Canadian Oil Sands Production and Emissions Outlook (2020-2039)

STUDY NO. 191 AUGUST 2020 CANADIAN OIL SANDS PRODUCTION AND EMISSIONS OUTLOOK (2020-2039)

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Canadian Energy Research Institute

CANADIAN OIL SANDS PRODUCTION AND EMISSIONS OUTLOOK (2020-2039)

Canadian Oil Sands Production and Emissions Outlook (2020-2039)

Author: Dinara Millington

Recommended Citation (Author-date style): Millington, D. 2020. “Canadian Oil Sands Production and Emissions Outlook (2020-2039).” Study No. 191. Calgary, AB: Canadian Energy Research Institute. https://ceri.ca/assets/files/Study 191 Full Report.pdf

Recommended Citation (Numbered style): D. Millington, “Canadian Oil Sands Production and Emissions Outlook (2020-2039),” Canadian Energy Research Institute, Calgary, AB, Study No. 191, 2020. URL: https://ceri.ca/assets/files/Study 191 Full Report.pdf

August 2020 Printed in Canada

Acknowledgements: The author of this report would like to extend her thanks and sincere gratitude to all CERI staff that provided insightful comments and essential data inputs required for the completion of this report, as well as those involved in the production, reviewing and editing of the material, including but not limited to Hamid Rahmanifard, Toufigh Bararpour, Allan Fogwill and Kelsey Marklund.

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE 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 Canadian Oil Sands Production and Emissions Outlook (2020-2039) iii

Table of Contents

Table of Contents ...... iii List of Figures ...... iv List of Tables ...... v Acronyms and Abbreviations ...... vi Executive Summary ...... vii Chapter 1: Introduction ...... 11 Organization of the Report ...... 11 Chapter 2: Oil Sands Industry Update ...... 12 Background ...... 12 Chapter 3: Oil Sands Production Scenarios ...... 18 Methodology and Assumptions ...... 18 Global Demand Assumptions ...... 18 Production Loss Scenario Assumptions ...... 19 Oil Sands Production – Three Scenarios ...... 20 Emissions ...... 24 Chapter 4: Conclusions ...... 26 Bibliography ...... 27 Appendix A: Production Forecasting Methodology ...... 28 Delay Assumptions ...... 28

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List of Figures

Figure E.1: Bitumen Production Scenarios ...... viii Figure E.2: Bitumen Emission Scenarios ...... x Figure 2.1: Canadian Crude Exports to the US ...... 13 Figure 2.2: Canadian Crude Exports by US PADD Region ...... 14 Figure 2.3: Total Operating Costs for In situ and Mining Projects (2019 C$/bbl) ...... 16 Figure 2.4: Emission Intensities by Project (kgCO2eq./bbl bitumen*) ...... 17 Figure 3.1: Bitumen Production Scenarios...... 22 Figure 3.2: Bitumen Production by Project Type (All Scenarios) ...... 23 Figure 3.3: Bitumen Emission Scenarios ...... 25

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List of Tables

Table 3.1: Scenario Assumptions for Global Demand...... 18 Table 3.2: Scenario Assumptions for Canadian Oil and Gas Production...... 19 Table 3.3: Oil Production Shares for Canadian Provinces ...... 20 Table 3.4: Bitumen Production Losses (KBPD) ...... 21 Table A.1: Project Delay Factors ...... 29

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Acronyms and Abbreviations

AER – Alberta Energy Regulator BPD – barrels per day CAPP – Canadian Association of Petroleum Producers CERI – Canadian Energy Research Institute CO2eq. – Carbon Dioxide equivalent GDP – Gross Domestic Product GHG – greenhouse gas IEA – International Energy Agency KBPD – thousand barrels per day MMBPD – million barrels per day MT or Mt – mega-tonne OPEC - Organization of the Petroleum Exporting Countries SAGD - Steam-Assisted Gravity Drainage SCO – Synthetic Crude Oil SGER - Specific Gas Emitters Regulation SOR – Steam to Oil Ratio TIER – Technology Innovation and Emissions Reduction Regulation US – United States US EIA – US Energy Information Administration US PADD – United States Petroleum Administration for Defense Districts USGC – United States Gulf Coast WCS – Western Canadian Select WTI - West Texas Intermediate

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) vii

Executive Summary

The health emergency caused by the COVID-19 pandemic is having a severe adverse impact on the global economy. In fact, this period is being equated to the state of the economy witnessed during the 1930s Great Depression (IEA 2020). At the time of writing, it was still unclear how long the current health crisis will continue and how deeply it will impact economic growth, employment, trade, social behaviour, and capital investment.

The energy sector, among other economic sectors, is continuing to feel the impact of the pandemic on energy demand, investment and employment. Highly volatile oil and gas prices are of particular concern for countries where the production and exports of crude oil and natural gas are important drivers for economic growth and government revenues.

Even before the pandemic, the decline in global oil prices, surging crude inventories and geopolitics have had an impact on the crude oil industry and slowed the pace of upstream investment around the world– including oil sands development in Canada. The global market remains volatile, as witnessed by temporary negative oil prices in April. There are early signs of improvement but, the recovery ahead is a long road filled with uncertainty. Indeed, prices have recovered from the negative territory; at the time of writing, WTI price was almost US$41/bbl while Brent was trading at US$43.25/bbl, a much-needed relief for oil producers.

This is the fourteenth annual edition of CERI’s oil sands supply costs and development projects update report. Like past editions of the report, several scenarios for oil sands development are explored. Unlike other past updates, given the ongoing worldwide COVID-19 pandemic and subsequent uncertainty around the market supply and demand dynamics, highly volatile oil prices, and uncertain levels of capital investment, the supply cost examination for greenfield development, together with economic impacts analysis, is omitted.

Three scenarios for oil sands development are explored. The scenarios represent potential pathways when it comes to oil sands production, especially in the short term. A high degree of variation in production levels in immediate years is symbolic of the level of uncertainty in global oil markets and the domestic ecosystem. This abbreviated report is based on the Reference Case production scenario from the July 2019 update (CERI 2019) and quantifies potential production losses and associated GHG emission levels within three different scenarios.

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A significant milestone of a 3.1 million-barrel-per-day production level reached in 2018 was maintained in 2019. In 2019, oil sands bitumen production was comprised of in situ (thermal and cold bitumen) production of 1.6 MMBPD and mining production of 1.5 MMBPD within the boundaries of oil sands areas.1

In Scenario I, production from mining and in situ projects (thermal and cold bitumen) is set to decline by 215 KPBD in 2020, with full recovery by 2021. By the end of the decade, production is forecasted to reach 3.9 MMBPD in 2030, peaking at 4.7 MMBPD by 2039.

In Scenario II, the production losses are more substantial than in Scenario I, amounting to 716 KBPD in 2020, 501 KBPD in 2021, and 143 KBPD in 2022 onward. This scenario introduces a permanent production loss of 143 KBPD in the overall outlook to 2039. After the initial production hit, bitumen production grows at a slower rate, rising to 3.8 MMBPD in 2030, and 4.6 MMBPD by the end of the forecast period.

Scenario III is the least optimistic of all scenarios, indicating a temporary loss of over a million barrels per day, while permanently losing almost half a million barrels per day. Projected production volume will rebound partially by 2023, eventually reaching 3.5 MMBPD by 2030, peaking at 4.3 MMBPD by 2039.

Figure E.1: Bitumen Production Scenarios

5,000

4,500

4,000

3,500

3,000

KBPD 2,500

2,000

1,500

1,000 Scenario I Scenario II Scenario III

500

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Historical Outlook

Source: CanOils, EDC Associates, CERI

CERI’s oil sands production outlook calls for immediate production losses in the short term with some permanent losses under two out of three scenarios. With the forecasted improvement of oil prices out

1 Totals may not add up due to rounding. Historical production is sourced from the AER ST-98 2020.

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) ix

to medium and long term2, bitumen production is assumed to resume and grow to the end of the forecast period. The plans to expand oil sands production, increase pipeline takeaway capacity, and gain access to other markets are still, however, dependent on key elements that must align for the industry. CERI believes these elements are:

i) favourable oil prices at levels where oil sands projects can be economical; ii) implementing cost-cutting measures through the adoption of improved processes and technologies; iii) continuous improvement in environmental performance among oil sand producers; iv) increased market access; and v) the ability to collaborate effectively in a competitive environment.

Table 3.2 illustrates the total oil sands emissions projections based on the three production scenarios presented. The oil sands emissions projection includes emissions from existing upgrading, electricity or fugitive emissions and flaring. Current on-site emissions are projected to change in tandem with bitumen and SCO production. Future emissions are calculated based on historic emission intensities, which have been decreasing but do not reflect any future innovation or technology change to reduce emission levels. However, considering historical and present efforts by many operators to reduce emission intensities, improvements in emissions over the forecast period are within reach. Hence this conservative outlook should be considered a ceiling on oil sands emissions.

Given the short-term production decline forecast in all three scenarios, emissions decline in parallel in the short term (except for Scenario I). In the medium to long term, emissions start to increase, reaching almost 100 Mt/year (98.5 Mt) in 2030 under Scenario I, 95 Mt in Scenario II and 87.3 Mt in Scenario III. In comparison to last year’s update, the 100 MT level was reached in 2030 in the Reference Case Scenario.

2 According to the US EIA’s Annual Energy Outlook 2020, annualized WTI reaches above US$71/bbl in 2030 and US$85/bbl in 2039.

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Figure E.2: Bitumen Emission Scenarios

140

Scenario I Scenario II Scenario III

120

100

(Tonnes CO2eq./yr) (Tonnes 60

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Historical Outlook

Source: CERI, CanOils

This report did not present the economic impacts of oil sands development as these are under development for an upcoming study. The upcoming CERI study on the recovery pathways for the energy sector will illuminate the economic impacts in detail. The study will analyze and present the economic impacts of recovery for four separate energy subsectors, including the oil and gas industry, based on the stimulus measures that are available from various governments and government organizations. Similar to this report, the recovery will be presented in a scenario-based approach, given the high level of uncertainty.

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Chapter 1: Introduction

Each year the Canadian Energy Research Institute (CERI) publishes its long-term outlook for Canadian oil sands production and supply in conjunction with an examination of oil sands supply costs. This is the fourteenth annual edition of CERI’s oil sands supply costs and development projects update report. Similar to past editions of the report, several scenarios for oil sands development are explored. Unlike other past updates, given the ongoing worldwide COVID-19 pandemic and subsequent uncertainty around the market supply and demand dynamics, highly volatile oil prices, and uncertain levels of capital investment, the supply cost examination for greenfield development, together with economic impacts analysis, is omitted.

Three scenarios for oil sands development are explored. The scenarios represent potential pathways when it comes to the oil sands production, especially in the short term. A high degree of variation in the production levels in the immediate years is symbolic of the level of uncertainty in global oil markets and the domestic ecosystem. This abbreviated report is based on the Reference Case production scenario from the July 2019 Oil Sands update (CERI 2019) and quantifies potential production losses and associated GHG emission levels within three different scenarios.

This report relies upon up-to-date information available on oil sands projects (updated to the end of 2019), and market intelligence gathered by CERI’s oil sands team.

This year’s report presents project vintages and production capacities of existing and planned projects. Within CERI’s oil sands database, the projects are identified by type (e.g., mining and extraction, in situ, upgrading), location, and extraction technologies (including pilot projects). Upgrading facilities are characterized by technology and by type (i.e., stand-alone or integrated with crude bitumen extraction facilities).

All the above information for both existing and future projects is presented at the aggregate industry level (i.e., oil sands industry as a whole) throughout this report. The oil sands projects are classified according to their stage of development.

Organization of the Report Chapter 1 highlights the background of the study and presents the objective and the scope.

Chapter 2 presents the status of the oil sands industry today, examines the issues of throughput and exports, and updates readers on operating costs of existing projects.

Chapter 3 highlights the assumptions and methodology used in the oil sands forecasting model and presents scenario-based production projections, followed by projections emission levels under the three scenarios.

Chapter 4 concludes.

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Chapter 2: Oil Sands Industry Update

Background

The energy sector, among other economic sectors, is continuing to feel the impact of the pandemic on energy demand, investment, and employment. Highly volatile oil and gas prices are of particular concern for countries where the production and exports of crude oil and natural gas are important drivers for economic growth and government revenues.

Even before the pandemic, the decline in global oil prices, surging crude inventories and geopolitics have had an impact on the crude oil industry and slowed the pace of upstream investment around the world– including oil sands development in Canada. The global market remains volatile, as witnessed by temporary negative oil prices in April. There are early signs of improvement, but the recovery ahead is a long road filled with uncertainty. Indeed, prices have recovered from the negative territory, at the time of writing, WTI price was almost US$41/bbl while Brent was trading at US$43.25/bbl, a much-needed relief for oil producers.

Canada’s oil sands, however, are still suffering from low capital investment, with many companies slashing their 2020 investment levels, ultimately impacting new drilling, jobs in the sector, production growth and overall economic benefits to the rest of the economy (Province 2020). While some early shut-in production is coming back, it is still uncertain how much and how quickly it will come online. Canada is still among the top five global crude oil producers, and synthetic crude oil (SCO), and bitumen production is still expected to take the lion’s share of total Canadian crude oil production. However, many factors need to align, one of which is the need for expansion in existing export oil pipeline capacity, in addition to higher oil prices. As Canadian crude oil continues to be a sought-after barrel, especially in US Midwest and the Gulf refineries, the leverage of these resources for economic benefits to the nation will depend on the ability to connect this growing supply with downstream demand.

The US Gulf Coast (USGC) is one of the world’s largest refining centres. Its considerable heavy oil processing capacity presents the most substantial opportunity for Western Canadian heavy crude oil supply, making it Canadian heavy producers’ first target for market access. Canadian heavy crude oil competes for market share in the US Gulf Coast with heavy crude oil from Latin American producers, mainly Mexico, Venezuela, Brazil, and Ecuador. More recently, crude exports from Mexico and Venezuela have been declining due to domestic social and economic reasons, providing an opportunity for Canadian heavy crude to replace some of the lost volumes and expand their market share in the US Gulf. Total Canadian crude exports to the US increased 2.4% in 2019, reaching 3.8 million barrels per day (MMBPD) Canadian Oil Sands Production and Emissions Outlook (2020-2039) 13 as compared to 2018 levels, with the largest share of total exports coming from heavy sour crudes; in 2019 its share decreased to 65% (Figure 2.1).

Figure 2.1: Canadian Crude Exports to the US

4,000

3,500

3,000

65% 2,500 68% 66% 62% 61% 2,000 60% KBPD 59% 59% 1,500 59% 55% 57%

1,000

500

- 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Light Sweet Light Sour Medium Heavy Sweet Heavy Sour

Source: EIA, CERI

The US Midwest region or PADD 2 is still the dominant market for Canadian crude, capturing almost 70% of all Canadian imports. However, PADD 3 or the US Gulf Coast is a growing market, evidenced by the growing Canadian crude imports into that region. Over the last 10 years, the volumes have increased three-fold, amounting to 500 thousand barrels per day (KBPD) in 2019, most of which is heavy crude supply (Figure 2.2).

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Figure 2.2: Canadian Crude Exports by US PADD Region

3,000.0

2,500.0

2,000.0

1,500.0 KBPD

1,000.0

500.0

- PADD1 (East Coast) PADD2 (Midwest) PADD3 (Gulf Coast) PADD4 (Rocky PADD5 (West Coast) Mountain)

Light Sweet Light Sour Medium Heavy Sweet Heavy Sour

Source: EIA, CERI

Expansion of pipeline infrastructure and shipping routes to international markets and the US would not only create opportunities for Canadian oil producers but benefit the Canadian economy as well. Through increasing market access for products, Canada will compete in global markets, capture higher tax revenues from producers, increase employment in energy and non-energy sectors, be able to continue to fund the critical social structure of this country, not to mention have a potential to invest in further research and development and innovation in Canadian energy systems. Allocating exports to other markets such as Asia and Europe also would also reduce dependence on the US markets.

Although the need to expand and reach new markets for oil sands is pressing, production and pipeline projects associated with oil sands have come under increased scrutiny, contributing to delays and uncertainty. Although not every factor will influence future markets for oil sands, some of the most prominent ones include regulatory processes, local concerns, greenhouse gas emissions and climate change policies, as well as Indigenous People’s rights in Canada.

If the advantage in tight oil plays goes to companies who move quickly to secure acreage and climb steep learning curves to economic oil production (and the steep downward curve of production decline), then the advantage in the oil sands goes to companies that effectively deliberate over the risks of multi-decade operations. Heavy oil differentials, pipeline capacity limitations and a volatile oil price all play a role in these considerations. Still, they invariably take a back seat to broader and more global oil supply and demand fundamentals.

For oil sands opponents, sustained decline in investment provides a point of view that the industry is too costly to compete. What this view ignores, however, is continuing capital and operating cost reductions captured by project operators through project efficiency initiatives such as debottlenecking. Continuing efforts at reducing costs through technological improvements and other operational measures, while remaining conscious of the environment, should ensure a robust future.

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Historically, oil sands projects have experienced significant inflationary pressures as projects progressed towards completion. Labour shortages, material scarcity, administrative and engineering delays have all contributed to cost overruns. Capital cost increases ultimately eroded returns for producers. The recent global pandemic and ensuing demand destruction have caused a downturn in global oil prices, and capital spending in new projects has experienced a tremendous decline, as more projects were being postponed and even cancelled.

The total operating costs have been decreasing year-on-year for most existing projects, in situ and integrated and stand-alone mining. Historical total operating costs for selected projects are shown in Figure 2.3. The sampled operating costs for in situ producers, who are mostly SAGD facility operators, shown in the top part of Figure 2.3, for integrated and stand-alone mining producers –sampled operating costs are shown in the bottom part of Figure 2.3. The selected in situ projects, for which operating costs are presented, represent 53% of all in situ or 25% of total bitumen production. The selected mining projects represent 81% of all mining or 41% of total bitumen production.

From 2014, when oil prices crashed, to 2018, total operating costs for both oil sands mining and in situ producers fell on average by 40%, and in some cases, operators slashed costs in half. SAGD producers achieved a 48% cost reduction between 2014 and 2018, and a year-on-year reduction of 7% in 2018 as compared to 2017. Integrated and stand-alone mining projects’ operating costs, on average, declined by 32% in 2018 versus 2014. However, the 2019 costs, for the most part, remained flat or slightly increased compared to 2018 costs in real 2019 dollars.

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Figure 2.3: Total Operating Costs for In situ and Mining Projects (2019 C$/bbl)

$30.00

$25.00

$20.00

$15.00

$10.00 CAD2019$/bbl

$5.00

$- 2014 2015 2016 2017 2018 2019

Christina Lake Cenovus Energy Firebag and MacKay River Suncor Energy Foster Creek Cenovus Energy Jackfish Devon Canada Peace River Cadotte Creek CNRL Great Divide Connacher Oil and Gas Christina Lake Regional MEG Energy

$60.00

$50.00

$40.00

$30.00

$20.00 CAD2019$/bbl $10.00

$- 2014 2015 2016 2017 2018 2019

AOSP Muskeg River CNRL Horizon CNRL Kearl Lake Imperial Oil Limited Suncor Base Mine Suncor Energy Inc. Syncrude North and Aurora North Mines

Source: CanOils, CERI Growth in commercial oil sands production has also caused absolute GHG emissions related to oil sands development to increase but at a declining rate per barrel. Figure 2.4 illustrates the historic emission intensities for selected projects from 2009 to 2017 (the most recent public data available). It is observed that between 2009 and 2016, average emission intensity levels of onstream projects have decreased by 11, 15 and 10% for SAGD, mining and upgrading, respectively. Year-on-year changes do not indicate a significant reduction; SAGD projects, on average, decreased their emission intensity by 1% in 2017 as compared to 2016, with some individual projects showing a decrease of 18% and some an increase of as much as 15%. Emission intensities for integrated mining and upgrading projects on average increased by 1% in 2017; emission intensity just for upgrading projects decreased 5% year over year.

Numerous policies and regulations have been adopted in recent years to limit and reverse oil sands emission growth while sustaining production levels and minimizing economy-wide impacts. Some of the mechanisms include intensity-based carbon pricing to protect trade-exposed sectors and limit carbon leakage, an absolute emissions cap on oil sands, and a federally mandated carbon tax.

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Figure 2.4: Emission Intensities by Project (kgCO2eq./bbl bitumen*)

A. SAGD Projects 180

160

140

120

100

80 kgCO2eq./bbl 60

20 2009 2010 2011 2012 2013 2014 2015 2016 2017

Christina Lake Firebag Foster Creek Jackfish Surmont (ConocoPhillips) Orion Christina Lake Regional

B. Mining Projects 90

kgCO2eq./bbl 30

- 2009 2010 2011 2012 2013 2014 2015 2016 2017

AOSP Jackpine AOSP Muskeg River Kearl Lake

C. Upgraders 150

130

110

kgCO2eq./bbl 70

30 2009 2010 2011 2012 2013 2014 2015 2016 2017

AOSP Scotford Upgrader Horizon Upgrader Lloydminster Upgrader Suncor UpgraderU1 & U2 Syncrude Upgrading

Source: Canoils, CERI. Note: (*) Emissions intensities for Suncor and Syncrude Upgrading are not broken down by mining and upgrading. Hence it’s presented on the kgCO2eq/bbl of SCO basis.

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Chapter 3: Oil Sands Production Scenarios

The past mega-large projects like open-pit mines are no longer the trend forward. Development of additional phases to existing brownfield facilities cost less than greenfield development and are a way to future growth. The current pandemic, the compliance of OPEC+ production cuts, unpredictable oil prices, and geopolitics have resulted in low capital spending globally and domestically. Some improvement in oil prices has been seen since April’s negative territory; however, the oil sands industry is still facing many uncertainties, with many projects shelved or cancelled.

The uncertainty in the global oil and gas sector further complicates the outlook for the Canadian oil sands sector. Hence in this annual production update, CERI has undertaken a scenario-based approach to dealing with uncertainty surrounding future production of crude oil and natural gas. This abbreviated report analyses Canadian oil sands bitumen production based on (CERI 2019) Oil Sands update and quantifies potential production losses and associated GHG emission levels. Given the level of uncertainty around capital spending, supply costs for greenfield drilling and economic impacts are omitted this year.

Methodology and Assumptions To maintain consistency with CERI’s sister report on the conventional oil and gas production outlook, this report adopts the same assumptions when it comes to determining global and domestic crude market dynamics, and in particular, the short to medium-term impacts on production levels. For ease of reference, the assumptions are repeated below.

Global Demand Assumptions Based on the global and domestic supply and demand assumptions obtained from the EDC Associates Ltd. (EDC Associates Ltd 2020), CERI analyzed three potential scenarios to investigate how Canadian oil sands production is impacted. The global demand assumptions for the three scenarios are shown in Table 3.1.

Table 3.1: Scenario Assumptions for Global Demand

Variable Scenario I Scenario II Scenario III

Global demand destruction 20 MMBPD 25 MMBPD 30 MMBPD Early in 2022 End of 2022 Demand recovery date Mid 2021 (not fully recovered) (not fully recovered) Demand after recovery date 100 MMBPD 95 MMBPD 90 MMBPD Source: (EDC Associates Ltd 2020)

In Scenario I, the most optimistic of the three, it is assumed that the global demand destruction will be short-lived and amount to 20 MMBPD. It is assumed that demand fully recovers in the second half of 2021. After this period, the global demand will return to the 2019 values (around 100 MMBPD).

In Scenario II, global oil demand destruction will be more extensive (25 MMBPD) than in Scenario I. Furthermore, the recovery date is extended to the year 2022. In this scenario, it is forecasted that the

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) 19

market will not fully recover, and the global demand will return to 95 MMBPD, thus permanently losing around 5 MMBPD. The permanent losses in Scenarios II and III are predicted to come from the transportation sector.

In Scenario III, even greater destruction will occur to the global demand, and the demand cut will reach up to 30 MMBPD. However, it is projected that demand will partially recover by the end of 2022. A permanent demand loss of up to 10 MMBPD is considered in this scenario, meaning that the global demand after the recovery date will be about 10 MMBPD lower than the values reported in 2019.

Production Loss Scenario Assumptions To set the global market changes within the Canadian context, we focus on critical variables such as annual production cuts, recovery dates and permanent production losses, which can cause significant and permanent adverse impacts on the Canadian economy. We base our three scenarios for analyzing the effect of these variables on oil sands production according to the assumptions obtained from EDC Associates Ltd (EDC Associates Ltd 2020). Table 3.2 summarizes the assumptions and their probable outcomes.

Table 3.2: Scenario Assumptions for Canadian Oil and Gas Production

Variable Scenario I Scenario II Scenario III Economy takes a hit and Economy takes a big hit in Economy devastated in Outcome returns to the same level 2020 2020 and into 2021 Economic activity Slowly recovers in 2021 & The second half of 2020 Slowly recovers in 2021 recovery date 2022 Total production 1 MMBPD in 2020 1.7 MMBPD in 2020 & 2021 300 KBPD in 2020 cuts 700 KBPD through 2021 1.4 MMBPD in 2022 Permanent loss 0 200 KBPD after 2021 600 KBPD in 2022 Proportional to the in situ Proportional to the in situ Proportional to the in situ Natural gas cut and mined bitumen cut and mined bitumen cut and mined bitumen cut Source: (EDC Associates Ltd, 2020)

Scenario I assumes that in Canada, the total crude oil production cut in 2020 will be short-lived and average about 300 thousand barrels per day (KBPD). In 2021, the production level returns to the pre- pandemic level. The first half of 2020 already saw production curtailed in larger volumes than 300 KBPD; hence these assumptions are optimistic, and the likelihood of this occurrence is low. We expect a more substantial hit to the overall oil and gas industry and an extended recovery date owing to the importance and seriousness of the recent events.

In Scenario II, the production cut is projected to be 1 MMBPD in 2020 and 700 KBPD in 2021. After 2021, a permanent production loss of 200 KBPD is considered in this scenario.

Scenario III is the worst-case scenario, assuming a production cut of up to 1.7 MMBPD in 2020 and 2021, and 1.4 MMBPD in 2022. After 2022, a permanent loss of 600 KBPD is estimated.

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Given the overall production impact assumptions, the next step is to estimate the oil sands share of the production losses. Given that bitumen production makes up about two-thirds of total Canadian crude oil production, it is not surprising that the assumed production losses will be felt the most in the oil sands.

We assume that the share of production cuts in the four Western crude-producing provinces3 is equivalent to their respective production share of total Canadian crude production. We consider the average shares between the years of 2014-2018 as the production share of each province of the total crude oil production in Canada (CAPP 2019)4. Table 3.3 provides the estimated percentages of provincial contributions for western Canadian provinces.

Table 3.3: Oil Production Shares for Canadian Provinces Province Production type Share BC oil 0.6% AB oil 13.5% AB bitumen 71.6% SK oil 13.1% MB oil 1.2% Oil Sands Split5 AB In situ 50% AB Mined 50% Source: (CAPP 2019; AER 2020)

Given this is an abbreviated report, the reader is encouraged to review the July 2019 update or Appendix A to familiarize themselves with CERI’s methodology for projecting bitumen production. This year’s production scenarios are based on the July 2019 Reference Case Scenario for bitumen production and production losses calculated for the oil sands portion of the total Canadian crude production (CERI 2019).

Oil Sands Production – Three Scenarios The projection of crude bitumen and SCO production is dependent on information provided by oil sands producers. This includes data on production capacity provided to the Alberta regulator, in addition to other publicly available documents, such as annual reports, investor presentations and press releases, as well as the CanOils database. The projections include production from existing projects as well as new projects that are under construction, approved, awaiting approval, and announced6. This year the projection period is from 2020 to 2039, inclusive.

3 We exempt Newfoundland and Labrador (NL) from production cuts because of its specific geographical situation and market structure and its ability to access global Brent prices. The released production data for March and April 2020, does not show any significant change in the crude oil production in NL (C-NLOPB 2020). 4 As the summation of the shares of four provinces is not equal to 100%, we then inflate the shares of these provinces to 100% based on the production weight of each province. 5 Based on 2019 production by project type. 6 Announced projects are assigned with high uncertainties regarding timing and project production capacities.

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Table 3.4 highlights the oil sands production losses by scenario.

Table 3.4: Bitumen Production Losses (KBPD)

Scenario 2020 2021 2022 2023+ Scenario I 215 0 0 0

Scenario II 716 501 143 143

Scenario III 1217 1217 1002 430

Source: EDC Associates Ltd., CERI

Figure 3.1 illustrates the possible paths for production under the three scenarios. In all three scenarios, bitumen production faces production cuts, some temporary, some permanent.

A significant milestone of a 3.1 million-barrel-per-day production level reached in 2018 was maintained in 2019 as well. In 2019, oil sands bitumen production was comprised of in situ (thermal and cold bitumen) production of 1.6 MMBPD and mining production of 1.5 MMBPD within the boundaries of oil sands areas.7

In Scenario I, production from mining and in situ projects (thermal and cold bitumen) is set to decline by 215 KPBD in 2020, with full recovery by 2021. By the end of the decade, production is forecast to reach 3.9 MMBPD in 2030, peaking at 4.7 MMBPD by 2039.

In Scenario II, production losses are more substantial than in Scenario I, amounting to 716 KBPD in 2020, 501 KBPD in 2021, and 143 KBPD in 2022 onward. This scenario introduces a permanent production loss of 143 KBPD in the overall outlook to 2039. After the initial production hit, bitumen production grows at a slower rate, rising to 3.8 MMBPD in 2030, and to 4.6 MMBPD by the end of the forecast period.

7 Totals may not add up due to rounding. Historical production is sourced from the AER ST-98 2020.

August 2020 22 Canadian Energy Research Institute

Figure 3.1: Bitumen Production Scenarios

5,000

4,500

4,000

3,500

3,000

KBPD 2,500

2,000

1,500

1,000 Scenario I Scenario II Scenario III

500

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Historical Outlook

Source: CanOils, EDC Associates, CERI

Illustrated in Figure 3.2 are the production projections by extraction type for all three scenarios. Based on the historical shares of mining and in-situ production, the losses are assigned based on those proportions. While the assigned production loss shares are similar for in situ and mining projects, it is also evident that over the forecast period, the share of bitumen production from mining will decrease – from 50% in 2019 to 30% in 2039. By the end of the projection period, in situ bitumen accounts for most incremental bitumen barrels produced.

The majority of oil sands mines are integrated with an upgrader that converts raw bitumen to synthetic crude oil or SCO, similar to the quality of WTI. On average, about 15% of raw bitumen used as feedstock for upgrading is lost in the conversion process. The growth in production of non-upgraded bitumen is expected to outpace that of upgraded bitumen, mainly because new mines (Fort Hills and Kearl) will not have upgrading capabilities and in situ projects, except for one, do not upgrade bitumen and instead dilute it with a lighter hydrocarbon to create a dilbit product that flows easily in the pipeline.

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) 23

Figure 3.2: Bitumen Production by Project Type (All Scenarios)

5,000 Scenario I

4,500

4,000 Total Mining Total In Situ 3,500

3,000

2,500 KBPD 2,000

1,500

1,000

500

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Historical Outlook Scenario II 5,000

4,500

4,000 Total Mining Total In Situ

3,500

3,000

2,500 KBPD 2,000

1,500

1,000

500

4,500 Total Mining Total In Situ 4,000

3,500

3,000

2,500 KBPD 2,000

1,500

1,000

500

August 2020 24 Canadian Energy Research Institute

Emissions Greenhouse gas (GHG) emissions are a significant area of environmental concern in the oil sands sector. Increasing concentrations of anthropogenic (i.e., human-produced) GHGs in the atmosphere are a major driver of climate change attributed to human activity. GHGs influence climate by trapping radiation from the earth’s surface, resulting in an overall warming effect on the planet. This can lead to several potentially adverse outcomes such as changing climate patterns (for example, increased or decreased precipitation) and rising sea levels.

According to the National GHG Inventory reported by the Environment and Climate Change Canada

(ECCC), total Canadian emissions of CO2eq were 729 Mt in 2018 (the most recent annual data available) (Environment and Climate Change Canada 2020). Of the total emissions, stationary combustion sources and fugitive emissions from the oil and gas extraction activities account for 106 Mt and 54 Mt, respectively. The effects of the sector on Canada’s total emissions and the ability to meet international commitments to GHG abatement are substantial. Canada has committed under the Paris Agreement of 2015 to decrease emissions by 30% below 2005 levels by the year 2030. Canada’s 2050 reduction targets are set at 80% below 2005.

Besides the international commitment, the provincial government has introduced an emissions cap associated with oil sands production of 100 Mt/year and a provincial Technology Innovation and Emissions Reduction (TIER) regulation. Albertans had the federal fuel charge imposed since January 1, 2020, under the Federal carbon tax regulations. Still, the affected sectors are not a subject of the federal output-based pricing system (OBPS), as it has its OBPS system that came into force on January 1, 2020, under the new TIER regulation.

There are two methods to consider when looking at emissions performance. The first is GHG emissions intensity, which is the emissions in CO2 equivalent per barrel of bitumen or synthetic crude oil produced. Emissions intensity is valuable for examining whether changes in operating conditions at a project level have been effective considering changing production volumes. The second is bulk emissions for a project. A project can make significant efforts to reduce GHG emissions, but total emissions can still rise if bitumen production has risen at a faster rate than emissions have fallen. Looking at bulk emissions can obscure progress made to curb GHGs. Still, this metric is critical to examine as the climate response of emissions will not depend on how many resources were extracted during the emission of these gases.

Figure 3.3 illustrates the total oil sands emissions projections based on the three production scenarios presented. The oil sands emissions projection includes emissions from existing upgrading, electricity or fugitive emissions and flaring. Current on-site emissions are projected to change in tandem with bitumen and SCO production. Future emissions are calculated based on historic emission intensities, which have been decreasing but do not reflect any future innovation or technology change to reduce emission levels. However, considering historical and present efforts by many operators to reduce emission intensities, improvements in emissions over the forecast period are within reach. Hence this conservative outlook should be considered a ceiling on oil sands emissions. CERI will evaluate emissions from oil sands technology innovations in the upcoming study to be released in Fall 2020. The report will outline the impacts of improving emissions intensity due to technological improvements in the oil sands industry.

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) 25

Figure 3.3: Bitumen Emission Scenarios

140

Scenario I Scenario II Scenario III

120

100

(Tonnes CO2eq./yr) (Tonnes 60

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 Historical Outlook

Source: CERI, CanOils

August 2020 26 Canadian Energy Research Institute

Chapter 4: Conclusions

Since the COVID-19 pandemic began in early 2020, a subsequent decrease in oil demand, record levels of crude inventories, negative oil prices, the significant increase in the unemployment rate, and the decrease in capital spending, are continuing to have an adverse impact on the Canadian oil sands industry. While Canadian oil sands are land-locked, they are not immune to the global crude market dynamics. All these elements point to just how uncertain and unpredictable forecasting of future oil sands production is.

The outlook becomes even more complicated when the governments intervene in the crude markets, which are fundamentally based on the natural laws of supply and demand. The two major examples are the Russia-Saudi Arabia price war and the agreements in the OPEC+ meetings regarding production cuts. The future of the oil and gas industry in this circumstance strongly depends on geopolitics and how decision-makers deal with the situation and what strategies are going to be implemented. The probability of a second wave of the pandemic would further undermine the market confidence and might cause more substantial detrimental impacts.

CERI’s oil sands production outlook calls for immediate production losses in the short term, with some permanent losses under two out of three scenarios. With the forecasted improvement of oil prices out to medium and long term8, bitumen production is assumed to resume and grow to the end of the forecast period. The plans to expand oil sands production, increase pipeline takeaway capacity and gain access to other markets are still dependent on key elements that must align for the industry. CERI believes these elements are:

vi) favourable oil prices at levels where oil sands projects can be economical; vii) implementing cost-cutting measures through the adoption of improved processes and technologies; viii) continuous improvement in environmental performance among oil sand producers; ix) increased market access; and x) the ability to collaborate effectively in a competitive environment.

8 According to the US EIA’s Annual Energy Outlook 2020, annualized WTI reaches above US$71/bbl in 2030 and US$85/bbl in 2039.

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) 27

Bibliography

AER. 2020. “ST98.” 2020. https://www.aer.ca/providing-information/data-and-reports/statistical- reports/st98.html. CAPP. 2019. “Statistical Handbook.” Canadian Association of Petroleum Producers. 2019. https://www.capp.ca:443/publications-and-statistics/statistics/statistical-handbook. CERI. 2019. “Canadian Oil Sands Supply Costs and Development Projects (2019-2039).” https://ceri.ca/assets/files/Study_183_Full_Report.pdf. C-NLOPB. 2020. “Statistical Information.” C-NLOPB. 2020. https://www.cnlopb.ca/information/statistics/. EDC Associates Ltd. 2020. “What Just Happened? Modelling Alberta’s Power Market in Unprecedented Times.” Webinar, EDC Associates Ltd. Environment and Climate Change Canada. 2020. “Greenhouse Gas Sources and Sinks: Executive Summary 2020.” Program results. Aem. June 22, 2020. https://www.canada.ca/en/environment-climate- change/services/climate-change/greenhouse-gas-emissions/sources-sinks-executive-summary- 2020.html. IEA. 2020. “Sustainable Recovery - World Energy Outlook Special Report.” Province, The. 2020. “Varcoe: Oil Taps Coming Back on, but Industry Keeps Tight Grip on Spending.” July 8, 2020. https://calgaryherald.com/opinion/columnists/varcoe-taps-coming-back-on-but- oilpatch-keeps-tight-grip-on-spending.

August 2020 28 Canadian Energy Research Institute

Appendix A: Production Forecasting Methodology

CERI’s methodology for projecting bitumen and SCO production remains unchanged from past reports. Projections are based on the summation of existing and new projects, with a variety of assumptions about the project schedule and delays, technology, and state of development. The method by which projects are delayed, or the rate at which production comes on-stream, is based upon CERI’s long-running observations of oil sands market dynamics and specific characteristics of oil sands projects.

The extraction of oil sands is currently based on two methods: in situ and mining. In situ recovery consists of primary recovery, thermal recovery, solvent-based recovery, and hybrid thermal/solvent processes. Surface mining and extraction9 could be either a stand-alone mine or integrated with an upgrader. Within in situ and mining methods, various technologies to extract valuable bitumen from the oil sands are utilized.10 Future R&D will focus on increasing recoverable reserves, reducing costs, improving product quality, and enhancing environmental performance. Industry, government, and community stakeholders will continue to carry out R&D as long as there is a perceived commercial incentive to do so. For more information on what technologies and processes are being developed, refer to CERI Study 16411.

Delay Assumptions Onstream projects are assumed to be producing bitumen until the end of the project (unless new phases were added). Projects that are under construction will proceed with minimal delays and reach their nameplate capacity. Projects further along the regulatory process are given shorter delays and have higher probabilities of proceeding to their announced production capacity. Given the current economic downturn, projects that have been announced but have not yet entered the regulatory process with a disclosure document are given the most extended delays. Table A.1 presents these factors according to project status.

Delays and probabilities, as measured by a probability fraction, for each phase of the regulatory approval process, are based upon reasonable estimates of the length of time each phase could take. Another factor that is contributing to this increase in delays and capacity curtailments is that existing export pipeline capacity is not sufficient to transport the incremental volumes of future produced bitumen and SCO and has an impact on the project announcements and construction. Although there are several pipeline projects proceeding, many are facing opposition. Hence incremental growth in oil sands production post-

9Within mining and extraction, various technologies are used to support the extraction process and transportation of oil sands. While each technology has some advantages and disadvantages, they have all been categorized as mining and extraction for this report and are treated as one technology type. 10The reader is assumed to have some familiarity with each extraction method. Detailed descriptions of the extraction technologies are available from CERI Study 122 and 126. 11 CERI Study 164. “Economic Potentials and Efficiencies of Oil Sands Operations: Processes and Technologies”. April 2017.

August 2020 Canadian Oil Sands Production and Emissions Outlook (2020-2039) 29

2019 could face market access challenges unless there is a significant increase in rail transport, additional export pipeline capacity or a reduction in the amount of diluent used to transport non-upgraded bitumen.

Table A.1: Project Delay Factors High Reference Low

Case Case Case

Project Status Capacity Delay Capacity Delay Capacity Delay Fraction Years Fraction Years Fraction Years Onstream 1.00 0 1.00 0 1.00 0 Under Construction 1.00 0 1.00 0 0.80 2 Approved 0.90 0 0.65 0 0.50 6 Awaiting Approval 0.80 4 0.65 6 0.45 8 Announced 0.75 5 0.50 7 0.35 10 Suspended 1.00 0 0.00 0 0.00 0 Prospect 0.00 0 0.00 0 0.00 0 Cancelled 0.00 0 0.00 0 0.00 0 Concluded 0.00 0 0.00 0 0.00 0

August 2020