurately separated out and
reported in the national statistics of non-OECD regions. As discussed above, there is open
acknowledgement that bunker consumption data are incomplete. For instance, TEA data report
bunker demand for Africa at a total of only 9.5 mmtpa or 6.4% of global bunker demand.
However, Bunkerworld data on ports and companies active in bunkering list some 93 bunkering
ports spread across 38 countries in Africa and with often several suppliers active in each port.
This does not seem consistent with data indicating only minimal bunker consumption. Note that
the situation regarding these statistics and estimation reinforces that the regional allocations of
bunker demand used in the BAU cases are approximate and that further work could be pursued
to arrive at more rigorous values.
4.5.6 Regulatory Outlook for Bunker Fuels
4.5.6.1 Primary Bunker Quality Regulations
For the BAU cases, the bunker demand and quality basis was that existing regulations
would apply, but that there would be no additional regulations, thus setting the modeling
framework for later subject cases to quantify the impacts of U.S. SEC As, etc (see tables 4-6 and
4-7). Specifically:
• MARPOL Annex VI (ISO 8217 2005) specifications were applied to all international
distillate and residual bunker fuels as set out in Figures 4-2 and 4-3. MGO
specifications were taken from those for DMA and the MDO specifications from
DMC. Based on industry advice, buyers almost exclusively opt for the higher grade
versions of IFO180 and 380. These are the ISO8217 2005 grades RME and RMG,
respectively (rather than RMF and RMH). RME and RMG have tighter specifications
for carbon residue and vanadium. The carbon residue specifications, at 15 and 18,
respectively, were activated in the model to provide a limit on possible future
degradation of IFO quality. Carbon residue was also activated on the DMC MDO
blend, even though this is likely to play less of a role as sulfur limits on MDO are
tightened.
• The EU Baltic and North Sea SEC As took effect in 2006 and therefore were applied.
They were, however, "locked" at the 1.5% sulfur level, even though current EU
initiatives make it clear that the intent is to achieve the equivalent of 0.5% sulfur fuel
across a broad swath of EU waters by 2012. Note, the ISO8217 2005 specification
explicitly allows for the 1.5% sulfur grades in SEC As.
4-17
-------
Table 4-6. World Regional Bunker Sales
Bunker Sales
Region ^003 2003 Comparison
Basis IEA RTI Delta
USECa 6.0 7.5
USGICEb 8.9 11.6
USWCCWC 5.5 8.4
GrtCARd 4.5 11.7
SthAnf 5.4 16.8
AfWestf 1.2 2.3
AfN-EMg 4.6 12.3
Af-E-Sh 3.7 7.1
EUR-No1 32.4 42.3
EUR-SoJ 14.9 27.1
EUR-Eak 0.5 1.4
CaspRg1 0.0 0.0
RusFSU111 0.4 7.8
MEGulf1 10.3 25.0
Paclnd0 6.1 25.9
PacHip 37.6 57.0
China 5.4 31.5
RoAsiaq 0.3 9.2
1.5
2.6
2.9
7.2
11.4
1.1
7.6
3.5
9.9
12.2
0.9
0.0
7.3
14.7
19.8
19.5
26.1
8.9
World 147.8 304.9 157.2
a U.S. East Coast
b U.S. Gulf Coast and Interior, plus Eastern
c U.S. West Coast, plus Western Canada
d Greater Caribbean
e South America
f Africa West
8 Africa North and the Mediterranean
h Africa East and South
1 Europe North
J Europe South
k Europe East
1 Caspian Region
m Russia/Former Soviet Union
n Middle East Gulf
0 Pacific Industrialized
p Pacific High Growth
q Rest of Asia
Canada
RTI vs.
IEA
Percent
124%
130%
152%
260%
312%
186%
265%
194%
131%
182%
293%
0%
1,865%
242%
421%
152%
587%
2,853%
206%
Bunker Sales
2012
RTI
9.5
14.7
10.7
15.9
21.0
2.7
14.5
8.7
52.8
34.8
2.0
0.0
10.3
31.8
29.0
69.4
66.5
12.0
406.2
2020
RTI
11.2
17.2
12.5
21.5
24.0
2.9
16.1
10.0
60.0
42.4
2.6
0.0
12.3
36.8
31.6
78.4
101.5
14.1
495.3
Growth Rates to
from 2003
2012
RTI
2.7%
2.7%
2.7%
3.4%
2.5%
1.9%
1.8%
2.2%
2.5%
2.8%
4.0%
3.1%
3.2%
2.7%
1.3%
2.2%
8.7%
2.9%
3.2%
2020
RTI
2.4%
2.4%
2.3%
3.7%
2.1%
1.5%
1.6%
2.0%
2.1%
2.7%
3.7%
2.5%
2.8%
2.3%
1.2%
1.9%
7.1%
2.5%
2.9%
4-18
-------
Table 4-7. Summary of Bunker Sulfur Specifications Used for 2012 and 2020 BAU Cases
MGO
MDO
IFO 180/3 80
California
MGO/MDO
Annex VI /
TSOS217 FIT
2005 SECAs
1.5% 0.2% a
2.0% 1.5%
4.5% 1.5%
CA
Jan 2007
Reg.
0.5% b
Percentage of N WE Bunker
Under SECA
2012
50%
50%
50%
2020
50%
50%
50%
Percentage of Model's
USWCCW Region
MGO/MDO Under CA Jan
2007 Reg.
75%
75%
Percentage of SECA Fuel
Requirement Met by LSFO
2012
95%
95%
95%
Percentage
Under Jan
95%
2020
80%
80%
80%
of CA MGO/MDO
2007 Reg. Met by
LSFO
80%
a The EU has proposed tightening MGO to 0.1% from 2008. BAU case is on basis of 0.2%.
b CARB has proposed tightening the MGO regulation to 0.1% by January 2010, but 0.5% was used in the BAU
cases.
• Regulations currently being finalized were applied to California bunker consumption.
There are two regulatory tracks under way in the state that will be examined as part of
the future subject cases. Firstly, CARB is considering additional bunker fuel
regulation. Specifically, the CARB rule under which both MGO and MDO in
California regulated waters used in auxiliary engines must comply with a 0.5% sulfur
maximum was included in the 2012 and 2020 BAU cases. CARB is evaluating further
tightening of PM, NOX, and SOX limits on auxiliary engine emissions, including a
possible 0.1% limit for MGO by January 2010, with analysis due by July 2008. In
addition, the port authorities for Long Beach and Los Angeles have finalized their
own plans, which go beyond the CARB regulations. The San Pedro Bay Ports Clean
Air Action Plan contains measures to require ships to use MGO with a sulfur content
of less than 0.2% in their main and auxiliary engines within a 40-nautical mile zone.
The regulations will either be implemented fully in 2007-2008 or will be applied
more gradually through 2011 as shipping companies' lease agreements are
renegotiated. A report on the legality of the ports' plans by the California Office of
Administrative Law is due by December 5, 2006. Note, these regulations replace use
of IFO fuels with the highest quality marine fuel MGO, not MDO.
4-19
-------
Characteristic
Der.sty at 'r C
Viscosity 3t -40 "C
Flash porM
Pour poi'M (upper i c
— winter quality
— summer qual ty
C :oud oo:nt
Suh'j'
Cetane i-rtex
C.!rbon 'escue
on 10°i!WVidstil!3ticr
bottoms
L a'Don ~es.ci.te
Ash
Appeararce'
Tola sedtwt! £*s:ei1
Wale'
Varad'jn
AluT' nurr pi us S'licon
Used jancaligoil JULOj
- Zmc
- P"ospho^js
- Ca'Ciurr:
Unii
kg-ri?
rrrr-:,;s D
'C
*i^
'C
°o ('.Will
—
°c (V^liJ
'it f«/'"i.'
°c fi!/i;l.l
-
°-c f^..,-J
% [,'V?-|
mg;kg
mg.Kg
•rg.-kg
Tg-kg
rg'kg
Limit
nax
nin
nox
mr
nir
nax
nax
riax
TKJX
mn
nax
nax.
riax
-
nax
nax
•nax
•FV3X
nax
nax
nax
Category ISO-F-
DMX
-
1 40
550
•43
-
-•r-, 3C
P.
—
200C
—
2.50
0,05
—
C.'O
C.3
•oc
•1C
Inefjei sna-l
DS 'ree of
ULO= 15
Ir,
3C
Test method
reference
ISO 3675 or
ISO 12186
(see a;so 7 1 )
ISC 31 CM
ISC 3 10-4
ISC 27 19
(see also 72i
ISO 30 16
ISO 3016
ISC 30 15
ISO 8754 or
ISC 14596
(see also 7 3)
ISC 4264
ISC 1C370
ISO 1C370
ISC 62-5
S«e 7-1 and 7.5
ISO 10307- i
(see" 5i
ISC 3733
ISO 145970' IP FOI
(xlP-70isee7,Sl
ISO 10-1730- IPEO1
or IF -70 isee7.9i
IP5C! 0' IP 473
IP 501 o- IP 500
!P£C: 0' IP 470
isee 7 7i
-' ^te t-ult arnouo'l yeoo- -%3fr.lv Exnsstrq of distillate 'uei tie -esd-i.il oil sropQrt>on c,vi b* SKjmfican:
- 1 mm-.<; - 1 e5l
: =L-c'us-s'? sl-oj d 6'tsuie "i.T lhr« aoi.f port it. iinnn hi ;h* eqi, o-tn) or boa-d asoec J y if tie vessel OPSIJ-.SS ir ocn tie
n:;^^t-^n ard bc'..J-^-n 'lemispneres
'^ 7 *i = f J4- is SJI13JI? (O' J*e v, :ho Jt headr^ o: ambler! I'HnperaX'e J tot< "i to - It 'C
f ^ 5^- 'jl i mr. o' l-£ % iwV .-.ill 33p(v "1 SC e^-isston c^r'jo' areas desgnated 3V *>e nteTa1iol3l M,Tlt'-£ Or'33niZ3t o^. .t.tl-?l
ts -t-e.ar: oroloed enters ito 'sr-:e Tisre nu, :>e oc--> vanrisr-s. for sxamplf Me EL -equ -estha: SL piur ccfflsn' ofcerair dcslillais
grades L* miled to C 2 : : ,;f; -."I n cpna ^ ^rjpliCvt^inrs 5ee C ? 3n>; re;eie-ice "^
1' tie sample s c ear a^id /. ± 10 . sitle sec mei ". 0' .val£'. t'i6 Id;* s*?d "v'H exigent 3nc v.atef t^st^ s-iall rot -:'e required S-^
7 J me 7 5
3 A 'i^e ^r.i be ccrsirf^ted 'c •>() •'•*?*!• c( used k.:ric,»'jrg oils ;U_O:.i ^' on* or nwe o; :he ^;e"-en:s zirc ph-aspro^s 3rd ca'ctuni
ir>r L«?c.». cr 3' the sp^c^f ed imrt? All -J--ee eier-'ec'.s S'lall *-xoee:! Irtfe 53nte lir its Lrt-fo'i? 3 f ,*• shall Dfc deemed to caiki i LLCs
Figure 4-2. Requirements for Marine Distillate Fuels
4-20
-------
£ o
Z =>
r *•
^ t
o:'
x .
I 13
S 00
a: «
u. .
in W o
«-> 2 m
o: —
S
^ (
a:
Figure 4-3. Requirements for Marine Residual Fuels
4-21
-------
4.5.6.2 EUSECA Compliance
A decision process was followed to set up the 2012 and 2020 premises related to the EU
SEC As (essentially the same process will need to be followed for all other SEC As studied in the
future). The WORLD model contains projections of total bunker demand broken down into
MGO, MDO, IFO180, and IFO380 for the North Europe region.
The first step in the process was to assess the proportion/volume of each type of bunker
fuel that would fall under the SECA standard (Baltic plus North Sea in this instance) within the
region. For the two North Europe SECAs, this was estimated at 50%, equivalent to 26 mmtpa
total in 2012.3 Secondly, an assessment was made regarding how much of the affected fuel
would be low sulfur (i.e., what part of the SECA fuel requirement would be met by this means,
rather than through abatement [or emissions trading]). For 2012, the base premise was that 90%
of the bunker fuel would be low sulfur; for 2020, 60%. The underlying rationale was that
abatement technology needs time to be proven commercially and to be taken up by the shipping
fleets. This will constrain the proportion of SECA requirements that can be met by abatement (or
emissions trading) in 2012, but by 2020 its potential expands. These premises can readily be
altered and need to be in the future subject cases to examine the refining/supply impacts of
growing SECA areas and tightening emissions standards with alternative compliance scenarios.
For California, the proportion of the MGO/MDO in the WORLD model region called
USWCCW needing to comply with the California regulation was estimated at 75% (i.e., that
California's economy, trade, and shipping dominates this West Coast region). It was further
estimated that, of this, 90% of compliance would be achieved by LSFO in 2012 and 60% in 2020
in the BAU cases. Again, these premises can be revised and also sensitivities studied.
4.5.7 IFO Viscosity/Grade Mix
Many marine engines today can handle IFO with a viscosity higher than 380 centistokes.
Raising viscosity to 500 or 700 centistokes slightly reduces the cutter stock content of the bunker
fuel. In today's market, this has led to IFO 380 to IFO500 price differentials on the order of $2 to
$4/ton. This, in turn, has created a growing interest in supplies of IFO500 and even IFO700. The
trend has been especially marked in Singapore where IFO500 sales have grown rapidly in the
last 2 years. To reflect this trend, the maximum viscosity of the "IFO380" bunker grade in the
model was raised moderately.
' Robin Meech at the DC MARPOL Consultative Meeting (February 2006) estimated 2012 North Europe SECA
bunker fuel at approximately 21 mmtpa but against a base projection understood to be based primarily on IEA
statistics. This figure was adjusted to arrive at the 2012 base volume to be used.
4-22
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The global bunker market is trending toward higher viscosity fuels containing less
distillate. Since raising the distillate content of an IFO fuel is one way to lower its sulfur content,
the SECA regulations could have the effect of reversing this trend in the affected regions. The
model was not set up to allow switching from IFO 180/3 80 to MDO as a means to meet sulfur
standards. Such a feature was not considered necessary because the model was set up to allow
IFO 180/380 viscosities to be lowered, thereby allowing more distillate streams into the IFO
blend if found to be economic as the means to reduce sulfur.
4.5.8 Refinery Capacity and Projects
The WORLD model contains a detailed bottom-up database by process unit and refinery
worldwide. This is brought up to date as new refinery capacity survey data are published. EnSys
has found, however, that extensive cross-checking of and corrections to data presented in sources
such as Oil & Gas Journal (OGJ) are necessary. The BAU cases were run with a capacity
database that was based on January 2005 OGJ data plus extensive review and revision.
For forward cases, WORLD has four ways of modifying the base capacity:
1. adding known projects to the base.
2. revamping selected existing units is allowed to take place (principally conventional to
ultra-low distillate desulfurization).
3. debottlenecking selected major units is allowed, subject to annual limits.
4. entering investments in major new unit capacity.
The projects database used for the BAU cases was based on detailed review of project
announcements through the end of 2005. In WORLD, projects are classified at four levels: under
construction, under engineering, planned, and announcement. These correspond to descending
levels of follow through to completion and also an increasing tendency for project delays versus
the initial start-up target date. The model user sets parameters by region that govern both the
proportion of each class of project to be completed and the associated delay profile.
Since mid-2005 especially, there have been numerous announcements of new projects,
many for major refinery expansions or new grassroots refineries. Nearly 11 mmbpd of refinery
crude unit capacity expansion projects are currently listed, with somewhat higher figures
according to more recent project reviews. However, based on experience, factors were applied to
curtail and delay particularly the "planned" and "announcement" projects in order to arrive at a
realistic level of projects likely to go ahead.
4-23
-------
The net effect was that the 2012 and 2020 BAU cases contained a total of 6.1 mmbpd of
new project capacity as summarized in Table 4-8. (This estimate compares to a figure of around
8 mmbpd by 2015 according to a Wood Mackenzie [2006] review.) The main regions expected
to see expansions are the United States and then the Middle East, China, and the rest of Asia
(India). The growing list of project announcements in India was particularly discounted.
Capacity expansion in Europe is projected to be minimal. While Table 4-8 lists crude unit major
capacity additions, the complete project database covers the full suite of refinery processes,
including upgrading and desulfurization. In the BAU cases, the model added capacity, using first
the low-cost revamp and debottlenecking potential allowed and then balanced on major new unit
additions.
Table 4-8. Major Capacity Additions
Based Major Capacity Additions Included in 2012 and 2002 cases
Mmpbcd
USEC
USGICE
USWCCW
GrtCAR
SthAm
AfWest
AfN-EM
Af-E-S
EUR-No
EUR-So
EUR-Ea
CaspRg
RusFSU
MEGulf
Paclnd
PacHi
China
RoAsia
Total
0.0
0.8
0.1
0.4
0.2
0.1
0.1
0.1
0.0
0.1
0.0
0.1
0.0
1.4
0.0
0.0
1.6
1.0
6.1
4.5.9 Refinery Technology and Costs
Based on a review of refinery process technologies centered on desulfurization,
adjustments were made to process unit capital costs in the model. Details of the base data
researched as part of the technology review are set out in Appendix A. Technologies in the
4-24
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WORLD model represent those that are proven or recently commercialized. In any long-term
study, this approach is conservative because it does not allow for the possible effects of more far-
reaching technology advances. An example in this study that could prove to be significant in the
future is the development of ultrasound-based desulfurization processes, as in that of Sulphco.
That particular technology is nearing commercial scale with the installation of seven 30,000 bpd
units in Fujairah. Should the supplier's claims be verified by sustained operation, the outlook for
future desulfurization and partial upgrading of residual fuels, crudes, and other streams could be
markedly altered relative to the projections made in this study. Other similar developments may
also occur. Excluding such processes does have the effect of ensuring that the quantitative
modeling results are based on known, feasible, and economic process paths.
The WORLD technology database has been the subject of ongoing review. A further
review was made to check the capital and operating costs and yields of units most likely to
impact bunker fuel economics, notably residual hydro-desulfurization and visbreaking, as
described in Section 4.3.
The process unit capital costs in WORLD originally were based on the year 2000 (U.S.
Gulf Coast). The impacts of changes that have occurred since to raise costs of construction were
examined. The Nelson Farrar Refinery Construction Inflation Index was found to have risen by a
factor of 1.32 between 2000 and February 2006, driven by well-publicized increases in costs for
steel, cement, specialty equipment items, and labor. However, applying this multiplier directly to
the 2000 basis capital costs in WORLD would have had the effect of stating that the costs of new
construction would remain at this elevated level for all new investments through 2020. The large
increase in the costs of refining and other oil-sector facilities is reflected in the IEA World
Energy Outlook, 2006. IEA estimates that capital costs will "fall back somewhat after 2010"
based on conditions in the A&E sector gradually easing.
In WORLD, the decision was made to use a multiplier of 1.30 for capacity additions in
the 2012 case and 1.20 for additions in the period from 2012 to 2020 (i.e., in the 2020 case).
Similarly, Nelson indices indicate that refinery chemicals' "OVC" type costs have risen by some
60% since 2000. Multipliers of 1.50 and 1.30 were used for the 2012 and 2020 cases,
respectively.
WORLD results are sensitive to the interplay between crude (and fuel) costs, refinery
capital costs, and freight rates.
4-25
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• Raising crude oil prices results in more refinery capacity investment, especially in
upgrading processes, with the logical effect of reducing the volume of, now high-cost,
raw material used to make a given product slate.
• Raising refinery process unit costs has an opposite effect; total dollar investments
may rise, but the new capacity bought for the money is less, and the industry responds
by using somewhat more crude oil.
• Raising tanker freight rates has the effect of, in turn, justifying additional refinery
process investment in order to minimize high-cost interregional movements of crude
and products.
Part of the "dilemma" of the EPA analysis was that we have entered into a high-cost
world where the traditional levels of and relationships between capital cost, crude and fuel costs,
and transport costs are being rewritten. In the BAU cases, higher crude oil price (versus history)
was a given, hence also higher refinery fuel and natural gas prices. Both refinery capital costs
and tanker freight rates were moved upward relative to history. This resulted in scenarios where
all costs—crude, fuel, OVCs, and freight—were elevated versus historical levels.
Nelson Refinery Cost Indices
Refinery Construction
Inflation Index
Refinery Fuel Cost Index
Refinery Chemicals cost
Index
1997
2000
2003
2006
Figure 4-4. Nelson Refinery Cost Indices
4.5.10 Transportation
WORLD contains details of interregional crude, noncrude, finished, and intermediate
product movements by tanker, pipeline, and minor modes. Each tanker movement is assigned to
one of five tanker size classes, and freight costs are built up based on the Worldscale flat rate
times the percentage of Worldscale plus ancillary costs such as canal dues and lightering, where
applicable, as well as duties. Reflecting the factors reviewed above, Worldscale percentage rates
were applied (see Table 4-9) that were higher than recent freight rate history. Again these reflect
4-26
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Table 4-9. Tanker Class
Tanker Class
MR@
Pana Max
AFRA max
Suez Max
VLCC
Size DWT
40,000
55,000
70,000
135,000
270,000
Percent WS 2012/2020
260
220
180
130
90
increases in steel/construction and fuel costs plus the fact that (a) there is current tightness in
capacity in shipbuilding yards; (b) there is an ongoing requirement to turn over world fleets to
new vessels, in part because of double hull regulations; and (c) there is a need to expand the
world's tanker fleets to meet growing trade requirements.
In general, high steel prices directly impact the cost of a tanker and, thus, may place a
damper on orders for new ships. High steel prices also indicate a potential "tight" supply of steel
that can also place a constraint on shipyard contracting practices (i.e., higher prices or flexible
pricing requirements). High steel prices also increase the price paid for scrap tankers, potentially
inducing tanker owners to hasten scrapping. In general, the supply of tankers looks to be
constrained in the next few years by shipyard construction capacity. Tankers are competing for
new construction space (berths) with LNG, container, and dry bulk ships. Usually only one
sector is doing well financially, which increases pressure for new building in the strong sector.
At this time, all sectors (LNG, container, and dry bulk ships) are doing very well. This has led to
difficulty for tanker owners to secure new building contracts. This all leads to higher prices for
new buildings.
In WORLD, freight rates are arrived at by multiplying the percentage of WorldScale by
the WorldScale 100 flat rate. (Other cost items such as canal tariffs or lightering are also added
in where relevant.) One issue is that the WorldScale Association issues updated flat rates each
January. These reflect cost changes, including for fuel (i.e., the underlying flat rates are not
constant over time). To best assess how to represent future freight rate levels in the model, recent
freight rate history was examined. Figure 4-5 shows that, although bunker fuel costs have risen
4-27
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Index of Bunker Fuel Price 1989 = 100
450
400
350 ^
300
250
200
150
100
50
0
^
0.00
Spot Crude Freight Costs $/bbl
o°
o°v
Spot Clean Product Freight Costs $/bbl
Gulf/EAST
Carib./USG
Med./NWE
0.00
o
o
o
Figure 4-5. Spot Market Costs
4-28
-------
substantially since 2002-2003 and the other factors described above have been at play, most
freight rates (stated as $/bbl) have increased only slightly.
In addition, we noted that, in the planned Phase II SEC A etc. cases, tightening of bunker
fuel regulations and/or shifts from IFO to marine diesel will inevitably increase bunker fuel costs
and consequently freight rates (i.e., in those cases, freight rates will need to be adjusted upward,
potentially regionally). EnSys intends to employ an in-house tanker cost model to assess the
appropriate increases for those cases.
As a component of recent assignments, care has been taken in WORLD to build in
accurate representations of major new, expanded, and existing pipelines. Particular emphasis has
been put on ensuring an accurate profile of pipelines and expansions for export routes for crudes
(including syncrudes) from Canada and export routes both east and west from Russia and the
Caspian. For Canada, the BAU premise was that one, but not both, of the export lines to the West
Coast/PADD V/Pacific would go ahead. This impacts the amount of syncrude and conventional
crudes routed into the U.S. PADDs II, IV, and potentially III versus west to PADD V and Asian
regions. For Russia, based on recent developments, the BAU case assumed the pipeline to the
Pacific would go ahead and would have a spur into China. In reality, this latter will most likely
partially displace growing rail movements of crude into China from Russia that were already in
the model.
4.6 Input Prices for the WORLD Model
4.6.1 Marker Crude Price
WORLD operates with a single marker crude price, and all other crudes and nearly all
noncrude supplies and product demand is fixed. Crude and product prices are thus generally
produced as model outputs. For the BAU cases, the model was run with Saudi Light as the
marker crude. This crude price was taken from the AEO 2006, but since EIA uses a U.S. average
acquisition price as its "world oil price," the EIA price was adjusted to obtain a corresponding
Saudi Light price using recent historical crude price data.
4.6.2 Natural Gas Price
Certain other prices are also inputs in the model. The most important among these is
natural gas prices as natural gas is the balancing refinery fuel supply in most regions, as well as a
primary feedstock for hydrogen production. Regional natural gas prices (major industrial user)
were set in the range of $4 to $6 per MMBTU—in line with AEO 2006 and third-party long-term
projections.
4-29
-------
4.6.3 Miscellaneous Prices
Input prices for the by-products—coke low sulfur, coke high sulfur, and elemental
sulfur—were set respectively at $25, $5, and $10 per ton. Purchased electricity prices were taken
for the U.S. regions from AEO 2006 and were generally in the range of 6 cents per kWh.
4.7 Reporting
The WORLD model's standard reports were modified to accommodate the revised
distillate and residual fuels products structure. Standard reports provide global and regional
information on
• refinery throughputs, capacity additions, investments;
• interregional crude, intermediate and product movements;
• supply/demand balance;
• crude FOB and GIF prices; and
• regional product prices.
As discussed in Section 4.4, blend reports were added for the residual grades, in part as a
check to ensure avoidance of potentially unstable blends.
4-30
-------
SECTION 5
THE WORLD MODEL'S BAU PROJECTIONS FOR 2012 AND 2020
This section presents results for the 2012 and 2020 WORLD model cases, based on the
projections and premises reviewed in Section 4. Business as usual (BAU) projections were
estimated for these 2 years using both the TEA and the RTI bunker demand assumptions.
Adopting the RTI fuel demand forecasts leads to a 2020 global demand for residual
bunker fuels of 6.87 mmbpd versus 1.92 mmbpd based on IEA forecasts. RTFs larger estimate is
partially offset by a reduction in inland residual fuel from 6.5 to 5.2 mmbpd. RTFs 2020
forecasts for MGO and MDO are equivalent to 1.9 mmbpd versus 0.6 mmbpd based on IEA
forecasts. Thus, RTFs forecasts imply that estimated impacts of SEC As or other marine fuels
regulations will be greater than those projected by IEA forecasts.
The second major driver in the WORLD analyses discussed in this section is the ongoing
shift toward distillates, especially in Europe and non-OECD regions. This shift is expected to
materially alter gasoline and distillate trade patterns, pricing, and refining investments. These
developments will also affect impacts of SEC As and global marine fuels regulations.
5.1 Supply-Demand Balance
Tables 5-1 and 5-2 summarize the supply and demand inputs and model run results from
the 2012 and 2020 WORLD BAU cases for both the RTI and the IEA forecasts. As discussed in
Section 4, the IEA base case was matched to the AEO 2006. A second case was run with RTFs
forecast, which increases bunker and total residual demand globally. The needed incremental
supply was taken to be OPEC crude. WORLD results generally do not match exactly the
underlying forecast numbers for total oil supply and demand. This is because several demand
factors, including internal refinery fuel, coke, and sulfur by-products, are dynamic within
WORLD and not fixed.
The 2012 and 2020 cases reflect the overall global trend for (a) an increase in demand to
be predominantly light, clean products and (b) growth globally to be concentrated in distillates,
particularly as diesel consumption in Europe increases and the demand growth for gasoline there
subsides.
The main effect of applying the RTI bunker projections is to raise total residual demand
by 1 mmbpd by 2012 and over 1.8 mmbpd by 2020. Increasing demand also entails a switching
5-1
-------
Table 5-1. WORLD Model Case Results—Supply
Bunker Basis
Supply — Crudes (includes syncrudes and condensates)
Crude gross production
of which
Grade direct use
Grade direct loss total
Grade net to refineries before TRLOS
Crudes net to refineries
GSY — syn crude (fully upgraded)
GCO — condensate
GSW— sweet <0.5%S
GLR— LT ST>35 API>0.5%S
GMR— MD SR 36-29 API > .58
GHR— HVY SR 20-29 API>.5S
GXR— XHVY SR <20 API>.5S
Grade supply to refineries
Grade direct loss in refineries
Grade TRLOS
Crude net, to refs before TRLOS
Supply — Noncrudes
NGL ethane
NGLs C3+
Petchem returns
Biomass
Methanol (EX NGS)
GTL liquids (EX NGS)
CTL liquids (EX COAL)
Hydrogen (EX NGS)
Total
Process Gain
2012
IEA
MMBPD
79.637
0.832
0.638
78.167
After
TRLOS
1.164
1.922
26.257
11.022
25.813
9.067
2.149
77.395
0.638
0.135
78.167
1.597
5.587
0.709
1.527
0.130
0.796
0.488
0.981
11.815
2.223
2012
RTI
MMBPD
80.352
0.832
0.638
78.882
After
TRLOS
1.164
1.922
26.473
11.214
26.055
9.131
2.149
78.108
0.638
0.136
78.882
1.597
5.587
0.709
1.527
0.128
0.796
0.488
0.940
11.771
2.151
2020
IEA
MMBPD
86.667
0.832
0.638
85.197
After
TRLOS
1.555
2.062
29.432
10.806
28.140
9.529
2.882
84.405
0.638
0.154
85.197
1.797
6.387
0.789
1.866
0.146
1.248
0.891
1.307
14.431
2.602
2020
RTI
MMBPD
88.160
0.832
0.638
86.690
After
TRLOS
1.555
2.062
29.771
11.122
28.871
9.633
2.882
85.896
0.638
0.156
86.690
1.797
6.387
0.789
1.866
0.146
1.248
0.891
1.205
14.328
2.509
5-2
-------
Table 5-2. WORLD Model Case Results—Demand
Bunker Basis
External Demands — Finished Products Nonsolid
Ethane
LPG
Naphtha
Gasoline
Jet/kero
Distillate
Residual fuel
Other products (excl coke, sulphur)
Crude direct use
Petr coke low sulphur MMBPD
Petr coke high sulphur MMBPD
Petr coke LS as % of total
Petr coke total MMBPD
Elemental sulphur MMBPD
Total
Internal Demands/Consumption
Refinery fuel — crude-based streams
Process gas
FCC catalyst coke
Minor streams
Residual fuel
Natural gas to RFO
Total incl natural gas
RFO incl NGS as pet of crude to refs
RFO excl NGS as pet of crude to refs
Merch FO — internal streams
Total internal consumption and loss excl nat gas
Transport/distribution losses
Transport loss total
Allocation to crude
Allocation to products and intermediates
Supply— Total
Crude — gross production incl condensates and syn crudes
Noncrudes incl H2 ex NGS
Process gain
2012
IEA
1.597
7.856
5.850
23.535
7.459
27.255
10.082
3.532
0.832
0.416
0.527
44%
0.943
0.215
1.158
2.458
0.377
0.000
1.291
1.641
5.766
7.5%
5.3%
0.005
4.130
0.189
0.135
0.054
WORLD
79.637
11.815
2.223
2012
RTI
1.597
7.856
5.850
23.535
7.459
27.128
11.088
3.532
0.832
0.442
0.240
65%
0.681
0.193
0.874
2.415
0.388
0.000
1.291
1.614
5.708
7.3%
5.2%
0.005
4.099
0.190
0.136
0.054
WORLD
80.352
11.771
2.151
2020
IEA
1.797
8.632
6.930
25.426
8.139
31.459
10.235
3.808
0.832
0.352
0.906
28%
1.259
0.261
1.520
2.574
0.379
0.000
1.682
1.813
6.448
7.6%
5.5%
0.007
4.641
0.215
0.154
0.061
WORLD
86.667
14.431
2.602
2020
RTI
1.797
8.632
6.930
25.426
8.139
31.298
12.060
3.808
0.832
0.405
0.510
44%
0.914
0.229
1.143
2.477
0.383
0.000
1.682
1.849
6.391
7.4%
5.3%
0.007
4.548
0.219
0.156
0.063
WORLD
88.160
14.328
2.509
(continued)
5-3
-------
Table 5-2. WORLD Model Case Results—Demand (continued)
Bunker Basis
Total Supply
Grade as percentage of total supply
Demand — Total
External — gases and liquid products (incl crude direct use
but not loss)
External — solid products
Internal — fuel excl natural gas incl FCC cat coke
Internal — process and crude losses
Internal — transport/distribution losses
Total Demand
Total demand — total supply
Total demand — total supply
2012
IEA
93.675
85%
87.998
1.158
4.130
0.000
0.189
93.475
(0.21%)
(0.200)
2012
RTI
94.275
85%
88.877
0.874
4.099
0.000
0.190
94.040
(0.25%)
(0.234)
2020
IEA
103.699
84%
97.258
1.520
4.641
0.000
0.215
103.634
(0.06%)
(0.065)
2020
RTI
104.998
84%
98.922
1.143
4.548
0.000
0.219
104.832
(0.16%)
(0.166)
between inland and bunker residual fuel grades. In the lEA-basis BAU cases, global inland
residual fuel quality was projected to progress partially toward a 1% standard by 2020. The RTI-
basis BAU cases increase total residual fuel demand, but, because the only active SECAs are in
Northern Europe in the cases, they shift global residual fuel toward higher average sulfur.
The change in overall global demand between the IEA and RTI cases is 0.6 mmbpd for
2012 and 1.3 mmbpd for 2020. The increase in residual demand is met by an increase in OPEC
crude runs. The incremental crude supply contains both light and heavy cuts..
5.2 Refining Capacity Additions
Table 5-3 and Table 5-4 summarize the refinery capacity additions, investments, and
utilizations for each case. Again, a major effect of the RTI basis is to ease the requirement for
residual fuel upgrading and desulfurization. As a consequence, less refining investment is needed
by 2020 under the RTI basis ($107.7 billion) than under the IEA basis ($117.6).1 The effect is to
1 The capital investments detailed in current WORLD reports are generally lower than those projected by the IEA,
for example, for the same time frame. There are three reasons for this. First, the WORLD costs are currently
reported in 2001 dollars. This will be changed in the future. Second, the stated WORLD investments generally
need to be increased to allow for extra capacity to cover seasonal variations (e.g., summer gasoline peak). Third,
the WORLD reports do not include an allowance for ongoing capital replacement. This is typically estimated at
1.5% to 3% per annum of the total installed capital base (which, of course, grows over time). It is EnSys' intent
to expand the WORLD reports in the future to make the basis consistent with IEA and others.
5-4
-------
Table 5-3. Capacity Additions and Investment
Bunker Basis
Capacity Additions and Investments — Over and Above 2005
Refinery
Revamp
Debottlenecking
Major new units
Total refining
Merchant
Major new units
Total refining + merchant
Crude Distillation Base Capacity and Additions
Base capacity
Firm construction
Debottlenecking additions
Major new unit additions
Total additions over base
Total crude unit capacity used
Secondary Processing Capacity Additions —
Debottlenecking + Major Units
Coking + visbreaking
Catalytic cracking
Hydro-cracking
Catalytic reforming — incl revamp
Catalytic reforming
Desulphurization (total)
Gasoline— ULS
Distillate ULS — incl revamp
Distillate ULS — revamp only
Distillate conv/LS
VGO/resid
Hydrogen (MMBFOED)
Sulphur plant (TPD)
MTBE to iso-octane (revamping USA)
2012 2012 2020
IEA RTI IEA
Base + Known
<
$5.4
$0.5
$58.2
$64.1
$0.3
$64.4
83.74
5.82
0.92
2.07
8.80
83.6%
77.39
0.10
0.10
0.70
1.16
0.54
7.16
1.81
4.93
4.25
0.16
0.26
0.52
6,350
0.08
Construction
8 billion ($2001)
$5.3 $6.4
$0.5 $1.4
$54.9 $109.8
$60.7 $117.6
$0.3 $0.9
$61.1 $118.5
mmbpcd
83.74 83.74
5.82 6.08
1.01 1.80
2.66 7.87
9.49 15.74
83.8% 84.9%
78.11 84.41
0.13 0.25
0.16 0.39
0.48 3.48
1.10 2.02
0.53 0.92
6.91 11.18
1.72 2.70
4.79 7.02
4.22 6.25
0.17 0.44
0.23 1.01
0.48 0.87
5,400 14,400
0.08 0.08
2020
RTI
$6.1
$1.2
$100.4
$107.7
$0.9
$108.6
83.74
6.08
1.90
9.04
17.01
85.3%
85.90
0.15
0.25
2.85
2.03
1.01
10.12
2.62
6.68
6.02
0.41
0.41
0.75
9,230
0.08
5-5
-------
Table 5-4. Refinery Capacity Additions
ss:
Sfe!
Sr
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5-6
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reduce the required capacity additions for coking/visbreaking, catalytic cracking, and especially
hydrocracking facilities. Vacuum gas oil/residual desulfurization requirements drop under the
RTI basis because demand for low-sulfur inland residual fuel is less. Similarly, the increase in
proportion of the total distillate pool occupied by bunker products moderately lowers the
proportions of ultra low-sulfur diesel in the distillate pool and thereby reduces the total
requirement for distillate desulfurization slightly.
The WORLD model projects that refinery utilization rates will continue to rise globally
through 2020. This stems in part from an assumption that levels in current low-utilization regions
(notably Russia/FSU, Caspian, Africa) will gradually improve. Appreciable capacity growth is
projected for North America, South America, Africa, and Russia as driven by AEO projections
of regional demand growth. The most significant refinery capacity growth areas are projected to
be the Middle East and Asia, led by China, which is projected to double its capacity by 2020.
Conversely, essentially no crude capacity growth is projected for Western Europe and only a
modest increase for Eastern Europe.
5.3 Refining Economics and Prices
Tables 5-5 and 5-6 summarize key price results from the 2012 and 2020 cases. In
reviewing these results, it should be noted that the WORLD model was run for 2012 and 2020 in
"long-run" mode. In other words, opportunities for investment were kept open, and price results
equate to long-run equilibrium prices, not short-run ones under which investment opportunities
are not permitted. Long-run equilibrium prices are more stable than short-run prices because they
incorporate an assumed long-run return on capital. Short-run prices can be relatively higher or
lower, depending on whether refining capacity is tight as it is currently or slack.
A central feature of these and other recent EnSys WORLD cases is that the global higher
growth rates for distillates relative to gasoline, driven by Europe's dieselization policy and
distillate-oriented demand growth in many non-OECD regions, lead to a situation where future
distillate prices are projected to exceed those for gasoline. Projected ultra low-sulfur diesel to
ultra low-sulfur gasoline premiums lie in the range of $3/bbl USGC by 2012 and 2020, and up to
$7 to $9/bbl in Asia and especially Europe.
Table 5-6 summarizes (long-run) price differentials as output from the WORLD cases.
For ultra low-sulfur diesel versus high-sulfur IFO380, differentials average $14/bbl. Light-heavy
product price differentials (gasoline and diesel to IFO380) narrow by around $l/bbl USGC and
5-7
-------
Table 5-5. Product Prices
Bunker Basis
Crude Prices Selected Major Crudes (FOB)
Saudi Arabian light (33.4, 1.8)
input — marker crude price
WORLD Output Prices
Texas West Intermediate (40.1, 0.4)
Texas West Sour (34, 1.9)
COM Deep Sour (35, 1.3)
UK North Sea Brent (36.9, 0.3)
Nigerian Bonny/Light (38.3, 0.14)
Nigerian Medium (25, 0.28)
Russia Urals (32.5, 1.56)
UAE Dubai (32.6, 1.96)
Iraq Basrah (33. 9, 2.08)
Saudi Arabian Heavy (28.2, 2.84)
Alaskan North Slope (30, 1.05)
California SJV Heavy (14.1, 1.06)
Mexican Isthmus (32.8, 1.51)
Mexican Maya (22, 3.3)
Venez Heavy (Bach Light) (17.4, 2.8)
Canadian Light (42.5, 0.3)
Canadian Heavy (25, 2.8)
Canadian Syncrude (33.5, 0.05)
Product Prices
WORLD Output Prices
USGC
LPG
Petchem naphtha
CG— ULS Premium
CG— ULS Regular
RFC— Premium (0/5.7/10% ETOH)
RFC— Regular (0/5.7/10% ETOH)
Kero/jet JTA/A1
DSL NO2 ULSD (50-10 ppm)
2012
IEA
$44.10
$47.68
$46.67
$46.90
$45.54
$46.32
$46.16
$44.49
$43.50
$42.04
$41.51
$43.72
$42.54
$45.94
$40.71
$41.42
$46.13
$38.65
$47.44
$45.20
$40.31
$54.81
$51.10
$52.33
$48.36
$52.78
$55.08
2012
RTI
$44.10
$47.61
$46.71
$46.92
$45.46
$46.17
$45.90
$44.63
$43.58
$42.35
$41.94
$43.73
$42.75
$45.94
$40.79
$41.45
$46.03
$38.74
$47.36
$45.08
$40.45
$54.96
$51.18
$52.40
$48.33
$52.59
$54.73
2020
IEA
$45.50
$49.30
$47.92
$48.34
$47.07
$48.06
$47.40
$45.95
$44.74
$43.25
$42.53
$45.29
$44.05
$47.22
$41.52
$42.42
$46.88
$39.33
$49.25
$46.46
$41.51
$56.16
$52.77
$53.38
$49.71
$54.75
$56.96
2020
RTI
$45.50
$49.07
$48.07
$48.31
$46.84
$47.66
$47.27
$45.97
$44.85
$43.66
$43.12
$45.60
$44.99
$47.34
$41.99
$42.78
$46.64
$39.85
$48.94
$46.63
$41.31
$55.90
$52.45
$53.10
$49.35
$54.49
$56.67
(continued)
-------
Table 5-5. Product Prices (continued)
Bunker Basis
MGO NO2 HSD (5,000-15,000 ppm)
MOD NO4 HSD (5,000-20,000 ppm)
Resid <3%
Resid .3-1.0%
IFO180 HS
IFO380 HS
Petchem gas oil
Aromatics
Lubes and waxes
Asphalt
Northwest Europe
LPG
Petchem Naphtha
RFC— Premium (EURO IMV/V)
RFC— Regular (EURO IMV/V)
Kero/Jet JTA/A1
DSL NO2 RFD
MGO NO2
MOD NO4 HSD (5,000-20,000 ppm)
MOD NO4 LSD (10-l,500ppm)
Resid <3%
Resid .3-1.0%
IFO180 LS
IFO180 HS
IFO380 LS
IFO380 HS
Aromatics
Lubes and Waxes
Asphalt
2012
IEA
N/A
$47.28
$49.61
$44.60
$42.49
$41.56
$51.00
$55.73
$66.97
$34.99
$46.52
$40.53
$51.74
$48.31
$54.09
$57.32
$50.50
$46.00
$46.50
$48.34
$43.61
$43.73
$43.43
$42.85
$42.27
$54.16
$70.55
$37.41
2012
RTI
$50.33
$48.08
$49.34
$44.51
$42.38
$41.49
$51.12
$55.84
$67.15
$35.13
$46.40
$40.51
$51.82
$48.33
$53.94
$57.02
$50.43
$46.81
$47.44
$47.60
$43.33
$44.52
$44.36
$43.50
$43.30
$54.32
$70.53
$37.88
2020
IEA
N/A
$48.65
$50.18
$44.48
$43.37
$42.31
$52.69
$57.39
$71.22
$35.00
$47.81
$41.96
$53.11
$49.37
$56.24
$58.96
$52.75
$48.05
$48.87
$49.29
$45.24
$45.50
$43.97
$44.55
$42.63
$55.97
$73.33
$36.92
2020
RTI
$51.91
$49.78
$50.63
$45.52
$44.01
$43.01
$52.74
$56.77
$71.09
$36.13
$47.98
$41.62
$52.80
$49.03
$56.02
$58.73
$52.55
$48.95
$49.22
$49.10
$44.98
$46.19
$44.80
$45.15
$44.65
$55.07
$73.21
$38.52
(continued)
5-9
-------
Table 5-5. Product Prices (continued)
Bunker Basis
Pacific (Singapore)
LPG
Petchem naphtha
RFC— Premium (EURO IMV/V)
RFC— Regular (EURO IMV/V)
Kero/jetJTA/Al
DSL NO2 RFD
DSL NO2 LSD (500 ppm)
DSL NO2 MSD (1,000-5,000 ppm)
DSL NO2 HSD (5,000-10,000 ppm)
MGO NO2 HSD (5,000-15,000 ppm)
MOD NO4 HSD (5,000-20,000 ppm)
Resid <3%
Resid .3-1.0%
Reside 1.0-3.0%
IFO180 HS
IFO380 HS
Aromatics
Lubes and waxes
Asphalt
2012
IEA
$48.80
$41.19
$52.37
$49.53
$54.56
$56.00
$55.10
$54.15
$53.67
$53.13
$45.66
$48.08
$45.35
$43.88
$42.66
$41.34
$51.68
$65.77
$35.56
2012
RTI
$48.69
$41.18
$52.44
$49.57
$53.94
$55.27
$54.47
$53.47
$53.05
$52.61
$46.89
$48.37
$45.80
$44.46
$43.67
$42.55
$51.85
$66.28
$37.73
2020
IEA
$50.10
$43.13
$54.97
$51.89
$57.19
$58.56
$57.77
$56.78
$56.16
$55.46
$47.19
$50.13
$46.80
$44.50
$43.96
$42.50
$53.48
$70.12
$34.99
2020
RTI
$50.27
$42.69
$54.59
$51.46
$56.49
$57.92
$57.10
$56.01
$55.34
$54.59
$47.91
$50.08
$47.13
$45.28
$45.19
$43.95
$52.59
$69.99
$38.12
$2/bbl Europe and Asia for 2020. The effect is less marked in 2012 because the impact on
residual fuel demand volumes is smaller. In the BAU cases, only the Northern European SEC As
were included. Thus, it is the Northwest Europe prices that provide the best insight into the
pricing of high- versus low-sulfur marine fuels. For IFO180 and IFO380 (nominal sulfur limits
of 4.5% for high sulfur and 1.5% for low sulfur, respectively), the indicated price differential is
around $l/bbl. For low- versus high-sulfur MDO, it is lower. The price differentials appear to be
reasonable as a starting point for examining the effects of wider SEC A designations and/or a
further tightening of marine fuels standards regionally and/or globally. Such developments,
which would be the subject of follow-up WORLD cases, will raise price differentials versus
those seen here with the degree of change dependent on specific scenarios for sulfur
specifications and for the compliance methods used by shippers.
5-10
-------
Table 5-6. Product Price Differentials
Bunker Basis
Product Price Differentials
WORLD Output Prices
USGC
CG ULS REG— IFO380 HS
DSL ULSD— IFO380 HS
MDO HS— IFO380 HS
RESID 1% S— IFO380 HS
IFO180 HS— IFO380 HS
CG ULS REG— DSL ULSD
DSL ULSD— MDO HS
Northwest Europe
RFC REG (EURO)— IFO380 HS
DSL ULSD (EURO)— IFO380 HS
MDO HS— IFO380 HS
RESID 1% S— IFO 380 HS
RESID 1% S— IFO180 HS
IFO180 LS— IFO380 LS
IFO 180 HS— IFO380 HS
RFC REG (EURO)— DSL ULSD (EURO)
DSL ULSD (EURO)— MGO
DSL ULSD (EURO)— MDO HS
MDO LS— MDO HS
Pacific (Singapore)
RFC REG (EURO)— IFO380 HS
DSL ULSD (EURO)— IFO380 HS
MDO HS— IFO380 HS
RESID 1% S— IFO 380 HS
IFO 180 HS— IFO380 HS
CG ULS REG— DSL ULSD
DSL ULSD— MDO HS
2012
IEA
$9.54
$13.53
$5.72
$3.04
$0.93
-$3.98
$7.80
$6.04
$15.05
$3.74
$1.34
-$0.13
$0.89
$1.16
-$9.01
$6.82
$11.32
$0.50
$8.19
$14.66
$4.32
$4.01
$1.32
-$6.47
$10.34
2012
RTI
$9.69
$13.24
$6.59
$3.02
$0.89
-$3.55
$6.65
$5.03
$13.72
$3.51
$0.04
-$1.18
$1.01
$1.06
-$8.69
$6.59
$10.21
$0.63
$7.02
$12.72
$4.34
$3.25
$1.12
-$5.70
$8.38
2020
IEA
$10.46
$14.65
$6.34
$2.17
$1.06
-$4.19
$8.30
$6.74
$16.33
$5.42
$2.61
-$0.26
$0.95
$1.34
-$9.59
$6.21
$10.91
$0.82
$9.40
$16.06
$4.69
$4.30
$1.47
-$6.66
$11.37
2020
RTI
$9.44
$13.66
$6.77
$2.52
$1.01
-$4.22
$6.89
$4.38
$14.08
$4.30
$0.33
-$1.21
$1.04
$0.15
-$9.70
$6.18
$9.78
$0.26
$7.51
$13.97
$3.96
$3.18
$1.23
-$6.46
$10.01
5-11
-------
5.4 Crude and Product Trade
Figures 5-1 through 5-6 summarize interregional trade movements from WORLD for the
2012 and 2020 RTI basis cases. Major trends and highlights on crude trade include the
following:
• Growing production from West and North Africa (totaling nearly 12 mmbpd by 2020)
offsets some of the decline in North Sea production. Significant volumes move into
the US PADDs I, II, and III as well as into Eastern Canada.
• West African crudes are widely distributed, including to the Caribbean/South
America, Europe, Asia/Pacific, and even the U.S. West Coast.
• Considerable uncertainty continues to exist over future Russian crude production
volumes and export routes. The 2012 and 2020 cases were run with export options
open with the result that Russian crudes continue to move in substantial volumes into
Western and Eastern Europe but otherwise move predominantly into Asia/Pacific. No
Russian crude is projected to be exported to the United States, although this could
change if northerly routes via Murmansk and the Baltic are expanded. Russian crude
production was projected at below 11 mmbpd for 2020 with domestic demand
growing to 6.5 mmbpd. This, in turn, reduces the volume of crude available for
export.
• Middle Eastern crudes are projected to be refined increasingly within the region as
the region's export refining capacity grows and demand in Asia/Pacific grows.
Continuance of movements into Europe and the United States depends on the level of
competition with other suppliers and on discounting policy by Saudi ARAMCO and
other Middle East Gulf producers.
• The 2012 and 2020 cases are exhibiting a new phenomenon that bears further
investigation, relating ultimately to the level of Canadian crude production. The AEO
2006 has a high level of Canadian production: 4.5 mmbpd in 2020. Even with western
outlets to the Pacific and the U.S./Canada West Coast expanded to a projected 0.8
mmbpd, the high production volume moves predominantly into the U.S. interior
(PADDs II, IV, and potentially some to PADD III). This has the effect of reallocating
Caribbean crude to Europe and reallocating Middle Eastern crude to Asia/Pacific, the
highest demand growth area.
5-12
-------
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5-13
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5-14
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5-15
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5-17
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Figure 5-6. Residual Bunker
5-18
-------
The period through 2020 will witness continued growth in trade of finished and
intermediate products, as illustrated by the WORLD case results. The case projections point to
the following main trends:
• Increases in product volumes being shipped into and between Asia/Pacific regions.
• Continued products and intermediates exports from Russia, mainly into Europe but
also into the United States and Far East.
• Potentially major exports from Europe of gasoline, on the basis of continuing
dieselization. WORLD cases indicate these exports growing to over 1.75 mmbpd by
2020. However, the cases also show the premium for diesel in Europe at $9/bbl above
gasoline, which raises questions about whether European authorities and consumers
will continue to opt predominantly for diesel vehicles.
Should dieselization continue, its impacts on product trade patterns will be far
reaching; 2020 exports of European gasoline to the United States are projected at
close to 1 mmbpd with other destinations likely to include Africa, Asia, and the
Caribbean. Offsetting the gasoline exports are a projected 1.65 mmbpd (2020) of
distillates imports from Russia, Caspian, Caribbean, and Africa.
• With U.S. refining capacity projected to not keep up with demand, gasoline imports
continue to rise into the U.S. East Coast (nearly 1.4 mmbpd into PADD I in 2020
from Europe, Caribbean, South America, Africa, and Russia) but also are indicated
into the U.S. Gulf Coast and Interior (over 0.4 mmbpd net) and the U.S. West Coast
(0.3 mmbpd net).
• Interregional movements of residual fuels are projected as limited, except for small
volumes of low-sulfur residual moving into the U.S. East Coast and of high-sulfur
residual and vacuum gas oil streams from Russia, mainly into Europe.
• This situation is projected as applying to residual bunker fuels (Figure 5-6), although
shifts in assumed locations of bunker demand could well lead to changes in trade
patterns.
5.5 Bunker Fuels' Quality and Blending
The current WORLD version does not possess standard reports for the details of fuel
blends. For the BAU cases, spot blends were inspected. MGO blends included light and middle
distillate streams characteristic of a lower quality, higher sulfur No. 2 type fuel. MDO No. 4 fuel
blends included heavier streams, consistent with a minimum API gravity allowed of 22.3, and
tended to limit on sulfur, and carbon residue (maximum 2.5%). Blend components included
vacuum gas oils and small proportions of atmospheric and vacuum residua, subject to the limits
placed by carbon residue, sulfur, viscosity (14 cks max at 40°C), and gravity.
The residual IFO blends for 2012 and 2020 comprised predominantly vacuum and
visbroken residual cut back with kerosene cutter stock plus small constrained (max 5%) volumes
5-19
-------
of FCC clarified oils. In a departure from historical patterns, the blends contained small
proportions at most of atmospheric residual and no vacuum gas oils. (A traditional IFO blend
would contain either atmospheric residual and cutter stock or a mix of vacuum residual and
vacuum gas oil and cutter stock.) This development in the blend compositions would appear to
be logical given that global demand growth is predominantly for light clean products that can be
readily produced inter alia from vacuum gas oils via catalytic and hydro-cracking. In other
words, in the future, vacuum gas oil will be too valuable as potential gasoline and distillate to
blend into bunker fuels. It will be more economical to blend in vacuum and visbroken residua
plus a higher than traditional quantity of kerosene, which is the most effective cutter stock by
virtue of its low viscosity. The IFO blends are universally limited on maximum viscosity. Sulfur
was a limiting constraint on the low-sulfur (1.5% nominal) blends but otherwise rarely
constrained (at 4.5%).
The indicated shift in residual bunker blend compositions does raise questions. First, in
the model cases, expansion of visbreakers was partially constrained because the general trend has
been to invest in cokers. Shifting to the RTI bunker basis from IEA led to a significant cut back
in coker throughputs because of the rise in residual fuel demand. For 2020, the global coker
throughput was 4.7 mmbpd in the IEA basis case and 3.7 under the RTI basis. However, the case
allowed little additional visbreaker throughput/capacity addition. Yet an increase in demand for
residual bunker fuels argues for an increase in attractiveness of visbroken vacuum residua. In
short, the BAU cases should arguably be tested with additional visbreaking allowed. Unlike
residual desulfurization, visbreaking is a low-cost process and one refiners could readily engage
in.
The second question these blends bring forward is an operational one. Namely, are there
any operational issues with residual bunker blends that comprise "dumbbell" blends of kerosene
with visbroken and vacuum residua?
5-20
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SECTION 6
TECHNOLOGY CONSIDERATIONS
RTI examined the various technology considerations associated with clean fuel
requirements in the marine sector. There is a linear relationship between the sulfur content of
fuel and SOX emissions, and this chapter reviews the technology alternatives that may be
available to ocean-going ships to comply with SECA emissions requirements. MARPOL Annex
VI explicitly allows for onboard abatement as an alternative means for meeting SOX
requirements, thus recognizing that the ultimate goal is a reduction in SOX emissions rather than
a reduction of fuel sulfur content per se.
The objectives of this section are to identify the compliance options available to the
marine vessel operators and to characterize the compliance options in terms of technology
applicability (for different marine vessels or market sectors), emissions reduction, and costs. A
thorough understanding of the technically feasible alternatives is essential because it will bound
the decision possibilities available to affected stakeholders and will greatly influence the burden
of potential SECA requirements.
This section provides technical background descriptions, cost information, and emissions
reduction potential for three onboard emissions abatement alternatives:
• fuel switching
• in-engine fuel mixing
• exhaust-gas scrubbing
The data were combined with Navigistics' and RTFs in-depth knowledge of marine
vessels, the shipping industry, and these technology options. RTI incorporated data, as available,
from various studies on these technology issues conducted in U.S. (primarily California) and
European markets. We also received input from leading technology providers such as MAN
B&W, Wartsila (Sulzer), marine engineers, oil companies, industry associations (e.g.,
INTERTANKO), and vessel operators through technical literature (reports and presentations)
and personal interviews to gather additional information. These sources and the experience of the
RTI team, together with EPA's input, provided the expertise to identify technically feasible
compliance options and to analyze their control costs.
In considering the impact of low sulfur fuel requirements on fuel volumes and costs, RTI
considered scenarios with and without the use of scrubbers on limited vessels. EPA provided
scrubber penetration scenarios for 2012 and 2020.
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6.1 Fuel Switching
Since the first oil shock in the early 1970s, the primary goal in ship power plant design
has been to reduce fuel costs. Reducing fuel costs has come about through two primary
mechanisms:
• improvement of the fuel efficiency by reducing the specific fuel consumption (SFC)
of the engines
• facilitation of marine power plants to burn lower quality and lower cost per ton fuel
This approach to marine power plant design has been very successful, with large, slow-speed,
2-stroke marine diesel engines replacing steam power plants on virtually all large ships.1
Prior to the 1973-1974 oil shock, the primary goal of ship diesel engine designers had
been to increase engine output to meet the demand of larger ship sizes and greater power
requirements. Steam power plants were installed on vessels that required more power than was
available from diesel engines. Steam power plants cost less to install (on a dollar per horsepower
basis) but were significantly less fuel efficient than diesel engines of similar sizes. SFC on the
largest and most efficient marine steam turbine power plants was about 212 grams per shaft
horsepower-hour (at full power and maximum efficiency), while marine diesel engines were
achieving test-bed SFCs of 165 grams per brake horsepower-hour. Despite diesel engines'
greater fuel efficiency, steam power plants of that era were able to burn lower quality, and
therefore lower cost, residual fuel (e.g., bunker "C").
Following the oil shocks, diesel manufacturers shifted their emphasis from engine output
to improved fuel efficiency and the ability to operate on lower quality fuels (Institute of Marine
Engineers [IME], 1979). Marine diesel engine manufactures developed engines that were
capable of running on these low-quality fuel oils. Prior to the introduction of large slow-speed
diesel engines, marine diesel engines were medium-speed, 4-stroke engines that required higher
quality distillate fuel oil for both full-time operation and operation during maneuvering (i.e.,
when speed changes rapidly, such as during in-port operations).
Today's marine diesel engines for ships are slow-speed, 2-stroke marine diesel engines
that typically operate on residual fuel oils at virtually all times. These power plants are
sometimes referred to as "unifuel" plants (Herbert Engineering Corp., 2007). SFC is
approximately 135 grams per brake horsepower-hour, though some manufacturers claim that
1 LNG tankers continued to use steam power plants because of the availability of LNG boil-off for propulsion fuel.
Diesel engine manufacturers have now introduced engines that are capable of running on traditional marine fuels
and LNG boil-off. These new engines are typically referred to as "dual fuel" engines.
6-2
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they are achieving test-bed measurements below 115 grams per horsepower-hour. Such SFCs
approach Carnot cycle efficiencies (i.e., theoretical maximum efficiency) for a diesel engine
(Aabo, 2007). Noted exceptions to full-time residual fuel consumption include preparation for
long-term shutdown for overhaul and emergencies, when fuel heating capability is lost. As
experience was gained with main diesel engines operating on residual fuel, engine manufacturers
began producing smaller engines that also could run on residual fuels. These smaller "auxiliary"
engines are used on ships for generators or as prime movers on smaller vessels.
However, improving fuel efficiency through engine design does little to reduce SOX
emissions beyond that associated with a reduction in fuel consumption. There is a linear
relationship between the sulfur content of fuels and SOX emissions. Thus, one immediate focus
for reducing shipboard SOX emissions is on reducing the sulfur content of the fuel burned. With
the current establishment of SEC As and the expected future establishment of more SEC As in
various areas around the world, it is anticipated that the easiest, although not necessarily most
cost-effective, approach to SEC A compliance will be through the use of fuel with lower sulfur
content by weight. Because of the cost differential of low-sulfur fuel, it is also anticipated that
ship owners and operators will try to burn low-sulfur fuel when in the SECA but not elsewhere.
This section addresses the practicality of switching from IFO to low-sulfur IFO or MDO
when in a SECA.2 Section 2.1 reviewed various marine fuel types. This section addresses
• shipboard fuel pretreatment and heating plants;
• burning of low-sulfur fuel in marine diesel engines;
• practicality of switching to low-sulfur fuels in SECAs;
• other fuel switching-related approaches to using low-sulfur fuels in SECAs; and
• fuel switching's emission reduction potential.
6.1.1 Primer on Bunker Fuel Treatment and Heating Plants
Because of their high viscosity and residual fuel components (including contaminants),
heavy marine fuels must be treated onboard before injection into a diesel engine. Onboard
treatment includes purification and heating to obtain the proper viscosity before injection. The
following discussion provides a primer on bunker fuel treatment and heating systems to better
! Two different compliance actions might be adopted by marine vessel operators in this category: (1) carrying both
high- and low-sulfur fuels and switching fuel sources as they approach or exit SECAs (commonly referred to as
"fuel switching") and (2) converting to low-sulfur fuel oils for all of their fuel needs (referred to as "fuel
converting").
6-3
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illustrate how fuel switching can be implemented and the engineering considerations that must
be made when switching fuels at sea.
A bunker fuel pretreatment and cleaning plant is designed to circulate fuel, remove
solids, and maintain the proper injection viscosity through temperature control. Fuel circulation
and temperature control are used to maintain viscosity and prevent heavy fuel oils from
solidifying in the fuel system. Removing solids improves operational efficiency and maintains
the integrity of the fuel circulation, injection, and combustion systems. The heavier the fuel, the
more complex the fuel treatment system must be (Rowan et al., 2005).
A ship's pretreatment system consists of storage, settling tanks, filters, and purifiers
(Fisher and Lux, 2004). This system removes solids and sediments and improves the overall
quality of the fuel such that it can be burned in diesel engines without causing damage or
excessive wear.
The engineering schematic in Figure 6-1 shows a typical shipboard pretreatment and
cleaning plant. Transfer pumps bring fuel from heated bunker tanks to the settling tank, which
serves a dual purpose. At any given time, enough fuel for 2 days of travel is held in this tank.
The settling tank also has heating coils to heat the fuel. As the fuel resides in the tank, heavy
solids settle to the bottom. The fuel to be burned is drawn off the top of the tank. If the fuel is
allowed to cool at any stage in the pretreatment, cleaning, or supply systems, it will become too
viscous to pump.
Next, feed pumps move the fuel from the settling tank through a preheater to one or more
separators. The separators act as centrifuges, removing as many of the remaining solids as
possible. The pretreated and cleaned fuel is stored in the day tank, which includes heating
elements to maintain fuel temperature and viscosity. At any given time, fuel sufficient for 1 full
day of travel is stored in this tank.
Figure 6-2 shows the pressurized fuel oil system. The day tank, or heavy fuel oil service
tank, is the main repository for fuel before it is combusted. The fuel supply system draws fuel
from the day tank and continuously circulates the fuel from the day tank to the injection system
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Figure 6-1. Typical Shipboard Pretreatment and Cleaning Plant
Source: MAN B&W Diesel A/S (MAN B&W). 2005. Operation on Low Sulphur Fuels: Two-Stroke Engines.
Published November 26, 2005.
bo'weon HFQ and DO/A.
Figure 6-2. Pressurized Fuel Oil System
Source: MAN B&W Diesel A/S (MAN B&W). 2005. Operation on Low Sulphur Fuels: Two-Stroke Engines.
Published November 26, 2005.
6-5
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and back to the day tank—more fuel is pumped in circulation than is drawn off to the injectors—
to prevent solidification anywhere in the supply system. Two sets of pumps, supply pumps and
circulating pumps, pressurize the system and maintain the free flow of fuel. Included is a
preheater, controlled by a viscosimeter, to maintain fuel temperature throughout the onboard
fuel-handling system. Before fuel is brought to the main engine's injection system, it is filtered
one last time to remove solids larger than 300 microns.
6.1.2 Burning Low-Sulfur Fuels in Main Engines
The concerns regarding burning low-sulfur fuels in marine engines are related to either
the steady state operation on low-sulfur marine distillates or issues relating to the changeover
from IFO to MDO/MGO and back. The primary issues related to the steady-state operation of
low-sulfur fuel in diesel powered ships are
• cylinder lubricants and feed rates and
• viscosity and temperature control.
6.1.2.1 Lubricating Oil Systems
Marine lubricating oils contain alkaline additives to counteract the acidity caused by
sulfur oxides. The base number (BN) of the lubricating oil (the measure of its alkalinity) must
match the sulfur content of the fuel used. Acid corrosion is the most significant cause of cylinder
wear and occurs during condensation of IFO's sulfur content in the combustion chamber (MAN
B&W, 2005). The sulfur from the fuel and water vapor combine to form sulfur trioxide. Cylinder
oil contains alkalines that control the deposition of acids in the cylinders and, thus, the wear.
According to MAN B&W (2005), some controlled deposition is helpful for the proper tribology
for maintaining a film of lubricating oil.
When running on fuels that are 1.5% or more sulfur, ships are recommended to use 70BN
cylinder oil. When running on fuels that are less than 1.5% sulfur, they are recommended to use
40BN cylinder oil (Wartsila, 2006a). In this way, they are able to maintain a proper BN-to-sulfur
(BN/S) ratio. Most ships' diesel engines are slow-speed, 2-stroke engines that inject lubricating
oil into the fuel just prior to combustion and therefore require separate fuel-feed systems to
implement fuel switching.
If low-sulfur fuels are used in conjunction with 70BN cylinder oil, ships risk excessive
ash deposit in the combustion chamber, exhaust valves, and turbocharger. 70BN has high ash
content, and this ash may be deposited on the piston crown head, causing bore polishing that may
lead to engine seizure. Although ships may run with low-sulfur fuels for a short time with 70BN,
6-6
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if the sulfur content is 1% or less, they are strongly recommended to use 40BN (Wartsila,
2006a).
These issues are compounded when operating on different fuels inside and outside of a
SEC A. Fuel switching increases the difficulty of maintaining a proper BN/S ratio in the
lubricating oil system. Although short periods of out-of-balance BN/S ratios do not generally
lead to excessive engine wear, compliance with low-sulfur fuel limits may require extended
operation with the low-sulfur fuel. Ships may require a two-cylinder lubricating system (storage,
service, and supply) to avoid excess engine wear when running on different fuels.
If ships run on IFO and continuously use low BN cylinder oil, they risk corrosion in the
engine. The low BN cylinder oil cannot neutralize the sulfuric acid generated during combustion.
Fuel switching requires monitoring BN levels and selecting lubricants that maintain the proper
BN/S ratio (Wartsila, 2006a).
If the fuel's sulfur level is below 1%, 40BN or 50BN lubricating oil is recommended by
MAN B&W (2005). However, a ship should only change over to 40BN or 50BN from 70BN if it
is to operate on fuel that is 1% sulfur or less for more than 1 week. If the fuel sulfur level is
between 1% and 1.5%, 40BN, 50BN, or 70BN lubricating oil can be used. Ships are
recommended to use 70BN lubricating oil exclusively when using fuels that are 1.5% sulfur or
greater.
6.1.2.2 Fuel Viscosity and Feed Temperature
Another issue that must be considered when using MDO/MGO in marine diesel engines
is viscosity. Marine diesel manufacturers design injection systems to operate with a minimum
fuel viscosity of between 1.8 and 3.0 centistokes (cSt) depending on specific engine type
(Wartsila, 2006). MDO/MGO is significantly less viscous than IFO. IFO380 has a viscosity of
35 cSt at 100°C. IFO380's viscosity is reduced by heating onboard to provide fuel at the
injectors of a suitable viscosity. The DMA specification requires fuel to be between 1.5 and 6.0
cSt at 40°C, and the DMB specification requires fuel to be between 2.5 and 11.0 cSt at 40°C.
The world average viscosity of DMA in 2006 was 3.5 cSt, and the U.S. average was 3.0 cSt at
40°C. The world average viscosity of DMB in 2006 was 4.2 cSt, and the U.S. average was 3.9
cSt at 40°C (DNV, 2007). These viscosity figures are based on a 40°C standard. However, on
marine vessels, the temperature of the fuel will normally rise above 40°C, further reducing the
viscosity (Herbert Engineering Corp., 2007). Viscosity only becomes an issue when MDO or
MGO is delivered at near-minimum specification.
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Low viscosity in 4-stroke diesel engines is generally not a major problem, but in severe
cases, damage to the fuel injection equipment may occur, and the running parameters of the
engine will be affected. In exceptional cases, there may be a risk of loss of capability to produce
full power, unexpected shutdown, and starting problems. The effect of low viscosity on 2-stroke
marine diesel engines is typically minor (Wartsila, 2006a). The low viscosity problem, however,
may arise, with the pumps in the fuel treatment system causing pump failure and unexpected
engine shutdown.
The immediate solution to low viscosity concerns is to cool the fuel to a suitable
temperature and viscosity. This would require the installation of a fuel cooler and associated
piping and viscosimeter in the fuel treatment system. The retrofit of a fuel cooler (using the main
engine cooling system) and associated system can be done at a ship's normal dry docking
(Herbert Engineering Corp., 2007). The cost for this retrofit is likely to be less than $50,000
(Herbert Engineering Corp., 2007). A concern, however, is that a seawater-based heat exchanger
may not be able to cool MGO (DMA) sufficiently in all parts of the world during summer
months. Preventing this problem may require the installation of a fuel chiller (i.e., refrigeration
system) that would be more costly. Other solutions may come about through the use of improved
or different materials (e.g., ceramics) in the fuel system (e.g., injectors, pumps).
If low sulfur IFO is used in the SEC As, viscosity and temperature are not a concern
because IFO and low-sulfur heavy fuel oil (LSIFO) have similar viscosity characteristics.
6.1.3 Practicality of Switching to Low-Sulfur Fuels in SECA
Switching from IFO to a low-sulfur distillate (MDO/MGO) when entering a SECA raises
the following two primary concerns:
• fuel compatibility
• temperature change and thermal shock
These are both concerns because, in existing fuel treatment plants, the fuel is drawn from either
the MDO/MGO day tank or the IFO day tank outside of the fuel recirculating loop (see
Figure 6-2). This means that, during the changeover from IFO to MDO/MGO, the two types of
fuel are cohabitating the pipes, pumps, filters, and heat exchangers in the recirculating loop.
6.1.3.1 Fuel Compatibility
The first consideration for the practicality of switching to low-sulfur fuels is fuel
compatibility. Prior to the 1980s, most refineries were hydro-skimming or straight-run refineries
that produced predominately paraffinic fuel oils. There were few compatibility issues with
-------
mixing different paraffmic fuel oils. Over the past 25 years, complex refineries have become the
norm, and aromatic heavy fuel oils have become the dominant fuel type. These fuels have high
levels of asphaltenes (high molecular weight hydrocarbons that are insoluble in n-heptane but
soluble in toluene). Mixing aromatic fuel oils with paraffmic fuel oils can cause significant
sludge formation. Even when mixing aromatic fuel oils, instability in the fuel oil can result,
leading to high sludge formation. Sludge formation results in fuel value loss through high sludge
removal rates in the centrifuge and can lead to clogged filters, blocked centrifuges, and other
mechanical difficulties. Consequently, switching or mixing different fuels is generally avoided in
current practice.
Although fuel switching historically has been avoided because of these uncertainties, this
does not imply that, given economic incentives, fuel switching will not become a viable
alternative in many instances. Catalytically cracked low-sulfur distillates (i.e., distillates with
high aromaticity) will generally be compatible with heavy fuel oils from complex refineries.
Developing costs of this implementation strategy must include the costs of fuel compatibility
testing and the likelihood of increased maintenance due to occasional excess sludge formation.
Fuel compatibility testing can be accomplished manually onboard using testing kits or by
contracting with third-party testing laboratories. Although fuel compatibility problems seldom
occur because of the low incidence of fuel switching, they are likely to occur more often once
fuel switching becomes more prevalent (MAN B&W, 2005).
6.1.3.2 Fuel Feed Temperature
Using lower-temperature fuels in a system designed for high-temperature fuels risks
thermal shock during the changeover from IFO to MDO. Appropriate fuel-switching procedures
must ensure a gradual changeover that avoids rapid fuel temperature changes. The fuel switching
cannot be too abrupt or the rapid change in fuel oil temperature may cause uneven thermal
expansion of the fuel injection equipment, which could cause seizure (i.e., thermal shock) of the
injection system.
Wartsila (2006) recommends continuous operation with IFO for engines and plants
designed for running on IFO. Changing MDO is only recommended when absolutely necessary,
such as, when flushing the engine before maintenance, when the heating plant is not available, or
when it is required for environmental reasons (e.g., when low-sulfur fuel is required). Risks may
be mitigated by arranging the fuel system to permit a controlled, slow change in fuel
temperature.
6-9
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If a ship does not have double IFO systems and does not have low sulfur IFO available
when entering a SEC A, the only alternative will be to switch all IFO engines to MDO at sea. In
this case, the MDO temperature and the temperature change gradient need to be considered. For
2-stroke engines, a controlled temperature gradient is recommended, with a reduced engine load.
If MDO is mixed in while the fuel temperature is still very high, there is a possibility of gassing
in the fuel oil service system, with subsequent loss of power. For 4-stroke engines, the fuel
changeover generally can be performed via the mixing tank at any load (Wartsila, 2006a).
Procedures or arrangements for switching from IFO to MDO may include fuel preheaters,
fuel pipe trace heating, a three-way valve in the suction line from the service tanks, redirection of
the return fuel to the MDO service tank, an MDO cooler, the possible need to control engine
load, and monitoring of the pressure difference of the fuel filter (Wartsila, 2006).
According to Wartsila (2006), if a ship is to operate on different IFO qualities inside and
outside of SECAs, it would be beneficial to install double IFO settling and service tanks for
reasons of operational convenience, economy, and safety. A double settling and service tank
system will reduce the time required for the fuel delivery system to be fully flushed of all fuels
exceeding the 1.5% sulfur limit before entering the SECA. Ships also would avoid consumption
of the more expensive LSIFO or distillates before entering or after exiting the SECA.
Studies of fuel switching conducted by MAN B&W (2005) indicate that, when dual fuel
systems are used, it takes approximately 55 minutes for a 2-stroke engine to change over from
diesel fuel to heavy fuel oil. Fuel temperature cannot be changed by more than 2° per minute.
Thus, if the system contains 40° C diesel fuel and it needs to be 80° C before heavy fuel oil can
be added, 20 minutes is required to heat the diesel fuel. The heavy fuel oil needs to be 25° C
higher than diesel fuel, or 105° C, requiring 12.5 additional minutes before it can be added to the
diesel fuel. As the system changes to heavy fuel oil, the temperature must rise to 150° C, which
requires an additional 22.5 minutes. In this case, it takes 32.5 minutes before heavy fuel oil is in
the system and an additional 22.5 minutes before the system is operating with 150° C heavy fuel
oil (MAN B&W, 2005).
6.1.3.3 Fuel System Configuration
On board fuel treatment systems are not identical, and the actual changeover from IFO to
MDO/MGO will vary based on the design of the fuel oil system. MAN B&W (2005) identified
three principal fuel system configurations for fuel switching:
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1 One Distillate System and One Heavy Fuel System. In a dual fuel system, each fuel
type has a dedicated bunkering, settling, centrifuging, and service tank system. The
distillate and heavy fuel systems are independent until fuel supply pressurization.
Most ships have distillate systems onboard; however, fuel switching may require
modification to accommodate greater distillate usage (Figure 6-3).
2 One Distillate System and Two Heavy Fuel Settling Tanks. Regular heavy fuel oil
and LSIFO have separate bunkering and settling systems. The two heavy fuel systems
merge at the centrifuges. As in the first option, the distillate system may connect with
the heavy oil supply lines before fuel supply pressurization (Figure 6-4). Additional
fuel-delivery equipment needs may include additional bunker tanks, bunkering
systems, bunker-heating systems, a settling tank, and a transfer pump.
3 One Distillate System and Two Separate Heavy Fuel Oil Systems. In contrast to
Option 2, heavy fuel systems have separate centrifuges and service tanks and are
isolated up until fuel supply pressurization. As in the first option, the distillate system
may connect with the heavy oil supply lines before fuel supply pressurization
(Figure 6-5). Additional fuel delivery equipment needs may include those from
Option 2, as well as additional centrifuges, service tanks, piping, and instrumentation.
MQO
(Boiler Support \—
Inert Gas eta.i I
- . if?1
yjy
MDO Storage Tar* j25°C>
SetilingTank (25°C[
HrO Supply HK) Circulating
pjmp pump
Figure 6-3. Fuel System with One MDO Settling Tank and One IFO Settling Tank
Source: MAN B&W Diesel A/S (MAN B&W). 2005. Operation on Low Sulphur Fuels: Two-Stroke Engines.
Published November 26, 2005.
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Figure 6-4. Fuel System with One MDO Settling Tank and Two IFO Settling Tanks
Source: MAN B&W Diesel A/S (MAN B&W). 2005. Operation on Low Sulphur Fuels: Two-Stroke Engines.
Published November 26, 2005.
MDO Storage Tart*. (25 °C)
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kinker Storage Ta-fc 1 i*_.
°C) |
| Buiker Sloraga lark 2 |45 °C) |
lb?
| Bimka Stcraea rank 3 ('15 °q |
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6.1.3.4 Shipboard Fuel Oil Tankage
There has been concern expressed that ships do not have sufficient onboard storage
capacity (i.e., tankage) to accommodate fuel switching in SECAs. Herbert Engineering Corp.
(2007) addressed the issue of onboard fuel oil tankage in a presentation to CARB on July 24,
2007. Herbert described the common features for all ships' fuel oil tankage as follows:
Ships devote the minimum space practical to fuel and machinery to maximize cargo.
• Minimal space is provided for distillate oil tanks on unifuel ships.
• Some ships have two IFO tank systems—one for IFO and one for LSIFO.
The most common arrangement is for one IFO tank system with multiple IFO tanks. The
IFO tank system will include IFO storage tanks, an IFO settling tank, and an IFO service (or day)
tank. The distillate oil system will usually have one or more MDO/MGO storage tank(s) and a
corresponding service (or day) tank. Typical fuel tank capacities for oil tankers are shown in
Table 6-1. Typical fuel tank capacities for containerships are shown in Table 6-2.
Table 6-1. Fuel Tank Capacities for Oil Tankers
Tank Type/Size
50,000 DWT Panamax
1 10,000 DWTAframax
160,000 DWT Suezmax
300,000 DWT VLCC
IFO
Tankage Description
2 IFO storage, 1 settling, and 1
service tank
4 IFO storage, 1 settling, and 1
service tank
4 IFO storage, 1 settling, and 1
service tank
4 IFO storage, 2 settling, and 1
service tank
IFO
Capacity
(m3)
1,500
3,000
4,000
5,500
MDO/MGO
Tankage Description
1 storage and 1 service tank
1 storage and 1 service tank
1 storage and 1 service tank
1 storage and 1 service tank
MDO
Capacity
(m3)
150
250
350
450
Source: Herbert Engineering Corp. 2007, July. "Fuel Oil Systems." Paper presented at the California Air Resources
Board Working Group on Fuel Switching.
Table 6-3 includes the at-sea cruising range (with a 15% reserve) for each ship type when
burning MDO/MGO in both the main engine and auxiliary engines, based on the fuel oil tank
capacities from Tables 6-1 and 6-2.
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Table 6-2. Fuel Tank Capacities for Containerships
IFO MDO
IFO Capacity MDO/MGO Capacity
Tank Type/Size Tankage Description (m ) Tankage Description (m )
2,500 TEU Feedership 6 IFO storage, 1 settling, and 1 3,200 1 storage and 1 service tank 300
service tank
4,000 TEU Panamax 8 IFO storage, 1 settling, and 1 7,000 1 storage and 1 service tank 350
Containership service tank
6,000 TEU Post-Panamax 10 IFO storage, 2 settling, and 8,000 1 storage and 1 service tank 400
Containership 1 service tank
9,000 TEU Post-Panamax 12 IFO storage, 2 settling, and 10,000 2 storage and 1 service tank 800
Containership 2 service tanks
Source: Herbert Engineering Corp. 2007, July. "Fuel Oil Systems." Paper presented at the California Air Resources
Board Working Group on Fuel Switching.
Table 6-3. Ship Fuel Ranges When Fuel Switched to MDO/MGO
Ship Type/Size
50,000 Panamax Tanker
1 10,000 Aframax Tanker
160,000 Suezmax Tanker
300,000 VLCC
2,500 TEU Feedership
4,000 TEU Panamax Containership
6,000 TEU Post-Panamax Containership
9,000 TEU Post-Panamax Containership
Range
(days)
3.3
3.5
3.6
3.3
2.6
1.9
1.7
1.8
Range
(nautical miles)
1,200
1,300
1,300
1,200
1,300
1,100
1,000
1,100
Source: Herbert Engineering Corp. 2007, July. "Fuel Oil Systems." Paper presented at the California Air Resources
Board Working Group on Fuel Switching.
Herbert Engineering Corp.'s (2007) analysis concludes that existing distillate oil tank
capacities should be sufficient to accommodate main and auxiliary engine operation in SECAs.
The analysis also concludes that existing engines and fuel oil systems are suitable for continuous
operation on distillate.
6.1.3.5 Maersk Pilot Fuel Switch Initiative
Maersk, the world's largest Containership operator, has entered into a voluntary program
in which all vessels calling at California ports switch main and auxiliary engines from IFO fuel
to MDO/MGO with a sulfur content of less than 0.2% when within 24 nautical miles of Los
Angeles and Oakland. This program started with the M/VSine Maersk's voyage on March 31,
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2006. As of April 2007, 78 different vessels involving 298 fuel switches were involved in this
study. The containerships involved are all large, slow-speed, 2-stroke diesel engines made by
either MAN B&W or Wartsila (Sulzer). The ships operate at sea on residual fuels (either RMH
380/700 or RMK 380/700). In California waters, they use either DMA or DMB (with DMX
carried for emergency generators and lifeboat engines). All ships are equipped with separate
service tanks for residual and distillate fuels.
Fuel switches are carried out per engine manufacturers' instructions with no special
training for the crew provided. The change is considered normal engineering practice. No
problems have been encountered to date with regard to the fuel changeover. The changeover
only has engines running on LSFO for short periods of time and does not require change in
cylinder lubrication oil.
6.1.4 Other Approaches to Using Low-Sulfur Fuels in SECAs
Besides the obvious switching from IFO to low-sulfur fuel oil using existing shipboard
systems, other approaches to using low-sulfur fuels in SECA include full-time switching to low-
sulfur fuel oil, onboard blending of IFO and MDO/MGO to achieve low-sulfur fuel, and
installation of a separate low-sulfur fuel oil fuel system.
6.1.4.1 Full-Time Fuel Switching
Full-time fuel switching, also referred to as "fuel converting," is permanently converting
from high-sulfur to low-sulfur fuels. Converting to distillate fuel from traditional residual fuel
has occurred in several shipping fleets in California and the EU. Converting to low-sulfur
distillates does not require new equipment, but, as discussed above, it does require use of a
different lubricating oil.
Fuel cleanliness has a direct effect on the wear and tear of engine components that come
into contact with heavy fuel or the byproducts of heavy fuel combustion. Slow- and most
medium-speed engines can run on low-sulfur distillates; however, owners accept fuel-cleaning
costs and increased engine maintenance in exchange for heavy fuel oil's lower price (Rowan et
al., 2005). Implicit in this economic trade-off are the advantages to combusting only distillates
that offset the price premium (Fisher and Lux, 2004). Specific advantages of converting to
distillates include the following:
• Conversion avoids fuel heating prior to injection to the combustion chamber.
Distillates are bunkered at the ambient temperature, and their low viscosity permits
ships to avoid heating systems dedicated to making the fuel more manageable.
Consequently, maintenance costs and inconvenience are expected to be lower.
6-15
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• Conversion requires less extensive settling, centrifuge, or filtration (fuel pretreatment)
systems, lowering maintenance costs and inconvenience.
• Conversion entails using lower BN lubricants (40BN or 50BN), which are less
expensive than higher BN lubricants (70BN).
• Conversion enables greater fuel efficiency, because the energy content per unit of
distillate fuel is greater than that of heavy fuel oil.
Several studies of ships converting to low-sulfur marine distillate fuel have found
reduced maintenance and higher fuel efficiency with the low-sulfur distillates. There are few
current examples of converting to low-sulfur fuels from conventional heavy fuel oils. Although
this conversion may require additional operational changes in lubricating oils and the fuel
heating system (to ensure proper viscosity at the fuel injectors), the primary hindrance to fuel
conversion is the higher price of the low-sulfur fuels.
For smaller vessels that travel primarily within SEC As, conversion to 100% low-sulfur
fuels is likely to be the most economic option. For larger vessels that operate a significant
portion of the time outside of SEC As, fuel switching is likely to be the most economic
compliance option.
INTERTANKO submitted a proposal to the MARPOL convention's Annex VI working
group to designate the whole world as a SEC A. This proposal would entail large-scale fuel
conversion.
6.1.4.2 Onboard Blending
Ships may acquire blended fuels from suppliers or may blend fuels onboard. It is
preferable for ships to acquire blended fuels from suppliers that run blend optimization
programs. Ships' fuel systems are not designed with fuel blending per se, and suppliers'
optimization programs can determine the optimum price, viscosity, density, flash point, ash
content, and sulfur content (Fisher and Lux, 2004). To avoid fuel incompatibility, ships segregate
fuels of different origins and types and submit fuel samples to independent testing laboratories to
confirm each fuel's properties. If ship engineers blend fuels onboard, it is incumbent upon them
to optimize the blended fuel.
Ships have two options for blending: steady-state blending and transient blending. In a
steady-state configuration, MDO is continuously blended with conventional IFO (Wartsila,
2006b). The advantage of blending IFO and LFO is that the ship avoids carrying low sulfur IFO,
which, in turn, circumvents complex changes to the fuel supply and bunkering systems. The
6-16
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tradeoff is increased consumption of more expensive MDO. The fuel supply system would
require a blending unit to blend the IFO and MDO to reach the required fuel sulfur content.
In a transient fuel-blending system, the settling tank is topped with low sulfur IFO, while
still containing IFO. When in the SEC A, the blending unit injects MDO into the fuel supply
system until the sulfur content of the combined IFO and low sulfur IFO coming from the day
tanks meets compliance standards (Wartsila, 2006b).
6.1.4.3 Installation of a Separate Low Sulfur Fuel Oil System
Installing a separate low sulfur fuel oil fuel system (including injectors), such as is done
on LNG tankers (dual fuel diesel engines burning both residual fuel and LNG boil-off), is the
likely next-generation response to SECA fuel switching; because the fuels would be entirely
isolated, a separate low sulfur fuel oil fuel system would avoid fuel compatibility, viscosity, and
thermal shock issues.
6.1.5 Emissions Reduction Potential
The emissions reduction potential of fuel switching, in terms of grams per horsepower-
hours, depends on the baseline fuel grade and the fuel grade selected for use in SECAs. Because
of the linear relationship between sulfur content and SOX, emissions reduction potential can be
reasonably estimated.
The components of exhaust gas emissions from ships are NOX, SOX, CO, CO2, HC, and
particulates. On average, the sulfur content of heavy fuel oil consumed by marine engines is
around 2.7% (MAN B&W, 2004, 2005). The three principal inputs required for an engine to
produce work are air, fuel, and lubricating oil (Figure 6-6). The exhaust gas will consist of
nitrogen, CO2, oxygen, and various pollutants.
Pollutants are measured as concentrations in the exhaust gas. If the engine is running on
3% sulfur fuel, then its exhaust gas is estimated to contain approximately 600 parts per million
by volume (vppm) SOX. For 2.5% sulfur, 74% of emissions is N2, 11.3% is O2, 8.1% is H2O, 6%
is CO2, and 0.3% is pollutants. Of those pollutants, 0.25 g/kWh is PM, and 10 g/kWh is sulfur
(Koehler and Windelev, 2001).
Total emissions reduction potential from ships fuel switching in SECAs is dependent on a
number of factors and will vary by number of vessels, vessel type, estimated time spent in and
outside of SECAs, engine type, load factors, and fuel selection. The actual emissions reduction
6-17
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Heat
Air
8.5 kg/kWh
21 % O2
79% N2
175%g/kWh
97% HC
3%S
Lube[H[>
1 g/kWh
97% HC
2.5% CA
0.5% S
EJ
f
Work
Exhaust gas
13.0% Os
75.8% N2
5.2% CQ,
5.35% H2O
1500 vppm NOX
600 vppm SOX
60 ppm CO
180 ppm HC
120mg/Nm3part.
Figure 6-6. Components of Marine Diesel Engine Exhaust Gas
Source: MAN B&W Diesel A/S (MAN B&W). 2004. Emission Control: MAN B&W Two-Stroke Diesel Engines.
Published January 9, 2004.
any one ship experiences will further vary because of differing equipment designs, maintenance,
and operating conditions (Entec, 2005b).
Recent original studies that calculated the emissions reduction potential for fuel
switching have measured the emissions reduction potential of fuel switching from the global
average of 2.7%S IFO to 1.5%S IFO or 0.5% MDO, including the 2002 and 2005 Entec studies
commissioned by the Directorate General-Environment for the European Commission to
estimate SOX emissions in European waters. The study found that switching from 2.7% sulfur to
1.5% or 0.5% sulfur reduces SOX emissions by 44% or 81%, respectively.
6.2 Exhaust Gas Scrubbing
An alternative to fuel switching or fuel converting is exhaust gas cleaning using seawater
scrubbing systems. Exhaust gas scrubbing systems are a mature technology for land-based
applications that have recently been adapted for use by ships (Entec, 2005a), although only a few
ship trials have taken place. Scrubbers transfer SC>2 from ships' exhaust gas to seawater, which is
then cooled and filtered before discharge into the seas. Exhaust gas scrubbing using seawater is
believed to be an effective alternative because of seawater's natural alkalinity and because
6-18
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seawater contains a large amount of sulfur naturally, making it a relatively safe reservoir (Entec,
2005b).
6.3 Description of Scrubber Technology
Scrubbing systems have four key components: (1) the scrubbing unit installed on the
exhaust stack, (2) water supply and discharge systems, (3) a water filtration plant, and (4) a
settling tank for solids (Figure 6-7). The scrubber is large and fitted on top of the exhaust pipe. It
removes SOX from exhaust gases by mixing gases and seawater in a turbulent cascade (Marine
Exhaust Solutions [MES], 2007). Scrubbed exhaust gases are then ventilated from the system,
and contaminated water is discharged into a filtration system that removes soot and solids. The
filtration system diverts the soot and solids into a settling tank for removal in port or combustion
in the ships' incinerator(s). Filtered discharge water is split into two streams, one of which passes
through a heat exchanger before being discharged overboard below the ship's lowest waterline.
The second stream returns to the water circulation system to provide cooling. The manufacturer
MES states that the discharge water meets or exceeds EPA Clean Water Act requirements and
that its systems are capable of removing 80% to 95% of SOX, depending upon water temperature
and salinity.
The maritime industry is very skeptical regarding the claim by MES that the scrubber
effluent stream will meet or exceed EPA Clean Water Act requirements for discharge within a
port area or even in offshore portions of the U.S. Exclusive Economic Zone (EEZ). There is
concern that the pH of the effluent stream will be so low as to necessitate a stainless steel
handling system and, probably, a stainless steel holding system for shore-side discharge. There
are also serious concerns regarding the cost and availability of shore-side reception facilities. If
discharge of the effluent stream is banned within the SECA (some of which will likely be no-
discharge zones), the effluent stream must be contained and possibly treated before discharge.
The IMO discharge rules for sulfuric acid are rigorous and may affect the discharge of the
effluent stream and require significant dilution before discharge is permitted.
Ship owners will incur increased capital, retrofit, or maintenance expenses to bunker the
same pre-SECA fuel grade when operating in SECA. Scrubbing systems required additional
maintenance and add complexity to ships' mechanical systems, as well as higher electrical
demand. Exhaust gas scrubbing emerged as a compliance alternative because of the limited
availability of low-sulfur fuel.
6-19
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Freshwater
Seawater
Supply pump
Hot exhaust
gas in
Cooling water
ean brine
—
-------
would be expected to be easier for new ships. For a retrofit, the ship would need to be taken out
of service. It may be that the schedule for periodic major maintenance on the ship would not
allow for a scrubber installation. Also, it may not be economical to retrofit an older ship that may
be near the end of its service life. Second, there may be a limitation on supply. Scrubber
manufacturers are largely still developing their systems and may not be able to meet high
scrubber demand. In the long term, it may be more reasonable to estimate scrubber penetration
based simply on consideration of cost.
EPA provided RTI with scrubber penetration scenarios for 2012 and 2020. For each
scenario, Table 6-4 presents both the percentage of ships projected to use scrubbers and the
corresponding percentage of fuel used on these ships.
Table 6-4. Near- and Long-Term Scrubber Penetration Scenarios in the U.S. EEZ
Estimate
Low Estimate
Medium Estimate
High Estimate
Percentage
% ships
%fuel
% ships
%fuel
% ships
%fuel
2012
0%
0%
NA
NA
1%
5%
2020
0%
0%
5%
31%
10%
47%
Source: EPA Estimates.
In both years, the low scrubber penetration scenario is the null case. In other words, all
of the vessels operating in the EEZ would use low sulfur distillate fuel. For the high scrubber
penetration scenarios, it should be noted that the percent of fuel affected is higher than the
percent of ships affected. This is due to the expectation that scrubbers would be applied first to
ships operating more often in the SEC As. This is reasonable given that these vessels, without a
scrubber, would be subject the highest fuel switching costs.
6.5 Summary Remarks
Enhancing efficiency through engine design does little to reduce SOX emissions beyond
the reductions resulting from burning less fuel of the same sulfur content. The accepted practice
among ship owners is to use lower sulfur fuels to reduce SOX emissions because of the linear
relationship between the sulfur content of fuels and SOX emissions. Fuel switching is expected to
be one of the primary compliance options selected by many vessel types. Until recently, such
changeovers between fuels with major differences in viscosity were only carried out before a
6-21
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major engine overhaul or prolonged engine shutdown. However, with ships operating both
within and outside of SEC As, fuel switching may occur more often, requiring routine
changeover procedures and systems. Engine manufacturers and marine engineering experts
believe that fuel switching can be implemented safely—but with varying degrees of complexity
based on ships' individual fuel system configurations—so long as proper procedures and
operating protocols are followed. Recent original studies have measured the emissions reduction
potential of fuel switching from the global average of 2.7% sulfur IFO to 1.5% sulfur IFO or
0.5% sulfur MDO. The studies found that switching from 2.7% sulfur to 1.5% or 0.5% sulfur
reduces SOX emissions by 44% or 81%, respectively. An alternative approach to fuel switching
may be the use of exhaust gas scrubbers.
6-22
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SECTION 7
SECA FUEL CONSUMPTION ESTIMATES
This section estimates the volume of bunker fuels consumed in 2012 and 2020 under two
mileage zone scenarios. The first scenario designates a SECA boundary in U.S. territorial waters
at 100 nm off the Pacific Coast and 50 nm off the East and Gulf Coasts. The second scenario
designates a SECA boundary at 200 nm off the East, Gulf, and Pacific Coasts.
Using the baseline estimates calculated in Section 3 as the primary input, we generated
SECA fuel consumption estimates. The methodologies discussed in this section continue the
bunker fuel demand forecast discussion; thus, the focus here is on estimating the amount of fuel
forecasted in Section 3 that is consumed within the SECA boundaries. The forecasts from this
section were inserted into the WORLD modeling cases as the affected fuel volumes in Section 8.
7.1 Summary of the SECA Fuel Consumption Modeling Approach
In general, estimating the amount of bunker fuel consumed within SECA boundaries
involved reviewing U.S.-related trade routes, estimating whether and to what extent ships would
alter their routing to minimize travel within the SECA, and calculating the volume of fuel
consumed within the SECA boundaries. As such, the primary input for the SECA fuel
consumption analysis was the time series of bunker fuel consumption from Section 3
disaggregated by route and by commodity type. The discussion in this section does not reiterate
the activity-based methodology for developing the time-series data; rather, this discussion
focuses on how fuel consumption in U.S. trading routes was apportioned to the SECA.
Key steps in the SECA fuel consumption analysis included
• isolating the trading routes, voyage characteristics, and fuel consumption estimates
for U.S.-related shipping activity;
• calculating the distance traveled within the SECA boundaries for each route;
• estimating whether ships would adjust routing to optimize time spent within the
SECA;
• calculating the number of days each voyage spent in U.S. ports; and
• apportioning estimated intra-SECA fuel consumption estimates by major U.S. SECA
zones by reviewing the distance each voyage traveled within the zones.
This analysis also estimated port of purchase for SECA fuel consumption for input into
the WORLD model.
7-1
-------
7.2 SECA Scenario Boundaries
There are five distinct regions for which fuel consumption estimates were generated, as
established by the U.S. coastline:
1. North Pacific, including the Alaskan Coast from Kodiak Island east and south to the
Oregon-California land border
2. South Pacific, including all U.S. waters off the coast of California
3. Gulf Coast, covering U.S. waters from Brownsville, Texas, to the Florida Keys
4. East Coast, encompassing U.S. waters from the Florida Keys and the Straits of
Florida to Maine
5. Great Lakes, including all of Lake Michigan and U.S. waters of the other four lakes
up through the end of the U.S. portion of the St. Lawrence River at Cornwall Island
EPA requested that RTI provide fuel consumption estimates for two SECA mileage zone
scenarios: (1) one in which the SECA boundary is set at 100 nm off the Pacific Coast and 50 nm
off the East and Gulf Coasts and (2) the other in which the SECA boundary is set at 200 nm off
the Pacific, East, and Gulf Coasts. Apart from the varying distances at which the SECA
boundary was placed, the two SECA scenarios share the following characteristics:
• The SECA boundary in the North Pacific is just east of Kodiak Island, Alaska; the
Bering Sea and U.S. territorial waters established by the Aleutian Islands are
excluded from the SECA.
• Western Canadian waters are assumed to be part of the SECA; innocent passage of
U.S.-related voyages (i.e., commodities, containers, Jones Act, and other vessels) in
Western Canadian waters is included in the U.S. North Pacific SECA fuel
consumption estimates.
• U.S. territorial waters in the Great Lakes are included in the SECA.
• U.S. territorial waters established by Hawaii are excluded from the SECA scenarios.
• U.S. territorial waters established by overseas territories and protectorates are
excluded from the SECA, with the exception of Puerto Rico, which is included in the
East Coast estimates.
7.3 Estimating Distances Traveled within SECA Boundaries
In brief, RTI and Navigistics reviewed the industry-standard distance, voyage time, and
routing information employed in the global fuel consumption analysis to identify distance
traveled within the SECA. We used the ratio of distance traveled in SECA to total distance
traveled to apportion global at-sea fuel consumption estimates. We derived in-U.S. port fuel
consumption estimates by reviewing the ports of call and assigning relevant in-port fuel
consumption to the SECA.
7-2
-------
Each international commodity, international container, and Jones Act voyage was
reviewed under both the 200 nm and the 100/50 nm boundary scenarios. As discussed in Section
3, data from Worldscale (2002), Maritime Chain (2005)—which is based on underlying BP
Shipping Marine Distance Tables—and Containerization International (Degerlund, 2005)
provided key routing data needed to develop the activity-based fuel consumption estimates. We
reviewed the same data for this component of the analysis. RTI and Navigistics reviewed trading
routes and frequency of service at major ports to calculate the mileage each voyage spent in the
SEC A under both of EPA's scenarios. For domestic noncargo ships, deployment, cruise, and fish
catch data were used to approximate the proportion of activity occurring within the SECA
boundaries because, with the exception of cruise ships, these vessels do not follow established
routes.
Navigistics also optimized ship routing to accommodate the SECA's SOX emissions
requirements where it was likely that a ship would exit the SECA and reenter at another point.
Few adjustments were made under the 200 nm scenario; however, some voyages on the East
Coast that included more than one U.S. port were optimized to minimize in-SECA travel.
All trading routes were reviewed, after which it was known for all voyage, cargo type,
and ship-type combinations under the 100/50 nm and 200 nm SECA scenarios:
• the optimized, in-SECA route distance, including mileage within multiple SECA
regions;
• the number of ports called on within each SECA region; and
• the proportion of total distance traveled.
Incorporating this information with the fuel consumption results from the base case
enabled RTI to determine the quantity of IFO380, IFO180, and MDO/MGO consumed at sea and
in port within each SECA region.
7.4 100/50 nm SECA Fuel Consumption Estimates
Under the 100/50 nm scenario, a total of 3.7 million tons of fuel is consumed by
international trading vessels (Table 7-1) in 2012. Including the domestic fleet brings total fuel
consumption to 7.5 million tons in 2012 (Table 7-2).
In 2020, international trading ships consume 4.9 million tons of fuel within the 100/50
nm SECA boundary (Table 7-3). Including domestic ships, total SECA fuel consumption
amounts to 8.9 million tons (Table 7-4).
7-3
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Table 7-1. 2012 SECA Fuel Consumption Estimates at 100/50 nm, International Trading
Ships
Commodity
Group
International
Commodities
Trade
International
Container Trade
International
Trade Subtotal
Region
US Great Lakes
US Gulf
US North Pacific
US South Pacific
US East
SECA Subtotal
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
IFO380
(thousand
tons)
96
394
78
49
170
787
139
56
354
579
1,129
96
533
135
404
749
56,112
IFO180
(thousand
tons)
33
223
41
35
135
467
119
97
292
521
1,028
33
342
137
326
655
8,546
MDO/MGO
(thousand
tons)
17
63
21
19
44
164
19
11
46
79
155
17
82
32
65
123
6,923
Total
(thousand
tons)
145
681
141
103
349
1,417
276
164
692
1,179
2,311
145
957
304
795
1,527
3,728
Source: Authors' calculations.
Table 7-2. 2012
Commodity
Group
International
Trade Subtotal
Domestic Fleet
(Jones Act and
Other Vessels)
Total SECA
SECA Fuel Consumption Estimates at 100/50
Region
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Total
IFO380
(thousand
tons)
96
533
135
404
749
56,112
100
409
352
248
373
1,482
195
942
487
651
1,122
3,398
IFO180
(thousand
tons)
33
342
137
326
655
8,546
57
84
73
52
64
331
90
426
210
379
720
1,825
nm, All Ships
MDO/MGO
(thousand
tons)
17
82
32
65
123
6,923
231
289
341
534
583
1,978
248
370
373
599
706
2,296
Total
(thousand
tons)
145
957
304
795
1,527
3,728
389
782
766
834
1,020
3,791
533
1,739
1,070
1,629
2,547
7,519
Source: Authors' calculations.
7-4
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Table 7-3. 2020 SECA Fuel Consumption Estimates at 100/50 nm, International Trading
Ships
Commodity
Group
International
Commodities
Trade
International
Container Trade
International
Trade Subtotal
Region
US Great Lakes
US Gulf
US North Pacific
US South Pacific
US East
SECA Subtotal
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
IFO380
(thousand
tons)
98
424
83
54
184
844
204
76
551
859
1,690
98
628
159
606
1,043
2,533
IFO180
(thousand
tons)
33
242
44
38
145
503
175
129
454
738
1,497
33
417
173
492
884
2,001
MDO/MGO
(thousand
tons)
17
68
21
21
48
176
27
15
72
115
229
17
95
36
93
162
404
Total
(thousand
tons)
149
734
148
114
377
1,523
406
220
1,078
1,712
3,416
149
1,141
368
1,191
2,089
4,938
Source: Authors' calculations.
Table 7-4. 2020
Commodity
Group
International
Trade Subtotal
Domestic Fleet
(Jones Act and
Other Vessels)
Total SECA
SECA Fuel Consumption Estimates at 100/50
Region
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Total
IFO380
(thousand
tons)
98
628
159
606
1,043
2,533
102
426
340
250
391
1,509
200
1,054
499
856
1,434
4,043
IFO180
(thousand
tons)
33
417
173
492
884
2,001
58
86
70
52
67
334
91
504
244
545
951
2,335
nm, All Ships
MDO/MGO
(thousand
tons)
17
95
36
93
162
404
240
336
337
548
625
2,086
257
432
373
641
787
2,490
Total
(thousand
tons)
149
1,141
368
1,191
2,089
4,938
399
849
747
850
1,083
3,929
548
1,989
1,116
2,041
3,172
8,867
Source: Authors' calculations.
7-5
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7.5 200 nm SECA Fuel Consumption Estimates
Under the 200 nm scenario, a total of 8.2 million tons of fuel is consumed by
international trading ships (Table 7-5) in 2012. Including the domestic fleet brings total fuel
consumption to 13.5 million tons in 2012 (Table 7-6).
In 2020, international trading ships consume 10.7 million tons of fuel within the 100/50
nm SECA boundary (Table 7-7). Including domestic ships, total SECA fuel consumption
amounts to 16.2 million tons (Table 7-8).
Table 7-5. 2012 SECA Fuel Consumption Estimates at 200 nm, International Trading
Ships
Commodity
Group
International
Commodities
Trade
International
Container Trade
International
Trade Subtotal
Region
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US Great Lakes
US Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
IFO380
(thousand
tons)
96
1,421
115
129
697
2,458
430
425
699
1,570
3,124
96
1,851
539
828
2,267
5,581
IFO180
(thousand
tons)
33
331
42
46
192
644
151
136
331
616
1,234
33
482
178
377
808
1,877
MDO/MGO
(thousand
tons)
17
176
28
37
148
406
42
40
74
157
313
17
218
69
111
305
718
Total
(thousand
tons)
145
1,928
185
212
1,037
3,507
623
601
1,103
2,343
4,670
145
2,551
786
1,315
3,380
8,177
Source: Authors' calculations.
7-6
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Table 7-6. 2012 SECA Fuel Consumption Estimates at 200 nm, All Ships
Commodity
Group
International
Trade Subtotal
Domestic Fleet
(Jones Act and
Other Vessels)
Total SECA
Region
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US Great Lakes
US Gulf
US_North_Pacific
US South Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Total
IFO380
(thousand
tons)
96
1,851
539
828
2,267
5,581
125
688
598
366
532
2,310
221
2,540
1,137
1,194
2,800
7,891
IFO180
(thousand
tons)
33
482
178
377
808
1,877
60
104
123
71
86
444
93
585
301
447
895
2,321
MDO/MGO
(thousand
tons)
17
218
69
111
305
718
241
340
732
591
692
2,595
258
558
800
702
996
3,314
Total
(thousand
tons)
145
2,551
786
1,315
3,380
8,177
427
1,132
1,452
1,028
1,310
5,350
572
3,683
2,239
2,343
4,691
13,527
Source: Authors' calculations.
Table 7-7. 2020 SECA Fuel Consumption Estimates at 200 nm, International Trading
Ships
Commodity
Group
International
Commodities
Trade
International
Container Trade
International
Trade Subtotal
Region
US Great Lakes
US_Gulf
US North Pacific
US South Pacific
US_East
SECA Subtotal
US Great Lakes
US Gulf
US North Pacific
US_South_Pacific
US_East
SECA Subtotal
US Great Lakes
US Gulf
US_North_Pacific
US South Pacific
US_East
SECA Subtotal
IFO380
(thousand
tons)
98
1,528
121
141
748
2,636
630
573
1,089
2,335
4,627
98
2,159
694
1,230
3,083
7,264
IFO180
(thousand
tons)
33
358
45
51
207
693
222
183
514
884
1,804
33
580
228
565
1,091
2,497
MDO/MGO
(thousand
tons)
17
190
28
41
159
435
61
54
115
231
462
17
251
82
156
390
897
Total
(thousand
tons)
149
2,076
194
233
1,114
3,765
914
810
1,719
3,451
6,893
149
2,989
1,004
1,952
4,564
10,658
Source: Authors' calculations.
7-7
-------
Table 7-8. 2020 SECA Fuel Consumption Estimates at 200 nm, All Ships
Commodity
Group
International
Trade Subtotal
Domestic Fleet
(Jones Act and
Other Vessels)
Total SECA
Region
US Great Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Subtotal
US Great Lakes
US Gulf
US_North_Pacific
US South Pacific
US_East
SECA Subtotal
US_Great_Lakes
US_Gulf
US_North_Pacific
US_South_Pacific
US_East
SECA Total
IFO380
(thousand
tons)
98
2,159
694
1,230
3,083
7,264
129
707
578
369
557
2,340
227
2,865
1,272
1,599
3,639
9,603
IFO180
(thousand
tons)
33
580
228
565
1,091
2,497
61
107
119
71
90
448
95
687
347
636
1,181
2,945
MDO/MGO
(thousand
tons)
17
251
82
156
390
897
252
401
722
607
746
2,727
270
651
804
763
1,136
3,624
Total
(thousand
tons)
149
2,989
1,004
1,952
4,564
10,658
443
1,214
1,419
1,046
1,393
5,515
592
4,203
2,423
2,998
5,957
16,173
Source: Authors' calculations.
7.6 Fuel Consumption Comparison across SECA Scenarios
Figure 7-1 presents a comparison of SECA fuel consumption between the two mileage
zone scenarios in 2012. Intra-SECA MDO and MGO fuel consumption is 44% greater, and
IFO180 fuel consumption is 27% greater under the 200 nm scenario than under the 100/50 nm
scenario. However, IFO380 fuel consumption more than doubles, from 3.4 million tons to 7.9
million tons. As such, total fuel consumption is nearly double under the 200 nm scenario.
Figure 7-2 presents a comparison of SECA fuel consumption between the two mileage
zone scenarios in 2020. Intra-SECA MDO and MGO fuel consumption is 45% greater, and
IFO180 fuel consumption is 26% greater under the 200 nm scenario than under the 100/50 nm
scenario. However, IFO380 fuel consumption more than doubles, from 4.0 million tons to 9.6
million tons. As such, total fuel consumption is nearly double under the 200 nm scenario: 16.2
million tons versus 8.9 million tons.
-------
io,uuu •
14,000 -
12,000 -
10,000 -
8,000 -
6,000 -
4,000 -
2 000 -
0 -
3,398
7,891
1
IFO380
1 875
2,321
1
IFO180
D1 00/50 nm
2,296
3,314
13,527
7,519
MDO/MGO
D 200 nm
1
Total
Figure 7-1. Comparison of SECA Fuel Consumption under Two Mileage Zone
Scenarios, 2012
IO.UUU
16,000 -
14,000 -
12,000 -
c! 10,000 -
0
£ 8,000 -
c
| 6,000 -
o
H 4,000 -
2,000 -
n -
9,603
4,043
?TVi
'
2,945
2,490
3,624
16,173
8 867
IF0380
IF0180
MDO/MGO
Q100/50 nm D200nm
Total
Figure 7-2. Comparison of SECA Fuel Consumption under Two Mileage Zone
Scenarios, 2020
7-9
-------
SECTION 8
SECA FUEL IMPACT ASSESSMENTS
This section presents the WORLD model results of the SECA designation under the two
scenarios detailed in Section 7: (1) a SECA at 100 nm off the Pacific Coast and 50 nm off the
Gulf and East Coasts and (2) a SECA at 200 nm off the Pacific, East, and Gulf Coasts. The
WORLD model case runs were developed using the assessments of affected fuel volumes
developed in Section 7 and EPA's scrubber penetration scenarios from Section 6.1
In addition, model run variants were undertaken for selected cases that added a Mexico
SECA, with the same fuel-quality regulations that apply in the U.S. (including innocent passage
in western Canada) cases. For the cases that include Mexico, we used a simplified approach.
Rigorous route analysis was not conducted. The incremental affected fuel volume was taken as
10% of the fuel volume applying to the U.S. SECA cases. Seventy-five percent of the fuel was
projected to come from the WORLD model's Greater Caribbean region (which includes
Mexico), with the remaining 25% spread across the U.S. regions.
8.1 Summary
This subsection summarizes key results of the SECA fuel impact analysis; the rest of this
section contains a more detailed discussion of the model cases and analytic results. As shown in
Table 8-1, projected global marine bunker consumption for 2012 and 2020 is 406 million tons
and 495 million tons, respectively. These projections correspond to an estimated demand of 358
million tons in 2007. Annual bunker demand growth rate through 2020 is just over 2.5%, which
is appreciably higher than the growth rate for total global petroleum products projected by EIA
when its 2006 Annual Energy Outlook is used as a reference case (1.4% per year) (EIA, 2006).
Global bunker consumption is composed of approximately 80% heavy IFO grades and
20% distillate grades (Figure 8-1). In 2012, the distillate grades are split between DMB-grade
MDO (25%) and DMA-grade MGO (75%). Over time, the proportions of IFO and MDO are
projected to increase moderately at the expense of MGO, reflecting increases in long-distance,
large ship trade.
1 This work was built on prior tasks undertaken for EPA, as well as assignments that EnSys and Navigistics
performed for the American Petroleum Institute (API) and IMO. Those analyses, like this one for EPA, consider
the refining investment, supply cost, and CO2 emissions effects of potential marine fuels regulations. While the
cases evaluated for API and IMO focused on global and multiple SECA scenarios, the cases evaluated here
superimpose a range of potential North American SECA scenarios onto a base case that represents the status quo
(i.e., current Annex VI regulations with SECAs at current standard in Northern Europe [Baltic and North
Sea/Channel], plus the EU 0.1% sulfur rule on marine distillate). Insights gained through the API and IMO
analyses were used mainly to set premises for base-case marine fuels qualities.
8-1
-------
Table 8-1. Base Effects and Total Bunker Fuel Volumes
Total Marine Distillate Plus IFO— No Scrubbing
SECA-Affected Fuel Volumes
Year
2007
2012
2020
2012
2020
2012
2020
100/50 nm
million tons/year
7.7
9.6
bpd
143,000
178,600
percent
1.9%
1.9%
USA
200 nm
million tons/year
13.9
16.6
bpd
255,900
304,200
percent
3.4%
3.3%
USA/Canada/Mexico
200 nm
million tons/year
15.3
18.2
bpd
281,300
334,600
percent
3.8%
3.7%
Total Global Fuel
Volumes
million tons/year
357.9
406.2
495.3
bpd
7,428,800
9,051,300
Note: Includes innocent passage in western Canada.
Q no/
OU/o
fiO% -
40%
70%
0%
DMGO
DMDO
• IFO180
• IFO380
2012
16.0%
5.3%
10.7%
68.1%
2020
14.0%
6.0%
10.9%
69.1%
Figure 8-1. Makeup of Global Bunker Fuel, 2012 and 2020
The quantities of marine bunker fuels consumed in the United States are projected to be
34.9 million tons per year in 2012 and 40.9 million tons per year in 2020, corresponding to about
8.5% of the global fuel consumption total.
The SECA boundary scenarios, including an approximation for a Mexico SEC A, yield a
total fuel consumption ranging from 7.7 million tons per year (143,000 bpd) under the 2012 U.S.
100/50 nm scenario to 18.2 million tons per year (334,600 bpd) under the 2020 U.S. 200 nm plus
8-2
-------
Mexico scenario. These levels equate to a range of 22% to 44% of U.S. bunker demand and
approximately 1.9% to 3.8% of global bunker consumption.
Depending on the time horizon and SECA boundary scenario, approximately 68% to
80% of the affected fuel volume is projected to be consumed in the United States and Canada
(Table 8-2). The proportions consumed in the United States are highest at the 100/50 nm zone
and lowest at the 200 nm plus Mexico SECA zone. In addition, the proportions projected to be
consumed in the United States decline slightly from 2012 to 2020. This shift reflects the
increasing significance of international trade between the United States and other nations.
Table 8-2. Proportion of Affected Bunker Fuel Volumes in the United States and Canada
Total Marine Distillate Plus IFO— No Scrubbing
SECA-Affected Fuel Volumes
Year
2012
2020
USA
100/50 nm
(percent)
79.9%
78.0%
200 nm
(percent)
74.9%
72.0%
USA/Canada/Mexico
200 nm
(percent)
70.4%
67.8%
Compliance with the projected North American SECA regulations will affect both
distillate (MDO and MGO) and heavy (IFO) bunker fuels (unless scrubbers are used). All the
model runs, save one, envisage conversion of MGO, MDO, and IFO grades at present-day
standards to DMA MGO-quality at sulfur levels ranging from 0.5% to 0.1% (5,000 ppm to 1,000
ppm). Global MGO (DMA) base-case sulfur was set to 0.5% (5,000 ppm), and MDO (DMB)
was set to 1.0% (10,000 ppm). As such, the primary effect of SECA standards with DMA at
0.5% (5,000 ppm), 0.2% (2,000 ppm), and 0.1% (1,000 ppm) sulfur relates to the cost of
converting IFO to DMA. The costs attributable to sulfur reduction of MGO fuel already at DMA
standard, or conversion of DMB-standard MDO at maximum 1.0% sulfur to DMA at lower
levels, represent the minority of the conversion cost.2 By far, the greater proportion of the total
compliance cost will relate to conversion of the IFO bunker grades to DMA MGO standard. This
will entail both upgrading and desulfurization; current global average IFO sulfur is around 2.7%
(27,000 ppm). Percentage sulfur by weight is generally below 1% (10,000 ppm) for MDO and
MGO.
2 Because MDO in the base cases is at DMB standard, there are some costs associated with the tighter viscosity,
lower maximum density, and elimination of any carbon residue associated with a change to DMA. These are in
addition to the costs of sulfur reduction.
8-3
-------
Table 8-3 shows the volumes of IFO required to be upgraded to DM A-standard MGO
under the different SECA scenarios analyzed and at the different scrubber-penetration levels
used. For 2012, EPA advised a base level of scrubber penetration of 0% and a high level of 5%,
implying that there is essentially no potential scrubber use until after 2012. For 2020, EPA
advised a best estimate of 31% of fuel consumption used by ships outfitted with scrubbers, with
a high estimate of 47% and a low of 0%. Thirty-one percent of fuel consumed by ships using
scrubbers equates to a smaller proportion of all ships because it is expected that scrubbers would
be fitted preferentially to larger ships with higher fuel consumption.
Table 8-3. Affected Bunker Fuel—IFO Shifted to Distillate
Alternative Mileage Zone
and Scrubbing Scenarios
SECA-Affected Fuel Volumes
USA
Year
2012
2012
2020
2020
2020
2012
2012
2020
2020
2020
Scrubbing
0%
5%
0%
31%
47%
0%
5%
0%
31%
47%
1500/0 nm
million tons/year
5.3
5.1
6.6
4.6
3.6
bpd
92,000
87,000
116,000
81,000
64,000
200 nm
million tons/year
10.7
10.1
13.0
(9.0)
6.9
186,000
176,000
228,000
(157,300)
122,000
USA/Canada/Mexico
200/200 nm
million tons/year
11.8
(11.2)
(14.4)
(10.0)
7.7
207,000
(196,700)
(256,600)
(177,000)
136,000
Notes: 1. Scrubbing usage level—percentage of fuel.
2. Figures in parentheses indicate WORLD case not run.
For 2012, the projected total volume of IFO to be converted to DMA-grade MGO is
somewhat greater than 5 million tons per year (92,000 bpd) if the SECA boundary is set at
100/50 nm, essentially doubles at 200 nm, and increases by an additional 10% (to 11.8 million
tons per year [207,000 bpd]) if Mexico is included.
For 2020, the range of IFO to be converted is estimated to be 6.6 million tons to 14.4
million tons per year (116,000 bpd to 256,600 bpd) if there is no use of scrubbers. However, this
range drops to 4.6 million to 10.0 million tons per year (81,000 bpd to 196,700 bpd) under
8-4
-------
EPA's "best estimate" of 31% scrubber use. Under the high estimate of 47% scrubber
penetration, the range of IFO to be converted reduces to 3.6 million tons to 7.7 million tons per
year (64,000 bpd to 136,000 bpd).
One implication of this finding is that, if scrubber use becomes significant by 2020, then
the volumes of IFO that will need to be converted to MGO will potentially be no larger—and
quite possibly smaller—in 2020 than in 2012. The analytic results show that the largest refining
and cost effects potentially will occur in 2012, because scrubber penetration by 2020 reduces the
fuel volumes to be converted, both in absolute terms and as a percentage of total global bunker
and oil products demand.
Overall, it should be kept in mind that these analyses relate to a small proportion of total
global oil demand of around 0.16% to 0.32% at 0% scrubbing, depending on SECA boundaries,
dropping by up to half under 2020 high scrubber-use scenarios. In addition, the actual total
volumes of future bunker fuel meeting SECA standards likely would be higher because other
SEC As would come into effect.3 The implementation of other SECAs or equivalent regulations
would tend to raise costs for bunker fuel quality improvement or conversion to distillate.
Tables 8-4 through 8-6 summarize key results from the WORLD model cases.
Table 8-4 contains results from 2012 and 2020 cases at the 100/50 nm scenario for
different sulfur levels, from 10,000 ppm to 1,000 ppm. Recall that all 2012 cases are at 0%
scrubbing; for the 2020 cases at multiple sulfur levels, scrubbing penetration was assumed to be
47%.4 As would be expected, costs increase with lower sulfur level and with use of DMA rather
than IFO in 2012. The North American SECA affects fuel costs mainly in the United States and
Canada. Marine fuel costs in these countries increase $1.16 to $1.35/barrel (bbl) in 2012 at
100/50 nm and increase $2.47 to $2.80/bbl at 200 nm.
3 The study was carried out with all regions outside North America at current 2007 regulations. Therefore, this study
included the two Northern European SECAs and the EU 0.1% marine diesel rule, but excluded any other
potential developments.
4 Limits on the total number of cases mean that not all permutations of mileage zone, sulfur level, and scrubber use
were run.
3-5
-------
Table 8-4. Effects of the Bunker Fuel Standard and Sulfur Level
2012 and 2020 USA SECAs—100/50 nm
Year
Scrubber Penetration
SECA Sulfur Level
ppm
SECA Fuel
Cost and Investment Changes vs. Base Case
Marine fuels global average cost ($/bbl)
All products global average cost ($/bbl)
Marine fuels U.S. and Canada average cost
($/bbl)
All products U.S. and Canada average cost
($/bbl)
Global refining investment ($bn)
Global Refinery and Marine Fuel CO2
Emissions vs. Base Case
Million tpa
Global marine fuel
Global refinery
Combined
Combined — percentage change vs. base case
2012
0%
1.0%
10,000
IFO
$0.024
$0.005
$0.294
$0.027
$0.14
(0.47)
0.06
(0.41)
(0.02%)
2012 2012 2012
0% 0% 0%
0.5% 0.2% 0.1%
5,000 2,000 1,000
DMA DMA DMA
$0.126 $0.139 $0.148
$0.033 $0.037 $0.038
$1.164 $1.284 $1.353
$0.069 $0.084 $0.090
$1.42 $1.36 $1.33
(1.18) (0.51) (0.37)
1.60 1.65 1.64
0.42 1.14 1.27
0.02% 0.05% 0.06%
2020 2020 2020
47% 47% 47%
0.5% 0.2% 0.1%
5,000 2,000 1,000
DMA DMA DMA
$0.129 $0.150 $0.151
($0.003) $0.003 $0.003
$0.903 $0.952 $0.939
$0.025 $0.029 $0.033
$0.98 $1.11 $1.38
(0.64) (0.15) (0.28)
0.94 1.30 1.41
0.30 1.15 1.13
0.01% 0.04% 0.04%
For 2020, the increases at 0% scrubbing are $0.90 to $1.64/bbl at 100/50 nm and $1.64 to
$3.02/bbl at 200 nm. At 47% scrubbing, the incremental U.S. marine fuel costs approximate
$1.84/bbl. Marine fuels in other regions also are affected to a small degree, because part of the
North American quality fuel is sourced outside the United States. Consequently, global marine
fuels costs increase by around $0.13 to $0.29/bbl depending on the scenario, for both 2012 and
2020, except that the 2020 increase at 200 nm and 0% scrubbing is estimated at $0.39/bbl.
Enacting the North American SECA increases the proportion of distillates in the U.S.,
Canadian, and global product pools and reduces the proportion of residual-type fuels.
Consequently, nonbunker distillate costs rise, costs of residual fuels drop slightly, and costs of
other products are affected slightly. At 0.5% to 0.1% DMA standards, total U.S. petroleum
product costs rise by $0.070/bbl to $0.240/bbl in 2012 and $0.023/bbl to $0.070/bbl (at 47%
scrubbing) in 2020. Global total product costs also are affected.
-------
In the 2020 cases, global refining investment is estimated to increase. In 2012, the reverse
trend is found. Prima facie, this is contrary to expectation but, as mentioned elsewhere, the
affected fuel volumes are a small proportion of global fuel demand. Thus, the model is incurring
increasing product supply costs with lower sulfur in 2012, but is doing so by making small
changes in blends and refining operations and capacity additions such that total investment
decreases slightly.
Because only small proportions of global fuels are changing quality or type under the
SECA scenarios, the effects on global marine fuel and refining emissions are small. Broadly,
increases in refinery CC>2 emissions driven by increases in processing intensity are offset
partially by reductions in the CC>2 emissions from marine fuels combustion, such that there are
small net increases, mainly less than 0.10%, excluding the effects of petroleum coke.5
Table 8-5 indicates that switching from a 100/50 nm scenario to a 200 nm SECA
boundary scenario approximately doubles incremental costs. For instance, 2012 U.S. marine fuel
costs rise by $1.35/bbl at 100/50 nm and by $2.70/bbl at 200 nm. Incremental global refining
investment also doubles from $1.33 billion to $2.55 billion, although these increases are against
a base-case total investment from 2006 to 2012 of $219.6bn. At high scrubber-penetration levels,
projected effects in 2020 are smaller than those in 2012.
Table 8-6 illustrates the effect of scrubber use in 2020. Incremental marine fuel costs and
refining investments drop proportionately with the percentage of marine fuel that must meet the
SECA standard. Thus, U.S. marine fuel costs drop from $1.63/bbl at 0% scrubbing to $0.94/bbl
at 47% scrubbing.
8.2 Basis of WORLD Model Cases for SECA Fuels' Effects
The following summarizes the WORLD model cases run for 2012 and 2020, the
projected affected volumes of marine fuels under the North American SECA scenarios, the
methodology employed for iterating on bunker demand, and key premises for marine fuels'
qualities.
5 The authors caution that the effects on CO2 emissions, especially in some cases, are so small that they are
approaching the limits of precision of the model.
3-7
-------
Table 8-5. Effect of Mileage Zone and Mexico SECA
2012 and 2020 USA SECAs—100/50 and 200/200 nm
Year
SECAs
Mileage Zone
Scrubber Penetration
SECA DMA Sulfur Level
ppm
Cost and Investment Changes vs. Base Case
Marine fuels global average cost ($/bbl)
All products global average cost ($/bbl)
Marine fuels U.S. and Canada average cost
($/bbl)
All products U.S. and Canada average cost
($/bbl)
Global refining investment ($bn)
Global Refinery and Marine Fuel CO2
Emissions vs. Base Case
Million tpa
Global marine fuel
Global refinery
Combined
Combined — percentage change vs. base case
2012
U.S.
100/50
0%
0.1%
1,000
$0.15
$0.04
$1.35
$0.09
$1.33
(0.37)
1.64
1.27
0.06%
2012
U.S.
200/200
0%
0.1%
1,000
$0.26
$0.10
$2.70
$0.22
$2.55
(0.45)
3.16
2.70
0.12%
2012
U.S./
Can/Mex
200/200
0%
0.1%
1,000
$0.29
$0.11
$2.80
$0.23
$2.86
(0.97)
3.25
2.27
0.10%
2020
U.S.
100/50
47%
0.1%
1,000
$0.15
$0.00
$0.94
$0.03
$1.38
(0.28)
1.41
1.131
0.04%
2020
U.S.
200/200
47%
0.1%
1,000
$0.24
$0.01
$1.64
$0.07
$2.63
(1.80)
2.39
0.59
0.02%
2020
U.S./
Can/Mex
200/200
47%
0.1%
1,000
$0.26
$1.01
$1.77
$0.07
$2.89
(0.18)
2.46
2.28
0.09%
Table 8-6. Effect of Scrubber Penetration
2020 0.1% Sulfur DMA USA SECAs-
Scrubber Penetration
Cost and Investment Changes vs. Base Case
Marine fuels global average cost ($/bbl)
All products global average cost ($/bbl)
Marine fuels U.S. and Canada average cost ($/bbl)
All products U.S. and Canada average cost ($/bbl)
Global refining investment ($bn)
Global Refinery and Marine Fuel CO2 Emissions vs. Base Case
Million tpa
Global marine fuel
Global refinery
Combined
Combined — percentage change vs. base case
-100/50 nm
0%
$0.24
$0.008
$1.63
$0.07
$2.50
(1.6)
2.3
0.7
0.03%
31%
$0.19
$0.004
$1.20
$0.04
$1.70
(1.1)
1.8
0.7
0.03%
47%
$0.15
$0.003
$0.94
$0.03
$1.38
(0.3)
1.4
1.1
0.04%
-------
8.2.1 Cases Run
Table 8-7 sets out the 26 cases that were analyzed in the WORLD model. Based on EPA
guidance, 10,000 ppm cases (which retained the current IFO/MDO/MGO grade structure) were
run only for 2012. The main emphasis was on cases requiring conversion of affected fuel
volumes to medium- (5,000 ppm) or low-sulfur DMA standard fuel (2,000 ppm or 1,000 ppm).
The differing sulfur levels were combined with permutations of nautical mileage zones, Mexico
SECA designation, and scrubber penetration to probe sensitivity effects. Note that what would be
the most costly case for 2020—at 1,000 ppm, 0% scrubbing, 200 nm (plus Mexico)—was not
requested and has not been run; therefore, the results for 2020 should be considered in this light.
Table 8-7. Summary of WORLD Cases—Revised
Summary of Model
Runs
High Sulfur— 2012
Medium Sulfur— 2012
Low Sulfur
2,000 ppm— 2012
Low Sulfur
1,000 ppm— 2012
Medium Sulfur —
2020a
Low Sulfur
2,000 ppm— 2020
Low Sulfur
1,000 ppm— 2020b
Time
Horizons
(2012/2020)
2012
2012
2012
2012
2020
2020
2020
Mileage
Zones
100/50
100/50
100/50
200/200
100/50
200/200
100/50
200/200
100/50
200/200
100/50
200/200
Number of
SECA
Regions
1
1
1
1
1
1
1
Sulfur
Levels
10,000
5,000
2,000
1,000
5,000
2,000
1,000
Scrubber
Penetration
Rates
0%, 5%
0%
0%
0%, 5%
0%, 31%, 47%
47%
0%, 31%, 47%
Total
WORLD
Case Runs
2
1
2
4
5
2
4
Mexico Runs: 10% fuel increase to approx. Mexico
Medium/Low
Sulfurs— 2012
Medium/Low
Sulfurs— 2012
Total Runs
2012 200/200 1 5,000 0%
2,000
1,000
2020 200/200 1 5,000 47%
2,000
1,000
— — — — —
3
3
26
a 31% penetration was run only at 100/50 nm.
b Only 47% penetration was run at 200 nm.
8.2.2 Bunker Quality Itemizes
The WORLD cases were run with the following bunker quality premises. These premises
are the same as those used in parallel work undertaken by EnSys and Navigistics for the EVIO:
8-9
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1. Recent analyses of sample data undertaken by DNV, together with feedback from the
bunker departments of major oil companies, have confirmed that (a) marine distillates
are overwhelmingly either DMA or DMB, not DMC, and that (b) the majority of
global distillate sold is at DMA standard. (This is doubtless driven, in part, by
constraints in the oil companies' logistics/distribution systems.) The updated findings
on marine distillates were incorporated into the base cases:
- MGO fuel was kept universally as DMA grade and MDO set to DMB standard.
— Based on findings from the EVIO work, a 70:30 split of MGO:MDO was applied
to the total distillate volumes in each region.
— The volume of MGO was further increased—and that of MDO reduced—in the
EU regions to reflect the EU 0.1% sulfur rule. Base-case MGO in the EU regions
was thus already at 0.1% sulfur.
The net effect was to arrive at an approximate 75:25 ratio globally of MGO (DMA)
to MDO (DMB) in the base cases.
2. Based on sample test results and commentary from DNV, maximum density and
viscosity specifications for DMA and DMB were set based on allowing small
increments over current reported worldwide averages (see Table 8-8).6
3. Base-case global average sulfur levels for DMA and DMB were set to 0.5% and
1.0% sulfur nominal, respectively. The same DNV sample results mentioned above
show current average levels of 0.35% and 0.55% (Kassinger, 2007). These are well
below the ISO 8217 specification limits for DMA and DMB of 1.5%. There are
arguably conflicting forces that will be at play through 2020. Logistical constraints
and the progressive reduction of sulfur levels in other diesel fuels and gas oils likely
will constrain increases in DMA and DMB sulfur levels. Conversely, refiners can be
expected to seek opportunities wherever possible to optimize against specifications,
with the potential that DMA and DMB sulfur levels would therefore rise.7 If marine
fuel volumes increase and if price differentials versus other diesel/gas oil grades
increase, refiners and blenders will have greater incentives to segregate marine fuels
and produce them closer to their (sulfur) specifications. The view was taken to follow
a middle path of allowing modest increases (i.e., to 0.5% and 1.0% nominal sulfur), to
reflect both sets of factors.
4. Carbon residue content (MCR) on DMB was set to 0.05% by weight maximum.
DNV reported a 0.1% global average but also reported that part of the fuel ordered as
DMB is actually delivered as DMA, indicating that what is considered in WORLD as
DMB (i.e., MDO in the base case) should have a lower MCR than 0.1%. Also, bunker
fuel testing generally is assumed to take place at downstream stages in the bunkering
supply system, where contamination may have occurred. Thus, the quality at the
refinery or blender can be expected to be tighter than that tested. Allowing 0.05%
6 The maximum density for DMA was set at 0.860 versus 0.890 specification and 0.853 reported global average; the
maximum density for DMB was set at 0.875 versus 0.900 specification and 0.865 global average. Maximum
viscosities were set at 3.8 cSt and 4.5 cSt at 40°C versus global averages of 3.5 cSt and 4.2 cSt and ISO 8217
specifications of 6 cSt and 11 cSt at 40°C maximum.
7 In the 2012 and 2020 base cases, current Annex VI (ISO 8217 2005) fuels regulations apply.
8-10
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carbon residue in WORLD for DMB creates a situation where a proportion of (light)
vacuum gas oil is allowed into the DMB blends. To meet sulfur and viscosity
specifications, lighter (heavy kerosene) streams are also added to the blend. The
authors believe such blends may not be in accord with current blending practice (i.e.,
that the appreciable vacuum gas oil content is not realistic). However, setting carbon
residue at nil would have locked out vacuum gas oils totally and thus increased the
costs for DMB in the base case, which would have raised the costs of the SEC A cases
versus the base cases.
5. The EU 0.1% rule was implemented by shifting MDO to MGO specification at 0.1%
sulfur DMA standard. Based on data supplied by IMO, Cofala et al. (2000) data
corresponded to approximately 50% of EU marine distillate being at the 0.1% sulfur
standard. Consequently, 50% of the base MDO volume for Europe (North South and
East) was reallocated and added to MGO. The remaining 50% stayed as MDO, of
which, 70% was presumed to come under SECA standard (Europe North in the base
case and all three European regions in the multiple SECA cases).
6. Maximum sulfur level for the two IFO grades was set to 3.5% nominal (3.4%
actual limit). As for DMA and DMB, the rationale was based on comparison of the
current specification (4.5%) with actual data. DNV data show regional average sulfur
levels for IFO fuel in the range of 2.3% to 3.4%, with an overall global average of
2.7% (see Table 8-9). The authors believe that this average sulfur level can be
expected to gradually move upward over time (under current regulations), as crude
sulfur levels rise and pressure on sulfur grows, leading to high sulfur residual fuels
being a convenient sink. Conversely, (a) there are logistical constraints on residual
fuel supply such that IFO fuels are at times co-sold as high-sulfur inland fuels, which
often have a 3.5% maximum sulfur, and (b) it is understood that the IMO would act to
constrain any sharp increase in IFO sulfurs. However, it was not the intention to
create base cases that would have required appreciable "on-purpose" residual
desulfurization, which would have been the case had the current average of 2.7%
been selected. As with the marine distillates, 3.4% was considered to represent a
reasonable middle path.8
1 As discussed in Section 8.3, the selection of a 3.4% maximum led to a global average IFO in the 2020 base case of
just over 3.2% sulfur. Also, the case lead to only a small increase (24,000 bpd) in residual desulfurization versus
the API 2020 base case. That case, with a 4.5% nominal ±0.2% giveaway had IFO global average sulfur at
3.56%. The situation that resulted in the EPA 2020 base case was considered reasonable.
8-11
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Table 8-8. DNV Petroleum Services Bunker Quality Report
Sulfur % m/m
Region
Northern Europe
Western Mediterranean
Central Mediterranean
Middle East
Eastern USA
USA Gulf
Western USA
Far East
Average
IFO180
1.9
2.9
2.6
3.4
2.7
3.1
2.6
2.8
2.6
Average
IFO380
2.3
3.0
2.6
3.4
2.4
3.2
2.4
3.1
2.7
IFO180
2.8
3.6
3.5
4.2
3.9
3.7
3.4
4.1
3.6
Max
IFO380
4.3
3.8
3.6
3.9
4.3
4.2
3.1
4.5
4.1
Note: Issued August 10, 2006.
8.2.3 Bunker Fuel Demand Projections
The RTI/Navigistics bunker demand projections originally developed in 2006 for EPA
under Task 1 were adjusted to employ different MGO/MDO grade splits, as described above. We
applied rigorous analysis of trade routes and volumes to assess volumes of marine fuel that
would need to meet U.S./Canadian SECA standards. For 2012, this led to a projection of nearly
80% of the affected fuel being consumed in the United States and Canada, with the percentage
somewhat lower in 2020. Table 8-10 provides an overview.
8.2.4 WORLD Model Weight/Volume Features and Bunker Methodology
Although WORLD was developed as a volume-based model, it also includes extensive
weight-based features. Specifically, these features are as follows:
1. Every refinery unit processing vector is weight and sulfur balanced to within tight
tolerances.
2. As well as drawing up a volume balance—which allows for process gain—a
supply/demand weight-balance check is undertaken at the global level. This check
uses static gravities for most products and supply streams, including major products.
Crude gravities are a direct function of individual crude production volumes. The
model is capable of accepting adjustments to the global average blend gravities used.
Future extensions could lead to automation of this model based on the computed
actual gravities of blended products.
8-12
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Table 8-9. Comparison of Fuel Grade Specifications
Category ISO-F-
Characteristic
Density at 15°C
Viscosity at 40°C
Flash point
Pour point (upper)0
Winter quality
Summer quality
Cloud point
Sulfur
Cetane index
Carbon residue on 10%
(V/V) distillation bottoms
Carbon residue
Ash
Appearancef
Total sediment, existent
Water
Vanadium
Aluminum plus silicon
Used lubricating oil (ULO)
Zinc
Phosphorus
Calcium
Unit
kg/m3
mm2/sb
°C
°C
°C
°C
% (m/m)
—
% (m/m)
% (m/m)
% (m/m)
—
% (m/m)
% (V/V)
mg/kg
mg/kg
mg/kg
mg/kg
mg/kg
Limit
max
min
max
min
max
max
max
max
max
min
max
max
max
—
max
max
max
max
max
max
max
DMX DMA
— 890,0
1,40 1,50
5,50 6,00
— 60
43 —
— -6
— 0
-16d -
1,00 1,50
45 40
0,30 0,30
— —
0,01 0,01
Clear and bright
— —
— —
— —
— —
— —
— —
— —
DMB
900,0
—
11,0
60
—
0
6
—
2,00e
35
—
0,30
0,01
f
0,1 Of
0,3f
—
—
—
—
—
DMCa
920,0
—
14,0
60
—
0
6
—
2,00e
—
—
2,50
0,05
—
0,10
0,3
100
25
The fuel
shall be free
ofULOg
15
15
30
Test Method
Reference
ISO 3675 or ISO
12185 (see also 7.1)
ISO 3 104
ISO 3 104
ISO 271 9
(see also 7.2)
ISO 3016
ISO 3016
ISO 3015
ISO 8754 or ISO
14596 (see also 7.3)
ISO 4264
ISO 10370
ISO 10370
ISO 6245
See 7.4 and 7. 5
ISO 10307-1 (see
7.5)
ISO 3733
ISO 14597 or IP 501
or IP 470 (see 7.8)
ISO 10478 or IP 501
or IP 470 (see 7.9)
IP 50 lor IP 470
IP 50 lor IP 500
IP 501 or IP 470 (see
7.7)
a Note that although predominantly consisting of distillate fuel, the residual oil proportion can be significant.
b 1 mm2/s = 1 cSt
0 Purchasers should ensure that this pour point is suitable for the equipment on board, especially if the vessel
operates in both the northern and southern hemispheres.
d This fuel is suitable for use without heating at ambient temperatures down to -16°C.
e A sulfur limit of 1.5% (m/m) will apply in SOX emission control areas designated by the International Maritime
Organization, when its relevant protocol enters into force. There may be local variations, for example the
EU requires that sulphur content of certain distillate grades be limited to 0.2% (m/m) in certain
applications. See 8.3 and reference [7].
f If the sample is clear and with no visible sediment or water, the total sediment existent and water tests shall not be
required. See 7.4 and 7.5.
g A fuel shall be considered to be free of used lubricating oils (ULOs) if one or more of the elements zinc,
phosphorus, and calcium are below or at the specified limits. All three elements shall exceed the same
limits before a fuel shall be deemed to contain ULOs.
8-13
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Table 8-10. Affected and Total Fuel Volumes, Million Tons per Year
Affected and Total Fuel Volumes million tons per year
2012
2020
Affected Fuel Volumes under United
100/50 nm
7.67
9.56
States SECAs
200nm
13.95
16.58
Total Fuel Volumes
406.2
495.3
3. A more rigorous methodology has been adopted for marine fuels, as described below.
4. The weight balances achieved at the global level are generally in the range of 0.2%
weight to 0.5% weight.
Given the existence of bunker demand projections on a weight basis, and the need to
account for the effects of bunker types changing from one class to another (notably IFO to DMB
or DMA distillate), we applied a rigorous, iterative approach to computation of bunker demand
tons, barrels, and related energy content.
There appears to be confusion regarding the fact that, when bunker demand is switched
from IFO to distillate fuel type, the amount of fuel required on a weight basis drops, while the
amount of fuel required on a volume basis rises. Table 8-11 illustrates this computation.
The lighter fuels have higher heating value per unit mass. Therefore, based on the
specific gravities used for illustrative purposes in Table 8-11,9 0.936 tons of DMA delivers the
same heating value as 1.000 tons of IFO380; in other words, fewer tons of DMA are needed.
However, there are large differences in the specific gravities and, hence, in barrels per ton.
Again, based on the specific gravities used, DMA has a specific volume of 7.44 bbl/ton as
compared with 6.46 bbl/ton for IFO380, a factor of 1.152 to 1.000. Thus, DMA has a heating
value of 5.909 million BTU/barrel compared with 6.373 million BTU/barrel for IFO380. Also,
1.0785 barrels of DMA are required deliver the same heating value as 1.0000 barrels of IFO380
(i.e., 6.3730/5.9090 = 1.0785). A similar rationale applies for other fuel conversions (e.g., for
IFO 180 to DMA, DMB to DMA).
9 The specific gravities shown here are not the precise gravities that evolved in the WORLD base case or other
cases, but they are close. The values used here are intended to illustrate the effect and the typical volume factors
that we obtained. Actual volume factors were developed and applied in each WORLD case through the iteration
procedure to converge on consistent tons, barrels, and energy figures.
8-14
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Table 8-11. Computation of Heating Values and Weight and Volume Factors for the Same
Energy Content
Bunker
Grade
MGODMA
MDODMB
MDODMC
IFO 180
IFO 380
Sulfur
wt%
0.20%
0.45%
1.50%
3.00%
3.00%
s.g.
Estimated
0.845
0.8606
0.900
0.968
0.9735
API
Gravity
36.0
32.9
25.7
14.7
13.9
HHV
BTU/lba
19,954
19,779
19,364
18,728
18,680
HHV
million
BTU/ton
43,979
43,594
42,679
41,276
41,172
Tonnes
Required
for Same
HHV vs.
IFO380
0.936
0.944
0.965
0.997
1.000
bbls/
ton
7.4426
7.3077
6.9878
6.4969
6.4602
bbls/
tonne
ratio
1.1521
1.1312
1.0817
1.0057
1.0000
HHV
million
BTU/bbl
5.909
5.965
6.108
6.353
6.373
Barrels
Required
for Same
HHV vs.
IFO380
1.0785
1.0683
1.0435
1.0031
1.0000
a Basis as MEPC formulae.
All the relevant conversions to allow for energy content and density effects were built
into WORLD. Unlike all the other fuels, the source data for bunker demand per RTI and
Navigistics are in tons. An iterative procedure was consequently adopted. The bunker-tons
figures by grade were multiplied by assumed gravities to give initial volumes (million bpd). A
first-pass case was then run. Global average gravities for each bunker grade were extracted from
the model case results and fed back into the input to adjust the bunker volumes derived from the
initial figures in tons. If necessary, the iteration was repeated to ensure stable gravities. This
procedure was used to establish a converged base case.
For subject cases, the iterative procedure with the MEPC energy content formulae
enabled computation of volume factors for each shift (i.e., IFO180 and IFO380 to DMA, DMB
to DMA), taking into account the energy effect on a BTU per barrel basis and which were based
on fuel global average gravities.10 Again, the case was iterated to ensure stable blend gravities. In
this way, the main energy content effects of bunker grade shifts were captured by altering the
volume demand and, at the same time, consistency was maintained between the bunker demand
figures in tons and in barrels.
The effect of this situation is that partial or total conversion of IFO to distillate leads to a
reduction in the total global tons of bunker fuel required but also leads to an increase in the
barrels required. These effects are evident in the WORLD case results.
10 The global average gravities by bunker fuel type are built up from the barrels, gravities, and tons of demand in
each region.
8-15
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8.2.4.1 Model Reporting Extensions
Reporting extensions developed under the EnSys and Navigistics work for the IMO have
been applied to the model reports here. Specifically, we applied the following:
1. bunker fuels' demand in weight, as well as in volume units
2. base 2006 capacities by major unit type by region and "allowed" project capacity
additions by major unit by region (these are added in WORLD to the base refining
capacities so that the model selects what is needed on top of base capacity plus
known construction)
3. the total investment by region associated with the allowed projects, which then
provides a picture—when added to the base-case investments selected by WORLD—
of the total base-case investment needed over the 2006 base capacities and better
enables the magnitude of the subject-case incremental investments to be put into
context
4. regional reports on internal refinery energy consumptions and refinery CO2 emissions
In addition, case results for the United States and Canada are broken out.
8.3 Case Results Details
The following is an itemization of results categorized into refining investments, refining
capacity additions, marine fuel costs, and CO2 emissions. These categorizations act to extend the
discussion presented in Section 8.1. They are presented in conjunction with Tables 8-12 through
8-15, which provide comparisons with the respective 2012 and 2020 base cases of key WORLD
model results. These categorizations also form the basis of the tables presented in Section 8.1.
8.3.1 Global Refinery Investments and Capacities
Refinery investment increases versus the base cases for 2012 and 2020, respectively, are
as follows:
• 2012
- 10,000 ppm (IFO) + $0.14bn
- 5,000 ppm-1,000 ppm (DMA) $1.3bn$1.4bn at 100/50 nm, rising to $2.5bn at
200/200 nm and to more than $2.8bn at 200/200nm + Mexico. Essentially all
results are at 0% scrubbing.
8-16
-------
• 2020
- 5,000 ppm-1,000 ppm (DMA) $lbn-$2bn at 100/50 nm, rising to $2bn-$4bn at
200/200 nm. Scrubber use is the main determinant of investment level. Raising
use from 0% to 47% essentially halves investment. Adding in the Mexico SECA
raises global investment by around $0.2bn-$0.4bn
Capacity additions in 2012 cases center on small increments in vacuum distillation and
hydro-cracking (mainly resid), VGO/residual desulfurization plus associated hydrogen, and
sulfur recovery plant. The 2020 cases present a slightly different picture: they present vacuum
distillation, but also coking and hydro-cracking as the main addition (mainly ULS VGO type),
with partially offsetting reductions in ULS gasoline and diesel desulfurization, again supported
by additions to hydrogen and sulfur plant.
U.S./Canadian refinery investments increase in all subject cases, but the bulk of the
investments occur outside the United States and Canada. These two countries generally represent
around 10% to 30% of the total incremental investment. Especially in 2012, U.S./Canadian
refinery throughputs are projected to drop (from 31,000 bpd to 161,000 bpd), partially offset by
increases elsewhere. For the 2020 cases, the effect is still there, although it is smaller.
8.3.2 Crude Supply Cost/Price Differentials
In the 2012 cases, crude differentials (stated as WTI - Mayan) widen by around 14 c/bbl
under 100/50 nm scenarios, rising to around 35 c/bbl at 200/200 nm and 36 c/bbl to 41 c/bbl at
200/200 nm plus Mexico. Projected 2020 impacts on differentials are smaller.
8.3.3 Product/Marine Fuels' Costs
- 2012
- Under the 10,000 ppm IFO scenario, low-sulfur IFO380 costs rise by $2.64-
$2.92/bbl on the U.S. Gulf and East Coasts and $4.20/bbl on the West Coast.
There are also changes from -2 c/bbl on the West Coast to +7 c/bbl on the Gulf
Coast in MGO/MDO supply costs.
— Under the DMA scenarios, marine distillate costs rise by $1.53-$2.51/bbl on the
East Coast, $1.28-$2.23/bbl on the Gulf Coast, and $1.20-$3.95/bbl on the West
Coast, with the higher levels corresponding to lower sulfur (1,000 ppm) and a
200/200 nm scenario.
- U.S./Canadian supply costs of other distillate fuels also rise by up to 60 c/bbl and
gasoline prices by up to 10 c/bbl; the IFO380 HS price drops.
- Prices in other world regions are also affected.
8-17
-------
• 2020
— Projected increases in U.S./Canadian supply costs for marine distillate vary with
the scenario and region: $1.67-$2.32/bbl on the East Coast, $1.05-$1.71/bbl on
the Gulf Coast, and $3.28-$5.58/bbl on the West Coast, again depending on the
DMA sulfur level, scrubber penetration, and mileage zone.
- Trends in the costs of other products are similar to those for 2012 except that, in
2020, there are slight projected price drops for U.S./Canadian gasoline grades.
8.3.4 Total Fuel Costs (All Products from LPG to Coke, Including Gasoline, Distillates, and
Marine Fuels)
* U.S./Canadian total fuel cost is most affected under the 2012 200/200 nm scenario
because there is little or no projected mitigating scrubber penetration. Total costs rise
by 0.04% to 0.46%, depending on the specific case. For 2020, the corresponding
increases are 0.04% to 0.19%.
• Effects on total global cost across all fuels are indicated at 1 c/bbl to 4 c/bbl for 2012
under 100/50 nm cases and 10 c/bbl to 11 c/bbl under 200/200 nm. For 2020, the
indicated effects are around 1 c/bbl.
8.3.5 CO2 Emissions
* U.S./Canadian refinery CC>2 emissions are projected to rise in 2012 by 0.13 million
tons to 0.85 million tons per year—with larger increases in other regions, ranging
from 1.05 million tons to 2.5 million tons per year.
• For 2020, the U.S./Canadian refinery CC>2 increments are indicated at 0.02 million
tons to 0.35 million tons per year. Elsewhere, the CC>2 increases are indicated at 0.80
million tons to 2.73 million tons per year, leading to total global increments of 0.98
million tons to 3.08 million tons per year. The larger increases in 2020 potentially
reflect a world that already has a higher proportion of distillates in the base-case
scenario and, thus, where the processing and CC>2 effects for additional conversion of
residual streams to distillate are higher.
• Across all cases, global refinery CC>2 emission increases with petroleum coke CC>2
added in generally lie in the range of 2.7 million tons to 6.7 million tons per year.
• The marine fuels tons demanded decrease under the DMA cases; this is because of
DMA's higher energy content per ton than IFO. The effects are small though, around
0.2 million tons to 0.7 million tons per year out of global marine fuel totals of 406
million tons per year in 2012 and 495 million tons per year in 2020. There are small
reductions in associated marine fuel CC>2 emissions.
• These reductions partially offset the refinery CC>2 increases, leading to net increases
on the order of 0.1% to 0.2%.
We reiterate that many of the changes in these EPA cases are small on a global scale.
Consequently, even with the rigorous iteration procedure used to converge marine fuels weight,
volume, and energy (see below), the precision of some of these very small effects on CC>2
8-18
-------
emissions is limited, and the reader is cautioned not to associate too much precision with these
very small changes.
8.4 Tabulated Results
Tabulated results comparing subject cases with base cases are presented in Tables 8-12
through 8-15.
8-19
-------
Table 8-12a. WORLD Model Results—Changes vs. 2012/2020 Base Cases
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8-20
-------
Table 8-12b. WORLD Model Results—Changes vs. 2012/2020 Base Cases
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8-21
-------
Table 8-12c.WORLD Model Results—Changes vs. 2012/2020 Base Cases
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8-22
-------
Table 8-12d. WORLD Model Results—Changes vs. 2012/2020 Base Cases
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-------
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APPENDIX A
REVIEW OF REFINERY PROCESS COSTS1
Task 1 called for an analysis of the potential technical and economic impacts of
designating one or more SEC As along the North American Coastline, as provided by the
MARPOL treaty, Annex VI, which places limits on both NOX and SOX emissions. Countries
participating in the treaty must use a bunker fuel with a sulfur content at or below 4.5%.
Countries participating in the treaty are also permitted to request designation of SEC As in which
ships must treat their exhaust to 6.0 g of SC>2 per kWh or further reduce the sulfur level of their
fuel to 1.5%.
The results obtained from this study will be primarily cost-of-production driven with
respect to the different components of bunker fuel and the resulting fuel oil blend. These tie back
directly to the investment and operating costs applied to the various refinery processes involved
in their production as one of the key factors in determining economic impacts.
Not all refinery processes affect the results in equal measure. Obviously, those processes
directed to producing residual fuel blend components are key, along with processes that produce
blend stocks in the diesel fuel boiling range. Table A-l illustrates a typical composition of
bunker fuel oil, in this example blended to 380 centistokes for bunker grade RMG 35.
Table A-l. Bunker Fuel Composition
Stream
Residual
VGO
MidDistillate
Target
Blend
Quantity
MT
15000
15000
5000
35000
35000
Weight
Percent
43
43
14
100
Viscosity
cks@50 deg C
1500
100
3
380
380
Density®
15 deg C
1.006
0.979
0.85
0.991 max
0.972
Sulfur
WtPct
3
1.5
0.2
4.5
1.96
Vanadium
Mg/kg
600
10
0
300
261
AL+SI
Mg/kg
12
5
0
250
7.3
Water
Vol Pet
0.3
0
0
0.5
0.13
Source: Based on "Bunkers." Fisher, Christopher and Jonathon Lux. 2004. Bunkers, 3rd Edition. Banbury, England:
Petrospot, Ltd. page 33.
1 The mention of certain Licensors and Companies in the text of this appendix and supporting references does not
imply any preference for or endorsement of these processes or endorsement of operating practices as opposed to
alternatives made available or employed by others. This is particularly so since there are several process
alternatives available and several companies involved in any given area of refinery technology and any one may
be more appropriate based on a specific refinery situation. Those processes cited are therefore cited for
illustrative purposes only. The views and opinions of authors expressed herein do not necessarily reflect those of
the United States Government or any agency thereof.
A-l
-------
Using current and recognized sources, the following section provides base data on
investment costs and operating requirements for a variety of refinery processes, with the stress
on the "bottom of the barrel." These are estimates based on current known refinery technology
and do not include revolutionary technology breakthroughs, although these could occur in an
extended 2010-2030 timeframe. They were used to review and guide any modifications required
to cost and operating data in the WORLD model.
Recent progress in refinery technology development has been reported for several of the
refinery process areas considered below. This progress reflects process unit potential for
investment and operating cost reduction and capacity increase through technology advances and
revamp experience, as well as by process product quality and yield improvement. These are
described, again based on current and recognized sources and extend the time frame. In general,
these refer to incremental improvements as opposed to revolutionary breakthroughs, with the
exception of using ultrasound to reduce residual fuel sulfur, which is briefly described.
A.I Atmospheric Residuals Desulphurization
Investment and Operating Costs
Basis 2nd Quarter 1995 U.S. Gulf Coast
Similar erected Chevron Units
Feed Rate 70,000 bpd AR 650+
Feed 11.8 API, 4.37% sulfur, 0.4 % 650+ product for RFCC feed
Investment Cost Summary, millions U.S. dollars:
Total On-Plot Cost 234.2
Total Off-Plot Cost 70.3 (30% of on-plot)
Catalyst Charge 8.8 per charge
Hydrogen and Utility Requirements:
Hydrogen 71.7 million SCFD
Fuel 272 BPD EFO
Power 27,000 kWh
A-2
-------
Net Steam 94 klb/h
Cooling water 8200 gal/min
Net process & BOW -25 kgal/min
Catalyst 8.8 million dollars/year
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 8.22-8.33
Using the latest technology catalysts and improved operational procedures, a large
Middle East refinery has reported a 30% increase in the amount of feed processed in the first
cycle. (NPRA Annual Meeting, March 13-15, 2005. NPRA Paper AM-05-54).
A.2 Vacuum Residual Hydro Cracking
Investment cost depending on feedstock properties and product requirements, typical
investment costs range from $2000 to $ 5000 ISBL per BPSD. Basis 2002. This corresponds to
60-95% desulphurization.
Source: Robert A. Meyers Handbook of 'Petroleum Refining Processes, Third Edition,
2003, pg. 8.81-8.83—LC-Fining.
A.3 Ultra Sound Process to Reduce Heavy Sour Crude Sulfur
Patents awarded in 2005 and earlier describe the application of ultrasound to upgrade
sour heavy crude oil into sweeter lighter crude (U.S. Patent No. 6,897,628, May 24, 2005). A
5,000 bpd commercial demonstration unit is planned with potential scale-up to 25,000 bpd and
joint venture agreements have been entered into. It is anticipated that the technology could have
upstream and downstream applications. A preliminary capital investment estimate of $1 million
for a 2,000 bpd unit or $500 per bpd signals the potential for a dramatic reduction in the cost of
desulphurization of residual fuel oil blend fractions (Chemical Engineering, March and June
2005). This process development is cited here because of its potential impact, but it must be
realized that it is very much in the research and development stage (see www.Sulphco.com for
additional information).Tracking of future progress is warranted.
A.4 Delayed Coking Process
Investment and Operating Requirements:
Investment costs may range from $45,000 to $95,000 per short ton of coke produced.
This excludes the VRU unit and support facilities but includes the coke handling costs. The basis
is 4th quarter 2002 and the Foster Wheeler process.
A-3
-------
Operating requirements based on 1000 BPSD of fresh feed are as follows:
Fuel Liberated 5.1 mmBTU/h
Power consumed 150 kW
Steam exported 17001b/h
Boiler feed water consumed 2400 Ib/h
Cooling water 5-25 gal/min
Raw water consumed 20-35 gal/day per short ton/day coke
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 12.86-12.88.
A.5 Visbreaker Process
Investment and Operating Requirements:
Battery limits investment costs are $17 million for a 10,000 bpsd unit and $33 million for
a 40,000 bpsd unit. This excludes the vacuum flasher and the gas plant. The basis is 4th quarter
2002 and the Foster Wheeler/UOP process.
Typical operating requirements per bpsd of fresh feed are as follows:
Fuel consumed 0.1195 million BTU
Power consumed .0358 kW
Steam consumed 6.4 Ib
Boiler feed water consumed 2400 Ib/h
Cooling water 71 gal/min
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 12.104-12.105.
A.6 Solvent Deasphalting Process (ROSE Process)
Investment and Operating Requirements:
The estimated installed cost for a 30,000 bpsd unit is $1,250 per bpsd. The basis is 2nd
quarter 2002, U.S. Gulf Coast. Typical operating requirements per bbl of feed with propane
deasphalting are as follows:
A-4
-------
Process heat consumed 12 million BTU
Power consumed 1.5-2.1 kWh
Steam consumed 12 Ib
Solvent loss, wt% of feed 0.05-0.10
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 10.27-10.28.
A.7 Gas Oil Hydro Cracker
Investment and Operating Requirements:
Basis Jan 1, 2002 U.S. Gulf Coast
Similar projects executed for UOP Unicracking Process
VGO feed 22.2 API, 2.5% sulfur
Product 94% distillate vs.98% naphtha
Investment Cost Summary, millions U.S. dollars
Total Erected Cost $^psd
Distillate Mode 2500-3500
Naphtha Mode 2000-3000
Typical Utility Requirements, per 1,000 bpsd fresh feed
Fuel 2-6 million BTU/h
Power 200-400 kW
Net Steam 0.11-0.22 klb/h
Cooling water 40-120 gal/min
Net process & BFW 0.08 klb/h
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 7.33.
A-5
-------
A.8 Fluid Catalytic Cracking (FCC)
Investment and Operating Requirements:
Basis 1st Quarter 2002 U.S. Gulf Coast
Similar projects executed for KB RFCC Process
50,000 bpd VGO feed
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 3.32.
Total installed cost $/ bpsd $2,250 to $2,500—Includes gas system (without power
recovery), main fractionator, VRU, and amine treater.
Typical Utility Requirements, per bpsd fresh feed
Steam 40-200 Ib Hp steam
Power 0.7tol.OkWh
Residual cat cracking is significantly different than gas oil cracking with respect to feed
properties and gasoline and distillate yields (conversion). As old FCC units are being replaced
and new capacity is being added, up to 50% of the worldwide FCC capacity will become residual
crackers.
Recent advances in RDS catalyst technology and integration with RFCC catalyst design
have resulted in a 40% reduction on light cycle oil sulfur and a 50% reduction in RFCC sulfur
along with allowing the FCC to process heavier feedstocks. Also a new RDS catalyst system
developed allows substantially more 1,000 degF + material to be processed. (NPRA Annual
Meeting, March 21-23, 2004. NPRA Paper AM-04-29).
Conversions approach 65% with recently tested FCC catalysts.
The heaviest residuals contain high levels of contaminant metals such as nickel,
vanadium and iron. New FCC catalysts have been developed that improve the passivation of
contaminant metals over previous residual matrix technologies. A typical feedstock is a mix of
reduced crude, vacuum bottoms, deasphalted oil and bulk distillate, with feed properties typically
20 API (18-29), 7 wt% Conradson Carbon (0-9), 42 ppm nickel +vanadium( 10-50), 2.0 wt%
sulfur (0.2-2.4), and 0.3 wt% nitrogen(0.05-0.35). The values in parentheses are current
commercial ranges. (NPRA Annual Meeting, March 21-23, 2004. NPRA Papers AM-04-16 and
A-6
-------
AM-04-31). Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition, 2003,
p3.81.
A.9 FCC Stack Emission Reduction
Total 2002 dollar annualized (operating plus capital) costs range from $300 to 600 per
ton of SC>2 removed depending on the specific type of SC>2 wet scrubbing system used.
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 11.28
With the advent of consent decrees, SOX and NOX additives are being used increasingly to
achieve ultra-low FCC stack emissions and reduce acid rain formation. With extensive research
on how these additives work in the FCC regenerator, refiners have been able to reduce SOX
emissions to less than 25 ppm without the high capital cost of installing hardware. NOX emission
reduction poses a more difficult problem and results vary from unit to unit. Commercial
examples demonstrate that NOX reduction can be achieved in excess of 75%. In many units
additives can reduce NOX emissions to 35 ppm and at times below 25ppm of NOX (NPRA
Annual Meeting, March 13-15, 2005 NPRA Papers AM-05-21).
A.10 Low-Sulfur and Ultra Low-Sulfur Diesel Production
Operating Requirements for Hydro treating Diesel and Gas Oil Streams:
Units are per barrel feed
Stream
Diesel
Hvy. Gas Oil
Electric
(KWh)
3.
6.
Fuel
(Mmbtu)
0.15
0.20
Steam
(Lb)
8.
10.
Hydrogen
(Scf)
300.
600.
Investment Requirements for Hydro treating Diesel and Gas Oil Streams:
Basis: 1999 U.S. Gulf Coast, ISBL million of dollars, 30,000 bpsd
Diesel Feed 35.0
Heavy Gas Oil Feed 50.0
Source: Gary and Handwerk, Petroleum Refining Process Economics, Fourth Edition,
2001, pg. 182-183.
A. 11 Ultra Low-Sulfur Diesel Processes
It is highly unlikely that ultraslow diesel production would be blended with residual fuel
oil because of the high cost of production and the fact that its substitution for conventional diesel
fuel does not exert sufficient leverage on the residual fuel blend sulfur content. It is more likely
A-7
-------
that it would be blended with the higher sulfur middle distillate components to produce the
marine diesel fuel grades. Representative ultraslow diesel processes are described below:
Operating and Investment Requirements for the Phillips S Zorb Process
Feed rate, BPD 20,000 40,000
Feed sulfur wt ppm 2600 500
Product Sulfur wt ppm 6 6
Power kWh 2511 3698
Steam nil nil
Nitrogen, million scfd 807 332
Cooling water gpm 1835 1870
Fuel gas, million btu/h 46.5 109.6
Total hydrogen, million scfd 1.24 1.44
Sorbent makeup, Ib per month 9970 19085
Erected Equipment, million dollars 20.85 30.60
Basis 2nd Quarter 2002 U.S. Gulf Coast
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 11.56.
Operating and Investment Requirements for the UOP/Eni Oxidative Desulphurization Process
30% LCO, 70% straight run diesel
30,000 bpsd feed @400ppm sulfur and 10 ppm diesel product sulfur
U.S. Gulf Coast, 2nd quarter 2003
Capital cost, MM$ 16.0
Hydrogen cost $MM/yearl3.4
Utilities cost $, MM$/year 1.0
Catalyst cost $MM/year 1.3
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Total cost $, MM$/year 15.7
Source: NPRA Annual Meeting, March 21-23, 2004, Paper AM-04-48.
A. 12 Syntroleum Gas to Liquids (diesel)
Capital Cost of Plant $25,000 per bpd capacity
Operating Cost $5.00 per barrel excluding cost of natural gas
Product nil sulfur and aromatics, 74 cetane number
Basis 2001 U.S. Gulf Coast
Source: Robert A. Meyers Handbook of Petroleum Refining Processes, Third Edition,
2003, pg. 15.23.
A. 13 Process Unit Revamping For Ultra Low-Sulfur Diesel Production
Claims have been made that revamping for ultra low-sulfur diesel production with
countercurrent reactors can save up to 50% in Capex and 20% in OPEX based on recent pilot
plant tests (NPRA Annual Meeting, March 21-23, 2005 NPRA Papers AM-04-22). Also, that
integration of isotherming into an existing conventional unit is 60% of the total cost of a
conventional revamp (NPRA Annual Meeting, March 21-23, 2005 NPRA Papers AM-04-40).
The estimated ISBL Investment Cost for (U.S. Gulf Coast, 1st Quarter 2005) for
upgrading a 20,000 bpsd unit with light cycle oil (LCO) feed to produce 10 ppm ULSD at 45
cetane number is estimated at $36.4 million (NPRA Annual Meeting, March 13-15, 2005 NPRA
Paper AM-05-53).
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