Study No. 175 July 2018 - CERI › assets › files › Study_175_Full_Report.pdf · CANADIAN ENERGY RESEARCH INSTITUTE AN ECONOMIC ASSESSMENT OF THE INTERNATIONAL MARITIME ORGANIZATION

CANADIAN ENERGY RESEARCH INSTITUTE

AN ECONOMIC ASSESSMENT OF THE INTERNATIONAL

MARITIME ORGANIZATION SULPHUR REGULATIONS

ON MARKETS FOR CANADIAN CRUDE OIL

Study No. 175 July 2018

Canadian Energy Research Institute | Relevant • Independent • Objective

An Economic Assessment of the International Maritime Organization i Sulphur Regulations on Markets for Canadian Crude Oil

July 2018

AN ECONOMIC ASSESSMENT OF THE INTERNATIONAL MARITIME ORGANIZATION SULPHUR REGULATIONS ON MARKETS FOR CANADIAN CRUDE OIL

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An Economic Assessment of the International Maritime Organization Sulphur Regulations on Markets for Canadian Crude Oil Authors: Experience Nduagu Evar Umeozor Alpha Sow Dinara Millington With contributions from: Aashish Gaurav Hassan Assaad ISBN 1-927037-60-7 Copyright © Canadian Energy Research Institute, 2018 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute July 2018 Printed in Canada Front cover photo courtesy of Google images Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to all CERI staff that provided insightful comments and essential data inputs required for the completion of this report, as well as those involved in the production, reviewing and editing of the material, including but not limited to Allan Fogwill and Megan Murphy. The authors would also like to thank the following individuals and institutions for providing data and helpful insights for this study. Responsibility for any errors, interpretations, or omissions lies solely with CERI.

• James Storm

• William R. Edwards

• Gerard Monaghan

• Neil Camarta

• Eric P. Murray

• Ian Austin

• Kavan Motazedi

• Dr. Joule Bergerson

• Argus

• Methanex

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE – CANADA’S VOICE ON ENERGY Founded in 1975, the Canadian Energy Research Institute (CERI) is an independent, registered charitable organization specializing in the analysis of energy economics and related environmental policy issues in the energy production, transportation and consumption sectors. Our mission is to provide relevant, independent, and objective economic research of energy and environmental issues to benefit business, government, academia and the public. For more information about CERI, visit www.ceri.ca CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: [email protected] Phone: 403-282-1231

http://www.ceri.ca/

mailto:[email protected]

An Economic Assessment of the International Maritime Organization iii Sulphur Regulations on Markets for Canadian Crude Oil

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Table of Contents LIST OF FIGURES ............................................................................................................. v

LIST OF TABLES ............................................................................................................... vii

ACRONYMS AND ABBREVIATIONS .................................................................................. ix

EXECUTIVE SUMMARY .................................................................................................... xi

CERI Refinery Optimization Modelling .............................................................................. xi Non-Compliance Scenarios ................................................................................................ xii IMO Regulation: Impact on US Refinery Margins ............................................................. xii Scenario Assumption and Compliance Options ................................................................. xiii Impacts on Canadian Heavy Oil ......................................................................................... xv

CHAPTER 1 HISTORY OF THE IMO AND REGULATIONS ................................................. 1

Historic Levels of Compliance ............................................................................................ 2 Impact of Previous IMO/ECA Regulations on Crude Markets ........................................... 3

CHAPTER 2 GLOBAL CRUDE OIL MARKETS ................................................................... 5

Crude Supply and Demand ................................................................................................ 5 Global High Sulphur Residual Oil Market........................................................................... 10 Middle Distillates Oil Markets ............................................................................................ 12

CHAPTER 3 IMPACTS ON THE REFINING SECTOR ......................................................... 15

CERI Refinery Model .......................................................................................................... 15 CERI Refinery Modelling Results ........................................................................................ 25 CERI Refinery Linear Programming Results ....................................................................... 27 Potential Crude Displacement ..................................................................................... 27 Realistic Optimal Crude Blends and Margins ..................................................................... 30

CHAPTER 4 SCENARIO ANALYSIS ................................................................................. 33

Scenarios for Future Refinery Outlook .............................................................................. 33 Residual Fuel Oil Balance and Potential Markets .............................................................. 33 Non-Compliance Scenarios ................................................................................................ 39 Crude Diet Prices and Refinery Products ........................................................................... 41 IMO Regulation: Impact on US Refinery Margins ............................................................. 43

CHAPTER 5 COMPLIANCE OPTIONS ............................................................................. 49

Scenario: Moderate Non-Compliance .............................................................................. 49 Scrubbers ........................................................................................................................... 50 Refinery Additions .............................................................................................................. 52 Slow-Steaming ................................................................................................................... 55 Distillates ............................................................................................................................ 56 Liquefied Natural Gas......................................................................................................... 59 Methanol ............................................................................................................................ 60 Arctic Heavy Oil Transport Ban .......................................................................................... 60

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CHAPTER 6 IMPACTS ON CANADIAN HEAVY OIL ......................................................... 63

Price of Canadian Heavy .................................................................................................... 63 WTI-WCS Price Differential ................................................................................................ 68 Canadian Crude Oil Exports to the US ............................................................................... 72 Canadian Export Pipeline Network .................................................................................... 76 Canadian Rail Network ....................................................................................................... 77

CHAPTER 7 CONCLUSION ............................................................................................ 79

REFERENCES ................................................................................................................... 89

APPENDIX....................................................................................................................... 93

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List of Figures E.1 Refinery Margin Impacts Due to IMO 2020 Regulation .............................................. xii E.2 Resid Bunker Fuel Substitution Effects under the Moderate NC Scenario ................. xiii E.3 WTI and WCS Price Differential ................................................................................... xv 2.1 Global and North American Crude Oil Production ...................................................... 5 2.2 Global Crude Production Volume by Quality in 2016 .................................................. 6 2.3 Quality and Production Volume of Major Crudes in 2016 .......................................... 7 2.4 The America’s Share of Global Crude Oil Types Produced, 2016 ................................ 9 2.5 Canadian Historical and Projected Bitumen Production ............................................. 9 2.6 Residual Fuel Oil Demand ............................................................................................ 10 2.7 Jurisdictional Fuel Oil Consumption ............................................................................ 11 2.8 Bunker Fuel Consumption by Type, 2016 .................................................................... 12 2.9 Global Diesel and Gasoil Consumption ........................................................................ 12 2.10 Global Refined Oil Product Desulphurization Capacities ............................................. 13 3.1 A Typical Hydroskimming Refinery Process ................................................................. 15 3.2 Product Yields for Refineries with Different Complexities .......................................... 16 3.3 Historical Ranges of Crude Oil Flows into US PADDs ................................................... 18 3.4 Historical Percentages of Refined Oil Products ........................................................... 19 3.5 Optimization Model Design and Components ............................................................ 22 3.6 Historical Crude Pricing ................................................................................................ 24 3.7 PADD 1 Calculated versus Actual Refined Product Volumes ....................................... 25 3.8 PADD 2 Calculated versus Actual Refined Product Volumes ....................................... 25 3.9 PADD 3 Calculated versus Actual Refined Product Volumes ....................................... 26 3.10 PADD 4 Calculated versus Actual Refined Product Volumes ....................................... 26 3.11 PADD 5 Calculated versus Actual Refined Product Volumes ....................................... 27 3.12 Potential Crude Displacements.................................................................................... 27 3.13 Composition of Heavy Sour and Heavy Sweet Crudes: Model versus Optimal Blends ...................................................................................... 28 3.14 Composition of Light Sour and Light Sweet Crudes: Model versus Optimal Blends ...................................................................................... 29 3.15 Composition of Medium Sour Crudes: Historical versus Optimal Blends .................. 29 3.16 Composition of Crude Blends Limited by Logistics and Operations ............................ 30 3.17 Average 2017 Refinery Margins of Cokers and FCC .................................................... 31 3.18 Improvement of Refinery Margins .............................................................................. 32 4.1 Global Fuel Oil Production, 2015 ................................................................................. 34 4.2 Residual Fuel Oil Consumption by Country ................................................................. 35 4.3 Regional Residual Fuel Oil Consumption ..................................................................... 36 4.4 Residual Fuel Oil Consumption Sectors ....................................................................... 36 4.5 Market Share of International Bunker Fuel Oil ............................................................ 37 4.6 Change in Demand for Residual Fuel Oil ..................................................................... 38 4.7 Switchable Demand for HSFO ...................................................................................... 39 4.8 Non-compliance Scenario Assumptions ...................................................................... 40

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4.9 Light Sweet Crude Oil Price Outlook With and Without the IMO Regulation ............. 41 4.10 Historical Refined Product Prices ................................................................................. 42 4.11 Price Forecast for Ultra Low Sulphur Diesel ................................................................ 43 4.12 Average 2017 Refinery Margins of Cokers and FCC .................................................... 43 4.13 Medium (FCC) Refinery Margins under Different Compliance Scenarios ................... 44 4.14 Complex (Coker) Refinery Margins under Different Compliance Scenarios ............... 45 5.1 Substitution Options of Resid Bunker Fuel .................................................................. 49 5.2 Estimates of Ships with Scrubbers by Previous Studies .............................................. 51 5.3 Substitution Volumes for Resid Bunker Fuel ............................................................... 52 5.4 Global Crude and Vacuum Distillation Capacities, 2017 ............................................. 54 5.5 Fuel Consumption and Speed Relationship ................................................................. 55 5.6 Prices of MGO, IFO 180 and IFO 380 Bunker Fuels at Houston ................................... 58 5.7 Marine Oils and Blends Prices...................................................................................... 59 6.1 Light-Heavy Differentials ............................................................................................. 63 6.2 Maya-WCS and WTI-WCS Differentials at Cushing ...................................................... 64 6.3 Potential Composition Changes in the Optimal Crude Blend ...................................... 65 6.4 Venezuela and Mexico Crude Outputs are Decreasing ............................................... 66 6.5 Competing International Crudes in the Gulf Coast ...................................................... 67 6.6 Changes to WTI and WCS Prices Due to the IMO Regulation ...................................... 69 6.7 In Situ Capital and Operating Production Costs........................................................... 70 6.8 New SAGD Project Viability by 2020 ............................................................................ 71 6.9 Expanded SAGD Project Viability by 2020 ................................................................... 71 6.10 Canadian Supply and Disposition of Crude Oil ............................................................ 72 6.11 Canadian Crude Exports to the US ............................................................................... 74 7.1 Refinery Margin Impacts Due to the IMO Regulation ................................................. 81 7.2 Resid Bunker Fuel Substitution Options ...................................................................... 82 7.3 Resid Bunker Fuel Substitution Volumes ..................................................................... 83 7.4 Prices of Conventional Marine Oils and the Blend Options ........................................ 84 7.5 WCS-WTI Price Differential Impact Due to the IMO Regulation ................................. 85 7.6 New SAGD Project Viability by 2020 ............................................................................ 86 7.7 Expanded SAGD Project Viability by 2020 ................................................................... 86 A.1 Generic Refinery Input-Output Regression Model ...................................................... 93 A.2 LP Optimization Model ................................................................................................ 95

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List of Tables 1.1 SOx Emissions Controls ................................................................................................ 2 2.1 Crude Classifications by API and Sulphur Content ...................................................... 8 2.2 Available Refining Capacity .......................................................................................... 13 3.1 Crude Oil Classifications ............................................................................................... 18 3.2 Configurations of US Refineries ................................................................................... 20 3.3 Canadian and US Refinery Capacity and Configurations ............................................. 21 3.4 Sulphur Specifications of Refinery Products ................................................................ 23 3.5 Fixed and Variable US Refinery Costs .......................................................................... 24 4.1 High Sulphur Bunker Fuel Price ................................................................................... 40 5.1 Operational Risks of Using Marine Gasoil as a Bunker Fuel ........................................ 57 6.1 Maximum Refinery Losses Under Different Scenarios ................................................ 68 6.2 Canadian Crude Exports Status by PADD Region ......................................................... 75 6.3 Existing Rail Terminals and their Capacity from Western Canada .............................. 78 A.1 US Refinery Capacities and Configurations ................................................................. 95

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An Economic Assessment of the International Maritime Organization ix Sulphur Regulations on Markets for Canadian Crude Oil

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Acronyms and Abbreviations DFO Diesel Fuel Oil

ECA Emission Control Areas

FCC Fluid Catalytic Cracking

FMG Finished Motor Gasoline

GDP Gross Domestic Product

HFO Heavy Fuel Oil, same as HSFO and RFO

HSFO Heavy Sulphur Fuel Oil, same as HFO and RFO

HSO Heavy Sour Crude

HSW Heavy Sweet Crude

IBIA International Bunker Industry Association

IFO Intermediate Fuel Oil

IMO International Maritime Organization

KTJF Kerosene-Type Jet Fuel

LNG Liquefied Natural Gas

LP Linear Programming

LS Low Sulphur

LSFO Low Sulphur Fuel Oil

LSO Light Sour Crude

LSW Light Sweet Crude

MED Medium Crude

MGO Marine Gas Oil

NC Non-Compliance

PADD Petroleum Administration for Defence District

RFO Residual Fuel Oil, same as HSFO and HFO

SAGD Steam-Assisted Gravity Drainage

SOR Steam-to-Oil Ratio

TAN Total Acid Number

ULSD Ultra-Low Sulphur Diesel

WCS Western Canadian Select

WTI West Texas Intermediate

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An Economic Assessment of the International Maritime Organization xi Sulphur Regulations on Markets for Canadian Crude Oil

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Executive Summary A recent regulation by the International Maritime Organization (IMO) sets a global limit for sulphur in fuel oil used to power ships at 0.5% (by mass) from the current 3.5% starting in January 2020. This more stringent regulation restricting emissions from ships plying international waters could significantly change the crude oil landscape at regional and global levels. For example, the 2020 IMO sulphur regulation would require the removal of up to 12,000-16,000 tonnes per day of sulphur contained in the 3-4 million barrels/day of high sulphur bunker fuel used for marine transport. This change will propagate through the value chain; from the marine industry that will seek replacement fuels to refiners that produce bunker fuel, and to upstream oil producers who produce crudes that generate high sulphur residues used in bunkering.

Canada is one of the major producers of high sulphur heavy crude oil with production growing steadily since 2008. Bitumen production is expected to reach 3 million bbl/day by the end of 2018 and continue increasing. Canadian heavy sour crude is refined primarily in Canada and the United States (US) where there are sufficient capacities of complex refineries to handle this type of crude. Canadian bitumen contributes very little to bunkering since it is consumed by the complex refining in Canada and the US. Instead, Canadian crude will have to compete for US refining space on netback refining value with other crudes that currently contribute to High Sulphur Fuel Oil (HSFO) supply. The Canadian Energy Research Institute (CERI), therefore, used a refinery modelling and optimization approach to investigate the impact of the IMO regulation on Canadian crude production and price.

CERI Refinery Optimization Modelling CERI developed an optimization model to account for US refinery configurations and their operating costs, capital investments, crude oil blending, and the associated refinery acquisition costs of crude blends, product slates and their market values, thus requiring the development of revenue forecasts from the sales of refinery products. The results show that the optimization of US refineries at a Petroleum Administration Defense District level (PADD-level) can lead to a potential displacement of some volumes of certain crudes that have historically been processed in some PADDs. Also, our results indicate that heavy sour crudes are likely to displace mostly light sweet and medium crudes in a logistically and operationally unconstrained environment. In addition, increases in heavy sweet crudes are expected in some PADDs.

With the imposition of more realistic constraints, the magnitude of these displacements is reduced - mirroring recent crude receipts with optimal refinery margins. These results are driven

by cheaper heavy crudes, yield levels of high-value product slates, and profitability of the process. The refinery margin improvements obtained from the realistic optimal case range from a 75% to 300% increase in profit, with the most notable improvement coming from PADD 1 (the US Eastern region) but no improvement recorded for PADD 4.

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Non-Compliance Scenarios Non-compliance regarding this new regulation is a serious concern for the IMO. CERI developed scenario and price outlooks for various crude diets and refinery products for 2020, 2025 and 2030. This facilitated the analysis of future prices for middle distillates, represented by ultra-low sulphur diesel. Three non-compliance scenarios are assessed:

• Low non-compliance (Low NC) – assumes 80% compliance (20% non-compliance) by 2020 given up to 80% of global trade occurs between regions where ECA is in force and other regions of the world.

• Moderate non-compliance (Moderate NC) – assumes 75% compliance (25% non-compliance) by 2020.

• High non-compliance (High NC) – assumes 70% compliance (30% non-compliance) by 2020.

These scenarios consider the fact that non-compliance will differ across geographical regions, for example in regions known for strict enforcement versus those known for less rigid enforcement.

IMO Regulation: Impact on US Refinery Margins Changes in resid and distillate prices will reduce refinery margins to a notable degree, particularly those of simple and medium refineries (Figure E.1).

Figure E.1: Refinery Margin Impacts Due to IMO 2020 Regulation

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Our analysis indicates a general trend of decreasing refinery netbacks in the years after 2020 in

all the non-compliance scenarios for medium refineries; complex refineries enjoy increased margins in the Low NC scenario. Under the Low NC and Moderate NC scenarios, which are considered the plausible scenarios given the low probability of the High NC, the IMO regulation impacts will bring about a refinery margin loss of $16/bbl to $20/bbl between 2020 and post-2025 relative to average 2017 margins.

Although some PADDs will have low margin reductions and even an increase in margins for some by 2020, we expect the highest margin reduction refineries, in this case, the medium refineries in the US, to set the prices for heavy sour crudes and determine the light-heavy crude price differentials.

A general trend of declining margins for some years after 2020 results from an expected drop in

prices of middle distillates as the market rebalances and the distillate prices drop to normal levels. Unfortunately, the price of resid will not recover at a rate that can stabilize the refinery margins, and thus, cannot cushion the effect of the rebalancing middle distillates prices. This is because the effect of price movements of the middle distillates outweighs the margin-boosting effect from slowly increasing resid prices.

Scenario Assumption and Compliance Options The Moderate NC scenario is chosen to assess how different options can substitute resid bunker fuel volumes by 2020, 2025 and 2030 (see Figure E.2).

Figure E.2: Resid Bunker Fuel Substitution Effects under the Moderate NC Scenario

5.0% 5.0%1.9%

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Once the rules take effect, almost 60% of the shipping industry fuel currently using high sulphur

resid will need to switch to either marine gasoil or a blend of high sulphur and ultra-low sulphur middle distillate marine fuels. Under the Moderate NC scenario, we estimate that scrubbers will be used for only about 3% of the HSFO volume by 2020. Adoption of scrubbers is likely to increase moderately and peak by 2025 where about 5% of the resid bunker demand is consumed in tandem with scrubbers. CERI projects that LNG will replace about 1.9% to 7% of resid bunker fuel volume during the study period.

Conversion additions, mainly in China and India refineries, between end-2017 and the beginning of 2020, amount to 1.7 million bbl/day, nearly split between coking, hydrocracking and catalytic cracking (S&P Global Platts, 2018). The location of the refineries makes it improbable that these conversion capacities will contribute significantly to low sulphur marine bunker fuels.

About 240,000 bbl/day resid hydrodesulphurization capacity can be assumed to contribute to low sulphur fuel oil by 2020. This number will increase in the future as the increase in the light-heavy product differentials is expected to motivate investments in desulphurization. Desulphurization will capture up to 14% planned additional refinery resid hydrodesulphurization capacity by 2025.

Increasing refinery utilization capacities will be part of the solution to the bunker fuel availability problem but will equally add to the problem of resid glut. This is because more resid will be produced as refiner’s process more crude. World refineries can produce about 1.3 million bbl/day of distillates together with 1.2 million bbl/day heavy fuel oil and related products. A 10% increase in the global refinery capacities will result in 2.6 million bbl/day of distillates together with 2.3 million bbl/day heavy fuel oil and other products by 2030. In each case, large amounts of distillates that can bridge the gap of cleaner bunker fuel demand can be produced, thereby

keeping high sulphur fuel oil prices low. Additionally, the world is reaching peak gasoline demand and would not need the additional naphtha generated by the added crude processing.

The reason refiners are not making costly refining modifications like adding new coking capacities at faster rates may be because the price volatility that will be created from the IMO rule implementation is not expected to last long enough to make such investments viable. Markets are expected to rebalance in a couple of years, and this discourages significant capital investments in complex refining units, which have payback periods of at least two decades. Also, there seems to be enough room to process more crudes to meet the expected increases in demand for distillates for marine fuel use, but this does not address the problem of the residual oil glut arising from the introduction of the IMO regulation.

Slow-steaming of ships is another approach the shipping industry may likely employ to save fuel costs by consuming less fuel. Given that shipping fuel consumption has a velocity-squared relationship, a slight reduction in ship speeds by a few knots (equivalent to 1.85 km/hour) will lead to a significant reduction in fuel consumption and costs. Our analysis shows that reducing ship’s speed to achieve a 25-50% reduction in fuel consumption is possible if the compliant fuel prices skyrocket.

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Impacts on Canadian Heavy Oil The price discount on Western Canada Select (WCS) crude with respect to the West Texas Intermediate (WTI) price point will expand significantly due to the IMO regulation. Figure E.3 illustrates how the refinery margin loss affects the WCS (heavy sour) pricing relative to WTI (light sweet). The dotted lines represent the WCS pricing that is historically discounted at $13/bbl plus the discounts resulting from the IMO regulation for the three scenarios considering a medium refinery in the US.

Figure E.3: WTI and WCS Price Differential (2017 US$)

Source: CERI

Under the plausible scenarios, a refinery margin loss of $16/bbl to $20/bbl between 2020 and post-2025 is expected to be directly transferred to a light-heavy differential. The cumulative differential which includes the historical WTI-WCS discount of $13/bbl sums up to $31/bbl-$33/bbl of WTI-WCS differential within the study period.

Our analysis shows that new SAGD projects with SORs of less than 3 m3/m3 are likely to break even when the IMO regulation is introduced whereas those with SORs greater than 3 m3/m3 will operate at a loss. A significant volume of SAGD-derived bitumen production could be affected. Based on SAGD production data, about 574,000 bbl/day of bitumen produced in Alberta has an SOR of more than 3 m3/m3 (CanOIl, 2017).

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An Economic Assessment of the International Maritime Organization 1 Sulphur Regulations on Markets for Canadian Crude Oil

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Chapter 1: History of the IMO and Regulations The International Maritime Organization (IMO), formerly known as the Inter-Governmental Maritime Consultative Organization, or IMCO, was established in 1948 in recognition of the common goals for shipping nations to improve safety at sea. The first success of this organization was the implementation of the International Convention for the Safety of Life at Sea (SOLAS) in 1960. This is still considered the most important of all treaties dealing with maritime safety. After adopting SOLAS, the IMO proceeded to deal with matters such as the facilitation of international maritime traffic, load lines and the carriage of dangerous goods.

Although safety was and remains the IMO's most important responsibility, a new problem began to emerge – pollution. The growth in the amount of oil being transported by sea and in the size of oil tankers was of concern and the Torrey Canyon disaster of 1967, in which 120,000 tonnes of oil was spilled, demonstrated the scale of the problem.

In the late 1970s, the IMO introduced a series of measures designed to prevent tanker accidents and to minimize their consequences. It also tackled the environmental threat caused by routine operations such as the cleaning of oil cargo tanks and the disposal of engine room wastes. In tonnage terms, engine room wastes are a bigger hazard than accidental pollution.

The most important of all these measures was the International Convention for the Prevention of Pollution from Ships, 1973, as modified by the Protocol of 1978 (MARPOL). It covers not only

accidental and operational oil pollution but also pollution by chemicals, goods in packaged form, sewage, garbage and air pollution.

MARPOL has been updated by amendments throughout the years to protect human health in coastal cities from sulphur pollution, a known health hazard, and for protection of international waters and the broader global environment. In 1997, a Protocol was adopted to amend the Convention, and a new Annex VI was added which entered into force in May 2005. Annex VI – Prevention of Air Pollution from Ships – set limits on sulphur oxide (SOx) and nitrogen oxide (NOx) emissions from ship exhausts, prohibited deliberate emissions of ozone-depleting substances, such as halons and chlorofluorocarbons (CFC), and designated emission control areas (ECAs) with more stringent standards for SOx, NOx and particulate matter.

Further changes to MARPOL Annex VI addressed a progressive reduction globally in emissions of

SOx, NOx and particulate matter. The MARPOL Annex VI regulations that came into force in 2005 were revised in 2008; the revision came into force in 2010. For all oceans worldwide, the sulphur content allowed was capped at 4.5%, and after 2012 this limit was reduced to 3.5%. Also, ECAs established a further reduced sulphur limit. One ECA is along the North American coast, and another comprises the Baltic Sea and the North Sea up to the Shetland Islands and the western

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entrance of the English Channel. Within ECAs the sulphur limit was initially set to 1.5%,

subsequently reduced to 1.0% in 2010 and now at its current limit of 0.1% since January 2015.

The ECAs established are:

• Baltic Sea area – as defined in Annex I of MARPOL (SOx only);

• North Sea area – as defined in Annex V of MARPOL (SOx only);

• North American area (entered into effect August 1, 2012) – as defined in Appendix VII of Annex VI of MARPOL (SOx, NOx and PM); and

• The United States Caribbean Sea area (entered into effect January 1, 2014) – as defined in Appendix VII of Annex VI of MARPOL (SOx, NOx and PM).

In 2016, the IMO introduced a new global limit on the sulphur content in marine fuels powering

ships with an effective date for the reduction of January 1, 2020. Under the new global cap, ships will have to use marine fuels with a sulphur content of no more than 0.5%. The Emission Control Areas will remain at the 2015 standard of 0.1% sulphur content in North America, Europe and Baltics (Table 1.1).

Table 1.1: SOx Emissions Controls

Outside an ECA Established to Limit SOx and Particulate Matter Emissions

Inside an ECA Established to Limit SOx and Particulate Matter Emissions

4.5% m/m prior to January 1, 2012 1.5% m/m prior to July 1, 2010

3.5% m/m on and after January 1, 2012 1.0% m/m on and after July 1, 2010

0.5% m/m on and after January 1, 2020 0.1% m/m on and after January 1, 2015

Source: IMO

Historic Levels of Compliance With the regulations in place, the question remains on how to verify the compliance of the ships efficiently. To date, compliance is checked by inspection authorities who enter ships at berth, review fuel log books and fuel quality certificates and, if suspicion is raised, take a fuel sample to be analyzed at certified laboratories. With the results of the analysis, it is possible to verify compliance and if needed, take legal action. However, these controls can check just a minor number of ships. It is also not possible to evaluate the performance and compliance of scrubber technology by predicting the amount of sulphur removed in bunker oil samples. This is a challenge if this method becomes a more popular and common method to meet compliance in the future.

In the ECAs, compliance by ships is high. For example, researchers at the Chalmers University of Technology in Sweden have shown that between 87% and 98% of ships comply with the tougher regulations for sulphur emissions that were introduced in northern Europe in 2015. The lowest levels of compliance were observed in the western part of the English Channel and the middle of the Baltic Sea.


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While the 1% limit in the ECAs could still be met with sulphur-reduced Heavy Fuel Oil (HFO), the

new regulation forces ships to either use more expensive alternatives such as marine gas oil (MGO), ultra-low sulphur HFO, or consider reconstruction to enable the use of alternative fuel such as liquefied natural gas (LNG) or methanol. As an alternative technology, the operation of exhaust gas cleaning systems (scrubbers) is also permitted, if it provides the same level of protection against sulphur dioxide emissions as the use of low sulphur fuel. These options have been deployed to some ships, and the first studies have documented their effectiveness and economic efficiency (Reynolds, 2011; Jiang et al., 2014), but they are still under development and are not widespread. For the vast majority of ships, the only option to meet the regulations is to use desulphurized fuel.

The different compliance methods include:

• Desulphurize refinery fuels and use lower sulphur content fuel.

• Switch entirely or partially to middle distillates for bunker fuel.

• Reduce SOx emissions via on-board scrubbers (also helps reduce particulate matter, PM).

• Undertake custom blending of fuels on board and use segregated bunkers tanks.

• Establish emissions trading, which could allow trading of marine and shore-based credits.

• Switch to alternative fuel sources (e.g., LNG, methanol).

Currently, enforcement rules and penalties are up to the individual member states and flag states. Although there are no IMO global enforcing mechanisms, there are other approaches countries might use to manage enforcement including restricting non-compliance ships and firms from business dealings in the host or flag country. Those firms also face a reputational risk if non-compliance is alleged or confirmed.

Impact of Previous IMO/ECA Regulations on Crude Markets Much tougher rules governing emissions from ships plying international waters could significantly change the crude oil market landscape at regional and global levels. For example, the 2020 IMO sulphur regulation could require the removal of up to 20,000 tons per day of sulphur contained in the 3-4 million barrels/day of high sulphur bunker fuel used for marine transport by 2020. These sudden changes will propagate all along the value chain, from the marine industry that will seek a replacement fuel, to refiners that produce bunker fuel, and to upstream oil producers who produce crudes that generate high sulphur residues used in bunkers.

Will global refinery capacity be deployed to serving the marine market in 2020? Will refiners produce suitable fuels, and what will be the composition of these fuels? How does one ensure

compliance, and how will the IMO tackle transitional issues? To what extent will the uptake of scrubbers and alternatives impact overall demand?

In the previous regulations, when the ECA’s sulphur content dropped from 1% to 0.1%, the market saw an introduction of a range of new fuel formations that cost less than expensive marine gas oil, suggesting that a future with a global cap of 0.5% would not solely rely on an all-in switch to distillates. There is likely going to be new types of blends emerging to meet the 0.5% limit. In fact,


July 2018

the International Bunker Industry Association (IBIA) expects a more widespread use of vacuum

gas oil and use of very low sulphur HFO where available with a bit of low sulphur blendstock added. Some refineries are exploring opportunities to produce specific 0.5% marine fuels from existing product streams, some refineries may desulphurize HFO, and some independent innovators are looking to get into the marine fuel market by stripping sulphur out of HFO.

As with all predictions, there are uncertainties.


July 2018

Chapter 2: Global Crude Oil Markets Crude Supply and Demand Crude oil production and consumption have grown historically, and all indications are that despite carbon management pledges by governments, production and consumption will continue to grow (Figure 2.1). This growth responds to global population and gross domestic product (GDP). Global GDP growth averaged 3.8% from 2001 to 2017 (IMF, 2018) whereas global population growth averaged 1.2% within the same period (Worldometers, 2018).

Figure 2.1: Global and North American Crude Oil Production

Source: EIA, CERI

According to the EIA’s International Energy Outlook 2017, global petroleum liquids consumption is expected to have an average annual growth of 0.7% between 2015 and 2050 while global annual GDP growth will average 2.3% during the period. Petroleum and other liquids production are projected to have average annual production growth of 1.2% and 0.3% in Canada and the United States, respectively (EIA, 2017).

Reduction of the sulphur content of bunker fuels from 3.5% to 0.5% in 2020 will ultimately decrease the demand for high sulphur fuel oil flows, and as a result, impact crude oil flows and prices globally. In 2016, sour and medium sour crudes, with sulphur content above 0.5 wt.%, made up 64.5% of the global crude supply which is a significant fraction (Figure 2.2).

0

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ion

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)

World - ref World - High oil price United States

World - Low oil price Canada


July 2018

Figure 2.2: Global Crude Production Volume by Quality in 2016

Source: ENI, CERI.

Global crude oil produced has seen an increase in its sulphur content, thereby becoming increasingly sour. The fraction of medium sour and sour crude produced increased by 2.4% from

62.1% in 2000 to 64.5% in 2016. This trend seems to continue given depleting global sweet crude oil resource dispositions and technological advancements that render unconventional resources technologically and economically viable to extract. An exception to this trend is the fact that technological innovation has also enabled significant increases in production of light sweet crude from unconventional shale oil resources in the United States. US light oil production has increased significantly whereas the Mexican Maya and Venezuelan heavy crudes supply have waned in recent years and may continue to decline in future.

Figure 2.3 shows global crude oils, their sulphur contents and API gravities. The sulphur content of residual oil reflects the quality of the crude oil that produces it. Crude quality is influenced chiefly by its sulphur content and the density measured as API gravity. This means that the higher the sulphur content of the crude, the higher the sulphur content of the residual oil, and vice versa.

On the other hand, the higher the API gravity, the lower the yield of residual oil produced and vice versa.

-

10,000

20,000

30,000

40,000

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60,000

70,000

80,000

90,000

2000 2005 2010 2012 2013 2014 2015 2016

Cru

de o

il pr

oduc

tion

('000

bbl

/d)

Ultra Light Light and Sweet Light & Medium Sour Light & Sour

Medium & Sweet Medium & Medium Sour Medium & Sour Heavy & Sweet

Heavy & Medium Sour Heavy Sour Unassigned production


July 2018

Figure 2.3: Quality and Production Volume of Major Crudes in 2016

Source: ENI

Unless significant shale oil fracking is sanctioned and deployed in other regions with shale oil resources, it is still reasonable to expect that the long-term outlook of crude quality will at least

remain unchanged or become increasingly sour. Crude with a sulphur content greater than 0.5 wt.% are regarded as sour (see Table 2.1), and these types of crudes generate a significant proportion of high sulphur fuel oil used as bunker fuel.


July 2018

Table 2.1: Crude Classifications by API and Sulphur Content

Crude Classification

API S Wt.% Examples

Light sweet >=35 <0.5 WTI, LLS, Brent

Light sour >=35 >0.5 Arab Light (Saudi Arabia), West Texas Sour, Canadian Light Sour, Alaska North Slope, Forties Blend, Hibernia Blend

Medium sour 27-35 >0.5 Mars, WTS, Arab medium, Basra light, etc. Heavy sweet <=27 <0.5 Indonesia Duri

Heavy sour <=27 >0.5 Maya, Cold Lake, WCS, Arab Heavy

Source: CERI; classifications are based on EIA (2018) crude imports.

Though marine bunker fuels account for about 4% of global demand, they are an important outlet and revenue for the refining industry (IEA, 2018a). The marine industry absorbs unwanted residual fuel oil – a refinery product which has declining demand due to factors including emissions control regulations that require cleaner-burning fuels onshore and the decrease in residual fuel oil demand for non-bunker uses.

Figure 2.4 shows that heavy crude oil production from the Americas (Argentina, Brazil, Canada, Colombia, Ecuador, Mexico, United States and Venezuela) is a large portion of the global medium sour and sour crudes produced in 2016. A staggering portion (about 82%) of global heavy crude supply came from the Americas in 2016. Twenty-nine percent of all crudes produced in this region is medium sour and sour crude types (not shown in Figure 2.4). The Americas produced about 26% of the global crude volume in 2016. The significance of these statistics is that the IMO sulphur

regulation is likely to have the greatest impact on producers in the Americas because countries in this region are the producers of heavy and sour crudes.


July 2018

Figure 2.4: The America’s Share of Global Crude Oil Types Produced, 2016

Source: Data from ENI, Calculations by CERI

Crude oil production growth in the US will be dominated by light sweet shale oil whereas in Canada crude oil production growth will be driven by oil sands-derived heavy sour crude. Canada’s resource disposition is predominantly high sulphur heavy crudes. Canada (specifically, Alberta) is one of the major producers of high sulphur heavy crude oil with its production growing steadily since 2008. In CERI’s reference case, shown in Figure 2.5, bitumen production is expected

to reach 3 million bbl/day by the end of 2018 and continue afterwards (Millington, 2018).

Figure 2.5: Canadian Historical and Projected Bitumen Production

Source: CERI

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

Total

Ultra Light

Light and Sweet

Light & Medium Sour

Light & Sour

Medium & Sweet

Medium & Medium Sour

Medium & Sour

Heavy & Sweet

Heavy & Medium Sour

Heavy Sour

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men

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ion

('000

bbl

/day

)

Mined Bitumen Extraction Total In-Situ Bitumen Extraction


July 2018

Canadian heavy sour crude is refined primarily in Canada and the United States. These countries

have sufficient capacities of complex refineries that can handle this type of crude. Refinery operators want to minimize the residual oil yield unless they are built to process residual oils into lighter ends, through medium and deep conversions. Therefore, heavy sour crudes are sold at a discount to the light sweet crudes. The price discount of Canadian heavy crude relative to light sweet crudes is analyzed in Chapter 4.

Global High Sulphur Residual Oil Market The global market for high sulphur resid has been under pressure for some time with the increased availability of LNG primarily for power generation. According to the EIA, the global residual oil demand stands at about 7.8 million bbl/day. Of this amount, about 3.2 million bbl/day is used as bunker fuel (see Figure 2.6).

Figure 2.6: Residual Fuel Oil Demand

Source: Shell (2017), S&P Global Platts (2018)

The decline in the demand and supply of residual fuel oil is caused by a perpetual decrease in the demand of the non-bunker residual market. As can be seen in Figure 2.6, residual fuel oil demand for purposes other than bunker fuels has declined since the 1990s. This trend is expected to continue given the increasing use of natural gas and LNG which are cleaner fuel options and are becoming more economical alternatives to residual fuel oil use for power generation and industrial use. It remains to be seen whether a decrease in the price of high sulphur fuel oil will lead to a significant increase in the use of this fuel for power generation and industrial

applications. The global residual oil demand and supply have decreased historically, and this trend is expected to continue in the future (Figures 2.6 and 2.7).


July 2018

Figure 2.7: Jurisdictional Fuel Oil Consumption

Source: BP (2017), CERI.

The global residual fuel demand has decreased since the 1980s from close to 13 million barrels/day to about 8 million barrels/day in 2014 (Mayes, 2015). Residual fuel production has followed the same trend, declining in response to the falling trend of demand.

The period 2005 to 2010 marks a period of remarkably high bunker demand growth which also matched periods of high growth in GDP, global trade and fleet capacity. During this period, bunker demand grew by 3.1% annually on average driven by an expansion of global trade of 4% and overall GDP growth of 3.4% (S&P Global Platts, 2018). The bunker demand growth dropped to an average growth of 1.3% annually between 2010 and 2015 but is projected by S&P Global to stay above 2.5% annually between 2020 and 2025. The projected growth is expected to be driven by an optimistic future of GDP and waterborne growth of 3%.

The projected bunker demand growth will not translate to residual oil demand growth for bunker fuel. Rather, a dramatic decrease in the residual oil demand for bunker fuel is expected by 2020 due primarily to the MARPOL 2020 Regulation. In 2016, high sulphur residual oil made up about 45.8% of the total fuel oil demand out of 7.2 million bbl/day fuel oil demand and 3.5% of total oil

demand (Fitzgibbon, Martin, & Kloskowska, 2017). Regional bunker fuel demand by type (Figure 2.8) shows that the Asia Pacific and Europe have the highest levels of fuel oil demand.

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l Oil

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n (m

illio

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)

Asia Middle East Europe & Eurasia S. & Cent. America Africa U.S. Canada


July 2018

Figure 2.8: Bunker Fuel Consumption by Type, 2016

Source: McKinsey (Fitzgibbon et al., 2017), CERI.

Middle Distillates Oil Markets Historically, global demand for diesel and other distillates has increased and is projected to grow further. Global consumption of diesel and gasoil is dominated by Asia and Europe, with more than half of the global demand coming from these regions (Figure 2.9).

Figure 2.9: Global Diesel and Gasoil Consumption

Source: BP (2017), CERI.

Global capacity to produce desulphurized gasoil, resid and middle distillates is highest in three regions: North America, Asia Pacific and Europe (Figure 2.10 and Table 2.2). Fortunately, the major demand centres for diesel and gasoil such as Asia, Europe and North America have high desulphurization capacities. However, even if the capacities are ramped up to 90%, they will not

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July 2018

sufficiently meet the demand for diesel and gasoil. On the contrary, desulphurization capacities

for vacuum gasoil and fuel oil far exceed the demand for fuel oil in some regions, particularly in North America and Europe.

Table 2.2: Available Refining Capacity (million bbl/day 2017)

US and Canada

Latin America

Africa Europe Russia

and Caspian

Middle East

China Other Asia-

Pacific World

Distillation

Crude oil (atmospheric)

20.3 8.0 4.1 17.1 7.1 8.9 13.9 18.0 97.4

Vacuum 9.3 3.6 1.0 6.7 2.9 2.5 5.5 5.7 37.2

Upgrading

Coking 2.9 0.8 0.1 0.7 0.4 0.3 1.9 0.9 8.0

Visbreaking 0.2 0.4 0.2 1.6 0.5 0.6 0.2 0.5 4.1

Solvent Deasphalting

0.4 0.1 0.0 0.1 0.0 0.1 0.1 0.1 1.0

Catalytic cracking 6.0 1.6 0.3 2.4 0.7 0.9 3.1 2.8 17.7

Hydrocracking 2.3 0.2 0.2 2.0 0.4 0.8 1.6 1.5 9.0

Total Upgrading 11.8 3.1 0.8 6.8 2.0 2.7 6.9 5.8 39.8

Source: OPEC WOO 2017

Figure 2.10: Global Refined Oil Product Desulphurization Capacities

Source: OPEC (2017)

0 5 10 15 20 25 30

US & Canada

Latin America

Africa

Europe

Russia & Caspian

Middle East

China

Other Asia-Pacific

World

Capacity (million bbl/day)

Vacuum gasoil/Residual Middle distillates


July 2018


July 2018

Chapter 3: Impacts on the Refining Sector In this chapter, the impacts of the IMO regulation on the refining sector are assessed.

Refineries are a complex system of various operations and vary from simple (hydroskimming) to medium and deep conversion configurations. Hydroskimming refineries are simple in configuration with crude distillation being the major process operation. This type of refinery lacks upgrading facilities, and thus, cannot further process residuals into high-value products. However, medium and deep conversion refineries, which are complex refineries, can process heavier fractions into lighter distillates.

An overall process schematic for a typical refinery operation resulting in distillates and the

residual oil is shown in Figure 3.1. Figure 3.2 shows the percentage yield of refineries with various complexities.

Figure 3.1: A Typical Hydroskimming Refinery Process

Source: Kaiser (2017)


July 2018

Figure 3.2: Product Yields for Refineries with Different Complexities

Source: CERI

An important challenge for refiners will be the disposal of excess high-sulphur residue, which will no longer find demand as a bunker fuel by 2020. The composition of residuum are as follows: carbon (83%–87%), hydrogen (10%–14%), nitrogen (0.1%–2%), oxygen (0.1%–1.5%), sulphur (0.5%–6%), and heavy metals (e.g., Ni and V) under 10 parts per million (Elshout, Bailey, Brown, & Nick, 2018).

The dramatic decrease in demand is expected to lower the price for high-sulphur resid fuel. Most analysts agree that this surplus would have to clear into lower price tiers, such as oil-fired power

generation, at prices which could be as low as thermal parity with coal (Grati, 2017). The situation creates both opportunities and challenges for refiners.

Delayed coking, visbreaking, fluid coking, solvent deasphalting and residual fluid catalytic cracking (FCC) are some of the widely applied processes to convert resid into lighter products which are more valuable (Elshout et al., 2018). Refiners with these carbon rejection technologies have significant advantages over others.

Refiners that could benefit from the IMO regulations (Ruiz-Cabrero, Govindahari, & Moreno, 2017) would have the following characteristics:

• Complex refineries with coking, hydrocracking and residue desulphurization that maximize LSFO and distillate. For example, most refineries in the US (particularly in PADDs 2 and 3), Asia and the Middle East.

• Refiners that convert residual oil to distillates will benefit because of investments in delayed coking which produces both gasoline and distillates.

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July 2018

• Refiners that use intermediate residue streams, such as hydrotreated vacuum gas oil (VGO) will benefit by realizing a higher price at a lower cost than refiners that use distillates (Ruiz-Cabrero et al., 2017).

• Coker refineries, especially in the US Gulf Coast (PADD 3), PADD 2 and Asia.

• Refineries with access to crudes with a very low sulphur content.

Refineries that will suffer from the IMO regulations (Ruiz-Cabrero et al., 2017) include:

• Simple refineries that produce mostly HSFO. Examples are high sulphur hydroskimming and topping refineries in Russia.

• Refineries with low distillate yields such as pure-play gasoline refineries in northwest Europe and the US East Coast.

• Pure-play gasoline refiners with FCC units and reformers will be unfavourably affected during the period of disruption.

• Pure-play gasoline refiners may operate the gasoline-generating FCC units at lower utilization rates in order to reduce gasoline production.

Refinery location is also important. HSFO prices have been lower in regions such as northwest Europe, the US Gulf Coast and Singapore.

CERI Refinery Model CERI uses a generic Input-Output model to capture:

• Inputs and outputs of the US refineries by PADD as illustrated in Figure 3.6.

• The various types of refinery configurations currently operating in the United States.

• Nominal and available refining capacities at individual PADDs.

• Differences in crude blend flows and product slates at each PADD.

• Sulphur handling capacities at refineries within each PADD.

The model predicts product slates using as predictors the crude blends flows at different types of refineries in each US PADD district. More detail about the modelling approach is presented in Appendix A. CERI developed its crude oil refinery model using historical EIA data of crude oil

feedstocks into various refineries within individual PADDs in the United States. Crude oil flows are categorized into five types based on API values and sulphur contents, as shown in Table 3.1.


July 2018

Table 3.1: Crude Oil Classifications

Crude Oil Type Range of API o

Range of Sulphur Content (wt.%)

Representative Crude

API o Sulphur Content (wt.%)

Light Sweet (LSW) >35 <0.5 WTI 37.5 0.4

Light Sour (LSO) >35 >0.5 Arab light 38.7 0.8

Medium (MED) 27-35 >0.5 Iraq Basra 30.2 2.9

Heavy Sweet (HSW) <=27 <0.5 Indonesia Duri 20.3 0.2

Heavy Sour (HSO) <=27 >0.5 WCS 21.0 3.5

Source: CERI; classifications are based on EIA (2018) crude imports.

A monthly time series data from January 2009 to December 2017 is explored to understand the range of quantities of each crude type refined at the PADDs – as shown in Figure 3.3. Analysis of the time series data is important to understand the patterns of crude flows into various US PADDs.

Figure 3.3: Historical Ranges of Crude Oil Flows into US PADDs

Product data (see Figure 3.4) reveals the products predominantly generated from each PADD. The product information allows the model to reflect the important products and enhance its predictive power.

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July 2018

Figure 3.4. Historical Percentages of Refined Oil Products

KEY

• HGLs – Hydrocarbon gas liquids,

• FMG – Finished motor gasoline

• AG – Aviation gasoline

• KTJF – Kerosene-type jet fuel, • Lub – Lubricants

• ARO – Asphalt and road oil

• DFO – Distillate fuel oil

• RFO – Residual fuel oil

• OOP – Other oils for petrochemicals

• SNaphtha – Special naphtha

• SG – Still gas

• MPP – Miscellaneous petroleum products


July 2018

As can be observed from Figures 3.3 and 3.4, greater effort is focused mainly on the major

products which include finished motor gasoline (FMG), distillate fuel oil/diesel (DFO), kerosene-type jet fuel (KTJF), residual fuel oil (RFO) and coke.

Refinery configuration, crude feedstock data from the EIA, refining economics data from the Oil & Gas Journal (Oil & Gas Journal, 2017) and the recommendations from NETL`s Refinery Benchmark Study (Cooney et al., 2016) provided relevant information used to develop the refinery model. The model known as PRELIM (Abella, Motazedi, Guo, & Bergerson, 2016) is used as a source of crude assay data and model validation. Further, refinery products modelling results are compared with EIA published products data at the PADD level.

The US and Canadian refinery information, their configurations and throughputs are presented in Tables 3.2 and 3.3.

Table 3.2: Configurations of US Refineries (bbl/day)

US

Region Capacity (bbl/day)

Hydro- skimming

Medium Conversion Deep Conversion - Coker Deep

Conversion - Resid HC

FCC GO-HC Both FCC GO-HC Both FCC

PADD1 1,213,800 5.8% 66.8% - - 12.8% - 14.7% -

PADD2 4,004,040 10.7% 17.0% - 1.8% 46.9% - 23.6% -

PADD3 9,621,767 5.1% 7.9% 1.3% 2.7% 45.0% 0.4% 35.0% 2.6%

PADD4 683,245 26.6% 17.6% - - 55.7% - - -

PADD5 2,934,785 7.9% 9.6% 5.6% 8.6% 37.4% 12.1% 18.9% -

US 18,457,637 7.6% 14.6% 1.6% 3.1% 42.4% 2.1% 27.3% 1.3%

Source: NETL (Cooney et al., 2016), Oil and Gas Journal (2017), CERI.


July 2018

Table 3.3: Canadian and US Refinery Capacities and Configurations

Thermal Processes Catalytic Cracking

Catalytic Hydrocracking

Catalytic Hydrotreating

US Refining Capacities Crude Vacuum Coking &

visbreaking

Fresh & recycled

feed

Distillate, Gasoil & Resid

Distillate, Gasoil & Resid

desulphurization

PADD 1 1,213,800 526,680 73,350 453,150 40,770 409,140

PADD 2 4,004,040 1,723,470 529,020 1,216,620 318,980 1,674,610

PADD 3 9,621,767 4,509,333 1,468,150 2,820,015 1,204,600 3,840,653

PADD 4 683,245 241,005 81,290 203,539 54,720 304,623

PADD 5 2,934,785 1,521,150 548,580 815,580 536,570 1,097,250

Total US Refining Capacities 18,457,637 8,521,638 2,700,390 5,508,904 2,155,640 7,326,276

Canadian Refineries

Parkland Fuel Corp. - Burnaby, BC 55,000 11,800 0 17,800 0 16,500

Consumers - Cooperative Refineries Ltd. - Regina, Sask. 145,000 40,000 10,000 25,000 0 55,000

Husky Oil Operations Ltd. - Lloydminster, Alta. 82,000 15,000 7,500 0 0 0

Husky Oil Operations Ltd. - Prince George, BC 12,000 0 0 3,300 0 0

Imperial Oil - Edmonton, Alta. 189,000 69,000 0 64,500 0 78,500

Imperial Oil - Dartmouth, NS 85,000 41,500 0 31,500 0 16,000

Imperial Oil - Nanticoke, Ont. 113,500 48,000 0 48,500 0 29,500

Imperial Oil - Sarnia, Ont. 119,000 31,500 25,500 30,500 18,500 14,500

Irving Oil Ltd. - St. John, New Brunswick. 300,000 100,000 20,000 95,000 34,000 0

Nova Chemicals (Canada) Ltd. - Corunna, Ont.* 80,000 33,000 0 0 0 0

Shell Canada Ltd. - Scotford, Alta. 92,000 0 0 0 62,000 0

Shell Canada Ltd. - Sarnia, Ont. 71,000 24,400 5,000 19,000 9,000 0

Silver Range Financial Partners LLC -, Newf. 115,000 55,000 20,000 0 0 25,000

Suncor Energy Inc. - Edmonton, Alta. 142,000 47,500 17,100 40,850 0 98,800

Suncor Energy Inc. - Sarnia, Ont. 85,000 26,730 0 16,668 32,078 43,588

Suncor Energy Inc.- Montreal, Que. 137,000 54,000 0 32,000 0 33,000

Valero Energy Corp., Ultramar Ltd. - Levis, Que. 23,5000 48,500 0 67,500 0 70,800

Total Canadian Refining Capacities 2,057,500 645,930 105,100 492,118 155,578 481,188

*Uses Marcellus ethane feedstock

Source: Oil and Gas Journal (2017), CERI


July 2018

A linear programming optimization model is developed using the input-output refinery model,

and the parameters obtained based on the above-noted methodology. In developing a refinery linear programming model, the following economic parameters considered are (see Figure 3.5):

• Refinery configurations and their operating and fixed costs.

• Crude oil blending and the associated refinery acquisition costs of crude blends.

• Revenue generated from the sales of refinery products.

Figure 3.5: Optimization Model Design and Components

The objective of the PADD-level refinery optimization is to determine the makeup of a crude blend that maximizes refinery margins given certain imposed constraints.

The baseline refinery LP optimization model is developed to determine optimal margins for each

PADD for the refineries operated in December 2017. The results are compared with those obtained using PADD-level historical information published from December 2016 to December 2017.

Compliance scenarios for 2020, 2025 and 2030 when the IMO sulphur regulations will be in effect are assessed using the optimized model. Historical minimum and maximum compositions (based on January 2009 to December 2017 monthly values) of crude feedstocks into the US PADDs are considered.

By constraining the composition of each crude type flowing into individual PADDs within limits of the volumes processed in the past (following EIA data, Figure 3.3), CERI maintained realistic crude input flows into each PADD. We also recognize the different refinery configurations that exist in

each PADD and their requirements on handling high sulphur crude or high TAN (Total Acid Number) crude. For example, Canadian bitumen is high sulphur, high TAN which only a few refineries have the required metallurgy to process.

It is important to note the absence of vacuum distillation units in some of the complex coking refineries in PADD 3. By implication, these refineries cannot operate above the 950 oF residue cut point when significant quantities of bitumen are in the feed. The furnace tube velocity is too low


July 2018

to increase the required transfer temperature needed for bitumen without excessive feed

cracking and tube coking in the furnace. To achieve a more reasonable 1,020/1,050 cut point, therefore, requires design modifications to the velocity steam system, furnace tube sizing, transfer piping diameter, column inlet design and overhead vacuum system for many, if not most, vacuum column systems in PADD 3 (James, 2018).

However, our PADD-level model only permits the historical levels of different types of crudes that have been previously processed in each PADD. This means that the refineries in that PADD treated such crude blends in the past and, thus, it can be assumed that the PADD can process the same type of crude blends currently or in the future.

This is a conservative approach that restricts the crude blending options to a known historical observation. We recognize that there might be other crude blend alternatives that exist outside

the historical space being considered. However, the introduction of those alternative blends brings issues of sulphur and TAN limitations that affect the compatibility of the blends with the existing refinery infrastructure. It is for this reason that the model is scoped only to include crude blends that have been processed previously.

Similar to the historical crude blend constraints, the minimum and maximum yields of each product produced between January 2009 and December 2017 (EIA data, Figure 3.4) are identified and used to constrain the yields of products from the optimization model. This approach limits the solution space to only the range of yields that have been reported to correspond to historical crude mix processed in that PADD during the same period.

The refinery capacity factors published by the EIA are imposed on the optimization model to

specify availability. This is necessary to ensure that the volumes of crudes processed in a PADD are aligned with the design and operational capacity factor and throughput.

Sulphur contents of the crude blends and products are very important parameters of the model. The sulphur content of the crude is controlled to ensure that the refinery can handle the feed whereas the sulphur content of the refinery products must meet set requirements (see Table 3.4).

Table 3.4: Sulphur Specifications of Refinery Products

Refinery Products Notation Sulphur Specs. (Wt.%)

Finished motor gasoline FMG 0.003

Kerosene-type jet fuel KTJF 0.3

Distillate fuel oil DFO 0.0015-0.05

Heating fuel oil HFO 0.05

Residual fuel oil (Bunker) RFO 0.4-3.5

Coke Coke 1-6

Source: CERI


July 2018

Also, information on total sulphur input into refineries and sulphur production from the PADDs

are used to constrain the model to the historical range of sulphur loads and to ensure that the material balance of sulphur flows is satisfied.

Table 3.5 shows our assumed fixed and variable costs for refineries. The cost does not include initial capital investments.

Table 3.5: Fixed and Variable US Refinery Costs

Fixed Variable Total

PADD 1 3.54 0.96 4.5

PADD 2 2.87 0.89 3.76

PADD 3 2.55 1.05 3.6

PADD 4 2.87 0.89 3.76

PADD 5 3.34 1.38 4.72

Source: Oil & Gas Journal (2018)

For the baseline refinery and LP optimization model, the average crude and product prices for December 2017 are used (see Figure 3.6 and Table 3.6).

Figure 3.6: Historical Crude Pricing

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CERI Refinery Modelling Results We present in this section the results of the generic PADD-level refinery model which is for PADDs 1-5. When provided with a crude blend assay that typifies what has historically been fed into PADDs 1-5, the model calculates the product slate using built-in multivariate correlations (see Figures 3.7-3.11). The PADD-level refinery model shows a reasonable fidelity level with a coefficient of determination of between 77% and 87%, indicating the ability of the model to predict the response variable.

Figure 3.7: PADD 1 Calculated versus Actual Refined Product Volumes



July 2018




July 2018


CERI Refinery Linear Programming Results

Potential Crude Displacement

For the case modelled here, the results show that optimization of refineries at a PADD-level can lead to a potential displacement of some volumes of certain crudes that have historically been processed (see Figure 3.12).

Figure 3.12: Potential Crude Displacements

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Results (Figure 3.12) show that the heavy sour crudes are likely to displace mostly light sweet and

medium crudes. In addition to this observation, increases in heavy sweet crudes are expected in some PADDS. These results are driven by the cheaper priced crudes, yield levels and high-value products, and profitability of the process.

In the optimized scenarios, PADDs 1, 4 and 5 have their heavy sour crude intakes increased by 17-20% above what they processed between December 2016 and December 2017 (Figure 3.13). The optimal crude composition indicates that heavy sweet components of the crude blends will increase by 6% in PADDs 1, 13% in PADD 2 and 16% in PADD 5.

Figure 3.13: Composition of Heavy Sour and Heavy Sweet Crudes: Model versus Optimal Blends

On the other hand, the light sour composition in the optimal crude blends for all the PADDs except PADD 4 increased when compared to the historical data (Figure 3.14). Light sour crude composition increased by 11% in PADD 1, 3% in PADD 2, 10% in PADD 3 and 27% in PADD 5.


July 2018

Figure 3.14: Composition of Light Sour and Light Sweet Crudes: Model versus Optimal Blends

Results show a decrease of light sweet compositions in almost all the PADDs. The highest and most notable drop in the light sweet composition is in PADD 1 which has a 21% reduction. In the rest of the PADDs, only a decrease of less than 3% is expected. A reason for this general trend is the high cost of light sweet crude, which is represented using the WTI price benchmark. Another reason is that the yields are less than those from heavier crudes.

Similarly, medium crude has its composition in the optimal crude slate decreased in all the PADDs (Figure 3.15) with PADD 5 being the most notable case with a 56% reduction followed by PADD 1

with a 16% reduction.

Figure 3.15: Composition of Medium Sour Crudes: Historical versus Optimal Blends


July 2018

It is important to remember that in the optimal scenario, each PADD is constrained to process

crude blends within the highs and lows of the crude blend compositions treated in the past. These conditions are imposed upon the refinery regression model that captures the operations of the US refineries at PADD-levels. In other words, the results push the boundaries of crude types processed in a PADD-level refinery to an edge. The optimal solution may replicate certain past operating conditions which may not be the exact current operating strategy.

However, availability and accessibility of the different crude types and logistical issues impose additional constraints that warrant further consideration.

Realistic Optimal Crude Blends and Margins If adequate volumes of the crudes are available, the logistics to deliver the crude is in place, and the refineries are equipped to handle the corresponding levels of sulphur and TAN, then

processing cheaper heavy and sour crudes will improve refinery margins because of high conversion levels and product yields. However, that is not the case for all the PADDs. Some PADDs cannot receive and process larger amounts of some crude types. For example, PADD 2 has the highest concentration of coking refineries among the US PADDs and thereby, processes the highest amount of heavy sour crudes. PADD 2 currently processes about 1,767,000 bbl/day of Canadian heavy crude and provides the largest market for Canadian crude exports.

When operational and logistical constraints are applied to the optimal model, CERI determines crude blends which reflect frequently used crude compositions and optimizes the PADD-level refinery margins. Examples of such realistic and optimal refinery crude intakes are shown in Figure 3.16.

Figure 3.16: Composition of Crude Blends Limited by Logistics and Operations

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Results of an assessment of the refinery margins of complex refineries (cokers) and medium

refineries (catalytic hydrocrackers, FCCs) using the historical average blend compositions for each PADD in 2017 are presented in Figure 3.17. It is important to note that the refinery margins for cokers are significantly higher than those of FCCs. Medium and simpler (hydroskimming) barely break even. Current margins for global hydro skimming refiners provide little if any room for these refiners to accept less. An example is the recent bankruptcy of the 335,000 bbl/day Philadelphia Energy Solutions refinery. On the other hand, however, complex refineries had margins that are 3.5-9 times higher than those of FCCs.

Figure 3.17: Average 2017 Refinery Margins of Cokers and FCC

By optimizing refinery margins in our PADD-level analyses, significant improvements in the refinery margins are obtained given the wider solution space – relative to that of an individual refinery. Consequently, the refinery margin improvements obtained from the realistic optimal case range from 75 to 300 percentage points with the most notable improvement coming from PADD 1 (Figure 3.18). However, no visible improvement is recorded in the case of PADD 4.

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Figure 3.18: Improvement of Refinery Margins

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Chapter 4: Scenario Analysis In this chapter, modelling results and interpretation will be presented. Scenarios will explore non-compliance levels, crude and refinery product prices and how these affect refinery margins, and consequently, determine the light-heavy crude price differentials. The baseline for this analysis is 2017, and the analysis covers pre- and post-2020. Detailed modelling and analysis are made up to 2025.

Scenarios for Future Refinery Outlook In this section, we explore how US refining margins will respond to the IMO 2020 regulations, and in particular to an expected drop in the price of high sulphur resid. The IMO regulations, if fully complied with, should displace more than 3.2 million bbl/day of resid currently used as fuel in

the shipping industry. The resultant effect is a potential demand loss of more than 3.2 million

bbl/day of resid by 2020 and afterwards, and consequently, a product price decrease compared to 2019 price levels.

The level at which demand and price drop will be influenced by the level of compliance of the shipping industry to the IMO regulation.

We used our optimized model to assess the refining margins by 2020, 2025 and 2030 at PADD-levels. This calculation is done by considering compliance scenarios and price outlook of various crude diets and refinery products. Future prices of middle distillates, represented using ultra-low sulphur diesel, are also assessed. The price of ultra-low sulphur diesel is expected to increase in response to the dynamics of the bunker fuel markets.

Residual Fuel Oil Balance and Potential Markets Asia produces the highest amount of fuel oil from refineries in the world, accounting for 22% of the 8.6 million of global fuel oil production (Figure 4.1). Asia is also the largest importer of fuel oil with about 2.18 million bbl/day imported in 2015.


July 2018

Figure 4.1: Global Fuel Oil Production, 2015

Source: UN Data (2018), CERI

The second and third largest fuel oil producers are non-EU Europe and the EU, each contributing about 19% and 15% of the total global fuel oil production. Thus, cumulatively, fuel oil production in Europe makes up 34% of the global fuel oil production. While being a large producer of fuel oil does not mean that the region is a large consumer of fuel oil for international bunkers, as is the case with the EU, the third largest fuel oil producer as well as the second largest user of fuel oil for international bunkering. The EU is another region to watch because the 2020 sulphur regulation is likely to impact the region significantly as compliance levels are expected to be high.

Another region that will be hard hit by the IMO 2020 regulation is the Middle East. This region produces 18% of the global fuel oil from refineries but consumes about 16% of the global fuel oil used in international bunkers. The extent of the impact that the IMO sulphur regulation will have on Middle East bunker fuel market will depend on the compliance level in this region. The compliance level will vary in different jurisdictions. The Middle East is the second highest consumer of fuel oil in the world after Asia.

Currently, residual fuel oil finds applications across different industries in virtually every continent. Figure 4.2 shows the relative amounts of the residual fuel oil use by country.

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Figure 4.2: Residual Fuel Oil Consumption by Country (2015 values)

Sources: CERI (from UN Data, 2018)

Although the global residual oil demand has decreased for decades – a trend that is observed

across many global jurisdictions, some regions have seen gradual growth in residual fuel oil consumption (Figure 4.3) over the same period. The Middle East, South America and the Caribbean are regions that continue to experience growth in residual oil consumption whereas Asia’s consumption seems to have stabilized since 2008.


July 2018

Figure 4.3: Regional Residual Fuel Oil Consumption (million bbl/day)

Source: Data from UN Data (2018)

Figure 4.4: Residual Fuel Oil Consumption Sectors (‘000 bbl/day)


Generally, Asia uses the highest amount of fuel oil followed by the Middle East, Europe and South America (Figure 4.4). In Figure 4.4, residual fuel oil use in different sectors are grouped into Bunkering (40%), Combustion (24%) and Transformation (36%). Transformation refers to residual fuel oil the is used in refineries as a feedstock to a hydrocracker and a coker after desulphurization

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and for other production purposes. Significant amounts of residual fuel oil are used as fuel for

industrial heat generation and electricity generation in Asia, the Middle East, Europe and South America.

Figure 4.5: Market Share of International Bunker Fuel Oil


Asia equally uses the largest amount of fuel oil for international bunker fuel. Its fuel oil use in international bunkers makes up 45% of the total global fuel oil for international bunkers in 2015 (Figure 4.5). This implies that almost half of the global fuel oil used for international bunkering

should find a replacement in Asia. The implications of the change will be significant in the region and expose the Asian bunker market to the highest levels of bunker fuel price fluctuations and risks if compliance is strictly monitored and enforced.

The discussion of where a large fraction of the current residual bunker demand (3.5 million bbl/day) will find new markets brings to focus the possibility of a trend increasing cleaner fuel options such as natural gas and LNG in some regions. Asia, the Middle East, South America and Africa are likely major destinations for increased use of residual fuel oil, which will become cheaper as the IMO regulation kicks in. This is because each of these regions used between 120,000-681,500 bbl/day of residual fuel oil in 2015. These regions used the highest residual fuel oil for heating and electricity in the world. Thus they are jurisdictions where it is possible to re-purpose the fuel oil surplus for fuel for electricity and industrial heating.

A recent S&P Global news report indicates that fuel oil traders are turning to the power sector to assess how much demand may remain for their product after the IMO's tighter bunker sulphur limits leave most ship operators buying cleaner fuels in 2020 (Burns, Pittalis, Sleiman, Jordan, & Rubin, 2018). However, it is uncertain how much of the surplus residual fuel oil will be cleared for electricity and industrial heating. On the one hand, the current global push for cleaner fuels and

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climate change action may deter this option. On the other hand, will the lack of demand and

consequently, the potential low prices of residual fuel oil, make it an attractive fuel option by 2020?

Globally, about 1.86 million bbl/day of residual fuel consumption was used for electricity generation and industrial heating in 2015. Increases in the amount of residual fuel oil used for combustion in places like Asia, the Middle East, South America and Africa has the potential to dramatically address the oversupply of residual oil. The combined amount of residual fuel oil combusted in these jurisdictions amounts to almost 1.5 million bbl/day. It is unlikely that the use of residual fuel oil for combustion in these places will double. However, there is a possibility of an increase of 20-40% which is equivalent to an additional 300,000-600,000 bbl/day of residual fuel oil uptake in electricity generation and industrial heating (Figure 4.6). It remains to be seen whether a decrease in the price of high sulphur fuel oil will lead to a significant increase in the

use of this fuel for electricity generation and industrial heating.

Figure 4.6: Change in Demand for Residual Fuel Oil

Even if significant amounts of the residual fuel oil supply in 2020 is channelled towards electricity generation, this can only happen because of cheap residual fuel oil prices. An increase in demand

for residual fuel oil for heat and electricity generation is not likely to rebalance the prices of the fuel. It is important to determine the levels of price discount of resid bunker fuel where the demand for the fuel will switch from one sector to another. Assumptions are made on possible levels of discount in the price of resid bunker fuels as a result of the IMO regulation. Currently, the price of HSFO is high due to a tight supply of heavy residue streams for non-switchable

residual oil demand, which is used dominantly by shippers for marine fuel use and refineries as a conversion feedstock (Ruiz-Cabrero et al., 2017).

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Figure 4.7: Switchable Demand for HSFO

As shown in Figure 4.7, the price setting point between 2017 and 2019 will be set by unswitchable demand for residual fuel oil demand for conversion feedstock at refineries. However, between 2020 and 2025, a disruption period when the price of HSFO is set to decline due to a glut of about more than 3 million bbl/day, the HSFO price will be set by demand substitution with switchable demand options (see Figure 4.7). The switchable demand options include the use of fuel oil to

replace petroleum coke, which is used as a fuel in cement manufacturing and to substitute coal and natural gas in power plants. This rationale forms the basis on which the compliance scenarios are assumed.

Non-Compliance Scenarios Three non-compliance scenarios (see Figure 4.8) are assessed:

• Low non-compliance (Low NC) – assumes 80% compliance (20% non-compliance) by 2020 given up to 80% of global trade occurs between regions where ECA is in force and other regions of the world.

• Moderate non-compliance (Moderate NC) – assumes 75% compliance (25% non-compliance) by 2020.

• High non-compliance (High NC) – assumes 70% compliance (30% non-compliance) by 2020.


July 2018

Figure 4.8: Non-compliance Scenario Assumptions

CERI assumed the following resid price cuts by 2020, 2025 and 2030 (Table 4.1). These vary based on the level of non-compliance with the IMO regulation.

Table 4.1: High Sulphur Bunker Fuel Price ($/bbl)

2017 2020 2025 2030

Low NC 42 8 9 12

Moderate NC 42 21 22 30

High NC 42 29 31 42

Source: CERI

During the first few months or years of the IMO 2020 regulation’s implementation, some level of non-compliance may be accommodated. This will be due to fuel availability, and different levels of enforcement in different regions. Given that about 87-98% of ships comply with the 0.1%-wt

ECA sulphur rule in Europe, we are assuming the Low NC scenario will be slightly less than the ECA sulphur rule compliance levels in Europe. We consider the fact that non-compliance will differ across geographical regions, for example in regions known for strict enforcement versus those known for less rigid enforcement. Thus, our Low NC scenario assumption is a compliance of 80% and above. At this level of compliance, we assume that the price of resid bunker fuel will be at parity or fall below prices of coal or petroleum coke. Thus, our assumption of $8/bbl resid bunker fuel under the Low NC scenario by around 2020 and slight increases in the prices after that is due

to increases in coking and desulphurization capacities.

The Moderate NC case assumes that the resid bunker prices will approach parity with natural gas prices. On an energy content basis, prices of natural gas at $3.2/bbl is equivalent to the price of resid bunker fuel at $21/bbl. Similarly, slight increases in the prices of resid bunker fuels after 2020 are expected due to increases in coking and desulphurization capacities. The High NC scenario is chosen as a 30% drop in price of the resid bunker fuel by 2020 caused by a non-trivial

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drop in the demand for the fuel in most developed countries. The price at this level corresponds

to the price of natural gas at slightly above $4/GJ. There is almost a consensus that a high level of compliance is expected. This is because most ships docking and fueling at the major shipping hubs in Houston, Singapore and Rotterdam will comply with the IMO 2020 regulation. In addition to that, the shipping industry has formed a network, the Trident Alliance, with members agreeing to contribute their reputations, resources, access and competence to drive solution strategies that contribute to the vision of robust enforcement of the sulphur regulation (The Trident Alliance, 2018). This shipping industry group of more than 45 companies is attempting to mitigate the threat of weak enforcement of the sulphur regulations and serve the best interests of the environment and human health as well as create a level playing field for business.

Crude Diet Prices and Refinery Products The goal of this section is to determine the prices of crudes and refinery products that will be

used for determining future refinery margins and the impact of the IMO regulation on refinery profitability. The EIA projection for WTI is used to represent the price of light sweet crude between 2017 and 2030 without the IMO regulation. Considering the amount of resid produced based on light sweet crude assays and deducting the value loss of refinery products from drops in resid prices under each compliance scenario, new price profiles for light sweet crude are generated. The EIA price outlook without the IMO regulation and the new price outlook generated for the light sweet crude under the three IMO regulation compliance scenarios are presented in Figure 4.9.

Figure 4.9: Light Sweet Crude Oil Price Outlook With and Without the IMO Regulation

Source: EIA, CERI

A similar analysis is performed using crude assays and the potential loss of value of refinery products to project the potential price losses of other types of crudes (light sour, medium, heavy sour and heavy sweet), which form the crude blends processed in each of the US PADDs. The prices of the light sour, medium, heavy sour and heavy sweet crudes are projected for a future without the IMO regulation by accounting for the potential loss in resid value.

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A slightly different approach is used to estimate the future product prices of gasoline, heating oil,

jet fuel and ultra-low sulphur diesel. Looking at the pattern of historical price peaks and troughs (Figure 4.10), the average growth rate during the last extended period of price increases (1990-2008) is used to project future prices of motor gasoline, jet fuel, heating fuel oil and coke.

Figure 4.10: Historical Refined Product Prices

Source: EIA

The period between 1990 and the recession in 2008 witnessed an annual average price increase of 0.03%. However, 0.05% is assumed as the future annual average price increase. With these

prices and that of the resid bunker fuel determined, the price of Ultra Low Sulphur Diesel (ULSD) is calculated at refinery margin breakeven point for each compliance scenario analyzed (Figure 4.11).

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Figure 4.11: Price Forecast for Ultra Low Sulphur Diesel

Under the non-compliance scenarios analyzed, the middle distillate (represented by ULSD) price is estimated to rise by ~19-30% in 2020 from 2017 prices. For both the High NC and Moderate NC scenarios, a ULSD price of up to $93-$96/bbl is anticipated by 2020. This is a 19-23% increase in the price of diesel from $78/bbl. On the other hand, the Low NC scenario is expected to push diesel prices higher to slightly above $101/bbl.

IMO Regulation: Impact on US Refinery Margins Relative to the 2017 refinery margins (Figure 4.12), the changes in resid and middle distillate prices will reduce refinery margins to a notable degree.

Figure 4.12: Average 2017 Refinery Margins of Cokers and FCC

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As shown in Figure 4.13 and later in Figure 4.14, the impact is different for the three compliance

scenarios and affect medium and complex refineries disproportionately.

Figure 4.13: Medium (FCC) Refinery Margins under Different Compliance Scenarios

As discussed previously, current margins for the complex refineries are some multiples of those of the medium refineries. Simple and medium refineries in the US and worldwide seem to have little or no flexibility to absorb cuts in their netbacks. The results presented in Figure 4.13 confirm

this fact.

Under the Low NC scenario, medium refineries will see their margins reduced by $15/bbl-$19/bbl (with an average $17/bbl) by 2020 relative to the average 2017 margins. Some slight but negligible differences in margin impacts are observed between the PADDs, so average margin impact will be indicative of the general effects. By 2025 and 2030 the margins for these refineries would have

improved slightly due to market re-structuring. The reduction in their margins will average about $16/bbl and $13/bbl for 2025 and 2030, relative to 2017 values. The market rebalancing improves margins of a medium refinery as a result of recovering residual oil prices (Figure 4.11) and of a reduction in crude oil prices as a result of the crash in the prices of residual oil. However, the distillate prices will start to fall to approach new equilibrium prices after 2020 (see Figure 4.11) and consequently, will counterbalance the effects of a reduction in crude oil prices. This is the

reason why refinery margin improvements are not expected to be significant after 2025.

For the Moderate NC scenario, medium refineries will have their margins reduced by an average of $15/bbl by 2020 relative to 2017 margins. Unlike in the Low NC scenario where the margins improve by 2025, the refinery margins are reduced further under the Moderate NC scenario by $3/bbl bringing the average margin reduction to $18/bbl by 2025. This is caused by the rebalancing market where the drop in middle distillate prices far outweigh the cumulative


July 2018

positive effect of increases in residual price and fall in oil prices. The refinery margin outlook for

2030 under the Moderate NC gets better than that of 2025 and approaches the 2020 refinery margins. This effect is because the market rebalances the prices of middle distillates and the residual oil prices increase further.

Under the High NC scenario, medium refineries will have margins similar to those of the Low NC scenario by 2020 and thereafter, even the worst refinery margin outlook is likely. A margin loss of up to $26/bbl is expected between 2025 and 2030. There are a few reasons why this scenario has interesting outcomes. One cogent factor is the fact that compliance levels will be reasonably high even in this scenario. The Low NC scenario represents compliance of up to 70%. Although the compliance level is non-trivial, there is not as significant an increase in middle distillate prices as is observed in the other two non-compliance scenarios. Nevertheless, residual oil prices still fall significantly, though not like in the other scenarios. This scenario presents an interesting case for

the seriousness of the impacts of the IMO regulation no matter how low compliance levels will be. From the perspective of the refiners with complex refineries, low levels of compliance could bring significant negative impacts on their margins.

Figure 4.14: Complex (Coker) Refinery Margins under Different Compliance Scenarios

Margins of complex refineries will be better off than they were in 2017 under the Low NC scenario as a result of the IMO 2020 regulations. These sophisticated refineries that specialize in processing heavy crudes will enjoy increases in refinery margins. However, under the Moderate and Low NC scenarios, they will not be unscathed.


July 2018

Under the Low NC scenario, complex refineries will see their margins increased by $2/bbl-$4/bbl

(with an average $3/bbl) by 2020 relative to the average 2017 margins. The margins for all the PADDs except PADD 4 would still be better than 2017 margins by about $1/bbl-$4/bbl and $5/bbl-$8/bbl by 2025 and 2030, respectively. The margins of these PADDs improve because of favourable crude and refinery product prices. However, PADD 1 has a positive margin (~$2/bbl) by 2020 and barely reaches a breakeven point by 2025, but its margins become -$3/bbl by 2030. PADD 1 margins are not promising because of the composition of the crude blend feedstock into the refineries which is chiefly more expensive crudes such as light sweet and medium crudes. The PADD also produces the least amount of the middle distillate cuts which are expected to increase in price as a result of the IMO regulations.

Under the Moderate NC scenario, the general trend shows that margins of complex refineries in all the US PADDs will reduce relative to 2017 margins. Only a slight variance in the impact on the

PADDs for 2020 and 2025 is observed. The reduction in their margins will average about $2/bbl (with a range of -$1/bbl and -$3/bbl) by 2020 and $7/bbl (with a range of -$5/bbl and -$8/bbl) by 2025 relative to 2017 values. For the reasons explained previously, the impacts on margins are not improving with time under this scenario. The market dynamics in 2025 which slightly increases residual oil prices (Figure 4.11) and reduces crude oil prices are outweighed by rebalancing middle distillate prices. Again, for the reasons above, the IMO regulation has a higher impact on PADD 1 than in the other PADDs beyond 2025.

For the High NC scenario, margins of complex refineries will suffer as average refinery margin losses of $8/bbl, $19/bbl and $23/bbl are expected in 2020, 2025 and 2030, respectively. It is no longer a surprise why the scenario attracts the highest margin penalty. Though it is the least level of compliance, the extent of compliance is still reasonably high, and as a result, residual oil prices

still fall significantly. But this scenario does not attract the high middle distillate prices seen in the other scenarios. Again, this scenario shows that the IMO 2020 regulations will have even greater negative impacts for complex refineries at low compliance levels.

On a PADD-level, although some PADDs will have low margin reductions and even an increase in margins by 2020, it is reasonable to assume that refinery planners and crude buyers will use the highest margin reduction to make decisions. Therefore, we expect the highest margin reduction cases from medium refineries to set the prices for heavy sour crudes and the light-heavy crude price differential. If FCCs are considered as the price-setting refineries, a $15/bbl to $17/bbl drop in refinery margins relative to 2017 can be expected in 2020 for all the non-compliance scenarios. By 2025, refineries are likely to see their margins drop by $16/bbl to $26/bbl relative to 2017 margins in all the non-compliance scenarios assessed.

Salient observations:

• Increased level of non-compliance may not push middle distillate prices as high as one would expect with increased levels of compliance. The higher the price of middle distillates, the higher the margins and this effect outweighs the penalty from diminishing


July 2018

resid prices. An exception to this pattern is a case where the refinery does not produce a reasonable volume of low sulphur middle distillates.

• A general trend of declining margins is expected for some years after 2020 due to an expected drop in prices of middle distillates post-2020 as the market rebalances and the distillate prices drop towards its normal levels. Unfortunately, the price of resid will not recover at a rate that can stabilize the refinery margins, and thus, cannot cushion the effect of the rebalancing middle distillates prices. This is because the effect of price movements of ULSD outweighs the margin-boosting effect from slowly increasing resid prices.

• It can be deduced that the IMO regulations will have serious negative impacts on simple and medium refinery margins no matter the non-compliance scenarios considered. Also, complex refineries will not be spared of these impacts if compliance levels are not high enough to drive up the prices of middle distillates and push down the prices of residual fuel oil and heavy sour crudes to significant levels.


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Chapter 5: Compliance Options The shipping industry will bear the brunt of the IMO regulation more than other sectors. They will have to respond to or bear the brunt of a change in their bunker fuel requirements and the associated market and price dynamics. No industry other than shipping is more directly impacted – other industries are only indirectly affected. Also, the level of compliance with the IMO rule will be determined mostly by the shipping industry.

The industry is capital constrained and has very tight margins, and their margins may shrink further.

There are uncertainties associated with the way this regulation interfaces with many industrial

sectors (transportation, refining, oil production) and the existence of many options to comply. Therefore, ship owners have not made significant investments or decisions to modify their vessels before the 2020 deadline, to discontinue exclusive use of HSFO.

Scenario: Moderate Non-Compliance After examining the three scenarios, we chose the Moderate NC scenario for further analysis. Figure 5.1 shows how different options are projected to substitute resid bunker fuel volumes by 2020, 2025 and 2030 under this scenario.

Figure 5.1: Substitution Options of Resid Bunker Fuel

Compliance is a concern given the fact that levels of compliance in the short- and long-term may determine if the goals of the regulation will be achieved and how the markets will respond. Also, it is still uncertain how compliance will be enforced because the IMO cannot enforce the rule. The

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flag states where the ships are registered, and the port states could be in a better position to

enforce the rule.

The proposed Carriage Ban, which makes it illegal to carry HSFO on ships that have not installed sulphur scrubbers, increases the likelihood of higher compliance. The Carriage Ban is expected to come into effect, but not until March 1, 2020. With the Carriage Ban, it is believed by shipping industry participants that there will be effective enforcement of the IMO regulation. This is because the Carriage Ban regulatory amendment makes it easier for port state authorities to detect and sanction ships (IBIA, 2018). Given these developments, an assumption of 75% compliance may be low.

Previous estimates of how much of the world fleet will continue to use sulphur fuel vary significantly. For example, S&P Global Platts (2018) allocates 10-15 vol.% of the displaceable high

sulphur fuel oil to exhaust gas scrubbers, LNG bunkers, or waivers/non-compliance in 2020. However, it is important to note that the first few months or years of the IMO regulation’s implementation may likely accommodate some level of non-compliance due to a variety of reasons including fuel availability, and different levels of enforcement in different regions. Some of these are the reasons why the Carriage Ban is delayed to March 2020. More so, if about 87-98% of ships comply with the 0.1%-wt ECA sulphur rule in Europe, it would not be surprising to see lower compliance levels at a global scale for a slightly less-stringent 2020 IMO sulphur rule. This is the context for CERI’s Moderate NC assumption of 75% compliance.

Below is the list of the major compliance options which are further assessed.

1. Scrubbers – to reduce SOx emissions via on-board scrubbers (also helps reduce particulate matter, PM).

2. Desulphurize refinery fuels and use lower sulphur content fuel. 3. Switch entirely or partially to middle distillates for bunker fuel. 4. Undertake custom blending of fuels on board and use segregated bunkers tanks. 5. Switch to alternative fuel sources (e.g., LNG and methanol) that reduce sulphur, CO2, and

particulate emissions. 6. Establish emissions trading, which could allow trading of marine and shore-based credits.

Scrubbers There are uncertainties as to the market uptake of scrubbers. Questions regarding scrubber uptake levels, how soon and how strict policing of the new rules will be, as well as calls for a phased introduction to the new cap (rather than a "hard" start for all on January 1, 2020), means that shippers and refiners have little idea what roles the other options will play in 2020.

Responses to fuel demand with improved refined products will be slow given the investments needed. Investing in technology to convert fuel oil into distillates is not only expensive ($1 billion+ per refinery), it is also time-consuming to implement (5-7 years). Buyers can expect price spikes if there is a shortfall (Hampton & Kumar, 2017).


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Scrubbers, which reduce the sulphur content of onboard fuel ships, are alternatives to buying

more expensive, cleaner fuel. Shippers are making some investments in onboard scrubbers. For example, Trafigura, a shipping and chartering company, has invested in 36 tankers with scrubbers (Hampton & Kumar, 2017). Previous studies have estimated different numbers of ships that will be equipped with scrubbers by 2020 (Figure 5.2.). H

However, there is a unanimous agreement that the rate at which sulphur scrubber investments are being made across the shipping industry is not fast enough given that 2020 is not far away.

Figure 5.2: Estimates of Ships with Scrubbers by Previous Studies

Data sources: CE Delft, Assessment of Fuel Oil Availability – Final Report, 2016 and EnSys/Navigistics, Supplemental Marine Fuel Availability Study 2016

Several issues have been identified as factors in determining the preferred options for ships. These factors include the cost of scrubber installation, trading routes, the age of vessels, parties responsible for fuel, type of vessel and trade, bunker market conditions and availability and affordability of fuels. The uncertainties associated with these issues are highlighted below.

For a financially challenged industry with vessel oversupply and low charter rates, what is the best option among two options: bear the capital costs of scrubbers (average of $4-5 million) and operation costs and continue to use low-cost bunker fuels, or switch to low sulphur marine fuel? Installing a scrubber takes about six months which will be a lost revenue period (Ruiz-Cabrero et al., 2017). About $2-3 million per vessel will be associated with the IMO’s requirement for ballast water management system and will add to the financial challenges of the shipping industry. Other considerations include:

• Trade routes,

• Type of trade,

• Age of vessels, and

• Party responsible for the fuel costs.

Estimated HSFO demand for ships equipped with scrubbers - 2020

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Currently, less than 1% of the worldwide fleet is operating within the future regulatory limits for

sulphur emissions for open ocean areas outside the Emission Control Areas (ECAs). Scrubbers are installed in less than 1% of ships worldwide, and analysts believe that its future adoption will be minimal.

Under the Moderate NC scenario, we estimate that scrubbers will capture only about 3% of the HSFO volume to be displaced by 2020. It is important to note that the costs of HSFO may increase as a result of costs of maintaining HSFO bunkering logistics and infrastructure such as HSFO barges, storage, and pipelines (Ship & Bunker, 2020). This is because HSFO will no longer be the mainstream bunker fuel and this will adversely affect investments in maintaining bunkering logistics and infrastructure. Different levels of bunkering logistics and infrastructural development in hubs have already created a wide HFSO price margin between ports; this margin is likely to increase significantly in the future. As shown in Figure 5.3, scrubber adoption is likely to increase

moderately and peak at a point where about 5% of the resid bunker demand is replaced with scrubbers.

Figure 5.3: Substitution Volumes for Resid Bunker Fuel

Refinery Additions Global refining capacity additions to 2023 are forecast to amount to 7.7 million bbl/day whereas the rate of growth of refined product demand is slowing to 5 million bbl/day (IEA, 2018b). About

a third of an additional 7.7 million bbl/day of the extra refining capacity expected to come online by 2023 will be in the Middle East and the rest in Asia (Denning, 2018). Enough low sulphur-compliant fuels can be created from these additions to meet the demand for cleaner fuels for the shipping industry by 2023. However, most of the resid to be produced from these expected additions may be economical feedstock for FCC and not readily available for low sulphur fuel oil supply (S&P Global Platts, 2018).

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Conversion additions in mostly China and India between 2017 and the beginning of 2020 amount

to 1.7 million bbl/day, and are expected to be nearly split between coking, hydrocracking and catalytic cracking (S&P Global Platts, 2018). The location of the units is not linked to non-bunker suppliers; thus, it is unlikely that these conversion capacities will contribute significantly to low sulphur marine bunker fuels. However, they may be export destinations that accept and destroy unwanted high sulphur resids.

Similarly, though heavy oil desulphurization facilities of 1.1 million bbl/day are expected between 2017 and 2020, only 20 percent of this capacity is a location outside Asia. About 580,000 bbl/day capacity is for resid treatment, out of which about half of that capacity is intended for FCC feed pre-treatment (S&P Global Platts, 2018). About 240,000 bbl/day resid hydrodesulphurization capacity can be assumed to contribute to low sulphur fuel oil by 2020. This number will increase in the future as the increase in the light heavy product differentials is expected to motivate

investments in desulphurization. Desulphurization will capture up to 14% of the 2025 planned additional refinery resid hydrodesulphurization capacity.

Investment in desulphurization units is an attractive option because of the price premium that LSFO will attract by 2020. Desulphurization is still expensive despite being cheaper than cokers and hydrocracking, the cost being $900 million. However, desulphurization offers more flexibility (Ruiz-Cabrero et al., 2017). When price differentials are wide between refined light and heavy products, desulphurization can produce more distillates to maximize profits. On the other hand, when the price differentials narrow, desulphurization units can be used to hydrotreat fuel oil to produce a compliant fuel (Ruiz-Cabrero et al., 2017).

S&P Global Platts (2018) estimates that after considering the incremental crude runs, and asphalt

demand, the planned new facilities are capable of absorbing 1.6 million bbl/day out of the 3.2 million bbl/day resid volumes that need to be destroyed. This means half of the target still needs to be met, so it would be necessary to examine how modifications of the current refinery operations could absorb the remaining resid supply.

Currently, the global crude distillation capacity is 97.4 million bbl/day whereas that of vacuum distillation is 37.2 million bbl/day. North America, Asia Pacific and Europe are the three major refining hubs with North America having the highest vacuum distillation capacity (Figure 5.4). Capacity factors have averaged around 78%.


July 2018

Figure 5.4: Global Crude and Vacuum Distillation Capacities, 2017

Source: OPEC 2017

Refiners can process additional millions of barrels per day of crude to make more distillate. Hampton & Kumar (2017) put this number at 2.5 million bbl/day of crude. This estimate seems to underrate possible capacity factor increases because it suggests an increase of only 0.3% capacity factor. While the global average is 78%, some regions such as North America, Europe, the Middle East and Asia already operate at capacity factors that are close to 90%.

A 5-10% increase in capacity factors across all regions will result in an additional 4.9-9.7 million bbl/day capacity of crude refining. Thus, room exists to increase the utilization capacity of refineries at a global level. Even in regions with already high capacity factors, there are opportunities beyond the 0.3% forecast noted above.

One example of this is increasing capacity factors of refineries in the US PADDs by 3%, 5% and 8% which will result in productions of about 38,000 to 100,000 bbl/day additional volume of distillates. A high-level estimation of the limits of global refining capacity increases to meet distillate demand by 2020 can be made using conversion capacity and product yield approximations.

If we assume world refineries are, on average, medium refineries, about 1.3 million bbl/day of

distillates together with 1.2 million bbl/day heavy fuel oil and other bottoms will be produced from a 5% increase in the global refinery capacities. On the other hand, a 10 percent increase in the global refinery capacities will result in 2.6 million bbl/day of distillates together with 2.3 million bbl/day heavy fuel oil and other bottoms. In each case, large amounts of distillates that can bridge the gap of cleaner bunker fuel demand can be produced. Equally large amounts of heavy fuel oil are produced alongside the production of distillates. This will likely keep high sulphur fuel oil prices low. Additionally, the world is reaching peak gasoline demand and would

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not need the additional naphtha generated by the added crude processing. So, increasing

capacity may be part of the solution to the bunker fuel availability problem but adds to the problem of resid glut because more resid will be produced as refiner’s process more crude volumes.

The reason why refiners are not making costly refining modifications like adding new coking capacities at faster rates may be because the price volatility that will be created from the IMO rule implementation is not expected to last long enough to make such investments viable and there exists some spare capacity to meet demand in the short term. The markets are expected to rebalance in a couple of years, and this discourages serious capital investments in complex refining units, which has a payback period of at least two decades.

Slow-Steaming Slow-steaming, which is a term used for reducing ship speeds, will be one of the options the shipping industry will use to reduce fuel costs. When marine fuels are cheap, ships travel faster than usual, and because of that, they consume more fuel. However, when marine fuel prices skyrocket as is expected by 2020, ships are likely to slow down their speeds in order to conserve fuel and save costs. Therefore, the rate at which slow steaming will be used will be contingent on how expensive compliant fuels become during the onset of the IMO regulation.

Figure 5.5: Fuel Consumption and Speed Relationship

Source: Bialystocki and Konovessis, CERI

The slow-steaming approach can be an effective way to cut costs that the shipping industry cannot pass on to their customers. Given that shipping fuel consumption has a velocity-squared relationship, as shown in Figure 5.5, a slight reduction in ship speeds by a few knots (equivalent to 1.85 km/hour) will lead to a significant reduction in fuel consumption and costs. For example, slowing down by 2 knots (3.7 km/hour), from 19 knots to 17 knots, results in a fuel savings of about 15 tonnes/day, from 60 tonnes/day to 45 tonnes/day (Figure 5.5) – about a 25% reduction


July 2018

in fuel costs. With this illustration, it is evident that reducing ship’s speed to achieve a 25-50%

reduction in fuel consumption is possible if the compliant fuel prices skyrocket.

Considering the potential of fuel savings from slow-steaming of ships, it will not be surprising to see this option deployed at significant levels to address fuel shortages and buffer high prices of compliance fuels by 2020. CERI envisages a dynamic balancing act between complaint distillate fuel demand and prices and the rates of slow-steaming. It is important to note that most of the slow-steaming ships will use compliant fuels, most of which will be distillates. Slow-steaming will be used to reduce the costs of running the compliant fuel which will be expensive at the onset of the rule.

However, slow-steaming will increase voyage time, delay deliveries and cause more ships to be deployed on the oceans. Longer voyage times will cause more ships to be used to meet global

trade balance. But on the other hand, the world currently has an oversupply of ships, a situation that will benefit from increasing the number of ships required for global shipping demand.

Slow-steaming does not help in the destruction of excess High Sulphur Fuel Oil but precludes the treatment of additional crudes in order to produce more distillates in response to compliant fuel scarcity. Slow steaming does nothing to address the amount of HSFO that is in excess of market requirements in 2020 and beyond. Unfortunately, this latter point is of uttermost importance for Alberta.

Distillates Switching to marine gas oil1 (MGO) is seen as the easiest route to compliance, and it is expected that MGO will be the preferred option for ship owners by 2020 (ExxonMobil, 2018). There is one

outstanding benefit to the option: the use of MGO requires no upfront investment. However, it also faces a major setback, which is associated with high fuel costs. For example, Ship & Bunker data indicates that over the last five years, the average premium for MGO over HFO in Rotterdam was $255/MT (ExxonMobil, 2018). By 2020 the price of MGO will significantly increase whereas that of HFO will decrease dramatically. This is because of demand-price dynamics of the products which will result from the IMO sulphur limit regulation.

Distillates refer to fractions separated from the crude oil in fractional distillation. Distillates are colloquially known as marine gasoil (MGO). Marine gasoil is like diesel fuel but has a higher density. Unlike HFO, marine gasoil does not have to be heated during storage. Marine gasoil is used in smaller medium- to high-speed auxiliary units or auxiliary motors and ship’s engines. It is produced with varying degrees of sulphur content, though the maximum permissible sulphur

content is 1.5% (ISO 8217 DMA quality label).

To achieve various specifications and quality levels, HFO is blended with distillates, e.g., marine gasoil or marine diesel oil. The resulting blends are also referred to as intermediate fuel oils (IFO) or marine diesel oil. They are classified and named according to their viscosity. The most

1 This is 100% distillate oil.


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commonly used types are IFO 180 and IFO 380, with viscosities of 180 mm²/s and 380 mm²/s,

respectively.

In choosing marine fuel blends, for shippers, fuel oil is preferred over gasoil. Many marine engines are optimized to operate on heavy fuel oil (HFO). Because of its low viscosity, lubricity, acidity and flash point, marine gas oil often leads to several adverse effects on fuel and engine systems. Thus, switching to MGO in traditional marine engines carries significant operational risks which are listed in Table 5.1.

Table 5.1: Operational Risks of Using Marine Gasoil as a Bunker Fuel

Characteristics Operational Drawbacks

Low Viscosity Fuel oil pump: Internal leakage, breakdown of the hydrodynamic film leading to seizures Fuel oil pump: Insufficient fuel index margin, limiting acceleration Fuel injection nozzle: Increase inflow, leading to non-uniform combustion and decreased fuel efficiency

Low Lubricity Fuel injection pump: abnormal wear of plunger/barrel Low Sulphur/ Low Acidity

Boilers: Increased turndown ratio and minimum boiler load, leading to deterioration of ignitability Engines: Ignition delay and defective combustion With the reduction in acidity (sulphuric acid formed), deposits may be formed using high alkali base number cylinder oil and abnormal cylinder liner may occur

Flashpoint Higher fire hazard

Fuel oil is a fraction obtained from distilling crude oil during the refining process. It could be a distillate or a residue and is the least volatile and heaviest of the commercially-used fuels. Some 10% of fuel oil produced is used to power large ships. A further 15% is used for heating, and refineries use the remainder as feedstock for further upgrading.

Bunker fuel prices vary according to fuel type, quality, and bunkering locations. Figure 5.6 shows the prices of MGO, IFO 1802 and IFO 3803 at the Houston hub.

2 IFO 180 is an Intermediate Fuel Oil blend of 88% residual oil and 12% distillate oil 3 IFO 380 is an Intermediate Fuel Oil blend of 98% residual oil and 2% distillate oil.


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Figure 5.6: Prices of MGO, IFO 180 and IFO 380 Bunker Fuels at Houston

Source: Ship & Bunker (2018), CERI

Significant price differentials exist between the bunker fuels and across the hubs. At the Houston hub, for example, the prices for MGO were higher than that of IFO 380 prices by as much as $175/tonne to $250/tonne between June 2017 and March 2018. Also, the price differentials vary across regions, for example, the MGO - IFO 380 price differential at the Singapore hub varied between $150/tonne and $247/tonne within the same period.

On the other hand, and as expected, the price differentials between MGO and IFO 180 are significantly less than those of MGO and IFO 380 between June 2017 and March 2018. Note that

both MGO and IFO 180 are cleaner fuels than the IFO 380. At the Houston hub, the prices for MGO were higher than that of IFO 380 prices by $41.5 to $90/tonne in that period.

Blending is another option that can achieve compliance with the IMO regulation. We first considered mixing ULSD and heavy bunker fuel (Blend I). Achieving a sulphur content under 0.5% would require about 14% of heavy bunker fuel. The cost of the blend is high (43 cents per kilogram). Nevertheless, using a fuel mix of ULSD and heavy bunker fuel is still better than running 100% ULSD due to a potential savings of $30/tonne.

Alternatively, a blend of LS-MGO and heavy bunker fuel (Blend II) contains 12% heavy bunker fuel and 88% LS-MGO with a blended cost of $440/tonne. This blend also achieves the 0.5% sulphur content. The cost of this blend is $20/tonne cheaper than using LS-MGO.

When the two blending options are compared (Figure 5.7), it is assumed that Blend II is likely to be preferred because it is cheaper and has better fuel properties than Blend I.

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Figure 5.7: Marine Oils and Blends Prices

There is no current incentive to blend fuels. However, by 2020 the prices of LS-MGO and ULSD are expected to increase significantly. This will create a greater price spread between low and high sulphur bunker fuels. Consequently, the price movements by 2020 may motivate more use of blending, especially for Blend II.

Results show that the spread between the low sulphur distillates (ULSG and LS-MGO) and the blended fuel is likely to be highest at the onset of the IMO rule but will dramatically narrow in the long run. A high differential of about $30/bbl can be expected by 2020 whereas by 2025 the value may decrease to $3-5/bbl. Unless inhibited by logistics, blending and storage infrastructure, we expect that a significant portion of distillates that will be introduced into the marine fuel market will be blended with HSFO by 2020.

Liquefied Natural Gas A small but growing number of vessels will use liquefied natural gas (LNG) and other compliant alternate bunkers (ExxonMobil, 2018). LNG is expected to be applied to newly built vessels, particularly those that operate on fixed, predictable routes, or within a geographic area, particularly ECAs (Grati, 2017). Retrofits have been rare so far; a recent example is the WES Amelie, a container ship operating almost exclusively in the Baltic and the North Sea ECA (Grati, 2017). The current infrastructure for LNG bunkering is limited and will need to rapidly expand if LNG bunkers are to become more common for the largest consumers (Grati, 2017).

IHS Maritime counts 218 ships fitted for LNG fuel in service or under construction, and another 123 deemed "LNG ready." Although the switch to LNG requires a higher up-front investment,

lower LNG prices could enable a more cost-effective approach than low sulphur oils. LNG also has lower carbon emissions which provide additional environmental benefits beyond the decrease in sulphur emissions (Grati, 2017). LNG bunker consumption is expected to grow, yet by 2020, LNG bunkers will form only a very small percentage of total bunker consumption.

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The CE Delf report projected LNG consumption on board LNG carriers based on the projected

number of LNG carriers operating in 2020. The report projected the number of LNG carriers to increase by 20-35% from that of 2012. It further evaluated the use of LNG as a fuel by 2020. They concluded that LNG would power a total of 170 ships in 2020. The study also found that given the low market penetration of other alternative fuels such as methanol and other biofuels, their share in the marine fuel market will be negligible.

Our analysis aligns with the EnSys 2016 and CE Delf reports’ conclusion of negligible market penetration of alternative fuels in the maritime industry by 2020. The previous reports identified ship retrofitting and LNG bunkering as the two main obstacles to LNG development as a maritime fuel. Our projection of 1.9% to 7% of resid bunker fuel displacement volume fuel consumption falls within the range of IMO 3rd GHG study’s projection of 2-10% of the total marine fuel share.

Methanol Methanol is a fuel that could be used significantly in the marine industry in the future. Currently, there are seven ocean-going chemical tankers operating and four more under construction which ship methanol and are powered by two-stroke dual-fuel engines capable of running on methanol, fuel oil, marine diesel oil or gas oil (DNV.GL, 2016). Methanol consumption has lower GHG emissions compared to conventional shipping fuels and meets IMO sulphur restrictions, while also significantly reducing NOx emissions. The sustainable development of the fuel requires that overall lifecycle emissions do not exceed those of conventional shipping fuels. For this reason, the source and method of production are considered important.

Some previous studies have confirmed the availability of technologies for extensive methanol-as-fuel supply chain development. According to DNV GL (2018), the operational costs for methanol

systems are expected to be comparable with those for oil-fueled vessels without scrubber technology. The additional costs of installing methanol systems on board a vessel (e.g., internal combustion engine, fuel tanks, piping) is roughly one third that of the additional costs associated with LNG systems. This is because there is no need for special materials able to handle cryogenic temperatures or for pressurized fuel tanks. In addition, capital costs are reducing dramatically, as learnings from experiences are yielding benefits.

A majority of the existing methanol supply infrastructure is tailored to channel it as feedstock to the chemical industry. As the supply chain extends further into the transportation fuel market, including shipping, more low-carbon methanol may be needed to improve the environmental performance. Low-carbon methanol can be produced from both natural gas or alternative feedstocks such as biomass. These considerations lead us to conclude that methanol’s use as a

substitute for resid bunker fuel is limited, at least in the short run, but it can grow substantially depending on future oil price scenarios.

Arctic Heavy Oil Transport Ban Another issue worth considering is the “ban versus no ban” debate of high sulphur heavy crude oil in the Arctic. The US and Greenland support the ban whereas Russia and Canada and other countries oppose it. If there is a ban, that means higher transport costs for transporting high


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sulphur heavy oil that could be cheaply transported to destinations with sufficient coker

capacities. The imposition of a ban on heavy sour oil in the Arctic, if implemented, will put more downward price pressure on Canadian heavy crude markets.


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Chapter 6: Impacts on Canadian Heavy Oil The contribution of Canadian oil to the global HSFO bunker fuel supply is not significant. This is because Canadian bitumen is consumed by the bottom of the barrel complex refining in the US and Canadian refineries. Nevertheless, it is envisaged that Canadian bitumen will have to compete for US refining space on netback refining value with other crudes that currently contribute to HSFO. Therefore, there is a need to understand what constitutes the marginal barrel, what drives the quality discount and crude cost structure and the impacts on Canada’s heavy oil production.

Price of Canadian Heavy Figure 6.1 illustrates the historical benchmark price series and the WTI-WCS differential (Millington, 2018). The WTI-WCS differential is a discount on the Canadian crude price benchmark, Western Canadian Select (WCS) against the West Texas Intermediate (WTI) crude benchmark. The reality is that the WTI-WCS differential fluctuates over time based on market conditions. Historically, a low of US$6/bbl in April 2009 and a high of US$42/bbl in December 2007 have been recorded. Even recently, the differential was US$27.20/bbl in March 2018.

Figure 6.1: Light-Heavy Differentials (US$/bbl)

Source: EIA, Baytex Energy, CERI

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The price of crudes used in CERI’s models varies according to the quality and access to demand

centres. Light sweet crudes are easier to process, yield more high-value refinery products, and thus, are priced higher than heavy and sour crudes. Proximity to the coast or unrestrained access to markets is an equally important contributor to how much crude is discounted relative to others.

Figure 6.2: Maya-WCS and WTI-WCS Differentials at Cushing (US$/bbl)

Source: Argus, CERI

For example, WCS trades at a discount to the Mexican Maya although they are of similar quality. Historically, Maya has traded at a premium to WCS (Figure 6.2). This is because Maya is a

waterborne crude, which is readily available to US Gulf Coast refiners. However, the price of Maya represents the potential price WCS producers could realize (Millington, 2018). The majority of Canadian heavy crude (WCS) must be transported via pipeline or rail from Alberta (Edmonton and Hardisty) to the US Midwest where the benchmark is WTI.

Increase in demand for light sweet crude, which will arise due to the IMO 2020 rule, is expected to widen light sweet crude’s premium over heavier, sour crudes. On the positive side, the widening of the price differential could boost the advantage some Canadian and US refiners have gained by configuring their plants to further process heavy, sour crude over the past 20 years. These refineries can increase their margin by buying heavy sour crude feedstock at significant discounts. It seems reasonable to discount heavy sour crude due to the decrease in resid demands and prices.

The refinery optimization model is used to assess the optimal relationships between crude quality, refinery configuration and margins at PADD levels. Based on the refinery optimization model for each class of refinery configuration (hydroskimming, medium and deep conversion refineries), certain crude blends maximize the refinery margins. The optimal crude feedstock blends will be preferred unless in market situations where the prices of other crudes which are

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not part of the optimal crude blend become so cheap that a change in crude feedstock makes

economic sense.

Light sour and heavy sour crudes are likely to compete in the Gulf Coast (PADD 3) and US Midwest (PADD 2) if there are no notable logistical constraints. The competition will be simply about price and maximization of refinery margins. In this respect, the results from our optimal refinery model do not show any increase in the heavy sour crudes in PADDs 1 and 2 (Figure 6.3). It even suggests that a slight decrease (about 3%) of heavy sour, a 7% decrease in medium crudes and an increase in heavy sweet and light sour crudes to be treated in the US Midwest will result in higher margins. However, it seems almost certain that logistics and refinery make-up will guarantee the continued receipts of Canadian heavy sour in this region.

Figure 6.3: Potential Composition Changes in the Optimal Crude Blend

No change in the heavy crude composition of the Gulf Coast crude diet is indicated. On the other hand, the results show that increasing heavy sweet crude by 8% and decreasing heavy sweet and medium crudes in PADD 3 will lead to better margins. The increased production of light tight oil in the US has recently led to higher intakes of this oil in refineries on the East and Gulf Coast, but the results show that these regions may have had enough of this crude. A reduction of the light sweet intakes in these regions is indicated for higher margins. For the East Coast (PADD 1), logistical constraints will limit additional intakes of Canadian heavy crude.

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July 2018

Figure 6.4: Venezuela and Mexico Crude Outputs are Decreasing

Source: Argus

Although the model does not indicate additional heavy sour intakes in the Gulf Coast, the inability of Mexico and Venezuela to continue to supply competing heavy sour crudes to the Gulf Coast refineries presents additional opportunities for Canadian heavy oil. Figure 6.4 shows that Venezuelan and Mexican crude outputs have decreased dramatically over the past 2 years. If the declining trends of supply of Mexican Maya and Venezuelan heavy sour crudes persist, with the exception of logistical issues of pipeline access to the Gulf Coast, PADD 3 has suitable refinery equipment to handle heavy sour crudes. This should make for an easy replacement of the shrinking Maya and Venezuelan heavy volumes with Western Canadian Select crude. However, until new pipeline capacity is available, replacing supplies from Venezuela and Mexico will provide only limited opportunities (CAPP, 2018).

Our optimal model suggests that a 17% growth in the heavy sour composition in the crude diet of PADDs 4 and 5 will yield better margins. This is accompanied by a significant reduction in the medium crude component of the optimal crude blend for both PADDs. A reduction in heavy sweet crude for PADD 4 and an increase in the same crude type for PADD 5 are indicated. Currently, Canadian crudes make up 100 percent of the imports into PADD 4, most of it heavy crudes. Increasing heavy sour composition of the PADD 4 crude diet could result in operational bottlenecks given that the PADD processes predominantly light crudes. However, at least a stable outlook for Canadian crude is plausible given adequate pipeline accessibility.

Barring no logistical and operational limitations, PADD5 is likely to see significant increases (about 27%) in light sour crudes to maximize margins. Heavy oil conversion and asphalt capacities in the Washington area have the pipeline logistics and capacity to accept and process Canadian heavy

crude. Given that higher quantities of heavy sour are indicated to improve refinery margins, it is likely that the competition to meet this potential demand will come from countries that supply this crude type to the region – and these are Canada, Colombia and Ecuador.

Currently, the price of HSFO is high due to a tight supply of heavy residue streams for non-switchable residual oil demand. Being a conversion feedstock, it sets the price for HSFO (Ruiz-Cabrero et al., 2017). On the other hand, by 2020 when the price of HSFO is set to decline due to

Venezuela oil output Mexico oil output


July 2018

a resid glut, the HSFO price will be set by switchable demand and competition with other fuel

options.

Loss of volumes of Canadian heavy sour crude is possible because of the likelihood of foreign crude suppliers competing in North America, especially in the US Gulf Coast The glut of resid, and consequently, its price crash of heavier crudes, will spur low-cost producers of heavy crudes in the other parts of the world to compete in the Gulf Coast. As shown in Figure 6.5, these countries already hold significant market shares in the Gulf Coast and will be looking to expand their market shares when the IMO regulations kick-off.

Figure 6.5: Competing International Crudes in the Gulf Coast

Source: EIA, Argus

The margin losses will be transferred to the heavy crude that yields relatively high amounts of resid, with an accompanying reduction in the global price of all high sulphur crudes. This reduced netback for the Eastern Hemisphere supply of high sulphur crudes will increase the competition faced by Canadian suppliers and could potentially reduce the volume of Canadian crude processed in the US, especially in the Gulf Coast where several international crudes from Canada, Venezuela, Saudi Arabia, Mexico, Iraq and Colombia are competing (Figure 6.5).

The expected discount will be added to the existing Western Canadian Select price discount due to crude quality and market access limitations. Market access limitation and logistics is a factor

that has also impacted the crudes from the US Midland. The first quarter of 2018 benefited simple refineries which had access to the light sweet West Texas Crude. Full pipeline linkages in West Texas, where light US oil originates from, have depressed prices for Midland Texas crude to more than three-year lows (Kumar, 2018).

On the other hand, OPEC production cuts, supply issues and political instability among big producers of heavy crude like Venezuela and Mexico have raised the cost of heavy, sour oil

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(Kumar, 2018). As a result, complex refineries that can process high sulphur crude but are heavily

dependent on Venezuelan and Mexico crudes had reduced margins. This is the case for refineries in the Gulf Coast which do not have access to Canadian heavy crude due to lack of or sufficient connecting pipelines. This has indirectly strengthened the price of the Canadian high sulphur heavy crude.

WTI-WCS Price Differential It is important to assess the light-heavy price differential and the volumes of Canadian heavy oil that may be at risk (supply costs constrained) due to the potential widening of the light-heavy differential arising from the 2020 IMO sulphur regulation. Our methodology for assessing this risk is based on a project supply cost model which ranks projects according to economic viability concerning a range of light-heavy differentials.

Table 6.1: Maximum Refinery Losses ($/bbl) Under Different Scenarios

2020 2025 2030

Medium Refineries Low NC -18.6 -16.9 -18 Moderate NC -16.2 -19.1 -20.3 High NC -17.8 -27 -28.2

Complex Refineries Low NC 1.6 -0.2 -2.5 Moderate NC -2.8 -8.1 -12.6

High NC -8.7 -20.2 -25.7

As shown in Table 6.1, for the medium refineries, refinery margin losses of $16/bbl to $28/bbl are possible under the scenarios assessed. These losses may be directly transferred to a light-heavy differential given the assumption that medium refineries with the highest margin losses will set the price. Figure 6.6 illustrates how the refinery margin loss affects the WCS (heavy sour) pricing

relative to WTI (light sweet) for each of the scenarios. The dashed lines represent the WCS pricing that is historically discounted at $13/bbl plus the refinery margin losses from our analysis of the discount resulting from the IMO regulation.


July 2018

Figure 6.6: Changes to WTI and WCS Prices Due to the IMO Regulation (2017 US$)

Source: CERI

The cumulative discount on WCS with respect to WTI expands dramatically. Between 2020 and 2025, the cumulative WTI-WCS price differential averages $30/bbl. This is an unsustainably high differential though it is close to the WTI-WCS price differential seen recently. In March 2018, the differential was US$27.20/bbl due to transportation and logistical bottlenecks. If the differential remains steady at this point without a continued increase in oil price, some oil sands producers may be forced to shut down production. This was the situation recently when Cenovus Energy shut down production due to high price differentials. However, continued upward movement of

the WCS pricing in the case shown in Figure 6.6 could cushion some of the effects of the higher-than-usual light-heavy differential. If there is Low NC, the WTI-WCS will widen further, with a possibility to extend the cumulative WTI-WCS price differential to $40/bbl. This level of differential could present a challenge to the Canadian oil sands industry because the high supply costs of oil sands could render some bitumen production uneconomical. However, based on many indications, the Low NC is an unlikely scenario.

Given that the supply costs are made up of the capital and operating costs (Figure 6.7), it is important to assess how they contribute to the total supply costs of in situ bitumen production in Canada. Some of the projects are yet to recover their capital investments. By implication, these projects must generate sufficient income to cover the capital and operating costs in order to break even.

On the other hand, it can be assumed that projects over 20 years have their capital investments fully recovered which means that only the operating costs and sustaining capital costs are to be covered by the income projects generate to break even. The operating expense fraction of the supply costs have varied over time as a function of operational performance, efficiencies and energy (mainly natural gas) costs. However, after the oil price slump in 2014, several cost-cutting

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strategies have been deployed, and as a result, operating costs across the industry and the cost

of new capital investments are declining (Figure 6.7).

Figure 6.7: In Situ Capital and Operating Production Costs

Source: CERI

One factor that has reduced operating costs is that natural gas prices have been relatively low in recent times due to the shale gas boom. The declining operating costs have also been attributed to efficiency improvement efforts of the sector. The efficiency improvement efforts that have led to lower operating costs can also be related to a reduction in steam-to-oil ratios (SOR) of the

projects.

The SOR is the volume of steam in cold-value equivalents used to extract a unit volume of bitumen. The lower the volume of steam used to extract a barrel of bitumen, the more efficient the process which consequently lowers the energy-related costs. The SORs of the current in situ projects vary considerably though about half of the production volume has a SOR between 2 and 4 m3/m3.

Change in the SOR of a project can significantly influence the supply costs or the viability of the project. A 25% increase in the SOR of a new and expanding SAGD project from a SOR of 3 m3/m3 will increase the supply costs by 7-9%. However, a 25% reduction in the SOR of the project will reduce the supply costs by almost 4-7%. The results are similar when the same sensitivity results

applied to non-energy operating costs.

Figure 6.8 shows the profitability of a new SAGD project (2017 US$ values) for different WCS pricing cases: 1) Without the IMO regulation, 2) Low NC scenario with the IMO regulation, and 3) Moderate NC scenario with the IMO regulation. The results show that only new SAGD projects with SORs of less than 3 m3/m3 may break even when the IMO regulation is enforced under the most likely scenarios presented in Figure 6.8.

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Figure 6.8: New SAGD Project Viability by 2020

Source: CERI

Similarly, Figure 6.9 shows the profitability by 2020 of a SAGD expansion project (2017 US$ values) for the different WCS pricing cases mentioned above. It appears that for expanded SAGD projects, a wider range of SORs would not be affected by the IMO regulation under the most probable scenarios.

Figure 6.9: Expanded SAGD Project Viability by 2020

Source: CERI

Given these results, the volume of SAGD bitumen production at risk can be deduced. Expanded projects may not be affected significantly, but standalone projects with a SOR greater than 3 m3/m3 are at risk. The significant volume of SAGD-derived bitumen production could be affected. Based on SAGD production data, about 574,000 bbl/day of bitumen produced in Alberta has a SOR of more 3 m3/m3 (CanOIl, 2017).

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Canadian Crude Oil Exports to the US Canada has been the top foreign supplier of crude oil to the US since 2004, and it is likely to remain as such for the foreseeable future. According to the latest data from the US Energy Information Administration (EIA), Canada’s total exports to the US increased by 185,000 bpd in 2017; a 6 percent increase from 2016 despite no significant growth in total US crude oil imports (US EIA, 2018). Statistics Canada data shows that Canada produced 4.2 MMbpd of crude oil equivalent in 2017 and exported 3.33 MMbpd, with most of these volumes (3.3 MMbpd) being exported to the US.4 The remaining exports were destined to other countries (Figure 6.10).

Figure 6.10: Canadian Supply and Disposition of Crude Oil

Source: (Statistics Canada, 2018).

Nearly all of Canada’s crude oil exports to the US come from the western provinces of Alberta and Saskatchewan, primarily heavy crude oil producers. Newfoundland and Labrador light crude is destined for other markets. The clear majority of Canada’s crude oil reserves reside in the oil sands, so it is natural for these bituminous resources to be the primary driver of Canadian production. Conventional oil reservoirs are also dominated by resources in the Western Canadian Sedimentary Basin (WCSB) within the provinces of British Columbia, Alberta, and Saskatchewan (production out of the Northwest Territories is minimal) and offshore production in Newfoundland and Labrador. In 2017, central and eastern Canada accounted for only 0.22

MMbpd of total Canadian crude production, while western Canadian production made up 95 percent of the total, with two-thirds coming from oil sands production and the remainder from conventional production, including pentanes plus and condensate.

4 According to the NEB 2015 Canadian crude oil exports, in 2015, less than 1% of total Canadian exports end up in markets other than the US.

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Canadian refineries received almost 1.8 MMbpd in 2017 from domestic sources topped with

imports of 0.8 MMbpd. Even though Canadian crude oil production can accommodate the demand from domestic refineries, Canada still imports foreign-sourced crude. In the West, Canadian oil sands producers receive imports of condensate from the US as domestically-produced pentanes; condensates are not enough to meet the diluent demand for bitumen transportation. In central and eastern Canada, refineries can receive crude oil by rail and pipeline. In addition, Atlantic Canada has tidewater access and imports crude from several different countries.

The rise in US domestic production, driven by the horizontal hydraulic fracturing of tight oil plays in Texas and the Dakota’s has displaced some oil imports. In 2014, US production of crude oil exceeded the level of US imports for the first time in 20 years and continued to rise. This light tight oil has flooded refineries on the East and Gulf Coast. However, since the projected growth

of western Canadian crude oil supplies is predominately heavy crude oil, the US Gulf Coast and Midwest refineries – with their substantial heavy oil processing capacities – remain a key target market. Demand for Canadian heavy oil is expected to increase in the US Gulf Coast refining complex to replace shrinking volumes that come from Mexico and Venezuela. Canada represents a reliable source of crude for the US, transported straight to the refinery gate.

The US Midwest is still the largest importer of Canadian crude. In 2017, 68% of total Canadian exports to the US went to the US Midwest (PADD 25). Whereas the US Gulf Coast (PADD 3) represents a smaller but a growing market, importing almost 0.4 MMbpd of crude oil from Canada in 2017, which translates to 11 percent of Canada’s total imports, an increase of 5 percent from 2016 (US EIA, 2018). Although the Gulf Coast refineries are best suited to handle Western Canadian heavy crudes, the existing pipeline infrastructure is not sufficient to effectively access

the market. TransCanada’s Keystone XL pipeline, if successfully implemented, will address the access issue, adding another 830,000 bpd, but the project has been in development for nearly a decade. With recently secured 20-year commitments from shippers in the amount of 500,000 bpd (Vamburkar & Orland, 2018), TransCanada might move forward. It has not officially green-lighted the project and is still working toward a final investment decision (FID).

Overall, heavy sweet and sour crude exports account for 72 percent of total Canadian exports (2.5 MMbpd) (US EIA, 2018). Medium crudes make up almost 20 percent, and the remainder is split between light sweet and sour volumes. Figure 6.11 illustrates Canadian heavy crude oil exports by type and destination in 2017, as reported by the US EIA.6

5 The Petroleum Administration for Defense District (PADD) are geographic aggregations of the 50 States used as their official delineation to describe their oil market regions. There are five different PADDS: East Coast (1), Midwest (2), Gulf Coast (3), Rocky Mountain (4) and West Coast (5). 6 National Energy Board estimated Canadian crude oil exports by type and destination, 2014-2015.


July 2018

Figure 6.11: Canadian Crude Exports to the US

Source: US EIA

Table 6.2 summarizes the status of Canadian crude exports in all five US PADD regions and identifies future opportunities to expand Canadian market shares at various locations.

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July 2018

Table 6.2: Canadian Crude Exports Status by PADD Region

Canadian Crude Oil Processed

Pipeline Opportunities Other Movement Opportunities

PADD 1 199.3 Mbpd 33.6 Mbpd of heavy crude

Limited movement due to TransCanada cancelling Energy East pipeline project

Rail is the key transportation mode for future Canadian supplies. Since rail is more expensive than pipeline/tanker for other supply sources, ability to compete for market share is limited.

PADD 2 2,335 Mbpd 1,769 Mbpd of heavy crude

The largest market for Canadian crude exports. Expected increased reliance on heavy crude from Canada is anticipated if refinery upgrades proceed. Extensive pipeline network is available from western Canada.

No need for another mode of transport due to extensive pipeline network available from Western Canada.

PADD 3 383.6 Mbpd 381.5 Mbpd of heavy crude

Demand for over 2 MMbpd of heavy crude oil imports remains. Opportunity for Canada to increase market share based on declining Venezuelan supplies. Limited pipeline capacity leaving western Canada and connecting to Cushing, Oklahoma will limit how much Canadian heavy crude oil can replace Venezuelan market share.

Canadian crude oil can be transported through Cushing into the southern refineries of Louisiana and Texas, however, currently limited due to capacity limitations in pipelines delivering western Canadian oil to Cushing. Opportunity to rely on rail, however, will limit competition due to higher incurred costs.

PADD 4 273 Mbpd 227 Mbpd of heavy crude

Stable outlook for western Canadian oil to continue supplying import needs through Enbridge’s Express pipeline

No need for another mode of transport.

PADD 5 226 Mbpd 58.3 Mbpd of heavy crude

Some volumes can be provided by the Trans Mountain pipeline to Washington market.

Rely on marine shipments for half of the required refinery feedstock. Washington and California primarily represent the future need for western Canadian crude oil. Rail can provide access to the North Dakota market. Trans Mountain pipeline can also provide access for western Canadian crude oil to the West Coast of California through marine tankers from Westridge Marine Terminal in BC.

Source: US EIA; CAPP


July 2018

Canadian Export Pipeline Network Western Canada production centers are connected to domestic and US refining and export centers mainly through pipelines. In 2017, the majority of western Canadian crude oil supplies were transported to markets by pipeline, but the volumes in excess of available pipeline capacity relied on rail. Members of the Canadian Energy Pipeline Association (CEPA) reportedly transported 3.7 MMbpd of crude oil and other liquids over approximately 41,000 km of pipeline in 2017 (CEPA, 2017). Although pipelines are the preferred method of transportation, an increasing volume of crude is now transported by rail because of infrastructure constraints.

The existing export pipeline system out of western Canada is currently operating at overcapacity and producers are relying more on rail to move incremental volumes. Both the Enbridge Mainline system and Trans Mountain continue to apportion crude supply by reducing shippers’ nominated volumes to derive an aggregate amount which can be safely transported by the pipeline in

accordance with its available capacity.

Some excess capacity is crucial to be able to manage pipeline maintenance times and to provide flexibility for new market development and spot shippers. In addition, constraints in pipeline capacity and the lack of access to existing and new demand centers have deepened the discount between WTI and Western Canadian crudes and hence have had an impact on the netbacks realized by Canadian producers.

The combined nominal takeaway capacity of the major pipelines originating from Western Canada is just over 4 MMbpd. However, in 2017, about 660,000 bpd of this capacity was unavailable for transporting western Canadian crude oil due to a combination of factors including equipment being offline, constraints on downstream pipelines, and capacity being allocated for

transporting refined petroleum products for US Bakken crude oil production.

Pipeline capacity is a bottleneck for the Western Canadian crude oil production growth forecast. Three major pipeline projects remain under active development following the cancellation of TransCanada’s Energy East pipeline project in October 2017. The combined capacity from Enbridge’s Line 3 Replacement project (370,000 bpd), Kinder Morgan’s Trans Mountain Expansion (590,000 bpd), and TransCanada’s Keystone XL (830,000 bpd) would equal 1.8 MMbpd. All this capacity would be needed to transport the anticipated supply growth from western Canada.

Additionally, Enbridge has invested in the Southern Access pipeline, which started operating in 2016 and transports 300,000 bpd from Flanagan to Patoka, Illinois (Enbridge Inc., 2018). This line is a link in the transport of western Canadian crude to the US Gulf Coast.

TransCanada completed another pipeline project, within the US, known as the Gulf Coast Extension pipeline in 2014. This pipeline transports 591,000 bpd of crude from Cushing, Oklahoma to Texas refineries. It has been key in solving some of the infrastructure constraints that led to an oversupply of oil at the Cushing storage hub.


July 2018

Western Canadian production has had limited access to the US Gulf Coast market, especially

because of the lack of infrastructure connecting Cushing, Oklahoma (the primary US hub for Western Canadian crude oil) to refineries in Texas. Besides TransCanada’s efforts, Enbridge decided to reverse the direction of flow of their Seaway Pipeline (jointly owned with Enterprise Product Partners L.P.). Since 2012, Seaway has delivered Western Canadian crude oil from the Mainline system at Cushing, Oklahoma to Freeport, Texas. The original capacity of the reversed pipeline was only 150,000 bpd but was increased to 400,000 bpd through pump station modifications and additions in 2013. In 2014, capacity was expanded to 450,000 bpd.

To support Western Canadian market access to the Gulf Coast through Seaway, Enbridge also built a new line between Pontiac, Illinois and Cushing, Oklahoma (called Flanagan South) with 585,000 bpd of capacity. Enbridge shippers that contract capacity on Flanagan South can nominate Western Canadian crude volumes for delivery to the US Gulf Coast through this pipeline, which

connects to the downstream Seaway line. In total, more than 1.2 MMbpd of pipeline capacity has been installed in the US to support market access for Western Canadian crude oil to the Gulf Coast refining hub.

Canadian Rail Network Rapid growth in Western Canadian crude oil production (especially from oil sands operations) has outpaced pipeline capacity and pipeline companies’ expansion efforts. In recent years, rail transport of crude oil has surged as an alternative mode of transport to accommodate new supply volumes that exceed pipeline capacity.

Rail provides flexibility to move to different markets in response to demand, which is valuable in the current economic climate. Rail also provides flexibility in amounts of product shipped and

type of product. The coil and insulated (C&I) rail cars can transport bitumen with little or zero need for diluent. In comparison, diluted bitumen or dilbit via rail would use the same amount of diluent as dilbit in pipelines, or around 30%. Railbit will require about 17% diluent and cleanbit would require no diluent at all.

As current pipeline constraints persist, widening the differential between WCS and WTI, rail can increase its crude-by-rail rates, but both Canadian railway companies, CN and CP, demand long-term take-or-pay contracts to backstop investments in additional locomotives and train crews. The business risk for the rail companies is that these transport volumes would evaporate once new export pipelines come on stream (Healing, 2018).

Rail transport is expected to continue to increase due to the lack of pipeline capacity. The National

Energy Board states crude-by-rail exports from Canada grew to a record 193,500 bpd in April 2018, a 13% increase from the previous month, as full pipelines forced more producers to use trains to get their products to market. The oil shipping tally beat the previous record of nearly 179,000 bpd in September 2014 and was well ahead of the 150,000-bpd moved in April 2017.


July 2018

CAPP estimates current rail loading capacity is originating in western Canada at 858,400 bpd.

However, not all this capacity is used and in fact, is shared with other commodities. Table 6.3 displays the existing rail terminals with their capacity from Western Canada.

Table 6.3: Existing Rail Terminals and their Capacity from Western Canada

Source: (CAPP, 2018b)

The lack of access to locomotives, personnel and rail track is limiting shippers’ ability to move crude by rail. To increase shipped volumes, rail companies will have to make significant investments, which they are reluctant to do without long-term arrangements with crude suppliers.


July 2018

Chapter 7: Conclusion This study assesses the impact of the IMO 2020 sulphur regulation on Canadian oil production. Though the focus of analysis is the regulation’s impact on heavy oil production in Canada, the assessment is structured to draw insight from in-depth background and analysis covering global crude oil markets, PADD-level refinery modelling and linear programming of US refineries, IMO regulation non-compliance scenarios and compliance options.

In 2016, the IMO introduced a new global limit on the sulphur content in marine fuels powering ships with an effective date for the reduction of January 1, 2020. Under the new global cap, ships will have to use marine fuels with a sulphur content of no more than 0.5% (m/m) against the current limit of 3.5% to reduce emissions. However, Emission Control Areas (ECAs) will remain at

the 2015 standard of 0.1% sulphur content in North America, Europe and Baltics.

The new rule is not as stringent as that of ECAs but is tougher than the current limit and applies more broadly to ships sailing international waters. The regulation could significantly change the crude oil market landscape at regional and global levels as it requires the removal of up to 20,000 tons per day of sulphur contained in the 3-4 million barrels/day of high sulphur bunker fuel used for marine transport. The sudden changes will propagate all along the value chain, from the marine industry that will seek a replacement fuel, to refiners that produce bunker fuel, and to upstream oil producers who produce crudes that generate high sulphur residues used in bunkers, particularly heavy oil producers like Canada, Venezuela, and Mexico.

Marine bunker fuels account for about 4% of the global crude oil demand, but they are an

important outlet and revenue for the refining industry (IEA, 2018a). The marine industry absorbs unwanted residual fuel oil – a refinery product which has declining demand due to emissions control regulations (requiring cleaner-burning fuels onshore) and a decrease in residual fuel oil demand for non-bunker uses.

Sour and medium sour crudes, with sulphur content above 0.5 wt.% constitute about 64.5% of the global crude supply – a significant fraction of the total crude production. Moreover, heavy crude oil production from the America’s (Argentina, Brazil, Canada, Colombia, Ecuador, Mexico, United States and Venezuela) is a large portion of the global medium sour and sour crudes produced in 2016.

Canada (specifically, Alberta) is one of the major producers of high sulphur heavy crude oil with its production growing steadily since 2008. Bitumen production is expected to reach 3 million

bbl/day by the end of 2018 and continue afterwards. Canadian heavy sour crude is refined primarily in Canada and United States which has sufficient capacities of complex refineries to handle this type of crude. Canadian bitumen contributes hardly anything to bunkers since it is consumed by the bottom of the barrel complex refining in Canada and the US. Instead, Canadian crude will have to compete for US refining space on netback refining value with other crudes that


July 2018

currently do contribute to HSFO supply. Therefore, a refinery optimization model is used to

understand the impact of the IMO regulation.

CERI developed a linear programming model using the input-output refinery model to account for US refinery configurations and their operating costs and capital investments. This provided an analysis of crude oil blending and the associated refinery acquisition costs of crude blends and revenue generated from the sales of refinery products. The results show that optimization of refineries at a PADD-level can lead to a potential displacement of some volumes of certain crudes that have historically been processed there. Also, results show that heavy sour crudes are likely to displace mostly light sweet and medium crudes in a logistically and operationally unconstrained environment. In addition to this observation, increases in heavy sweet crudes are expected in some PADDS.

With the imposition of more realistic constraints, the magnitude of these displacements is reduced to resemble recent past crude diet receipts with optimal refinery margins. These results are driven by lower-priced crudes, yield levels of high-value products, and profitability of the process.

Our analysis overlaid the crude blends being selected by refineries with three different non-compliance scenarios of the IMO regulation. When assessed together the margin requirements of refineries and the non-compliance possibilities lead to a price outlook for different oil types and the WCS-WTI price differential.

The changes in resid and distillate prices will reduce refinery margins to a notable degree. Our analysis indicates that this is the general trend in the years after 2020 in all the non-compliance

scenarios. We found that a $16/bbl to $19/bbl drop in margins for a medium refinery in the US relative to 2017 values can be expected in 2020 for all the non-compliance scenarios (Figure 7.1). By 2025-2030, medium refineries in the US are likely to see their margins drop by $17/bbl to $28/bbl relative to 2017 margins in all the non-compliance scenarios assessed. However, for the scenarios we consider plausible, the Low NC and Moderate NC scenarios, the margins of medium refineries in the US drop by $16/bbl in 2020 and $20/bbl by 2025 and beyond.


July 2018

Figure 7.1: Refinery Margin Impacts Due to the IMO 2020 Regulation

Complex refineries are not considered to set the prices for heavy crude because they would not be impacted as significantly as the simpler refineries will, at least not in the short term. As shown in Figure 7.1, margins of complex refineries will be better off than they were in 2017 under the

Low NC scenario because of the IMO 2020 regulation. This is because the complex refineries that specialize in processing heavy crudes will enjoy increases in refinery margins from low heavy crude prices and higher than normal middle distillate prices. However, under the Moderate and High NC scenarios, the margins of complex refineries will not be spared, because compliance levels may not be high enough to drive up the prices of middle distillates and push down the prices of residual fuel oil and heavy sour crudes to significant levels.

Different levels of profitability are expected from the PADDs. PADD 4 appears to bear the greatest brunt of the IMO regulation among all the PADDs. Although some PADDs will have low margin reductions and even an increase in margins for some by 2020, we expect the highest margin reduction case from medium refineries to set the prices for heavy sour crudes and determine the light-heavy crude price differential.

Increased level of non-compliance may not push middle distillate prices as high as one would expect with an increased level of compliance. The higher the price of middle distillates, the higher the margins and this effect outweighs the penalty from diminishing resid prices. An exception to this pattern is a case where the refinery does not produce a reasonable volume of low sulphur middle distillates.


July 2018

A general trend of declining margins is expected for some years after 2020 due to a drop in the

price of middle distillates post-2020 as the market rebalances and the distillate prices drop to normal levels. However, the price of resid will not recover at a rate that can stabilize the refinery margins, and thus, cannot cushion the effect of the rebalancing middle distillates prices. This is because the effect of price movements of the middle distillates outweighs the margin-boosting effect from slowly increasing resid prices.

CERI assessed how the market share of different substitution options for high sulphur bunker fuel would evolve over time (see Figure 7.2). We note that the most likely substitution would be by low sulphur fuel oil options followed by desulphurization. The installation of scrubbers was found to be the least preferred option.

Figure 7.2: Resid Bunker Fuel Substitution Options (Moderate NC scenario)

Currently, less than 1% of the worldwide fleet is operating within the future regulatory limits for sulphur emissions for open ocean areas outside the Emission Control Areas (ECAs). Scrubbers are installed in less than 1% of ships worldwide, and analysts believe that its future adoption will be

minimal. Under the Moderate NC scenario, we estimate that scrubbers will capture only about 3% of the HSFO volume to be displaced by 2020.

Ship retrofitting and LNG bunkering are the two main obstacles to LNG development as a maritime fuel. Our projection of 1.9% to 7% of resid bunker fuel displacement volume fuel

5.0% 5.0%1.9%

5.0% 7.0%

57%

61%60%

25.0%14.0% 11.0%

14.0% 15.0%

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

2020 2025 2030

Vo

lum

e o

f H

SFO

cap

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d



July 2018

consumption falls within the range of the IMO 3rd GHG study’s projection of 2-10% of the total

marine fuel share.

The majority of the existing methanol supply infrastructure is as feedstock to the chemical industry. As the supply chain extends further into the shipping fuel market, more methanol might need to come from sources other than natural gas to improve environmental performance. These considerations lead us to conclude that methanol’s use as a substitute for resid bunker fuel is limited, at least in the short run.

Market share percentages are translated into volume demand in Figure 7.3.

Figure 7.3: Resid Bunker Fuel Substitution Volumes (Moderate NC Scenario)

Increasing refinery utilization capacities is part of the solution to the bunker fuel availability problem but adds to the problem of resid glut because more resid will be produced as refiner’s process more crude. World refineries can produce about 1.3 million bbl/day of distillates together with 1.2 million bbl/day heavy fuel oil and other bottoms through a 5 percent increase in

capacities if we assume that global refineries are predominantly medium conversion. On the other hand, a 10 percent increase in the global refinery capacities will result in 2.6 million bbl/day of distillates together with 2.3 million bbl/day heavy fuel oil and other bottoms. In each case, large amounts of distillates that can bridge the gap of cleaner bunker fuel demand can be produced. Equally large amounts of heavy fuel oil are produced alongside the production of distillates. This will likely keep high sulphur fuel oil prices low. Additionally, the world is reaching

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

2020 2025 2030

Vo

lum

e o

f H

SFO

cap

ture

d (

bb

l/d

ay)

Scrubbers Methanol LNG Low Sulfur Distillates

Non Compliance Desulphuration Blended HSFO


July 2018

peak gasoline demand and would not need the additional naphtha generated by the added crude

processing.

The reason why refiners are not making costly refining modifications now may be because the price volatility that will be created from the IMO rule implementation is not expected to last long enough to make such investments viable. The markets are expected to rebalance in a couple of years, and this discourages significant capital investments in complex refining units, which has a payback period of at least two decades. Also, there seems to be enough room to process more crudes to meet the expected increases in demand for distillates for marine fuel use.

Once the rules take effect, the shipping industry will need to switch to either marine gasoil, marine diesel, low sulphur residual fuel oil or a blend of high sulphur and ultra-low sulphur fuel. We assessed two blending options and identified that blending of HSFO and LS-MGO (Blend II) is

likely to be preferred because it is cheaper and has better fuel properties than the Blend II option which blends HSFO with ULSD (Figure 7.4).

Figure 7.4: Prices of Conventional Marine Oils and the Blend Options

By 2020 the prices of LS-MGO and ULSD are expected to skyrocket and consequently create a greater spread between low and high sulphur bunker fuels. Therefore, the price movements by 2020 may motivate more use of blending, especially for the Blend II option.

It is important to note that in choosing marine fuel blends, for shippers, fuel oil is preferred over

gasoil. Many marine engines are optimized to operate on HSFO. The use of marine gas oil or any of the blends presented in Figure 7.4 often leads to several adverse effects on fuel and engine systems. Switching to these fuels in traditional marine engines carries significant operational risks of low viscosity, lubricity, acidity and flash point. Some analysts believe that some of these issues can be resolved by adapting the engines to burn these fuels, the cost of which is not significant.

0

20

40

60

80

100

120

2017 2020 2025 2030

Mar

ine

Fue

l Pric

e ($

/bbl

)

MGO ULSD Heavy Bunker Blend I Blend II


July 2018

A key finding of this analysis is how the IMO regulation will affect the Canadian oil sector. Western

Canadian oil is priced at a discount to WTI. That discount has a significant impact on the viability of oil sector investments in western Canada. The cumulative discount on WCS with respect to WTI will expand dramatically due to the IMO regulation.

Figure 7.5 illustrates how the refinery margin loss affects the WCS (heavy sour) pricing relative to WTI (light sweet). The dotted lines represent the WCS pricing that is historically discounted at $13/bbl plus the discounts resulting from the IMO regulation for the three scenarios considering a medium refinery in the US.

Figure 7.5: WCS-WTI Price Differential Impact Due to the IMO Regulation (2017 US$)

Source: CERI

Given the low possibility of the High NC scenario, its effects on WCS are not emphasized. The plausible cases are the Moderate and Low NC scenarios where the effects fall within a reasonable band. Under the plausible scenarios, a refinery margin loss of $16/bbl to $20/bbl between 2020 and post-2025 may be directly transferred to a light-heavy differential. The cumulative discount sums up to $31/bbl-$33/bbl. This expanded discount could portend high risks of shutting down production for some oil sands producers; however, it could be offset by continued upward price movements of WCS and WTI pricing. On the other hand, if global oil prices remain static or decline, such a higher-than-usual WTI-WCS price differential shall pose a business challenge to western Canada’s oil sector. The viability of different SAGD projects could be challenged (Figure 7.6) for a new project with steam-to-oil ratios of more than 3 m3/m3 and for an expansion project

with steam-to-oil ratios of more than 4 m3/m3 (Figure 7.7).

20

30

40

50

60

70

80

90

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Cru

de p

rices

($/

bbl)

WTI WCS w/o IMO WCS Low NC WCS Moderate NC WCS High NC


July 2018

Figure 7.6: New SAGD Project Viability by 2020

It can be deduced that new SAGD projects with SORs of less than 3 m3/m3 are likely to break when the IMO regulation is introduced. New projects with SORs greater than 3 m3/m3 will operate in losses. A significant volume of SAGD-derived bitumen production could be affected. Based on SAGD production data, about 574,000 bbl/day of bitumen produced in Alberta has a SOR of more 3 m3/m3 (CanOIl, 2017).

The expanded SAGD projects will perform profitably for a wider range of SORs (Figure 7.7).

Figure 7.7: Expanded SAGD Project Viability by 2020

Based on the supply costs and profitability analysis, under the most probable scenarios, bitumen volumes produced from expanded projects may not be affected significantly, but bitumen volumes produced from new standalone projects with a SOR greater than 3 m3/m3 are at risk.

If no foreign crude suppliers compete in North America, there may be no significant loss of current volumes of Canadian heavy sour crude exported to refineries in the US. However, the glut of resid,

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July 2018

and consequently, its price decrease is a major challenge that will lead to the refinery margin

losses and the light-heavy differentials that we observe. The refinery margin losses will likely translate into the market prices of those heavy crudes that yield relatively high amounts of resid, with an accompanying reduction in the global price of all high sulphur crudes. This reduced netback for the Eastern Hemisphere supply of high sulphur crudes will increase the competition faced by Canadian suppliers and could potentially reduce the volume of Canadian crude processed in the US.


July 2018


July 2018

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July 2018

Appendix CERI Input-Output Refinery Model A generic Input-Output model which uses a linear multivariate regression method is developed to capture:

• Inputs and output of the US refineries by PADD as illustrated in Figure A.1

• The various types of refinery configurations currently operating in the United States

• Nominal and available refining capacities within each PADD

• Differences in crude blend flows and product slates at each PADD

• PADD-level sulphur handling capacities

Figure A.1: Generic Refinery Input-Output Regression Model

The model is developed and implemented in the R programming language. The model predicts product slates using as the predictors the crude blend flows at different types of refineries in each US PADD district. The modelling equation can be summarized mathematically as:

[𝑦1

1, 𝑦12, ⋯ 𝑦1

𝑛

⋮ ⋱ ⋮𝑦𝑝

1, 𝑦𝑝2 ⋯ 𝑦𝑝

𝑛] = [

𝛽11, 𝛽2

1, ⋯ 𝛽𝑚1

⋮ ⋱ ⋮𝛽1

𝑝, 𝛽2𝑝 ⋯ 𝛽𝑚

𝑝] [

𝑥11, 𝑥1

2, ⋯ 𝑥1𝑛

⋮ ⋱ ⋮𝑥𝑚

1 , 𝑥𝑚2 ⋯ 𝑥𝑚

𝑛] (Eqn. 1)

From the above expression, the parameters m and p are the numbers of predictors and response variables, respectively. Parameter n defines the size of the dataset used, whereas y and x are the refinery products and crude oil blends, respectively. The modelling parameters, 𝛽, are obtained

by performing the multivariate regression in R programming platform.


July 2018

LP Model Equations 𝐹𝑜𝑟 𝑐𝑟𝑢𝑑𝑒 𝑜𝑖𝑙 𝑏𝑙𝑒𝑛𝑑 (𝑖), 𝑟𝑒𝑓𝑖𝑛𝑒𝑑 𝑝𝑟𝑜𝑑𝑢𝑐𝑡 𝑡𝑦𝑝𝑒 (𝑗)𝑎𝑛𝑑 𝑟𝑒𝑓𝑖𝑛𝑒𝑟𝑦 𝑐𝑜𝑛𝑓𝑖𝑔𝑢𝑟𝑎𝑡𝑖𝑜𝑛 (𝑘); 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝑑𝑢𝑟𝑖𝑛𝑔 𝑡𝑖𝑚𝑒 (𝑡): 𝑚𝑎𝑥𝑖𝑚𝑖𝑧𝑒 𝑅𝑒𝑓𝑖𝑛𝑒𝑟𝑦𝑀𝑎𝑟𝑔𝑖𝑛 = ∑ ∑ ∑ 𝑝𝑝𝑡,𝑗 × 𝑃𝑟𝑜𝑑_𝑉𝑜𝑙𝑡,𝑗,𝑘𝑘𝑗𝑡 − ∑ ∑ ∑ 𝑝𝑐𝑡,𝑖 ×𝑘𝑖𝑡

𝐹𝑒𝑒𝑑_𝑉𝑜𝑙𝑡,𝑖,𝑘 − ∑ ∑ ∑ 𝑝𝑟𝑜𝑐𝑒𝑠𝑛𝑔_𝑐𝑜𝑠𝑡𝑘 × 𝐹𝑒𝑒𝑑_𝑉𝑜𝑙𝑡,𝑖,𝑘𝑘𝑖𝑡 𝑠𝑢𝑏𝑗𝑒𝑐𝑡 𝑡𝑜: 𝑅𝑒𝑓𝑖𝑛𝑒𝑟𝑦 𝑀𝑜𝑑𝑒𝑙 𝐸𝑞𝑢𝑎𝑡𝑖𝑜𝑛𝑠: [𝐏𝐫𝐨𝐝_𝐕𝐨𝐥𝑚𝑎𝑡𝑟𝑖𝑥] = [𝐂𝐨𝐞𝐟𝐟𝐢𝐜𝐢𝐞𝐧𝐭𝐬𝑚𝑎𝑡𝑟𝑖𝑥][𝐅𝐞𝐞𝐝_𝐕𝐨𝐥𝑚𝑎𝑡𝑟𝑖𝑥]

∑ 𝐹𝑒𝑒𝑑_𝑉𝑜𝑙𝑡,𝑖,𝑘

𝑖

≤ 𝑐𝑓𝑘 × 𝑅𝑒𝑓𝑖𝑛𝑒𝑟𝑦𝐶𝑎𝑝𝐿𝑖𝑚𝑖𝑡𝑘 ∀𝑘, 𝑡

∑ 𝐹𝑒𝑒𝑑_𝑉𝑜𝑙𝑡,𝑖,𝑘

𝑘

≤ 𝑚𝑎𝑥𝐹𝑒𝑒𝑑𝑖 × ∑ 𝑐𝑓𝑘 × 𝑅𝑒𝑓𝑖𝑛𝑒𝑟𝑦𝐶𝑎𝑝𝐿𝑖𝑚𝑖𝑡𝑘

𝑘

∀𝑖, 𝑡

∑ 𝐹𝑒𝑒𝑑𝑉𝑜𝑙𝑡,𝑖,𝑘

𝑘

≥ 𝑚𝑖𝑛𝐹𝑒𝑒𝑑𝑖 × ∑ 𝑐𝑓𝑘 × 𝑅𝑒𝑓𝑖𝑛𝑒𝑟𝑦𝐶𝑎𝑝𝐿𝑖𝑚𝑖𝑡𝑘

𝑘

∀𝑖, 𝑡

∑ 𝑃𝑟𝑜𝑑_𝑉𝑜𝑙𝑡,𝑗,𝑘

𝑘

≤ 𝑚𝑎𝑥𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑗 × ∑ 𝑃𝑟𝑜𝑑𝑐𝑢𝑡𝐿𝑖𝑚𝑖𝑡𝑘,𝑗

𝑘

∀𝑗, 𝑡

∑ 𝑃𝑟𝑜𝑑_𝑉𝑜𝑙𝑡,𝑗,𝑘

𝑘

≥ 𝑚𝑖𝑛𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑗 × ∑ 𝑃𝑟𝑜𝑑𝑐𝑢𝑡𝐿𝑖𝑚𝑖𝑡𝑘,𝑗

𝑘

∀𝑗, 𝑡

∑ 𝑆𝑢𝑙𝑓𝑢𝑟𝑖,𝑘,𝑡

𝑖

= ∑ 𝑆𝑢𝑙𝑓𝑢𝑟𝑗,𝑘,𝑡

𝑗

+ 𝑆𝑢𝑙𝑓𝑢𝑟_𝐿𝑜𝑎𝑑𝑘,𝑡 ∀𝑘, 𝑡

∑ 𝑆𝑢𝑙𝑓𝑢𝑟_𝐿𝑜𝑎𝑑𝑘,𝑡

𝑘

≤ 𝑆𝑢𝑙𝑓𝑢𝑟𝐵𝑎𝑙𝑎𝑛𝑐𝑒𝑡 ∀ 𝑡


July 2018

Refinery Optimization Model

Figure A.2: LP Optimization Model

Table A:1: US Refinery Capacities and Configurations

Thermal Processes Catalytic Cracking

Catalytic Hydrocrackin

g Catalytic

Hydrotreating

US Region Crude Vacuum

Coking and visbreaking

Fresh & recycled feed

Distillate, Gasoil &

resid

Distillate, Gasoil & resid desulphurizati

on

PADD1 1,213,800 526,680 73,350 453,150 40,770 409,140

PADD2 4,004,040 1,723,470 529,020 1,216,620 318,980 1,674,610 PADD3 9,621,767 4,509,333 1,468,150 2,820,015 1,204,600 3,840,653 PADD4 683,245 241,005 81,290 203,539 54,720 304,623 PADD5 2,934,785 1,521,150 548,580 815,580 536,570 1,097,250

Source: Oil and Gas Journal (2017), CERI

Objectives:

The analysis below will be conducted at PADD levels and for each refinery configuration

1. Find the makeup of a crude blend that minimizes the sulphur content in the Liquid Heavy Ends (Bunker) and Fuel Oil (Heating oil) but maximizes refinery margins

2. Find the makeup of a crude blend that minimizes the produced volumes of Liquid Heavy Ends (Bunker) and Fuel Oil (Heating oil) but maximizes refinery margins

3. For types of refineries offer superior economics 4. Estimate the economic impacts of increasing capacity factors of the refineries to maximize

ULSD yields

Documents

Study No. 175 July 2018 - CERI › assets › files › Study_175_Full_Report.pdf · CANADIAN ENERGY RESEARCH INSTITUTE AN ECONOMIC ASSESSMENT OF THE INTERNATIONAL MARITIME ORGANIZATION