Study No. 167 January 2018

CANADIAN AN ECONOMIC AND ENVIRONMENTAL ENERGY ASSESSMENT OF EASTERN CANADIAN RESEARCH INSTITUTE CRUDE OIL IMPORTS

Canadian Energy Research Institute | Relevant • Independent • Objective

AN ECONOMIC AND ENVIRONMENTAL ASSESSMENT OF EASTERN CANADIAN CRUDE OIL IMPORTS

ii Canadian Energy Research Institute

An Economic and Environmental Assessment of Eastern Canadian Crude Oil Imports

Authors: Paul Kralovic Andrei Romaniuk Anna Vypovska Dinara Millington

ISBN 1-927037-52-2

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

January 2018 Printed in Canada

Front photo’s courtesy of various Google searches

Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to the Canadian Fuels Association and ClipperData; as well as all CERI staff involved in the production and editing of the material, including but not limited to Allan Fogwill and Megan Murphy.

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

January 2018 An Economic and Environmental Assessment of iii Eastern Canadian Crude Oil Imports Table of Contents LIST OF FIGURES ...... v LIST OF TABLES ...... vii ACRONYMS AND ABBREVIATIONS ...... ix EXECUTIVE SUMMARY ...... xiii CHAPTER 1 INTRODUCTION ...... 1 CHAPTER 2 BACKGROUND INFORMATION ...... 3 Crude Oil Supply and Disposition ...... 3 Refineries: Background and Trends ...... 6 The Refinery Process ...... 6 Eastern Canadian Refineries within a North American and Global Context ...... 13 Crude Oil Transportation – Pipeline, Rail and Tanker/Barge ...... 21 Pipeline...... 22 Crude-by-Rail...... 26 Oil Tankers and Marine Terminals ...... 29 CHAPTER 3 METHODOLOGY AND ANALYSIS ...... 33 Overview of Methodology and Description of Scenarios ...... 33 Models and Their Approaches ...... 39 Crude Flows Model ...... 39 Costs of Feedstock Model ...... 52 Emissions/LCA Model...... 61 CHAPTER 4 MODELLING RESULTS ...... 83 Made in Canada Scenario ...... 83 Crude Flows ...... 83 Cost of Feedstock ...... 87 Emissions ...... 88 Expanded Access Scenario ...... 91 Crude Flows ...... 91 Cost of Feedstock ...... 95 Emissions ...... 96 Current Reality Scenario ...... 99 Crude Flows ...... 99 Cost of Feedstock ...... 104 Emissions ...... 105 International Social Concerns Scenario...... 107 Crude Flows ...... 108 Cost of Feedstock ...... 111 Emissions ...... 113

January 2018 iv Canadian Energy Research Institute

CHAPTER 5 CONCLUSIONS AND IMPORTANT FUTURE DYNAMICS ...... 115 Conclusions by Scenario...... 115 Made in Canada ...... 116 Expanded Access ...... 118 Current Reality ...... 118 International Social Concerns ...... 119 Conclusions by Province ...... 120 Inter-scenario Comparisons ...... 122 Expanded Access vs. Current Reality ...... 123 Expanded Access vs. Made in Canada ...... 123 Important Future Dynamics ...... 124 Crude Oil Price Dynamics ...... 124 Availability of Crude Oil ...... 126 Final Remarks ...... 128 BIBLIOGRAPHY ...... 131 APPENDIX A FACTUAL AND USED 2016 IMPORT VOLUMES ...... 143 APPENDIX B DETAILED CRUDE FLOWS AND TRANSPORTATION PATH OF THE BASE CASE ...... 145 APPENDIX C INVENTORY OF CANADIAN AND FOREIGN CRUDE OILS USED IN THE STUDY AND RESULTS OF UPSTREAM AND MIDSTREAM GHG EMISSIONS MODELLING ...... 147 APPENDIX D TANKER TRANSPORTATION COSTS BY ORIGIN AND DESTINATION...... 157 APPENDIX E DETAILED SUBSTITUTION OF CRUDE OIL BY SCENARIO ...... 159 APPENDIX F DETAILED EMISSIONS BY SCENARIO ...... 167 APPENDIX G COST OF FEEDSTOCK VS. GHG EMISSIONS BY PROVINCE ...... 171 APPENDIX H SELECTED FOREIGN CRUDE OIL BRANDS IMPORT VOLUMES AND PRICE COMPARISON WITH SELECTED CANADIAN CRUDES ...... 177

January 2018 An Economic and Environmental Assessment of v Eastern Canadian Crude Oil Imports List of Figures

2.1 Canadian Crude Oil Production by Province, Conventional + Oil Sands ...... 4 2.2 US Imports from Canada by Crude Type ...... 5 2.3 Eastern Canadian Crude Oil Imports by Country, 2016 ...... 6 2.4 Breakdown of an Average Barrel of Canadian Refined Petroleum Products ...... 7 2.5 Distribution of Selected Canadian and Imported Crude Oils by API Gravity and Sulfur Content ...... 8 2.6 Refining Flow Scheme ...... 9 2.7 A Topping/Hydroskimming Refinery ...... 11 2.8 A Catalytic Cracking Refinery ...... 12 2.9 A Coking Refinery ...... 13 2.10 Canada’s Refining Sector, 2016 ...... 14 2.11 Supply and Disposition of Refined Petroleum Products in Canada ...... 15 2.12 Canadian Refining Capacity and Number of Refineries, 1948-2016 ...... 18 2.13 Crude Distillation Capacity Additions by Region, 2016-2040 ...... 20 2.14 Eastern Canadian Crude Oil Transportation Infrastructure ...... 22 2.15 Enbridge’s Mainline System Configuration ...... 24 2.16 Enbridge’s Line 9 System Configuration ...... 25 2.17 Canadian Railway Network for Crude Oil Transportation ...... 27 2.18 Quarterly Volumes of Crude Oil Exported by Rail to the US ...... 29 3.1 The Four Scenarios ...... 34 3.2 Schematic of the Modelling Approaches ...... 38 3.3 Crude Intake by Type by Province ...... 41 3.4 Canadian Oil Supply Routes to Central and Eastern Refineries – Base Case ...... 45 3.5 Availability and Usage of Crude and Infrastructure by Eastern Canadian Refineries – Base Case ...... 46 3.6 Canadian Crude Oil Production Forecast, 2017-2027 ...... 47 3.7 Available Western Canadian Crude for Central and Eastern Refineries and Demand by Central and Eastern Refineries by Crude Type ...... 50 3.8 Selected Foreign Crude Oil Brands Import Volumes and Prices ...... 56 3.9 Upstream and Midstream GHG Emissions for Selected Canadian and Foreign Crude Oils Used in the Study ...... 68 3.10 GHG Emissions Ranges for Crude Oils Used in the Study ...... 70 3.11 Upstream and Midstream GHG Emissions for Canadian Proxy and Modelled Crude Flows ...... 71 3.12 Total Upstream GHG Emissions for Canadian and Foreign Crude Oils Used for the Study ...... 73 3.13 Upstream GHG Emissions for Canadian and Foreign Crude Oils Used for the Study Split by Main Emissions Drivers ...... 73 3.14 Midstream GHG Emissions Results for Canadian and Foreign Crude Oils Used for the Study ...... 74

January 2018 vi Canadian Energy Research Institute

3.15 Transportation GHG Emissions for Canadian and Foreign Crude Oils Used in the Base Case, Refineries Located in ON ...... 77 3.16 Transportation GHG Emissions for Canadian and Foreign Crude Oils Used in the Base Case, Refineries Located in QC, NB and NL ...... 78 4.1 Total Crude Intake for Central and Eastern Refineries – Made in Canada ...... 84 4.2 Canadian Crude Supply to Central and Eastern Refineries – Made in Canada ...... 85 4.3 Availability and Usage of Crude and Infrastructure – Made in Canada ...... 86 4.4 Made in Canada and Base Case Emissions ...... 89 4.5 Change in Emissions Intensity – Made in Canada ...... 90 4.6 Total Crude Intake for Central and Eastern Refineries – Expanded Access ...... 92 4.7 Canadian Supply to Central and Eastern Refineries – Expanded Access ...... 93 4.8 Availability and Usage of Crude and Infrastructure – Expanded Access ...... 94 4.9 Expanded Access and Base Case Emissions ...... 97 4.10 Change in Emissions Intensity – Expanded Access ...... 98 4.11 Total Crude Intake for Central and Eastern Refineries – Current Reality ...... 100 4.12 Canadian Supply to Central and Eastern Refineries – Current Reality ...... 102 4.13 Availability and Usage of Crude and Infrastructure – Current Reality...... 103 4.14 Current Reality and Base Case Emissions ...... 106 4.15 Change in Emissions Intensity – Current Reality ...... 107 4.16 Total Crude Intake for Central and Eastern Refineries – International Social Concerns ...... 109 4.17 Canadian Supply to Central and Eastern Refineries – International Social Concerns . 110 4.18 Availability and Usage of Crude and Infrastructure – International Social Concerns .. 111 4.19 International Social Concerns and Base Case Emissions ...... 113 4.20 Change in Emissions Intensity – International Social Concerns ...... 114 5.1 Future Availability of Canadian Crude ...... 127 G.1 Ontario – Cost of Feedstock vs. GHG Emissions ...... 171 G.2 Quebec – Cost of Feedstock vs. GHG Emissions ...... 172 G.3 Quebec – Cost of Feedstock vs. GHG Emissions (zoomed in portion of G.2) ...... 173 G.4 New Brunswick – Cost of Feedstock vs. GHG Emissions...... 174 G.5 Newfoundland & Labrador – Cost of Feedstock vs. GHG Emissions ...... 175 H.1 Selected Foreign Crude Oil Brands Import Volumes and Prices ...... 179 H.2 Selected Foreign Crude Oil Brands Import Volumes and Full-cycle Delivered Average Prices ...... 179

January 2018 An Economic and Environmental Assessment of vii Eastern Canadian Crude Oil Imports List of Tables

E.1 Key Conclusions under the Four Scenarios ...... xiv 2.1 Eastern Canadian Refinery Capacity and Crude Oil Intake ...... 16 2.2 Canada’s Refining Sector Configurations, 2016 ...... 17 2.3 Crude-by-Rail Offloading Terminals in Eastern Canada ...... 28 2.4 Oil Tanker Size ...... 30 2.5 Oil Marine Terminals in Canada ...... 31 3.1 Crude Intake by Eastern Canadian Refineries, by Oil Type ...... 40 3.2 Crude Intake by Eastern Canadian Refineries, by Source ...... 42 3.3 Oil Type Shares as Input to Western Canadian Refineries ...... 48 3.4 Crude Oil Demand by Western Canadian Refineries ...... 49 3.5 Available Oil Stock for Central and Eastern Refineries, 2017-2027 ...... 49 3.6 Crude Oil Brands Used in the Study and Their Prices ...... 54 3.7 Pipeline Tolls for Crude Oil...... 57 3.8 Price of Crude Oil Brands at Refinery Gate of Eastern Canadian Refineries ...... 60 3.9 Transportation GHG Emissions for Canadian and Foreign Crude Oils Used in the Base Case and the Four Modelled Scenarios ...... 79 4.1 Cost of Feedstock – Made in Canada ...... 87 4.2 Cost of Feedstock – Expanded Access ...... 95 4.3 Cost of Feedstock – Current Reality ...... 104 4.4 Cost of Feedstock – International Social Concerns ...... 112 5.1 Key Conclusions under the Four Scenarios ...... 115 5.2 Merchandise Trade Levels between Canada and the Nations’ Canada Imports Foreign Oil – Made in Canada ...... 117 5.3 Merchandise Trade Levels between Canada and the Nations’ Canada Imports Foreign Oil – International Social Concerns ...... 120 5.4 Comparison of Availability of Light Oil with Demand by the Central and Eastern Refineries, by Scenario ...... 128 C.1 Inventory of Canadian and Foreign Crude Oils Used in the Study for Crude Flows and GHG Emissions Modelling ...... 147 C.2 Results of Upstream and Midstream GHG Emissions Modelling for Canadian and Foreign Crude Oils Used in the Study ...... 151 E.1 Substitution of Oil in the Made in Canada Scenario ...... 159 E.2 Substitution of Oil in the Expanded Access Scenario ...... 161 E.3 Substitution of Oil in the Current Reality Scenario ...... 163 E.4 Substitution of Oil in the International Social Concerns Scenario ...... 165 F.1 Emissions in the Made in Canada Scenario ...... 167 F.2 Emissions in the Expanded Access Scenario ...... 168 F.3 Emissions in the Current Reality Scenario ...... 169 F.4 Emissions in the International Social Concerns Scenario ...... 170

January 2018 viii Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of ix Eastern Canadian Crude Oil Imports Acronyms and Abbreviations

AB Alberta AFRA Average Freight Rate Assessment API American Petroleum Institute API Gravity Measure (in degrees) of an oil’s gravity or weight ATL Atlantic Canada bbl Barrel bpd Barrels per day BC British Columbia CA California CARB California Air Resources Board CAPP Canadian Association of Petroleum Producers CBA Cost-Benefit Analysis CBOB Conventional Blendstock for Oxygenate Blending (gasoline production) CHOPS Cold Heavy Oil Production with Sand CEPA Canadian Energy Pipeline Association CERI Canadian Energy Research Institute CFA Canadian Fuels Association CN Canadian National (railway) CNRL Canadian Natural Resources Limited CO2 Carbon Dioxide CO2 eq Carbon Dioxide Equivalent (including all GHGs) COLC Crude Oil Logistics Committee (Canada) CP Canadian Pacific (railway) dilbit Diluted Bitumen DWT Deadweight Tonnage EIA Energy Information Administration (US) EPA Environment Protection Agency (US) FCC Fluid Catalytic Cracking FERC Federal Energy Regulatory Commission (US) GDP Gross Domestic Product GHGs Greenhouse Gases GO-HC Gas Oil-Hydrocracker GREET The Greenhouse gases, Regulated Emissions, and Energy use in Transportation Model HS High Sulfur ICE InterContinental Exchange IEA International Energy Agency KOH Potassium hydroxide LA Louisiana LCA Life-Cycle Assessment LLS Louisiana Light Sweet

January 2018 x Canadian Energy Research Institute

LPG Liquefied Petroleum Gas LR Large Range (tanker) LS Low Sulfur m3 Cubic meter MB Manitoba Mbpd Thousand barrels per day MMbpd Million barrels per day MCR Micro-Carbon Residue MI Michigan MMBtu million British thermal units MJ Megajoule MR Medium Range (tanker) Mt Million tonnes MTCO2eq Million tonnes of carbon dioxide equivalent NB New Brunswick ND North Dakota n.d. Not dated NEB National Energy Board NL Newfoundland & Labrador NRCan Natural Resources Canada NS Nova Scotia NYMEX New York Mercantile Exchange ON Ontario OPEC Organization of the Petroleum Exporting Countries OPEM Oil Products Emissions Module OPGEE Oil Production Greenhouse Gas Emissions Estimator PADD United States Petroleum Administration for Defense District ppmw parts per million weight PRELIM Petroleum Refinery Life-cycle Inventory Model ptb Pounds per thousand barrel (salt content) QC Québec RBOB Reformulated Blendstock for Oxygenate Blending (gasoline production) RFG Reformulated Gasoline RPP Refined Petroleum Product SCO Synthetic Crude Oil SHP Selective Hydrogenation Process SK Saskatchewan TAN Total Acid Number TCPL TransCanada Pipelines Limited tonne Metric ton TX Texas UK United Kingdom ULCC Ultra Large Crude Carrier US United States

January 2018 An Economic and Environmental Assessment of xi Eastern Canadian Crude Oil Imports

VFF Venting, Flaring or Fugitive (emissions) VLCC Very Large Crude Carrier WCB Western Canadian Blend WCS Western Canadian Select wt% Percentage on weight basis WTI Western Texas Intermediate

January 2018 xii Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of xiii Eastern Canadian Crude Oil Imports Executive Summary

Canada is the fifth largest oil producer in the world, accounting for 4.8 percent of world production in 2016, ranking behind the US (13.4 percent), Saudi Arabia (13.4 percent), Russia (12.2 percent) and Iran (5.0 percent) (BP 2017). Canada’s proved reserves, totaling 171.5 billion barrels or 10 percent of the world’s share of proved reserves, are behind Venezuela (300.9 billion barrels) and Saudi Arabia (266.6 billion barrels) (BP 2017).

Yet, despite this, Canada still imports oil. Eastern Canadian crude oil imports rose slightly in 2016, reaching 607 thousand barrels per day (Mbpd), with the majority of imports from the US (259 Mbpd), followed by Saudi Arabia (87 Mbpd) and Algeria (85 Mbpd) (Government of Canada 2017; NEB 2017f; Statistics Canada 2017a).

The nature of the imports, however, is different between western and eastern Canada. Western Canadian crude oil imports are entirely from the US and are attributed to diluent or condensate, product used to dilute oil sands bitumen to facilitate transportation by pipeline. Eastern Canadian provinces, on the other hand, use domestic oil (either from western Canada or offshore Newfoundland & Labrador (NL)) and imported oil from various parts of the world for feedstock into eight refineries (four in Ontario (ON), 2 in Quebec (QC) and single refineries in New Brunswick (NB) and NL & Labrador) to process oil into gasoline, diesel, heating oil, propane, asphalt, and petrochemical feedstock.

The scope of this study is to analyze the potential complete or partial substitution of eastern Canadian crude oil imports via domestically-sourced oil. The research provides a cost and emissions comparison based on four potential scenarios of substituting domestic vs. foreign crude oil in the central and eastern Canadian refinery market.

The four scenarios include:

• Made in Canada – in this scenario we consider complete substitution of Canadian crude oil for imported oil regardless of the cost. This scenario allows for expanded pipeline infrastructure in Eastern Canada.

• Expanded Access – in this scenario we allow for the economic substitution of less expensive Canadian crude for imported oil. Again, a new oil pipeline is assumed in this scenario.

• Current Reality – in this scenario we use the existing infrastructure but maximize the selection of Canadian crude from an economic perspective. The Base Case which now exists, has a portion of Canadian crude being used in central and eastern Canadian refineries but not the full amount that would be selected if only price was used to make the selection.

January 2018 xiv Canadian Energy Research Institute

• International Social Concerns – is a scenario that substitutes Canadian crude for imported oil from countries where international organizations have identified some social concerns. CERI uses the Economist’s Democracy Index as a proxy for the range of social concerns (e.g., living standards, food security, human rights, environmental protection, health outcomes, etc.).

Table E.1: Key Conclusions under the Four Scenarios

Expanded Infrastructure Existing Infrastructure Category International Made in Expanded Current Social Canada Access Reality Concerns Additional western 424 248 120 123 Canadian supply (Mbpd) Additional eastern

177 96 160 177 Canadian supply (Mbpd)

Flows Total additional Canadian 601 344 280 300 crude (Mbpd)

Substituted foreign oil (%) 100% 57% 47% 50%

Annual Cost of feedstock -23 -317 -210 +79

Costs ($ million)

Emissions (million tones -2.2 -2.0 -2.0 -2.8 CO2eq per year)

Change of emissions (%) -6.2% -5.7% -5.7% -7.9% Emissions Emissions

This study provides a comprehensive look at the substitution impact on refinery costs and emissions for refineries in ON, QC, NB and NL. Refineries in these provinces only process lighter crudes and are not able to process some of the heavier crude oils from Western Canada. As such, the substitution is on a like-for-like basis. The crude oil quality being imported is substituted with the same quality of crude from other parts of Canada.

In all the scenarios, the substitution of Canadian crude oil for imported oil reduces overall global CO2 emissions compared to a business as usual (Base Case) option. Emissions are reduced by 2 MTCO2eq per year to 2.8 MTCO2eq per year. In some cases, Canadian emissions increase, but overall emissions which are linked to climate change decrease.

Cost savings range from $23 million in the Made In Canada scenario to $317 million in the Expanded Access scenario. Both scenarios call for a new oil pipeline. In the case of Expanded Access, only those Canadian crude oil supplies cheaper than their imported counterparts are consumed in central and central and eastern refineries.

January 2018 An Economic and Environmental Assessment of xv Eastern Canadian Crude Oil Imports

One scenario results in higher costs for QC and NB refineries. This is the substitution of oil from countries where international organizations have noted some social concerns. In this case, the cost of this policy would be approximately $79 million in additional crude oil costs.

January 2018 xvi Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 1 Eastern Canadian Crude Oil Imports Chapter 1: Introduction

Canada is the fifth largest oil producer in the world, accounting for 4.8 percent of world production in 2016, ranking behind the US (13.4 percent), Saudi Arabia (13.4 percent), Russia (12.2 percent) and Iran (5.0 percent) (BP 2017). Canada’s proved reserves, totaling 171.5 billion barrels or 10 percent of the world’s share of proved reserves, are behind Venezuela (300.9 billion barrels) and Saudi Arabia (266.6 billion barrels) (BP 2017).

Yet, despite this, Canada still imports oil.

Canadian crude oil imports were 759 thousand barrels per day (Mbpd) in 2016 with the majority coming into the Eastern part of the country. ON, QC, NB, and NL imported 607 Mbpd combined, with most of imports from the US (259 Mbpd), followed by Saudi Arabia (87 Mbpd) and Algeria (85 Mbpd). Other imports in 2016 over 10 Mbpd include Nigeria (74 Mbpd), Norway (42 Mbpd), Kazakhstan (19 Mbpd), and the Ivory Coast (13 Mbpd) (Government of Canada 2017; National Energy Board [NEB] 2017f; Statistics Canada 2017a).

The nature of the imports, however, is different between western and eastern Canada. Western Canadian crude oil imports are all from the US and are attributed to imports of diluent or condensate, which is used to dilute oil sands bitumen to facilitate transportation by pipeline. Eastern Canadian provinces, on the other hand, use domestic oil (either from western Canada or offshore NL) and imported oil from various parts of the world for feedstock in local refineries.

The theoretical objective of an oil refiner is simple – to minimize operating expenses and maximize margins. In practice, however, the economics of a refinery is dictated by a complex set of intertwined factors, at the heart of which are three variables: crude oil type used (crude slate), refinery size and configuration and final product range (product slate) (Natural Resources Canada [NRCan] 2016). Other important variables include a refinery’s operational efficiency, or utilization rate, as well as regulatory requirements, often reflecting environmental considerations (NRCan 2016).

These factors, as well as their proximity to crude oil producing areas and available transportation infrastructure, help explain why each province has very different crude oil supply dynamics. The role of transportation options (pipelines, rail, and tankers and/or barges) in determining a refiners’ crude sources cannot be overstated. In the west, it is not surprising that western Canadian refineries, on the other hand, use exclusively crude oil produced in the region.

In the east, the dynamics are more complicated. ON accesses western Canadian production via the Enbridge Mainline pipeline, as does Suncor’s refinery in Montréal via the Line 9b reversal. ON is, however, unique in that it uses feedstock from western Canada, but also imports crude oil, primarily from the US. In QC, while Montréal’s Suncor refinery can be supplied with western Canadian crude oil by pipeline and rail, as well as receive eastern Canadian oil through the Portland-Montréal pipeline, QC’s Valero refinery relies more on importing foreign crudes by

January 2018 2 Canadian Energy Research Institute

tankers. Located near Quebec City, Valero can access western Canadian crude oil from Montréal via smaller tankers and is also able to receive oil from the west by rail. The facility can also access eastern Canadian oil by tanker through its offloading facilities, which are primarily used for importing foreign-sourced crude oil. Like QC’s Valero refinery, Atlantic Canada also depends on importing crudes due to a lack of pipeline infrastructure. They access a diverse slate of foreign crudes, including the US, via tankers. In 2016, QC received crude from nations such as Algeria, Azerbaijan, Kazakhstan, Norway and Nigeria while NB received crude from nine different nations including Saudi Arabia, Congo, Ivory Coast, Colombia, Nigeria and Norway (Government of Canada 2017; NEB 2017f; Statistics Canada 2017a). The crude slate for NL’s single refinery is equally diverse. And while the facility uses some of its offshore oil as a feedstock, it does not use any crude from western Canada. NB’s Irving Oil refinery, however, can access western Canadian crude oil via rail, as well as Offshore NL crude oil by tanker.

The scope of this study is to analyze the potential complete or partial substitution of eastern Canadian crude oil imports via domestically-sourced oil. The research provides a cost and emissions comparison based on four potential scenarios of substituting domestic vs. foreign crude oil in the central and eastern Canadian refinery market.

It is important to note that transportation capacity is not the constraint and consideration in foreign oil substitution. Other constraints in refinery decision-making include economics of supply and crude availability in western and eastern Canada. The former means that refineries modus operandi is to optimize cost of feedstock while gaining desired yields demanded by the refined petroleum markets. Thus, if Canadian oil is more expensive at the gate of a refinery compared to foreign oil, in a market-driven non-policy constrained decision-making world, it would prefer the cheaper feedstock (if it can get the same desired yields). Prices of particular brands of foreign and domestic oil as well as transportation costs play a role in the selection of the crude slate.

This CERI study will show market- and socially-pushed scenario outcomes, via existing and expanded transportation infrastructure, which could serve as a sign for Canadians on how beneficial or costly such substitution could be. This research is a first of its kind comparison that has not been done by any other organization.

Before discussing the methodology and assumptions undertaken in this study, it is prudent to provide a brief review of several important concepts central to this study. Prior to discussing any substitution, it is important to grasp the sheer complexity of the eastern refinery market, in terms of the refinery business as well as the complex transportation system connecting western and eastern Canadian producers, and their international counterparts, to the eastern Canadian refineries.

January 2018 An Economic and Environmental Assessment of 3 Eastern Canadian Crude Oil Imports Chapter 2: Background Information

This chapter is divided into three parts: an overview of Canada’s crude oil supply and disposition, an overview of the eastern Canadian refining sector within a global context, and a brief overview of the various transportation modes used in the study (pipeline, rail, and tanker and/or barge). In addition to providing a discussion of the refinery sector in eastern Canada (including refiner capacities, use rates, crude intakes, and mode of supply), this section will also include a brief discussion of trends and the Canadian refinery sector within a global context. Likewise, the overview of transportation modes will focus on pipelines, rail, and tankers important to transport crude oil to eastern Canadian refineries.

Crude Oil Supply and Disposition Canada’s total oil production, including bitumen and synthetic, has been continuously growing over the last seven years except for the 2015-16 period where production is flat, due to the Fort McMurray wild fires. In 2016, production was 3,872 Mbpd, up from 3,869 Mbpd in 2015 and up from 3,698 Mbpd in 2014 (2017a, 2017b). Canada’s total conventional (including light, C5+/condensate and heavy) oil production in 2016 was 1,448 Mbpd, led by 666 Mbpd in AB, followed by 461 Mbpd in SK and 210 Mbpd in Atlantic Canada (NEB 2017a, 2017b). AB oil sands production, including bitumen and synthetic production, totals 2,418 Mbpd (NEB 2017a, 2017b).

Figure 2.1 illustrates total oil production in Canada from 2009 to 2016. Canadian conventional production includes light, C5+/condensate and heavy crude oil production and is shown by producing province. AB’s oil sands production includes bitumen and synthetic.

January 2018 4 Canadian Energy Research Institute

Figure 2.1: Canadian Crude Oil Production by Province, Conventional + Oil Sands (Mbpd)

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

0 2009 2010 2011 2012 2013 2014 2015 2016

Atlantic ON MB SK AB BC NWT AB - Bitumen & Synthetic

Data Sources: (NEB 2017a, 2017b), Canadian Energy Research Institute (CERI) calculations. Figure by CERI.

Canada is a significant exporter of crude oil, with most oil exported to the US. Figure 2.2 illustrates the US imports from Canada by type. Total US imports from Canada in 2016 were 3,264 Mbpd, up from 3,169 Mbpd in 2015 and up from 1,939 Mbpd in 2009 (US Energy Information Administration [US EIA] 2016). In addition, it is important to mention that Canadian production, in western Canada, does supply other provinces.

January 2018 An Economic and Environmental Assessment of 5 Eastern Canadian Crude Oil Imports

Figure 2.2: US Imports from Canada by Crude Type (Mbpd)

3,500

3,000

2,500 60% 62% 2,000 60% 59% 59% 1,500 59% 55% 57%

1,000 21% 22% 26% 25% 25% 500 27% 27% 27%

- 2009 2010 2011 2012 2013 2014 2015 2016

Light Sweet Light Sour Medium Heavy Sweet Heavy Sour

Data Source: (US EIA 2016). Figure by CERI.

It is interesting to note that the largest share of exports is heavy sour bitumen, accounting for 60 percent of type of crude exported from Canada to the US. Heavy sour exports to the US increased from 1,063 Mbpd in 2009 to 1,970 Mbpd in 2016 (US EIA 2016) and are destined to refineries capable of processing heavier crudes in the US Midwest (US Petroleum Administration for Defense District [PADD] II) and the US Gulf Coast (PADD III).

Eastern Canadian crude oil imports rose slightly in 2016, reaching 607 Mbpd, with most of the imports from the US (259 Mbpd). Rounding out the top 5 in 2016 is Saudi Arabia (87 Mbpd), Algeria (85 Mbpd), Nigeria (74 Mbpd) and Norway (42 Mbpd) (Government of Canada 2017; NEB 2017f; Statistics Canada 2017a). This is illustrated in Figure 2.3.

January 2018 6 Canadian Energy Research Institute

Figure 2.3: Eastern Canadian Crude Oil Imports by Country, 2016 (Mbpd)

United States 259.4

Algeria 84.8

Saudi Arabia 86.7

Nigeria 73.7

Norway 41.8

Kazakhstan 19.2

Ivory Coast 12.6

United Kingdom 9.9

Azerbaijan 6.9

Colombia 5.3

Congo 2.7

Equatorial Guinea 2.4

Denmark 1.7

0.0 50.0 100.0 150.0 200.0 250.0 300.0 Data Sources: (Government of Canada 2017; NEB 2017f; NRCan 2017b; Statistics Canada 2017a), CERI calculations. Figure by CERI.

Refineries: Background and Trends Refineries and their economics are dictated by a complex set of variables. In the short term, refineries must juggle their choices of inputs (crude slate) and refined outputs (product slate), both of which are typically price-takers. Refineries must optimize production against a backdrop of changing demand patterns and increased global competition among refiners to be profitable. In the longer term, refiners should decide whether to invest in changing their configuration or shutting down. While changing environmental regulations are typically not part of the day-to-day crude slate decision making, these changes affect the refinery capital program and long-term plan.

The Refinery Process The refining sector is a critical component of the value chain of oil as a commodity, an intermediary between crude oil and valuable and usable refined products. Oil is the primary feedstock into the petroleum refining industry, processing oil into products such as gasoline, diesel, heating oil, propane, asphalt, and petrochemical feedstock. The latter transforms crude oil into a variety of consumer goods and products, ranging from plastics to pharmaceutical products.

January 2018 An Economic and Environmental Assessment of 7 Eastern Canadian Crude Oil Imports

Figure 2.4 illustrates the breakdown of an average barrel of Canadian refined petroleum products, produced by Canadian refineries. The products are illustrated from heaviest to lightest, by percentage. In Canada, between 2011 and 2016, the largest component is motor gasoline (36 percent), followed by diesel and middle distillates (33 percent), petrochemical feedstocks and LPGs (7 percent), heavy fuel oil (6 percent), other heavy products (6 percent), aviation fuel (5 percent), other light products (4 percent) and asphalt (4 percent) (NEB 2017g).

Figure 2.4: Breakdown of an Average Barrel of Canadian Refined Petroleum Products (%)

Source: (NEB 2017g)

The primary end-products are typically classified into three separate categories: light distillates, middle distillates, and heavy distillates. Light distillates include liquified petroleum gas (LPG), gasoline and heavy naphtha while middle distillates include kerosene, automotive and railroad diesel fuels, residential heating fuel and other light fuel oils. Heavy distillates include heavy fuel oils.

However, before discussing the complex refining process, it is prudent to review the distinct types of crude oil. Globally, there are over 150 different types of crude and even more brands of crude (CFA 2013). Not only do they impact the price of feedstock to the refiner, they also produce different yields for the refiners (CFA 2013). On the simplest level, crude oils are differentiated by sulfur content (sweet or sour) and by American Petroleum Institute (API) gravity (light or heavy). Aside from density (kg/m3), API gravity (degrees), sulfur (percentage on weight basis [wt%]), grades of crude are also differentiated by several other physical characteristics including micro-

January 2018 8 Canadian Energy Research Institute

carbon residue (MCR) (wt%), sediment (parts per million weight [ppmw]), total acid number (TAN) (mg potassium hydroxide [KOH]/g), salt (pounds per thousand barrel [ptb]), nickel (mg/kg), vanadium (mg/kg) and olefins (wt%).

Figure 2.5 illustrates the distribution of selected Canadian and imported crude oils used in this study by API gravity and sulfur content.

Figure 2.5: Distribution of Selected Canadian and Imported Crude Oils by API Gravity and Sulfur Content

Data Sources: (PRELIM v1.1 (J. A. Bergerson et al. 2016); CrudeMonitor.ca (Crude Quality Inc. 2017)), crude oil assays from EcoPetrol, ExxonMobil, Maersk Oil, TOTAL, Tullow Oil websites. Figure by CERI. Notes: Canadian crude oils, foreign crude oils. API gravity values represented in Figure 2.5 are the crude oil API gravity values at the refinery inlet gate.

The higher the sulfur content, the sourer the crude oil while the lower the sulfur content, the sweeter the crude oil. Likewise, crude oil with a low API gravity is considered a heavy crude oil and typically has a higher sulfur content, resulting in a larger yield of lower-valued products (NRCan 2016). Therefore, the lower the API of a crude oil, the lower the value it has to a refiner, as crude will either require more processing or yield a higher percentage of lower-valued by- products such as heavy fuel oil, which usually sells for less than gasoline (NRCan 2016). Refiners

January 2018 An Economic and Environmental Assessment of 9 Eastern Canadian Crude Oil Imports are willing to pay more for light, low sulfur crude oil. While lighter grades require less upgrading at the refinery, they are in decreasing supply (CFA 2013). Heavy crude oils, on the other hand, are cheaper, but more expensive to refine since they require significant investments (CFA 2013).

It is important to note that at the core of this research study is the substitution of foreign crude oils by western Canadian crude, by type. Imported light oil is, hence, substituted by light oil of a similar crude type and physical characteristics by either western Canadian crude oil or from Offshore NL. This is discussed in greater detail later in this chapter.

Figure 2.6 illustrates the complex refining process, as crude oil moves to its various derivative products, such as gasoline, kerosene and jet fuel, diesel, as well as heavier products such as lubricants (lubricating oil), fuel oil and residual, used for roads and building materials. The derivative products are listed on the right side of the figure.

Figure 2.6: Refining Flow Scheme

Source: (Honeywell UOP 2017) Note: FCC – fluid catalytic cracking; LPG – liquified petroleum gas; SHP – selective hydrogenation process.

January 2018 10 Canadian Energy Research Institute

While there are common features and processes, no two refineries are identical. Refineries process different crude oils with different chemical characteristics and process them into a range of refined products. In doing so, refinery configurations, or the type of processing units at the refinery, are different. Different types of processing units can process certain types of crude oil. As such, some refineries are simply not able to process heavier crude oils. Canadian oil production has shifted from declining conventional reserves to heavier, higher sulfur crudes, such as bitumen. Eastern Canadian refineries that wish to take advantage of lower priced bitumen will need to change their refinery configurations and to invest into additional coking, hydrocracking and hydrotreating units to process heavier barrels into the same yield of refined products. Hydrotreating will be needed to meet the Canadian fuels regulations for lower sulphur products, especially if the crude slate includes higher sulphur crudes.

While there are multiple processing units used, most refineries fall into three broad categories: a topping plant with a distillation unit, a cracking refinery, and a coking refinery. They represent increasing levels of complexity and increase in cost.

A topping refinery is the simplest type of refinery. They have a distillation tower and convert light sweet crude oil into either light or middle distillates. Some topping refineries are also equipped with a catalytic reformer, adding a layer of complexity, as well as the capability to produce gasoline (Simmons and Phillip 2008). These refineries are referred to as hydroskimming refineries. The latter provides octane to gasoline for example. In addition, some topping refineries can be asphalt plants.

The atmospheric distillation units produce hydrocarbon boiling point cuts from resid to LPG (Sep- Pro Systems 2009). The crude oil is heated with fire heaters to temperatures ranging between 650 and 700 degrees Fahrenheit (Inkpen and Moffett 2011). With most of it vapourizing, it enters the atmospheric distillation tower or column, getting cooler as it goes up in the tower (Inkpen and Moffett 2011). This process is illustrated by Figure 2.7.

January 2018 An Economic and Environmental Assessment of 11 Eastern Canadian Crude Oil Imports

Figure 2.7: A Topping/Hydroskimming Refinery

Source: (Simmons and Phillip 2008) Note: CARB gasoline – gasoline that meets California Air Resources Board (CARB) regulations; CBOB – conventional blendstock for oxygenate blending; HS – high sulfur; LS – low sulfur; RBOB – reformulated blendstock for oxygenate blending.

As the various hydrocarbons cool below their respective boiling points, they revert to a liquid state. Heavier hydrocarbons such as heavy gas oil or lubricating oil are collected on the lower trays of the distillation tower, while lighter hydrocarbons are collected near the top of the tower (Inkpen and Moffett 2011). Vacuum distillate units are often used to separate the gas oil from the lower quality heavy fuel or resid (Simmons and Phillip 2008). Lighter hydrocarbon products range from the heavier middle distillate, to kerosene and naphtha and low octane gasoline. Catalytic reformers increase the octane number of gasoline.

Light sweet crude or condensate is used as the crude slate at a topping or hydroskimming refinery. Asphalt plants are topping refineries that run heavy crude oil because they are primarily interested in producing asphalt.

The second type of refinery is a cracking refinery. This level of process is often referred to as medium conversion. This type of refinery takes the gas oil portion from the crude distillation unit and breaks it down further into gasoline and distillate components. Cracking breaks or cracks the heavier products into more valuable products such as gasoline and diesel (Inkpen and Moffett 2011). The fluid catalytic cracker (FCC) process is shown in red and illustrated in Figure 2.8.

January 2018 12 Canadian Energy Research Institute

Figure 2.8: A Catalytic Cracking Refinery

Source: (Simmons and Phillip 2008) Note: CARB gasoline – gasoline that meets California Air Resources Board (CARB) regulations; HS – high sulfur; LS – low sulfur; RFG – reformulated gasoline.

The FCC, for example, converts heavier hydrocarbon molecules into lighter hydrocarbon molecules. This is done using catalysts, high temperature and/or pressure, operating at approximately 986 degrees Fahrenheit (Vellenga 2017).

It is important to note that cracking refineries tend to use more sour crude oils and upgrade them to higher value products. They have increased yields of higher value products than topping refineries.

These types of refineries, using FCC, are common in the US, due to the higher demand in gasoline. FCC units are, on the other hand, less common in Europe and parts of Asia, due to the higher demand in diesel and kerosene, both of which can be satisfied by hydrocracking. The latter is similar to FCC but yields more diesel and represents a more complex type of refinery (Inkpen and Moffett 2011).

The most complex type of refinery, or high conversion refinery, is the coking refinery. This type of refinery processes residual fuel, the heaviest material from the crude unit and thermally cracks it into lighter product. This is done in a coker or a hydrocracker. The addition of a FCC unit significantly increases the yield of higher-value products like gasoline and diesel oil from a barrel of crude. High conversion refinery processes are illustrated in Figure 2.9.

January 2018 An Economic and Environmental Assessment of 13 Eastern Canadian Crude Oil Imports

Figure 2.9: A Coking Refinery

Source: (Simmons and Phillip 2008) Note: CARB gasoline – gasoline that meets California Air Resources Board (CARB) regulations; RFG – reformulated gasoline.

It also allows the refinery to process cheaper, heavier crude while producing an equivalent or greater volume of high-value products (Simmons and Phillip 2008). Other processes such as hydrotreating, which removes sulfur from finished products, give the refiners the ability to process crude oil with a higher sulfur content.

Canada has primarily cracking refineries, using a mix of light and heavy crude oils to meet Canadian demand for gasoline, diesel, and other products. Historically, the abundance of domestically produced light sweet crude oils and a higher demand for distillate products, such as heating oil, reduced the need for upgrading capacity in Canada (NRCan 2016). However, in more recent years, the supply of light sweet crude has declined, and newer sources of crude oil tend to be heavier.

Eastern Canadian Refineries within a North American and Global Context Canada’s refinery market is considered as three separate entities: Western Canada; ON; and QC and Atlantic Canada. In some cases, QC and Atlantic Canada are considered separate entities as well. Western Canada is land-locked and refineries have primarily sourced their crude from local and regional production. ON can access western Canadian production via pipelines, QC and Atlantic Canada depend on importing crudes because of a lack of pipeline infrastructure, and the cost of transporting crude from western to eastern Canada is more expensive than importing foreign crudes.

There are 15 refineries in Canada, seven of which are in western Canada and eight located in eastern Canada. In addition, Canada also has two refineries producing asphalt (Husky’s

January 2018 14 Canadian Energy Research Institute

Lloydminster Refinery and Gibson Energy’s Moose Jaw Refinery) and a lubricants plant (Hollyfrontier’s Clarkson Refinery). Figure 2.10 illustrates the location of Canada’s refineries as well as their capacity and product demand (by region). The two main clusters are the Edmonton area (AB) and the Sarnia area (ON). It is important to note that Canada’s first new refinery since 1984 is the North West Redwater Partnership, sometimes referred to as the Sturgeon Refinery (AB). North West Refining and Canadian Natural Resources Limited (CNRL) have a 50/50 partnership in the Sturgeon Refinery.

Figure 2.10: Canada’s Refining Sector, 2016

Source: (CFA 2017b) Note: kb/d – thousand barrels per day.

Canada is a net exporter of refined products – refinery capacity exceeds domestic demand, notably in QC and Atlantic Canada. Net exports reached nearly 17 billion litres in 2013, decreasing to 6 billion litres in 2016 (Statistics Canada 2017e). Figure 2.11 illustrates the net exports, as well as domestic sales of refined petroleum products by product (motor gasoline, diesel, and other refined petroleum products [RPP]) and total refinery production. Total refinery production reached 117 billion litres in 2010 and decreased to 105 billion litres in 2014, but increased slightly to 109 billion litres in 2016 (Statistics Canada 2017d).

January 2018 An Economic and Environmental Assessment of 15 Eastern Canadian Crude Oil Imports

Figure 2.11: Supply and Disposition of Refined Petroleum Products in Canada (billion litres)

140

120

100

80

60

40

20

0 2009 2010 2011 2012 2013 2014 2015 2016

Refinery Production Motor Gasoline Sales Diesel Fuel Oil Sales Other RPPs Sales Net Exports

Source: (Statistics Canada 2017e) and CERI calculations. Figure by CERI.

This section delves into the eight eastern Canadian refineries and various important metrics, including their location, capacity, use rates, crude intakes (or crude slate) and mode of supply (transportation). Consumption of feedstock (crude slate) and product slate of the eight refineries is reviewed, establishing the current state of refineries in eastern Canada. The crude slate is reviewed more closely, breaking it down by domestic-sourced crude and foreign-sourced crude.

It is first important to note the sources of data used. The data was obtained from several sources including Statistics Canada, Natural Resources Canada (NRCan), Canadian Fuel Association (CFA), Canadian Association of Petroleum Producers (CAPP), various refinery websites, midstream companies’ websites (Enbridge and others), Clipper Data (transportation of oil by tankers), as well as calculations and estimates by CERI where needed. Statistics Canada CANSIM Table 126- 0003 Supply and Disposition of Crude Oil and Equivalent and Table 134-0001 Refinery Supply of Crude Oil and Equivalent were used (Statistics Canada 2017c, 2017d). If the data was suppressed, missing, or conflicted with one another, CERI reconciled using multiple sources to infer quality and certainty in data. For instance, for QC, 10 months of 2016 were used to determine the shares of the different crude oil intake; likewise, for ON, five months of 2016 were used due to the availability of data (other months are either not available or suppressed by Statistics Canada’s data). Information on type and volumes of crude that Irving Oil Refinery and North Atlantic Refining are receiving is not available from Statistics Canada. As such, numbers are estimated by CERI using data from other sources and various publications.

Refining capacity in eastern Canada is represented by eight refineries with a total capacity of 1,228 Mbpd (CFA 2017b). Four refineries are in ON, two in QC, and one each in NB and NL. All eight refineries, their capacities, use rates and total 2016 crude intakes are illustrated in Table 2.1.

January 2018 16 Canadian Energy Research Institute

Table 2.1: Eastern Canadian Refinery Capacity and Crude Oil Intake Province Refinery Capacity Utilization Rate Total Intake (Mbpd) (%) (Mbpd) ON Imperial, Sarnia 121 86% 104.1 Shell Canada, Corunna 75 88% 65.9

Suncor Energy, Sarnia 85 92% 77.8

Imperial, Nanticoke 112 86% 96.3 ON Subtotal 393 QC Valero, Lévis 265 88% 232.8 Suncor Energy, Montréal 137 92% 125.4 QC Subtotal 402 NB Irving Oil, Saint John 318 87% 277.8 NL North Atlantic Refining, 115 81% 93.1 Come By Chance Atlantic Canada Subtotal 433 Total 1,228 1,073.0

Data Sources: (CFA 2017b; Statistics Canada 2017c, 2017d), various refinery websites & CERI (calculations and estimates). Table by CERI.

All of ON’s refineries are in the south of the province, with three refineries found in the Sarnia area (Suncor Energy and Imperial Oil operate refineries in Sarnia while Shell Canada operates the Corunna Refinery in nearby St. Clair). Imperial Oil operates a refinery in Nanticoke. As can be seen from Table 2.1, Imperial Oil’s Nanticoke Refinery and Sarnia Refinery have capacities of 112,000 and 121,000 bpd, respectively. Suncor Energy’s Sarnia refinery has a capacity of 85,000 bpd and Shell Canada’s St. Clair refinery has a capacity of 75,000 bpd. QC has two refineries, Suncor Energy’s Montréal Refinery and Valero’s Jean-Gaulin Refinery, in Lévis, near Quebec City. The refineries have capacities of 137,000 bpd and 265,000 bpd, respectively. Atlantic Canada also has two refineries, Irving Oil Refinery in Saint John, NB, and the North Atlantic Refinery in Come By Chance, NL. The former has a capacity of 318,000 bpd and is Canada’s largest refinery. The North Atlantic Refinery has a capacity of 115,000 bpd.

Table 2.2 illustrates the refinery configurations for Canada’s central and eastern refineries. These include coking (25.5 Mbpd in ON), visbreaking (5 Mbpd in ON and 40 Mbpd in Atlantic provinces), hydrocracker (around 60 Mbpd in ON, 22 Mbpd in QC, and 72 Mbpd in Atlantic provinces), catalytic cracker (116 Mbpd in ON, 100 Mbpd in QC, and 95 Mbpd in Atlantic provinces), catalytic reformer (107 Mbpd in ON, 84 Mbpd in QC, 69 Mbpd in Atlantic provinces), and hydrotreating (291 Mbpd in ON, 321 Mbpd in QC, and 148 Mbpd in Atlantic provinces) (Oil & Gas Journal 2016b).

January 2018 An Economic and Environmental Assessment of 17 Eastern Canadian Crude Oil Imports

Table 2.2: Canada’s Refining Sector Configurations, 2016 (Mbpd)

Hydro- Catalytic Catalytic Hydro- Refinery Location Vacuum Coking Visbreaking cracker Cracker Reformer treating Imperial Oil Sarnia 32 26 19 31 28 89 Shell Canada Corunna 24 5 9 19 22 21 Suncor Energy Sarnia 27 32 17 23 82 Imperial Oil Nanticoke 48 49 34 99 Valero Lévis 49 68 48 199 Suncor Energy Montreal 54 22 32 36 122 Irving Oil Saint John 100 20 34 95 35 92 North Atlantic Come by 55 20 38 32 56 Refining Chance Data Source: (Oil & Gas Journal 2016b). Table by CERI.

The economics behind whether to invest in these additional coking units is determined by the current and expected spread between light and heavy oil prices. The gain in value for investing in additional units must yield a high enough return to offset the increased costs of building more units. Refining capacity to process heavy crude is limited because recently the light-heavy crude differential has not been consistently wide enough to cover the cost of installing additional upgrading or refining capacity.

It is important to put the current state of Canadian refineries into a historical and global context. The former is illustrated in Figure 2.12.

January 2018 18 Canadian Energy Research Institute

Figure 2.12: Canadian Refining Capacity and Number of Refineries, 1948-2016

Source: (Oil Sands Magazine 2016). Note: kbpcd – thousand barrels per calendar day

From a historical perspective, the number of refineries has been decreasing over the past several decades. With the closures of Shell’s Montréal refinery in 2010 and the Imperial Oil refinery in Dartmouth, NS, there are now 15 refineries. Recall, Figure 2.12 also includes the Hollyfrontier Refinery, the Moose Jaw Refinery, and the Lloydminster Refinery, which are either asphalt or lubricant plants. This is down from 36 in 1980 and down from a high of 45 refineries in 1958. The same is true south of the border. The number of operating refineries decreased from 300 in 1982 to 137 in 2017 (US EIA 2017).

Refinery capacity in Canada increased dramatically from 264 Mbpd in 1947 to a record-high of 2,232 Mbpd in 1980. The capacity subsequently decreased in the 1990s, hovering around the 1,800 Mbpd level. It has increased to 1,910 Mbpd in 2016 (Oil Sands Magazine 2016). Again, these totals include asphalt and lubricant plants. A similar pattern occurs in the US. Operating refinery capacity decreased from 18 million barrels per day (MMbbl per calendar day) to a low of 15 MMbbl per calendar day in 1993, where capacity increased back to 18 MMbbl per calendar day in 2017 (US EIA 2017).

January 2018 An Economic and Environmental Assessment of 19 Eastern Canadian Crude Oil Imports

However, the number of refineries in Canada is likely to decrease further, due to several factors. First, like their global counterparts, including in the US, refineries are getting larger and more efficient, and increasingly satisfying local demand for gasoline and diesel. With cars and trucks increasing fuel efficiency, the future demand for refined petroleum products is flat in North America, if not decreasing. While increased vehicle efficiency and renewable fuels will likely impact the near-term, another question is the penetration of electric vehicles into the US transportation fleet. As a net exporter of refined petroleum products, this will leave several Canadian refineries vulnerable. It should, however, be emphasized that the rate of decline varies widely depending on the assumptions made by different studies; factors include the growth of electric vehicle sales, growth in biofuel production and consumption, and the effectiveness of current climate and transportation policies.

Second, as previously mentioned, refineries could also be susceptible to changes in regulations, most notably, climate change initiatives. A recent study (March 2017), Cumulative Impacts on Climate Change and Other Policy Scenarios Facing the Canadian Petroleum Sector, suggested that eastern Canadian refineries are more vulnerable to potential closure by 2030 (Tamm and Milburn 2017). A potential 20 to 40 percent drop in demand could lead to shutting down three refineries in the case of the former and five refineries in the case of the latter. Some pundits expect a decrease of 20-40 percent of capacity in the next few years (Tamm and Milburn 2017). It should be noted that in the context of current policies, decrease in demand of more than 20 percent (and associated refinery closures), appear to be an unlikely scenario at this point.

Within a global context, North America’s share of global refining capacity decreased slightly from 25 percent to 24 percent between 2005 and 2015 (Oil Sands Magazine 2016). Over the same time frame, Europe and Eurasia decreased from 28 percent to 25 percent. While the Middle East’s share of the global refining capacity stayed at 9 percent, the largest growth occurred in the Asia Pacific, which increased from 28 percent to 34 percent between 2005 and 2015. The latter is led by rapid growth in China, increasing from a capacity of approximately 9,000 Mbpd in 2008 to over 14,000 Mbpd in 2015 (Oil Sands Magazine 2016).

North American refineries, particularly Canadian, face competition from abroad as global refining capacity is capable of processing heavy crudes at lower costs than in North America. Aside from the economic challenges, locational and political issues affect access to this processing capacity. Refineries tend to be found close to their markets for refined products.1 Some of the reasons behind this are that it is less expensive to transport crude oil than refined products, the specifications for gasoline vary across the world, and countries prefer energy security for refined products. For example, historically the US refinery configuration has been to maximize gasoline production, but in Asia, refinery configurations support industrial development especially for diesel and petrochemical production (Hackett et al. 2013).

1 Even though the scale of refining capacity and proximity to tidewater could mean that the refineries do not necessarily need to be in close proximity to their markets.

January 2018 20 Canadian Energy Research Institute

Refiners also face challenges in that the North American market has peaked in its product demand, meaning that an expansion of refining capacity to meet oil production would mean selling refined products to the export markets, specifically in developing nations of the Asia Pacific (IHS CERA 2013).

Figure 2.13 depicts crude distillation capacity additions by region. Forty-six percent of the capacity additions are projected for the Asia-Pacific region between 2016 and 2040 (OPEC 2016). This is followed by the Middle East, Africa and Latin America at 17 percent, 16 percent and 11 percent, respectively (OPEC 2016).

Figure 2.13: Crude Distillation Capacity Additions by Region, 2016-2040 (MMbpd)

Source: (OPEC 2016)

On a global scale, China and the Asia-Pacific region are leading the growth of refined product demand. This is reflected in the region’s refining capacity. The region is leading the worldwide trend of larger, more efficient refineries. The Asia-Pacific, including China, is expected to add around 3.3 MMbpd of new distillation capacity in the medium-term to 2021, while the Middle East should expand by 1.7 MMbpd (OPEC 2016). This is followed by growth in Latin America and Africa. The figure reflects that markets in Canada, US and Europe are mature and growing at a slower rate.

It is not surprising that the 10 largest oil refineries in the world are primarily situated in the Asia- Pacific region: Reliance Jamnagar Refinery, India (1.24 MMbpd), Paraguana Refining Centre, Venezuela (955,000 bpd), Ulsan Refinery South Korea (840,000 bpd), Yeosu Refinery, South Korea,(775,000 bpd), Onsand Refinery, Ulsan, South Korea (669,000 bpd), Port Arthur Refinery, Texas, US (600,000 bpd), ExxonMobil’s Singapore Refinery (592,000 bpd), ExxonMobil’s Baytown Refinery, Texas, US (584,000 bpd), Ras Tanura Refinery, Saudi Arabia (550,000 bpd) and Garyville

January 2018 An Economic and Environmental Assessment of 21 Eastern Canadian Crude Oil Imports

Refinery, Louisiana, US (522,000 bpd) (Dudu 2013). The largest Canadian refinery is NB’s Irving Refinery at 318,000 bpd.

Crude Oil Transportation – Pipeline, Rail and Tanker/Barge Crude oil can be transported in four ways: pipeline, rail, tanker/barge, and truck. While discussed in greater detail in Chapter 3, transporting crude from western Canadian producers to eastern Canadian refineries use various modes of transportation, depending on the location of the refinery. The same is true for transporting foreign crude oil to eastern Canadian refineries.

This section highlights the various elements of the three modes of transport primarily used in this study: pipeline, rail, and tankers. In the context of this study, the pipeline and rail are used to transport crude oil from western Canada and the US to refineries in eastern Canada. Tanker, and to lesser extent barges, on the other hand, are used to transport crude oil from the US and other parts of the world to refineries in eastern Canada.

Figure 2.14 illustrates the complex web of liquids pipelines in eastern Canada and the US. While the pipeline illustrates Enbridge’s Line 9 Reversal, the Portland-Montréal Pipeline, and the Energy East Pipeline (as proposed), the map does not show the Enbridge Mainline, transporting crude from AB, SK, and MB to eastern Canadian markets. The Energy East pipeline was cancelled on October 5, 2017. It is interesting to note that the Trans-Northern Pipeline, from Nanticoke, ON to Montréal, QC, and the St. Lawrence Pipeline, from Quebec City to Montréal, are transporting refined petroleum products. Also illustrated are the locations of Canada’s central and eastern refineries, as well as the rail network in eastern Canada. Rail infrastructure is, however, discussed in greater detail later in this chapter.

January 2018 22 Canadian Energy Research Institute

Figure 2.14: Eastern Canadian Crude Oil Transportation Infrastructure

Source: (NEB 2016a)

Pipeline There are approximately 41,000 kilometers of crude oil pipelines in Canada, transporting 3.7 MMbpd (Canadian Energy Pipeline Association [CEPA] 2017). In addition, there are approximately 77,000 kilometers of natural gas pipelines in Canada, transporting 15.3 billion cubic feet per day (CEPA 2017). While it is not prudent to review over two dozen existing liquids pipelines that either originate in or operate within Canada, it is important to review several pipelines, within the context of this study, that transport liquids to eastern Canada that directly influence the movement of crude oil into eastern Canadian refineries, whether from western Canada or from the US.

Western Canadian production is connected to domestic and US refining and export centers, through an extensive network of pipeline but also through rail. For example, most Canadian exports are destined for the US Midwest (PADD II) and the US Gulf Coast (PADD III) – the latter being one the world’s largest refining centers, with a refining capacity of 9.4 MMbpd. Nevertheless, 400 Mbpd of western Canadian crude oil was transported to refineries in ON, QC and NB, the bulk of which was transported by pipeline (CERI Crude Flow Model).

January 2018 An Economic and Environmental Assessment of 23 Eastern Canadian Crude Oil Imports

The following section is divided into three parts: Enbridge’s Canadian Mainline (with a focus on Line 5 & Line 78), Enbridge’s Line 9b Reversal and the Portland-Montréal Pipeline.

Enbridge Canadian Mainline Enbridge operates the world’s longest crude oil and liquids transportation system, slightly over 30,000 kilometers in length (Enbridge 2017a). While moving 64 percent of Canadian exports to the US, it plays an important role in transporting crude oil across Canada, from western Canadian producing regions to eastern Canadian refineries (Enbridge 2017a).

Enbridge’s Canadian Mainline, or simply referred to as the Enbridge System, begins in Edmonton and runs to Montréal. It is 2,306 kilometers in length (Enbridge 2016a; Enbridge Inc. n.d.). The Canadian Mainline ends at Gretna, MB when the pipeline enters the United States and starts again in Sarnia, ON, where it extends through Toronto and on to Montréal (Enbridge 2016a; Enbridge Inc. n.d.). The Canadian Mainline transports crude oil and diluted bitumen, while the Enbridge Lakehead transports crude oil, condensate and NGLs (Enbridge Inc. n.d.). In combination with the Enbridge Lakehead System the capacity of the pipeline is 2,500,000 bpd (Enbridge Inc. n.d.).

The US Mainline, or Enbridge’s Lakehead System, connects the western portion of the Canadian Mainline from Edmonton, AB, to Gretna, MB and the eastern portion of the mainline that runs between Montréal and Sarnia, ON. The Lakehead System loops around Lake Michigan, as far north as Lewiston and runs southward through Bay City, Michigan and northwards to Sarnia, ON. The US Mainline is 3,057 kilometers in length and is owned by Enbridge Energy Partners LP (Enbridge Inc. n.d.).

Figure 2.15 illustrates the Enbridge Mainline System configuration. The schematic includes 14 lines, or pipelines, as of Q1 2016. The Canadian Mainline system includes Lines 1, 2, 3, 4, 7, 9, 10 and 11. The US Mainline, on the other hand, includes Lines 5, 6, 14/64, 61 and 62. It is important to note that Line 55 (Flanagan to Cushing) and Line 17 (Stockbridge to Toledo) are not part of the Enbridge Mainline system. The previously mentioned Line 9b, known as the Line 9b Reversal, runs between Sarnia, ON and Montréal, QC. It is discussed separately.

January 2018 24 Canadian Energy Research Institute

Figure 2.15: Enbridge’s Mainline System Configuration

Source: (Enbridge 2016a)

Lines 4, 6, 7, 10, 11, 62, 14/64, 61 and 67 can transport heavy crude. Lines 4 and 67 are dedicated to heavy oil. Lines 2, 3, 5, 7, 10, 11 and 14/64 are used, in part, to transport condensates. All the lines, except for Lines 62 and 67 are used to transport various products (i.e., Line 2 is used to transport condensates, light synthetics, sweet crude, and light and high sour crude). The proposed multi-billion-dollar Line 3 Replacement Program expands capacity to satisfy Canadian crude oil production growth, as well as Canadian and US refinery demand (Enbridge 2017c). The Canadian-side and the US-side of the project are both 1,660 kilometers and the pipeline is expected to have an initial capacity of 760 Mbpd (Enbridge 2017d).

In establishing crude flows in this study, both Line 5 and Line 78 play important roles. The Mainline enters Sarnia via two entry lines – Line 5 and Line 78 with a total capacity of 1,040 Mbpd. The former transports western Canadian crude along Lines 1, 2, 3 and 67 to Superior, Minnesota, where it is transported to Sarnia. Line 78, on the other hand, expands Enbridge’s capacity to transport crude produced in the Williston Basin region, North Dakota, and light and heavy crude production in western Canada and also transports product to Sarnia (Enbridge 2017b). Line 78 begins in Flanagan, Illinois and terminates in Sarnia, via Griffith/Hartsdale and Stockbridge (Enbridge 2017b). The pipeline runs parallel to Line 62 between Flanagan and Griffith/Hartsdale.

As ON refineries consume 344 Mbpd (total refining capacity 393 Mbpd) (see Table 2.1), the incoming pipeline capacity is enough to carry more Canadian oil east of ON.

January 2018 An Economic and Environmental Assessment of 25 Eastern Canadian Crude Oil Imports

Enbridge Line 9 Reversal While Line 9 is also operated by Enbridge, it operates outside of the Mainline, and is consequently discussed separately. In addition, Line 5 is being expanded and Line 9B reversed from Westover, ON to Montréal (Enbridge 2017e). The latter was approved by the NEB on March 6, 2014 (Enbridge 2017e). The mandate was to provide crude oil to refineries in Montréal from western Canada and the Bakken region in North Dakota. The pipeline originally shipped oil from the North Sea, West Africa, and the Middle East from Montréal to refineries in Sarnia.

In 2012, Enbridge applied to reverse the flow direction and expand the capacity of Line 9, from 240,000 bpd to 300,000 bpd (NEB 2016b). Line 9, which now carries light crude from the Williston Basin to refineries in QC, allows refineries in QC to use North American light oil as a feedstock instead of importing crude oil from overseas, which trades at a premium to North American grades of crude.

Figure 2.16 illustrates Enbridge’s Line 9.

Figure 2.16: Enbridge’s Line 9 System Configuration

Source: (Enbridge Geomatics Services 2011)

In QC, the two refineries in Montréal and Lévis can be accessed by western and eastern Canadian oil producers. Montréal’s refinery, with oil intake of 125.4 Mbpd (total capacity 137 Mbpd), can be fully supplied from the west through the 300 Mbpd Enbridge Line 9, which is connected to Sarnia.

January 2018 26 Canadian Energy Research Institute

Portland–Montréal Pipeline Today, the Portland-Montréal Pipeline consists of two pipes: one 18-inch diameter pipe, and one 24-inch diameter pipe. The two pipes that connect Montréal to Portland tidewater have a combined engineering capacity of 602,000 bpd of light crude (24” – 410,000 bpd, 18” – 192,000 bpd) (Gillies 2009).

The pipeline reported no throughputs from January to March 2016, likely in part due to the beginning of Enbridge’s Line 9 Expansion and the Line 9b Reversal (NEB 2017d). QC refiners could access western Canadian oil through the latter. The reversal of Line 9 has also had an impact on oil tanker traffic in Portland. Not even a decade ago, with nearly 200 tankers each year, Portland was the largest oil port on the US east coast (Bell 2008).

While refineries in QC are likely using a combination of light crude oil from Enbridge’s Line 9, as well as overseas imports through the Portland-Montréal Pipeline, the pipeline’s utilization rate was actually 22 percent in 2015 (61 Mbpd out of 280 Mbpd capacity in 2015, according to the NEB (NEB 2017d). There is speculation that the Portland-Montréal Pipeline could be reversed. By reversing the flow direction of one of the pipelines, western Canadian heavy oil could be transported from AB to Portland, where crude oil is later loaded onto tankers and shipped to refineries along the US Gulf Coast for refining.

The Portland Pipe Line Corp. filed a lawsuit against the city of South Portland that has blocked the company from reversing the pipeline’s flow (that the company would immediately undertake if not prohibited by legal barriers) (Bouchard 2017).

Crude-by-Rail Non-intermodal traffic is primarily comprised of bulk cargo and tank cars, and includes commodities such as petroleum products, wheat, coal, or potash. Railcars are used to transport petroleum fuels (gasoline, diesel, aviation fuels, fuel oil and lubricants), chemical products (ethylene glycol, chlorine, ammonia, vinyl chloride and caustic soda), and LPG products (propane, butane, and pentanes).

Crude-by-rail emerged several years ago, stemming from various regulatory issues that proposed pipelines faced. Rapid growth in western Canadian crude oil production (especially from oil sands operations) has outpaced pipeline capacity and pipeline companies’ expansion efforts. In more recent years, rail transport of crude oil has subsided as an alternative mode of transport to accommodate surplus volumes that exceed pipeline capacity, as the economic downturn reduced or eliminated the surplus.

Figure 2.17 shows the current Canadian railway network for crude oil transport, and outlines the key shipping terminals and main refining centers receiving the product.

January 2018 An Economic and Environmental Assessment of 27 Eastern Canadian Crude Oil Imports

Figure 2.17: Canadian Railway Network for Crude Oil Transportation

Source: (CAPP 2017a)

By global standards, Canadian National (CN) and Canadian Pacific (CP) are major players, both considered Class I rail carriers by US definition. As of June 8, 2017, CN had a market value of US$55.9 billion (ranked second in the world behind Union Pacific at US$86.9 billion) while CP had a market value of US$22 billion, ranked eighth in the world, between Central Japan Railway and China’s Daqin Railway (Statista 2017).

Of the two Canadian railways, CN has the longest railway network in Canada, reaching from the Pacific coast in BC to the Atlantic coast in NS, and extending to the US Gulf Coast. CN operates in 8 provinces and 16 US states (Meyer 2009).

Oil from western Canada can be transported from as far north as Fort McMurray to marine terminals in Vancouver, to terminals in eastern Canada, as well as to refineries in the southern US and US Gulf Coast. CN-served ports include the Port of Halifax, Port Montréal, Prince Rupert Port Authority, Port Metro Vancouver (PMV) and Port of New Orleans (CAPP 2017a).

January 2018 28 Canadian Energy Research Institute

While CP was Canada’s first transcontinental railway, it now does not reach the Atlantic coast. Its rail network stretches from Vancouver to Montréal, and as far north as Edmonton. The CP rail network serves several major US cities, such as Minneapolis, Detroit, Chicago, and New York.

Various arrangements give CP access to terminals in Detroit, Buffalo, New York, Philadelphia, and Binghamton. Intermodal terminals located in Canada and the US include Vancouver, Calgary, Edmonton, Regina, Saskatoon, Winnipeg, Montréal, Minneapolis, Milwaukee, Detroit, and two terminals in Toronto and Chicago (CAPP 2017a). CP-served ports include Port Montréal, Port Metro Vancouver, and Port of Thunder Bay. CP’s rail network is frequently divided into four primary corridors: Western, Southern, Central and Eastern (US Securities and Exchange Commission 2006). With the purchases of the Dakota, Minnesota and Eastern Railroad (DM&E) and the Iowa, Chicago and Eastern Railroad (IC&E) in September 2007, CP’s rail network extends into the US Midwest as far as the natural resource-rich Powder River Basin in Wyoming (Dowd 2007). Additionally, CP connects with Kansas City Southern (KCS), Norfolk Southern (NS) and Union Pacific (UP) at Kansas City and connects with UP at Minneapolis and Minot, North Dakota (Canadian Pacific 2016).

CAPP estimates current rail loading capacity originating in western Canada at 754,000 bpd (CAPP 2017b).

Most of this capacity has come online in recent years. Table 2.3 illustrates the operator, location, and capacity of rail offloading terminals in eastern Canada.

Table 2.3: Crude-by-Rail Offloading Terminals in Eastern Canada Loading Capacity Terminal Operator Location (Bpd) Irving Oil Rail Terminal Irving Oil Saint John, NB 145,000 Sorel-Tracey Rail Terminal Kildar Services ULC Sorel-Tracey, QC 33,000 Montréal Rail Terminal Suncor Energy Montréal, QC 30,000 Valero Rail Terminal Valero Lévis, QC 60,000 Nanticoke Rail Terminal Imperial Nanticoke, ON 20,000

Data Source: (Oil Sands Magazine 2017b). Table by CERI.

Irving’s oil rail terminal in Saint John is the largest in eastern Canada and the country’s second largest. While Irving Oil in NB stands on the water and has direct access to Eastern offshore oil (47,000 barrels of eastern crude were used in 2016), the refinery also has a large rail offloading capacity of 145 Mbpd, the largest in Canada. Usage of rail however has decreased in recent years, as Irving Oil used to import around one-third of its intake by rail. This decrease also coincides with the fatal accident in Lac-Mégantic on July 6, 2013, when a train derailment resulted in 47 deaths. The unattended train, operated by Montréal, Maine & Atlantic Railway (MMA), was carrying crude oil from the Bakken formation to the Irving Oil refinery (Transportation Safety Board of Canada 2014).

January 2018 An Economic and Environmental Assessment of 29 Eastern Canadian Crude Oil Imports

Recall, Montreal’s Suncor Energy refinery can receive up to 35 Mbpd by rail. Valero can also receive oil from the west by rail (up to 60 Mbpd) as well as eastern oil directly by water to its offloading facilities.

In western Canada, there are 14 rail terminals in AB and 13 terminals in SK (Oil Sands Magazine 2017b). The largest three terminals in western Canada are Kinder Morgan’s Edmonton facility (210,000 bpd), Gibson/USDG’s Hardisty terminal (140,000 bpd) and Cenovus’ Bruderheim terminal (100,000 bpd) (Oil Sands Magazine 2017b).

Figure 2.18 illustrates the crude-by-rail exports by quarter to the US. The figure includes data from the NEB and the EIA. Monthly volumes as of July 2017 are 92.5 Mbpd, down considerably from the record high of 179 Mbpd in September 2014 (NEB 2017h).

Figure 2.18: Quarterly Volumes of Crude Oil Exported by Rail to the US

Source: (NRCan 2017c)

Oil Tankers and Marine Terminals There are two types of oil tankers: crude tankers and product tankers. The former moves large quantities of unrefined crude oil to refineries while the latter transports petrochemicals from refineries to market for consumption. This section focuses on the crude tankers.

Oil tankers are divided into subclasses: Product Tanker/Seawaymax, Panamax, Aframax, Suezmax, Very Large Crude Carriers (VLCC) and Ultra Large Crude Carriers (ULCC) (Rodrigo de Larrucea 2010). Table 2.4 illustrates the typical minimum and maximum deadweight tonnage (DWT).

January 2018 30 Canadian Energy Research Institute

Table 2.4: Oil Tanker Size Average Freight Rate Assessment Flexible Market Scale (AFRA) Scale Class Size in DWT Class Size in DWT General Purpose Tanker 10,000-24,999 Product Tanker 10,000-60,000 Medium Range Tanker 25,000-44,999 Panamax 60,000-80,000 LR1 (Large Range 1) 45,000-79,999 Aframax 80,000-120,000 LR2 (Large Range 2) 80,000-159,999 Suezmax 120,000-200,000 160,000- VLCC VLCC 200,000-320,000 319,999 320,000- ULCC ULCC 320,000-550,000 549,999

Source: Evangelista 2002, as referred to in (Rodrigo de Larrucea 2010). Modified by CERI.

Product tankers and Panamax vessels are known as product tankers or general purpose or Medium Range (MR) tankers, by the Average Freight Rate Assessment (AFRA) scale. These tankers often carry refined petroleum products. Panamax, or the Large Range 1 (LR1), as the name suggests, refers to ships that are able to travel through the Panama Canal with a crude capacity of up to 500,000 bbls (Marine Insight 2016). The Panama Canal, opened in 1914, has undergone an expansion so that ever-growing tankers can make use of the facility. New Panamax vessels with dimensions of 427 m in length, a 55 m beam and depth of 18 m will be able to use the new locks (Marine Insight 2016). The new Canal dimensions will not be able to fit vessels categorized as VLCCs and ULCCs, or supertankers.

Aframax tankers, or Large Range 2 (LR2), have a DWT of less than 120,000 and the name is based on the AFRA tanker rate system (Marine Insight 2016). The latter was a rating system started by Shell in 1954 to categorize the size and purpose of vessels (AUUUU.com 2015). Aframax tankers are generally used in the North Sea, Black Sea, the Caribbean Sea, the China Sea and the Mediterranean (Marine Insight 2016). Aframax tankers have a capacity of approximately 650,000 bbls (National Research Council 1998).

Suezmax, ranging between 120,000 and 200,000 DWT, refers to the category of vessels able to pass through Egypt’s Suez Canal (Rodrigo de Larrucea 2010). Once regarded as supertankers, this distinction is now reserved for the much larger VLCC and ULCC vessels. Suezmax tankers have a capacity of approximately 1,000,000 bbls (Kinder Morgan Canada 2013). The VLCC can transport between 200,000 and 320,000 DWT and average 331 meters in length and 60 meters in width. The capacity of a VLCC is approximately 2,000,000 bbls (US EIA 2014; Maritime-Connector.com n.d.; AllOilTank.com n.d.). The latest generation of supertanker is the Ultra Large Crude Carrier (ULCC) and has a capacity of up to 550,000 DWT, or approximately 4,000,000 bbls (US EIA 2014; Maritime-Connector.com n.d.; AllOilTank.com n.d.). It is interesting to note that because of their sheer size, they are usually not permitted to enter a port fully loaded (Huber 2010).

January 2018 An Economic and Environmental Assessment of 31 Eastern Canadian Crude Oil Imports

As of end-2016, there were 688 VLCCs, 509 Suezmaxes/LR3, 971 Aframaxes/LR2, 430 Panamaxes/LR1 and 1,986 MR-type (TankerOperator 2017). For comparison, as of January 2008, there were 492 VLCCs, 360 Suezmaxes, 783 Aframaxes, 329 Panamaxes and 981 MR-type (or Seawaymaxes) (TankerOperator 2008).

While there are numerous marine terminals in Canada, there are seven marine terminals suitable for loading and offloading oil. Table 2.5 illustrates oil marine terminals in Canada. It is interesting to note that a single terminal is found on the west coast, the Westridge Marine Terminal in Burnaby. The terminal lies at the end of the TMX pipeline, transporting crude oil from Edmonton, AB to Burnaby, BC.

Table 2.5: Oil Marine Terminals in Canada Name Operator Location Port of Come By Chance North Atlantic Refining Come By Chance, NL Canaport Crude Receiving Terminal Irving Oil Saint John, NB Port of Sainte Victoire Kildar Services ULC Sorel-Tracey, QC Port of Montréal Marine Terminal Suncor Energy Montréal, QC Port of Montréal East Suncor Energy Montréal, QC Port of QC Valero Lévis, QC Westridge Marine Terminal Kinder Morgan Canada Burnaby, BC

Source: (Oil Sands Magazine 2017a)

Montréal can also accept at least Panamax (60,000-80,000 DTW) size tankers directly from the eastern offshore projects.

January 2018 32 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 33 Eastern Canadian Crude Oil Imports Chapter 3: Methodology and Analysis

This Chapter reviews the methodology of various models and calculations used in this study. It is divided into two sections: a) a discussion of the methodology and scenarios used and b) the models and their approaches. The latter discusses the various modelling approaches and their assumptions. It is subsequently divided into three parts: the crude flow model, the cost of feedstock model and the emissions/LCA model. Each model is applied to the previously mentioned four scenarios, as well as the Base Case.

Overview of Methodology and Description of Scenarios This section provides an overview of the scenarios and the various modelling approaches used in this study. Greater details of the models used are discussed separately later in this chapter.

The scope of this study is to analyze the potential complete or partial substitution of imported foreign oil in the central and eastern Canadian refinery market with domestically-sourced oil supply. The research provides a cost and emissions comparison of four potential scenarios of feedstock for eastern Canadian refineries, substituting domestic versus foreign crude in central and eastern Canadian refinery markets. Modelling the different scenarios and their effects are in turn compared to the Base Case.

The Base Case provides a snap shot of the crude flows in 2016, representing the reconstruction of current flows (Canadian and imported feedstock supply). It also explores the refineries themselves, their technologies, as well as existing and potential transportation routes for western and eastern Canadian oil to central and eastern refineries, as used in 2016. The data however is incomplete and CERI made assumptions where information is either missing or suppressed in the collected statistics. For instance, if crude brands of imported oil are not certain per refinery from an export country, the most abundant brands available in the export country were taken. Or, if there is no certainty of how crude oil is supplied per refinery from western Canada, an assumption was made based on the distances from the western crude sources, railway network and other available information. The objective was to reconstruct the existing flows accurately.

While there are an infinite number of potential scenarios for displacing central and eastern refineries’ foreign oil imports, CERI created four scenarios defined in terms of two separate uncertainties: the level of infrastructure available to transport crude to central and eastern refineries transportation infrastructure (existing versus expanded) and the general approach of decision-making (a market- or policy-based approach). This is illustrated in Figure 3.1.

January 2018 34 Canadian Energy Research Institute

Figure 3.1: The Four Scenarios

Expanded Infrastructure

Made in Expanded Canada Access Social Push/ Economic Pull/ Policy-based Market-based Approach Approach International Current Social Reality Concerns

Existing Infrastructure

Mirroring the four quadrants and their scenarios in Figure 3.1, this research explores four key questions:

1. How much additional oil can be economically sourced through existing infrastructure to central and eastern refineries (from west and from east) substituting foreign oil, and how will this impact emissions? In this case, more expensive foreign oil volumes are substituted.

2. How would the cost of feedstock and emissions levels differ if oil from authoritarian states was substituted?

3. If there was additional transportation pipeline infrastructure (such as the cancelled Energy East project), how much more “economic” oil could be brought to central and eastern refineries and at what emissions levels?

4. What would the cost of feedstock and emissions levels be if all foreign crude was substituted with Canadian crude using expanded transport infrastructure?

Before exploring the four scenarios, it is prudent to review several major assumptions.

First, this research is not from the perspective of the producers and transportation sector, but from the refinery level, and more particularly, from central and eastern Canadian refineries. As such, this study explores the cost impacts in course of substitution for the refineries, but not for producers or transportation companies. Note that in this study, midstream is defined as the

January 2018 An Economic and Environmental Assessment of 35 Eastern Canadian Crude Oil Imports refining sector, while services of oil delivery (by any mode) is defined as the transportation sector. This deviates from the industry conventional value chain breakdown, but it is done so to be more consistent with LCA models used for the study (typically the transportation sector would be under midstream, and refining would fall under downstream activities).

Second, this study assumes that Western Canadian crude oil used by eastern Canadian refineries in the various scenarios is assumed to be taken from the current export markets and redirected to eastern Canadian refineries. As such, this analysis does not assume incremental production to offset Canadian crude oil displacing foreign crude in eastern Canadian refineries.

In addition, it is beyond the scope of this study to delve into downstream markets and implications due to substitution, if any. CERI does not explore where the refined petroleum products go, but focuses on displacing like-for-like foreign oil with domestically-sourced equivalents (i.e., light-for-light, etc.). The latter assumption enables CERI to assume that refineries’ yields in the Base Case and in the various scenarios remains the same, and allows a comparison of costs of feedstock and emissions between different hypothetical scenarios while keeping the sales variable constant. Recall, this a scenario-based approach and, as such, is not a forecast. This means there is limited impact on GDP associated with indirect and induced economic activities from changes in the trade balance (lower value of imports).

The four scenarios and their main assumptions are summarized below.

Current Reality adopts a market-based approach, optimizing for cost of feedstock and emissions. However, the difference is that it assumes crude oil can be transported from western and eastern Canada to eastern Canadian refineries via existing infrastructure – pipelines, marine tankers, or rail. Crude oil substitutes feedstock in eastern Canadian refineries utilizing three modes of transport. Enbridge Mainline (Line 5 and Line 78) connects Hardisty, AB to Sarnia, ON, while Enbridge’s Line 9 reversal transports oil from Sarnia to Montréal. Quebec City is connected via two tankers from Montréal. This scenario will identify the throughput capacity of existing pipelines and rail systems to move additional oil from west to central and eastern refineries. The remainder will be supplied by foreign crude oil from the sources which supplied central and eastern refineries in 2016. This is a market-based approach to substituting foreign crude oil in Canadian refineries meaning that more expensive foreign crude is displaced; cheaper foreign crude is kept in the slate of refineries. Proponents include the transportation sector and refineries. Of the four scenarios, Current Reality represents the closest to status quo, simply a more optimal solution regarding costs of feedstock and emissions utilizing the existing infrastructure available.

Expanded Access is a market-based approach. Western and eastern Canadian crude oil is transported to central and eastern refineries via an expanded transportation infrastructure. The difference here is that Expanded Access allows for more domestic volumes to be substituted economically. Thus, even if more is available, if Canadian oil is more expensive at the refinery gate compared to foreign oil, in this market-driven decision making a refinery will prefer the cheaper imports (if it can get the same desired yields). Prices of particular brands of foreign and

January 2018 36 Canadian Energy Research Institute

domestic oil as well as transportation costs play a role in the selection of the crude intake slate. Tankers are cheaper transport options than pipelines and rail. As western production is far from the central and eastern refinery market, transportation costs by pipeline and rail will almost always be at a cost disadvantage to foreign tanker costs. In other words, in the Expanded Access scenario, more expensive foreign crude is displaced; cheaper foreign crude is kept in the slate of refineries.

Made in Canada assumes that all Canadian crude, be it from western or eastern parts of the country, will substitute for all foreign imported crude oil via an expanded transportation infrastructure. The pipeline infrastructure with a new pipeline is used and transports oil from Hardisty to Saint John, NB, via Montréal and Lévis. This is in addition to existing infrastructure, mainly the Enbridge Mainline (Line 5 and Line 78), which connects Hardisty, AB to Sarnia, ON, while Enbridge’s Line 9 reversal transports oil from Sarnia to Montréal. While western Canadian crude is used in refineries in ON and QC, as well as a portion of Irving refineries feedstock, the remaining refineries and feedstock demands are satisfied with eastern Canadian oil production. This scenario is often categorized by a nationalist or protectionist stance, and is either highlighted by security of supply or keeping the macroeconomic benefits within Canada, particularly for a country which is a major producer of oil.

International Social Concerns assumes that crude oil will be transported to eastern markets via the existing pipeline infrastructure and rail. This scenario, however, assumes that domestically- sourced crude oil will substitute for foreign crude oil coming from countries that have generated concern by international organizations for their treatment of their citizens or their environment. CERI reviewed several indices by internationally recognized organizations including those produced by the World Bank (various), the United Nations (Human Development Index) and the Freedom House, as well as other organizations. The indices range from ranking the democratic process to human rights to quality-of-life. For this study, however, CERI utilized the widely-cited Economist Intelligence Unit’s Democracy Index 2016. Often cited in peer-reviewed journals, the Democracy Index includes five diverse elements to determine a nation’s classification: electoral process/pluralism, functioning of government, political participation, political culture, and civil liberties. While it is not perfect, it provides a proxy for reflecting social concerns. Nations fit into four categories: full democracy, flawed democracy, hybrid regime, and authoritarian (The Economist Intelligence Unit 2017). Canada, Norway, Denmark, the United Kingdom, Colombia, and the US are classified as either full or flawed democracies. Except for Nigeria (hybrid regime), the rest of the countries that supply Canada’s imported oil are classified as authoritarian, according to the index. As such, this scenario substitutes all foreign oil that are not classified as either full or flawed democracies. This is a policy-based approach to substituting foreign crude oil in central and eastern Canadian refineries. It is important to note that more expensive oil from democratic states is kept in the crude slate. This approach allows CERI to assess the direct impact on costs and emissions tied to substitution of oil from states that have caused international concern for the treatment of their citizens or environment.

January 2018 An Economic and Environmental Assessment of 37 Eastern Canadian Crude Oil Imports

The four scenarios are highlighted by two critical uncertainties, based on the level of infrastructure available to transport crude to central and eastern refineries (y-axis) and the general approach of decision-making (x-axis), whether a market- or policy-based approach (Figure 3.1). CERI identifies and quantifies the costs to refiners and effects on emissions in four very different scenarios, guided by two critical uncertainties. Each of which contain several unique assumptions.

First, the transportation-related uncertainty determines whether the scenario is influenced by transporting crude through existing pipeline, railway and marine infrastructure or transporting crude through existing pipeline, railway, and marine infrastructure plus additional, or expanded, pipeline infrastructure. The available capacity of transporting crude is an important factor, determining in part the amount and how crude is transported to central and eastern refineries, displacing foreign crude oils. Existing transportation infrastructure allows more Canadian crude from the west and east to central and eastern Canadian refinery markets, however, it is not sufficient to substitute all foreign oil. The major infrastructural bottleneck for western crude is Line 9’s capacity to supply any refinery east of Montréal.

This affects the Made in Canada and Expanded Access scenarios. In these two cases of an expanded infrastructure, CERI assumes a new pipeline extending from Hardisty, AB to Saint John, NB via Montréal and Lévis, QC. To simplify matters, CERI assumes that the route of the pipeline, its capacity and toll structure are the same as the now-cancelled Energy East pipeline, proposed by TransCanada Pipeline (TCPL). Energy East was cancelled on October 5, 2017.

Second, CERI also examines whether partially or completely substituting foreign crude oil is fueled by a market-based approach (or economic pull) or policy-based approach (or social push or government policy). The general approach of decision-making and whether a market- or policy-based approach, the research question of partially or completely substituting foreign crude oil is fueled by various arguments. While each has their own motives, they are typically driven by economic (a market-based approach) or social rationale (a policy-based approach).

The International Social Concerns scenario is reflective of a policy fueled by social “push” stemming from an increasing awareness in elements of society asking, “where do the products we consume originate?” or “what are the labour and environmental standards for manufacturing in those countries we buy from?” This trend has ramifications not only for the energy sector but other goods and services that Canada trades.

CERI is not promoting policy or evaluating its relevance but exploring examples of policy initiatives that could possibly affect the substitution of foreign crude oil and thus the central and eastern Canadian refineries. As such, CERI does not discuss the type of policy instruments to implement such programs, or their effect on costs and emissions on the refinery-level.

This CERI study will show market- and socially-pushed scenario outcomes, via existing and expanded transportation infrastructure, which could serve as a good indication for Canadians on how beneficial or costly such substitution could be. This research is a first of its kind comparison

January 2018 38 Canadian Energy Research Institute

that has not been done by any organization. However, in allowing CERI to make a comparison across the four scenarios,

CERI uses its proprietary Crude Flow Model and its Costs of Feedstock Model, as well as utilizing a life-cycle assessment (LCA) of greenhouse gas (GHG) emissions of individual crude oils used in the study. Recall, CERI is substituting like for like crude oils, substituting crude oil from all over the world with the like Canadian equivalent. The objective of the emissions modelling is to establish an emission intensity profile for each crude oil used in the central and eastern Canadian refinery market. The latter is done through utilizing the publicly available GHG estimation models: OPGEE (upstream emissions) and PRELIM (midstream emissions).

Figure 3.2 illustrates the four different modelling approaches and calculations and the relationship between them. There are several major components, or elements, to this study. Using the established crude flows for each of the scenarios, the following are, in a sense, the “inputs” into the costs of feedstock model and the emissions model. Costs of feedstock and emissions are influenced by the flow of crude in the four scenarios. Modelling the different scenarios, their effects are in turn compared to the Base Case – a snap shot of crude flows in 2016.

Figure 3.2: Schematic of the Modelling Approaches

Crude Flows Model

Costs of Emissions/ Feedstock LCA Model Model

The crude flows from western and eastern Canada that displace foreign oil by the various scenarios is a critical component, impacting the other models. Costs of feedstock model and the emissions modelling determine the various costs and emissions of the four scenarios.

Each of these models and their assumptions are discussed in greater detail in the following section.

It is, however, important to mention that, despite the complexity of the various approaches, one of the most challenging elements of this study is the lack of data, particularly on the refinery level. One of the early core research questions was whether partial or entire substitution of imported crude in the central and eastern refineries will be of benefit or cost to Canada. This

January 2018 An Economic and Environmental Assessment of 39 Eastern Canadian Crude Oil Imports was initially answered by utilizing the cost-benefit analysis (CBA) from the unique perspective of the eastern Canadian refiner. Providing a robust method for evaluating the costs and benefits, including economic and non-economic impacts, this method is ideal for comparing a policy change, projects, or a mode of action in today’s dollars to a society. And while the CBA is far from perfect, the CBA provides a framework that identifies, quantifies, and compares the costs and benefits of a proposed policy or mode of action. The CBA approach was, unfortunately, significantly limited by the data available, and was subsequently altered to the approach instead.

Models and Their Approaches The following discusses the four models used in this study, their assumptions, and forecasts, where applicable. This section is divided into three parts: crude flows model, cost of feedstock model and emissions/LCA model. The discussion is based on the Base Case. This section discusses the how and the why, pertinent to each model. The results of these models within the context of each of the four scenarios are discussed in Chapter 4.

Crude Flows Model CERI’s Crude Flow Model lies at the core of the modelling approach used in this study. The crude flows from western and eastern Canada that displace foreign oil are determined by the various scenarios as a critical component, impacting the other models. Costs of feedstock, emissions and calculating the economic effects are influenced by the flow of crude in the four scenarios.

This section is divided into three parts: establishing a Base Case, calculating the stock of Canadian crude oil available for substitution purposes and discussing the assumptions used in modelling the scenario’s crude flows.

Establishing the Base Case This section delves into the eight eastern Canadian refineries and various important metrics, including their location, capacity, utilization rates, crude intakes (or crude slate) and mode of supply (transportation). The data represents 2016. Consumption of feedstock (crude slate) and product slate of the eight refineries is reviewed, establishing the current state of refineries in eastern Canada. The crude slate is reviewed more closely, breaking it down by domestic-sourced crude and foreign-sourced crude.

The data for this study was obtained from several sources as mentioned in Chapter 2. If the data was suppressed, missing, or conflicted, CERI reconciled using multiple sources to infer quality and certainty in data.

Refining capacity in eastern Canada is represented by eight refineries with a total capacity of 1,228 Mbpd. Four refineries reside in ON, two in QC, and one each in NB and NL & Labrador. All eight refineries, their capacities, utilization rates, crude intakes and mode of supply are illustrated in Table 3.1.

January 2018 40 Canadian Energy Research Institute

Table 3.1: Crude Intake by Eastern Canadian Refineries, by Oil Type (Mbpd) Province Refinery Capacity Capacity Utilization Total Light SCO Heavy Bitumen Available by Rate Intake Mode of Province (%) Transport ON Imperial, 121 86% 104.1 51.4 21.5 6.0 25.2 Pipeline Sarnia Shell Canada, 75 88% 65.9 37.5 13.6 14.8 - Pipeline Corunna

Suncor 393 Energy, 85 92% 77.8 47.0 16.1 14.8 - Pipeline Sarnia Imperial, Pipeline, 112 86% 96.3 61.7 19.9 14.8 - Nanticoke Rail Suncor Energy, 137 92% 125.4 109.0 - - 16.4 Pipeline, Montreal 402 Tanker, QC Rail Valero, Lévis 265 88% 232.8 131.9 81.2 8.1 11.6

NB Irving Oil, Tanker, 318 318 87% 277.8 250.6 11.9 15.3 - Saint John Rail NL North Atlantic Refining, 115 155 81% 93.1 93.1 - - - Tanker Come by Chance Total 1,228 1,228 1,073 758.8 180.1 80.9 53.1 Percent 73% 15% 7% 5%

Data Source: CERI Crude Flow Model. Table by CERI.

Note that for this study, the intake for QC was altered from the factual data of 2016. In 2016, QC refinery utilization rates did not seem to be representative across the refining industry in Canada (an average 78 percent for two refineries based on CERI calculations of Statistics Canada data) (Statistics Canada 2017c, 2017d). For the purposes of modelling, an adjusted utilization rate of 88 percent was assumed for Valero, and 92 percent for the Suncor Energy refinery. Suncor Energy’s estimate was taken from the company Annual Report (Suncor Energy Inc. 2017a). For reference, the factual 2016 import volume in QC was 214.1 Mbpd. However, due to an increase in utilization rates, the modelled 2016 import volume for QC is 9.8 percent higher than factual – 235 Mbpd (Government of Canada 2017). Hence, eastern offshore and western supply were also increased by the same rate. Modelled and factual imports are presented in Appendix A.

Light oil prevails in the supply slate for the four provinces comprising 73 percent, followed by synthetic crude (SCO) with 15 percent in the crude slate; heavy and bitumen both comprise 12 percent of the crude intake. This is illustrated in Figure 3.3.

January 2018 An Economic and Environmental Assessment of 41 Eastern Canadian Crude Oil Imports

Figure 3.3: Crude Intake by Type by Province (Mbpd)

Data Source: CERI Crude Flow Model. Figure by CERI.

Fifty-six percent of oil into the eastern region is imported, while 39 percent comes from western Canada and five percent is supplied from Canadian eastern offshore assets (offshore NL & Labrador as well as 0.6 Mbpd from ON). Among eastern Canadian refineries, ON receives the highest amount of western crude (almost 83 percent), followed by QC (33 percent) and NB (4 percent). NL & Labrador does not receive oil from western provinces.

The largest exporters to Canada are the US, Saudi Arabia, Algeria, Nigeria and Norway (Government of Canada 2017; NEB 2017f; Statistics Canada 2017a). Detailed information on the sources of oil for eastern refiners is provided in Table 3.2 (imports per country in the last column are rounded; detailed information can be found in Appendix B). Based on the import data, up to 601 Mbpd could be substituted by Canadian crude oil.

January 2018 42 Canadian Energy Research Institute

Table 3.2: Crude Intake by Eastern Canadian Refineries, by Source

Western Total Canada Eastern Imports from Intake Supply Canada Supply Imported Countries Province Refinery (Mbpd) (% / Mbpd) (% / Mbpd) (% / Mbpd) (Mbpd (Rounded)) Imperial 104.1 83.0 / 86.5 - 17 / 17.6 Shell Canada 65.9 83.0 / 54.8 - 17 / 11.1 ON US 58 Suncor Energy 77.8 83.0 / 64.6 - 17 / 13.1 Imperial 96.3 82.4 / 79.4 0.6 / 0.6 16.8 / 16.3 ON 344 82.9 / 285.3 0.2 / 0.6 16.9 / 58.1 Suncor Energy 125.4 13.1 / 16.4 4.6 / 5.8 82.3 / 103.2 US 100, Algeria 92, QC Kazakhstan 21, Valero 232.8 43.4 / 100.9 - 56.7 / 131.9 Nigeria 12, Others 10 QC 358 32.8/ 117.3 1.6 / 5.8 65.6 / 235.0 Saudi Arabia 87, Nigeria 45, US 34, NB Irving Oil 277.8 4.3 / 11.9 17.2 / 47.7 78.5 / 218.2 Norway 26, Others 27 North Atlantic US 49, Nigeria 18, NL 93.1 - 3.6 / 3.3 96.4 / 89.8 Refining Norway 14, Others 9 Atlantic Canada 371 3.2 / 11.9 13.8 / 51.0 83 / 307.9 Total 1,073 39 / 414.5 5 / 57.5 55 / 601.0 Data Source: CERI Crude Flows Model. Table by CERI.

The following describes the flows of crude to the eastern refinery market in the Base Case. To obtain this, CERI used many sources as previously mentioned in Chapter 2. Statistics Canada information presented a detailed view of ON and QC intake of oil from western and eastern provinces, as well as intake by province by type of crude – bitumen, heavy, light, and SCO. Statistics Canada trade information showed volumes and source of foreign oil per province (Statistics Canada 2017a). In ON, North Dakota was the foreign exporter. Its volume was distributed proportionally to all four refineries, as well as SCO. Bitumen was allocated to Imperial Oil’s refinery as it is the refinery in ON equipped with the coker technology.

In the case of QC, the volume of western, eastern and foreign oil was taken from Statistics Canada data on the provincial level. Clipper Data on tanker movements was used for apportioning specific volumes to a particular refinery as well as identifying transportation routes to refineries (ClipperData LLC 2017). The crude tanker shipments from Montreal to Valero data helped to allocate total volume of western oil between the two refineries. Likewise, shipment data to Portland, Maine (the origin of the Portland-Montreal pipeline), Quebec City, and Montreal ports and combining this information with Statistics Canada trade data, allowed CERI to allocate foreign oil volumes between the two refineries, as well as determine Canadian eastern offshore volumes. Utilizing Clipper Data, particular brands of imported oil were identified, which helped to assign light and heavy imported oil between refineries more accurately. This data was useful in

January 2018 An Economic and Environmental Assessment of 43 Eastern Canadian Crude Oil Imports reconciling the difference with Statistics Canada data as the latter showed a large volume of SCO which was not consistent with total volume of western crude (ClipperData LLC 2017; Statistics Canada 2017a). Thus, part of what Statistics Canada marked as SCO was marked as light crude oil in the study Base Case. Heavy and bitumen volumes were also adjusted slightly between these categories to reconcile refinery intake information, oil shipments data, and Statistics Canada data.

NB’s Irving oil feedstock was more easily established than QC’s, as the refinery stands on water, and the bulk of their intake arrive in tankers. Statistics Canada trade data (Statistics Canada 2017a) as well as Clipper Data (ClipperData LLC 2017) were sufficient to arrive at volumes of foreign and eastern Canadian crude and type of oil. Western crude was derived as the difference between the total intake and the amount delivered by tankers. NL’s North Atlantic Refining’s intake was also more easily established at it also stands on water allowing for using both Statistics Canada trade data and Clipper Data to get a full picture of feedstock supply.

Transportation routes were identified for all the refineries using multiple sources. As each refinery enjoys specific transportation options, combining a number of sources allowed CERI to establish a full picture of supply routes. Statistics Canada provided information that ON was fully supplied via pipelines (Line 5 and 78 enters ON). QC’s crude oil supply was established via solving for volumes from tanker shipments for Valero and Portland-Montreal pipeline intake; the remaining portion was delivered via Line 9.

Rail usage in the east was identified as follows. As 2016 data was limited, the year 2015 was studied in more detail to understand shipment volumes and routes. Data from 2015 showed domestic rail movements total volume of 53 Mbpd (NEB 2017e). Rail movements in 2015 for fuel oil and crude petroleum followed routes such as a) from AB to QC, ON and NB, b) from SK and MB to QC and ON, and c) from the US to QC (Canadian Pacific 2016; CAPP 2017a, 2017b; Statistics Canada 2017b). Domestic rail usage in the east was identified as limited to a relatively small number in 2016 – 11.9 Mbpd (CERI estimate). The number comes as a difference between movements of oil from west in 2016 in the amount of 100 mbpd (CAPP 2016), and export by rail data for 2016 (NEB 2017h).

To simplify the modelling, all 11.9 Mbpd in 2016 were assigned to NB’s refinery, rather than being distributed between the two refineries in QC and Irving Oil. For reference, railway offloading capacity is estimated at 255 Mbpd for all the central and eastern refineries (namely 20 Mbpd for Nanticoke, ON, 60 Mbpd for Lévis, QC, 30 Mbpd for Montreal, QC, and 145 Mbpd for Saint John, NB) (CAPP 2017b).

Finally, to identify which western province supplied which province in the east, Statistics Canada data (Statistics Canada 2016) was used for 2015 as a proxy which showed that MB and SK’s volumes of oil went to ON (as was assigned as such in the Base Case). Thus, ON’s demand for feedstock was first “satisfied” predominantly from these provinces; the rest came from AB. AB oil, on the other hand, was assigned to all provinces except for NL. Bitumen, heavy oil and SCO was assigned exclusively to AB in the Base Case. In addition, as rail movements in 2015 (for export

January 2018 44 Canadian Energy Research Institute

and domestically) predominantly originate from AB and Atlantic Canada’s supply in that year was also from AB, the above-mentioned volume – 11.9 Mbpd – was also allocated to this province.

Below is a description of crude flows in the Base Case, based on assumptions and data sources.

The single foreign exporter to ON’s four refineries was the US (58 Mbpd). Light oil comes from North Dakota and is modelled in this study to be transported through Enbridge Line 81 to Clearbrook, MN and further through the Enbridge Mainline system (Line 5 entering Sarnia). Canadian light, heavy, and bitumen crude from three provinces – AB, SK, and MB – flow through various lines of the Enbridge Mainline and enter ON via Line 5 and 78. AB supplies 206 Mbpd, followed by SK’s 72.6 Mbpd and MB’s 6.4 Mbpd.

Suncor’s Montreal refinery imports light oil from four countries – US (92.7 Mbpd), Azerbaijan (4.5 Mbpd), UK (4.1 Mbpd) and Norway (1.9 Mbpd). For crude that comes from the US, 62.1 Mbpd comes from North Dakota and Michigan through the Enbridge Mainline and Line 9 (going from Sarnia to Montreal). All other crude, including 30.6 Mbpd from Texas, is transported by tankers from loading ports to Portland, Maine and then transported via the Portland-Montreal pipeline to the refinery. Canadian supplies include 16.4 Mbpd of bitumen and 5.8 Mbpd of light crude that comes from eastern offshore assets. Bitumen comes through the Enbridge Mainline and Line 9, while the eastern crude follows the path of international oil via Portland.

With Line 9 reversal and the purchase of two Panamax tankers by Valero, with the goal to move 50-60% (or 130-160 Mbpd) from Montreal to Lévis (Van Praet 2014), the crude intake slate in the Valero refinery has changed dramatically. In 2016, it used 101 Mbpd of western Canadian crude, which includes synthetic, bitumen and heavy. The imported light oil came from four countries: Algeria (92.1 Mbpd), Kazakhstan (21.1 Mbpd), Nigeria (11.5 Mbpd), and US (Texas) (7.2 Mbpd). All foreign oil comes to Valero by tanker.

Irving Oil’s refinery in NB relies more heavily on imported oil and eastern offshore supply. Western Canada supplied 11.9 Mbpd of SCO via rail, 47.7 Mbpd of light crude came by tankers from Hibernia and other eastern offshore projects, and 218.2 Mbpd came by tankers from predominantly four countries. Except for 15.3 Mbpd of heavy oil coming from Colombia and the Ivory Coast, the remaining imported oil was light. The largest supplier of imported feedstock is Saudi Arabia (86.7 Mbpd), followed by Nigeria (45 Mbpd), United States (34 Mbpd), Norway (24 Mbpd), Ivory Coast (12.6 Mbpd), Colombia (5.3 Mbpd), Azerbaijan (2.8 Mbpd) and Congo (2.7 Mbpd).

Lastly, NL’s North Atlantic Refinery was supplied almost entirely by foreign crude via tankers. Eastern offshore light oil accounted for 3.3 Mbpd out of a modelled 93.7 Mbpd intake for the refinery. Imported oil comes from the US (49 Mbpd), Nigeria (18.3 Mbpd), Norway (13.7 Mbpd), UK (6.2 Mbpd) and Denmark (1.7 Mbpd).

Figure 3.4 shows the transportation routes of Canadian crude in the Base Case.

January 2018 An Economic and Environmental Assessment of 45 Eastern Canadian Crude Oil Imports

Figure 3.4: Canadian Oil Supply Routes to Central and Eastern Refineries – Base Case (Mbpd)

Data Sources: (CAPP 2017b; Enbridge Inc. n.d.; NEB 2017c). Figure by CERI, based on cartography from (Enbridge Inc. n.d.). Note: L5 – Line 5 pipeline; L78 – Line 78 pipeline, L9 – Line 9 pipeline, P-M - Portland–Montréal Pipeline. Sarnia (3) illustrates the number of refineries located in the Sarnia region.

There are two interesting key findings. First, in 2016 the reversed Line 9 was used at the level of 117 Mbpd out of its throughput capacity 285 Mbpd (assumed 95 percent of its total capacity). The lower than expected level may potentially be explained by the Fort McMurray wild fires in 2016 or other factors. Second, eastern offshore oil has limited use in central and eastern refineries due to some infrastructure restrictions. The largest user is Irving Oil with 47.7 Mbpd, followed by Suncor Energy in Montreal with 5.8 Mbpd, and NL & Labrador’s refinery with 3.3 Mbpd. According to the National Energy Board (NEB 2017c), the rest of NL Offshore Light production in 2015 went to US PADD I (116 Mbpd), Asia and Europe (20 Mbpd) and the US Gulf Coast (4 Mbpd).

The availability and usage of crude and transportation infrastructure by central and eastern refineries in the Base Case is illustrated in Figure 3.5. The top portion of the figure lists the various Canadian types of crude, ranging from AB Light and NL Offshore Light to AB Bitumen, in terms of availability and the amount used. The bottom portion of the figure, on the other hand, illustrates the various transportation modes potentially used in Canada, in terms of available infrastructure and their usage. In short, this figure provides a snap shot in time (2016) of the current crude flows from western and eastern Canada to the eastern Canadian refineries. Canada has enough light oil to be used in the eastern and western refinery markets.

January 2018 46 Canadian Energy Research Institute

Figure 3.5: Availability and Usage of Crude and Infrastructure by Eastern Canadian Refineries – Base Case (Mbpd)

0 200 400 600 800 1000 1200 1400 1600

AB Light 522.0 59.8

SK Light 149.8 72.6

AB SCO 896.8 164.1

Crude AB Heavy 125.6 57.2

SK Heavy 225.5 0.0

AB Bitumen 1423.3 53.2

NL Offshore Light 234.5 56.8

New infrastructue PL 1045.0 0.0

988.0

Mainline (Line78, 5) PL 522.8

Portland-Montreal PL 270.8 41.1

Line 9 PL 285.0

179.4 Transportation

Valero's tankers 159.0 100.9

Rail 255.0 12.5

Available Infrastructure Available Used

Data Source: CERI Crude Flows Model. Figure by CERI.

Note: The volumes shown for Mainline (Line 78 and Line 5) represent Canadian crudes for Canadian refineries. The graph does not show movements in the Mainline of Canadian or US crudes destined for US refineries.

January 2018 An Economic and Environmental Assessment of 47 Eastern Canadian Crude Oil Imports

It should be noted that the new pipeline infrastructure does not currently exist; it impacts the Made in Canada and Expanded Access scenarios, discussed in Chapter 4.

The important input into the study’s models is the availability of western Canadian crude supply for substitution. For this study, CERI considers oil produced in AB, SK, and MB, leaving BC production out of scope as it is assumed to be used in local refineries and not likely to be used in central and eastern refineries.

Available Stock of Canadian Crude for Substitution To arrive at crude stocks available for central and eastern refineries, CERI uses the crude oil forecast from its Study 159, “Canadian Crude Oil Production Forecast” (CERI 2016). Based on average percentage of type of crude from each province, a forecast of available supply is derived from total crude oil production. This is illustrated in Figure 3.6. Note AB bitumen includes bitumen, not diluent.

Figure 3.6: Canadian Crude Oil Production Forecast, 2017-2027 (Mbpd)

6,000

5,500

5,000

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

- 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

AB Light NL Offshore Light SK Light MB Light AB SCO SK Heavy AB Heavy AB Bitumen

Data Source: (CERI 2016). Figure by CERI.

The model assumes there are eight Canadian oil types modelled that represent the spectrum of the current crude intake (as of 2016) by refineries in eastern Canada. Four of them are based on existing crudes or blends – AB Bitumen as a proxy for Western Canadian Select, AB Heavy as a proxy for Western Canadian Blend, AB SCO as a proxy for Synthetic Sweet Blend, and NL Offshore Light as a proxy for Hibernia. The other four Canadian crudes that include AB Light, SK Light, MB

January 2018 48 Canadian Energy Research Institute

Light and ON Light are assumed to be blends of either two or three existing crude oil blends selected from Mixed Sweet Blend, Mixed Sour Blend, Light Sour Blend or Midale in various ratios based on (COLC 2016) data. These crudes are highlighted in blue in Appendix C, please refer to Table C.1. The ratios are also detailed in the same table.

To establish available stock for substitution purposes, the demand from western refineries is subtracted from the production forecast.

The crude utilization in western Canadian refineries is shown in Table 3.3. Utilization rates are taken from the refineries’ annual reports or websites where available (the average of 2017/2016 or 2016/2015 was taken when information was available). For Chevron, Shell Canada, North West Refining, and Fed Co-op, 90 percent utilization was assumed due to lack of data. The demand for light, SCO, heavy and bitumen crude per refinery was determined based on (Statistics Canada 2017d) demand province-wide, and then adjusted using corporate websites and annual reports of refineries. Specifically, for AB and BC, the shares of each type of oil were calculated for each province for 2016 and are provided in Table 3.3.

Table 3.3: Oil Type Shares as Input to Western Canadian Refineries Oil Type Oil Type Share in Refineries Intake (%) AB BC Conventional crude oil (light) 23.6% 32.5% Conventional crude oil (heavy) 6.7% 4.5% Synthetic crude oil (light) 59.9% 60.3% Crude bitumen charged 9.8% 0% Data Sources: (Statistics Canada 2017d), CERI calculations. Table by CERI.

These ratios for the above table were applied to both BC refineries and in AB, unless more detailed information was available. For instance, in AB, the Suncor Refinery and North West Refining are assumed to receive bitumen. Oil demand by type for the Fed Co-op refinery in SK was available on the refinery website (Federated Co-operatives Limited 2015). The resulting Table 3.4 shows modelled crude oil demand by western Canadian refineries.

January 2018 An Economic and Environmental Assessment of 49 Eastern Canadian Crude Oil Imports

Table 3.4: Crude Oil Demand by Western Canadian Refineries

Utilization Province Refinery Location Capacity Rate Throughput Light SCO Heavy Bitumen (Mbpd) (%) (Mbpd) (Mbpd) (Mbpd) (Mbpd) (Mbpd) BC Husky Prince 12 84 10.1 4.0 6.1 - - George BC Chevron Burnaby 57 90* 51.3 18.1 30.9 2.3 - AB Suncor Edmonton 142 92 129.9*** - - - 129.9 AB Imperial Strathcona 187 89 166.4 39.2 99.7 11.1 16.4 AB Shell Scotford 100 90* 90.0 21.2 39.9 20.0 8.9 Canada AB NW Sturgeon 50** 90* 45.0 - - - 45.0 Refining Country SK Fed Co-op Regina 130 90 * 117.0 - 63.0 54.0 - TOTAL 678 609.7 82.5 239.6 87.5 200.1

Data Sources: (Statistics Canada 2017d), various refinery websites, CERI estimates. Figure by CERI. Notes: *Utilization assumed by CERI; **For NW refining, total bitumen capacity was used; ***Suncor Edmonton refinery was assumed to intake bitumen as its feedstock ((Suncor Energy Inc. 2017b) suggests that the refinery processes approximately 41 Mbpd of blended bitumen, 44 Mbpd of sour SCO, and 57 Mbpd of sweet SCO). As bitumen and SCO are not used for substitution of foreign crudes, this assumption does not impact the outcome of the study, but impacts the availability levels of SCO and bitumen provided below.

The resulting available oil stock for central and eastern refineries after subtracting western refineries demand is depicted in Table 3.5. This is the total amount available for transporting to central and eastern refineries by type of crude and province.

Table 3.5: Available Oil Stock for Central and Eastern Refineries, 2017-2027 (Mbpd)

Type of Crude 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 and Province AB Heavy 126 119 115 111 107 106 103 102 102 101 102 AB Bitumen 1,423 1,565 1,661 1,717 1,758 1,817 1,910 2,027 2,130 2,310 2,415 AB Light 522 498 482 468 450 446 435 434 431 430 431 AB SCO 897 949 978 1,008 1,047 1,058 1,019 981 950 930 970 SK Light 150 149 149 150 151 152 155 157 159 161 164 SK Heavy 226 224 224 225 227 230 234 238 241 246 251 MB Light 36 35 35 35 35 35 36 36 36 37 37 NL Offshore Light 234 284 308 304 304 268 278 248 244 236 220 Sub-total Light 943 966 974 956 939 902 903 874 871 864 852 Sub-total Heavy 351 343 339 336 334 335 337 340 343 347 352 Sub-total SCO 897 949 978 1,008 1,047 1,058 1,019 981 950 930 970 Sub-total 1,423 1,565 1,661 1,717 1,758 1,817 1,910 2,027 2,130 2,310 2,415 Bitumen Total 3,614 3,823 3,952 4,018 4,078 4,113 4,168 4,222 4,294 4,452 4,589

January 2018 50 Canadian Energy Research Institute

Figure 3.7 illustrates the available crude oil for eastern Canadian refineries, as well as the demand by the refineries by crude type. The figure also shows that supply of light oil (conventional light + SCO) is enough to satisfy all the demand for light crude in the east. In fact, if all foreign oil was substituted in year 2027, there would still be 94 Mbpd of light oil left (852 Mbpd of available supply minus 758 Mbpd of refinery demand). Based on the availability of crude and demand by refineries, it is also clear that there is enough heavy, SCO and bitumen to supply central and eastern refineries’ needs.

Figure 3.7: Available Western Canadian Crude for Central and Eastern Refineries and Demand by Central and Eastern Refineries by Crude Type (Mbpd)

Light (includes Medium) Heavy

1,000 400

800 300 600 200 400

200 100

- - 2017 2019 2021 2023 2025 2027 2017 2019 2021 2023 2025 2027 Available West and East Available West East Refinery Demand East Refinery Demand Difference Difference

Synthetic Light Bitumen

1,000 2,500

800 2,000

600 1,500

400 1,000

200 500

- - 2017 2019 2021 2023 2025 2027 2017 2019 2021 2023 2025 2027 Available West Available West East Refinery Demand East Refinery Demand Difference Difference

Source: CERI Note: Western Canadian crude supply available for central and eastern refineries was calculated as western Canadian crude production minus demand by western refineries.

January 2018 An Economic and Environmental Assessment of 51 Eastern Canadian Crude Oil Imports

Modelling Scenario’s Flows In all the scenarios, imported oil per refinery was substituted with Canadian crude using the following guiding principles:

1. Foreign oil was always displaced with the same oil type (light oil was substituted with light, heavy with heavy). This approach ensured that a) refineries can process crude of the same quality without a need for retrofit and/or expansion of their technologies, and b) that refinery yields will remain the same. The above-mentioned are important assumptions to modelling as CERI aims to account and measure effects of substitution of imported oil and isolate the modelling from other effects (e.g., modelling different yields leading to different downstream sales compared to the Base Case 2016 situation).

2. Availability of certain crude provided a “stacking order” in the substitution. If the required Canadian oil was not available in the volume needed from a source, the next available source of the required oil was used.

3. Western Canadian crude was used more in substitution in ON and QC, while eastern offshore Canadian crude was used in substitution in NL and NB. However, eastern oil was also modelled as far as Montreal’s refinery, and western oil as far as NB.

4. Transportation infrastructure capacities also served as constraints: Line 5 and Line 78 pipelines (988 Mbpd), Line 9 pipeline (285 Mbpd), Portland-Montreal pipeline (270.8 Mbpd), rail offloading capacities at refineries (up to existing limits – 255 Mbpd), tanker’s capacity from Montreal to Valero’s refinery – up to 159 Mbpd. For all the pipelines, throughput was set as 95 percent of their total capacities.

5. For all the scenarios, pipeline delivery would take precedence over rail in the modelling. If pipeline capacity was full, but the scenario required further substitution, rail was used to compensate for lack of pipeline availability. At the same time, in the existing infrastructure scenarios, rail shipment of 11.9 Mbpd to NB’s Irving Oil was kept intact. In the Expanded Infrastructure scenarios, this shipment was switched to pipeline.

6. For the market-based scenarios – Current Reality and Expanded Access – more expensive foreign crude oil was substituted.

7. For the policy-driven International Social Concerns scenario, cost of feedstock was not considered as a factor. All oil from undemocratic states was substituted even if it was cheaper. At the same time, in this scenario, oil from democratic countries was kept fully intact even if there was cheaper Canadian crude.

8. For the policy-driven Made in Canada scenario, all foreign crude was substituted guided by point #3, irrespective if Canadian crude was more expensive than foreign.

The following section delves into some details of modelling crude flows for the four scenarios.

January 2018 52 Canadian Energy Research Institute

For the Made in Canada scenario, the crude flows modelling approach was as follows. All foreign oil was substituted with western and eastern Canadian crude (details of substitution are discussed further in Chapter 3). SK Light was used for ON refineries and in limited volume in QC (Suncor Energy refinery) until the availability of SK Light was used. AB Light and AB Heavy were used in QC and NB to substitute foreign crude. NL Offshore Light oil was used to displace all imported crude in North Atlantic Refining, the rest of available oil was modelled to be used in NB’s Irving Oil until the availability of NL Offshore Light was fully used. Valero’s and Irving Oil’s refineries used the new pipeline capacity available in the scenario, while Montreal’s Suncor Energy refinery proceeded to use the existing Mainline and Line 9. No rail deliveries were modelled.

For the Current Reality scenario, existing supply from western and eastern Canada to central and eastern refineries remains intact or unchanged. ON’s foreign oil was not substituted as foreign oil was found to be cheaper. In QC, AB Light was used until it was more expensive than foreign oil; then SK Light was used until it ran out of availability; then NL Offshore Light was used until it ran out of availability (because this oil was also used in Atlantic Canada). In all cases, more expensive oil was substituted. In NB, AB Light was used until it was more expensive than foreign crude. After that, NL Offshore was used for displacement, until it also was more expensive than foreign crude. NL Offshore was used to displace more expensive imports.

For the Expanded Access scenario, the difference with Current Reality became the availability of the expanded transportation infrastructure (it was used by Irving Oil and Valero). ON’s US foreign oil remained unsubstituted. QC’s refineries were modelled to use AB Light for more expensive foreign crude; Irving Oil’s was modelled to use AB Light via the new pipeline until it could not compete with cheaper foreign oil; then NL Offshore Light was used until it could not compete either. NL Offshore was used to displace more expensive imports – the same volume levels as in Current Reality.

Lastly, in the International Social Concerns scenario, SK Light was used in QC until it ran out of availability; NL Offshore Light was modelled to be used in NB, NL, and Valero’s refinery until it also ran out of availability; the rest was substituted with AB Light. This approach ensured that while pursuing a policy scenario, the cheapest oil was used for substitution purposes (as it is seen in section below, NL Offshore Light is cheaper in all provinces (QC, NB, and NL) than AB Light, but it is more expensive than SK Light in QC). In this scenario, additional rail movements were modelled as tanker’s capacity to Valero was not sufficient.

Costs of Feedstock Model To understand the effect on cost of oil substitution, CERI had to establish costs of feedstock for each refinery for Canadian and foreign feedstock, as well as for Canadian crudes which are not currently used in the east refineries but could be used for substitution. This section describes the methodology that was used to generate costs for each refinery. It is subsequently divided into two parts: crude prices and transportation costs; and crude oil costs at refinery gate.

January 2018 An Economic and Environmental Assessment of 53 Eastern Canadian Crude Oil Imports

Crude Oil Prices and Transportation Costs There are two elements of feedstock costs for a refinery: a) the cost of crude and b) the cost of delivery. The first element is represented by the price of a particular brand at a geographical price-point. The second element of feedstock costs for a refiner is the cost of transportation by a pipeline, rail, tanker, or a mix of the various modes.

Table 3.6 shows the crude oils and their prices used in the study. The table includes the oil type (light, heavy, SCO and bitumen), the crude brand, proxy crude (or the formula used to determine the price, and the weighted price ($CAD) in 2016. Recall, there are over 150 different types of crude and even more brands of crude (CFA 2013). Listed are the crude oils used in this study.

The presented prices are shown at location where they are sold, not at refinery gate. These were identified as crudes that are imported into Canada. Crude oil brands for foreign oil were taken from Clipper Data (ClipperData LLC 2017). In some cases, however, when a crude brand is not explicitly specified, CERI used a proxy crude from the location. Proxy crude oils are illustrated in the third column, where necessary. In four cases, crude prices were available, and the differential was not easily established. In these cases, CERI used Statistics Canada trade data to get an average price for a crude in 2016 (Government of Canada 2017; Statistics Canada 2017a). This was necessary with Denmark DUC, Equatorial Guinea Crude, and the two crude oils from Ivory Coast (Baobab and Espoir).

It is also interesting to note that 21 out of 24 imported brands of crude oil are more expensive than AB Light. The exceptions are US North Dakota, Louisiana Thunderhorse, and US Eagle Ford. Also illustrated is that 10 out of 24 are more expensive than NL Offshore Light.

January 2018 54 Canadian Energy Research Institute

Table 3.6: Crude Oil Brands Used in the Study and Their Prices

Oil Type Crude Category/ Proxy Crude or Formula Used to Name Used in the Weighted Brand Determine Price Study Price in 2016 ($CAD) Light Canada Hibernia Brent Canada Hibernia 57.9 Canada NL Light Brent NL Offshore Light 57.9 Offshore Light Light Canada AB Light Edmonton Light AB Light 51.9 Edmonton Light multiplied by factor of 1.084 (average factor SCO Canada AB SCO AB SCO 56.3 between AB SCO and Edmonton Light for Jun-Aug 2017) Heavy Canada AB Heavy Western Canadian Select (WCS) AB Heavy 39.0 Bitumen Canada AB Dilbit Western Canadian Select (WCS) AB Bitumen 39.0 Canada SK Light, Light Edmonton Light SK Light, MB Light 51.9 MB Light Light Canada ON Light Edmonton Light ON Light 51.9 Algeria Saharan Light No proxy needed Algeria Saharan Blend 58.6 Blend Azerbaijan Azeri Light No proxy needed Azerbaijan Azeri Light 60.7 Light Colombia Castilla Colombia Castilla Heavy Brent minus $9.5 45.3 Blend Blend Light Congo Djeno Blend Brent minus $2.5 Congo Djeno Blend 54.6 Average price paid in 2016 by Light Denmark DUC Canadian refineries (Statistics Denmark DUC 56.8 Canada trade data) Equatorial Guinea New Zafiro Blend, Equatorial Guinea Equatorial Guinea Light Average price paid in 2016 by 62.6 Crude New Zafiro Blend Canadian refineries (Statistics Canada trade data) Heavy Ivory Coast Baobab Average price paid in 2016 by Ivory Coast Baobab 52.0 Canadian refineries (Statistics Light Ivory Coast Espoir Canada trade data) Ivory Coast Espoir 52.0

Kazakhstan CPC Light Brent minus $0.15 Kazakhstan CPC Blend 57.7 Blend Michigan Sweet Michigan Sweet Light No proxy needed 57.0 Crude Oil Crude Oil Light Nigeria AKPO Blend No proxy needed Nigeria AKPO Blend 58.4 Light Nigeria Bonga No proxy needed Nigeria Bonga 58.8 Light Nigeria Bonny Light No proxy needed Nigeria Bonny Light 58.3 Light Nigeria Brass River No proxy needed Nigeria Brass River 59.4

January 2018 An Economic and Environmental Assessment of 55 Eastern Canadian Crude Oil Imports

Oil Type Crude Category/ Proxy Crude or Formula Used to Name Used in the Weighted Brand Determine Price Study Price in 2016 ($CAD) Light Nigeria Qua Iboe Brent plus $0.5 Nigeria Qua Iboe 58.8 Light Nigeria Usan No proxy needed Nigeria Usan 55.5 Light Norway Ekofisk No proxy needed Norway Ekofisk 58.3 Origin: Norway Oseberg; Price: Light Norwegian Crude Norwegian Crude 58.3 Norway Ekofisk Source: Saudi Ghawar; Price: Light Saudi Crude Saudi Arabia Light 54.2 Saudi Arabia Light Light UK Brent No proxy needed UK Brent 57.9 Light UK North Sea UK Brent UK North Sea 57.9 Light US Louisiana LLS No proxy needed US Louisiana LLS 53.0 US Louisiana Source: Louisiana Thunderhorse, US Louisiana Light 47.8 Thunderhorse Price: West Texas Sour Thunderhorse Light US North Dakota No proxy needed US North Dakota 48.7 Source: Texas Eagle Ford; Price: Light US Texas Eagle Ford US Texas Eagle Ford 46.2 Gulf Coast Sweet Light US WTI No proxy needed US WTI 57.3

Data Sources: (Government of Canada 2017; IEA 2016; NRCan 2017a; Oil & Gas Journal 2016c; OPEC 2017; Statistics Canada 2017a), African countries websites. Table by CERI.

January 2018 56 Canadian Energy Research Institute

Figure 3.8 illustrates selected volume of imported crudes per refinery and prices in comparison with AB Light and NL Offshore Light. Volumes of more than 10 Mbpd are shown.

Figure 3.8: Selected Foreign Crude Oil Brands Import Volumes and Prices

61.0 100

90 59.0

80 57.0 70

55.0 60

53.0 50

40 Volume,mbpd Crude Price, CAD Price, Crude 51.0

30 49.0 20

47.0 10

45.0 0 US North US North US WTI US Algeria Kazakhstan US WTI US Saudi Nigeria Nigeria Norway US WTI US Nigeria Dakota Dakota Michigan Lousiana Arabia Bonga Usan Lousiana Bonny LLS LLS Light Ontario Montreal-Suncor Quebec-Valero NB-Irving Oil NL-North Atlantic refineries

Volume Foregin Crude Price, CAD AB/SK Light Price NL Offshore Light Price

Data Sources: (Government of Canada 2017; IEA 2016; NRCan 2017a; Oil & Gas Journal 2016c; OPEC 2017; Statistics Canada 2017a), African countries websites. Figure by CERI.

At least three foreign crudes deserve attention based on their import volumes. First, the US North Dakota price beats the prices for both AB Light and NL Offshore Light. Second, Algerian oil is more expensive than both western and eastern Canadian crudes and thus has a good potential to be displaced cost-effectively. Third, Saudi Arabian oil is less expensive than NL Offshore Light but more expensive than AB Light; difference in cost for transportation will play a role in determining if substitution is cost-effective by both Canadian crudes.

The following section describes the methodology used to determine transportation costs.

For certain pipelines – Enbridge Mainline, Line 9, Portland-Montreal, ‘New Pipeline’, Enbridge pipelines in North Dakota – existing and projected tolls were used. In several cases where tolls were not available (i.e., transporting crude oil from Cushing, Oklahoma to the Gulf Coast or transporting Michigan oil to Sarnia, ON), a formula was used based on the cost per kilometer. The formula was originally established based on tolls of certain Canadian low, medium, and long- range pipelines. In all cases where committed tolls were available from the tariffs, those were used for the study.

January 2018 An Economic and Environmental Assessment of 57 Eastern Canadian Crude Oil Imports

Table 3.7 illustrates tolls used for calculations in the study.

Table 3.7: Pipeline Tolls for Crude Oil ($CAD/barrel)

Pipeline Oil Type To From (Destination) Edmonton, Hardisty, Cromer, Clearbrook, Sarnia, Portland, North Cushing, AB AB MB MI ON ME Dakota OK Enbridge Heavy Sarnia, ON 6.38 Mainline Light/SCO 5.99 5.34 3.89 Light 2.61* Light Nanticoke, 3.11* Light/SCO ON 6.49 5.84 4.39 Heavy 6.99 Light/SCO Montreal, 8.09 7.44 5.87 1.98** Heavy QC 8.83 2.31** New N/A Montreal, 6.71 (20 Pipeline QC years) ** N/A QC, QC 7.02 (20 years) N/A Saint John, 8.74 8.6 (20 NB (Combo years) toll, 20 years) Portland- Light Montreal, 0.64- Montreal QC 0.81 ND Light Clearbrook, 2.83 Pipeline MI Co. Seaway Light US Gulf, TX 4.46* Data Sources: (Enbridge Pipelines Inc. 2017a, 2017b, 2017c; FERC 2017; Montreal Pipe Line Limited 2015; TransCanada 2016), CERI estimates. Table by CERI. Notes: *CERI estimates based on tariffs for other pipelines of similar lengths; ** a toll from Hardisty to Montreal via new Pipeline is illustrated for comparison; it is not used in the study as Montreal keeps using Line 9 in all scenarios for western oil intake.

Tanker costs were established using both Clipper Data and Oil & Gas Journal data (ClipperData LLC 2017; Oil & Gas Journal 2016a). Clipper Data oil shipments provided information on shipments volume, type of tanker and days in transition from a country to a particular port (Montreal, Portland, QC, etc.). The following tanker charter daily rates were used: Panamax (23 thousand US dollars per day), Aframax (40 thousand US dollars per day), Suezmax (48 thousand US dollars per day), VLCC (60 thousand US dollars per day) (Oil & Gas Journal 2016a). Daily rates are determined by the size of the tanker.

Using this information, a cost per barrel per shipment was established, and then averaged for the country. A spill tax, tug fee and other fees of $0.36 USD was added for shipments. Other specific destinations needed for the study, for instance, Montreal to Saint John or Whiffen Head Terminal, NL & Labrador to QC, were estimated based on obtained costs for international and domestic tanker costs per barrel. Detailed transportation costs are provided in Appendix D. It is important to note that different costs for the same country and destination port are provided for different crude brands originating in that country. The difference in shipment costs is explained by different ports of origin within a state/country and/or different type of tanker.

January 2018 58 Canadian Energy Research Institute

To put tanker costs in comparison with pipeline costs for western crude, the lowest tanker cost is $0.91/bbl from Algeria to the North Atlantic refinery in NL & Labrador while the highest tanker cost is $2.12/bbl from Colombia to Irving Oil. Half of the shipments are under $1.45/bbl. At the same time, to move AB Light to Montreal, QC, and Saint John (the latter two by the New Pipeline) would cost $7.44/bbl, $7.02/bbl, and $8.60/bbl, respectively. NL Offshore Light oil can reach the same refineries by tanker for $0.80/bbl, $0.60/bbl and $0.70/bbl. For more details on tanker transport costs, refer to Appendix D.

Rail transportation is used once in the modelled Base Case, transporting 12 Mbpd from AB to NB. This mode of transport is not projected to be used more intensively in scenarios with expanded pipeline infrastructure than in the Base Case, but may be needed to fulfill targets for existing infrastructure scenarios.

Rail costs for light oil/SCO ($/bbl) were calculated using the following metric – $/barrel per km. The metric is estimated for each route using the formula derived from (Olateju and Kumar 2016):

y = 0.0034x + 0.2, where y is cost ($/bbl), and x is distance, kilometers1

The most likely rail routes, which might be employed for crude flows modelling, are AB/SK to refineries in QC and NB. Heavy oil is not expected to be additionally moved by rail in the modelling. If a small amount of foreign heavy oil is to be displaced according to a scenario rationale, it will be transported by pipelines from the western provinces.

Crude Oil Costs at Refinery Gate The combination of crude prices and transportation costs make up the total cost of crude feedstock at the refinery gate.

To obtain cost of feedstock per refinery per route (from the specific origin by the specific mode), all the above-mentioned data was combined. Coupled with changes in crude flows per scenario, these costs of feedstock at a refinery gate will drive the cost results of oil substitution for each refinery.

Table 3.8 illustrates the cost of feedstock per refinery per route. Along the top of the table there is the list of the eight refineries in eastern Canada, as well as the mode of transportation used to deliver the crude oil to each refinery gate. The grey cells denote rail shipments. Columns on the left of the table illustrate the name of the producing country as well as the crude brands that are used in this study.

1 The formula was estimated by CERI from a graph “Comparative Transportation Cost: Rail vs Pipeline – Impact on Distance” in (Olateju and Kumar 2016), where costs were a linear function of distance.

January 2018 An Economic and Environmental Assessment of 59 Eastern Canadian Crude Oil Imports

From a Canadian perspective, it is interesting to note that prices of crude oils increase at the refinery gate the further east that western Canadian oil is transported. This is particularly true when rail and tankers are used to transport western crude, adding other layers of cost.

The comparison of prices of selected foreign and Canadian crudes, at place of initial sale and at the refinery gate (cost of feedstock with transportation costs), are provided in Appendix H.

January 2018 An Economic and Environmental Assessment of 60 Eastern Canadian Crude Oil Imports

Table 3.8: Price of Crude Oil Brands at Refinery Gate of Eastern Canadian Refineries

ON QC Atlantic Canada Country of Crude Imperial Shell Suncor Imperial Crude Oil Brand Suncor Energy Valero Irving Oil North Atlantic Refining Oil Origin Oil Canada Energy Oil Mainline/ Mainline/ New Tanker/Portland Mainline/ New Tanker/ Mainline/ New Tanker/ Mainline/ New Mainline Mainline Mainline Tanker Tanker Rail Line 9 Pipeline Pipeline Line 9/Tanker Pipeline Rail Line 9/Tanker Pipeline Rail Line 9/Tanker Pipeline/Tanker AB Light 57.9 57.9 57.9 58.4 60.0 58.6 60.7 59.0 65.9 60.9 60.6 61.0 61.5 AB SCO 61.6 61.6 61.6 62.1 64.4 63.3 64.9 72.9 AB Heavy 45.3 45.3 45.3 46.0 48.5 46.0 48.5 47.6 AB Bitumen 45.3 47.8 48.5 46.0 Canada SK/MB Light 55.8 55.8 55.8 56.3 57.7 58.5 SK Heavy ON Light 55.2 NL Offshore Light 59.0 59.6 58.7 58.8 58.7 North Dakota 54.2 54.2 54.2 54.7 56.7 WTI 63.9 64.5 63.5 63.4 Eagle Ford 48.0 47.9 US Louisiana, LLS 55.5 55.5 Louisiana, 50.0 Thunderhorse Michigan 62.0 Algeria Saharan Blend 60.8 60.2 59.8 Azerbaijan Azeri Light 63.6 62.8 Colombia Castilla Blend 48.1 Congo Djeno Blend 56.5 Denmark DUC 58.2 Equatorial Guinea New Zafiro Blend 64.9 Ivory Coast Espoir 54.8 Ivory Coast Baobab 54.4 Ekofisk 60.7 Norway Norwegian Crude 60.0 UK Brent 60.8 59.8 Kazakhstan CPC Blend 59.8 AKPO 60.9 Bonny Light 60.1 Qua Iboe 60.3 Nigeria Brass River 61.0 Bonga 61.5 Usan 57.6 Saudi Arabia Saudi Arabia Light 56.5

Data Sources: CERI estimates based on: (ClipperData LLC 2017; Oil & Gas Journal 2016a); (Government of Canada 2017; IEA 2016; NRCan 2017a; Oil & Gas Journal 2016c; OPEC 2017; Statistics Canada 2017a); African countries websites; (Enbridge Pipelines Inc. 2017a, 2017b, 2017c; FERC 2017; Montreal Pipe Line Limited 2015; TransCanada 2016). Figure by CERI. Note: Grey cells denote rail shipments

January 2018 An Economic and Environmental Assessment of 61 Eastern Canadian Crude Oil Imports

Emissions/LCA Model The objective of the emissions modelling is to establish an emissions profile for each crude oil in terms of CO2 equivalent per refinery. The specific methodology to obtain upstream, transportation and refinery emissions is stipulated below in greater detail.

Life cycle assessment of GHG emissions of individual crude oils used in the study was used to inform environmental costs for each of the refineries. Analysis of available peer-reviewed literature, reports and documents from government, research institutions and international organizations shows that a number of approaches to model lifecycle GHG emissions of crude oils currently exists (Argonne National Laboratory 2017; J. Bergerson and MacLean n.d., 2016; Cai et al. 2015; El-Houjeiri and Brandt 2017; IHS Energy 2014; Jacobs Consultancy 2009, 2012; Lattanzio 2014; Moorhouse, Droitsch, and Woynillowicz 2011; Nimana, Canter, and Kumar 2015; Nimana et al. 2017; Pacheco et al. 2016; Tarnoczi 2013; TIAX LLC and MathPro Inc. 2009; Vafi and Brandt 2014).

After detailed review of the above documents, the Oil Production Greenhouse Gas Emissions Estimator (OPGEE) developed at Stanford University was selected as a tool to assess GHG emissions from exploration, production, surface processing, and transport of crude oil to the refinery inlet (El-Houjeiri and Brandt 2017), and the Petroleum Refinery Life-Cycle Inventory Model (PRELIM) developed at the University of Calgary was selected to estimate GHG emissions related to crude oil processing in different types of refineries that combine different processing units (J. A. Bergerson et al. 2016). The approach used by CERI was a partial life cycle assessment, since downstream GHG emissions after the refinery outlet (resulting from the transport and end use of refined petroleum products) were out of the scope of this research.

The reasons behind selecting these specific two models for GHG emissions calculations for the purposes of our study included the following:

• Both OPGEE and PRELIM models have been run on a wide range of individual crude oils with extensive geography (approximately 300 global crudes for OPGEE model, and more than 110 global crudes for PRELIM model) (J. A. Bergerson et al. 2016; CARB 2015b; Vafi and Brandt 2013; Wang et al. 2016). That represents more upstream and midstream crude runs than other modelling efforts, in particular, those presented in (IHS Energy 2014; Jacobs Consultancy 2009, 2012; TIAX LLC and MathPro Inc. 2009);

• OPGEE and PRELIM are built as engineering-based models that use public datasets where possible, open academic sources, technical reports, and industry references, with documenting sources for all equations, parameters, and assumptions. This approach allows more flexible and accurate estimations of upstream and midstream GHG emissions from various emissions sources in comparison with some other publicly available models. It also provides more transparency and accessibility in methods and data compared to private models that use proprietary datasets (J. Bergerson and

January 2018 62 Canadian Energy Research Institute

MacLean 2016; J. A. Bergerson et al. 2016; El-Houjeiri et al. 2017; Vafi and Brandt 2013, 2014);

• It was important to select tools where input data were available to model both upstream and midstream GHG emissions for many individual crude oils (Canadian and international) used in the study, with outputs that could be easily converted to the same functional units (kg of CO2 equivalent per barrel of crude oil).

OPGEE model requires up to 50 data inputs, however, it can function sufficiently with limited key parameters entered and built-in defaults that can fill in data gaps. According to the model, the most important characteristics depend on extraction method specifications and activity per unit of production, and include steam-to-oil and water-to-oil ratios, flaring and venting rates, and crude density (measured as API gravity). Other important inputs also include gas-to-oil ratios, oil production rates, location (onshore, offshore) and depth of the oil field (El-Houjeiri et al. 2017; El-Houjeiri and Brandt 2017). The model uses the following classification of crude oils by their API gravity: extra-heavy (≤12 API), heavy (12–20 API), medium (20–30 API), light (30–40 API), ultra- light (≥40 API) and condensate (El-Houjeiri et al. 2017). By sulfur content, oil is classified as sweet (<0.5% sulfur) or sour (>0.5% sulfur). It should be noted that for synthetic crude oils, the sulfur content is reported after the bitumen is upgraded. OPGEE generates final upstream GHG emissions outputs in kg CO2 eq/megajoule (MJ) which can be converted into kg CO2 eq/barrel (bbl) of crude oil by multiplying them by the lower heating value of each oil (in MJ/bbl; this factor depends on API gravity of oil) (El-Houjeiri and Brandt 2017; El-Houjeiri et al. 2017).

The most important upstream GHG emission drivers identified by OPGEE include flaring, land use (that impacts the land’s carbon storage capacity), steam, venting and fugitive emissions, pumping, and upgrading (Brandt et al. 2015; El-Houjeiri and Brandt 2017; El-Houjeiri et al. 2017).

OPGEE also includes GHG emissions from the transportation of oil to the refinery inlet that depend on the mode of transportation (can include ocean tankers, pipeline, railway, or tanker trucks), transport fuel used, the distance traveled and mass of crude oil. While publicly available input datasets for OPGEE obtained from California ARB and Stanford University assume that all oil is transported by default to the refinery hub in Houston, TX, or Los Angeles, CA, as default destinations, CERI used the actual average distances traveled by crude oils from their countries/places of origin to a refinery in eastern Canada. Emissions of imported oil, including upstream activities and transportation of the oil, were accounted for, even if they are produced outside of Canadian territory. Volume of crude oil transported was converted to mass (from barrels to tonnes) using reported product densities, and the vehicle and fuel emissions factors as suggested in the OPGEE model (with references made in this model to other relevant sources) were applied (El-Houjeiri and Brandt 2017; Argonne National Laboratory 2017; US EPA 2015). Based on the above sources, transporting GHG emissions (kg of CO2eq) per tonne of fuel shipped for 1 km (kg CO2eq/tonne-km) are as follows:

January 2018 An Economic and Environmental Assessment of 63 Eastern Canadian Crude Oil Imports

• Tanker trucks – 0.09 • Railway – 0.02 • Pipeline – 0.01 • Barge – 0.042

For marine tankers (ocean crude carriers), transportation emissions factors also depend on an ocean tanker size (tonnes). GHG emissions for various ocean tanker sizes referred to in the study were provided in the OPGEE model in g/MMBtu-mi fuel transported (El-Houjeiri and Brandt 2017). They were further converted to kg CO2eq/tonne-km and are as follows:

• Ocean tanker (250,000 tonnes) – 0.003 • Ocean tanker (120,000 tonnes) – 0.004 • Ocean tanker (80,000 tonnes) – 0.005 • Ocean tanker (60,000 tonnes) – 0.006

The PRELIM model for refinery GHG emissions calculations requires comprehensive crude oil assays as inputs; each parameter at the assay must be specified at the specific temperature cut, with consistent temperature cut ranges for each assay. According to the model, the most important parameters for oil assays include API gravity, sulfur, hydrogen and nitrogen content, density, volume/mass flow, micro-carbon residue or Conradson carbon residue, and viscosity for vacuum residuum (Abella et al. 2016a; J. A. Bergerson et al. 2016; J. Bergerson and MacLean 2016). Ideally, they should be reported for nine temperature cuts with corresponding products; however, the above parameters for at least four temperature cuts could also be entered into the model, but in this case, it will create uncertainty and could possibly affect GHG emissions outputs (Abella et al. 2016a). For the purposes of midstream GHG emissions estimates, in addition to the crude oil assays presented in the PRELIM assay inventory, CERI used other open-source crude assays consistent in a format with the PRELIM requirements, as discussed below.

PRELIM uses ten different combinations of processing units within three different types of refinery (hydroskimming, medium conversion, or deep conversion). A default refinery configuration is assigned in the model as the most suitable for each crude oil, based on the oil assay parameters and using API gravity and sulfur content as the criteria. The default configurations are as follows (Abella et al. 2016a; J. Bergerson and MacLean 2016):

• hydroskimming – for light sweet crudes;

• medium conversion (with fluid catalytic cracking and gas-oil hydrocracking units [FCC & GO-HC]) – for medium sweet and sour crudes, and light sour crudes;

• deep conversion (with fluid catalytic cracking and gas-oil hydrocracking units [FCC & GO- HC]) – for heavy sweet and sour crudes. Deep conversion can further include either a coking or hydrocracking refinery configuration.

January 2018 64 Canadian Energy Research Institute

However, the user can override these default selections if necessary. It is worth noting that for the upgraded extra-heavy oils, the model uses API gravity for their synthetic crude oil (instead of their initial gravity) to determine the default refinery configuration; for the bitumen that was simply diluted without being upgraded, the API gravity of the oil sand is used to determine the default refinery configuration (Abella et al. 2016b; J. A. Bergerson et al. 2016). The most important midstream GHG emission drivers identified by PRELIM include refinery heat and refinery hydrogen (which is produced for adding to carbon-heavy oils) (Abella et al. 2016a).

While both models have numerous advantages discussed above which make them particularly useful for the current study, it is critical to remember their limitations. For both OPGEE and PRELIM, quality of input data is paramount. The accuracy of modelling results is fundamentally related to data inputs available; it is especially true for the OPGEE model. Key parameters that determine data quality are their consistency, completeness, representativeness, accuracy, and comparability. With proper assumptions and good quality detailed data, more accurate emissions estimates can be generated and the individual models can be tuned to match real world results. The main obstacles for obtaining quality input data for these models include lack of publicly available and transparent crude oil information, as well as data inconsistency and discrepancy. Input data for a crude oil are difficult to find and validate, and alternate interpretations may result in varying GHG estimates. OPGEE GHG calculations are the primary source of variation in GHG emissions estimates, whereas PRELIM provides little additional uncertainty (Abella et al. 2016a; El-Houjeiri et al. 2017; Vafi and Brandt 2013, 2014).

The objective of the work on GHG emissions/LCA modelling was to collect information on upstream, transportation and midstream emissions for all the crude oils (Canadian and international) that are being imported and that will be used for substitution in eight eastern Canadian refineries. One of the potential limitations of the study was lack of information on what type of crude oil or crude oil brand is imported from specific countries, as well as which particular brands of light, heavy, SCO and bitumen are supplied to refineries.

Therefore, selection of crude oils for the purposes of GHG emissions modelling was based on:

• information on crude intake (country/province, crude type/category, etc.) for eight eastern Canadian refineries in 2016 obtained from several sources (Clipper Data 2017, COLC 2016, Crude Monitor 2017, Statistics Canada 2017, various refineries’ websites, CERI’s assumptions);

• data availability for both upstream and midstream GHG modelling (operations specifications, publicly available assays, input data in the models);

• oil blend composition and characteristics (API gravity, sulfur content, etc.) that allowed to assume which individual crude brand or blend can represent each crude flow taken by the refineries;

January 2018 An Economic and Environmental Assessment of 65 Eastern Canadian Crude Oil Imports

• if the detailed information on an imported crude oil brand was absent, CERI used the most abundant crude oil brand from the import country per refinery when modelling baseline flows.

More information on individual crude oils and blends selected for the purposes of crude flows and/or GHG emissions modelling, as well as assumptions on proxy crudes selection for GHG emissions modelling, is presented in Table C.1 (Appendix C). In Table C.1, there are 32 individual crude brands or blends selected for the purposes of GHG emissions modelling, including eight Canadian and 24 foreign crude oils (25 percent and 75 percent of total amount, respectively). The spectrum of crude types includes bitumen (one Canadian blend), three heavy oils (one of which is a Canadian blend), five medium crude oils (one of which is a Canadian blend), SCO (one Canadian blend), 18 light oils (four of which are Canadian blends) and four ultra-light oils (all foreign blends).

For the foreign crude flows, 22 were actual crude oil brands or blends imported to Canada in 2016 (Statistics Canada, NRCan, CFA, Clipper Data), and for 20 of the 22 crudes, sufficient data for upstream and midstream GHG emissions modelling were available. In the absence of publicly available data for the remaining two crude flows, Denmark DUC and Kazakhstan CPC Blend, proxy crude oil blends (Denmark Dansk Blend and Kazakhstan Tengiz) were used for the purposes of GHG emissions modelling for these flows (see the Assumptions column). Data available for the other four crude flows (Norwegian Crude, Saudi Arabia Light, UK North Sea, and US Michigan Light) were not specific in terms of actual crude oil brands imported to Canada, so for each of them an individual proxy brand or blend (Norway Oseberg, Saudi Arabia Ghawar, UK Brent or US Bakken) was selected based on the criteria described above. Please note that UK Brent and US Bakken were used as proxies twice (see Table C.1 for details), this explains the difference between the number of foreign crude flows (26) and the number of individual foreign crude brands or blends (24) used for GHG emissions modelling.

Table C.2, also in Appendix C, presents the results of upstream and midstream GHG emissions modelling for eight Canadian and 24 foreign crude oil brands and blends (referred to earlier in Table C.1 as individual brands and blends selected as proxies for crude flows modelling). Table C.2 also provides detailed information on models applied, sources of input data and assumptions behind the GHG emissions modelling. All upstream GHG emissions for the crude oils used in the study were calculated using the OPGEE v2.0a model which was the most current version of OPGEE as of September 2017.23 To run the model, CERI has collected input data for the 32 crude oils of interest from a variety of sources, mostly California ARB (CARB 2015a, 2015b) and Stanford University (Wang et al. 2016), but also from (Crude Quality Inc. 2017; Kable Intelligence Ltd. 2017; Wiki.dot 2015) and crude oil producing companies’ websites. All upstream GHG emissions calculated using the OPGEE model exclude transportation emissions. GHG emissions resulting from crude oil transport to the refinery inlet in Los Angeles, California, or Houston, Texas, as default destinations according to (CARB 2015b; Wang et al. 2016) were

2 The latest version of the model, OPGEE v2.0b, was released in July 2017, however, it was not available for download until November 2017.

January 2018 66 Canadian Energy Research Institute

deducted from the total upstream GHG emissions outputs for each modelled oil (see Notes to Table C.2).

For several crude oils, a few sources of input data for upstream GHG emissions calculations were available, with comparable output results. However, for some crudes the resulting emissions based on input data from different sources varied substantially. For example, GHG emissions for Canada Synthetic Sweet Blend based on (CARB 2015b) data were estimated to be 129.4 kg CO2eq/bbl crude. The same emissions based on (Wang et al. 2016) were calculated as a weighted average of upstream GHG emissions for Suncor A and Syncrude Sweet Premium that constitute Synthetic Sweet Blend (see the Assumptions column in Table C.2) and were estimated to be 177.5 kg CO2eq/bbl crude.

The result based on California ARB (2015) data was selected, since it aligns with upstream GHG emissions results for Canadian SCOs provided in other sources (Jacobs Consultancy 2009; CERI 2017). For Nigeria Brass River, upstream GHG emissions calculations based on input data provided by six producing companies (SPDC, Chevron, NAOC Phillips, Addax, AENR/AGIP, others) disclosed an almost ten-fold difference between the lowest and the highest emissions values (CARB 2015b). Upstream GHG emissions outputs based on Chevron data were selected for the purposes of this study to reflect the fact that Chevron has one of the highest oil production volumes and the biggest number of producing wells within this field (see also Notes to Table C.2). In the case of Nigeria Bonny Light, where input data from four producing companies (SPDC, Chevron, Total E&P, and others) resulted in a 2.5 times difference between the lowest and the highest upstream GHG emissions values obtained in OPGEE model (CARB 2015b), the outputs based on Chevron data were selected for the same reason.

As it can be seen from Table C.2, all midstream GHG emissions for the crude oils used in the study were calculated using the PRELIM v1.1 model (J. A. Bergerson et al. 2016). For 21 crude oil brands or blends, input data based on numerous crude assays (CrudeMonitor, BP, ExxonMobil, Chevron, Statoil, Stratiev, Platt, etc.) were available from the assay inventory spreadsheet (PRELIM v1.1). For the other 11 crude oil blends, publicly available crude assays obtained by CERI from CrudeMonitor.ca, EcoPetrol, ExxonMobil, Maersk Oil, TOTAL and Tullow Oil websites had to be converted to the PRELIM format first and then run through the PRELIM v1.1 model.3 4

It should be noted that different results for midstream GHG emissions could be obtained depending on different crude assay data available from various companies for some crude oils. A few examples include Azerbaijan Azeri Light where different PRELIM outputs were obtained based on Chevron, ExxonMobil, and Statoil assays; Norway Ekofisk (BP, Statoil, and Chevron assays), UK Brent (BP, Chevron, ExxonMobil); Canada Hibernia (ExxonMobil, Statoil, and Chevron), etc. To decide which crude assay (if there are multiple assays available) should be selected to run in the PRELIM model, CERI checked the availability of oil producing companies’

3 The authors would like to personally thank John Guo, MSc., and Dr. Joule Bergerson at the University of Calgary (PRELIM project team) for their help with converting publicly available assays for the selected crude oils into the PRELIM format.

January 2018 An Economic and Environmental Assessment of 67 Eastern Canadian Crude Oil Imports input data for upstream GHG modelling. If a company’s data were available for both upstream and midstream GHG modelling, this dataset (including crude oil assay) was used for the purposes of the study, for the sake of consistency.

The results of GHG emissions modelling presented in Table C.2 demonstrate that upstream GHG emissions vary significantly among the individual crude brand/blends used for the study, ranging from 129.4 to 7.7 kg CO2eq/bbl crude. Midstream GHG emissions for the same crude brand/blends vary less significantly (ranging from 92.7 to 12.5 kg CO2 eq/bbl crude), based on the assumption that heavy crudes undergo the deep conversion refining process with the hydrocracking unit. Table C.2 also provides numbers for the midstream GHG emissions from heavy crudes that undergo the deep conversion refining process with the coking unit. In this case, there will be approximately six times difference in midstream GHG emissions for the studied crude oils, ranging from 77.6 to 12.5 kg CO2eq/bbl crude.

Upstream and midstream GHG emissions for selected Canadian and foreign crude oils used in the study are also shown on Figure 3.9. Crude oil brands/blends previously discussed in Table C.2, are split by crude categories – heavy, medium, light (including SCO) and ultra-light crude oils. This provides visualization for the purposes of total, upstream and midstream GHG emissions comparison both between the categories, and between Canadian and foreign crude oils within each crude category.

January 2018 68 Canadian Energy Research Institute

Figure 3.9: Upstream and Midstream GHG Emissions for Selected Canadian and Foreign Crude Oils Used in the Study (by Crude Categories)

Data Sources: (PRELIM v1.1 (J. A. Bergerson et al. 2016); OPGEE v2.0a (El-Houjeiri and Brandt 2017); CARB 2015b; Wang et al. 2016), CERI calculations. Figure by CERI. Notes: Stacked columns with borders represent Canadian crude oils, stacked columns without borders represent foreign crude oils. Upstream and midstream GHG emissions for Canada WCS dilbit are presented per barrel of diluted bitumen, not per barrel of crude oil produced. For midstream GHG emissions from heavy crude oils, the deep conversion refinery configuration with hydrocracking is assumed.

January 2018 An Economic and Environmental Assessment of 69 Eastern Canadian Crude Oil Imports

Please note that midstream GHG emissions from heavy crude oils are shown on Figure 3.9 for the deep conversion refinery with the hydrocracking unit only. Total GHG emissions differ approximately 7.6 times between the highest numbers (196.3 kg CO2eq/bbl, Canadian WCS Dilbit) and the lowest ones (25.7 kg CO2eq/bbl, US Bakken No Flare) for the studied crudes. If comparing total GHG emissions within each crude category for the studied crudes as presented on Figure 2.10, there was approximately 1.6 times difference for four heavy crudes (from 196.3 to 126.2 kg CO2eq/bbl), approximately 3.3 times difference for five medium crudes (from 151.5 to 45.3 kg CO2eq/bbl), approximately 5.6 times difference for 19 light crudes including one SCO (from 144.1 to 25.7 kg CO2eq/bbl) and approximately 2.4 times difference for four ultra-light crudes (from 94.4 to 39.9 kg CO2eq/bbl).

While the highest total GHG emissions were observed for Canadian WCS Dilbit, it should be noted that the Canadian oil sands industry is working diligently to reduce its bitumen production footprint, in terms of reducing natural gas use, fresh water use, steam management, well pad design, and so on. The technologies that are being tested, commercialized, and implemented are at various stages of adoption by industry players. The viability of some of these technologies on how they can help to reduce the environmental footprint was discussed in CERI Study 164, “Economic Potential and Efficiencies of Oil Sands Operations: Processes and Technologies” (CERI 2017).

Figure 3.10 provides a graphic summary of the results of emissions modelling presented earlier in Table C.2 and on Figure 3.9, showing ranges of total GHG emissions separately for Canadian and foreign crude oils split by crude categories.

January 2018 70 Canadian Energy Research Institute

Figure 3.10: GHG Emissions Ranges for Crude Oils Used in the Study (by Crude Categories)

Data Sources: (PRELIM v1.1 (J. A. Bergerson et al. 2016); OPGEE v2.0a (El-Houjeiri and Brandt 2017); CARB 2015b; Wang et al. 2016), CERI calculations. Figure by CERI. Notes: Average GHG emissions for crude oils in each category are represented by “X”. GHG emissions for Canadian dilbit are presented per barrel of diluted bitumen, not per barrel of crude oil produced.

As it can be seen from Figure 3.10, Canadian Dilbit (i.e., Canada WCS Dilbit) shows the highest total GHG emissions, however, they are presented per barrel of diluted bitumen, not per barrel of crude oil produced.45 Canadian Heavy (i.e., Canada WCB Heavy) is higher in total GHG emissions (150.9 kg CO2eq/bbl) than Foreign Heavy (average 128.0 kg CO2eq/bbl), but Canadian Medium (i.e., Midale) has lower GHG emissions (83.6 kg CO2eq/bbl) than average total GHG emissions (100.3 kg CO2eq/bbl) for Foreign Medium crude. This is also the case for Canadian Light: the average total GHG emissions (58.8 kg CO2eq/bbl) for this crude category are lower than average total emissions for Foreign Light (68.7 kg CO2eq/bbl) and Foreign Ultra-Light (67.8 kg CO2eq/bbl) crude categories. In contrast to conventional Canadian light oils, Canadian SCO (i.e., Canada Synthetic Sweet Blend) shows high total GHG emissions (144.1 kg CO2eq/bbl). However, it is still comparable in emissions with some conventional, not upgraded light foreign oils, for example, US Louisiana Light Sweet (143.2 kg CO2eq/bbl).

4 For Canadian WCS it is assumed that a barrel of oil produced from bitumen is 70% bitumen blended with 30% diluent (CARB 2015b). Upstream GHG emissions from producing the diluent for dilbit are also considered in OPGEE (El-Houjeiri et al. 2015).

January 2018 An Economic and Environmental Assessment of 71 Eastern Canadian Crude Oil Imports

Figure 3.11 graphically represents information provided in Tables C.1 and C.2 for upstream and midstream GHG emissions from individual Canadian crude oil blends used as proxies, as well as the resulting GHG emissions for Canadian crude flows modelled by CERI based on these proxy blends.

Figure 3.11: Upstream and Midstream GHG Emissions for Canadian Proxy and Modelled Crude Flows

Data Sources: (PRELIM v1.1 (J. A. Bergerson et al. 2016); OPGEE v2.0a (El-Houjeiri and Brandt 2017); CARB 2015b; Wang et al. 2016), CERI calculations. Figure by CERI.

Stacked columns representing GHG emissions in Figure 3.11 have either solid fill (for individual proxy crudes), or diagonal stripes pattern fill (for crudes modelled by CERI). Columns representing each modelled crude flow along with columns representing individual crude brand(s) or blend(s) used to create the particular crude flow are surrounded with rectangles to visually separate flows from each other. As it can be seen from Figure 3.11, if the modelled crude flow is deemed to consist of one proxy crude brand/blend, GHG emissions for the flow are understandingly the same as the emissions for its proxy crude (e.g., Western Canadian Blend and AB Heavy, or Hibernia and NL Light Offshore, etc.). However, if the modelled crude flow consists of two or three individual proxy blends, the resulting upstream and midstream GHG emissions for the flow were calculated as a weighted average of OPGEE and PRELIM outputs for individual proxy blends (see, for example, AB Light, or SK Light, etc.). Recall, since AB Light and ON Light (as well as SK Light and MB Light) are assumed, for the purposes of modelling, to be blends of the same proxy crudes with the same proportions (see Table C.1 for assumptions), their resulting GHG emissions per barrel of modelled crude oil will be the same. Again, upstream, and

January 2018 72 Canadian Energy Research Institute

midstream GHG emissions for Western Canadian Select and AB Bitumen are presented per barrel of diluted bitumen, not per barrel of crude oil produced.

Figures 3.12 and 3.13 provide detailed information on OPGEE GHG emissions results for Canadian and foreign crude oils used for the study, either showing the total for upstream emissions (Figure 3.12) or splitting them by the main upstream emissions drivers (Figure 3.13). Both figures are at the same scale, and are organized in the same order, with crude oils ranked by the total upstream emissions (highest to lowest) for the convenience of comparing. As it can be seen, Figure 3.13 looks different from Figure 3.12, even if total upstream emissions for each individual crude depicted on both figures are the same. This is related to the fact that the OPGEE model considers GHG emissions from a lifecycle perspective, therefore, upstream GHG emissions associated with electricity generated on-site or natural gas produced that is gathered, sold, and not flared (i.e., off-site emissions) are credited back or deducted from total upstream GHG emissions (Brandt et al. 2015; Argonne National Laboratory 2017; El-Houjeiri et al. 2017; El- Houjeiri and Brandt 2017). For some crudes (e.g., UK Brent, Nigeria Usan or Nigeria Akpo Blend), the off-site emissions credited towards total GHG emissions compensate their otherwise high upstream emissions.

For many crude oils presented on Figure 3.13, the main driver for upstream emissions is venting, flaring or fugitive emissions (VFF). For some crude oils with a high gas-to-oil ratio (especially light and ultra-light oils), gas can be vented during processing even if the flaring rate is low, whereas for other crude oils their relatively high GHG emissions can be attributed to flaring of associated gas if it is not very well managed (El-Houjeiri and Brandt 2017; El-Houjeiri et al. 2017). However, some crude oils with a high gas-to-oil ratio where their associated natural gas is responsibly managed and can be gathered and exported (e.g., US Bakken (No Flare), US Eagle Ford, US WTI or Norway Ekofisk,) generate negative off-site GHG emissions that can lower total upstream emissions (El-Houjeiri and Brandt 2017; Wang et al. 2016). For some crude oils, the main emission driver will be production and extraction, specifically for conventional oils from depleted fields (e.g., US Louisiana Light Sweet) as they use energy-intensive pumping techniques (Masnadi and Brandt 2017), or for bitumen (e.g., Canada WCS Dilbit), which requires substantial amounts of energy to be produced. For SCOs (e.g., Canada Synthetic Sweet Blend), upgrading operations are the main driver behind upstream GHG emissions.

January 2018 An Economic and Environmental Assessment of 73 Eastern Canadian Crude Oil Imports

Figure 3.12: Total Upstream GHG Emissions for Canadian and Foreign Crude Oils Used for the Study

Figure 3.13: Upstream GHG Emissions for Canadian and Foreign Crude Oils Used for the Study (Split by Main Emissions Drivers)

Data Sources: (CARB 2015b; OPGEE v2.0a (El-Houjeiri and Brandt 2017); Wang et al. 2016), CERI calculations. Figure by CERI. Notes: Stacked columns with borders represent Canadian crude oils, stacked columns without borders represent foreign crude oils. Upstream GHG emissions for Canada WCS Dilbit are presented per barrel of diluted bitumen, not per barrel of produced crude oil. Off-site emissions can be either added to (positive) or deducted from (negative) total upstream GHG emissions.

January 2018 74 Canadian Energy Research Institute

Figure 3.14 provides detailed information on PRELIM GHG emissions results for Canadian and foreign crude oils used for the study, with crude oils ranked by the total midstream emissions (highest to lowest). Please note that the studied crude oils on Figure 3.14 are ranked differently from those on Figure 3.12 (though in the order of decreasing emissions on both figures), since there is no direct correlation between upstream and midstream GHG emissions for these crudes.

Figure 3.14: Midstream GHG Emissions Results for Canadian and Foreign Crude Oils Used for the Study

Data Sources: (PRELIM v1.1 (J. A. Bergerson et al. 2016); Abella et al. 2016b), CERI calculations. Figure by CERI. Notes: Stacked columns with borders represent Canadian crude oils, stacked columns without borders represent foreign crude oils. Midstream GHG emissions for Canada WCS Dilbit are presented per barrel of diluted bitumen, not per barrel of produced crude oil. Medium and deep conversion refineries use fluid catalytic cracking (FCC) and gas-oil hydrocracking (GO-HC).

It can be seen from the figure that the main difference in midstream GHG emissions from the selected crudes is related to the default refinery configuration (deep conversion, medium conversion or hydroskimming). The studied crude oils undergoing the refining process in a hydroskimming refinery have the lowest GHG emissions ranging from 26.4 to 12.5 kg CO2eq/bbl crude. Crude oils depicted on Figure 3.14 that undergo the refining process in a medium conversion refinery have their emissions in a range from 47.1 to 21.0 kg CO2eq/bbl crude. Midstream GHG emissions from heavy crude oils on Figure 3.14 are assumed to be from the refining process in a deep conversion refinery with the hydrocracking unit, and they range from 92.7 to 78.5 kg CO2eq/bbl crude. Canadian crudes are present on both ends of the emissions spectrum, both for upstream GHG emissions (Figure 3.12) and midstream GHG emissions (Figure 3.14).

As discussed above, all upstream GHG emissions calculated using the OPGEE model exclude transportation GHG emissions. They were calculated separately in accordance with the

January 2018 An Economic and Environmental Assessment of 75 Eastern Canadian Crude Oil Imports methodology described at the beginning of this section. The results for transportation GHG emissions for Canadian and foreign crude oils used in the Base Case are graphically presented on Figures 3.15 and 3.16.

As it can be seen from Figure 3.15, the main transportation mode for all crudes shipped to ON refineries in the Base Case is by pipeline (gathering and main pipelines), except for ON Light that is shipped to Imperial refinery in Nanticoke by gathering pipeline and rail. Transportation GHG emissions in this case range from 5.59 kg CO2eq/bbl crude (AB Heavy to Imperial refinery in Nanticoke) to 0.26 kg CO2eq/bbl crude (ON Light, Imperial refinery in Nanticoke).

All refineries shown on Figure 3.16 use transportation by tanker (either combined with transportation by pipeline, or without pipeline, if tanker was offloaded offshore). Despite the large distances associated with marine transportation, GHG emissions for this mode are low related to the lower transportation emissions factors for tankers – 0.003 to 0.006 kg CO2eq/tonne-km depending on tanker size (tonnes). Recall, the factor for pipeline transportation is 0.01 kg CO2eq/tonne-km, and for railway it is 0.02 kg CO2eq/tonne-km. This means an ocean tanker moving a tonne of crude oil one kilometer will emit 3.3 times less GHG emissions than a pipeline moving a tonne of crude oil one kilometer, or 6.6 times less than moving a tonne of crude the same distance by rail. Transportation GHG emissions in the case of a tanker range from 6.01 kg CO2eq/bbl crude (Saudi Arabia Light to Irving Oil refinery, NB) to 0.32 kg CO2eq/bbl crude (NL Light Offshore to North Atlantic Refining, NL). The highest transportation emissions (13.20 kg CO2eq/bbl crude) for all studied crude oils were obtained for AB SCO shipped by rail to the NB refinery.

Table 3.9 provides a detailed summary of transportation GHG emissions for Canadian and foreign crude oils used in the Base Case and the four modelled scenarios introduced in Chapter 2, split by eight refineries in four provinces (ON, QC, NB, and NL & Labrador). Unlike upstream and midstream GHG emissions, transportation emissions in Table 3.9 (as well as on Figures 3.15 and 3.16) are attributed to the modelled crude flows (see Table C.1, Appendix C) based on proxy crude oil brands/blends. Transportation emissions are low; for the crude oils used in the study, they do not exceed 30 percent of total upstream GHG emissions (except for Azerbaijan Azeri Light, US Bakken, Kazakhstan CPC Blend, and Saudi Arabia Light), and are lower for many of the selected crudes. The lowest ratio for transportation emissions was 0.6 percent of upstream GHG emissions for ON Light transported to the Imperial refinery in Nanticoke due to a short transportation distance (100 km by railway). For Azerbaijan Azeri Light, this ratio is almost 52 percent and can be explained with very low upstream GHG emissions for the crude oil and the distance (approximately 1,770 km by pipeline and 9,600 km by tanker) Azerbaijan Azeri Light travels to the Suncor Energy refinery in QC. The same (low upstream GHG emissions combined with long distances the crude travels by pipeline and tanker) is true for Kazakhstan CPC Blend whose transportation to upstream GHG emissions ratio is 34.1 percent (shipping to the Valero refinery in QC) and Saudi Arabia Light (31.6 percent ratio, shipping to the Irving Oil refinery in NB). The high transportation to upstream GHG emissions ratio for US Bakken is also related to its very low upstream GHG emissions (in terms of kg CO2eq/bbl, the lowest ones among all crude

January 2018 76 Canadian Energy Research Institute

oils used for the study) and long traveling distances (approximately 2,800 km by pipeline to Suncor Energy refinery in QC).

January 2018 An Economic and Environmental Assessment of 77 Eastern Canadian Crude Oil Imports

Figure 3.15: Transportation GHG Emissions (kg CO2 eq/bbl crude) for Canadian and Foreign Crude Oils Used in the Base Case Refineries Located in ON

Source: CERI calculations Notes: Stacked columns with borders represent Canadian crude oils, stacked columns without borders represent foreign crude oils. Transportation GHG emissions for AB Bitumen are presented per barrel of diluted bitumen, not per barrel of produced crude oil. Transportation by pipeline includes gathering pipeline and/or main pipeline. ON Light is transported by gathering pipeline and railway.

January 2018 78 Canadian Energy Research Institute

Figure 3.16: Transportation GHG Emissions (kg CO2 eq/bbl crude) for Canadian and Foreign Crude Oils Used in the Base Case Refineries Located in QC, NB and NL

Source: CERI calculations Notes: Stacked columns with borders represent Canadian crude oils, stacked columns without borders represent foreign crude oils. Transportation GHG emissions for AB Bitumen are presented per barrel of diluted bitumen, not per barrel of produced crude oil. Transportation by pipeline includes gathering pipeline and/or main pipeline. Transportation by tanker assumes tanker was offloaded offshore. For US LLS (LA), transportation by tanker also includes transportation by barge for a portion of the route.

January 2018 An Economic and Environmental Assessment of 79 Eastern Canadian Crude Oil Imports

Table 3.9: Transportation GHG Emissions (kg CO2 eq/bbl crude) for Canadian and Foreign Crude Oils Used in the Base Case and the Four Modelled Scenarios (Split by Refinery)

Base Case 'Made in Canada' Scenario 'Expanded Access' Scenario 'Current Reality' Scenario 'International Social Concerns' Scenario

Crude Oil Flow Name

Imperial, Sarnia, ON Sarnia, Imperial, ON Shell Canada, Energy, ON Suncor Nanticoke, Imperial, ON Energy, QC Suncor QC Valero, Irving Oil, NB Atlantic North Refining, NL ON Sarnia, Imperial, ON Shell Canada, Energy, ON Suncor Nanticoke, Imperial, ON Energy, QC Suncor QC Valero, Irving Oil, NB Atlantic North Refining, NL ON Sarnia, Imperial, ON Shell Canada, Energy, ON Suncor Nanticoke, Imperial, ON Energy, QC Suncor QC Valero, Irving Oil, NB Atlantic North Refining, NL ON Sarnia, Imperial, ON Shell Canada, Energy, ON Suncor Nanticoke, Imperial, ON Energy, QC Suncor QC Valero, Irving Oil, NB Atlantic North Refining, NL ON Sarnia, Imperial, ON Shell Canada, Energy, ON Suncor Nanticoke, Imperial, ON Energy, QC Suncor QC Valero, Irving Oil, NB Atlantic North Refining, NL 5.40/ AB Light 4.11 4.11 4.11 4.49 ------4.11 4.11 4.11 4.49 5.21 5.68 6.25 -- 4.11 4.11 4.11 4.49 5.21 5.68 6.25 -- 4.11 4.11 4.11 4.49 5.21 5.40 6.83 -- 4.11 4.11 4.11 4.49 5.21 10.74 7.01 -- AB SCO 4.34 4.34 4.34 4.73 -- 5.67 13.94 -- 4.34 4.34 4.34 4.73 -- 5.88 6.60 -- 4.34 4.34 4.34 4.73 -- 5.88 6.60 -- 4.34 4.34 4.34 4.73 -- 5.67 13.94 -- 4.34 4.34 4.34 4.73 -- 5.67 13.94 -- AB Heavy 5.17 5.17 5.17 5.59 -- 6.61 -- -- 5.17 5.17 5.17 5.59 -- 6.12 7.11 -- 5.17 5.17 5.17 5.59 -- 6.12 7.11 -- 5.17 5.17 5.17 5.59 -- 6.61 -- -- 5.17 5.17 5.17 5.59 -- 6.61 7.96 -- AB Bitumen 5.25 ------6.48 6.69 -- -- 5.25 ------6.48 6.20 -- -- 5.25 ------6.48 6.20 -- -- 5.25 ------6.48 6.69 -- -- 5.25 ------6.48 6.69 -- -- MB Light 2.51 ------2.51 ------2.51 ------2.51 ------2.51 ------SK Light 2.62 2.62 2.62 3.01 ------2.62 2.62 2.62 3.01 3.74 ------2.62 2.62 2.62 3.01 ------2.62 2.62 2.62 3.01 -- 4.35 -- -- 2.62 2.62 2.62 3.01 -- 3.93 -- --

ON Light ------0.26 ------0.26 ------0.26 ------0.26 ------0.26 ------Canadian Crude Oils Crude Canadian NL Hibernia ------0.98 ------0.98 ------0.98 ------0.98 ------0.98 -- NL Light Offshore ------2.08 -- 1.30 0.32 ------1.57 -- 1.30 0.32 ------1.57 -- 1.30 0.32 ------1.57 1.41 1.30 0.32 ------1.57 1.41 1.30 0.32 Algeria Saharan Blend ------4.00 -- 3.89 ------3.89 ------Azerbaijan Azeri Light ------7.70 -- 7.3 ------Colombia Castilla Blend ------3.86 ------3.86 ------3.86 ------3.86 -- Congo Djeno ------5.38 ------5.38 ------5.38 ------5.38 -- Denmark DUC ------3.03 ------3.03 ------3.03 ------3.03 Equatorial Guinea Zafiro ------4.99 ------Ivory Coast Baobab ------4.43 ------4.43 ------Ivory Coast Espoir ------4.19 ------4.19 ------4.19 ------Kazakhstan CPC Blend ------6.45 ------Nigeria Akpo Blend ------4.74 ------Nigeria Bonga ------4.90 ------Nigeria Bonny Light ------4.61 ------4.61 ------Nigeria Brass River ------5.11 ------Nigeria Qua Iboe ------4.60 ------Nigeria Usan ------4.96 ------4.96 ------

Foreign Crude Oils Crude Foreign Norway Ekofisk ------3.82 -- -- 3.92 ------3.82 -- -- 3.92 Norway Norwegian Crude ------2.94 2.79 ------2.94 2.79 Saudi Arabia Light ------6.95 ------6.95 ------6.95 ------UK Brent ------3.20 -- -- 2.46 ------3.20 ------UK North Sea ------2.46 US Bakken (ND) 2.61 2.61 2.61 2.99 3.71 ------2.61 2.61 2.61 2.99 3.71 ------2.61 2.61 2.61 2.99 3.71 ------2.61 2.61 2.61 2.99 3.71 ------US WTI ------4.54 4.49 4.18 4.71 ------4.54 4.49 4.18 4.71 US Eagle Ford (TX) ------3.11 2.83 ------3.11 2.83 ------3.11 2.83 ------3.11 2.83 -- US LLS (LA) ------3.30 3.84 ------3.30 3.84 ------3.30 3.84 ------3.30 3.84 US Thunder Horse (LA) ------2.82 ------2.82 ------2.82 ------2.82 -- US Michigan Light (MI) ------1.51 ------1.51 ------Source: CERI calculations Note: Color coding in Table 3.9 specifies modes of crude oil transportation to the refinery inlet and are defined as follows: transportation by gathering pipeline and main pipeline; by gathering and/or main pipeline and tanker; by gathering pipeline and railway; various modes of transportation, with a portion of crude flow transported by gathering pipeline, main pipeline and tanker (first number), and another portion transported by gathering pipeline and railway (second number); by tanker (offloaded offshore). For US LLS (LA), transportation by tanker also includes transportation by barge for a portion of the route.

January 2018 An Economic and Environmental Assessment of 80 Eastern Canadian Crude Oil Imports

A review of transportation GHG emissions for the Base Case and the four modelled scenarios resulted in the following conclusions and observations:

• transportation GHG emissions intensity in terms of kg CO2eq/bbl crude for all Canadian crude oils shipped to the four refineries in ON has not changed in any of the four scenarios, in comparison with the Base Case;

• transportation GHG emissions for Canadian crude oils shipped to the refineries in ON range from 5.59 kg CO2eq/bbl (AB Heavy, by pipeline, to Imperial refinery in Nanticoke) to 0.26 kg CO2eq/bbl (ON Light, by gathering pipeline and rail, to Imperial refinery in Nanticoke) in the Base Case and all four scenarios;

• transportation emissions (kg CO2eq/bbl crude) for the foreign crude, US Bakken, imported to the ON refineries, have not changed in three scenarios in comparison with the Base Case (US Bakken has been fully substituted in the Made in Canada scenario);

• two US crude oils (Bakken and Michigan Light) are transported to Suncor Energy refinery in QC by pipeline, whereas all other foreign crudes imported to this refinery in the Base Case and the International Social Concerns scenario come by tankers (with gathering/international pipelines involved for the portion or the route);

• all foreign crude oils imported to the remaining three refineries (Valero in QC, Irving Oil in NB and North Atlantic Refining in NL & Labrador) are transported by tankers, or by international pipelines for the portion of route and tankers, in the Base Case and three scenarios (excluding the Made in Canada scenario, where all foreign crudes have been substituted);

• seven foreign crudes (Azerbaijan Azeri Light, Equatorial Guinea Zafiro, Kazakhstan CPC Blend, Nigeria Akpo Blend, Nigeria Bonga, Nigeria Brass River and Nigeria Qua Iboe) have been substituted in all four scenarios and have not been used except in the Base Case;

• the largest variety of crude flows is taken by the Irving Oil refinery in NB (the Base Case). There are three Canadian crudes (transportation GHG emissions range from 13.94 to 0.98 kg CO2eq/bbl crude) and 14 foreign crudes (transportation emissions range from 7.30 to 2.82 kg CO2eq/bbl);

• transportation emissions for Canadian crudes in the Base Case (all refineries) range from 13.94 CO2eq/bbl crude (AB SCO, by gathering pipeline and rail, to Irving Oil refinery, NB) to 0.26 CO2eq/bbl crude (ON Light, by gathering pipeline and rail, to Imperial refinery in Nanticoke);

• transportation GHG emissions for foreign crudes in the Base Case (all refineries) range from 7.70 CO2eq/bbl crude (Azerbaijan Azeri Light, by tanker and pipeline, to Suncor Energy refinery in QC) to 1.51 CO2eq/bbl crude (US Michigan Light, by pipeline, to Suncor Energy refinery in QC);

January 2018 An Economic and Environmental Assessment of 81 Eastern Canadian Crude Oil Imports

• while GHG emissions for the same mode of crude oil transportation will expectedly increase with distance, this increase was the most noticeable for NL & Labrador Light Offshore (0.32 CO2eq/bbl when transported by tanker to North Atlantic refinery vs. 1.57 CO2eq/bbl when transported by tanker to Suncor Energy refinery, QC). Similarly, for AB Light supplied to seven out of eight refineries in all four scenarios, transportation emissions have increased from 4.11 CO2eq/bbl (by pipeline to Imperial refinery, Sarnia) to 6.25 CO2eq/bbl (by pipeline to Irving Oil refinery, NB).

Based on the results of GHG emissions modelling for each individual crude oil and crude flow, calculation of upstream, transportation and midstream emissions per crude stream, per refinery and per scenario was undertaken. Refer to Chapter 4 for additional details.

However, CERI does not discuss emission costs in terms of carbon pricing. It should be clear that for impact of carbon pricing, the focus should be on emissions reported by refineries and associated with their respective production process, since this is the focus of current carbon pricing policies (either through provincial cap-and-trade/carbon tax) or federal output-based allocation systems for large final emitters. It is interesting to note that under QC and ON cap- and-trade systems, most of the emissions from oil refineries are covered by free allowances, as they are considered trade-exposed emitters.

January 2018 82 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 83 Eastern Canadian Crude Oil Imports Chapter 4: Modelling Results

This section discusses the results of the modelling and is divided into four parts. Within each section, the results are reviewed and highlighted using the same four elements: crude flows (including transportation capacities used and remaining), costs of feedstock, emissions, and economic effect. It is important to note that the results of each of the scenarios is compared to the Base Case (2016). A set of drivers are presented to understand the difference between the Base Case and each scenario. The order of the scenario description and results is not indicative of the importance of any scenario.

Made in Canada Scenario Made in Canada assumes that all Canadian crude will substitute all foreign imported crude oil, occurring via an expanded transportation infrastructure. This is a policy-based approach to substituting foreign crude oil in eastern Canadian refineries.

Crude Flows Figure 4.1 illustrates the crude intakes for all the refineries in the Made in Canada scenario. As previously mentioned, the existing transportation infrastructure is augmented by the new pipeline, allowing the substitution of all foreign crude, 601 Mbpd. This includes an additional 423.7 Mbpd of light and heavy crude from western Canada (408.4 Mbpd of light and 15.3 Mbpd of heavy), as well as 177.3 Mbpd of light oil from eastern Canadian offshore assets. The scenario assumes the usage of almost all available oil from the eastern offshore (234.2 Mbpd) and all of SK (149.7 Mbpd). It is important to note that for AB, 130.9 Mbpd of light oil remains available in the west for domestic refining after supplying 391.1 Mbpd to the central and eastern refineries. In total, scenario modelling results in 838.2 Mbpd of crude supply from Canadian western provinces, 234.8 Mbpd from Canadian eastern offshore assets, and no imports.

January 2018 84 Canadian Energy Research Institute

Figure 4.1: Total Crude Intake for Central and Eastern Refineries – Made in Canada (Mbpd)

Scenario 93.1

NL 3.3

North Base 89.8

Atlantic Refining

Scenario 142.5 135.3

Oil NB

Irving Base 11.9 47.7 218.2 Scenario 232.8

Valero Base 100.9 131.9 QC Scenario 119.6 5.8-

5.8 Energy Suncor Base 16.4 103.2 Scenario 95.7 0.6

Oil Base 79.4 0.6 16.3 Imperial

Scenario 77.8 Energy Suncor Base 64.6 13.1

ON Scenario 65.9

Shell Base

Canada 54.8 11.1 Scenario 104.1

Oil Base 86.5 17.6 Imperial - 50.0 100.0 150.0 200.0 250.0 300.0

Western Eastern Imported

A detailed review of crude substitution per refinery is illustrated in Table E.1 in Appendix E. While it is not realistic to review all the transactions, it is prudent to discuss the highlights.

In ON, all of North Dakota’s Bakken oil (58.1 Mbpd) is displaced with light oil from SK via Enbridge’s Mainline. This occurs in all four of ON’s refineries.

In QC, the dynamics are more complex. Suncor Energy’s refinery in Montreal is modelled to proceed using Enbridge Mainline and Line 9 to satisfy its crude intake. Feedstock is predominantly from AB, as well as SK. Although for reference, the cost of feedstock at the refinery gate for AB light oil is $1.38 per bbl cheaper using a new pipeline than using the Mainline and Line 9, based on projected tolls and current Enbridge tolls. Total replaced volume for the Suncor refinery is 103.2 Mbpd. Valero’s refinery in Lévis, on the other hand, is modelled to use a new pipeline, substituting all its foreign crude in the volume of 131.9 Mbpd. In this scenario, Valero stops using Line 9 as well as its two tankers currently transporting crude oil between Montreal and Quebec City. Recall, supplying crude oil to Valero fully on new infrastructure pipeline versus utilizing the existing Line 9 and two tankers is an assumption of the study. However, during the modelling process, this assumption is underpinned by economics, as the costs of AB oil through Line 9 plus the usage of tankers is $1.66 per bbl more expensive for AB Light, $1.13 per bbl more expensive for AB SCO, and $2.52 per bbl more expensive for AB Heavy and bitumen.

January 2018 An Economic and Environmental Assessment of 85 Eastern Canadian Crude Oil Imports

Irving Oil’s refinery in NB is modelled to use both western oil as well as eastern oil to substitute its vast foreign crude slate. Western crude oil comes through new infrastructure pipelines, while eastern crude is delivered by tankers from offshore NL. NL & Labrador’s North Atlantic Refining’s foreign crude slate was fully substituted with nearby Canadian offshore production.

The crude flows in the Made in Canada scenario are illustrated in Figure 4.2.

Figure 4.2: Canadian Crude Supply to Central and Eastern Refineries – Made in Canada (Mbpd)

Source: Figure by CERI based on cartography from (Enbridge Inc. n.d.).

The capacity of the expanded infrastructure scenario and the availability of light oil in western Canada would allow a full western Canadian crude substitution in NB. However, eastern Canadian crude costs $1.8 per bbl less then western crude at the gate of this refinery, hence, a significant portion of eastern crude supply is modelled – the amount of additional eastern oil which was used for NB – 119.2 Mbpd makes up the remaining available eastern oil after satisfying demand of North Atlantic Refining of 93.1 Mbpd and delivering 5.8 Mbpd to Montreal’s Suncor Energy.

The availability and usage of crude and transportation infrastructure by central and eastern refineries is illustrated in Figure 4.3. Canada has enough light oil to be used in the eastern and western refinery markets. As mentioned above, after all foreign oil has been substituted, there is still 130.9 Mbpd of light oil available in the western part of the country. The amount of SCO and Bitumen used by the eastern refinery market is small.

January 2018 86 Canadian Energy Research Institute

Figure 4.3: Availability and Usage of Crude and Infrastructure – Made in Canada (Mbpd)

Mbpd

0 200 400 600 800 1000 1200 1400 1600

522.0 AB Light 391.1 149.8 SK Light 149.7

896.8 AB SCO 164.1

Crude 125.6 AB Heavy 72.5 225.5 SK Heavy 0.0 1423.3 AB Bitumen 53.2 234.5 NL Offshore Light 234.2 1045 New infrastructue PL 375.2

Mainline (Line78, 5) PL 988

462.9 270.75 Portland-Montreal PL 0.0 285 Line 9 PL 119.6 159 Transportation Valero's tankers 0.0 255 Rail 0.0

Available Infrastructure Available Used

Note: The volumes shown for Mainline (Line 78 and Line 5) represent Canadian crudes for Canadian refineries. The figure does not show movements in the Mainline of Canadian or US crudes destined for US refineries.

In terms of infrastructure, several conclusions stand out. First, with new pipeline infrastructure being in place and used by Valero, Line 9 becomes underused. Simultaneously, there is zero usage of rail from west to east, and the Portland-Montreal pipeline becomes obsolete in its current flow direction. If Valero’s refinery is modelled to use a mix of Line 9 (to its capacity), tankers (to their planned capacity) as well as the new infrastructure pipeline, the new infrastructure pipeline usage would drop from 375.2 Mbpd to 216.3 Mbpd. Rail and the Portland-Montreal Pipeline would not be needed. This is due to rail being more expensive than pipeline delivery. In addition, eastern offshore oil production in the Montreal refinery via the Portland-Montreal Pipeline is $0.48 per bbl more expensive than AB Light via the Mainline and Line 9, and $1.87 per bbl more expensive via the new infrastructure pipeline.

January 2018 An Economic and Environmental Assessment of 87 Eastern Canadian Crude Oil Imports

Cost of Feedstock Feedstock costs varied across all examined refineries. This is illustrated in Table 4.1.

Table 4.1: Cost of Feedstock – Made in Canada 10-year Difference Aggregated Annual Base Cost of Scenario Difference Difference Feedstock Province Refinery Case Feedstock ($bbl) ($bbl) Cost of Costs ($bbl) (annual, Feedstock (%) million $) (million $) Imperial Oil 53.77 54.04 0.27 10.18 101.8 0.5 Shell Canada 54.63 54.90 0.27 6.45 65.5 0.5 ON Suncor 76.1 0.5 Energy 55.15 55.42 0.27 7.61 Imperial Oil 56.19 56.46 0.27 9.43 94.3 0.5 Suncor -202.2 -0.8 QC Energy 58.44 57.99 -0.48 -20.22

Valero 60.36 59.41 -0.95 -80.78 -807.8 -1.6 NB Irving Oil 58.70 59.20 0.50 51.09 510.9 0.9 North 58.94 58.73 -0.21 -6.97 -69.7 -0.3 NL Atlantic Refining Total -23.2 -232.1

In ON, under the Made in Canada scenario, if all foreign oil (US Bakken) is substituted, all four refineries end up having more expensive feedstock. The results are driven by the difference in costs of US Bakken oil versus SK light oil – $1.59 per bbl – at the gates of the ON refineries (difference versus AB Light would be $3.69). The increase constitutes a 0.5 percent increase in the refineries annual costs and is due to the fact that oil from the Bakken is more cost competitive than its Canadian counterpart.

On the other hand, if all foreign crude was substituted, the two QC refineries could save on feedstock costs – approximately $103 million per year. For Suncor Energy, the difference in costs is driven by using AB Light ($59.97 per bbl) and SK Light ($57.75 per bbl) instead of oil from US WTI ($63.87 per bbl), Michigan ($61.96 per bbl), and Azerbaijan ($63.59 per bbl). In fact, AB Light and SK Light are cheaper than any other foreign light oil supplied to Suncor Energy’s refinery in 2016, except for oil from the US Bakken. The difference between AB Light and North Dakota is $3.31 per bbl. This illustrates the competitiveness of Enbridge Mainline tariffs coupled with western crude prices. It also supports the economics of the Line 9 reversal project. Recall, transportation costs are included in these estimated costs.

The Valero refinery in Lévis is the largest benefactor in this scenario, with potential savings of $80.8 million per year. The largest driver for such a decrease is the cost difference of oil from AB ($59.03 per bbl), via the new infrastructure pipeline, and from Algeria ($60.17 per bbl) and

January 2018 88 Canadian Energy Research Institute

Kazakhstan ($59.77 per bbl). Recall that these two countries represent 86 percent of foreign intake for this refinery. Overall, AB Light is cheaper than any foreign light oil at Valero’s gate, except for US Texas Eagle Ford ($47.98 per bbl).

North Atlantic refinery’s cost of feedstock would decrease by almost $7 million annually if foreign crude was substituted entirely with eastern offshore crude, as domestic offshore crude ($58.73 per bbl) is cheaper than any 2016 foreign crude in the Base Case except for US Louisiana LLS ($55.46 per bbl) and Denmark DUC ($58.19 per bbl).

The Irving Oil Refinery, on the other hand, will face higher feedstock costs in the amount of $51.1 million per year. This represents an increase in cost of around 1 percent. The reason for this increase is the refineries low-priced crude oil slate in the Base Case. For heavy oil, Irving Oil could benefit as AB Heavy costs $47.57 per bbl (transported via the new infrastructure pipeline route) and has lower tolls than heavy oils from the Ivory Coast ($54.41 per bbl) and Colombia ($48.13 per bbl). For light oil, AB Light ($60.62 per bbl) and Eastern Offshore Light ($58.83 per bbl) are more expensive than 7 of 13 imported crude brands, especially versus Saudi Arabia oil ($56.46 per bbl). The latter comprises nearly 40 percent of total imports of this refinery. Canadian crude is still less expensive than many imported crudes used for this refinery. The feedstock cost would be less if Irving Oil could use 100 percent of domestic NL offshore oil for substitution purposes. However, per the crude flows modelling, there is not enough light oil in eastern Canada to meet the two Atlantic Canada refineries full capacity.

Emissions Based on the results of the emissions/LCA modelling, total upstream, transportation and refining emissions decrease if all imports are substituted with Canadian crude supply, 6.2 percent less than the Base Case or 2.2 million tones CO2eq (MTCO2eq). In absolute terms, it is a decrease from 35.87 MTCO2eq to 33.65 MTCO2eq. This difference represents how much emissions would increase/decrease globally if substitution was to happen. It is important to note that this decrease represents a global emissions decrease, as these emissions reductions are not all realized within Canadian borders.

The major driver for the emissions decrease is overall lower upstream emissions of Canadian light oil versus the imported slate (-2.24 MTCO2eq). Midstream emissions increase by 0.14 MTCO2eq, while transportation emissions decrease in the Made in Canada scenario by 0.12 MTCO2eq. The detailed information can be found in Appendix F in Table F.1.

Figure 4.4 illustrates the difference between the Base Case and Made in Canada scenarios, by refinery. Emissions are also divided by upstream, refining (midstream) and transport.

January 2018 An Economic and Environmental Assessment of 89 Eastern Canadian Crude Oil Imports

Figure 4.4: Made in Canada and Base Case Emissions (tonnes CO2eq per year)

10,000,000 9,000,000 Global-wide Total Emissions: 8,000,000 -2,222,442 tones CO2eq Annually 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 1,000,000

-

Base Base Base Base Base Base Base Base

Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Imperial Oil Shell Canada Suncor Imperial Oil Suncor Valero Irving Oil North Energy Energy Atlantic Refining ON QC NB NL

Upstream Midstream Transport

In all ON refineries, as well as Suncor Energy in Montreal, total emissions increase modestly because of full substitution. ON’s result is driven by the fact that North Dakota’s light oil emission intensity of 28.31 kg CO2eq/bbl is lower than SK Light which is used for substitution (emission intensity of 74.46 kg CO2eq/bbl). For reference, AB Light average at ON refineries is 63.99 kg CO2eq/bbl. For Suncor Energy’s refinery in Montreal, the increase in emissions is linked to upstream activities, and less so, to midstream and transportation. The average of foreign oil total emissions is 54.76 kg CO2eq/bbl in the Base Case, while the emissions intensities from AB Light is 64.99 kg CO2eq/bbl and SK Light is 75.58 kg CO2eq/bbl at the gate of this refinery.

For Valero’s refinery, full substitution of foreign oil decreases total emissions by 9.9 percent, on the upstream side. The average foreign crude emissions are 77.48 kg CO2eq/bbl, while AB Light is 65.47 kg CO2eq/bbl. Regarding the latter, the difference between the emissions intensity in AB Light for Valero and the refineries in ON is due to transportation. For reference, Algeria’s Saharan Blend, which at 91.1 Mbpd, is the largest foreign intake for Valero, has total emissions of 92.9 kg CO2eq/bbl at refinery gate.

Irving Oil’s emissions profile decreases significantly, by 14.9 percent. Most of the decrease occurs in upstream and midstream activities, while transportation related emissions also decrease. Average foreign crude emissions are 86.07 kg CO2eq/bbl, while AB Light via the new pipeline is 66.04 kg CO2eq/bbl and the eastern offshore average is 37.7 kg CO2eq/bbl. Western Canadian

January 2018 90 Canadian Energy Research Institute

crude emissions profile was lower than 7 of 14 foreign crudes which were imported in the Base Case. Eastern offshore crude had lower emissions from any other crude oil in the Base Case, except for Azeri Light.

The largest decrease of emissions stemmed from the North Atlantic Refinery, with a significant 64 percent reduction in total emissions, the majority of which is derived from upstream (75 percent drop) and transportation activities. Midstream activities, on the other hand, experience an increase in emissions. Total transportation emissions for the refinery decrease by 92 percent compared to the Base Case. This is due in part to the proximity of the upstream offshore activities to the refinery. Average foreign crude total emissions are 83.96 kg CO2eq/bbl, while Eastern offshore crude at this refinery gate is 36.72 kg CO2eq/bbl.

The difference in the weighted average kg CO2eq per barrel per refinery is illustrated in Figure 4.5. As different refineries increase or decrease their total intensity (upstream, transportation and midstream), the average decrease at the national level is 5.7 kg CO2/bbl. To obtain each refinery’s weighted average increase or decrease of emissions (kg/bbl), each refinery’s absolute increase or decrease of emissions (kg/bbl) was multiplied by share of intake of the refinery in total central and eastern refineries crude intake.

Figure 4.5: Change in Emissions Intensity – Made in Canada (kg/bbl)

Global-wide Total Emissions:

-5.7 kg CO2eq / bbl

January 2018 An Economic and Environmental Assessment of 91 Eastern Canadian Crude Oil Imports

Expanded Access Scenario Expanded Access assumes that Canadian crude will substitute foreign imported crude oil, occurring via an expanded transportation infrastructure (new pipeline). This is a market-based approach to substituting foreign crude oil in eastern Canadian refineries, meaning that more expensive foreign crude is displaced; cheaper foreign crude is kept in the slate of refineries.

Crude Flows Figure 4.6 illustrates the crude intakes for all the refineries in the Expanded Access scenario. As previously mentioned, the existing transportation infrastructure is augmented by a new pipeline, allowing additional substitution of foreign crude, 344.1 Mbpd. This includes an additional 248 Mbpd of light and heavy crude from western Canada (232.7 and 15.3 Mbpd, respectively), as well 96.1 Mbpd of light oil from eastern Canadian offshore assets. The modelling results in the usage of 65 percent of available light oil from the eastern offshore (153 Mbpd), 87 percent of SK light (130.7 Mbpd) and 56 percent of AB light (292.5 Mbpd). The remaining 42.8 percent is foreign crude that is cheaper than Canadian supply options. In total, scenario modelling results in 662.5 Mbpd of crude supply from Canadian western provinces, 153.6 Mbpd from Canadian eastern offshore assets, and 256.9 Mbpd from foreign sources.

It is important to note that 248.6 Mbpd of light oil remains available in western Canada after supplying the above-mentioned volumes to central and eastern refineries; 81.5 Mbpd of light oil remains available in eastern Canada.

January 2018 92 Canadian Energy Research Institute

Figure 4.6: Total Crude Intake for Central and Eastern Refineries – Expanded Access (Mbpd)

Scenario 57.2 35.9

NL North

Atlantic Base

Refining 3.3 89.8 Scenario 79.1 90.0 108.7

NB Base 11.9 47.7 218.2 Irving Oil Irving Scenario 226.5 6.3

Valero Base 100.9 131.9 QC Scenario 71.5 5.8 48.0

5.8 Energy Suncor Base 16.4 103.2

Scenario 79.4 0.6 16.3 Oil Base

Imperial 79.4 0.6 16.3

Scenario 64.6 13.1 Energy Suncor Base 64.6 13.1

ON Scenario 54.8 11.1 Shell

Canada Base 54.8 11.1

Scenario 86.5 17.6 Oil Base

Imperial 86.5 17.6

- 50.0 100.0 150.0 200.0 250.0 300.0

Western Eastern Imported

A detailed review of crude substitution per refinery is illustrated in Table E.2 in Appendix E. While it is not realistic to review all the transactions, it is prudent to discuss the highlights. If foreign oil is mentioned as not substituted, then it is less expensive than any of the available Canadian supply under consideration.

In ON, North Dakota’s Bakken oil (58.1 Mbpd) is not displaced as it is cheaper than AB Light or SK Light by $1.59 and 3.69 per bbl, respectively.

In QC, the dynamics are a little more complex. Suncor Energy’s refinery in Montreal is modelled to proceed using Enbridge Mainline and Line 9 to satisfy its crude intake. North Dakota’s Bakken (48 Mbpd) remains unchanged, while a mix of crude in the total volume of 55.1 Mbpd from US Michigan, US WTI, Azerbaijan, Norway, and UK are displaced with AB Light brought via the Enbridge Mainline and Line 9. For reference, the cost of feedstock at the refinery gate for AB light oil is $1.38 per bbl cheaper using the new pipeline, based on projected tolls and current Enbridge tolls.

January 2018 An Economic and Environmental Assessment of 93 Eastern Canadian Crude Oil Imports

The Valero refinery in Lévis, on the other hand, is modelled to use the new pipeline. The competitive price of AB Light at this refinery gate allows to substitute almost all its foreign crude in the volume of 125.6 Mbpd, except for 6.3 Mbpd Texas Eagle Ford imported from US Texas in the Base Case. In this scenario, Valero stops using Line 9 as well as its two tankers currently transporting crude oil between Montreal and Quebec City. Recall, supplying crude oil to Valero fully on the new infrastructure pipeline versus utilizing the existing Line 9 and two tankers is an assumption of the study. However, during the modelling process, this assumption appeared to be underpinned by economics, as the cost of AB oil through Line 9 plus usage of tankers is $1.66 per bbl more expensive for AB Light, $1.13 per bbl more expensive for AB SCO, and $2.52 per bbl more expensive for AB Heavy and Bitumen.

For the Irving Oil refinery in NB, 50 percent of foreign feedstock is substituted with cheaper western or eastern Canadian oil. The remaining 50 percent of foreign intake is from the US (16.7 Mbpd), Congo (2.7 Mbpd), Ivory Cost (2.6 Mbpd) and Saudi Arabia (86.7 Mbpd), and is less expensive for the refinery than any Canadian option. The difference between AB Light via new pipeline and Saudi Arabia light is $4.16 per bbl.

NL’s North Atlantic Refining’s foreign crude slate was substituted by 60 percent with nearby Canadian offshore production. US Louisiana LLS and oil from Denmark are not substituted as the former is $3.27 per bbl cheaper than Canadian offshore and the latter is cheaper by $0.55 per bbl.

The crude flows in the Expanded Access scenario are illustrated in Figure 4.7.

Figure 4.7: Canadian Supply to Central and Eastern Refineries – Expanded Access (Mbpd)

Source: Figure by CERI based on cartography from (Enbridge Inc. n.d.)

January 2018 94 Canadian Energy Research Institute

The availability and usage of crude and transportation infrastructure by central and eastern refineries is illustrated in Figure 4.8. Canada has enough light oil to be used in the eastern and western refinery markets. As mentioned above, after all foreign oil being substituted, there is still 330 Mbpd of light oil available in the western and eastern parts of the country. The amount of SCO and Bitumen used by the eastern refinery market is small.

Figure 4.8: Availability and Usage of Crude and Infrastructure – Expanded Access (Mbpd)

Mbpd 0 200 400 600 800 1000 1200 1400

522.0 AB Light 292.5 149.8 SK Light 130.7

AB SCO 896.8 164.1 125.6

AB Heavy 72.5 Crude 225.5 SK Heavy 0.0 1423.3 AB Bitumen 53.2 234.5 NL Offshore Light 153.0 1045.0 New infrastructue PL 305.6 988.0

Mainline (Line78, 5) PL 521.0

270.8 Portland-Montreal PL 0.0 285.0 Line 9 PL 119.6 159.0

Valero's tankers 0.0 Transportation 255.0 Rail 0.0

Available Infrastructure Available Used

Note: The volumes shown for Mainline (Line 78 and Line 5) represent Canadian crudes for Canadian refineries. The figure does not show movements in the Mainline of Canadian or US crudes destined for US refineries.

In terms of infrastructure, several conclusions stand out. First, with new pipeline infrastructure being in place and used by Valero, Line 9 becomes underused. Simultaneously, there is zero usage of rail from west to east and the Portland-Montreal pipeline. If Valero’s refinery is modelled to use a mix of Line 9 (to its capacity), tankers (to their planned capacity) as well as the new infrastructure pipeline, the new infrastructure pipeline usage would drop from 305.6 Mbpd to 156.6 Mbpd. Rail and the Portland-Montreal Pipeline would not be needed. This is due to rail being more expensive than pipeline delivery. In addition, eastern offshore oil production in the Montreal refinery via the Portland-Montreal Pipeline is $0.48 per bbl more expensive than AB

January 2018 An Economic and Environmental Assessment of 95 Eastern Canadian Crude Oil Imports

Light via the Mainline and Line 9, and $1.87 per bbl more expensive via the new infrastructure pipeline.

Cost of Feedstock The feedstock costs varied across all examined refineries. This is illustrated in Table 4.2.

Table 4.2: Cost of Feedstock – Expanded Access 10-year Difference Aggregated Annual Base Cost of Scenario Difference Difference Feedstock Province Refinery Case Feedstock ($bbl) ($bbl) Cost of Costs ($bbl) (annual, Feedstock, (%) million $) (million $) Imperial Oil 53.77 54.04 0.00 0.00 0.00 0.0 Shell Canada 54.63 54.90 0.00 0.00 0.0 0.0 ON Suncor Energy 55.15 55.42 0.00 0.00 0.0 0.0 Imperial Oil 56.19 56.46 0.00 0.00 0.0 0.0 Suncor QC Energy 58.44 57.99 -1.37 -62.91 -629.1 -2.4

Valero 60.36 59.41 -1.25 -106.00 -1,060.0 -2.1 NB Irving Oil 58.70 59.20 -0.99 -100.36 -1,003.6 -1.7 North NL Atlantic 58.94 58.73 -1.42 -48.15 -481.5 -2.4 Refining Total -317.42 -3,174.16

In ON, under the Expanded Access scenario, as no oil is displaced, there is no difference to the Base Case.

For the other three provinces, the partial substitution of more expensive foreign oil would save $317.4 million on feedstock annually.

For Suncor Energy, the difference in costs is driven by using AB Light ($59.97 per bbl) and SK Light ($57.75 per bbl) instead of oil from US WTI ($63.87 per bbl), Michigan ($61.96 per bbl), and Azerbaijan ($63.59 per bbl). In fact, AB Light and SK Light are cheaper than any other foreign light oil supplied to Suncor Energy’s refinery in the Base Case, except oil from the Bakken. The difference between AB Light and North Dakota is $3.31 per bbl.

The Valero refinery in Lévis is the largest benefactor in this scenario, with potential savings of $106 million per year (or 2.1 percent). The largest driver for the decrease is the cost difference of oil from AB ($59.03 per bbl), via new infrastructure pipeline, and crude from Algeria ($60.17 per bbl) and Kazakhstan ($59.77 per bbl). Recall that these two countries represent 86 percent

January 2018 96 Canadian Energy Research Institute

of foreign intake for this refinery. Overall, AB Light is cheaper than any foreign light oil at Valero’s gate, except for US Texas Eagle Ford ($47.98 per bbl).

NB and the Irving Oil Refinery is the second-largest benefactor as its feedstock cost decreases by $100.4 million per year. This represents a decrease in cost of 1.7 percent. On the heavy oil side, Irving Oil could benefit as AB Heavy costs $47.57 per bbl (transported via the new infrastructure pipeline route) versus heavy oils from the Ivory Coast ($54.41 per bbl) and Colombia ($48.13 per bbl). On the light oil side, AB Light ($60.62 per bbl) and Eastern Offshore Light ($58.83 per bbl) are less expensive than 6 of the 13 imported crude brands – US WTI ($63.54 per bbl), Nigeria Bonga ($61.53), and Azerbaijan ($62.77), to name a few. Saudi Arabia oil, which accounts for 40 percent in imports, is very competitive in price at the refinery gate to be substituted ($56.46 per bbl).

North Atlantic refinery’s cost of feedstock would decrease by almost $48.15 million annually if foreign crude was substituted entirely with eastern offshore crude, as domestic offshore crude ($58.73 per bbl) is cheaper than any 2016 foreign crude in the Base Case except for US Louisiana LLS ($55.46 per bbl) and Denmark DUC ($58.19 per bbl).

Emissions Based on the results of the modelling, total upstream, transportation and refining emissions decrease in this scenario and will equal 2.1 million tones CO2eq (MTCO2eq) or 5.1 percent from the Base Case. In absolute terms, it is a decrease from 35.87 MTCO2eq to 33.83 MTCO2eq. This difference represents how much emissions would increase/decrease globally if substitution was to happen. It is important to note that this decrease represents a global emission decrease, as these emissions reductions are not all realized within Canadian borders.

The major driver for the emissions decrease is overall lower upstream emissions of Canadian light oil versus the imported slate (by 1.96 MTCO2eq). However, emissions in both refining and transportation are also lower in this scenario compared to the Base Case, by a total of 0.084 MTCO2eq (0.068 MTCO2eq for midstream, and 0.016 MTCO2eq for transportation). The detailed information can be found in Appendix F in Table F.2.

Figure 4.9 illustrates the difference between the Base Case and Expanded Access scenario, by refinery. Emissions are also divided by upstream, refining (midstream) and transport.

January 2018 An Economic and Environmental Assessment of 97 Eastern Canadian Crude Oil Imports

Figure 4.9: Expanded Access and Base Case Emissions (tones CO2eq per year)

10,000,000 9,000,000 Global-wide Total Emissions: 8,000,000 -2,048,275 tones CO2eq Annually 7,000,000 6,000,000 5,000,000 4,000,000 3,000,000 2,000,000 1,000,000

-

Base Base Base Base Base Base Base Base

Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Imperial Oil Shell Canada Suncor Imperial Oil Suncor Valero Irving Oil North Energy Energy Atlantic Refining ON QC NB NL

Upstream Midstream Transport

In all ON refineries, emissions stay the same as no substitution of oil is occurring.

For Suncor Energy’s refinery in Montreal, the increase in emissions is linked to predominantly upstream activities, and less so, to midstream and transportation. The average of foreign oil total emissions intensity is 54.76 kg CO2eq/bbl in the Base Case, while AB Light is 64.99 kg CO2eq/bbl at the gate of this refinery.

For Valero’s refinery, full substitution of foreign oil decreases total emissions by 10.4 percent, driven by lower emissions on the upstream side. The average foreign crude emissions intensity is 77.48 kg CO2eq/bbl, while AB Light is 65.47 kg CO2eq/bbl. For reference, Algeria’s Saharan Blend, which at 91.1 Mbpd is the largest foreign intake for Valero, has total emissions intensity of 92.9 kg CO2eq/bbl at refinery outlet gate.

Irving Oil’s emissions profile decreases by 7.6 percent. The decrease occurs in all the three components – upstream, midstream and transportation. Recall, that in this scenario all substituted oil comes from the west by new infrastructure pipeline. Average foreign crude emissions intensity average is 86.07 kg CO2eq/bbl, while AB Light via the new pipeline is 66.04 kg CO2eq/bbl and the Eastern offshore average is 37.7 kg CO2eq/bbl. The western Canadian crude emissions profile was lower than 7 of 14 foreign crudes which were imported in the Base Case. Eastern offshore crude had lower emissions from any other crude oil in the Base Case, except for Azeri Light.

January 2018 98 Canadian Energy Research Institute

The largest decrease of emissions stemmed from the North Atlantic Refinery, with a significant 24 percent reduction in total emissions, all of which is derived from upstream (31% drop) and transportation activities; midstream activities, on the other hand, experience an increase in emissions. Total transportation emissions for the refinery decrease by 56 percent compared to the Base Case. This is due in part to the proximity of the upstream offshore activities to the refinery. Average foreign crude total emissions are 83.96 kg CO2eq/bbl, while Eastern offshore crude at this refinery gate is 36.72 kg CO2eq/bbl.

The difference in the weighted average kg CO2eq per barrel per refinery is illustrated in Figure 4.10. As different refineries increase or decrease their total intensity (upstream, transportation and midstream), the total decrease on the Canadian level is 5.2 kg CO2/bbl. To obtain each refinery’s weighted average increase or decrease of emissions (kg/bbl), each refinery’s absolute increase or decrease of emissions (kg/bbl) was multiplied by share of intake of the refinery in total central and eastern refineries crude intake.

Figure 4.10: Change in Emissions Intensity – Expanded Access (kg/bbl)

Global-wide Total Emissions:

-5.2 kg CO2eq / bbl

January 2018 An Economic and Environmental Assessment of 99 Eastern Canadian Crude Oil Imports

Current Reality Scenario Current Reality assumes that Canadian crude will substitute foreign imported crude oil, occurring via existing transportation infrastructure – pipelines, marine tankers, or rail. This is a market- based approach to substituting foreign crude oil in eastern Canadian refineries meaning that more expensive foreign crude is displaced; cheaper foreign crude is kept in the slate of refineries.

Crude Flows Figure 4.11 illustrates the crude intakes for all the refineries in the Current Reality scenario. As previously mentioned, the existing transportation infrastructure allows substitution of foreign crude in the volume of 279.8 Mbpd (47 percent). This includes an additional 119.7 Mbpd of light crude from western Canada, as well as 160 Mbpd of light oil from eastern Canadian offshore assets. The modelling results in the usage of 93 percent of available light oil from the eastern offshore (216.9 Mbpd), 100 percent of SK Light (149.7 Mbpd) and 31 percent of AB Light (160.5 Mbpd). The remaining 53 percent of foreign crude is cheaper than Canadian supply options. In total, scenario modelling results in 534.2 Mbpd of crude supply from Canadian western provinces, 217.6 Mbpd from Canadian eastern offshore assets, and 321.3 Mbpd from foreign sources.

It is important to note that 361.6 Mbpd of light oil remains available in western Canada after supplying the above-mentioned volumes to central and eastern refineries and 17.5 Mbpd of light oil remains available in eastern Canada.

January 2018 100 Canadian Energy Research Institute

Figure 4.11: Total Crude Intake for Central and Eastern Refineries – Current Reality (Mbpd)

Scenario 57.2 35.9

NL

North Atlantic Refining Base 3.3 89.8

Scenario 45.1 92.8 139.9 NB Base

Irving Oil Irving 11.9 47.7 218.2

Scenario 132.3 61.1 39.4

Valero Base 100.9 131.9 QC

Scenario 71.5 5.8 48.0 Energy Suncor Base 16.4 5.8 103.2

Scenario 79.4 0.6 16.3 Oil

Imperial Base 79.4 0.6 16.3

Scenario 64.6 13.1 Energy

Suncor Base 64.6 13.1 ON

Scenario 54.8 11.1 Shell

Canada Base 54.8 11.1

Scenario 86.5 17.6 Oil

Imperial Base 86.5 17.6

- 50.0 100.0 150.0 200.0 250.0 300.0

Western Eastern Imported

A detailed review of crude substitution per refinery is illustrated in Table E.3 in Appendix E. While it is not realistic to review all the transactions, it is prudent to discuss the highlights. If foreign oil is not substituted, the reason is it was cheaper than any of the available Canadian supply under consideration (western and eastern) unless stated otherwise.

In ON, none of North Dakota’s Bakken oil (58.1 Mbpd) is displaced as it is cheaper than AB Light or SK Light by $1.59-$3.69 per bbl.

In QC, the dynamics are a little more complex. Suncor Energy’s refinery in Montreal is modelled to proceed using Enbridge Mainline and Line 9 to satisfy its crude intake. North Dakota’s Bakken (48 Mbpd) is also not substituted, while the mix of crude in the total volume of 55.1 Mbpd from US Michigan, US WTI, Azerbaijan, Norway, and UK are displaced with AB Light brought via Mainline and Line 9. For reference, the cost of feedstock at the refinery gate for AB Light oil is $1.38 per bbl cheaper using a new pipeline, based on projected tolls and current Enbridge tolls.

January 2018 An Economic and Environmental Assessment of 101 Eastern Canadian Crude Oil Imports

The Valero refinery in Lévis is modelled to use the Enbridge Mainline, Line 9 and tankers from Montreal. The competitive price of AB Light and NL Offshore Light at this refinery gate allows, from a price standpoint, to substitute all its foreign crude, except US Texas Eagle Ford. However, as offshore oil is also used in the Maritimes, the modelling showed not enough available oil from eastern assets. Thus, in addition to US Texas Eagle Ford, not all Algerian Saharan Blend oil was substituted (64 percent out of 92.1 Mbpd). In total, 66.6 Mbpd is displaced using AB Light, SK Light, and NL Offshore Light.

For the Irving Oil refinery in NB, 36 percent of foreign feedstock could be substituted with cheaper western or eastern oil. The remaining part of the foreign intake, which comes in the Base Case from several countries, including the US (all by WTI), Saudi Arabia, Ivory Coast, Congo and others, is kept in the slate as more cost-effective for the refinery. Of the 78.3 Mbpd of Canadian crude used for substitution, more than half, 45.1 Mbpd, is supplied from eastern offshore production. The remaining western crude comes by rail and via Mainline, Line 9 and tanker from Montreal to Saint John.

Colombia heavy crude, US (except for WTI) light, Congo light, Ivory Coast light, Saudi Arabian light, and Nigeria Usan brands are not displaced as they are cheaper than Canadian alternatives. The Ivory Coast’s heavy oil volume of 10 Mbpd, though more expensive than AB Heavy, is not substituted as Line 9 capacity is reached.

NL & Labrador’s North Atlantic Refining’s foreign crude slate was substituted by 60 percent with nearby Canadian offshore production. US Louisiana LLS and oil from Denmark could not be substituted as the former is $3.27 per bbl cheaper than Canadian offshore, and the latter is cheaper by $0.55 per bbl.

The crude flows in the Current Reality scenario are illustrated in Figure 4.12.

January 2018 102 Canadian Energy Research Institute

Figure 4.12: Canadian Supply to Central and Eastern Refineries – Current Reality (Mbpd)

Source: Figure by CERI based on cartography from (Enbridge Inc. n.d.)

The availability and usage of crude and transportation infrastructure by central and eastern refineries is illustrated in Figure 4.13. Canada has enough light oil to be used in the eastern and western refinery market. As mentioned above, after all foreign oil being substituted, there is still 379.1 Mbpd of light oil available in the western and eastern parts of the country. The amount of SCO and bitumen used by the eastern refinery market is small.

January 2018 An Economic and Environmental Assessment of 103 Eastern Canadian Crude Oil Imports

Figure 4.13: Availability and Usage of Crude and Infrastructure – Current Reality (Mbpd)

Mbpd

0 200 400 600 800 1000 1200 1400 1600

522.0 AB Light 160.5

SK Light 149.8

149.7

AB SCO 896.8

Crude 164.1

125.6 AB Heavy 57.2

225.5 SK Heavy 0.0

1423.3 AB Bitumen 53.2

234.5 NL Offshore Light 216.9

1045.0 New infrastructue PL 0.0

988.0 Mainline (Line78, 5) PL 686.5

Portland-Montreal PL 270.8 0.0

285.0 Line 9 PL 285.0

159.0 Valero's tankers 132.3

Transportation 255.0 Rail 12.5

Available Infrastructure Available Used

Note: The volumes shown for Mainline (Line 78 and Line 5) represent Canadian crudes for Canadian refineries. The figure does not show movements in the Mainline of Canadian or US crudes destined for US refineries.

In terms of infrastructure, several conclusions stand out. First, Valero’s tanker fleet and Line 9 becomes used to full capacity. Second, there is zero usage of the Portland-Montreal pipeline. Third, Line 9 capacity becomes a bottleneck on the path of western crude to NB; however, this is not a significant bottleneck as 10 Mbpd of heavy oil could not be delivered.

January 2018 104 Canadian Energy Research Institute

Cost of Feedstock Feedstock costs varied across all examined refineries. This is illustrated in Table 4.3.

Table 4.3: Cost of Feedstock – Current Reality 10-year Difference Aggregated Annual Base Cost of Scenario Difference Difference Feedstock Province Refinery Case Feedstock ($bbl) ($bbl) Cost of Costs ($bbl) (annual, Feedstock (%) million $) (million $) Imperial Oil 53.77 54.04 0.00 0.00 0.00 0.0 Shell Canada 54.63 54.90 0.00 0.00 0.0 0.0 ON Suncor Energy 55.15 55.42 0.00 0.00 0.0 0.0 Imperial Oil 56.19 56.46 0.00 0.00 0.0 0.0 Suncor QC Energy 58.44 57.06 -1.37 -62.91 -629.1 -2.4

Valero 60.36 59.84 -0.52 -44.45 -444.5 -0.9

NB Irving Oil 58.70 58.16 -0.54 -54.38 -543.8 -0.9 North NL Atlantic Refining 58.94 57.52 -1.42 -48.15 -481.5 -2.4 Total -209.89 -2,098.92

In ON, under the Current Reality scenario, as no oil is displaced, there is no difference to the Base Case.

For all other provinces, the partial substitution of more expensive foreign oil drives a total $209.89 million of savings on feedstock.

For Suncor Energy, cost savings is the same as the Expanded Access scenario (for additional detail and drivers please see previous scenario).

Valero refinery’s savings on feedstock reach $44.5 million per year or 0.9 percent. The savings come from using AB Light ($60.68 per bbl) versus Nigeria AKPO ($60.93 per bbl) and Nigeria Brass River ($61.02 per bbl); SK Light ($58.46 per bbl) versus Kazakhstan ($59.77 per bbl); NL Offshore Light ($58.68 per bbl) versus Algeria ($60.17 per bbl).

The Irving Oil Refinery is the second-largest benefactor as its feedstock cost decreases by $54.4 million per year. The decrease of costs of feedstock come from using AB Light ($60.94 per bbl) and Eastern Offshore Light ($58.83 per bbl) instead of US WTI ($63.54 per bbl), Nigeria Bonga ($61.53), Azerbaijan ($62.77), and Norway ($60.02) to name a few. Saudi Arabia oil, which

January 2018 An Economic and Environmental Assessment of 105 Eastern Canadian Crude Oil Imports accounts for 40 percent of imports, is very competitive in price at the refinery gate to be substituted ($56.46 per bbl).

The North Atlantic refinery’s cost of feedstock would decrease by $48.2 million annually if foreign crude was substituted entirely with eastern offshore crude. Cost savings are the same as for the Expanded Access scenario (for additional detail and drivers please see previous scenario).

Emissions Based on the results of the modelling, total upstream, transportation and refining emissions decrease in this scenario by 2.0 million tones CO2eq (MTCO2eq) or 5.7 percent from the Base Case. In absolute terms, it is a decrease from 35.87 MTCO2eq to 33.84 MTCO2eq. This difference represents how much emissions would decrease globally if substitution was to happen. It is important to note that this decrease represents a global emission decrease, as these emissions reductions are not all realized within Canadian borders.

The major driver for the emissions decrease is overall lower upstream emissions of Canadian light oil versus the imported slate (by 2.23 MTCO2eq). Transportation emissions are also lower in the Current Reality scenario by a total of 0.14 MTCO2eq, however, midstream emissions grew by 0.33 MTCO2eq. Detailed information can be found in Appendix F in Table F.3.

Figure 4.14 illustrates the difference between the Base Case and Current Reality scenarios, by refinery. Emissions are also divided by upstream, refining (midstream) and transport.

January 2018 106 Canadian Energy Research Institute

Figure 4.14: Current Reality and Base Case Emissions (tones CO2eq per year)

10,000,000

9,000,000

8,000,000 Global-wide Total Emissions: 7,000,000

6,000,000 -2,035,632 tones CO2eq Annually

5,000,000

4,000,000

3,000,000

2,000,000

1,000,000

-

Base Base Base Base Base Base Base Base

Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Imperial Oil Shell Canada Suncor Imperial Oil Suncor Valero Irving Oil North Energy Energy Atlantic Refining ON QC NB NL

Upstream Midstream Transport

In all ON refineries, emissions stay the same as no substitution of oil is happening. For Suncor Energy’s refinery in Montreal, the increase in emissions is identical to the Expanded Access scenario (as the same substitution happens).

For Valero’s refinery, substitution of foreign oil deceases total emissions by 13 percent, on the upstream side and on the transportation side. The average foreign crude emissions intensity is 77.48 kg CO2eq/bbl, while AB Light is 65.18 kg CO2eq/bbl. For reference, Algeria’s Saharan Blend, which at 91.1 Mbpd is the largest foreign intake for Valero, has total emissions intensity of 92.9 kg CO2eq/bbl at refinery gate.

Irving Oil’s emissions profile decreases by 4.5 percent. The decreases occur in the upstream and transportation emissions, with increases in midstream. The average foreign crude emissions intensity average is 86.07 kg CO2eq/bbl, while AB Light via Mainline, Line 9 and tanker is 66.62 kg CO2eq/bbl and the Eastern offshore average is 37.7 kg CO2eq/bbl. The western Canadian crude emissions profile was lower than 7 of 14 foreign crudes which were imported in the Base Case. Eastern offshore crude had lower emissions from any other crude oil in the Base Case, except for Azeri Light.

January 2018 An Economic and Environmental Assessment of 107 Eastern Canadian Crude Oil Imports

The largest decrease of emissions stemmed from the North Atlantic Refinery, with a significant 24 percent reduction in total emissions. The emissions decreases are identical to the Expanded Access scenario.

The difference in the weighted average kg CO2eq per barrel per refinery is illustrated in Figure 4.15. As different refineries increase or decrease their total intensity (upstream, transportation and midstream), the total decrease on the national level is 5.2 kg CO2/bbl. To obtain each refinery’s weighted average increase or decrease of emissions (kg/bbl), each refinery’s absolute increase or decrease of emissions (kg/bbl) was multiplied by share of intake of the refinery in total central and eastern refineries crude intake.

Figure 4.15: Change in Emissions Intensity – Current Reality (kg CO2eq/bbl)

Global-wide Total Emissions:

-5.2 kg CO2eq / bbl

International Social Concerns Scenario International Social Concerns assumes that Canadian crude will substitute foreign imported crude oil from our proxy index for those concerns (undemocratic states), occurring via existing transportation infrastructure – pipelines, marine tankers, or rail. In 2016, Canada imported crude oil from a range of nations (in alphabetical order) including Algeria, Azerbaijan, Colombia, Congo, Denmark, Equatorial Guinea, Ivory Coast, Kazakhstan, Nigeria, Norway, Saudi Arabia, United Kingdom and the US (Government of Canada 2017; NEB 2017f; Statistics Canada 2017a). Recall, CERI used the Economist Intelligence Unit’s Democracy Index 2016, which fits into four categories

January 2018 108 Canadian Energy Research Institute

including full democracy, flawed democracy, hybrid regime, and authoritarian (The Economist Intelligence Unit 2017).

This is a policy-based approach to substituting foreign crude oil in eastern Canadian refineries meaning that crudes from those states is displaced; it is important to note that more expensive oil from democratic states are kept in the crude slate of eastern Canadian refineries. This approach allows CERI to assess the direct impact on costs and emissions tied to substitution of oil from states that cause international social concerns regarding the treatment of their citizens or the environment.

Crude Flows Figure 4.16 illustrates the crude intakes for all the refineries in the International Social Concerns scenario. As previously mentioned, the existing transportation infrastructure is used to substitute for foreign crude, 300.4 Mbpd (50 percent). This includes an additional 123 Mbpd of light crude from western Canada, as well as 177.4 Mbpd of light oil from eastern Canadian offshore assets. The modelling results in the usage of 100 percent of available light oil from the eastern offshore (234.5 Mbpd), 100 percent of SK Light (149.7 Mbpd) and 22 percent of AB Light (115.9 Mbpd). The remaining crude comes from other foreign states. In total, scenario modelling results in 537.5 Mbpd of crude supply from Canadian western provinces, 234.9 Mbpd from Canadian eastern offshore assets, and 300.7 Mbpd from foreign sources.

It is important to note that 406.1 Mbpd of light oil remains available in western Canada after supplying the above-mentioned volumes to central and eastern refineries.

January 2018 An Economic and Environmental Assessment of 109 Eastern Canadian Crude Oil Imports

Figure 4.16: Total Crude Intake for Central and Eastern Refineries – International Social Concerns (Mbpd)

A detailed review of crude substitution per refinery is illustrated in Table E.4 in Appendix E. While it is not realistic to review all the transactions, it is prudent to discuss the highlights. If foreign oil is mentioned as not substituted, then it is less expensive than any of the available Canadian supply under consideration (western and eastern), unless stated otherwise.

In ON, North Dakota’s Bakken oil (58.1 Mbpd) is not displaced, as it comes from the US.

In QC, 4.5 Mbpd from Azerbaijan is displaced with AB Light in Suncor Energy’s refinery in Montreal. The remaining 98.7 Mbpd originate in democratic countries including the US, the UK and Norway. The substitution share in Valero is higher than in Montreal; out of 132 Mbpd, 7.2 Mbpd is kept intact as it is supplied from the US. The bulk of imported crude is from Algeria, Kazakhstan, and Nigeria. This crude slate is substituted with a mix of AB Light, SK Light, and NL Offshore Light. Western Canadian crude oil is delivered via Enbridge Mainline, Line 9 and tankers, as well as rail. The rail shipment comprises 50 percent of Valero’s rail offloading capacity

January 2018 110 Canadian Energy Research Institute

(29 Mbpd). This is because tankers (between Montreal and Lévis) were used to the full capacity of 159 Mbpd.

For Irving Oil’s refinery in NB, crude oil from the Ivory Coast, Azerbaijan, Congo, Equatorial Guinea, Saudi Arabia, and Nigeria, totaling a volume of 152.1 Mbpd, is displaced. The remaining imported crude originates from the US, Colombia, and Norway. Instead of the displaced foreign oil, 23 Mbpd are modelled to originate from AB and 129.3 Mbpd from Canadian eastern offshore assets. Recall, this is not total crude intake but refers to additional volumes.

NL & Labrador’s North Atlantic Refining’s foreign crude slate from Algeria and Nigeria is also substituted. This amounts to 19.1 Mbpd or 21 percent being substituted with nearby Canadian offshore production. Foreign oil from the US, Denmark, the UK, and Norway remains in the crude intake.

The crude flows in the International Social Concerns scenario are illustrated in Figure 4.17.

Figure 4.17: Canadian Supply to Central and Eastern Refineries – International Social Concerns (Mbpd)

Source: Figure by CERI based on cartography from (Enbridge Inc. n.d.)

The availability and usage of crude and transportation infrastructure by central and eastern refineries is illustrated in Figure 4.18. Canada has enough light oil to be used in the eastern and western refinery market. As mentioned above, after all foreign oil being substituted, there is still 406.1 Mbpd of light oil available in the western and eastern parts of the country. The amount of SCO and bitumen used by the eastern refinery market is small.

January 2018 An Economic and Environmental Assessment of 111 Eastern Canadian Crude Oil Imports

Figure 4.18: Availability and Usage of Crude and Infrastructure – International Social Concerns (Mbpd) Mbpd 0 200 400 600 800 1000 1200 1400 1600

522.0 AB Light 115.9 149.8 SK Light 149.7 896.8 AB SCO 164.1

125.6 AB Heavy 57.2

Crude 225.5 SK Heavy 0.0 1423.3 AB Bitumen 53.2 234.5 NL Offshore Light 234.2 1045.0 New infrastructue PL 0.0 988.0 Mainline (Line78, 5) PL 665.9 270.8 Portland-Montreal PL 36.6 285.0 Line 9 PL 264.4 159.0

Valero's tankers 159.0 Transportation 255.0 Rail 50.5

Available Infrastructure Available Used

Note: The volumes shown for Mainline (Line 78 and Line 5) represent Canadian crudes for Canadian refineries. The figure does not show movements in the Mainline of Canadian or US crudes destined for US refineries.

In terms of infrastructure, several conclusions stand out. First, Valero’s tanker fleet is used to full capacity and becomes a constraint to further substitution of western oil to Valero, while Line 9 is used to its fullest. Second, rail usage is higher than in the Base Case and grows to 50.5 Mbpd, to 2016 levels of 53 Mbpd – the highest domestic oil traffic during 2014-2016.

Cost of Feedstock The feedstock costs varied across all examined refineries. This is illustrated in Table 4.4.

January 2018 112 Canadian Energy Research Institute

Table 4.4: Cost of Feedstock – International Social Concerns 10-year Difference Aggregated Annual Base Cost of Scenario Difference Difference Feedstock Province Refinery Case Feedstock ($bbl) ($bbl) Cost of Costs ($bbl) (annual, Feedstock (%) million $) (million $) Imperial Oil 53.77 54.04 0.00 0.00 0.00 0.0 Shell Canada 54.63 54.90 0.00 0.00 0.0 0.0 ON Suncor Energy 55.15 55.42 0.00 0.00 0.0 0.0 Imperial Oil 56.19 56.46 0.00 0.00 0.0 0.0 Suncor Energy 58.44 58.28 -0.16 -7.32 -73.17 -0.3 QC Valero 60.36 61.05 0.69 58.64 586.40 1.1 NB Irving Oil 58.70 59.09 0.39 39.33 393.34 0.7 North Atlantic NL 58.94 58.59 -0.35 -11.82 -118.21 -0.6 Refining Total 78.84 788.36

In the course of substitution under the International Social Concerns scenario, two refineries’ feedstock cost decreases while for two others, it increases. In this scenario, refinery cost of feedstock has an increase of $78.84 million for all central and eastern refineries.

In ON, under the International Social Concerns scenario, there is no difference to the Base Case as no oil is displaced.

For Suncor Energy’s Montreal refinery, the cost of feedstock decreased by $7.3 million per year or 0.3%. This is due to the difference in costs between AB Light ($59.97 per bbl) and Azerbaijan oil ($63.59 per bbl), as well as saving $0.65 per barrel for eastern offshore oil as it is modelled to be delivered directly to the refinery, bypassing the Portland-Montreal pipeline.

The Valero refinery in Lévis has the highest impact as its annual costs increase by $58.6 million per year. The increase comes from using AB Light (39 Mbpd @ $60.68 per bbl) via pipeline and AB Light (38 Mbpd @ $65.88) via rail versus Kazakhstan ($59.77 per bbl) and Algeria ($60.17 per bbl). SK Light ($58.46 per bbl) and NL Offshore Light ($58.68 per bbl), which are cheaper than foreign crude, are also used for displacement, but their share in the slate is not enough to outweigh the cost effects caused by more expensive AB Light.

NB and the Irving Oil Refinery also experience more expensive feedstock costs under the International Social Concerns scenario – $39.4 million annually. The increase of costs of feedstock come from using AB Light ($60.94 per bbl) and Eastern Offshore Light ($58.83 per bbl) instead of the cheaper Saudi Arabia oil ($56.46 per bbl), Nigeria Bonga ($61.53 per bbl) and several others. Canadian oil is cheaper than some substituted crudes, i.e., Azerbaijan or Equatorial Guinea, but the sheer volume of Saudi Arabia crude imports in the Base Case drives the negative result for the refinery.

January 2018 An Economic and Environmental Assessment of 113 Eastern Canadian Crude Oil Imports

North Atlantic refinery’s cost of feedstock would decrease by $11.18 million annually in this scenario as well. The result comes from the difference of NL Offshore Light ($58.73 per bbl) and Nigerian oil brands (between $60.15 and $60.31 per barrel).

Emissions Based on the results of the emissions modelling, total upstream, transportation and refining emissions intensity decrease in this scenario by 2.8 million tones CO2eq (MTCO2eq) or 7.9 percent from the Base Case. In absolute terms, it is a decrease from 35.87 MTCO2eq to 33.05 MTCO2eq. This difference represents how much emissions would increase/decrease globally if substitution was to happen. It is important to note that this decrease represents a global emission decrease, as these emissions reductions are not all realized within Canadian borders.

The major driver for the emissions intensity decrease is overall lower upstream emissions of Canadian light oil versus the imported slate (by 2.5 MTCO2eq). Transportation and midstream emissions are also lower in the International Social Concerns scenario by a total of 0.33 MTCO2eq (midstream by 0.14 MTCO2eq, transportation by 0.19 MTCO2eq). The detailed information can be found in Appendix F in Table F.4.

Figure 4.19 illustrates the difference between the Base Case and International Social Concerns scenarios, by refinery. Emissions are also split into upstream, refining (midstream) and transport.

Figure 4.19: International Social Concerns and Base Case Emissions (tones CO2eq per year)

Global-wide Total Emissions:

-2,819,336 tones CO2eq Annually

January 2018 114 Canadian Energy Research Institute

In all ON refineries, emissions remain the same as if no substitution of oil is occurring.

For Suncor Energy’s refinery in Montreal, the increase in emissions intensity is 1.7 percent in two components (upstream and midstream) as Azerbaijan oil (35.90 kg CO2eq/bbl) is displaced with AB Light (64.99 kg CO2eq/bbl). For Valero’s refinery, substitution of foreign oil decreases total emissions intensity by 12.1 percent due to significant decreases on the upstream side. The average foreign crude emissions intensity for substituted oil is 93.05 kg CO2eq/bbl, while AB Light is 65.18 kg CO2eq/bbl and NL Offshore Light is 37.97 kg CO2eq.

Irving Oil’s emissions profile decreases by 16.4 percent. The decrease occurs in all three components – upstream, transportation and midstream. Average foreign crude emissions intensity for substituted oil is 92.96 kg CO2eq/bbl, while AB Light via Mainline, Line 9 and tanker is 66.62 kg CO2eq/bbl and the Eastern offshore average is 37.7 kg CO2eq/bbl. Recall, the latter is heavily used for substitution in this scenario. The western Canadian crude emissions profile was lower than 7 of 14 foreign crudes which were imported in the Base Case. Eastern offshore crude has lower emissions from any other crude oil in the Base Case, except for Azeri Light.

Foreign oil substitution for the North Atlantic Refinery resulted in 13.9 percent reduction in total emissions. This is due in part to the difference in emissions of eastern Canadian crude oil (36.7 kg CO2eq/bbl) and Nigerian crude oil (116.6 and 90 kg CO2eq/bbl).

The difference in total kg CO2eq per barrel per refinery is illustrated in Figure 4.20. As different refineries increase or decrease their total intensity (upstream, transportation and midstream), the total decrease on the Canadian level is 7.2 kg CO2eq/bbl.

Figure 4.20: Change in Emissions Intensity – International Social Concerns (kg/bbl)

Global-wide Total Emissions:

-7.2 kg CO2eq / bbl

January 2018 An Economic and Environmental Assessment of 115 Eastern Canadian Crude Oil Imports Chapter 5: Conclusions and Important Future Dynamics

This section provides analysis and summarizes key findings. Key conclusions are divided and reviewed in three parts: by scenario, key findings in two inter-scenario comparisons and by province. The latter reveals key findings by a regional analysis. This is to avoid repetition in highlighting the larger story lines. Recall, Canada’s refinery market is considered as three separate entities: Western Canada; ON; and QC and Atlantic Canada. In the case of this study, eastern Canadian refineries are divided into ON, QC, and Atlantic Canada.

Conclusions by Scenario Table 5.1 illustrates key conclusions under the four scenarios. Crude flows results include the additional volumes of western and eastern Canadian supply, as well as the total additional Canadian crude used and percentage of substituted foreign oil.

Table 5.1: Key Conclusions under the Four Scenarios

Expanded Infrastructure Existing Infrastructure International Made in Expanded Current Category Social Canada Access Reality Concerns Additional Western Canada 424 248 120 123 Supply (Mbpd) Additional Eastern Canada 177 96 160 177

Supply (Mbpd)

Total Additional Canadian 601 344 280 300

Crude (Mbpd) Flows Substituted Foreign Oil (%) 100% 57% 47% 50% Total Western Canadian / 663 / 154 / 534 / 218 / 538 / 235 / Eastern Canadian / Foreign 838 / 235 / - 257 321 301

Crude Supply (Mbpd)

Cost of Feedstock -23 -317 -210 +79

Costs ($million)

Emissions (tones CO2eq -2,222,442 -2,048,275 -2,035,632 -2,819,336 per year)

Decrease of Emissions (%) -6.2% -5.7% -5.7% -7.9% Emissions

January 2018 116 Canadian Energy Research Institute

Made in Canada Under the Made in Canada scenario, 100 percent of foreign crude oil is substituted. As such, a total of 601 Mbpd was used, or an additional 424 Mbpd from western Canada and 177 Mbpd from eastern Canada.

In terms of costs of feedstock and emissions, overall Canadian refineries save $23 million per year, as well as reduce emissions by 2.2 MTCO2eq. Of the four scenarios, this scenario ranked third with regards to cost savings; second with regards to emissions reductions. Not only is NL’s offshore crude light by type, it is also near refineries utilizing it as feedstock as both the Come By Chance and Irving Oil refineries are located in Atlantic Canada. It is also 75 percent less intensive in emissions on the upstream side. Substituting light crude, in general, is cleaner overall than Base Case foreign crude intake, resulting in a decrease in total emissions of 6.2 percent. Recall, as CERI is substituting foreign oil by type of crude, if the crude was not substituted by offshore NL but by SCO from western Canada, the emissions would be higher due to the nature of the crude oil (additional processing is necessary to produce SCO) and the crude must be delivered over a longer distance, also resulting in higher emissions.

While western Canadian crude is used in refineries in ON and QC, as well as a portion in NB feedstock, the remaining refineries and feedstock demands are satisfied with eastern Canadian oil production. While an expanded infrastructure is required to transport oil in the Made in Canada scenario, not all existing pipelines and rail would benefit. Some of the infrastructure may be underused (Line 9) or not used at all. Rail and the Portland-Montreal Pipeline (in its current flow direction), for example, face uncertain futures. The same is true for the two tankers currently used by Valero to supply their facility with domestically-sourced crude oil from Montreal; the expanded pipeline infrastructure would make them redundant under this scenario.

Recall, the expanded infrastructure, transporting oil from Hardisty, AB to Saint John, NB, via Montréal and Lévis, is operating in conjunction with the existing pipeline infrastructure (Enbridge Mainline and Line 9). For the refineries which will use new pipeline infrastructure (QC’s Valero and Irving Oil), transportation emissions for the Base Case are 927.5 thousand tonnes, while in the Made in Canada scenario, transportation emissions are 862.7 thousand tonnes, a decrease of 9.3 percent.

In terms of transportation emissions, Canadian combined transportation infrastructure (pipelines from the west and tanker supply from the east) is lower than foreign oil’s transportation emissions by 7 percent. Upstream emissions are 13 percent lower while midstream emissions are 1.3 percent higher than foreign crude oil slate.

QC, on the other hand, would benefit from the Made in Canada scenario, at over $1 billion over the span of a decade. While many focus on Saint John as a major export point of a new pipeline, the proposed pipeline passes through Montréal and Lévis, QC. The latter could also benefit as an export facility.

January 2018 An Economic and Environmental Assessment of 117 Eastern Canadian Crude Oil Imports

With policies such as the Made in Canada scenario, where the solution to the problem is homemade, excluding other countries and their product, there can often be unintended trade implications. Table 5.2 illustrates the level of trade between Canada and the nations that Canada imports foreign oil from. Data is collected from Statistics Canada’s Canadian International Merchandise trade database (Statistics Canada 2017a) and is categorized by the 6-digit harmonized system, on the customs basis, in 2016.

Table 5.2: Merchandise Trade Levels between Canada and the Nations’ Canada Imports Foreign Oil – Made in Canada Total Merchandise Value Crude Oil* Value ($CAN 2016) ($CAN 2016) Country Exports Imports Exports Imports Algeria 508,167,052 1,856,887,336 0 1,821,897,269 Azerbaijan 10,334,021 134,871,072 0 134,332,693 Colombia 765,029,408 787,066,029 0 101,572,358 Congo 35,658,128 75,183,731 0 51,240,985 Denmark 241,313,716 1,015,615,896 0 35,566,063 Equatorial Guinea 3,516,980 54,197,547 0 53,966,940 Ivory Coast 56,288,967 423,345,491 0 238,462,382 Kazakhstan 70,338,587 690,254,420 0 427,461,029 Nigeria 294,667,170 1,574,576,117 0 1,518,733,253 Norway 1,444,191,939 1,576,372,757 0 862,787,758 Saudi Arabia 1,161,200,286 1,705,483,424 0 1,606,830,358 United Kingdom 16,323,958,226 8,258,410,522 450,216,997 185,772,941 United States 353,919,646,571 278,203,230,179 51,474,028,786 7,369,868,024 Source: (Statistics Canada 2017a) Note: *Crude oil is represented on the 6-digit commodity level by “270900 Petroleum oils and oils, obtained from bituminous minerals, crude”.

From the perspective of the foreign nation, crude oil exports dominate the total merchandise trade exports from several countries. For example, crude oil exports from Algeria, Azerbaijan, Equatorial Guinea, Nigeria, and Saudi Arabia make up between 94 and 100 percent of the countries’ total merchandise exports to Canada. However, from Canada’s perspective, Canada’s total value of merchandise exports to the countries exceeds $374.8 billion in 2016, with the US and the UK accounting for $353.9 billion and $16.3 billion, respectively. That being said, not utilizing a product, particularly with obvious cost advantages, could possibly lead to trade implications in other goods and services that Canada exports to the listed nations. For example, while Canada imports crude oil valued at $1.6 billion from Saudi Arabia, it also exports a total merchandise value of $1.2 billion in other goods and services.

January 2018 118 Canadian Energy Research Institute

Expanded Access Under the Expanded Access scenario, 57 percent of foreign crude oil is substituted economically. As such, an additional total of 344 Mbpd was used, or an additional 248 Mbpd from western Canada and 96 Mbpd from eastern Canada. As this is a market-based approach, this suggests that the remaining 43 percent of the crude slate is more cost competitive than its Canadian counterparts. Thus, if Canadian oil is more expensive at the refinery gate compared to foreign oil, in this market-driven scenario, a refinery will prefer cheaper feedstock.

A new pipeline infrastructure would allow the transport of an additional 128.3 Mbpd to central and eastern refineries from western Canada. This amounts to a 40 percent increase in crude oil from western Canada compared to the Base Case, this is second to the Made in Canada scenario.

Similar to the Made in Canada scenario, not all transportation modes benefit; existing pipelines and rail would not benefit. The future is uncertain for rail and the Portland-Montreal pipeline (in its current flow direction). Line 9, on the other hand, is half used under this scenario.

In terms of costs of feedstock and emissions, overall Canadian refineries save $317 million per year, as well as reduce emissions by 2.1 MTCO2eq. In terms of cost savings for refineries, this scenario is the best of all four plausible outcomes, while in terms of emissions it is the third-best scenario. All component emissions, upstream, midstream and transport, are lower than the Base Case, showing that Canadian oil and transport infrastructure is, on average, “cleaner” than its foreign counterpart.

The Expanded Access scenario is the most cost-effective scenario for refineries ($3.2 billion savings on cost of feedstock over a ten-year period). This translates into higher margins for the refinery, as well as an increase in provincial and federal corporate taxes (with sales assumed the same as in the Base Case).

Current Reality Of the four scenarios, Current Reality represents the closest to status quo, simply a more optimal solution regarding costs of feedstock. Similar to the Expanded Access scenario, proponents include transportation and refineries. Both focus on transporting and substituting economic barrels, adopting a market-based approach. The difference in this case is it uses the existing transportation infrastructure. This scenario identifies the throughput capacity of existing pipelines and rail system to provide additional oil from the west to central and eastern refineries. The remainder is supplied by foreign crude oil from the sources which supplied central and eastern refineries in 2016.

As such, an additional total of 280 Mbpd was used, or an additional 120 Mbpd from western Canada and 160 Mbpd from eastern Canada. It allows for the economic substitution of 47 percent of foreign oil.

January 2018 An Economic and Environmental Assessment of 119 Eastern Canadian Crude Oil Imports

No more oil from the west could be transported in this scenario, as Line 9 becomes a constraint. However, if Line 9 were larger, an additional 10 Mbpd could be sourced economically. Transporting 120 Mbpd from western Canada is the lowest volume in the four scenarios. Following a market-based approach, if more western Canadian crude is to be used as feedstock in central and eastern refineries, additional infrastructure is likely required. Within this scenario, the future is uncertain for the Portland-Montreal pipeline in its current directional flow and rail is not required.

In terms of cost of feedstock and emissions, overall Canadian refineries save $210 million per year, as well as reduce emissions by 2.0 MTCO2eq. In terms of cost savings for refineries, this scenario is the second-best of all four outcomes, behind Expanded Access. In terms of decreasing emissions, it ranked last of the four scenarios, however very close to Expanded Access. Emission intensity decreases on upstream and transport, showing that Canadian oil and infrastructure on average produces lower emissions than imported oil. Midstream emissions increase in Canada.

International Social Concerns Recall, International Social Concerns assumes that crude oil will be transported to eastern markets via the existing pipeline infrastructure. It also assumes that domestically-sourced crude oil will substitute foreign crude oil coming from authoritarian states. Canadian crude oil substitutes for all imports except from Norway, Denmark, the United Kingdom, the US and Colombia.

As such, an additional 300 Mbpd (above the Base Case) of Canadian crude was used, 123 Mbpd from western Canada and 177 Mbpd from eastern Canada representing 50 percent of all imports to central and eastern Canada. While substituting 50 percent of foreign crude, this scenario leads to a net cost for refineries in the amount of $79 million per year. This is in part due to substituting large, cheap volumes from nations such as Nigeria and Saudi Arabia, with more expensive crude oils. Overall emissions are reduced by 2.8 MTCO2eq, putting the scenario in first place in emissions reduction. Interestingly, this equates to $28/T CO2 eq, below the federal 2022 target of $50.

Similar to the Made in Canada scenario, there could possibly be trade implications from not importing crude oil from countries with international social concerns. Table 5.3 illustrates the level of trade between Canada and those nations.

January 2018 120 Canadian Energy Research Institute

Table 5.3: Merchandise Trade Levels between Canada and the Nations’ Canada Imports Foreign Oil – International Social Concerns Total Merchandise Value Crude Oil* Value ($CAN 2016) ($CAN 2016) Country Exports Imports Exports Imports Algeria 508,167,052 1,856,887,336 0 1,821,897,269 Azerbaijan 10,334,021 134,871,072 0 134,332,693 Congo 35,658,128 75,183,731 0 51,240,985 Equatorial Guinea 3,516,980 54,197,547 0 53,966,940 Ivory Coast 56,288,967 423,345,491 0 238,462,382 Kazakhstan 70,338,587 690,254,420 0 427,461,029 Nigeria 294,667,170 1,574,576,117 0 1,518,733,253 Saudi Arabia 1,161,200,286 1,705,483,424 0 1,606,830,358 Source: (Statistics Canada 2017a) Note: *Crude oil is represented on the 6-digit commodity level by “270900 Petroleum oils and oils, obtained from bituminous minerals, crude”.

Canada’s total value of merchandise exports to the afore-mentioned countries exceeds $2.1 billion in 2016, with Saudi Arabia accounting for $1.2 billion and Algeria accounting for $0.5 billion. As previously mentioned in the Made in Canada scenario, not utilizing a product could possibly lead to unintended trade implications in other goods and services that Canada exports.

Conclusions by Province This section presents results from a provincial perspective. This is important as the regional dynamics in ON, QC and Atlantic Canada differ in their foreign intake, transportation modes used to deliver crude, capacities and other factors.

All four of ON’s refineries have access to Enbridge’s Mainline, and thus, to western Canadian oil. While they lack access to rail or supply by water, they still have an opportunity to increase their Canadian share of crude intake. It is interesting to note, however, in three of the four scenarios, this does not happen. In both market-based scenarios (Expanded Access and Current Reality), regardless of the level of infrastructure, western Canadian crude cannot beat North Dakota’s Bakken in price. The price differential with SK Light and AB Light is $1.6 and $3.7 per bbl, respectively. In International Social Concerns, US Bakken crude is not displaced. When crude is substituted in the Made in Canada scenario, the results, on a refinery level, are negative as cost of feedstock increases for all four refineries by $33.7 million dollars. Emissions increase by 0.98 MTCO2eq annually. For greater details regarding the cost of feedstock versus GHG emissions, refer to Appendix G (Figure G.1).

QC is more complex, particularly due the fact that the dynamics in both refineries in Montreal and Lévis are different. While both refineries can receive western Canadian crude, Suncor’s refinery is accessible by pipeline. Valero, on the other hand, is accessible by rail and barge, both

January 2018 An Economic and Environmental Assessment of 121 Eastern Canadian Crude Oil Imports from Montreal, resulting in higher transportation costs. QC refineries certainly have a more intricate dynamic, as its two refineries are positioned to substitute large volumes of foreign crude cost-effectively. Western and eastern Canadian oil, however, are competitively priced at both refineries’ gates compared to number of foreign crudes.

Suncor Energy’s Montreal refinery was found to always benefit on the refinery level in course of substitution, irrespective of a scenario. In the market-based scenarios, it gains $62.1 million dollars of savings annually from the costs of feedstock, followed by full substitution (Made in Canada) at $20.2 million in savings, and by partially-displaced (International Social Concerns) at $7.3 million in savings. The mix of western and eastern crude yields results in lower costs than just using western oil for displacement. The cost of AB Light is close to NL Offshore Light – approximately $1 per bbl higher – while SK Light is $1.24 per bbl cheaper than NL Offshore Light.

The Suncor refinery has full access to Line 9, whose capacity is much higher than the capacity of the refinery. The cost of western Canadian crude, as well as eastern Canadian crude, is lower than all foreign oil, except North Dakota’s Bakken. Suncor Energy’s refinery is set to substitute all 55 Mbpd of foreign oil, except for 48 Mbpd from North Dakota. In all four scenarios, substitution brings increases in emissions from as low as 0.05 to as high as 1 MTCO2eq annually.

Valero’s refinery enjoys different transportation options of oil supply from Canada. It has access to at least half of Line 9’s capacity, rail offloading capacity of 60 Mbpd, as well as access to eastern offshore supply by water. The refinery benefits in all scenarios except International Social Concerns. Costs of feedstock savings range from $44.5 to $106 million dollars per year. Costs of feedstock, however, increase in the International Social Concerns scenario ($58 million dollars) driven by high costs of rail, which had to be modelled as Valero’s tanker capacity had been exhausted, while Line 9 capacity was remaining. If the tanker’s capacity was expanded, the International Social Concerns scenario would also yield positive cost-of-feedstock results. NL Offshore Light is more competitive than AB Light by $2 per bbl via Mainline and tanker, and by $0.34 per bbl via new pipeline and tanker. SK Light is cheaper than NL Offshore Light via Mainline by $0.22 per bbl. For greater details regarding the cost of feedstock versus GHG emissions, refer to Appendix G (Figures G.2 and G.3).

A large portion of foreign crude oil is displaced in all four scenarios for this refinery. In market- driven cases, 6.3 Mbpd (Expanded Access) to 39.4 Mbpd (Current Reality) of foreign crude remains in the intake crude slate, underlining the competitiveness of Canadian crude in the region. In International Social Concerns, 7.2 Mbpd of imported oil remains in the intake. In all cases, emissions decrease for this refinery and vary from 0.98 to 1.3 MTCO2eq annually. In terms of a QC aggregate, this effect negates the increase in Suncor Energy’s refinery in three of four scenarios and leads to a decrease in emissions province-wide.

NB’s Irving Oil saves on costs of feedstock in both market-driven scenarios ($54.4 million in the Current Reality scenario to $100.4 million in the Expanded Access scenario) while its feedstock costs increase in both policy-driven scenarios (by $40 million in the International Social Concerns scenario and $51.1 million in the Made in Canada scenario). NL Offshore Light gains an advantage

January 2018 122 Canadian Energy Research Institute

over AB Light at this refinery. The latter is transported farther, adding $2.11 per bbl via Mainline, Line 9 and tanker, or $1.79 per bbl via a new pipeline, compared to what NL Offshore Light costs to Irving Oil. However, Line 9 is a bottleneck. After satisfying QC’s refineries, 33.2 Mbpd is transported to Irving Oil. The AB Light advantage also decreases compared to foreign crudes, it is cost-competitive compared to four foreign crude oils. SK Light is cheaper than AB Light and more competitive, but its volume is limited as was modelled to be used primarily in ON. More detail regarding the cost of feedstock versus GHG emissions can be found in Appendix G (Figure G.4).

In the Current Reality scenario, 140 Mbpd of foreign crude remains in the refineries crude slate, while 108 Mbpd of foreign crude are used under the Expanded Access scenario. This is in part because Irving Oil’s crude slate in the Base Case is cheap and, thus, costlier to substitute. Saudi Arabia’s crude, making up most of the facilities’ diverse crude slate, is cost competitive at the refinery gate, even compared to adjacent supply from NL. It is interesting to note that in two scenarios, more western crude is purchased by the refinery due to competitive tolls of a new pipeline.

In all four cases, emissions decrease, varying from 0.3 to 1.18 MTCO2eq annually.

North Atlantic Refinery in NL is uniquely positioned, as it is accessible by water. Consequently, NL Offshore oil was used to displace imported crude. However, offloading western crude is also possible from NB provided there is a new pipeline or, theoretically, transported by tanker from Montreal. Again, however, the capacity of Line 9 is a bottleneck. The cost of NL Offshore at the refinery is $2.78 per bbl cheaper than AB Light oil via the expanded pipeline infrastructure and tanker. The refinery saves in terms of the cost of feedstock in all four scenarios, $48.2 million per year in market-driven scenarios and between $7 and $12 million per year in two policy-driven scenarios (Made in Canada and International Social Concerns). Emissions decrease in all four scenarios, varying from 0.5 to 2.2 MTCO2eq annually. For greater details regarding the cost of feedstock versus GHG emissions, refer to Appendix G (Figure G.5).

In terms of volumes displacing foreign crude oil, the market-based approaches allow to displace 53.8 Mbpd of foreign crude out of 89.9 Mbpd. In the International Social Concerns scenario, 19.1 Mbpd of oil is substituted.

Inter-scenario Comparisons The main objective of the modelling exercise in this study was to compare the four scenarios to the Base Case. The two inter-scenario comparisons that really stand out are 1) Expanded Access and Current Reality and 2) Expanded Access and Made in Canada. Both share a critical uncertainty, allowing for an interesting comparison between different scenarios. For example, while Expanded Access assumes an expanded infrastructure and Current Reality assumes existing infrastructure, both also assume a market-based approach or economic pull. Within the market- based approach, how many additional economic barrels of oil can be transported from western and eastern Canada with the expanded infrastructure? Regarding the other comparison,

January 2018 An Economic and Environmental Assessment of 123 Eastern Canadian Crude Oil Imports

Expanded Access and Made in Canada share the same expanded infrastructure, but differ as the former is a market-based approach while the latter is a policy-based approach. This comparison looks at the implications if refineries had more transport infrastructure and society/policy push for Canadian barrels beyond what the market suggests.

The overall conclusions are identified below.

Expanded Access vs. Current Reality

• In terms of crude flows, costs of feedstock and emissions, the Expanded Access scenario yields results for refineries, as well as for Canada.

• The new pipeline infrastructure allows an additional 128.3 Mbpd of Canadian crude to be substituted economically to central and eastern refineries from the west. This is in addition to the movement of crude oil along the existing infrastructure. This is both due to expanded transportation capacity and more competitive tolls of new pipeline versus existing Enbridge Mainline and Line 9.

• In total, 64.4 Mbpd more Canadian oil could be sourced in the Expanded Access compared to the Current Reality scenario, transporting via a more limited existing infrastructure.

• Cost of feedstock for all refineries is $107.5 million lower in the Expanded Access scenario than in Current Reality. The scenarios emissions are almost identical.

Expanded Access vs. Made in Canada

• In terms of crude flows and emissions, the Expanded Access scenario yields positive results for refineries, as well as for Canada. In terms of cost of feedstock savings, Expanded Access is more than 10 times better than Made in Canada, with 3 of 8 better off economically.

• The Made in Canada scenario results in 257 Mbpd more Canadian crude used than in the market decision-making behavior of refineries would suggest in the Expanded Access scenario.

• The total savings of refineries is $23 million in Made in Canada versus $317 million in Expanded Access. It is important to note that while in Expanded Access, all the refineries save on feedstock costs, 3 refineries do so in the Made in Canada (Valero, Suncor Energy in Montreal and North Atlantic for total of $108 million); the other five refineries’ costs increase by $85 million.

• Emissions decrease is 0.17 MTCO2eq per year larger under the Made in Canada scenario than under the Expanded Access scenario.

January 2018 124 Canadian Energy Research Institute

Important Future Dynamics

Crude Oil Price Dynamics In two of four scenarios which look at an expanded infrastructure, the excess capacity that remains after filling it with light conventional crude to eastern Canadian refineries, could be used by transporting heavy Canadian output, like diluted bitumen or conventional heavy crude oil to be exported to other markets, outside of Canada. Those markets are characterized by increasing demand for crude oil and where refining technology can process heavy crude like bitumen. There is also an argument that reaching markets outside of North America carries an additional financial incentive for producers. Whether there is merit to this argument will be explored in this section.

In North America, Western Canadian heavy crude prices are attached to the price of benchmark Western Canadian Select (WCS).1 WCS has grown to become a benchmark crude due to its tightly controlled stream with stringent specifications, supervised by its producers (Suncor, Cenovus, Canadian Natural Resources, and the former Talisman Energy). This assures refiners receive a stable, reliable, and consistent heavy crude oil stream with minimal variability; important crude oil characteristics for refinery operations. WCS is a sour heavy crude oil with an API between 20.5 and 21.5 and sulfur content of approximately 3.5% w/w. However, it’s important to note that not all bitumen supply is sold at WCS prices.

Since lighter crude is easier to process and yields more desirable light products than heavy crude, WCS has traditionally been priced at a discount to US light, sweet benchmark West Texas Intermediate (WTI) at Cushing, Oklahoma. This difference between WTI and WCS is called the light-heavy differential and historically has varied from $10 to $40 per barrel. The widening of the heavy oil discount beyond crude quality discount (~$10/bbl) was in the past caused by infrastructure bottlenecks and refinery demand.

Given that most of the WCS supply is destined for the US Midwest or PADD 2, the main price for Western Canadian heavy crude oil is then dictated by the refiner’s value of the crude in the US Midwest. This is in turn dictated by a series of factors including the crude gross product worth, indicative of the value of refined products in the yield of the total barrel of crude, as well as the processing costs, transportation costs, refinery margins, and the availability and price of competing crudes (Hart Energy 2012). Since most of heavy crude oil processed in the US Midwest is Canadian heavy crude, the price of Canadian heavy crudes is therefore dictated by the availability of required refining capacity in the area for such crudes.

In recent years, Canadian heavy crude volumes have exhausted the refining capacity in this market. According to the EIA, US Midwest refineries ran at 94% capacity in 2015, and have become saturated, as evidenced by the high level of inventories from growing domestic production (US tight oil) and imports of heavy crude oil from Western Canada (US EIA 2015). If

1 A mix of about 20 heavy conventional and bitumen crudes all sourced from Western Canada. These different crude oils are blended at the Husky terminal in Hardisty, AB and then diluted with sweet synthetic crude oil (upgraded bitumen) and gas condensates or naphtha in order to reduce viscosity and facilitate transport.

January 2018 An Economic and Environmental Assessment of 125 Eastern Canadian Crude Oil Imports this persists, Canadian heavy crudes will need to be sold at steeper discounts to remain competitive in the US Midwest market. Potential Canadian heavy crude discounts due to saturation supports the debate of opening new markets. This was partially materialized in recent years, as Canadian bitumen started to be exported to the US Gulf Coast, rising to near 400,000 bpd.

As US tight oil supply grew in recent years, the US Midwest was the most affected. From 2011, light crude has oversupplied the US Midwest, resulting in regional oil price discounts. The price of crude in the US Midwest, as measured by West Texas Intermediate (WTI), has averaged $17 below comparable crude oils on the US Gulf Coast in 2012. Over the last few years, however, planned pipeline projects2 between the US Midwest and the US Gulf Coast have become operational, thus alleviating excess crude supply, boosting prices for WTI and other inland crudes and realigning them to be more comparable with US Gulf Coast and global prices.

Eventually though, strong supply growth for light crude combined with limited outlets led to lower oil prices for both inland and US Gulf Coast crudes in the range of $3 or more per barrel against a global benchmark Brent. This led to changes in the US policy prohibiting the export of its domestic crude oil offshore, and in 2015 the US government lifted the 40-year ban on crude oil exports. Given the regional interdependency of WCS and other Canadian crudes to WTI, a situation that once was thought to provide Canadian producers and transportation providers a financial incentive to reach new markets – ones that reflect global crude prices instead of discounted ones – no longer applies. But the situation does highlight the risk of a lack of market diversity and the need for options, providing a strong case for infrastructure projects that will provide global access for Canadian crudes.

Short-term fluctuations and even potential short-term gains in prices for Canadian crudes through accessing other global markets might be enough incentive to a producer. But a long- term gain of strategically placing Canada as a global supplier of crude oil is more important.

Recent empirical research suggests that there is significant symmetric dependence between different global crude oil prices of different qualities, suggesting that oil prices are linked with the same intensity both during bull runs (price spikes) and bear markets (price declines) thus supporting the hypothesis that the oil market is one great pool as opposed to being regionalized in nature (Reboredo 2011).

Other studies of crude oil price differentials have found that price differentials between crude oils follow a stationary process3 even for pairs of crudes with very different qualities. This

2 These include the Seaway pipeline expansion and twinning (increasing from 150,000 bpd to 400,000 bpd in 2013 and 800,000 bpd in 2014) and the Gulf Coast Pipeline Project (700,000 bpd in 2013). Other projects that are important for western Canadian producers as well as producers in North Dakota and Montana include the Flanagan South expansion (160,000 bpd in 2014) and greater rail capacity. 3 This refers to a situation where the random movement in the main variable in question has a probability distribution that does not change when shifted in time or at different points in time. Therefore, mean and variance remain constant over time while there might be variation in the variable, in this case the price differential.

January 2018 126 Canadian Energy Research Institute

conclusion once again suggests that markets for oil are global in nature as mentioned above. However, it is also found that price differentials between various prices of crude follow different dynamics depending on certain features such as the types of crude oil, and whether crude is connected to a futures market such as NYMEX for WTI and ICE for North Sea Dated Brent. In the case of crude oils with different qualities, different price adjustments occur compared with those for similar quality crudes. Crude oils of different qualities are shown to have a threshold such that the price adjustment process to the long-term equilibrium follows a non-linear process. Thus, the differentials return to long-run equilibrium after the price differentials rise above a certain threshold. This can reflect on refiners’ willingness to take heavy/sour crude types at a large enough discount so that it compensates refiners for running their facilities on less suitable crudes. However, this threshold is not present across different crude types that have established futures markets (think Dubai medium sour crude and WTI), which indicates that crude oils with highly tradable contracts reduce transaction costs and facilitate arbitrage. It is also noted in this study that bottlenecks such as in Cushing, Oklahoma can lead to decoupling in prices on a global basis as well as a sharp narrowing of light-heavy differentials. Finally, these dislocations are found to be short-lived and the market returns to equilibrium (Fattouh 2010).

Availability of Crude Oil The study’s results are contingent on the possibility, from the volume and transportation standpoint, to substitute foreign crude oil (almost entirely light oil) with Canadian oil. The maximum domestic available light oil that eastern refineries would need, unless refineries expand capacity, is 758 Mbpd.

Figure 5.1 illustrates the future availability of Canadian crude.

Figure 5.1: Future Availability* of Canadian Crude (Mbpd)

5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 - 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 MB Light SK Light AB Light NL Offshore light AB SCO SK Heavy AB Heavy AB Bitumen

*Availability refers to crude supply net of western Canadian refinery demand.

January 2018 An Economic and Environmental Assessment of 127 Eastern Canadian Crude Oil Imports

Overall, the forecasted light oil supply is expected to decrease from 943 Mbpd in 2017 to 852 Mbpd in 2020. SK Light is stable over time and increases from 159 Mbpd to 173 Mbpd over the same period. AB Light, however, is projected to diminish in volume from 522 Mbpd to 431 Mbpd. NL Offshore Light grows in the next several years, primarily due to Hebron project supply. It is subsequently projected to decrease from 234 Mbpd in 2017 to 220 Mbpd in 2027.

Table 5.4 illustrates the total usage for crude oil used for substitution – AB Light, SK Light, and NL Offshore Light – by scenario. In all years, except 2027 for NL Offshore Light, there is always enough Canadian oil for any scenario. This suggests that conclusions made in the study are valid not just for 2016 (if substitution was to happen), but for at least 10 years in the future. The validity of these conclusions relies on the ceteris parabis concept.

January 2018 128 Canadian Energy Research Institute

Table 5.4: Comparison of Availability of Light Oil (after subtraction of demand in the west) with Demand by the Central and Eastern Refineries, by Scenario

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 AB Light Availability 522 498 482 468 450 446 435 434 431 430 431 Made in Canada 391 391 391 391 391 391 391 391 391 391 391 International Social 116 116 116 116 116 116 116 116 116 116 116 Concerns Expanded Access 293 293 293 293 293 293 293 293 293 293 293 Current Reality 161 161 161 161 161 161 161 161 161 161 161 SK Light Availability 150 150 150 150 151 152 155 157 159 161 164 Made in Canada 150 150 150 150 150 150 150 150 150 150 150 International Social 150 150 150 150 150 150 150 150 150 150 150 Concerns Expanded Access 131 131 131 131 131 131 131 131 131 131 131 Current Reality 150 150 150 150 150 150 150 150 150 150 150 NL Offshore Light Availability 234 284 308 304 304 268 278 248 244 236 220 Made in Canada 234 234 234 234 234 234 234 234 234 234 234 International Social 234 234 234 234 234 234 234 234 234 234 234 Concerns Expanded Access 153 153 153 153 153 153 153 153 153 153 153 Current Reality 217 217 217 217 217 217 217 217 217 217 217

Final Remarks The ability of CERI to conduct this analysis is based on the availability of data. For refineries in Canada, this is particularly challenging as there is a widespread desire to keep detailed information confidential. Governments and stakeholders struggle with making evidence-based decisions due to the challenge of finding data in Canada. For now, the concerted efforts of CERI have developed a comprehensive dataset that can be used to answer different questions about this market.

Canada is also debating the best approaches to addressing climate change by reducing carbon dioxide emissions. This study provides information that suggests decisions that create higher emissions in Canada can contribute to lower global emissions. Is this solution something to be considered by Canadian governments?

Finally, the idea of substituting domestic products for imports has always been debated. Where do the benefits occur within the Canadian federation and at what cost? In this case, changing

January 2018 An Economic and Environmental Assessment of 129 Eastern Canadian Crude Oil Imports the trade balance to create an increased trade surplus may be of net benefit to the country but it is a complicated question that is best answered through additional analysis.

January 2018 130 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 131 Eastern Canadian Crude Oil Imports Bibliography

Abella, Jessica P., Kavan Motazedi, John Guo, and Joule A. Bergerson. 2016a. “Petroleum Refinery Life Cycle Inventory Model (PRELIM) - PRELIM v1.1 - User Guide and Technical Documentation.” University of Calgary. http://www.ucalgary.ca/lcaost/files/lcaost/prelim-v1-1- documentation.pdf. ———. 2016b. “Petroleum Refinery Life Cycle Inventory Model (PRELIM) - PRELIM v1.1 - User Guide and Technical Documentation.” University of Calgary. http://www.ucalgary.ca/lcaost/files/lcaost/prelim-v1-1-documentation.pdf. AllOilTank.com. n.d. “Oil Tanker Ship: Capacity, Size.” AllOilTank.com (blog). n.d. http://alloiltank.com/oil-tanker-ship/. Argonne National Laboratory. 2017. “GREET 2017 Model. The Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model.” Argonne National Laboratory. October 9, 2017. https://greet.es.anl.gov/. AUUUU.com. 2015. “Supertanker.” AUUUU.com. 2015. http://auuuu.com/shiptravel/supertanker/. Bell, Tom. 2008. “Pipeline Pondering Flow Change.” Portland Press Herald, February 6, 2008. http://defendingwater.net/maine/2012/04/pipeline-pondering-flow-change/, http://defendingwater.net/blog/2012/04/pipeline-pondering-flow-change/. Bergerson, Joule A., Jessica P. Abella, Kavan Motazedi, and John Guo. 2016. PRELIM: The Petroleum Refinery Life Cycle Inventory Model (version 1.1). Calgary, AB: The Life Cycle Analysis of Oil Sands Technologies Research Group (University of Calgary). http://www.ucalgary.ca/lcaost/prelim. Bergerson, Joule, and Heather MacLean. n.d. “LCAOST: Life Cycle Assessment of Oil Sands Technologies.” University of Calgary | LCAOST. n.d. http://www.ucalgary.ca/lcaost/. ———. 2016. “PRELIM: The Petroleum Refinery Life Cycle Inventory Model.” University of Calgary | LCAOST. 2016. http://www.ucalgary.ca/lcaost/prelim. Bouchard, Kelley. 2017. “Federal Judge Validates Pipeline’s Plan to Reverse Flow to South Portland.” Portland Press Herald, August 25, 2017. http://www.pressherald.com/2017/08/25/federal- judge-validates-pipelines-plan-to-reverse-flow-to-south-portland/. BP. 2017. “BP Statistical Review of World Energy, June 2017.” London, UK. http://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review- 2017/bp-statistical-review-of-world-energy-2017-full-report.pdf. Brandt, Adam R., Yuchi Sun, Sharad Bharadwaj, David Livingston, Eugene Tan, and Deborah Gordon. 2015. “Energy Return on Investment (EROI) for Forty Global Oilfields Using a Detailed Engineering-Based Model of Oil Production.” PLOS ONE 10 (12):1–18. https://doi.org/10.1371/journal.pone.0144141. Cai, Hao, Adam R. Brandt, Sonia Yeh, Jacob G. Englander, Jeongwoo Han, Amgad Elgowainy, and Michael Q. Wang. 2015. “Well-to-Wheels Greenhouse Gas Emissions of Canadian Oil Sands Products:

January 2018 132 Canadian Energy Research Institute

Implications for U.S. Petroleum Fuels.” Environmental Science & Technology 49 (13):8219–27. https://doi.org/10.1021/acs.est.5b01255. Canadian Pacific. 2016. “Rail Network Map.” Calgary, AB: Canadian Pacific. http://www.cpr.ca/en/choose-rail-site/Documents/cp-network-map-2016.pdf. CAPP. 2016. “Crude Oil: Forecast, Market and Transportation.” 2016-0007. Calgary, AB: Canadian Association of Petroleum Producers. www.capp.ca/~/media/capp/customer- portal/publications/284950.pdf. ———. 2017a. “Rail.” Canadian Association of Petroleum Producers. 2017. http://www.capp.ca/canadian-oil-and-natural-gas/infrastructure-and-transportation/rail. ———. 2017b. “2017 Crude Oil Forecast, Market and Transportation.” 2017-0009. Calgary, AB: Canadian Association of Petroleum Producers. http://www.capp.ca/~/media/capp/customer- portal/publications/303440.pdf. CARB. 2015a. “MCON Inputs Spreadsheet for 2010 Baseline Crudes - LCFS Crude Oil Lifecycle Assessment.” California Air Resources Board. https://www.arb.ca.gov/fuels/lcfs/crude- oil/2010_baseline_mcon_inputs_opgee_v1.1_april_3_2015.xlsx. ———. 2015b. “MCON Inputs Spreadsheet for Crude Lookup Table - LCFS Crude Oil Lifecycle Assessment.” California Air Resources Board. https://www.arb.ca.gov/fuels/lcfs/crude- oil/lookup_table_mcon_inputs_opgee_v1.1_april_3_2015.xlsx. CEPA. 2017. “2016 CEPA Member Operating and Financial Statistics.” Canadian Energy Pipeline Association. 2017. https://cepa.com/en/membership/member-statistics/. CERI. 2016. “Canadian Crude Oil and Natural Gas Production and Supply Costs Outlook (2016 – 2036).” Study No. 159. Calgary, AB: Canadian Energy Research Institute. http://resources.ceri.ca/PDF/Pubs/Studies/Study_159_Full_Report.pdf. ———. 2017. “Economic Potentials and Efficiencies of Oil Sands Operations: Processes and Technologies.” No. 164. Calgary, AB: Canadian Energy Research Institute. https://www.ceri.ca/assets/files/Study_164_Full_Report.pdf. CFA. 2013. “The Economics of Petroleum Refining: Understanding the Business of Processing Crude Oil into Fuels and Other Value Added Products.” Canadian Fuels Association. http://www.canadianfuels.ca/website/media/PDF/Publications/Economics-fundamentals-of- Refining-December-2013-Final-English.pdf. ———. 2017a. “Refineries 101 - Canadian Fuels Association.” Canadian Fuels Association. 2017. http://www.canadianfuels.ca/ASR-Fuels-en/Refineries-101/. ———. 2017b. “A Graphic View: Today’s Refining Capacity across Canada.” Canadian Fuels Association. April 6, 2017. http://canadianfuels.ca/Blog/April-2017-/A-graphic-view-today-s-refining- capacity-across-Canada/.

January 2018 An Economic and Environmental Assessment of 133 Eastern Canadian Crude Oil Imports

Chevron Corporation. 2017. “CPC Blend and Tengiz.” Chevron Crude Oil Marketing. 2017. http://crudemarketing.chevron.com/crude/central_asian/cpc_blend_tengiz.aspx. ClipperData LLC. 2017. “Crude Oil Reports.” ClipperData. July 23, 2017. http://www.clipperdata.com/crude-oil-reporting. COLC. 2016. “COLC - Crude Oil Logistics Committee - Reports.” Crude Oil Logistics Committee. 2016. http://colcomm.com/secure/reports.aspx. Crude Quality Inc. 2017. “CrudeMonitor.ca.” CrudeMonitor.ca - Canadian Crude Quality Monitoring Program. 2017. http://www.crudemonitor.ca/home.php. Dowd. 2007. “CP Rail Agrees to Buy DM&E for at Least $1.5 Billion.” Reuters, September 5, 2007. https://www.reuters.com/article/us-canadianpacific-dme/cp-rail-agrees-to-buy-dme-for-at- least-1-5-billion-idUSN0543024620070906. Duddu, Praveen. 2013. “Top 10 Large Oil Refineries.” News and Analysis. Hydrocarbons Technology. September 29, 2013. http://www.hydrocarbons-technology.com/features/feature-top-ten- largest-oil-refineries-world/. El-Houjeiri, Hassan M., and Adam R. Brandt. 2017. Oil Production Greenhouse Gas Emissions Estimator (OPGEE) (version 2.0a). Stanford, CA: Stanford University. http://pangea.stanford.edu/departments/ere/dropbox/EAO/OPGEE/OPGEE_2.0a.xlsm. El-Houjeiri, Hassan M., Mohammad S. Masnadi, Kourosh Vafi, James Duffy, and Adam R. Brandt. 2017. “Oil Production Greenhouse Gas Emissions Estimator OPGEE v2.0a. User Guide & Technical Documentation.” https://pangea.stanford.edu/departments/ere/dropbox/EAO/OPGEE/OPGEE_documentation_v 2.0a.pdf. Enbridge. 2016a. “Pipeline System Configuration Q1, 2016.” Enbridge Inc. http://www.enbridge.com/~/media/Enb/Documents/Infographics/ENB%20Mainline%20Pipeline %20System%20Q1%202016.pdf. ———. 2016b. “Commodity Receipt Summary. Table 1.” https://www.enbridge.com/~/media/Enb/Documents/Shippers/Table_1_Commodity_Receipt_S ummary.pdf?la=en. ———. 2017a. “Crude Oil and Liquids Pipelines.” Enbridge Inc. 2017. http://www.enbridge.com/about- us/our-work/transportation-and-transmission/liquids-pipelines. ———. 2017b. “Expansion Projects: The Line 78 Pipeline Project (Line 78).” Enbridge Inc. 2017. http://www.enbridge.com/projects-and-infrastructure/public-awareness/illinois/expansion- projects. ———. 2017c. “Line 3 Replacement Program.” Enbridge Inc. 2017. https://www.enbridge.com/Line3ReplacementProgram.aspx.

January 2018 134 Canadian Energy Research Institute

———. 2017d. “Line 3 Replacement Program (Canada).” Enbridge Inc. 2017. https://www.enbridge.com/projects-and-infrastructure/projects/line-3-replacement-program- canada. ———. 2017e. “Line 9B Reversal and Line 9 Capacity Expansion Project.” Enbridge Inc. 2017. http://www.enbridge.com/ECRAI.aspx. ———. 2017f. “Crude Oil Commodity Management Map and Reference.” http://www.enbridge.com/~/media/Enb/Documents/Shippers/Crude_Oil_Commodity_Map_an d_Reference.pdf?la=en. Enbridge Geomatics Services. 2011. “Enbridge Pipelines Inc. (Eastern Region).” Enbridge Inc. https://line9communities.files.wordpress.com/2013/09/enbridge-9b-pipeline-map.png. Enbridge Inc. n.d. “Infrastructure Map.” Enbridge Inc. n.d. http://www.enbridge.com/Map.aspx#map:infrastructure. Enbridge Pipelines Inc. 2017a. “FERC No. 5.0.0 North Dakota Pipeline Company, LLC in Connection with Sacagawea Pipeline Company, LLC Joint Rate Tariff.” Enbridge Pipelines Inc. https://www.enbridge.com/~/media/Enb/Documents/Tariffs/2017/NDPL%20FERC%20500.pdf. ———. 2017b. “NEB No. 414, FERC No. 45.13.0 Enbridge Pipelines Inc. in Connection with Enbridge Energy, Limited Partnership International Joint Rate Tariff.” Enbridge Pipelines Inc. https://www.enbridge.com/~/media/Enb/Documents/Tariffs/2017/EELP_FERC_45130.pdf. ———. 2017c. “NEB No. 416, FERC No. 1.9.0 Enbridge Pipelines Inc. in Connection with Enbridge Energy, Limited Partnership International Joint Rate Tariff.” Enbridge Pipelines Inc. https://www.enbridge.com/~/media/Enb/Documents/Tariffs/2017/EELP_FERC_190_L9_NEB%2 0416.pdf. Fattouh, Bassam. 2010. “The Dynamics of Crude Oil Price Differentials.” Energy Economics 32 (2):334– 42. https://doi.org/10.1016/j.eneco.2009.06.007. Federated Co-operatives Limited. 2015. “Co-Op Refinery Complex.” Coop Refinery Complex. 2015. http://www.co-oprefinery.ca/wps/portal/facts. FERC. 2017. “Tariff Browser.” Federal Energy Regulatory Commission. 2017. https://etariff.ferc.gov/TariffBrowser.aspx?tid=2094. Gillies, Chris. 2009. “Portland Pipeline Corporation/Montreal Pipeline Limited.” Technical presentation presented at the Crude Oil Quality Association General Meeting, Philadelphia, PA, June 18. http://www.coqa-inc.org/meeting-archives. Government of Canada. 2017. “Trade Data Online.” Home page. Government of Canada. 2017. http://www.ic.gc.ca/eic/site/tdo-dcd.nsf/eng/Home. Hackett, D., L. Noda, S. Grissom, M.C. Moore, and J. Winter. 2013. “Pacific Basic Heavy Oil Refining Capacity.” The School of Public Policy Research Papers, SPP Research Papers, 6 (8):1–48.

January 2018 An Economic and Environmental Assessment of 135 Eastern Canadian Crude Oil Imports

Hart Energy. 2012. “Refining Unconventional Oil – U.S. Resources Invigorate Mature Industry.” Houston, TX: Hart Energy. https://www.hartenergystore.com/. Honeywell UOP. 2017. “Refining Flow Scheme.” Honeywell International Inc. 2017. https://www.uop.com/refining-flowscheme-2/. Huber, Mark. 2010. Tanker Operations: A Handbook for the Person-In-Charge (PIC). 5th edition. Atglen, PA: Schiffer Pub Ltd. IEA. 2016. “Oil Medium-Term Market Report.” Medium-Term Report. Market Analysis and Forecasts. Paris, France: International Energy Agency. https://www.iea.org/publications/freepublications/publication/MTOMR2016.pdf. IHS CERA. 2013. “Extracting Economic Value from the Canadian Oil Sands: Upgrading and Refining in Alberta (or Not)?” Special Report. IHS Canadian Oil Sands Energy Dialogue. IHS CERA. https://www.ihs.com/forms/contactinformation.html?efid=tFSzO+2aeGqpKuUQPMWZ3Q==. IHS Energy. 2014. “Comparing GHG Intensity of the Oil Sands and the Average US Crude Oil.” Special Report. IHS Canadian Oil Sands Energy Dialogue. IHS Markit. https://www.ihs.com/forms/contactinformation.html?efid=tFSzO+2aeGqpKuUQPMWZ3Q==. Inkpen, Andrew, and Michael H. Moffett. 2011. The Global Oil & Gas Industry: Management, Strategy and Finance. Unknown edition. Tulsa, Oklahoma: Pennwell Corp. Jacobs Consultancy. 2009. “Life Cycle Assessment Comparison of North American and Imported Crudes.” AERI 1747. Chicago, IL: Alberta Energy Research Institute. http://eipa.alberta.ca/media/39640/life%20cycle%20analysis%20jacobs%20final%20report.pdf. ———. 2012. “EU Pathway Study: Life Cycle Assessment of Crude Oils in a European Context.” Prepared For Alberta Petroleum Marketing Commission. Calgary, AB: Jacobs Consultancy. http://www.energy.alberta.ca/Oil/pdfs/OSPathwayStudyEUjacobsRept2012.pdf. Kable Intelligence Ltd. 2017. “Offshore Technology - Projects.” Offshore Technology. 2017. http://www.offshore-technology.com/projects/. Kinder Morgan Canada. 2013. “Trans Mountain Pipeline.” presented at the Crude Oil Quality Association meeting, Seattle, WA, June 6. http://www.coqa-inc.org/docs/default-source/meeting- presentations/20130606_sauer.pdf. Lattanzio, Richard K. 2014. “Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions.” R42537. Congressional Research Service Reports. Washington, DC: Congressional Research Service. https://fas.org/sgp/crs/misc/R42537.pdf. Marine Insight. 2016. “Panamax and Aframax Tankers: Oil Tankers with a Difference.” Marine Insight (blog). July 20, 2016. https://www.marineinsight.com/types-of-ships/panamax-and-aframax- tankers-oil-tankers-with-a-difference/. Maritime-Connector.com. n.d. “VLCC and ULCC.” Maritime-Connector.com. n.d. http://maritime- connector.com/wiki/vlcc/.

January 2018 136 Canadian Energy Research Institute

Masnadi, Mohammad S., and Adam R. Brandt. 2017. “Climate Impacts of Oil Extraction Increase Significantly with Oilfield Age.” Nature Climate Change 7 (8):551–56. https://doi.org/10.1038/nclimate3347. Meyer, Randy. 2009. “CN Transportation Solutions for Oil Sands Production Phase.” presented at the Transportation Innovation in Alberta Oil Sands: A Summit, The Van Horne Institute, Calgary, AB, May 13. http://www.vanhorneinstitute.com/wp-content/uploads/2016/09/2-CN.pd_.pdf. Montreal Pipe Line Limited. 2015. “N.E.B. No. 173 Montreal Pipe Line Limited Tariff.” Montreal Pipe Line Limited. http://www.pmpl.com/wp-content/uploads/MPLL-Local-Tariff-N.E.B.-No.-173.pdf. Moorhouse, Jeremy, Danielle Droitsch, and Dan Woynillowicz. 2011. “Life Cycle Assessments of Oilsands Greenhouse Gas Emissions: A Checklist for Robust Analysis.” Backgrounder. The Pembina Institute. https://www.pembina.org/reports/pembina-lca-checklist.pdf. National Research Council. 1998. Oil Spill Risks From Tank Vessel Lightering. Washington, DC: The National Academies Press. https://doi.org/10.17226/6312. NEB. 2016a. “Feature Article: Understanding the Production, Transport, and Refining of Crude Oil in Canada.” National Energy Board | Government of Canada. April 29, 2016. https://www.neb- one.gc.ca/nrg/ntgrtd/mrkt/ftrrtcl/2016-04-29ndrstndngcrl-eng.html. ———. 2016b. “2012-11-29 - Application for the Line 9B Reversal and Line 9 Capacity Expansion Project (OH-002-2013).” REGDOCS. National Energy Board | Government of Canada. December 23, 2016. https://apps.neb-one.gc.ca/REGDOCS/Item/View/890819. ———. 2017a. “Archived - Estimated Production of Canadian Crude Oil and Equivalent.” National Energy Board | Government of Canada. March 15, 2017. https://www.neb- one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/archive/stmtdprdctnrchv-eng.html. ———. 2017b. “2016 Estimated Production of Canadian Crude Oil and Equivalent.” National Energy Board. https://www.neb- one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/2016/stmtdprdtncdncrdlqvlnt2016.xls. ———. 2017c. “Canada’s Pipeline Transportation System 2016.” National Energy Board | Government of Canada. June 2, 2017. https://www.neb-one.gc.ca/nrg/ntgrtd/trnsprttn/2016/cnds-ppln- trnsprttn-systm-eng.html. ———. 2017d. “Canada’s Pipeline Transportation System 2016. Montreal Pipe Line Limited’s Montreal Pipe Line.” National Energy Board | Government of Canada. June 2, 2017. https://www.neb- one.gc.ca/nrg/ntgrtd/trnsprttn/2016/grp2cmpns/lndlqds/mntrl-pp-ln-lmtd-mntrl-pp-ln- eng.html. ———. 2017e. “Feature Article: Estimates of Canadian Crude by Rail Movements Show a Peak in October 2015, Roughly One Quarter of Total Loading Capacity.” Government of Canada - National Energy Board. June 2, 2017. https://www.neb-one.gc.ca/nrg/ntgrtd/mrkt/ftrrtcl/2016- 02-01cndncrdrl-eng.html.

January 2018 An Economic and Environmental Assessment of 137 Eastern Canadian Crude Oil Imports

———. 2017f. “Market Snapshot: Canadian Crude Oil Imports from the U.S. Decline in 2016, Overseas Imports Increase.” Government of Canada - National Energy Board. June 22, 2017. https://www.neb-one.gc.ca/nrg/ntgrtd/mrkt/snpsht/2017/02-04cndncrlmprtsdcln-eng.html. ———. 2017g. “Market Snapshot: What Products Are Created from the Oil Processed in Canadian Refineries?” Government of Canada - National Energy Board. August 8, 2017. https://www.neb- one.gc.ca/nrg/ntgrtd/mrkt/snpsht/2017/08-02prdctsmdfrml-eng.html. ———. 2017h. “Canadian Crude Oil Exports by Rail – Monthly Data.” National Energy Board | Government of Canada. November 29, 2017. https://www.neb- one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/cndncrdlxprtsrl-eng.html. Nimana, Balwinder, Christina Canter, and Amit Kumar. 2015. “Life Cycle Assessment of Greenhouse Gas Emissions from Canada’s Oil Sands-Derived Transportation Fuels.” Energy 88 (August):544–54. https://doi.org/10.1016/j.energy.2015.05.078. Nimana, Balwinder, Aman Verma, Giovanni Di Lullo, Md. Mustafizur Rahman, Christina E. Canter, Babatunde Olateju, Hao Zhang, and Amit Kumar. 2017. “Life Cycle Analysis of Bitumen Transportation to Refineries by Rail and Pipeline.” Environmental Science & Technology 51 (1):680–91. https://doi.org/10.1021/acs.est.6b02889. NRCan. 2016. “Refinery Economics.” Refinery Economics | Natural Resources Canada. November 14, 2016. http://www.nrcan.gc.ca/energy/crude-petroleum/4561. ———. 2017a. “Selected Crude Oil Prices Monthly - 2016.” Government of Canada | Natural Resources Canada. January 9, 2017. http://www.nrcan.gc.ca/energy/fuel-prices/crude/17087. ———. 2017b. “Oil Supply and Demand.” Oil Supply and Demand | Natural Resources Canada. July 25, 2017. http://www.nrcan.gc.ca/energy/oil-sands/18086. ———. 2017c. “Crude Oil Facts.” Government of Canada | Natural Resources Canada. October 6, 2017. http://www.nrcan.gc.ca/energy/facts/crude-oil/20064. Oil & Gas Journal. 2016a. “Oil Tanker Freight-Rate Volatility Increases.” Oil & Gas Journal, July 4, 2016. http://www.ogj.com/articles/print/volume-114/issue-7/transportation/oil-tanker-freight-rate- volatility-increases.html. ———. 2016b. “2017 Worldwide Refining Survey.” Special Report. Houston, TX: Oil & Gas Journal. http://www.ogj.com/content/ogj/en/downloadables/survey-downloads/worldwide- refining/2016/2016-worldwide-refining-survey.pdf. ———. 2016c. “Worldwide Production.” Special Report. Houston, TX: Oil & Gas Journal. http://www.ogj.com/content/ogj/en/downloadables/survey-downloads/worldwide- production/2016/worldwide-production.pdf. Oil Sands Magazine. 2016. “A Look at Canada’s Refining Capacity and How We Compare to the Rest of the World.” News. Oil Sands Magazine. July 5, 2016. http://www.oilsandsmagazine.com/news/2016/7/5/canadian-refining-capacity-versu-the-rest- of-the-world.

January 2018 138 Canadian Energy Research Institute

———. 2017a. “Oil Transport Marine Terminals.” Oil Sands Magazine. 2017. http://www.oilsandsmagazine.com/projects/oil-loading-marine-terminals. ———. 2017b. “Crude-by-Rail Loading & Offloading Terminals.” Oil Sands Magazine. November 14, 2017. http://www.oilsandsmagazine.com/projects/crude-oil-rail-terminals. Olateju, Babatunde, and Amit Kumar. 2016. “Life Cycle Assessment and Cost of Pipeline vs Rail Transport of Bitumen.” presented at the Canadian Crude Quality Technical Association Conference, Edmonton, AB, June 8. http://www.coqa-inc.org/docs/default-source/edmonton-2016/8--- babatunde-olateju---transportation-crude-quality-conference-presentation---june-8th- 2016.pdf?sfvrsn=7a1c47bb_4. OPEC. 2016. “2016 World Oil Outlook.” World Oil Outlook. Vienna, Austria: Organization of the Petroleum Exporting Countries. http://www.opec.org/opec_web/static_files_project/media/downloads/publications/WOO%20 2016.pdf. ———. 2017. “OPEC Annual Statistical Bulletin.” Annual Bulletin. Vienna, Austria: Organization of the Petroleum Exporting Countries. http://www.opec.org/opec_web/static_files_project/media/downloads/publications/ASB2017_ 13062017.pdf. Pacheco, Diana M., Joule A. Bergerson, Anton Alvarez-Majmutov, Jinwen Chen, and Heather L. MacLean. 2016. “Development and Application of a Life Cycle-Based Model to Evaluate Greenhouse Gas Emissions of Oil Sands Upgrading Technologies.” Environmental Science & Technology 50 (24):13574–84. https://doi.org/10.1021/acs.est.5b04882. Reboredo, Juan C. 2011. “How Do Crude Oil Prices Co-Move?: A Copula Approach.” Energy Economics 33 (5):948–55. https://doi.org/10.1016/j.eneco.2011.04.006. Rodrigo de Larrucea, Jaime. 2010. “Oil Tankers Safety: Legal Aspects.” Barcelona, Spain: Universitat Politècnica de Catalunya. http://upcommons.upc.edu/bitstream/handle/2117/6129/OIL%20TANKERS%20SAFETY.pdf. Sep-Pro Systems. 2009. “Crude Oil Topping Units.” Sep-Pro Systems, Inc. 2009. http://www.sepprosystems.com/Crude_Oil_Topping.html. Simmons, Gary, and Ralph Phillip. 2008. “Valero Energy St. Charles Refinery Tour – April 6, 2008.” Management Presentation, Valero, QC, April 6. https://www.slideshare.net/finance2/valero- energy-st-charles-refinery-tour-april-6-2008. Statista. 2017. “World’s Largest Railway Companies: Market Value 2017.” The Statistics Portal. Statista.com. 2017. https://www.statista.com/statistics/260683/the-largest-energy-railway- companies-worldwide-based-on-market-value/. Statistics Canada. 2016. “CANSIM - 133-0004 - Receipts and Disposition of Crude Oil and Pentanes Plus, by Source Monthly (Cubic Metres).” CANSIM (database). Statistics Canada | Government of Canada. April 19, 2016. http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=1330004.

January 2018 An Economic and Environmental Assessment of 139 Eastern Canadian Crude Oil Imports

———. 2017a. “Canadian International Merchandise Trade Database.” Government of Canada | Statistics Canada. October 23, 2017. http://www5.statcan.gc.ca/cimt-cicm/home- accueil?lang=eng. ———. 2017b. “CANSIM - 404-0021 - Rail Transportation, Origin and Destination of Commodities.” Government of Canada | Statistics Canada. October 31, 2017. http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=4040021. ———. 2017c. “CANSIM - 126-0003 - Supply and Disposition of Crude Oil and Equivalent Monthly (Cubic Metres).” CANSIM (database). Statistics Canada | Government of Canada. November 9, 2017. http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=1260003. ———. 2017d. “CANSIM - 134-0001 - Refinery Supply of Crude Oil and Equivalent, Monthly.” CANSIM (database). Statistics Canada | Government of Canada. November 10, 2017. http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=1340001. ———. 2017e. “CANSIM - 134-0004 - Supply and Disposition of Refined Petroleum Products Monthly (Cubic Metres).” CANSIM (database). Statistics Canada | Government of Canada. November 14, 2017. http://www5.statcan.gc.ca/cansim/a26?lang=eng&id=1340004. Suncor Energy Inc. 2017a. “Annual Report 2016.” Annual Report. Calgary, AB: Suncor Energy Inc. http://www.suncor.com/investor-centre/financial-reports/annual-disclosure. ———. 2017b. “Annual Information Form.” Suncor Energy Inc. https://sustainability.suncor.com/2017/pdf/Annual_Information_Form_2016_EN.pdf. Tamm, David C., and Kevin P. Milburn. 2017. “Cumulative Impacts of Climate Change and Other Policy Scenarios Facing the Canadian Downstream Petroleum Sector.” Baker & O’Brien, Inc. TankerOperator. 2008. “Tanker Shipping Review 2008.” TankerOperator. https://www.scribd.com/document/6008299/TANKER-SHIPPING-REVIEW-March2008. ———. 2017. “Where Next?” TankerOperator, 2017. Tarnoczi, Tyler. 2013. “Life Cycle Energy and Greenhouse Gas Emissions from Transportation of Canadian Oil Sands to Future Markets.” Energy Policy 62 (November):107–17. https://doi.org/10.1016/j.enpol.2013.08.001. The Economist Intelligence Unit. 2017. “Democracy Index 2016.” The Economist Intelligence Unit. 2017. https://www.eiu.com/topic/democracy-index. TIAX LLC, and MathPro Inc. 2009. “Comparison of North American and Imported Crude Oil Lifecycle GHG.” Final Report TIAX Case No. 5595. Cupertino, CA: TIAX LLC. http://www.assembly.ab.ca/lao/library/egovdocs/2009/aleri/173913.pdf. TransCanada. 2016. “Energy East Pipeline Ltd. Consolidated Application Volume 3: Commercial.” Consolidated Application. Calgary, AB: National Energy Board. https://apps.neb- one.gc.ca/REGDOCS/File/Download/2958032.

January 2018 140 Canadian Energy Research Institute

Transportation Safety Board of Canada. 2014. “Runaway and Main-Track Derailment: Montreal, Maine and Atlantic Railway, Freight Train Mma-002, Mile 0.23, Sherbrooke Subdivision, Lac-Mégantic, Quebec, 06 July 2013.” Railway Investigation Report R13D0054. Gatineau, QC: Transportation Safety Board of Canada. http://www.tsb.gc.ca/eng/rapports- reports/rail/2013/r13d0054/r13d0054.pdf. US EIA. 2014. “Oil Tanker Sizes Range from General Purpose to Ultra-Large Crude Carriers on AFRA Scale.” U.S. Energy Information Administration - Today in Energy. September 16, 2014. https://www.eia.gov/todayinenergy/detail.php?id=17991. ———. 2015. “Midwest (PADD 2) Refinery Utilization and Capacity.” U.S. Energy Information Administration. 2015. https://www.eia.gov/dnav/pet/pet_pnp_unc_dcu_r20_m.htm. ———. 2016. “Crude Imports.” Independent Statistics and Analysis. U.S. Energy Information Administration. 2016. https://www.eia.gov/petroleum/imports/browser/#/?vs=PET_IMPORTS.WORLD-US-ALL.A. ———. 2017. “U.S. Number and Capacity of Petroleum Refineries.” Independent Statistics and Analysis. U.S. Energy Information Administration. June 21, 2017. https://www.eia.gov/dnav/pet/pet_pnp_cap1_dcu_nus_a.htm. US EPA. 2015. “Emission Factors for Greenhouse Gas Inventories.” EPA Centre for Corporate Climate Leadership. https://www.epa.gov/sites/production/files/2016-09/documents/emission- factors_nov_2015_v2.pdf. US Securities and Exchange Commission. 2006. “Form 40-F. Annual Report Pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934: Canadian Pacific Railway Limited.” http://www.barchart.com/plmodules/?module=secFilings&filingid=4291896&type=HTML&popu p=1&override=1&symbol=CP. Vafi, Kourosh, and Adam R. Brandt. 2013. “Greenhouse Gas Emissions from Oil Production: Insights from an Open-Source Modelling Effort.” presented at the 2013 CRC Life Cycle Analysis of Transportation Fuels Workshop, Argonne National Laboratory, October 15. https://crcao.org/workshops/LCA/LCA%20October%202013/Session%204/Brandt,%20Adam.pdf . ———. 2014. “Reproducibility of LCA Models of Crude Oil Production.” Environmental Science & Technology 48 (21):12978–85. https://doi.org/10.1021/es501847p. Van Praet, Nicolas. 2014. “Valero Moves to Source All Crude for Quebec Refinery from North America by End of 2014.” Financial Post, March 20, 2014. http://business.financialpost.com/commodities/energy/valero-strikes-deal-to-ship-line-9-crude- from-montreal-to-quebec-city-by-tanker. Vellenga, John. 2017. “Oil Refinery.” The Cheaper Petrol Party. 2017. http://www.cpp.org.au/Refinery.php.

January 2018 An Economic and Environmental Assessment of 141 Eastern Canadian Crude Oil Imports

Wang, Jingfan, Yuchi Sun, Sharad Bharadwaj, and Adam Brandt. 2016. “Operating Data for CEIP Oil Carbon Index.” Stanford University, Department of Energy Resources Engineering. http://oci.carnegieendowment.org/assets/resources/opgee-oci-website-75-fields-v20.xlsx. Wiki.dot. 2015. “Oil And Gas Field Database - A Barrel Full.” A Barrell Full - Wiki.dot. 2015. http://abarrelfull.wikidot.com/oil-and-gas-field-database.

January 2018 142 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 143 Eastern Canadian Crude Oil Imports Appendix A: Factual and Used 2016 Import Volumes in the Study

2016 Actual Import 2016 Used Import Province Country Volumes Volumes (Mbpd) (Mbpd) NB Azerbaijan 2.8 2.8 NB Colombia 5.3 5.3 NB Congo 2.7 2.7 NB Equatorial Guinea 2.4 2.4 NB Ivory Coast 12.6 12.6 NB Nigeria 44.9 44.9 NB Norway 26.3 26.3 NB Saudi Arabia 86.7 86.7 NB United States 34.4 34.4 NL Algeria 0.8 0.8 NL Denmark 1.7 1.7 NL Nigeria 18.3 18.3 NL Norway 13.8 13.8 NL United Kingdom 6.2 6.2 NL United States 49.0 49.0 ON United States 85.0 58.1 QC Algeria 83.9 92.1 QC Azerbaijan 4.1 4.5 QC Kazakhstan 19.2 21.1 QC Nigeria 10.5 11.5 QC Norway 1.7 1.9 Papua New QC Guinea 0.0 0.0 QC United Kingdom 3.7 4.1 QC United States 91.0 99.9 Total 607.0 601.0

January 2018 144 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 145 Eastern Canadian Crude Oil Imports Appendix B: Detailed Crude Flows and Transportation Path of the Base Case

Province/Refinery Base Case Crude Volume Origin Transportation Path Type ON Imperial Bitumen 25.2 AB Bitumen Pipeline, Mainline Oil-Sarnia Heavy 6.0 AB Heavy SCO 21.5 AB SCO Light 9.3 AB Light Light 17.6 US North Dakota Shell- Heavy 14.8 AB Heavy Sarnia SCO 13.6 AB SCO Light 8.2 AB Light Light 11.12 US North Dakota Suncor Heavy 14.8 AB Heavy Energy- SCO 16.1 AB SCO Sarnia Light 15.7 AB Light Light 13.13 US North Dakota Imperial Heavy 14.8 AB Heavy Oil- SCO 19.1 AB SCO Nanticoke Light 0.6 ON Light Rail Light 26.6 AB Light Pipeline, Mainline Light 16.26 US North Dakota QC Suncor Bitumen 16.4 AB Bitumen Pipeline, Mainline, Line 9 Energy- Light 16.4 NL Offshore Light Tanker, Portland-Montreal Montreal pipeline Light 48.0 US North Dakota Pipeline, Mainline, Line 9 14.1 US Michigan Pipeline, Mainline, Line 9 30.63 US WTI Pipeline, Tanker, Portland- 4.5 Azerbaijan Montreal pipeline 1.9 Norway 4.1 UK Valero- Bitumen 11.6 AB Bitumen Pipeline, Mainline, Line 9, Tanker Lévis Heavy 8.1 AB Heavy SCO 81.2 AB SCO Light 6.3 US Texas Eagle Ford Pipeline, Mainline 0.9 US WTI Pipeline, Mainline 92.1 Algeria Tanker 21.1 Kazakhstan Pipeline, Tanker 11.5 Nigeria Tanker

January 2018 146 Canadian Energy Research Institute

Province/Refinery Base Case Crude Volume Origin Transportation Path Type NB Irving Oil- SCO 11.9 AB SCO Rail Saint Jones Light 31.6 NL Offshore Light Tanker Light 16.1 NL Offshore Light (Hibernia) Heavy 5.3 Colombia Heavy 10.0 Ivory Coast Light 17.7 US WTI Pipeline, Tanker 1.5 US Texas Eagle Ford Pipeline, Tanker 12.8 US Louisiana LLS Tanker 2.4 US Louisiana Thunderhorse Tanker 2.8 Azerbaijan Pipeline, Tanker 2.7 Congo Tanker 2.4 Equatorial Guinea 2.6 Ivory Coast 86.7 Saudi Arabia 15.9 Nigeria Usan 29.0 Nigeria Bonga 26.3 Norway NL North Light 3.3 NL Offshore Light Atlantic 14.8 US WTI Pipeline, Tanker Refining 34.2 US Louisiana Tanker 0.8 Algeria 18.3 Nigeria 13.8 Norway 6.2 UK 1.7 Denmark

January 2018 An Economic and Environmental Assessment of 147 Eastern Canadian Crude Oil Imports Appendix C: Inventory of Canadian and Foreign Crude Oils Used in the Study and Results of Upstream and Midstream GHG Emissions Modelling Table C.1: Inventory of Canadian and Foreign Crude Oils Used in the Study for Crude Flows and GHG Emissions Modelling Crude oil Is this Is this an Individual crude oil Crude Assumptions/reasons for selecting individual crude oil brand/blend as a brand/blend name used existing brand/blend category proxy for GHG emissions modelling name as used for crude crude oil selected as proxy in the report flows blend? for GHG emissions modelling? modelling Canadian Crude Oils Mixed Sweet No Yes Mixed Sweet Blend Light Sweet Represents AB, SK, and MB light sweet crude oils. As transport Blend commodity, Mixed Sweet Blend includes 16 light sweet crude oil brands and blends as receipt commodities, with most them from AB, but also from southeastern SK and southwestern MB1. Mixed Sour No Yes Mixed Sour Blend Light Sour Represents AB light sour crude oils. As transport commodity, Mixed Sour Blend Blend includes 14 light and medium sour crude oil brands and blends as receipt commodities2. AB Light Yes Modelled Mixed Sweet Blend Light For modelling, AB Light is assumed to be a blend of Mixed Sweet Blend by CERI and Mixed Sour (72 percent) and Mixed Sour Blend (28 percent), based on data from the Blend Crude Oil Logistics Committee (COLC 2016). Light Sour No Yes Light Sour Blend Light Sour Represents SK and MB light sour crude oils. As transport commodity, Light Blend Sour Blend includes five crude oil brands from southeastern SK and southwestern MB3. Midale No Yes Midale Medium Represents southeastern SK and southwestern MB medium-light sour Sour crude oils4. SK Light Yes Modelled Mixed Sweet Blend, Light For modelling, SK Light is assumed to be a blend of Mixed Sweet Blend by CERI Light Sour Blend, (30 percent), Light Sour Blend (35 percent) and Midale (35 percent) based and Midale on data from the Crude Oil Logistics Committee (COLC 2016). MB Light Yes Modelled Mixed Sweet Blend, Light For modelling, MB Light is assumed to be a blend of Mixed Sweet Blend by CERI Light Sour Blend, (30 percent), Light Sour Blend (35 percent) and Midale (35 percent) based and Midale on data from the Crude Oil Logistics Committee (COLC 2016).

January 2018 148 Canadian Energy Research Institute

Crude oil Is this Is this an Individual crude oil Crude Assumptions/reasons for selecting individual crude oil brand/blend as a brand/blend name used existing brand/blend category proxy for GHG emissions modelling name as used for crude crude oil selected as proxy in the report flows blend? for GHG emissions modelling? modelling NL Light Yes Modelled Hibernia Light Sour Represents Eastern Canadian light offshore oils. Offshore by CERI ON Light Yes Modelled Mixed Sweet Blend Light In the absence of data that specifies which fields constitute ON Light crude by CERI and Mixed Sour oil blend, AB Light (consisting of Mixed Sweet Blend and Mixed Sour Blend Blend) was used as a proxy for the purposes of modelling. AB SCO Yes Modelled Synthetic Sweet Light Sweet Represents a typical AB SCO - extra-heavy and high-sulfur bitumen mined by CERI Blend SCO from the Athabasca oil sands (AB) that is upgraded to a light sweet synthetic crude oil before transport to the refinery (CARB 2015b). AB Heavy Yes Modelled Western Canadian Heavy Sour Represents conventional heavy sour crude oils from the heavy oil belt by CERI Blend regions of AB (CARB 2015b; COLC 2016; Crude Quality Inc. 2017). AB Bitumen Yes Modelled Western Canadian Dilbit Western Canadian Select is a blend of conventional and oil sands by CERI Select production that represent AB dilbit (COLC 2016; Crude Quality Inc. 2017). Foreign Crude Oils Algeria Yes Yes Algeria Saharan Ultra-Light Saharan Blend represents Algerian light crudes and is an actual crude oil Saharan Blend Sweet brand imported to Canada. Blend Azerbaijan Yes Yes Azerbaijan Azeri Light Sweet Azeri Light represents Azerbaijanian light crudes and is an actual crude oil Azeri Light Light brand imported to Canada. Colombia Yes Yes Colombia Castilla Heavy Sour Castilla Blend represents Colombian heavy crudes and is an actual crude Castilla Blend Blend oil brand imported to Canada. Congo Djeno Yes Yes Congo Djeno Blend Medium Djeno Blend represents Congolese medium crudes and is an actual crude Sweet oil brand imported to Canada. Denmark Yes Yes Denmark Dansk Light Sweet In the absence of publicly available data for the offshore DUC Blend, light DUC Blend sweet Denmark Dansk Blend (collected from some of the same fields in the North Sea) was used as a proxy for the purposes of modelling (Wang et al. 2016). Equatorial Yes Yes Equatorial Guinea Medium Zafiro Blend is one of the actual Equatorial Guinea medium crude oil Guinea Zafiro Zafiro Blend Sweet brands imported to Canada and was used as a proxy for the purposes of modelling. Ivory Coast Yes Yes Ivory Coast Baobab Heavy Baobab represents Ivorian heavy crudes and is an actual crude oil brand Baobab Sweet imported to Canada.

January 2018 An Economic and Environmental Assessment of 149 Eastern Canadian Crude Oil Imports

Crude oil Is this Is this an Individual crude oil Crude Assumptions/reasons for selecting individual crude oil brand/blend as a brand/blend name used existing brand/blend category proxy for GHG emissions modelling name as used for crude crude oil selected as proxy in the report flows blend? for GHG emissions modelling? modelling Ivory Coast Yes Yes Ivory Coast Espoir Light Sweet Espoir represents Ivorian medium-light crudes and is an actual crude oil Espoir brand imported to Canada. Kazakhstan Yes Yes Kazakhstan Tengiz Ultra-Light In the absence of publicly available data for the CPC Blend, Kazakhstan CPC Blend Sour Tengiz that represents approximately 60% of the Blend was used a proxy for the purposes of modelling (Chevron Corporation 2017). Nigeria Akpo Yes Yes Nigeria Akpo Blend Ultra-Light Akpo Blend is an actual Nigerian crude oil brand imported to Canada. Blend Sweet Nigeria Yes Yes Nigeria Bonga Medium Bonga is an actual Nigerian crude oil brand imported to Canada. Bonga Sweet Nigeria Yes Yes Nigeria Bonny Light Light Sweet Bonny Light is an actual Nigerian crude oil brand imported to Canada. Bonny Light Nigeria Brass Yes Yes Nigeria Brass River Light Sweet Brass River is an actual Nigerian crude oil brand imported to Canada. River Nigeria Qua Yes Yes Nigeria Qua Iboe Light Sweet Qua Iboe is an actual Nigerian crude oil brand imported to Canada. Iboe Nigeria Usan Yes Yes Nigeria Usan Medium Usan is an actual Nigerian crude oil brand imported to Canada. Sweet Norway Yes Yes Norway Ekofisk Light Sweet Ekofisk is an actual Norwegian crude oil brand imported to Canada. Ekofisk Norway Yes Modelled Norway Oseberg Light Sweet In the absence of data regarding a specific Norwegian light crude brand Norwegian by CERI imported to Canada, light sweet Norway Oseberg was used as a proxy for Crude the purposes of modelling. Saudi Arabia Yes Modelled Saudi Arabia Light Sour In the absence of data regarding a specific Saudi Arabian light crude brand Light by CERI Ghawar imported to Canada, light sour Saudi Arabia Ghawar that has the highest production volume was used as a proxy for the purposes of modelling (CARB 2015b). UK Brent Yes Yes UK Brent Light Sweet Brent is an actual crude oil brand imported to Canada from the UK. UK North Sea Yes Modelled UK Brent Light Sweet In the absence of data regarding a specific UK North Sea light crude brand by CERI imported to Canada, the UK Brent collected from the offshore fields in the North Sea was used as a proxy for the purposes of modelling.

January 2018 150 Canadian Energy Research Institute

Crude oil Is this Is this an Individual crude oil Crude Assumptions/reasons for selecting individual crude oil brand/blend as a brand/blend name used existing brand/blend category proxy for GHG emissions modelling name as used for crude crude oil selected as proxy in the report flows blend? for GHG emissions modelling? modelling US Bakken Yes Yes US Bakken (No Light Sweet Represents light sweet crude oils from the Williston basin (Bakken play) in (ND) Flare) North Dakota (CARB 2015b; Wang et al. 2016). US Bakken is an actual crude oil brand imported to Canada. US Bakken (No Flare) was used as a proxy for the purposes of modelling. US Eagle Ford Yes Yes US Eagle Ford (TX) Ultra-Light Represents light sweet crude oils from the complex Eagle Ford play in (TX) Sweet Texas where production zones range from oil to gas (Wang et al. 2016). Eagle Ford (TX) is an actual crude oil brand imported to Canada. US LLS (LA) Yes Yes US LLS (LA) Light Sweet Represents light sweet crude oils from the coast of Louisiana (Lake Washington field) (Wang et al. 2016). US Louisiana Light Sweet (US LLS) is an actual crude oil brand imported to Canada. US Thunder Yes Yes US Thunder Horse Light Sour Represents light sour crude oils located offshore in the US Gulf of Mexico Horse (LA) (LA) (Wang et al. 2016). US Thunder Horse is an actual crude oil brand imported to Canada. US Michigan Yes Modelled US Bakken (No Light Sweet In the absence of publicly available data for the US Michigan Light Sweet Light (MI) by CERI Flare) crude oil, US Bakken (No Flare) was used as a proxy for the purposes of modelling. US WTI Yes Yes US WTI Light Sweet Represents light sweet crude oils from the Permian basin (Wang et al. 2016). US West Texas Intermediate (US WTI) is an actual crude oil brand imported to Canada. Data Sources: (Enbridge 2016b, 2017f; CARB 2015b; Chevron Corporation 2017; COLC 2016; CrudeMonitor.ca (Crude Quality Inc. 2017); Wang et al. 2016), CERI assumptions.

Notes: 1. Mixed Sweet Blend as transport commodity includes Pembina, Gibson Light, Joarcam, Kinder Morgan Sweet, Pembina Sweet Blend, Peace Pipe Light, Rangeland Sweet, Redwater, Rainbow Light, Federated, HCT Sweet Blend, Gibson Mixed Blend Sweet, Light Smiley, MB Sweet Tundra, Plains Sweet Regina, and BP SW as receipt commodities (Enbridge 2016b, 2017f; COLC 2016). 2. Mixed Sour Blend as transport commodity Includes Gibson Sour, Kinder Morgan High Sour, Pembina High Sour, Peace Pipe Sour, Rangeland Sour, Gibsons High Sour, Central AB Pipeline, Pembina Light Sour, Gibson Light Sour, Joarcam, Kinder Morgan Low Sour, Pembina Low Sour, Gibsons Low Sour, and Hardisty Light as receipt commodities (Enbridge 2016b, 2017f; COLC 2016). 3. Light Sour Blend as transport commodity includes MB Light, South East Sask, Tundra Light Sour, ICG Light Sour, and Moose Jaw Tops as receipt commodities (Enbridge 2016b, 2017f; COLC 2016). 4. Midale as transport commodity includes MB Medium and Wispur Midale as receipt commodities (Enbridge 2016b, 2017f; COLC 2016).

January 2018 An Economic and Environmental Assessment of 151 Eastern Canadian Crude Oil Imports

Table C.2: Results of Upstream and Midstream GHG Emissions Modelling for Canadian and Foreign Crude Oils Used in the Study Crude oil GHG emissions, Input data sources and assumptions for GHG emissions calculations brand/blend kg CO2 eq/bbl crude name Upstream Midstream Upstream1 Midstream2 Canadian Crude Oils Mixed Sweet 40.8 15.3 Input data: California ARB (CARB 2015b). Input data: CrudeMonitor.ca mini-assay (Crude Quality Blend Input data use average crude production parameters Inc. 2017) converted to the PRELIM format3. Default for AB to model conventional light and medium blends refinery configuration: hydroskimming. from Western Canada, due to the lack of data for specific fields that constitute each crude oil blend (CARB 2015b). Mixed Sour 42.0 27.3 Input data: California ARB (CARB 2015b). Input data: CrudeMonitor.ca mini-assay (Crude Quality Blend Input data use average crude production parameters Inc. 2017) converted to the PRELIM format3. Default for AB to model conventional light and medium blends refinery configuration: medium conversion (FCC & GO- from Western Canada, due to the lack of data for HC). specific fields that constitute each crude oil blend (CARB 2015b). Light Sour 41.4 32.2 Input data: California ARB (CARB 2015b). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Blend Input data use average crude production parameters CrudeMonitor.ca assay. Default refinery configuration: for AB to model conventional light and medium blends medium conversion (FCC & GO-HC). from Western Canada, due to the lack of data for specific fields that constitute each crude oil blend (CARB 2015b). Midale 49.7 33.9 Input data: California ARB (CARB 2015b). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Input data use average crude production parameters CrudeMonitor.ca assay. Default refinery configuration: for AB to model conventional light and medium blends medium conversion (FCC & GO-HC). from Western Canada, due to the lack of data for specific fields that constitute each crude oil blend (CARB 2015b). Hibernia 12.2 24.2 Input data: Stanford University (Wang et al. 2016), Input data: Assay Inventory spreadsheet (PRELIM v1.1), ExxonMobil website. ExxonMobil crude assay. Default refinery configuration: medium conversion (FCC & GO-HC).

January 2018 152 Canadian Energy Research Institute

Crude oil GHG emissions, Input data sources and assumptions for GHG emissions calculations brand/blend kg CO2 eq/bbl crude name Upstream Midstream Upstream1 Midstream2 Synthetic 129.4 14.7 Input data: California ARB (CARB 2015b). Synthetic Input data: CrudeMonitor.ca mini-assay (Crude Quality Sweet Blend Sweet Blend is assumed to be a 50:50 blend of Suncor Inc. 2017) converted to the PRELIM format3. Default Synthetic A and Syncrude Sweet Premium. A weighted refinery configuration: hydroskimming. average of OPGEE outputs for these two crude blends was used to determine resulting upstream GHG emissions for Synthetic Sweet Blend (CARB 2015b). Western 72.4 57.7 Input data: California ARB (CARB 2015b). Input data use Input data: Assay Inventory spreadsheet (PRELIM v1.1), Canadian (78.5)4 average crude production parameters for AB to model CrudeMonitor.ca assay. Default refinery configuration: Blend conventional heavy blends from the oil sands and heavy deep conversion (FCC & GO-HC). oil belt regions of AB and SK, due to the lack of data for specific fields (CARB 2015b). For the purposes of modelling, these heavy crude blends are assumed to be produced using cold heavy oil production with sand (CHOPS) and be blended with diluent to specific API gravity before transportation (CARB 2015b). Western 111.4 61.3 Input data: California ARB (CARB 2015b). For the Input data: Assay Inventory spreadsheet (PRELIM v1.1), Canadian (84.9)4 purposes of modelling, WCS is assumed to be a blend of CrudeMonitor.ca assay. Default refinery configuration: Select5 sweet synthetic crude (30 percent), in situ bitumen deep conversion (FCC & GO-HC). (60 percent), and conventional heavy crude (10 percent) (CARB 2015b). Input data use the following crudes as proxies: Suncor Synthetic A for sweet synthetic; a 50:50 blend of CNRL Primrose Wolf Lake and Cenovus Foster Creek (partially diluted with diluent) for the in situ bitumen, and conventional heavy crude from AB or SK heavy oil belt region which is assumed to be produced using CHOPS and diluted with diluent (CARB 2015b). Foreign Crude Oils Algeria 71.9 17.0 Input data: California ARB (CARB 2015b). Input data: Maersk Oil crude assay converted to the Saharan Blend PRELIM format3. Default refinery configuration: hydroskimming.

January 2018 An Economic and Environmental Assessment of 153 Eastern Canadian Crude Oil Imports

Crude oil GHG emissions, Input data sources and assumptions for GHG emissions calculations brand/blend kg CO2 eq/bbl crude name Upstream Midstream Upstream1 Midstream2 Azerbaijan 14.8 13.4 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Azeri Light Chevron crude assay. Default refinery configuration: hydroskimming. Colombia 42.2 77.6 Input data: California ARB (CARB 2015b). For the Input data: EcoPetrol crude assay converted to the Castilla Blend (84.0)4 purposes of modelling, Castilla Blend is assumed to be a PRELIM format3. Default refinery configuration: deep blend of crudes from Castilla and other adjacent fields conversion (FCC & GO-HC). (70 percent) mixed with diluent (30 percent) (CARB 2015b). Congo Djeno 52.6 29.2 Input data: California ARB (CARB 2015b). Input data: TOTAL crude assay converted to the PRELIM Blend format3. Default refinery configuration: medium conversion (FCC & GO-HC). Denmark 20.8 12.5 Input data: Stanford University (Wang et al. 2016). For Input data: Assay Inventory spreadsheet (PRELIM v1.1), Dansk Blend the purposes of modelling, Denmark Dansk Blend is Statoil crude assay. Default refinery configuration: assumed to be a blend of crudes from Dan/Gorm fields hydroskimming. (Wang et al. 2016). Equatorial 109.7 41.8 Input data: California ARB (CARB 2015b). Input data: ExxonMobil crude assay converted to the Guinea Zafiro PRELIM format3. Default refinery configuration: Blend medium conversion (FCC & GO-HC). Ivory Coast 37.0 66.1 Input data: various sources, including (CNRL 2017, Input data: since Ivory Coast Baobab crude assay is not Baobab (92.7)4 Svenska 2016), (Kable Intelligence Ltd. 2017; Wiki.dot publicly available, Chevron’s China Qin Huang crude 2015). assay from the Assay Inventory spreadsheet (PRELIM v1.1) was used as a proxy for midstream GHG emissions modelling. Default refinery configuration: deep conversion (FCC & GO-HC)6. Ivory Coast 40.1 14.5 Input data: various sources, including (Svenska 2016, Input data: TullowOil crude assay converted to the Espoir TullowOil 2006), (Kable Intelligence Ltd. 2017; Wiki.dot PRELIM format3. Default refinery configuration: 2015). hydroskimming. Kazakhstan 18.9 29.0 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Tengiz Chevron crude assay. Default refinery configuration: medium conversion (FCC & GO-HC). Nigeria Akpo 74.4 20.0 Input data: various sources, including (CARB 2015b; Input data: TOTAL crude assay converted to the PRELIM Blend Wiki.dot 2015). format3. Default refinery configuration: hydroskimming.

January 2018 154 Canadian Energy Research Institute

Crude oil GHG emissions, Input data sources and assumptions for GHG emissions calculations brand/blend kg CO2 eq/bbl crude name Upstream Midstream Upstream1 Midstream2 Nigeria Bonga 24.3 21.0 Input data: California ARB (CARB 2015b). Input data: Assay Inventory spreadsheet (PRELIM v1.1), ExxonMobil crude assay. Default refinery configuration: medium conversion (FCC & GO-HC). Nigeria Bonny 91.2 20.8 Input data: California ARB (CARB 2015b)7. Input data: Assay Inventory spreadsheet (PRELIM v1.1), Light Chevron crude assay. Default refinery configuration: hydroskimming. Nigeria Brass 99.6 21.1 Input data: California ARB (CARB 2015b)8. Input data: TOTAL crude assay converted to the PRELIM River format3. Default refinery configuration: hydroskimming. Nigeria Qua 67.9 17.5 Input data: California ARB (CARB 2015b). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Iboe ExxonMobil crude assay. Default refinery configuration: hydroskimming. Nigeria Usan 75.9 47.1 Input data: various sources, including (CARB 2015b; Input data: ExxonMobil crude assay converted to the Kable Intelligence Ltd. 2017; Wiki.dot 2015). PRELIM format3. Default refinery configuration: medium conversion (FCC & GO-HC). Norway 12.9 26.4 Input data: Stanford University (Wang et al. 2016), Input data: Assay Inventory spreadsheet (PRELIM v1.1), Ekofisk Norwegian Petroleum website. Statoil crude assay. Default refinery configuration: hydroskimming. Norway 55.4 17.7 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Oseberg Statoil crude assay. Default refinery configuration: hydroskimming. Saudi Arabia 22.0 27.3 Input data: California ARB (CARB 2015b). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Ghawar Stratiev’s Arab Light crude assay. Default refinery configuration: medium conversion (FCC & GO-HC). UK Brent 84.9 16.5 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Chevron crude assay. Default refinery configuration: hydroskimming. US Bakken 7.7 18.0 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), (No Flare) a proxy crude assay from various sources (since US Bakken crude assay is not publicly available) (J. A. Bergerson et al. 2016). Default refinery configuration: hydroskimming.

January 2018 An Economic and Environmental Assessment of 155 Eastern Canadian Crude Oil Imports

Crude oil GHG emissions, Input data sources and assumptions for GHG emissions calculations brand/blend kg CO2 eq/bbl crude name Upstream Midstream Upstream1 Midstream2 US Eagle Ford 20.3 19.6 Input data: Stanford University (Wang et al. 2016). US Input data: Assay Inventory spreadsheet (PRELIM v1.1), (TX) Eagle Ford is assumed to be a 50:50 blend of US Eagle Platts’ Eagle Ford Ultralight crude assay as a proxy for Ford Black Oil and US Eagle Ford Volatile Oil. An US Eagle Ford Black Oil, and Ceric Emir’s Margham Light average of OPGEE outputs for those two crude blends crude assay as a proxy for US Eagle Ford Volatile Oil, was used to determine the resulting upstream GHG due to the absence of oil assays from the Eagle Ford emissions for US Eagle Ford. fields (J. A. Bergerson et al. 2016). An average of PRELIM outputs for those two crude assays was used to determine the resulting upstream GHG emissions for US Eagle Ford. Default refinery configuration: hydroskimming. US LLS (LA)9 127.8 15.4 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Stratiev’s Louisiana Light Sweet crude assay. Default refinery configuration: hydroskimming. US Thunder 18.8 32.1 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Horse (LA) BP Thunderhorse crude assay. Default refinery configuration: medium conversion (FCC & GO-HC). US WTI10 27.9 17.3 Input data: Stanford University (Wang et al. 2016). Input data: Assay Inventory spreadsheet (PRELIM v1.1), Stratiev’s West Texas Intermediate crude assay. Default refinery configuration: hydroskimming. Data Sources: (CARB 2015b; CrudeMonitor.ca (Crude Quality Inc. 2017); Kable Intelligence Ltd. 2017; OPGEE v2.0a (El-Houjeiri and Brandt 2017); PRELIM v1.1 (J. A. Bergerson et al. 2016); Wang et al. 2016; Wiki.dot 2015), crude oil assays from EcoPetrol, ExxonMobil, Maersk Oil, Norwegian Petroleum, TOTAL, Tullow Oil websites, CERI calculations. Notes: 1. All upstream GHG emissions for the crude oils used in the study were calculated using OPGEE v2.0a model (El-Houjeiri and Brandt 2017) and exclude transportation emissions. GHG emissions resulting from crude oil transport to the refinery inlet in Houston, TX, or Los Angeles, CA, as default destinations according to (CARB 2015b; Wang et al. 2016) were deducted from the total upstream GHG emissions outputs for each modelled oil. 2. All midstream GHG emissions for the crude oils used in the study were calculated using PRELIM v1.1 model (J. A. Bergerson et al. 2016). 3. The authors would like to personally thank John Guo, MSc., and Dr. Joule Bergerson at the University of Calgary (PRELIM project team) for their help with converting publicly available assays for the selected crude oils into the PRELIM format. 4. Midstream GHG emissions for the deep conversion refinery configuration with the coking unit (the first number) or the hydrocracking unit (the second number in parentheses). 5. Upstream and midstream GHG emissions for Western Canadian Select are reported per barrel of diluted bitumen, not per barrel of crude oil produced.

January 2018 156 Canadian Energy Research Institute

6. For the purposes of the study, Ivory Coast Baobab (API gravity 23.0) was considered as heavy crude oil, rather than medium, therefore, deep conversion (FCC & GO-HC) was selected as a default refinery configuration. 7. Upstream GHG emissions for Nigeria Bonny Light based on input data provided by four producing companies (SPDC, Chevron, Total E&P, others) differ 2.5 times (CARB 2015b). Upstream GHG emissions outputs based on Chevron data were selected for the purposes of the study to reflect the fact Chevron has one of the highest oil production volumes and the biggest number of producing wells within this field. 8. Upstream GHG emissions for Nigeria Brass River based on input data provided by six producing companies (SPDC, Chevron, NAOC Phillips, Addax, AENR/AGIP, others) range ten-fold difference (CARB 2015b). Upstream GHG emissions outputs based on Chevron data were selected for the purposes of the study to reflect the fact Chevron has one of the highest oil production volumes and the biggest number of producing wells within this field. 9. US Louisiana Light Sweet (LLS) is identified as US Louisiana Lake Washington Field in (Wang et al. 2016). 10. US West Texas Intermediate (WTI) is identified as US Texas Spraberry in (Wang et al. 2016).

January 2018 An Economic and Environmental Assessment of 157 Eastern Canadian Crude Oil Imports Appendix D: Tanker Transportation Costs by Origin and Destination

From To $ / bbl Canada-Canada Hibernia, NL & Labrador North Atlantic 0.61 Hibernia, NL & Labrador Portland 1.29 Montreal, QC Irving Oil 0.73 Montreal, QC North Atlantic 0.80 Montreal, QC Valero 0.54 Whiffen Head, NL & Labrador Irving Oil 0.68 Whiffen Head, NL & Labrador Irving Oil 0.68 Whiffen Head, NL & Labrador Montreal 0.80 Whiffen Head, NL & Labrador Valero 0.57 Foreign country – Algeria North Atlantic 0.91 Canada (or Portland, ME) Algeria Portland 1.14 Algeria Valero 1.18 Azerbaijan Irving Oil 1.54 Azerbaijan Portland 1.68 Colombia Irving Oil 2.12 Congo Irving Oil 1.41 Denmark North Atlantic 1.07 Equatorial Guinea Portland 1.67 Ivory Coast Irving Oil 1.79, 2.09 Kazakhstan Valero 1.54 Louisiana, US Irving Oil 1.40, 1.66 Louisiana, US North Atlantic 1.34 Nigeria Irving Oil 2.06, 1.63 Nigeria North Atlantic 1.42, 1.57 Nigeria Valero 1.88, 1.20 Norway Irving Oil 1.30 Norway North Atlantic 1.52, 1.66 Norway Portland 1.35 Saudi Arabia Irving Oil 1.69 Texas, US Irving Oil 1.31, 1.37 Texas, US North Atlantic 1.28 Texas, US Portland 1.00 Texas, US Valero 1.36, 2.08 UK North Atlantic 1.45 UK Portland 1.67 Note: Two numbers for the same route denote different shipment costs per barrel for different brands from the same country. The major influencing factor was loading in different ports and/or different types of tanker.

January 2018 158 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 159 Eastern Canadian Crude Oil Imports Appendix E: Detailed Substitution of Crude Oil by Scenario

Table E.1. Substitution of Oil in the Made in Canada Scenario Province/Refinery Base Case Substitution

Crude Volume, Mbpd Origin Transportation Volume, Mbpd Origin Transportation type path path

ON Imperial Oil-Sarnia Light 17.6 US North Pipeline, 17.6 SK Light Mainline Dakota Mainline

Shell-Sarnia Light 11.1 US North Pipeline, 11.1 SK Light Mainline Dakota Mainline

Suncor Energy- Light 13.1 US North Pipeline, 13.1 SK Light Mainline Sarnia Dakota Mainline

Imperial Oil- Light 16.3 US North Pipeline, 16.3 SK Light Mainline Nanticoke Dakota Mainline

QC Suncor Energy- Light 30.6 US WTI Pipeline, 19.0 SK Light Mainline, Montréal Tanker, Line 9 Portland- Montréal 11.6 AB Light Mainline, pipeline Line 9

48.0 US North Pipeline, 72.5 AB Light Mainline, Dakota Mainline Line 9

14.1 US Pipeline, Michigan Mainline

4.5 Azerbaijan Pipeline, Tanker, Portland- Montréal pipeline

1.9 Norway Tanker, Portland- Montréal pipeline

4.1 UK Tanker, Portland- Montréal pipeline

Valero-Lévis Light 7.2 US WTI, Pipeline, 131.9 AB Light New Eagle Ford Mainline infrastructure pipeline 92.1 Algeria Tanker

January 2018 160 Canadian Energy Research Institute

Province/Refinery Base Case Substitution

Crude Volume, Mbpd Origin Transportation Volume, Mbpd Origin Transportation type path path

21.1 Kazakhstan Pipeline, Tanker

11.5 Nigeria Tanker

NB Irving Oil-Saint Heavy 5.3 Colombia Tanker 5.3 AB New John Heavy infrastructure Heavy 10.0 Ivory Coast Tanker 10 pipeline

Light 19.2 US WTI, Pipeline, 115.3 AB AB Light AB - New Eagle Ford Tanker 87.6 NL NL infrastructure Offshore pipeline, NL - 15.2 US Tanker Tanker Louisiana

2.8 Azerbaijan Pipeline, Tanker

2.7 Congo Tanker

2.4 Equatorial Tanker Guinea

2.6 Ivory Coast Tanker

86.7 Saudi Tanker Arabia

44.9 Nigeria Tanker

26.3 Norway Tanker

NL North Atlantic Light 14.83 US WTI Pipeline, 93.09 NL Tanker Refining Tanker Offshore

34.17 US Tanker Louisiana

0.82 Algeria Tanker

18.30 Nigeria Tanker

13.77 Norway Tanker

6.16 UK Tanker

1.72 Denmark Tanker

January 2018 An Economic and Environmental Assessment of 161 Eastern Canadian Crude Oil Imports

Table E.2. Substitution of Oil in the Expanded Access Scenario Province/Refinery Base Case Substitution Crude Volume Origin Transportation Volume Origin Transportation type path path ON Imperial Oil- Light 17.6 US North Pipeline, Not substituted Sarnia Dakota Mainline Shell-Sarnia Light 11.12239 US North Pipeline, Dakota Mainline Suncor Energy- Light 13.1316 US North Pipeline, Sarnia Dakota Mainline Imperial Oil- Light 16.26275 US North Pipeline, Nanticoke Dakota Mainline QC Suncor Energy- Light 48.0 US North Pipeline, Not substituted Montreal Dakota Mainline 14.1 US Michigan Pipeline, 55.1 AB Light Mainline Mainline Pipeline, Tanker, 30.63 US WTI Portland- 4.5 Azerbaijan Montreal pipeline 1.9 Norway Tanker, 4.1 UK Portland- Montreal pipeline Valero-Lévis Light 6.3 US Texas Pipeline, Eagle Ford Mainline Not substituted 0.9 US WTI Pipeline, 125.6 AB Light New Mainline infrastructure 92.1 Algeria Tanker pipeline 21.1 Kazakhstan Pipeline, Tanker 11.5 Nigeria Tanker NB Irving Oil-Saint Heavy 5.3 Colombia Tanker 5.3 AB New pipeline John Heavy Heavy 10.0 Ivory Coast Tanker 10 AB New pipeline Heavy Light 17.7 US WTI Pipeline, Tanker 17.70 AB Light New pipeline 1.5 US Texas Pipeline, Tanker Eagle Ford 12.8 US Louisiana Tanker LLS 2.4 US Louisiana Tanker Thunderhorse Not substituted 2.8 Azerbaijan Pipeline, Tanker 2.84 AB Light New pipeline 2.7 Congo Tanker Not substituted 2.4 Equatorial Tanker 2.36 New pipeline Guinea AB Light 2.6 Ivory Coast Tanker 86.7 Saudi Arabia Tanker Not substituted 15.9 Nigeria Usan Tanker 15.9 NL Tanker Offshore 29.0 Nigeria Bonga Tanker 29.05 AB Light New pipeline 26.3 Norway Tanker 26.3 NL Tanker Offshore NL North Atlantic Light 14.8 US WTI Pipeline, Tanker NL Tanker Refining 14.83 Offshore 34.2 US Louisiana Tanker Not substituted

January 2018 162 Canadian Energy Research Institute

Province/Refinery Base Case Substitution Crude Volume Origin Transportation Volume Origin Transportation type path path 0.8 Algeria Tanker 0.8 NL Tanker 18.3 Nigeria Tanker 18.3 Offshore 13.8 Norway Tanker 13.8 6.2 UK Tanker 6.2 1.7 Denmark Tanker Not substituted

January 2018 An Economic and Environmental Assessment of 163 Eastern Canadian Crude Oil Imports

Table E.3. Substitution of Oil in the Current Reality Scenario Province/Refinery Base Case Substitution Crude Volume Origin Transportation Volume Origin Transportation type path path ON Imperial Oil- Light 17.6 US Texas Pipeline, Not substituted Sarnia Eagle Ford Mainline Shell-Sarnia 0 11.1 US WTI Pipeline, Mainline Suncor 0 13.1 Algeria Tanker Energy- Sarnia Imperial Oil- 0 16.3 Kazakhstan Pipeline, Tanker Nanticoke QC Suncor Light 48.0 US North Pipeline, Not substituted Energy- Dakota Mainline Montreal 14.1 US Michigan Pipeline, 55.1 AB Light Mainline, Mainline Line 9 30.6 US WTI Pipeline, Tanker, 4.5 Azerbaijan Portland- Montreal pipeline

1.9 Norway Tanker, Portland- 4.1 UK Montreal pipeline Valero-Lévis Light 6.3 US Texas Pipeline, Eagle Ford Mainline Not substituted 0.9 US Texas Pipeline, 0.9 AB Light Mainline, Eagle Ford Mainline Line 9, Tanker 92.1 Algeria Tanker 33.2 Not substituted, not enough offshore light oil available (NL offshore is cheaper) 59.0 NL Offshore Tanker 21.1 Kazakhstan Pipeline, Tanker 19.0 SK Light Mainline, Line 9, Tanker 2.1 NL Offshore Tanker 11.5 Nigeria Tanker 11.5 AB Light Mainline, Line 9, Tanker NB Irving Oil- Heavy 5.3 Colombia Tanker Not substituted Saint John Heavy 10.0 Ivory Coast Tanker Not substituted (no transportation capacity left, however AB Heavy is cheaper) Light 17.7 US WTI Pipeline, Tanker 17.70 AB Light Mainline, Line 9, Tanker 1.5 US Texas Pipeline, Tanker Eagle Ford 12.8 US Louisiana Tanker LLS 2.4 US Louisiana Tanker Thunderhorse Not substituted

January 2018 164 Canadian Energy Research Institute

Province/Refinery Base Case Substitution Crude Volume Origin Transportation Volume Origin Transportation type path path 2.8 Azerbaijan Pipeline, Tanker Mainline, Line 9, 2.84 AB Light Tanker 2.7 Congo Tanker Not substituted 2.4 Equatorial Tanker 2.36 Mainline, Guinea Line 9, AB Light Tanker 2.6 Ivory Coast Tanker 86.7 Saudi Arabia Tanker 15.9 Nigeria Usan Tanker Not substituted 29.0 Nigeria Bonga Tanker Mainline, Line 9, 10.29 AB Light Tanker 18.76 NL Offshore Tanker 26.3 Norway Tanker 26.3 NL Offshore Tanker NL North Light 14.8 US WTI Pipeline, Tanker 14.83 NL Offshore Tanker Atlantic 34.2 US Louisiana Tanker Not substituted Refining 0.8 Algeria Tanker 0.8 NL Offshore Tanker 18.3 Nigeria Tanker 18.3 13.8 Norway Tanker 13.8 6.2 UK Tanker 6.2 1.7 Denmark Tanker Not substituted

January 2018 An Economic and Environmental Assessment of 165 Eastern Canadian Crude Oil Imports

Table E.4. Substitution of Oil in the International Social Concerns Scenario Province/Refinery Base Case Substitution Crude Volume Origin Transportation Volume Origin Transportation type path path ON Imperial Oil- Light 17.6 US North Pipeline, Mainline Not substituted: Democratic Sarnia Dakota Shell-Sarnia Light 11.1 US North Pipeline, Mainline Dakota Suncor Light 13.1 US North Pipeline, Mainline Energy- Dakota Sarnia Imperial Oil- Light 16.3 US North Pipeline, Mainline Nanticoke Dakota QC Suncor Light 30.6 US WTI Pipeline, Tanker, Energy- Portland- Montreal Montreal pipeline 48.0 US North Pipeline, Mainline Dakota 14.1 US Michigan Pipeline, Mainline 4.5 Azerbaijan Pipeline, Tanker, 4.5 AB Light Mainline, Portland- Line 9 Montreal pipeline 1.9 Norway Tanker, Portland- Not substituted: Democratic Montreal pipeline 4.1 UK Tanker, Portland- Montreal pipeline Valero-Lévis Light 7.2 US WTI, Pipeline, Mainline Not substituted: Democratic Eagle Ford 92.1 Algeria Tanker 38.7 AB Light Mainline, Line 9 38 AB Light Rail 15.4 SK Light Mainline, 21.1 Kazakhstan Pipeline, Tanker 3.5 SK Light Line 9 17.5 11.5 Nigeria Tanker 11.5 NL Offshore Tanker NB Irving Oil- Heavy 5.3 Colombia Tanker Not substituted: Democratic Saint John Heavy 10.0 Ivory Coast Tanker 10 AB Heavy Mainline, Line 9, Tanker Light 19.2 US WTI, Pipeline, Tanker Not substituted: Democratic Eagle Ford 15.2 US Tanker Louisianan 2.8 Azerbaijan Pipeline, Tanker 10.5 AB Light Mainline, 2.7 Congo Tanker Line 9, 2.4 Equatorial Tanker Tanker Guinea 2.6 Ivory Coast Tanker 86.7 Saudi Arabia Tanker 2.39 NL Offshore Tanker 84.31 44.9 Nigeria Tanker 44.9 26.3 Norway Tanker Not substituted: Democratic NL Light 14.8 US WTI Pipeline, Tanker Not substituted: Democratic

January 2018 166 Canadian Energy Research Institute

Province/Refinery Base Case Substitution Crude Volume Origin Transportation Volume Origin Transportation type path path 34.2 US Louisiana Tanker 0.8 Algeria Tanker 0.8 NL Offshore Tanker North 18.3 Nigeria Tanker 18.3 Atlantic 13.8 Norway Tanker Not substituted: Democratic Refining 6.2 UK Tanker 1.7 Denmark Tanker

January 2018 An Economic and Environmental Assessment of 167 Eastern Canadian Crude Oil Imports Appendix F: Detailed Emissions by Scenario

Table F.1: Emissions in the Made in Canada Scenario

Emissions, tonnes CO2eq

CO2eq Province Refinery Upstream Refining Transport Total kg/bbl

Imperial Oil Base 2,780,788 1,277,289 147,428 4,205,504 110.7

Scenario 3,014,322 1,339,654 147,491 4,501,467 118.5

Shell Canada Base 1,479,797 808,831 89,698 2,378,326 98.9

Scenario 1,627,636 848,311 89,737 2,565,684 106.7

Suncor Energy Base 1,713,089 885,844 106,647 2,705,580 95.3

Scenario 1,887,633 932,457 106,694 2,926,784 103.1

Imperial Oil Base 2,076,651 1,005,863 145,750 3,228,264 91.8 ON Scenario 2,292,815 1,063,589 145,850 3,502,254 99.6

Suncor Energy Base 1,338,114 1,225,426 186,784 2,750,325 60.1

Scenario 2,261,849 1,324,951 228,005 3,814,805 83.4

Valero Base 7,511,408 1,958,615 429,352 9,899,376 116.5 QC Scenario 6,499,880 1,925,191 492,058 8,917,129 105.0 NB Irving Oil Base 3,921,679 2,831,561 501,303 7,254,543 71.6

Scenario 3,298,952 2,482,758 393,594 6,175,304 60.9 NL North Atlantic Refining Base 2,718,513 603,311 129,689 3,451,513 101.6

Scenario 414,529 822,262 10,771 1,247,562 36.72 Total Base 23,540,039 10,596,741 1,736,650 35,873,430

Scenario 21,297,615 10,739,173 1,614,200 33,650,988 Difference Scenario - Base -2,242,425 142,433 -122,450 -2,222,442

January 2018 168 Canadian Energy Research Institute

Table F.2: Emissions in the Expanded Access Scenario

Emissions, tonnes CO2eq

CO2eq Province Refinery Base/Scenario Upstream Refining Transport Total kg/bbl

Imperial Oil Base 2,780,788 1,277,289 147,428 4,205,504 110.7

Scenario 2,780,788 1,277,289 147,428 4,205,504 110.7

Shell Canada Base 1,479,797 808,831 89,698 2,378,326 98.9

Scenario 1,479,797 808,831 89,698 2,378,326 98.9

Suncor Energy Base 1,713,089 885,844 106,647 2,705,580 95.3

Scenario 1,713,089 885,844 106,647 2,705,580 95.3

Imperial Oil Base 2,076,651 1,005,863 145,750 3,228,264 91.8

ON Scenario 2,076,651 1,005,863 145,750 3,228,264 91.8

Suncor Energy Base 1,338,114 1,225,426 186,784 2,750,325 60.1

Scenario 1,655,113 1,250,510 211,947 3,117,570 68.1

Valero Base 7,511,408 1,958,615 429,352 9,899,376 116.5

QC Scenario 6,452,436 1,927,224 486,188 8,865,848 104.4

NB Irving Oil Base 3,921,679 2,831,561 501,303 7,254,543 71.6

Scenario 3,556,357 2,668,139 476,095 6,700,591 66.1 North Atlantic NL Refining Base 2,718,513 603,311 129,689 3,451,513 101.6

Scenario 1,861,865 705,164 56,443 2,623,472 77.2

Total Base 23,540,039 10,596,741 1,736,650 35,873,430

Scenario 21,576,096 10,528,864 1,720,195 33,825,155 Difference Scenario - Base -1,963,943 -67,877 -16,455 -2,048,275

January 2018 An Economic and Environmental Assessment of 169 Eastern Canadian Crude Oil Imports

Table F.3: Emissions in the Current Reality Scenario

Emissions, tonnes CO2eq

CO2eq Province Refinery Base/Scenario Upstream Refining Transport Total kg/bbl

Imperial Oil Base 2,780,788 1,277,289 147,428 4,205,504 110.7

Scenario 2,780,788 1,277,289 147,428 4,205,504 110.7

Shell Canada Base 1,479,797 808,831 89,698 2,378,326 98.9

Scenario 1,479,797 808,831 89,698 2,378,326 98.9

Suncor Energy Base 1,713,089 885,844 106,647 2,705,580 95.3

Scenario 1,713,089 885,844 106,647 2,705,580 95.3

Imperial Oil Base 2,076,651 1,005,863 145,750 3,228,264 91.8

ON Scenario 2,076,651 1,005,863 145,750 3,228,264 91.8

Suncor Energy Base 1,338,114 1,225,426 186,784 2,750,325 60.1

Scenario 1,655,113 1,250,510 211,947 3,117,570 68.1

Valero Base 7,511,408 1,958,615 429,352 9,899,376 116.5

QC Scenario 6,200,574 2,093,374 357,251 8,651,199 101.8

NB Irving Oil Base 3,921,679 2,831,561 501,303 7,254,543 71.6

Scenario 3,540,194 2,901,504 486,184 6,927,882 68.3 North Atlantic NL Refining Base 2,718,513 603,311 129,689 3,451,513 101.6

Scenario 1,861,865 705,165 56,443 2,623,473 77.2

Total Base 23,540,039 10,596,741 1,736,650 35,873,430

Scenario 21,308,071 10,928,379 1,601,347 33,837,798 Difference Scenario - Base -2,231,968 331,638 -135,303 -2,035,632

January 2018 170 Canadian Energy Research Institute

Table F.4: Emissions in the International Social Concerns Scenario

Emissions, tonnes CO2eq

CO2eq Province Refinery Base/Scenario Upstream Midstream Transport Total kg/bbl

Imperial Oil Base 2,780,788 1,277,289 147,428 4,205,504 110.7

Scenario 2,780,788 1,277,289 147,428 4,205,504 110.7

Shell Canada Base 1,479,797 808,831 89,698 2,378,326 98.9

Scenario 1,479,797 808,831 89,698 2,378,326 98.9

Suncor Energy Base 1,713,089 885,844 106,647 2,705,580 95.3

Scenario 1,713,089 885,844 106,647 2,705,580 95.3

Imperial Oil Base 2,076,651 1,005,863 145,750 3,228,264 91.8

ON Scenario 2,076,651 1,005,863 145,750 3,228,264 91.8

Suncor Energy Base 1,338,114 1,225,426 186,784 2,750,325 60.1

Scenario 1,381,258 1,234,048 181,611 2,796,916 61.1

Valero Base 7,511,408 1,958,615 429,352 9,899,376 116.5

QC Scenario 6,162,488 2,048,109 491,797 8,702,394 102.4

NB Irving Oil Base 3,921,679 2,831,561 501,303 7,254,543 71.6

Scenario 3,225,817 2,556,726 283,236 6,065,779 59.8 North Atlantic NL Refining Base 2,718,513 603,311 129,689 3,451,513 101.6

Scenario 2,234,476 636,872 99,983 2,971,332 87.4

Total Base 23,540,039 10,596,741 1,736,650 35,873,430

0 Scenario 21,054,365 10,453,581 1,546,149 33,054,095 Difference Scenario - Base -2,485,675 -143,160 -190,501 -2,819,336

January 2018 An Economic and Environmental Assessment of 171 Eastern Canadian Crude Oil Imports Appendix G: Cost of Feedstock vs. GHG Emissions by Province

Figure G.1: Ontario – Cost of Feedstock vs. GHG Emissions

Note: Two points for the same type of oil is explained by different location of refineries. The one with higher emissions and more expensive denotes Nanticoke as it is further away from Sarnia. Comparison comments (as study focused on light oil, comparison for this type is illustrated):

• AB Light and SK Light are both more expensive than foreign oil; they also yield more total emissions than foreign light crude

January 2018 172 Canadian Energy Research Institute

Figure G.2. Quebec – Cost of Feedstock vs. GHG Emissions

Comparison comments (as study focused on light oil, comparison for this type is illustrated):

• For Suncor Energy refinery in Montreal: o AB Light is cheaper than 6 of 7 foreign light crude oils; it also yields less total emissions than 2 out 7 light foreign crude oils o NL Offshore Light is cheaper than 6 of 7 foreign light crude oils; it also yields less total emissions than 5 of 7 light foreign crude oils • For Valero refinery in Lévis: o AB Light is cheaper than 3 of 6 foreign light crude oils (via Mainline) and 5 of 6 via New Pipeline; it also yields less total emissions than 3 of 6 light foreign crude oils (via Mainline or New Pipeline) o SK Light is cheaper than 5 of 6 foreign light crude oils; it also yields less total emissions than 3 of 6 light foreign crude oils o NL Offshore Light is cheaper than 5 of 6 foreign light crude oils; it also yields less total emissions than any foreign light oil

January 2018 An Economic and Environmental Assessment of 173 Eastern Canadian Crude Oil Imports

Figure G.3: Quebec – Cost of Feedstock vs. GHG Emissions (zoomed in portion of Figure G.2)

January 2018 174 Canadian Energy Research Institute

Figure G.4: New Brunswick – Cost of Feedstock vs. GHG Emissions

Comparison comments (as study focused on light oil, comparison for this type is illustrated):

• AB Light is cheaper than 4 of 12 foreign light crude oils; it also yields less total emissions than 6 of 12 foreign crudes • NL Offshore Light is cheaper than 5 of 12 foreign light crude oils; it also yields less total emissions than any foreign light crude, except for Azerbaijan’s Azeri Light.

January 2018 An Economic and Environmental Assessment of 175 Eastern Canadian Crude Oil Imports

Figure G.5: Newfoundland & Labrador – Cost of Feedstock vs. GHG Emissions

Comparison comments (as study focused on light oil, comparison for this type is illustrated):

• NL Offshore Light is cheaper than 7 of 9 foreign light crude oils; it also yields less total emissions than any foreign light crude, except for Denmark’s DUC.

January 2018 176 Canadian Energy Research Institute

January 2018 An Economic and Environmental Assessment of 177 Eastern Canadian Crude Oil Imports Appendix H: Selected Foreign Crude Oil Brands Import Volumes and Price Comparison with Selected Canadian Crudes

Figure H.1: Selected Foreign Crude Oil Brands Import Volumes and Prices (place of initial sale – without transportation costs to a refinery)

Figure H.2: Selected Foreign Crude Oil Brands Import Volumes and Full-cycle Delivered Average Prices (with transportation costs to a refinery)

January 2018