Study No. 141 July 2014

CANADIAN CANADIAN OIL SANDS SUPPLY ENERGY RESEARCH COSTS AND DEVELOPMENT INSTITUTE ROJECTS P (2014-2048)

Canadian Energy Research Institute | Relevant • Independent • Objective

CANADIAN OIL SANDS SUPPLY COSTS AND DEVELOPMENT PROJECTS (2014-2048)

Canadian Oil Sands Supply Costs and Development Projects (2014-2048)

Copyright © Canadian Energy Research Institute, 2014 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute

ISBN 1-927037-25-6

Authors: Dinara Millington Carlos A. Murillo Rob McWhinney

Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to all CERI staff that provided insightful comments and essential data inputs required for the completion of this report, as well as those involved in the production, reviewing, and editing of the material, including but not limited to Peter Howard and Megan Murphy

CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca

July 2014 Printed in Canada

Front Cover Photo’s Courtesy of Cenovus Energy Canadian Oil Sands Supply Costs and Development Projects (2014-2048) iii

Table of Contents

LIST OF FIGURES ...... v LIST OF TABLES ...... vii EXECUTIVE SUMMARY ...... ix Supply Cost Results ...... ix Supply Cost Sensitivities ...... x Projection Results – Three Scenarios ...... xiii Oil Sands Production ...... xiii Oil Sands Capital Investment ...... xiv Natural Gas Requirements ...... xv Oil Sands Emissions ...... xvi Oil Sands Royalties ...... xvii Environmental Considerations ...... xix CHAPTER 1 INTRODUCTION ...... 1 Background ...... 1 Approach ...... 4 Organization of the Report ...... 5 CHAPTER 2 OIL SANDS OVERVIEW ...... 7 Oil Sands, Background ...... 7 Oil Sands Development Scenarios ...... 10 CHAPTER 3 OIL SANDS SUPPLY COSTS ...... 15 Introduction ...... 15 Methodology and Assumptions ...... 15 Design Assumptions ...... 16 Light-Heavy Differential...... 22 Crude Oil Transportation Costs ...... 26 Economic and Taxation Assumptions...... 27 Royalty Assumptions ...... 29 US-Canadian Exchange Rate ...... 31 Supply Cost Results ...... 32 Supply Cost Sensitivities ...... 36 CHAPTER 4 OIL SANDS PROJECTIONS ...... 41 Methodology and Assumptions ...... 41 Delay Assumptions ...... 42 Estimating Royalty Revenues and Blending Requirements ...... 42 Oil Sands Projections – Three Scenarios ...... 43 Oil Sands Capacity ...... 44 Oil Sands Production ...... 46 Oil Sands Capital Investment ...... 48

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Natural Gas Requirements ...... 50 Oil Sands Emissions ...... 52 Oil Sands Royalties ...... 55 Oil Sands Projections – Reference Case Scenario ...... 56 Oil Sands Production – Historic and Forecast ...... 56 Diluent Demand, Supply and Transportation...... 59 Capital Investment and Operating Costs ...... 64 Alberta Oil Sands Royalty Revenues ...... 65 CHAPTER 5 ENVIRONMENTAL CONSIDERATIONS FOR OIL SANDS ...... 71 Air and Emissions ...... 71 Mining and Upgrading ...... 72 In Situ ...... 74 Water Use and Tailings Ponds Management ...... 76 Mining ...... 76 In Situ ...... 79 In Situ Water Regulations ...... 80 Update on Monitoring Programs ...... 83 AEMERA ...... 85

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List of Figures

E.1 Total Field Gate Bitumen/SCO Supply Costs – Reference Case Scenario ...... x E.2 Supply Cost Sensitivity – 30 MBPD SAGD Project ...... xi E.3 Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project ...... xi E.4 Supply Cost Sensitivity – 115 MBPD Integrated Mining, Extraction and Upgrading Project ...... xii E.5 Supply Cost Sensitivity – 100 MBPD Standalone Upgrader ...... xii E.6 Bitumen Production Projections ...... xiv E.7 Total Capital Requirements ...... xv E.8 Natural Gas Requirements ...... xvi E.9 Greenhouse Gas Emissions ...... xvii E.10 Oil Sands Royalties – Three Scenarios ...... xviii E.11 Alberta Oil Sands Royalties – Reference Case Scenario ...... xix 1.1 Full Cycle Supply Costs ...... 2 2.1 Alberta’s Oil Sands Areas ...... 8 2.2 Mining and Extraction ...... 9 2.3 In Situ – SAGD ...... 9 2.4 US and BRIC Oil Consumption, Shares of Total Oil Consumption ...... 11 2.5 World Oil Demand by Region (New Policies Scenario) 2012-2035 ...... 11 3.1 Average Initial Capital Cost ...... 19 3.2 Average Non-Energy Operating Costs ...... 20 3.3 Henry Hub Natural Gas Price Forecast ...... 21 3.4 Alberta End-use Industrial Electricity Price Forecast ...... 22 3.5 Densities and Sulfur Content of Crude Oils ...... 23 3.6 Light-Heavy Differentials ...... 26 3.7 Alberta Bitumen Royalty Rates ...... 30 3.8 WTI Price Forecast ...... 31 3.9 US/Canadian Exchange Rate ...... 32 3.10 Total Field Gas Bitumen/SCO Supply Costs ...... 33 3.11 Oil Sands Supply Costs – Reference Case Scenario ...... 35 3.12 Supply Cost Sensitivity – 30 MBPD SAGD Project ...... 37 3.13 Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project ...... 37 3.14 Supply Cost Sensitivity – 115 MBPD Integrated, Mining, Extraction and Upgrading Project ...... 38 3.15 Supply Cost Sensitivity – 100 MBPD Standalone Upgrader ...... 38 4.1 Bitumen Royalty Drivers ...... 43 4.2 Bitumen Capacity Projections ...... 45 4.3 Bitumen Production Projections ...... 48 4.4 Total Capital Requirements ...... 49 4.5 Natural Gas Requirements ...... 51 4.6 Greenhouse Gas Emissions ...... 54

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4.7 Oil Sands Royalties ...... 56 4.8 Bitumen Production Forecast – Comparison ...... 57 4.9 Bitumen Production by Extraction Type – Reference Case Scenario ...... 58 4.10 Net Bitumen and SCO Production by Project Status Reference Case Scenario ...... 59 4.11 Western Canada Heavy Oil and Oil Sands Diluent Demand by Project Type and Type of Diluent, 2007-2030 ...... 60 4.12 Pentanes Plus/Condensate Supply and Demand Balance, 2007-2030 ...... 61 4.13 Potential Diluent Demand Reduction from Moving Bitumen via Rail 2007-2030 ...... 62 4.14 Diluent Import Requirements and Import Infrastructure, 2007-2030 ...... 63 4.15 Total Capital Invested by Project Type – Reference Case Scenario ...... 64 4.16 Total Cost Requirements – Reference Case Scenario ...... 65 4.17 Bitumen Royalties Collected by Project Type ...... 67 4.18 BRIK Volumes Availability and Commitments and Royalty Value ...... 69 4.19 Total Bitumen Royalties Collected Based on Different Levels of BRIK Volumes ...... 70 5.1 Bulk GHG Emissions and GHG Emission Intensities for Oil Sands Mining Projects, 2004-2011 ...... 73 5.2 Bulk GHG Emissions and GHG Emission Intensities for Oil Sands In Situ Projects, 2004-2011 ...... 74 5.3 Fresh Water Usage by Oil Sands Mining Operations, 2005-2013 ...... 76 5.4 Fresh and Brackish Water Use by In Situ Oil Sands Producers ...... 80

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List of Tables

2.1 In-Place Volumes and Established Reserves of Crude Bitumen in Alberta ..... 10 3.1 Design Assumptions by Extraction Method ...... 18 3.2 Crude Oil Characteristics ...... 24 3.3 Phase-Out Schedule ...... 28 3.4 Supply Costs Summary ...... 34 3.5 Supply Costs Comparison – WTI Equivalent Supply Costs ...... 36 3.6 Assumptions for Sensitivity Analysis ...... 36 4.1 Oil Sands Production Forecast ...... 47 4.2 Emission Factors ...... 53 5.1 Required Fines Disposal Under Directive 74 and Mine Performance ...... 78 5.2 IL 89-5 Based Recycle Rates and Directive 81 Based Disposal Limits and Fines ...... 81 5.3 Disposal Factors for Thermal In Situ Oil Sands Producers ...... 82

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Executive Summary

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 ninth annual edition of CERI’s oil sands supply cost and development projects update report. Similar to past editions of the report, several scenarios for oil sands developments are explored. In addition, given the assumptions for the current cost structure, an outlook for future supply costs will be provided. Supply Cost Results Supply cost is the constant dollar price needed to recover all capital expenditures, operating costs, royalties and taxes and earn a specified return on investment. Supply costs in this study are calculated using an annual discount rate of 10 percent (real), which is equivalent to an annual return on investment of 12.5 percent (nominal) based on the assumed inflation rate of 2.5 percent per annum.

Based on these assumptions, the supply costs of crude bitumen using SAGD, surface mining and extraction, integrated mining and upgrading, and a standalone upgrader have been calculated for a hypothetical project. Figure E.1 illustrates the supply costs for these projects. The plant gate supply costs, which exclude transportation and blending costs, are C$50.89/bbl, C$71.81/bbl, C$107.57/bbl, and C$40.82/bbl for SAGD, standalone mine, integrated mining and upgrading, and a standalone upgrader, respectively. A loose comparison1 of field gate costs from CERI’s May 2013 update with this year’s supply costs indicates that, after adjusting for inflation, the supply cost for a SAGD producer has risen by 4.4 percent, 1.6 percent for a standalone mine and 5.9 percent for an integrated mining and upgrading project.

After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing for SAGD projects is US$84.99/bbl, US$105.54 for a standalone mine; US$109.50 for an integrated mining and upgrading;, and US$41.44/bbl for a standalone upgrader. At WTI prices of US$100/bbl, the only project that would be economic is a SAGD in situ project, which is consistent with how the oil sands projects are currently being developed. The greenfield projects that will be built are mostly in situ type projects, the development of mines and integrated mines is only happening as an expansion of existing projects that can provide some cost savings and economies of scale.

While capital costs and the return on investment account for a substantial portion of the total supply cost, the province stands to gain $9.40 to $13.60 in royalty revenues for each barrel of oil produced on average, over the life of an oil sands project.

1 Because some changes were made in the project energy requirements as well as project economics, a direct comparison of costs is not favoured.

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Figure E.1: Total Field Gate Bitumen/SCO Supply Costs – Reference Case Scenario

$120

$107.57 $110

$100

$90

$80 $71.81 $70

$60 $50.89 $50 $40.82 $40 2013 Real CDN$/bbl

$30

$20

$10

$0 Mining & Standalone SAGD 10% ROR Mining 10% ROR Upgrading 10% Upgrading 10% (a) (a) ROR (a) ROR (a) Fixed Capital (Initial & Sustaining) $18.92 $31.14 $54.72 $24.25 Operating Working Capital $0.45 $0.70 $1.06 $0.39 Fuel (Natural Gas) $4.31 $1.90 $3.03 $3.74 Other Operating Costs (incl. Elec.) $14.55 $19.97 $28.66 $9.07 Royalties $9.43 $13.61 $12.39 $0.00 Income Taxes $3.09 $4.42 $7.55 $3.33 Emissions Compliance Costs $0.11 $0.04 $0.05 $0.00 Abandonment Costs $0.03 $0.04 $0.07 $0.03

Source: CERI Supply Cost Sensitivities The presented costs for four different oil sands projects also need to be analyzed in terms of how sensitive costs are to changes to some of the variables. Bitumen supply cost sensitivities for a hypothetical SAGD, integrated mining, extraction and upgrading, and standalone mine projects and upgraders are represented graphically in Figures E.2- E.5.

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Figure E.2: Supply Cost Sensitivity – 30 MBPD SAGD Project

Discount Rate (2% change)

Initial Capital Cost (25% change)

Non-energy Operating Costs (25% change)

SOR (25 change)

Sustaining Capital Cost (25% change)

Carbon Dioxide Levy

40 45 50 55 60 2013 CDN$/bbl Source: CERI

Figure E.3: Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project

Non-energy Operating Costs (25% change)

Discount Rate (2% change)

Initial Capital Cost (25% change)

SOR (25 change)

Sustaining Capital Cost (25% change)

Carbon Dioxide Levy

$55 $60 $65 $70 $75 $80 $85 2013 CDN$/bbl Source: CERI

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Figure E.4: Supply Cost Sensitivity – 115 MBPD Integrated Mining, Extraction and Upgrading Project

Discount Rate (2% change)

Initial Capital Cost (25% change)

Non-energy Operating Costs (25% change)

Sustaining Capital Cost (25% change)

SOR (25 change)

Carbon Dioxide Levy

$90 $95 $100 $105 $110 $115 $120 $125 2013 CDN$/bbl

Source: CERI

Figure E.5: Supply Cost Sensitivity – 100 MBPD Standalone Upgrader

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Operating Costs (25% change)

Sustaining Capital Cost (25% change)

Carbon Dioxide Levy

SOR (25 change)

30 35 40 45 50 2013 CDN$/bbl

Source: CERI

The supply costs for all projects are most sensitive to changes in capital cost. A 25 percent increase in initial capital cost would affect an integrated project the most, raising its supply cost by C$13.93/bbl. The supply cost for a SAGD producer will increase by C$5.22/bbl and a standalone mine would experience a C$7.84/bbl increase from its base supply cost. For a standalone upgrader the cost will go up by C$5.69/bbl. Changes

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in discount rate and operating costs will also alter the supply costs. As expected, SAGD supply cost is more sensitive to changes in steam-to-oil ratio and carbon compliance cost changes than the supply costs of the other two projects. Projection Results – Three Scenarios Oil Sands Production Figure E.6 illustrates the possible paths for production under the three scenarios. For an oil sands producer, a project’s viability relies on many factors such as, but not limited to, the demand-supply relationship between production, operating and transportation costs (supply side) and the market price for blended bitumen and SCO (demand). All three scenarios show a significant growth in oil sands production for the 35-year projection period.

Total production from oil sands areas totaled 2.1 MMBPD in 2013, comprised of in situ and mining production of 1.9 MMBPD and 0.3 MMBPD of primary and enhanced oil recovery (EOR) production within the boundaries of oil sands areas. Total production in 2012 was 1.9 MMBPD, meaning the oil sands production grew 10.9 percent year over year. Production from oil sands comprises an increasing share of Alberta’s and Canada’s crude oil production. In 2013, non-upgraded bitumen and SCO production made up 54 percent of total Canadian crude production and 73 percent of Alberta’s total production.

In the High Case Scenario, production from mining and in situ thermal and solvent extraction (excluding primary recovery) is set to grow from 1.9 MMBPD in 2013 to 3.8 MMBPD by 2020 and 5.7 MMBPD by 2048. In the Low Case Scenario production rises to 4.2 MMBPD by 2030 and 4.3 MMBPD by the end of forecast period. CERI’s Reference Case Scenario provides a more plausible view of the oil sands production. Projected production volume will increase to 3.4 MMBPD by 2020 and 4.8 MMBPD in 2048. Cold bitumen production from primary and EOR wells is forecasted to increase from 0.27 MMBPD in 2013 to its peak of 0.35 MMBPD by 2020 and then slowly tapering off to just above 0.2 MMBPD by the end of forecast period.

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Figure E.6: Bitumen Production Projections

('000bpd)

7,000

6,000

5,000

4,000

3,000

(Production, High Case Scenario)

(Production, Low Case Scenario) 2,000

(Production, Reference Case Scenario)

1,000

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Note: Since the primary and EOR production forecast is estimated using CERI’s crude oil forecasting model, this Figure does not illustrate this forecast. Source: CERI, CanOils

Oil Sands Capital Investment CERI has estimated the total and annual financial commitments required for the oil sands. Initial capital costs, under the three scenarios, are illustrated in Figure E.7.

Over the 35-year projection period from 2014 to 2048 inclusive, the total capital required is projected to be C$636.6 billion under the High Case Scenario, C$597.9 billion under the Reference Case Scenario, and C$590.2 billion under the Low Case Scenario.2 These projections do not include capital investment required for primary and EOR oil sands projects that lie within oil sands areas. The forecast for cold bitumen capital spending is calculated under CERI’s conventional oil model and those results are presented in Chapter 4 and discussed only in the context of the Reference Case Scenario.

New investment dollars start declining half way through the forecast period, and approach zero by the end of the projection period. This, however, does not indicate a slowdown in the oil sands, merely a lack of information on new capacity that will be

2 The total capital spending on primary and EOR wells is estimated to be C$8.4 billion.

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coming on stream, and relates back to CERI’s assumptions for project start dates and announcements from the oil sands proponents. With careful planning, the Reference Case Scenario could be a viable target.

Ongoing investment, in the form of sustaining capital will take place on an annual basis. In each of the three scenarios, the annual sustaining capital required for the oil sands (excluding royalty revenues, taxes, and fixed and variable operating costs) exceeds C$6 billion by 2048. The Reference Case Scenario projection shows an annual investment of C$9.2 billion in 2048, and is estimated to average C$8.7 billion over the projection period. Under the High Case Scenario, the sustaining costs reach an all-time high of C$10.7 billion dollars in 2048, averaging C$9.9 billion over the 35-year window. In the Low Case Scenario, C$8.2 billion will be spent on sustaining costs in 2046, with an average of C$7.5 billion over the projection period.

Figure E.7: Total Capital Requirements

(Million CDN$) $50,000

$45,000

Total Capital Investments (Capacity, High Case Scenario) $40,000

Total Capital Investments (Capacity, Low Case Scenario)

$35,000 Total Capital Investments (Capacity, Reference Case Scenario)

$30,000

$25,000

$20,000

$15,000

$10,000

$5,000

$0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI, CanOils

Natural Gas Requirements More than the conventional oil and gas industries, the oil sands industry is a large consumer of energy. Given that most in situ projects generate steam using natural gas- fired steam generators, the single highest operating cost for these in situ thermal projects is the cost of natural gas. Although mining, extraction and upgrading projects use proportionately less natural gas than in situ projects, the industry’s demand for natural gas is still substantial.

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The amount of natural gas required to sustain the oil sands industry is substantial, and is illustrated in Figure E.8. By 2048, natural gas requirements will increase 2 to 3 times the current levels. Given the robust production projection, natural gas use is estimated to rise from the current 1,474 MMcf/d in 2013 to 3,753 MMcf/d in 2046 under the High Case Scenario, 3,170 MMcf/d in the Reference Case Scenario, and 2,870 MMcf/d under the Low Case Scenario. This year’s forecast of natural gas demand is a half percent lower overall for the Reference Case Scenario. Though not a significant change, the prospects for technology switching to use less natural gas and efficiency improvements are substantial.

Figure E.8: Natural Gas Requirements

(MMcf/d)

4,000

3,500

3,000

2,500

2,000

Total Natural Gas Requirements (Production, High Case Scenario) 1,500

Total Natural Gas Requirements (Production, Low Case Scenario)

Total Natural Gas Requirements (Production, Reference Case Scenario) 1,000

500

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI

Oil Sands Emissions Without equipment to sequester emissions, GHG emissions grow proportionately to the increase in production. While technological innovation within the oil sands industry (in addition to carbon capture and storage) is expected to help reduce these emissions, the emissions are still expected to rise. Figure E.9 illustrates the GHG emissions under CERI’s emission factor assumptions. GHG emissions are expected to rise in tandem with oil sands production.

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Figure E.9: Greenhouse Gas Emissions

(CO2 eq. MT/year)

180

160

140

120

100

80

Total Greenhouse Gas Emissions (Production, High Case Scenario) MT/Year

Total Greenhouse Gas Emissions (Production, Low Case Scenario)MT/Year 60

Total Greenhouse Gas Emissions (Production, Reference Case Scenario) MT/Year

40

20

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 Source: CERI

Emissions will rise from 55 Mt/year in 2012 to 144 Mt/year in 2048 under the Reference Case Scenario, to 165 Mt/year in 2048 in the High Case Scenario, and to 129 Mt/year under the Low Case Scenario. Cumulative emissions in the Reference Case Scenario are projected to be 4,587 Mt from 2014 to 2048, which is 3.3 percent higher than last year’s 35-year cumulative emissions projection.

Oil Sands Royalties Figure E.10 illustrates the bitumen royalty estimates under the Low, Reference, and High Case Scenarios both on an annual and cumulative basis (2014-2048). Royalty revenues rise in all three cases with the production as expected. Under the Low and High Case Scenarios annual royalty revenues reach (in 2013 dollars) C$39.6 billion and C$52.2 billion, respectively by 2048. Annual revenues amount to C$44.6 billion by 2048 in the Reference Case Scenario. The shaded area of Figure E.10 represents the difference in estimates between scenarios which is equal to over C$318 billion between the High and Low Case Scenarios. The cumulative royalty revenues over the 35-year forecast will amount to $1.2 trillion under the High Case Scenario, C$1.0 trillion under the Reference Case Scenario, and C$0.9 trillion under the Low Case Scenario.

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Figure E.10: Oil Sands Royalties – Three Scenarios

Annual ($MM) Cummulative ($MM) $60,000 $1,300,000

Estimated Royalties Range $55,000 $1,200,000 CERI-Low Case

$50,000 CERI-Reference Case $1,100,000 CERI-High Case $1,000,000 $45,000 Cumulative-Low Case Scenario (Right Scale) Cumulative-Reference Case Scenario (Right Scale) $900,000 $40,000 Cumulative-High Case Scenario (Right Scale) $800,000 $35,000 $700,000 $30,000 $600,000 $25,000 $500,000 $20,000 $400,000

$15,000 $300,000

$10,000 $200,000

$5,000 $100,000

$0 $0

2012 2017 2045 2007 2008 2009 2010 2011 2013 2014 2015 2016 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2046 2047 2048

Source: CERI

Under the Reference Case Scenario, royalties collected from the oil sands industry are expected to exceed $10 billion by 2019 and $30 billion by 2030. After 2027, royalties collected from in situ projects account for 65 percent of total oil sands royalties. By 2040, annual oil sands royalties are estimated at around $44 billion. Between 2014 and 2048 a total of over $1.0 trillion are estimated to be collected by the Alberta Government from oil sands operators, a figure equivalent to the current value of Canada’s GDP (see Figure E.11).

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Figure E.11: Alberta Oil Sands Royalties – Reference Case Scenario

Annual ($MM) Cumulative ($MM) $60,000 $1,300,000 Primary/ EOR Mining $1,200,000 $55,000 In Situ Total Oil Sands Royalties $50,000 2013 Royalty Curve (Study No. 133) $1,100,000 Cumulative (2014 - 2048) (Right Scale) $1,000,000 $45,000 2013 Cumulative (Study No. 133) $900,000 $40,000 $800,000 $35,000 $700,000 $30,000 $600,000 $25,000 $500,000 $20,000 $400,000 $15,000 $300,000

$10,000 $200,000

$5,000 $100,000

$- $0

2007 2034 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 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 Historical/ Actual Outlook

Source: CERI Environmental Considerations Greenhouse gas (GHG) emissions are a major 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 in 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 a number of potentially adverse outcomes such as changing climate patterns (for example, increased or decreased precipitation) and rising sea levels.

When placed in a global context, oil sands themselves are a relatively minor GHG 3 contributor. Globally in 2011, 34 billion tonnes of CO2 were emitted, while total Canadian emissions of CO2 were 556 Mt, or 1.6 percent of this value (EC 2013 NIR report). Overall, including non-CO2 gases such as methane (CH4) and nitrous oxide (N2O), Canada emitted 702 Mt of CO2 equivalents (CO2e) in 2011, and of these emissions, 55 Mt (7.8 percent) came from the oil sands sector.4 Thus, decreasing the emissions from the oil sands sector will do relatively little to GHG emissions on a global scale. However, the effects of the sector on Canada’s total emissions and ability to meet international commitments to GHG abatement are substantial. Canada has committed under the

3 Trends in Global CO2 Emissions: 2012 Report (2012), PBL Netherlands Environmental Assessment Agency. http://edgar.jrc.ec.europa.eu/CO2REPORT2012.pdf 4 Canada’s Emission Trends (2013), Environment Canada, Cat. No. EN81-18/2013E-PDF. http://www.publications.gc.ca/site/eng/449695/publication.html

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Copenhagen accord of 2009 to decrease emissions to 17 percent below 2005 levels by year 2020. By 2020, oil sands emissions are projected to nearly double to 101 Mt, and total share of the oil sands sector to Canadian emissions are projected to increase from 4.6 percent in 2005 to 13.8 percent in 2020. Environment Canada currently estimates that emissions in 2020 will only be 0.4 percent below 2005 levels, compared to 9.5 percent below 2005 in the absence of GHG emissions growth in the oil sands sector. Increasing production in this sector makes the meeting of international commitments increasingly difficult, and thus there is interest in reducing the amount of GHGs emitted to extract bitumen from the oil sands and generate synthetic crude oil.

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Chapter 1 Introduction

Background Production and capital investment forecasts for the oil sands industry are estimated to continue to increase well into the future, and there are some major projects still to be constructed, but currently many producers are reporting a bit of a pause in new contract awards and backlog. However, this may be more a function of the change of the pace of development than an indication of downward pressure on the sector. The nature of new project development in the oil sands has changed. Ten years ago the industry was dominated by megaproject mines and upgraders each built by several thousand people, since then the sector has transformed into a more manageable phased in situ growth.

Albeit uncertainties around market access and competition from the US tight oil projects, oil sands production is expected to reach three million barrels per day (MMBPD) around 2017. This means the industry is expected to add approximately 1 MMBPD of production in less than five years, from both mining and in situ operations. In addition to several in situ projects/phases currently underway or expected to get the necessary approval in the near term, at least three mining projects are considered for major growth. This includes the 100,000 barrel per day second phase at Kearl, which is under construction, the staged integrated mining/upgrading expansion at Horizon to 250,000 barrels per day, and the long-awaited 190,000 barrel per day greenfield installation at Fort Hills.

One of the main differences between the oil sands market of today and the oil sands market of 10 years ago is the emergence of tight oil development, primarily in the United States. Although the two plays have vastly different profiles, they are being compared against each other; with many assuming that oil sands project supply costs are prohibitive by comparison, which might not necessarily be the case. According to a study by Scotiabank of more than 50 plays across Canada and the US, Western Canadian plays — including those in the oil sands — cost less to produce on average than plays in the US such as the Bakken in North Dakota, and the Eagle Ford and the Permian Basin, both in Texas (Figure 1.1).

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Figure 1.1: Full Cycle Supply Costs

The Saskatchewan Bakken offers one of North America’s best deals with a break-even cost of US$44.30 a barrel — including a 9 percent after-tax return.

Oil from existing in situ oil sands projects in Alberta is produced at a break-even cost of US$63.50 on average, and oil from existing integrated oil sands mining projects has a breakeven cost of US$60 to US$65, also including a 9 percent after-tax return. However, according to CERI’s research and analysis of greenfield oil sands projects, the breakeven supply costs for in situ and mining projects are significantly higher, making them riskier if oil prices weaken significantly. Chapter 3 of this report discusses the supply costs for greenfield oil sands projects. The technology development and implementation when it comes to in situ extraction holds a large potential for cost reduction.

According to BMO’s research study on oil and gas global costs “…a shift in focus from integrated mining projects to smaller in situ developments has helped reduce the overall weighted average to $70 per barrel, with several projects economic at prices as low as $40 per barrel.”1 This is exactly what the industry is witnessing – a move towards more in situ projects as their smaller scale allows for more efficient management of capital and scheduling to match the availability of key inputs such as skilled labour.

1 BMO Capital Markets, “Oil and Gas Global Costs”, August 2013.

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Moreover, the smaller-scale in situ processing facilities are more easily modularized and can be outsourced to equipment fabrication shops.

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 far- sighted companies that effectively deliberate over the risks of multi-decade operations. Heavy oil differentials, pipeline capacity limitations and speculative oil price loadings all play a role in these considerations, but they invariably take a back seat to larger and more global oil supply and demand fundamentals.

Delays in the approval of TransCanada Corporation’s Keystone XL project – originally regarded as the essential link between Canadian bitumen and the US Gulf Coast’s untapped refining capacity – have already prompted the industry to look for other solutions. Given current constraints and opposition to expansion of existing pipeline capacity and new pipeline developments, companies have been proactive at exploring other transport options such as rail.

It is not all doom and gloom for pipeline projects. Some have caught traction. The Seaway line that used to flow north to Cushing has recently been reversed with current capacity of 400,000 BPD. It will be expanded to 600,000 BPD by mid-2014. Since the original Keystone XL was rejected, the Keystone XL project has been split into two parts: a southern leg from Cushing to the Gulf that has received all necessary permissions to proceed started operation in late 2013. A Seaway reversal and expansion, with the Keystone XL southern leg, adds over 1.65 MMBPD of capacity out of Cushing to the Gulf by 2014. This substantially alleviated the ‘Cushing congestion’ – storage volumes in PADD II are back from all-time highs of over 40 million barrels of crude to seasonal norms and the differential between West Texas Intermediate (WTI) and Brent have returned to historical values. A recent Canaccord Genuity report points out that the combination of developments in transportation of crude oil by rail, pipeline project progress in key areas and new refining capacity should “at the minimum mean heavy oil producers are no longer victimized by transportation bottlenecks.” Canaccord goes so far as to say that the Keystone XL pipeline isn’t even needed anymore.

As for light-heavy oil differentials, which widened early in 2013 (Canadian benchmark heavy pricing traded at a discount to Brent as high as a US$60 per barrel in the first quarter), by summer, they had narrowed to about $20. Much of that wide spread was connected to pipeline constraints. Going forward, in CERI’s analysis, the light-heavy differential of US$18.00/bbl between light WTI and Western Canadian Select (WCS) was assumed.

Another factor that plays a role in the pace of oil sands development after global and regional supply and demand fundamentals is the federal government’s new rules on

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foreign ownership. In handing down its decision on the US$15.1 billion takeover of Canadian oil and gas company Nexen Inc. by Chinese state-owned entity CNOOC Limited, Industry Canada ruled out majority stakes in the oil sands by foreign national oil companies. Tougher rules combined with market access issues left the mergers and acquisitions shelf empty in the first half of the year, but most analysts see more money coming from Asia in the future. Despite the new challenges, majors and national oil companies will find it difficult to ignore the scale of production and resource found in the oil sands.

If Warren Buffett’s recent disclosure that he increased Berkshire Hathoway Inc.’s stake in the oil sands to more than US$500 million and celebrity billionaire T. Boone Pickens’ similar move that saw BP Capital Management’s shares in Suncor increase to over US$160 million are visible signs of confidence in Alberta’s oil sands, then many on the ground closer to the action can share that optimism.

CERI’s oil sands production forecast calls for relatively strong growth in both mining and in situ over the next 20 years. The plans to expand oil sands production, increase pipeline take-away 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) favorable oil prices at levels where oil sands projects can be economic, ii) continuous improvement in an environmental performance among producers to maintain their social license to operate, iii) appropriately managing project cost inflation by addressing skilled labour shortages and operational efficiencies, and iv) the ability to collaborate effectively in a competitive environment.

Approach Similar to past editions of this report, several scenarios for oil sands developments are explored. In addition, given the assumptions for the current cost structure, an outlook for future supply costs will be provided.

The purpose of this report is to:

 Provide the reader with a better understanding of the current status of Canadian oil sands projects, both existing and planned. The status assessment covers the full spectrum of activities and technologies, such as in situ, mining, and integrated production; and facilities for upgrading crude bitumen to synthetic crude oil (SCO).  Explore the future direction of oil sands development, including projections of production, investments, royalties, natural gas and diluent requirements, and GHG emissions.

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 Understand the natural gas requirements of the industry, and the GHG emissions associated with the industry’s oil sands development.  Estimate the supply cost, including costs associated with carbon emissions, for greenfield projects consistent with in situ, mining, and integrated production.  Show how the supply costs are sensitive to changes in the capital cost, discount rates, etc.  Provide an overview of environmental issues facing the oil sands industry as they relate to air, water and monitoring of activities.

CERI has established itself as a leader in oil sands related market intelligence. CERI’s oil sands projections and supply cost analysis are used by industry, governments, and other stakeholders as part of their market analysis. This report relies upon up-to-date information available on project announcements (updated to March 3, 2014), 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). Similarly, upgrading facilities are characterized by technology, and by type (i.e., standalone or integrated with crude bitumen extraction facilities).

All of 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.

This report also presents greenfield supply costs by type (i.e., mining, in situ and upgrading), and by technology (e.g., SAGD for in situ operation).

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

Chapter 2 introduces the oil sands upstream activities, and the scenarios developed for this report.

Chapter 3 presents the assumptions and methodology used in the supply cost assessment, followed by results for supply costs and sensitivities.

Chapter 4 highlights the assumptions and methodology used in the oil sands forecasting model and presents scenario-based production projections, followed by projections of capital investment, operating costs, natural gas use, emissions, royalties, and compliance costs.

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Chapter 5 discusses environmental performance of the oil sands industry with respect to air emissions, water use, tailings ponds and the latest developments in technology that will help address the environmental degradation of oil sands activity.

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Chapter 2 Oil Sands Overview

Oil Sands, Background The phrase “resources beyond belief” has often been used to describe Alberta’s oil sands. Decades of research and development from all levels of government in Canada, in addition to industry, have transformed the oil sands from a worthless mixture of sand and oil (only good for paving roads), into one of the most sought after commodities on the planet. With remaining established reserves of 167 billion barrels of crude bitumen,1 Alberta’s oil sands are one the largest hydrocarbon deposits in the world, placing third on the world scale after Saudi Arabia and Venezuela.2

The ongoing development of Canada’s oil sands is within the confines of Alberta’s world class and transparent regulatory regimes, of which the Alberta Energy Regulator (AER) (previously known as the Energy Resources Conservation Board or ERCB) plays an integral role. In the last few years the development of the resource was extended into the neighboring province of Saskatchewan. The development of the oil sands in both provinces, no matter how transparent, will be carefully monitored by other governments and environmental activists that are sure to keep the industry on its toes, as they monitor the industry over the development of this extraordinarily valuable Canadian resource. According to the Centre for the Study of Living Standards (CSLS), the value of Canada’s oil sands is almost as great as the value of all of Canada’s residential structures, and three and a half times as valuable as the nation’s stock of machinery and equipment.3

While the resources in Saskatchewan are not fully delineated, the Canadian Energy Research Institute (CERI) is monitoring the ongoing development of Saskatchewan’s oil sands industry, and the associated regulatory requirements. In Alberta, the geological formations and geographical area containing bitumen4 are designated as distinct oil sands areas (OSAs) – the two largest deposits – the Athabasca Wabiskaw-McMurray and the Athabasca Grosmont, as well as the Cold Lake Clearwater and Peace River Bluesky- Gething deposits (illustrated in Figure 2.1). Together these regions cover an area over 142,000 square kilometres (km2). Within the OSAs, there are 15 deposits that cover the

1 Alberta Energy Regulator (AER), “Alberta’s Energy Reserves 2013 and Supply/Demand Outlook 2014-2023”, June 2014. 2In 2011, the Oil and Gas Journal updated reserves number for Venezuelan deposits. The update results from the inclusion of massive reserves of extra-heavy oil in Venezuela’s Orinoco belt, vaulting Venezuela into second place on the world scale of hydrocarbon reserves. 3Centre for the Study of Living Standards (CSLS). “The Valuation of the Alberta Oil Sands”. CSLS Research Report No. 2008-7. November 2008. 4Crude bitumen, or bitumen, is a term that reflects the extra heavy oil within the oil sands areas. The term “oil sands” includes the crude bitumen, minerals, and rocks that are found together with the bitumen (Source ERCB, 2010 ST98).

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specific geological plays containing the oil sands. Approximately 15 percent (25.3 billion barrels) of the 167.1 billion barrels is currently under active development.5

Figure 2.1: Alberta’s Oil Sands Areas

Source: ERCB, “Alberta’s Energy Reserves 2012 and Supply/Demand Outlook 2013-2022”, May 2013.

Mining and in situ production are the two bitumen recovery methods that are currently employed in the oil sands. Of the recoverable bitumen remaining, 80 percent is estimated to be recoverable using in situ methods, which target deposits that are too deep for mining (generally more than 75 meters). In situ extraction includes primary methods, similar to conventional crude oil production, enhanced oil recovery (EOR), and other methods, where steam, water, and/or solvents are injected in the reservoir to reduce viscosity of the bitumen, allowing it to flow. The remaining recoverable bitumen occurs near the surface and is anticipated to be recovered using mining techniques.

It is perceived in Canada, and internationally, that mining of the oil sands represents a substantial portion of the total surface area devoted to bitumen production. This perception is likely based upon the widely publicized images of oil sands mine sites and equipment (illustrated in Figure 2.2). More importantly, but less publicized however, is the fact that in situ production (illustrated in Figure 2.3) does not have the same visual impact, given the smaller footprint on a per project basis.6 The amount of surface area devoted to mining is 374,000 ha (or 2.6 percent of the total surface area), which pales in comparison to the 14,170,000 ha that could be recovered using in situ methods.

5AER, “Alberta’s Energy Reserves 2013 and Supply/Demand Outlook 2014-2023”, June 2014. 6 There is however a trade-off that should be considered: even though in situ thermal project occupies less surface area, it is more GHG-intensive since it consumes more natural gas to create steam.

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Figure 2.2: Mining and Extraction

Source: Suncor Energy Inc.

Figure 2.3: In Situ - SAGD

Source: Suncor Energy Inc. (Firebag project).

The AER continues to estimate and update Alberta’s crude bitumen resources and reserves. Table 2.1 provides a breakdown of the initial volume-in-place, initial established reserves, cumulative production, as well as the remaining established reserves as of December 1, 2013.

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Table 2.1: In-Place Volumes and Established Reserves of Crude Bitumen in Alberta (10^9 barrels)

Recovery Initial Initial Cumulative Remaining Method Volume-in- Established Production Established Place Reserves Reserves Total 1,845 176.8 9.62 167.1 Mining 130.8 38.7 5.85 32.8 In situ 1,712.8 138.0 3.77 134.2 Note: Any discrepancies are due to rounding. Source: AER, “Alberta’s Energy Reserves 2013 and Supply/Demand Outlook 2014-2023”, June 2014.

While the resource base is very large, it is worth noting the quality of the oil sands deposit is not the same throughout. The quality of an oil sands deposit depends mainly on the degree of bitumen saturation within the reservoir and the thickness of the saturated interval. The bitumen saturation level can also vary significantly, depending on the shale or clay content or amount of water within the pore space of the rock.

Oil Sands Development Scenarios The extraction of bitumen from the oil sands is driven by the market forces of supply and demand, with extraction technologies and available take-away pipeline capacity being integral components in ensuring that the oil sands remain competitive with other sources of crude oil. While the global economic recession has concluded, the aftershocks are still being felt either in the financial/economic or social aspects. Although large developed economies have emerged from the recession, the rate at which they are recovering remains inconsistent, given persistent high unemployment in the US, the continued economic crisis in Europe,7 and geopolitical unrest in the Middle East and North Africa. Furthermore, there is uncertainty as to how the speed of their recovery could help, or hinder, the ongoing development of developing nations. While the US share of world oil demand has been decreasing over the last ten years, the BRIC nations of Brazil, Russia,8 India and China have become the primary drivers of incremental non-OECD crude oil demand, as shown in Figure 2.4. In 2012 consumption of crude-derived products of BRIC nations continued to increase and surpassed the consumption of the world’s largest oil consuming nation, the US, which is continuing to consume less largely due to stricter guidelines of the Corporate Average Fuel Economy (CAFE) program and increasing vehicle efficiencies.

7 The European Central Bank lowered its deposit rate to -0.10% as the continent battles deflation after many failed monetary policy attempts. RT News, “ECB cuts deposit rate below zero in historic move”, June 6, 2014. http://rt.com/business/163908-ecb-negative-interest-rate/ Accessed on June 6, 2014. 8Even though Russia and Brazil are energy exporters, their domestic energy consumption has been increasing, just like China and India.

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Figure 2.4: US and BRIC Oil Consumption, Shares of Total Oil Consumption

28% BRIC US 26%

24%

22%

20%

18%

16%

14%

Source: BP Statistical Review of World Energy, June 2013

Going forward, the International Energy Agency (IEA) in their latest energy outlook9 forecasted that under the New Policies Scenario the demand for crude will reach 101.4 million barrels per day (MMBPD) in 2035 – 14 MMBPD higher than in 2012, but the pace of growth slows steadily, from an average increase of 1 MMBPD per year in the period to 2020 to an average of only 400,000 barrels per day (BPD) in subsequent years to 2035. This is mainly due to new efficiency policies and fuel switching in OECD countries, where the decline in oil demand accelerates. In 2035, the OECD share of global oil demand falls to one-third, from just under half today (see Figure 2.5).

Figure 2.5: World Oil Demand by Region (New Policies Scenario), 2012-2035

Source: IEA. “World Energy Outlook”, 2013.

9 IEA. “World Energy Outlook 2013”, 2013.

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This report is based on three plausible scenarios for oil sands development, which will be impacted by two constraints: project startup delays, and capacity curtailments. The methodology used to estimate project delays (i.e., the rate at which production comes on stream and the project’s ability to move through the regulatory and internal corporate approval processes) is based upon CERI’s past experience from monitoring the timelines and progress of various oil sands projects. The overall forecasts from three scenarios were then verified against historical trends.

The scenarios are representative of possible paths for future oil sands development taking into account the economic recovery (and demand for oil), emissions legislation, and lastly the impact that the emerging economies could have on the demand growth for crude. The scope of this study precludes a detailed assessment of long-term energy supply/demand and crude price scenarios. The projection period for this analysis extends from 2014 to 2048, spanning 35 years with 2014 being the first year of the forecast. The first scenario is CERI’s Reference Case Scenario, which assumes that the OECD nations have emerged from the recession and continue to recover, experiencing modest economic growth in 2014, bringing about a slow and steady growth in the demand for crude oil. The growth is tempered somewhat by geopolitical concerns in the Middle East and economic setbacks in some European nations. In this scenario, oil prices are in a favourable range for oil sands proponents to develop their projects and meet the demand for crude oil, which is assumed to be returning to its pre-recession growth rate, and a period of ongoing growth for the foreseeable future ensues.

The growth will be tempered, albeit modestly, by an ongoing push toward environmental protection, through modest emissions compliance costs. These costs are designed to stimulate the development and use of new oil sands technologies, and are not intended to “shut down” the industry.

It is assumed that the emissions costs will be driven not by a global market, but by a North American emissions policy that harmonizes compliance costs and seeks to reduce emissions, while not being overly onerous to the public and industry. Under the current provincial regulation, industrial facilities that emit more than 100,000 tonnes of carbon a year are required to reduce their "carbon intensity" – emissions per unit of production – by 12 percent per year or buy offset credits or pay a carbon tax levy. The $15/tonne of CO2 levy applies only to carbon that exceeds what the facility would have emitted if it had met the intensity target. The emissions compliance costs are implemented over the next 35 years, starting at $15/tonne of CO2 equivalent as set by the Alberta government in 2007, and rise at 2.5 percent each year after that. While this might not satisfy environmental activists, the modest emissions compliance costs act as a stimulant for

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technology development, as oil sands companies seek to differentiate themselves from the competition by producing a “greener” barrel.10

On the international scene Canada has committed under the Copenhagen Accord of 2009 to decrease emissions to 17 percent below 2005 levels by the year 2020. By 2020, oil sands emissions are projected to nearly double to 101 Mt, and total share of the oil sands sector to Canadian emissions are projected to increase from 4.6 percent in 2005 to 13.8 percent in 2020. Environment Canada currently estimates that emissions in 2020 will only be 0.4 percent below 2005 levels (not 17 percent below), compared to 9.5 percent below 2005 in the absence of GHG emissions growth in the oil sands sector. Increasing production in this sector makes the meeting of international commitments increasingly difficult, and thus there is interest in reducing the amount of GHG emitted to extract bitumen from the oil sands and generate synthetic crude oil. The application of new technologies is driven by economics, and no subsidies are provided. Carbon capture equipment is installed on some facilities for the purposes of storing carbon and supporting enhanced oil recovery.

The next two scenarios provide alternative views of how the global and North American economies could develop over the next 35 years. The Low Case Scenario represents a world in which the economic recovery is stalled in 2014-2015, and demand for crude oil and its products is stagnant. In addition, environmental policy becomes a priority for policy makers. Canada’s commitment to Copenhagen Accord is well on its way to being met. In this scenario, the trade flow of oil sands derived crude is limited due to stricter product restrictions across a wide variety of industries. These policies do not initially drive up oil prices, but instead raise the cost of living in developed economies, and negatively impact imports from the BRIC nations. This scenario results in minimal economic growth.

With high compliance costs and limited economic growth, oil sands development becomes stagnant over the next decade. Eventually, protectionist policies are relaxed, which helps spur a period of economic growth and, in turn, brings forth resumption in oil sands developments. The high compliance costs remain which drive the overall costs for oil sands producers up and might hinder the rate at which the oil sands projects come on stream.

The last scenario is the High Case Scenario. Under this scenario, the world’s economies, both developed and emerging, compete for hydrocarbon resources. The BRIC nations expand exports of products, which drives up their energy demand, notably crude oil.

10The Alberta Government enacted their climate change plan in 2007, as detailed in Bill 3, “Climate Change and Emissions Management Amendment Act, 2007”. This plan involves taxing large final emitters a sum of fifteen dollars per tonne of carbon dioxide equivalent emissions. A 2008 amendment to the Act outlines the potential investment areas for the tax, or compliance cost, revenues. Information on the Act and all amendments to it can be found by visiting Alberta Environment’s website, http://www.environment.alberta.ca/

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The major demand centers for the BRIC nations’ exports, the US and other developed countries, also experience a period of rapid economic growth and rising crude oil demand.

While environmental policies encourage the development of “green technologies”, those policies do not offset an increase in demand for crude oil from the emerging economies. Faced with rising oil prices and a surge in demand, the BRIC and other developed nations seek to secure access to physical supplies of oil. For instance, the US, the world’s largest consumer of crude oil, aggressively seeks to secure reliable sources of oil, and provides expedited approvals for pipeline expansions from Canada. While US demand for refined products does not increase, refineries are slowly converted to process heavy oil, and those refineries that previously accepted heavy oil, i.e., Venezuelan heavy oil or Mexican Maya, turn to Canadian oil sands. Venezuela’s or Mexico’s oil production is not curtailed, but instead displaced from the US Gulf of Mexico market. It is assumed that BRIC nations, notably China, absorb the displaced oil. Similarly, other heavy oils are displaced to other parts of the world.

Environmental policies and the development of “green” oil sands extraction technologies are not the primary concerns in this scenario. Environmental opposition to oil sands development continues, but environmental concerns are offset by concerns over energy security. This is not to say that environmental policies take a back seat. Moderate emissions compliance costs are introduced in North America, and new technologies are developed to reduce the environmental footprint of oil sands operations. The application of new technologies is driven by economics, and no subsidies are required. Carbon capture equipment is installed on some facilities for the primary purpose of supporting enhanced oil recovery rather than to reduce emissions.

Each of the three scenarios is important in understanding some of the drivers of oil sands developments. What will ultimately drive the development of the oil sands are the long-run global oil prices (driven by global supply and demand fundamentals), and development and operating costs (including emissions compliance costs).

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Chapter 3 Oil Sands Supply Costs

Introduction Sheer determination by pioneer oil sands developers and dedicated research and development (R&D) have stimulated the employment of innovative technologies to recover crude bitumen from Alberta’s vast oil sands resources. The result is a dynamic and commercially viable industry that effectively competes on the world scale with conventional and other energy sources. Continuing efforts at reducing costs through technological improvements and other operational measures, while remaining conscious of the environment, should ensure a robust future.

The extraction of Alberta’s oil sands is currently based upon 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 extraction1 could be either a standalone mine or integrated with an upgrader. Within in situ and mining methods, various technologies to extract valuable bitumen from the oil sands are utilized.2 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. The end result will be an oil sands industry that is better equipped to withstand adverse changes of market forces.

This chapter discusses CERI’s supply cost methodology and assumptions and presents supply cost results.

Methodology and Assumptions Supply cost, sometimes referred to as breakeven price, is the constant dollar price needed to recover all capital expenditures, operating costs, royalties, taxes, and earn a realistic return on investment. For this study, supply costs are calculated in constant 2013 dollars. CERI has used imperial units of measurement for production volumes and reserves. Oil supply costs and prices are stated in imperial units, either Canadian dollars per barrel (C$/bbl) or US dollars per barrel (US$/bbl).

CERI’s model solves for a breakeven oil price – that is, the oil price that gives a net present value (NPV) of zero – with a real discount rate of 10 percent. The model also has

1Within 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. 2The reader is assumed to have some familiarity with each extraction method. Detailed descriptions of the extraction technologies are available from CERI Studies 122 and 126.

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flexibility to vary inputs, thus allowing for estimation of the supply cost by extraction method required to bring forth new oil sands projects.

Supply costs have been calculated for the raw bitumen produced (at either an in situ or a mining and extraction operation) and, where appropriate, for the upgraded product at the source field location. To place these values in a market context, supply costs have been calculated in terms of equivalent prices for marketable crude oil (e.g., blended bitumen or SCO) at key Alberta market centers (i.e., Hardisty and Edmonton), and in terms of the corresponding equivalent market price of West Texas Intermediate (WTI) crude oil at Cushing, Oklahoma. This required that CERI make a number of assumptions about market pricing relationships – described later in this chapter.

Although each project is different in its geographical location, quality of reserves and financial structure, this analysis that relies heavily on capital and operating cost estimates is prepared for a more generic project. The generic project specification is based on production method. Here, CERI evaluates a typical steam-assisted gravity drainage (SAGD) project, a mining project, and a mine integrated with an upgrader. While there are no announcements to build standalone commercial upgraders, this year we have included the analysis of a standalone upgrader and its supply cost for illustrative purposes. While significant production comes from cyclic steam stimulation (CSS) projects, few new CSS projects have been announced; hence the supply cost analysis does not extend to a CSS project. The majority of new proposed and announced in situ projects will use SAGD technology and/or a variation of it.

Design Assumptions The Canadian oil sands industry is facing several cost-related issues that have affected the economic viability of some oil sands projects. Capital and operating costs play the most important role in determining the supply costs. In view of the cost pressures being faced by the industry, CERI decided it was necessary to update its existing cost assumptions. The assumptions that underpin each production method are presented in Table 3.1. The data for capital and operating costs is collected from CanOils database, as well as public sources, such as company annual reports, investor presentations, company announcements, etc., and is averaged across projects according to extraction method. These costs reflect today’s economy and are representative of costs for typical greenfield investment; they do not reflect opportunities for reduced supply costs that are available to industry. CERI identified some of these opportunities as:

 Expansion of existing projects may bring synergy through shared use of infrastructure and other facilities and economies of scale (e.g., Cenovus and ConocoPhillips);  The industry has been investigating the reasons for the large capital cost overruns and is already taking measures to reduce costs. An example of how companies plan on keeping the costs from escalating is CNRL’s expansion of the

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Horizon Oil Sands Project. The project has been broken into five separate phases to avoid the “mega-project” approach to development and to break the overall expansion into smaller, more manageable pieces that will lead to enhanced project and cost control. Current expansion and debottlenecking will be deliberate and flexible to ensure projects can be started or stopped based on market conditions.  Supply costs for SAGD producers (presented in this report) are based on operations in average quality reservoirs; many projects are operating and will be developed in higher quality deposits, such as Cenovus’ Christina Lake or Foster Creek SAGD projects, where they are known for the lowest capital and operating costs.  Thermal and integrated mining, extraction and upgrading projects have been devoting considerable effort (and have made considerable progress) towards reducing operating costs.  While the supply costs are based on a 10 percent (real) internal rate of return (IRR), they will be lower if oil sands producers are prepared to accept lower IRRs for long-term projects.

The project design parameters are typical of the industry’s projects that are being built today; a production flow rate of 30,000 BPD is assumed for a SAGD project and a rate of 100,000 BPD for a mine. The energy requirements have been estimated according to the design parameters and reflect today’s use of natural gas and electricity feedstock. The natural gas requirement for a SAGD plant increased from last year’s reporting from 32,100 GJ/d to 35,910 GJ/d (~2.8 steam to oil ratio or SOR) to reflect recent history – currently, SOR among SAGD operators varies between 1.5 to 7 barrels of steam per barrel of bitumen, with a bulk of projects operating in the SOR range of 2.5-3 bbl/bbl. All the other parameters remain the same as in last year’s report.

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Table 3.1: Design Assumptions by Extraction Method

Integrated Mining and Extraction Mining and and Stand Alone Measurement Units SAGD Extraction Upgrading Upgrading Project Design Parameters Stream day capacity bbl of bitumen per day 30,000 100,000 115,000 100,000 Production Life years 30 30 30 30 Average Capacity Factor (over production life) percent 75.00% 89.00% 89.00% 89.00% Capital Expenditures Initial Millions of dollars 1,050 8,276 16,417 6,000.0 Initial Dollars per bbl of capacity 34,987 82,760 142,760 60,000 Sustaining (Annual Average) Millions of dollars 27.4 109.5 210 73.0 Operating Working Capital Days payment 45 45 45 45 Operating Costs

Non-energy total (Annual Average) Millions of dollars 100 639 876 237.0 Non-energy total Dollars per bbl 9.1 17.5 24 6.5 Energy Requirements Natural Gas Royalty Applicable GJ per day 35,910 54,000 62,100 Non-Royalty Applicable GJ per day 20,871 81,436 Electricity Purchased Royalty Applicable MWh/d 300 0 1,128 Non-Royalty Applicable MWh/d 448 Electricity Sold MWh/d 0 728 0 0 Other Project Assumptions Abandonment and Reclamation percent of total capital 2% 2% 2% 2% Source: CanOils, CERI

With oil prices determined in the context of the global market, capital costs are one of only a few parameters operators directly control that have an impact on project economics. Historically, oil sands projects have experienced significant inflationary pressures as projects progressed towards completion. Labour shortages, material scarcity, administrative and engineering delays all have contributed to cost overruns. Capital costs increased which ultimately eroded returns for producers. Operators have learned from the most recent boom and are intently focused on controlling cost inflation; however, if oil prices strengthen further, CERI expects the pace of development to increase in response.

Adjusting the capital cost estimates from 2011 dollars to 2013 dollars, the real initial capital costs have increased across all projects on average (see Figure 3.1).

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Figure 3.1: Average Initial Capital Cost (Real % Change, 2011-2013) U 12%

10%

8%

6% 10.5% 4% 7.9% 6.1% 5.1% 2%

0% SAGD Mining and Integrated Stand Alone Extraction Mining and Upgrading Upgrading

Source: CanOils, CERI

Upgrading projects have experienced the highest increase of over 10 percent to C$60,000/bbl of capacity or C$6 billion for a 100,000 BPD upgrader, which is consistent with the most recent estimates for a proposed, since then suspended, Voyager upgrader and the Northwest Upgrader, which is currently under construction. SAGD producers experienced a 5.1 percent increase in capital costs followed by a standalone mine – 6.1 percent, and 7.9 percent for an integrated project. The sustaining capital costs have been adjusted downward to reflect the fact that these are greenfield projects that might exhibit lower sustaining capital requirements and are consistent with the industry estimates: sustaining capital costs are - $2.5/bbl per day of capacity for a SAGD project, $3.0/bbl per day of capacity for a standalone mine and $5/bbl per day of capacity for an integrated mining and upgrading project.

The average non-energy operating costs have increased noticeably for integrated mine projects (+6.4 percent) and upgraders (+21.8 percent) (see Figure 3.2). The increases are an indication that these projects are more labour and material-intensive as compared to an in situ type project – one of the reasons why there are no new integrated projects or upgraders being built.3 Costs have seen the greatest escalation in recent years due to ongoing labour shortages and increasing wages, global materials and equipment scarcity and increasing transportation related costs. Perhaps surprising for some, the non- energy operating costs for SAGD producers have declined by 7.5 percent on average. Albeit SAGD producers face similar industry-wide hurdles such as skilled labour shortages or transportation costs, the projects are less labour intensive, smaller in scale,

3 With the exception of Northwest Upgrader, but this is a special project in partnership with Alberta government’s BRIK program.

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compact with smaller land footprint and less to maintain. The efficiency gains through these and other avenues, such as shared use of infrastructure and other facilities and economies of scale have all contributed to the decline.

Figure 3.2: Average Non-Energy Operating Costs (Real % Change, 2011-2013) U

25%

20%

15%

10% 21.8%

5% 1.7% 6.4% 0%

-5% -7.5%

-10% SAGD Mining and Integrated Stand Alone Extraction Mining and Upgrading Upgrading Source: CanOils, CERI.

Even though the non-energy costs did not increase for a SAGD project, this is not to say that the overall total operating cost did not. The other portion that makes up the total operating cost is the energy-related portion. Oil sands projects are very energy- intensive, consuming large quantities of natural gas, electricity, and chemicals, which are purchased on the market and hence energy-related operating costs are very dependent on the prices of natural gas, electricity and others used as energy feedstock. To approximate energy related costs, natural gas and electricity prices are used.

While research continues on finding ways to use less natural gas, it is still the primary fuel source for the oil sands industry. Hence, the cost of gas is important and has become a significant component of the total supply cost framework. To approximate the cost of natural gas, a forecast of Henry Hub natural gas prices was obtained from the US EIA’s Annual Energy Outlook (AEO) 2014 for the period 2011 to 2040. Prices were then transformed to 2013 dollars and to extend the forecast to 2048, nominal prices from 2041 to 2048 were set to grow at an inflation rate of 2.5 percent, as seen in Figure 3.3. The Henry Hub prices were then converted to AECO-C basis gas prices to better reflect the actual cost paid by producers for natural gas. CERI used an AECO- C/Henry Hub differential of US$1.25/MMbtu, and a field premium of C$0.27/GJ.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 21

Figure 3.3: Henry Hub Natural Gas Price Forecast

$/MMBtu $16

$14 HH price (nominal C$/MMbtu) $12 HH price(real 2013 C$/MMbtu) $10

$8

$6

$4

$2

$0

2025 2041 2007 2009 2011 2013 2015 2017 2019 2021 2023 2027 2029 2031 2033 2035 2037 2039 2043 2045

Source: EIA, CERI

The price of natural gas has dropped by 74 percent from its previous level of C$10.70/MMBTU in 2008, to C$2.82/MMBTU in 2012, reflecting higher natural gas supply, which rose significantly as a result of development of shale gas deposits, especially in the eastern US states. New technologies and horizontal fracturing of shale rock (or “fracking” as it is called) has opened up enormous new gas deposits in North America. The prices recovered somewhat in 2013, rising to C$3.77/MMBTU on an annual basis, a 34 percent increase year over year, which contributed to an year-on-year increase in energy related operating costs for oil sands producers. The prices will remain flat (in real terms) until 2015 and then gradually start to increase, breaking the C$4/MMBTU mark by 2016 and surpassing the $6/MMBTU mark later in the forecast period by 2035, but never reaching the levels seen during the 2007-2008 period.

Another significant input to oil sands operations is electricity. It has been assumed that on-site cogeneration is in place for mining and upgrading projects. Any excess electricity is sold into the Alberta system. Over the next decade, it is anticipated that most in situ projects will move towards cogeneration, with units sized to match a projects’ steam and electricity load. In other words, most new in situ projects are not likely to produce excess amounts of electricity. However, for the purposes of calculating supply costs, in situ projects are assumed to purchase electricity from the Alberta grid.

Electricity prices will play a key role in determining the cost of electricity as feedstock to oil sands projects. To approximate the cost of electricity, a forecast of Alberta end-use electricity prices for the industrial sector were sourced from the NEB’s Energy Futures

July 2014 22 Canadian Energy Research Institute

report, released in November 2013 for the period of 2007 to 2035. Prices were then transformed to 2013 dollars and to extend the forecast to 2048, nominal prices from 2036 to 2048 were set to grow at an inflation rate of 2.5 percent, as seen in Figure 3.4. In the near term prices are forecast to decline by 4 percent per year on average until 2020, when the prices drop to C$90.25/MWh from C$118.01/MWh in 2013. Prices recover and average around C$97/MWh until 2030, at which point prices decline and stabilize around C$80/MWh.

Figure 3.4: Alberta End-use Industrial Electricity Price Forecast

$/MWh $200 $180 $160 $140 $120 $100 $80 $60 Industrial Elec. Price (real 2013 C$/MWh) $40 Industrial Elec. Price (nominal C$/MWh) $20

$0

2009 2023 2007 2011 2013 2015 2017 2019 2021 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045

Source: NEB, CERI

Light-Heavy Differential To place the oil sands supply costs of a barrel of bitumen in a market context, they have been calculated in terms of equivalent prices for marketable crude oil (e.g., blended bitumen or SCO) at key Alberta market centers (i.e., Hardisty and Edmonton), and in terms of the corresponding equivalent market price of WTI crude oil at Cushing, Oklahoma. This required CERI to make a number of assumptions about market pricing relationships. Of particular importance is the light-heavy differential, specifically the differential between light WTI barrel and heavy WCS.

All crude oil is not valued equally. Light oil that is low in sulphur content (i.e., sweet) is more valuable to refiners than heavy oil with higher sulphur content (i.e., sour), because it is less energy intensive to refine light sweet crude, and the resulting petroleum products are of higher quality. Thus, refining heavy sour grades requires more complex refining operations. The market value of each crude stream therefore reflects the crude characteristics as well as the refined products yield from such crude. The price

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 23

difference between a barrel of light sweet oil and a barrel of heavy sour oil represents the light-heavy or quality price differential.

Two of the most important physical crude qualities are density (as measured by API gravity) and sulfur content. Figure 3.5 illustrates those characteristics for various crudes from around the world (including various pricing benchmarks) and places Canadian crudes in the context of crude oil quality. It becomes very clear that bitumen derived crudes measure high in sulfur content and low on gravity as compared to some other crudes.

Figure 3.5: Densities and Sulfur Content of Crude Oils

5.50%

5.00% Peace River Heavy

4.50%

4.00% Wabasca Heavy

Cold Lake Blend > Sour) > - 3.50% Western Candian Select Mexico - Maya

3.00% Iraq - Basra Light Heavy Vs. Light

Kuwait - Kuwait Sweet Vs. Sour 2.50% Monterey Venezuela -Merey Venezuela - BCF-17 Albian Hvy. Syn. UAE - Dubai Canadian Crudes 2.00% Ecuador - Napo Mars Colombia - Castilla Blend West Texas Sour US Crudes Saudi Arabia - Arab Light SulfurContent wt.% (Sweet 1.50% Colombia - Rubiales Kern River Brazil - Polvo 1.00% Alaska North Slope Forties Blend Brazil - Marlim Hibernia Blend 0.50% Syncrude Synthertic Brent Condensate Blend Sumatra - Duri West Texas Intermediate Suncor Synthetic A Nigeria - Bonny Light Malaysia - Tapis Algerian Condensate 0.00% 0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 API Gravity (Heavy -> Light) Source: BP, EIA, Genesis Capital, Oil & Gas Journal, Pemex, Statoil

Almost all of Canadian oil production is transported to refineries in Canada and the US with the largest share originating in Alberta. The two main distribution hubs in Alberta are located near Edmonton and Hardisty – the price point for WCS as a crude benchmark. Launched in 2004 by Encana Corporation (now Cenovus Energy), Canadian Natural Resources Limited, Talisman, and Petro-Canada (now Suncor), the WCS is a blend of conventional Western Canadian heavy oil and crude bitumen that has been blended with sweet SCO and diluents.4 Table 3.2 compares the characteristics of the

4 While WCS or dilbit is a blend of bitumen, conventional, and synthetic crudes, its main crude quality parameters (both API gravity and sulfur content) are very similar to those of other western Canadian conventional heavy sour blends such as Lloyd Blend, Bow River, and other heavy sour conventional blends produced in Alberta and Saskatchewan. Cold Lake Blend is another dilbit blend that trades in large volumes. Other dilbits include Access Western Blend, Borealis Heavy Blend, Christina Dilbit Blend, Peace River Heavy, Seal Heavy, Statoil Cheecham Blend, and Wabasca Heavy (see: http://crudemonitor.ca/home.php)

July 2014 24 Canadian Energy Research Institute

WCS blend with two other heavy crude oils.5 Currently, WCS prices are closely linked to WTI because the majority of WCS crude is shipped to the US Midwest market, for which the historical benchmark has been WTI. WCS crude is sold at a discount to WTI because it is a lower quality crude, producing a positive light-heavy differential.

Table 3.2: Crude Oil Characteristics

WCS Target Maya Mars

Gravity (API0) 19-22 21.8 30.4 Carbon Residue (Wt %) 7.0-9.0 13 5.5 Sulphur (Wt %) 2.8-3.2 3.5 1.9 TANa (mo KOH/g) 0.7-1.0 0.3 0.68 aTAN – Total Acid Number, measured in mg of potassium hydroxide needed to neutralize one gram of oil. Source: Paterson, Shaun, “Restructuring the Canadian Heavy Oil Markets: The Case for a Large Heavy Oil Stream”, EnCana Corporation presentation to the Canadian Heavy Oil Association, February 3, 2005, http://www.choa.ab.ca/ documents/Feb0305.pdf. Accessed on January 11, 2011.

As the US tight oil production rose, flooding the US with extra crude supply and squeezing the outflow pipeline capacity in the Cushing, Oklahoma hub, the price for WTI at the hub, which had historically run in close parity with North Sea Brent, became depressed and started to disconnect from the global benchmark. Discounts deepened, affecting essentially all inland lower-48 crude grades, as well as WCS (since it is priced off WTI). Since January 2011, these discounts have been steep and have been considered ‘structural’ as seen in Figure 3.6.6 Since the reversal of Seaway pipeline and construction of the southern leg of the Keystone XL in 2013 to connect Cushing to the Gulf of Mexico, the WTI prices have increased, narrowing the differential between Brent and WTI, but not near its historical norm of US$2-5/bbl, potentially indicating two things: either the two markets are no longer correlated and prices are representative of regional markets only or the market to market connectivity is not sufficient to increase WTI prices to Brent levels (sans transportation costs) or a combination of both.

Besides the lack of appropriate pipeline capacity between the US markets, the problem is further exacerbated by the lack of much needed export pipeline capacity from Western Canada to the US, thus depressing WCS prices against WTI and other crudes, like Mexican Maya. Maya is considered close in quality to WCS, yet Maya is waterborne crude with readily available access to the US Gulf Coast (USGC) refiners and represents the potential price/market WCS producers could realize/access. Historically, WCS has

5Paterson, Shaun, “Restructuring the Canadian Heavy Oil Markets: The Case for a Large Heavy Oil Stream”, EnCana Corporation presentation to the Canadian Heavy Oil Association, February 3, 2005, http://www.choa.ab.ca/ documents/Feb0305.pdf. Accessed on January 11, 2011. 6 Another example is WTI versus Light Louisiana Sweet (LLS), a coastal crude, which prior to 2011 traded at $1/bbl discount to WTI but has recently traded at $24/bbl premium to WTI.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 25

tended to trade at a discount to Maya,7 averaging an annual discount of US$6.50/bbl between 2005 and 2010, but more recently the differential started to widen and reached as much as US$48/bbl as recently as February 2013.

Since the launch of WCS, the price has been tracking the movements of WTI fairly closely with periodic fluctuations. In turn, the differential between WTI and WCS has fluctuated from a low of just under US$6/bbl in April 2009 to a high of US$37/bbl in February 2013, with average and median differentials at about US$18/bbl.

The data series for WCS prices comes from the Baytex Energy website,8 SCO prices are sourced from Canadian Oil Sands’ website,9 while Brent, WTI and Maya prices are sourced from the US EIA from January 2005 to April 2014. Figure 3.6 illustrates the selected historical benchmark price series (top graph) and differentials between various crudes (bottom graph).

While the WTI-WCS differential has been much discussed and pondered upon by media, industry and government, empirical evidence shows that the differential fluctuates over time, that is, it narrows and widens based on market conditions. While this fluctuation is hard to estimate in the long-term, the data supports an assumption of a long-term average WTI-WCS differential of US$18/bbl, which is US$3/bbl higher than the differential used in last year’s report. Therefore, based on the historical data, the light- heavy differential (not including transportation costs) is assumed to be constant at US$18.00/bbl. Over time as more blended bitumen and SCO continue to penetrate the existing markets as well as new markets, such as the US Gulf Coast and markets outside of North America, the light heavy differential might narrow in the future.

7 Maya has in turn historically traded at a US$7-9/bbl discount to WTI reflecting mainly quality differences. On the other hand Maya has historically traded at a $10/bbl discount to LLS, which further reflects the light-heavy differential in the coastal area (more reflective of a global light-heavy differential) 8 http://www.baytexenergy.com/operations/marketing/benchmark-heavy-oil-prices.cfm 9 http://www.cdnoilsands.com/energy-marketing/Pricing/default.aspx

July 2014 26 Canadian Energy Research Institute

Figure 3.6: Light-Heavy Differentials (US$/bbl)

Brent UK 38 API $140.00 WTI Cushing Oklahoma SCO at Edmonton 32 API $120.00 Mexican Maya (FOB) 21.5 API WCS Hardisty 20.5 API $100.00

$80.00 $US/bbl $60.00

$40.00

$20.00

$-

Jul-07 Jul-05 Jul-06 Jul-08 Jul-09 Jul-10 Jul-11 Jul-12 Jul-13

Jan-06 Jan-05 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14

Oct-05 Oct-06 Oct-07 Oct-08 Oct-09 Oct-10 Oct-11 Oct-12 Oct-13

Apr-05 Apr-06 Apr-07 Apr-08 Apr-09 Apr-10 Apr-11 Apr-12 Apr-13 Apr-14

$60.00

Brent-WTI WTI - WCS WCS - Maya $50.00

$40.00

$30.00

$US/bbl $20.00

$10.00

$-

$(10.00)

Jul-07 Jul-05 Jul-06 Jul-08 Jul-09 Jul-10 Jul-11 Jul-12 Jul-13

Jan-06 Jan-05 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14

Oct-05 Oct-06 Oct-07 Oct-08 Oct-09 Oct-10 Oct-11 Oct-12 Oct-13

Apr-06 Apr-07 Apr-08 Apr-09 Apr-10 Apr-11 Apr-12 Apr-13 Apr-14 Apr-05 Source: EIA, Baytex Energy, Canadian Oil Sands, CERI

Crude Oil Transportation Costs The supply cost is calculated for raw crude bitumen produced in the field. This bitumen supply cost is converted to prices of marketable blended bitumen at key Alberta market centers (Edmonton and Hardisty), and to an equivalent market price of WTI crude oil at Cushing, Oklahoma. For non-integrated projects, blending costs are estimated through accounting for the volume of diluent required per barrel to bring the bitumen blend to a density that meets pipeline specifications, the cost of diluent, and the cost of transporting diluent to the field. Based upon industry data, a 5 percent premium has been applied to the cost of diluent. Transporting the blend from the field to Cushing, Oklahoma is assumed to be C$1.01 per barrel from the field to Hardisty and US$3.50 per barrel from Hardisty to Cushing. Per barrel transportation costs from the field to Hardisty, and Edmonton to Cushing, Oklahoma, are assumed to rise at an annual inflation rate of 2.5 percent.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 27

Economic and Taxation Assumptions The supply cost estimates presented in this study have been calculated using cash flow models similar to those used by industry and governments. The costs have been calculated using an annual discount rate of 10 percent (real). This is equivalent to an annual return on investment of 12.5 percent (nominal) based on the assumed average inflation rate of 2.5 percent per annum. Companies may evaluate individual investments using higher discount rates; these would translate to higher supply costs than those presented here.

Within the supply cost model, federal and provincial corporate income taxes have been assumed constant at 15 percent10 and 10 percent, respectively.

Currently most machinery, equipment and structures used to produce income from an oil sands project, including buildings and community infrastructure related to worker accommodations, are eligible for a capital cost allowance (CCA) rate of 25 percent under the Class 41 of Schedule II to the Income Tax Regulations.11 In addition to the regular CCA deduction, an accelerated CCA has been provided since 1972 for assets acquired for use in new mines, including oil sands mines, as well as assets acquired for major mine expansions (i.e., those that increase the capacity of a mine by at least 25 percent). In 1996, this accelerated CCA was extended to in situ oil sands projects. This change ensured that both types of oil sands projects are accorded the same CCA treatment.

The accelerated CCA takes the form of an additional allowance that supplements the regular CCA claim. Once an asset is available for use, the taxpayer is entitled to deduct CCA at the regular rate. The additional allowance allows the taxpayer to deduct up to 100 percent of the remaining cost of the eligible assets, not exceeding the taxpayer's income for the year (calculated after deducting the regular CCA). This accelerated CCA provides a financial benefit by effectively deferring taxation until the cost of capital assets has been recovered from project earnings.

This incentive helped to offset some of the risk associated with early investments in the oil sands and contributed to the development of this strategic resource. Over time, however, technological developments and changing economic conditions have led to major investments that have moved the sector to a point where the majority of Canada's oil production will soon come from oil sands. As a result, this preferential treatment is no longer required. Budget 2007 phased out the accelerated CCA for oil sands projects – both mining and in situ.12 The regular 25 percent CCA rate will remain

10 Effective January 1, 2012, the federal rate dropped to 15 percent from 16.5 percent. 11 Property acquired by a taxpayer for the purpose of gaining or producing income from a bituminous sands project in Canada will generally be included in Class 41. http://www.cra-arc.gc.ca/E/pub/tp/it476r/it476r- e.html#Bituminoussandsprojects. Accessed on February 28, 2012. 12 To the extent that the accelerated CCA for oil sands projects induces incremental oil sands development that could contribute to environmental impacts, such as greenhouse gas emissions, air and water contaminants, water usage, and disturbance of natural habitats and wildlife, these changes could help reduce such incremental impacts.

July 2014 28 Canadian Energy Research Institute

in place. To provide stability, and in recognition of the long lead time involved in some oil sands projects, the following transitional relief will be provided:

 the accelerated CCA will continue to be available in full for: - assets acquired before March 19, 2007, and - assets acquired before 2012 that are part of a project phase on which major construction began before March 19, 2007  for other assets, the additional accelerated allowance will be gradually phased down over the period from 2011 to 2015 (when it will be eliminated), according to the schedule set out below.

The percentage allowed will decline each calendar year, as shown in Table 3.3 (prorated for off-calendar taxation years).

Table 3.3: Phase-Out Schedule

Year Allowable % of Additional Allowance 2010 100 2011 90 2012 80 2013 60 2014 30 2015 0

Source: Budget Plan 2007, Annex 5.

For the purposes of this report, it is assumed that the transitional relief is not applicable for the supply cost calculation of our greenfield projects and hence the phase out schedule is applied as set in Table 3.3.

Oil sands operations are assumed to commence construction on January 1, 2013, and begin operating on January 1, 2015. The projects will continue to operate until end of year 2045, based on a 30-year project life.

Alberta has one of the few fully functioning compliance carbon markets in North America. On July 1, 2007 the Alberta Government enacted their climate change plan, as detailed in Bill 3, “Climate Change and Emissions Management Amendment Act, 2007”. Facilities with emissions greater than 100,000 tonnes of CO2e per year are regulated to reduce emissions by 12 percent in carbon intensity per production unit. To help meet this 12 percent reduction target, the Alberta regulation allows a facility to comply in four ways:

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 29

1. Make facility changes to improve performance and lower emissions 2. Purchase Alberta-based carbon offsets 3. Pay $15-a-tonne into the Climate Change and Emissions Management Fund 4. Purchase/use emission performance credits generated in previous years or at other facilities.

While the province has yet to deploy a trading mechanism/market for carbon, CERI’s model incorporates this $15.00/tonne tax for emissions over the 100,000 limit, increasing at an annual average inflation rate of 2.5 percent.13 The resulting impact on the overall cost of an oil sands project is minimal; however, as the market develops, the carbon tax/price will rise, and the resulting impact will increase over time. It is assumed that compliance costs are royalty deductible, as is currently the case. When compliance costs are royalty deductible, collected by the province, and spent entirely within the province, a transfer of wealth outside of Alberta does not take place. Under a harmonized system, emission compliance costs would be collected by the federal government, and represent a wealth transfer from Alberta to Ottawa.

Royalty Assumptions The Alberta oil sands royalty regime is based on the net revenue system whereby the oil sands producer pays a lower royalty rate based on gross revenues until the point at which the producer has recovered all the allowed project costs (those incurred up to three, and in some cases up to five, years prior to the approved effective date) plus a return allowance based on current Long Term Government Bond Rates (LTBR) issued by the Government of Canada (floor risk).14 After payout has been achieved, the project proponent pays the higher of gross revenue royalties based on a gross revenue royalty rate or net revenue royalties based on a higher net revenue royalty rate. Prior to 2009, the rates were fixed at 1 percent of gross revenues (pre-payout) and 25 percent of net revenues (post-payout). After 2009, royalty rates are calculated based on the Canadian dollar price of a barrel of WTI and are fixed at a floor of 1 percent (gross) and 25 percent (net) when the price is below $55/bbl, increasing linearly to a ceiling of 9 percent (gross) and 40 percent (net) when the price of WTI is above $120/bbl as seen in Figure 3.7.

The gross revenue of the project is defined as the revenue collected from the sale of oil sands products (or the equivalent fair market value) less the costs of any diluents contained in any blended bitumen sold. Allowed costs are those incurred by the project operator to carry out operations, and to recover, obtain, process, transport, or market oil sands products recovered, as well as the costs of compliance with environmental

13 CERI assumes that the reduction in carbon intensity and/or purchase of carbon offset credits more or less equates to carbon tax. 14 Assumed to be 5.5 percent.

July 2014 30 Canadian Energy Research Institute

regulations and with termination of a project, abandonment and reclamation of a project site.15

Figure 3.7: Alberta Bitumen Royalty Rates

45.00% 9.50% 44.00% 9.00% 43.00% 42.00% 8.50% 41.00% 8.00% 40.00% 7.50% 39.00% 38.00% 7.00% 37.00% 6.50% 36.00% 6.00% 35.00% 5.50% 34.00% 33.00% 5.00% 32.00% 4.50% 31.00% 4.00% 30.00%

29.00% 3.50% Net RevenueRoyalty Rate 28.00% 3.00% Gross Revenue Royalty Rate 27.00% 2.50% 26.00% Pre-Payout Gross Revenue Royalty Rate (%) 25.00% 2.00% Post-Payout Net Revenue Royalty Rate (%) 24.00% 1.50% 23.00% 1.00% 22.00% 21.00% 0.50%

20.00% 0.00%

0

13 26 39 52 65 78 91

104 117 130 143 156 169 182 195 208 221 234 247 260 273 286 299

C$/b of WTI Source: CERI

To better understand this year’s supply cost results, an oil price projection was required in order to accurately estimate the royalties. The forecast of the WTI price was obtained from the EIA’s AEO 2014, for the period 2011 to 2040. Prices were then transformed to 2013 dollars and, to extend the forecast to 2048, nominal prices from 2041 to 2048 were set to grow at an inflation rate of 2.5 percent, as seen in Figure 3.8. The WTI forecast was lowered from last year’s edition of the EIA’s AEO. The forecast shows the oil prices (in 2013 dollars) will go through a minor dip in the next decade, averaging US$95/bbl, followed by a modest recovery to a US$100/bbl level by 2027 and then increasing to US$120/bbl; the nominal prices continue to rise, escalating to US$150/bbl by 2029 and breaking US$200/bbl by 2037.

15 Government of Alberta, 2012. Service Alberta, Queen’s Printer, Laws Online/ Catalogue, Legislation, Mines and Minerals Act, Oil Sands Royalty Regulation, 2009 (http://www.qp.alberta.ca/574.cfm?page=2008_223.cfm&leg_type=Regs&isbncln=9780779732272), accessed on January 26, 2012.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 31

Figure 3.8: WTI Price Forecast

$US/bbl $300 WTI price (nominal US$/bbl) $250 WTI price (real 2013 US$/bbl) $200

$150

$100

$50

$-

2007 2021 2035 2009 2011 2013 2015 2017 2019 2023 2025 2027 2029 2031 2033 2037 2039 2041 2043

Source: EIA, CERI

US-Canadian Exchange Rate Canada’s dollar is often viewed as a petrocurrency because its movements often track oil prices (see Figure 3.9). In February 2008, the price of WTI crude oil closed for the first time at over US$100/bbl and the Canadian dollar was trading around parity with the US dollar. When the price of crude oil collapsed due to the global economic downturn and the drop in commodity prices, the Canadian dollar fell to about $0.82 US by November 2008. In late 2009, as oil prices recovered, the Canadian dollar approached parity with the US dollar again. Since then, in the last two years, the Canadian dollar was trading between US$0.96-$0.99 on average. Hence, an exchange rate of US$0.98 will be assumed throughout the projection period.

July 2014 32 Canadian Energy Research Institute

Figure 3.9: US/Canadian Exchange Rate

$1.10 160

$1.00 140

120 $0.90

100 $0.80 80

$0.70 US$/bbl

US$/C$ US$/C$ Ex.rate 60

$0.60 40

$0.50 20

$0.40 0

Jul-04 Jul-09

Jan-02 Jan-07 Jan-12

Jun-02 Jun-07 Jun-12

Oct-05 Oct-10

Apr-03 Apr-08 Apr-13

Feb-04 Feb-09 Feb-14

Sep-03 Sep-08 Sep-13

Dec-04 Dec-09

Aug-06 Aug-11

Nov-02 Nov-07 Nov-12

Mar-06 Mar-11

May-05 May-10

Source: Statistics Canada

Supply Cost Results Based on these assumptions, the supply costs of crude bitumen using SAGD, surface mining and extraction, integrated mining and upgrading, and a standalone upgrader have been calculated for a hypothetical project. Figure 3.10 illustrates the supply costs for these projects. The plant gate supply costs, which exclude transportation and blending costs, are C$50.89/bbl, C$71.81/bbl, C$107.57/bbl, and C$40.82/bbl for SAGD, standalone mine, integrated mining and upgrading, and a standalone upgrader, respectively. A loose comparison16 of field gate costs from the May 2013 update with this year’s supply costs indicates that, after adjusting for inflation, the supply cost for a SAGD producer has risen by 4.4 percent, 1.6 percent for a standalone mine and by 5.9 percent for an integrated mining and upgrading project.

16 Because some changes were made in the project energy requirements as well as project economics, a direct comparison of costs is not favoured.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 33

Figure 3.10: Total Field Gate Bitumen/SCO Supply Costs

$120

$107.57 $110

$100

$90

$80 $71.81 $70

$60 CDN$/bbl $50.89

$50 2013 $40.82 $40 Real

$30

$20

$10

$0 Mining & Standalone SAGD 10% ROR Mining 10% ROR Upgrading 10% Upgrading 10% (a) (a) ROR (a) ROR (a) Fixed Capital (Initial & Sustaining) $18.92 $31.14 $54.72 $24.25 Operating Working Capital $0.45 $0.70 $1.06 $0.39 Fuel (Natural Gas) $4.31 $1.90 $3.03 $3.74 Other Operating Costs (incl. Elec.) $14.55 $19.97 $28.66 $9.07 Royalties $9.43 $13.61 $12.39 $0.00 Income Taxes $3.09 $4.42 $7.55 $3.33 Emissions Compliance Costs $0.11 $0.04 $0.05 $0.00 Abandonment Costs $0.03 $0.04 $0.07 $0.03

aReturn on capital included. Source: CERI.

After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing for SAGD projects is US$84.99/bbl, US$105.54 for a standalone mine; US$109.50 for an integrated mining and upgrading, and US$41.44/bbl for a standalone upgrader. A summary of costs are presented in Table 3.4. At WTI prices of US$100/bbl, the only project that would be economic is a SAGD in situ project, which is consistent with how the oil sands projects are currently being developed. The greenfield projects that will be built are mostly in situ type projects, the development of mines and integrated mines is only happening as expansion of existing projects, that can provide some cost savings and economies of scale.

July 2014 34 Canadian Energy Research Institute

Table 3.4: Supply Costs Summary

Project SC at Field Gate WTI Equivalent SC (C$2013/bbl) (US$2013/bbl) SAGD 50.89 84.99 Stand-Alone Mine 71.81 105.54 Integrated Mining and Upgrading 107.57 109.50 Standalone Upgrader 40.82 44.13

Source: CERI While capital costs and the return on investment account for a substantial portion of the total supply cost, the province stands to gain $9.4 to $13.6 in royalty revenues for each barrel of oil produced on average, over the life of an oil sands project. On a percentage basis, these range from 11.5 to 19 percent (see Figure 3.11). The reason that the royalty share of the total cost is the lowest (11.5 percent) for an integrated mining and upgrading project has to do with the modeling methodology that calculates the supply cost for an integrated project that is normalized to light SCO, whereas SAGD and standalone mining are normalized to blended bitumen.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 35

Figure 3.11: Oil Sands Supply Costs – Reference Case Scenario (% Contribution)

100%

90%

80%

70%

60%

50%

40%

30% %of Total Supply Cost

20%

10%

0% Mining & Standalone SAGD 10% Mining 10% Upgrading Upgrading ROR (a) ROR (a) 10% ROR 10% ROR (a) (a) Fixed Capital (Initial & 37.2% 43.8% 50.9% 59.4% Sustaining) Operating Working Capital 0.9% 1.0% 1.0% 1.0% Fuel (Natural Gas) 8.5% 2.7% 2.8% 9.2% Other Operating Costs (incl. 28.6% 28.1% 26.7% 22.2% Elec.) Royalties 18.5% 19.1% 11.5% 0.0% Income Taxes 6.1% 6.2% 7.0% 8.2% Emissions Compliance Costs 0.2% 0.1% 0.0% 0.0% Abandonment Costs 0.1% 0.1% 0.1% 0.1%

Source: CERI.

How CERI’s estimates of supply costs compare to others is presented in Table 3.5, CERI’s supply costs are within the AER’s range for SAGD and a mining project, the rest were not available. The NEB’s estimates of costs fall below CERI’s calculated costs.

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Table 3.5: Supply Costs Comparison – WTI Equivalent Supply Costs

Project CERI (2013 NEB (2012 ERCB US$/bbl) US$/bbl)17 (2013 US$/bbl)18 SAGD 84.99 50-80 55-85 Stand-Alone Mine 105.54 70-100 75-105 Integrated Mining & Upgrading19 109.50 80-100 n/a Stand-Alone Upgrader 44.13 55-65 n/a

Source: CERI, ERCB, NEB. Supply Cost Sensitivities The presented costs for four different oil sands projects also need to be analyzed in terms of how sensitive costs are to changes to some of the variables. The ranges used for sensitivities are summarized in Table 3.6.

Table 3.6: Assumptions for Sensitivity Analysis

Parameter Sensitivity Initial Capital Cost +/-25% Sustaining Capital Cost +/-25% Non-Energy Operating Costs +/-25% Natural Gas and Electricity Prices +/-25% Discount Rate +/-2% Steam-to-Oil Ratio +/-25%

Carbon Tax +CDN$25/tonne CO2

Source: CERI

Bitumen supply cost sensitivities for a hypothetical SAGD, integrated mining, extraction and upgrading, a standalone mine and standalone upgrader projects are represented graphically in Figures 3.12-3.15.

17 NEB, “Canada’s Energy Future 2013: Energy Supply and Demand Projections to 2035”, November 2013. Includes an after-tax rate of return, in order of 10 to 15 percent. 18 AER, “Alberta’s Energy Reserves 2013 and Supply/Demand outlook 2014-2023”, May 2014. A nominal 10 percent discount rate is used. 19 There was no supply cost estimate presented for an integrated project in the ERCB’s ST-98, 2012.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 37

Figure 3.12: Supply Cost Sensitivity – 30 MBPD SAGD Project

Discount Rate (2% change)

Initial Capital Cost (25% change)

Non-energy Operating Costs (25% change)

SOR (25 change)

Sustaining Capital Cost (25% change)

Carbon Dioxide Levy

40 45 50 55 60 2013 CDN$/bbl Source: CERI

Figure 3.13: Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project

Non-energy Operating Costs (25% change)

Discount Rate (2% change)

Initial Capital Cost (25% change)

SOR (25 change)

Sustaining Capital Cost (25% change)

Carbon Dioxide Levy

$55 $60 $65 $70 $75 $80 $85 2013 CDN$/bbl Source: CERI

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Figure 3.14: Supply Cost Sensitivity – 115 MBPD Integrated Mining, Extraction and Upgrading Project

Discount Rate (2% change)

Initial Capital Cost (25% change)

Non-energy Operating Costs (25% change)

Sustaining Capital Cost (25% change)

SOR (25 change)

Carbon Dioxide Levy

$90 $95 $100 $105 $110 $115 $120 $125 2013 CDN$/bbl

Source: CERI

Figure 3.15: Supply Cost Sensitivity – 100 MBPD Standalone Upgrader

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Operating Costs (25% change)

Sustaining Capital Cost (25% change)

Carbon Dioxide Levy

SOR (25 change)

30 35 40 45 50 2013 CDN$/bbl

Source: CERI

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 39

The supply costs for all projects are most sensitive to changes in capital cost. A 25 percent increase in initial capital cost would affect an integrated project the most, raising its supply cost by C$13.93/bbl. The supply cost for a SAGD producer will increase by C$5.22/bbl and a standalone mine would experience a C$7.84/bbl increase from its base supply cost. For a standalone upgrader the cost will go up by C$5.69/bbl. Changes in discount rate and operating costs will also alter the supply costs. As expected, SAGD supply cost is more sensitive to changes in steam-to-oil ratio and carbon compliance cost changes than the supply costs of the other two projects.

July 2014 40 Canadian Energy Research Institute

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 41

Chapter 4 Oil Sands Projections

Based upon the supply cost results and given the oil price forecast (Figure 3.8), the last chapter concludes that although some mining projects might be challenged, the overall trend to develop in situ resources is strongly supported by project economics and presents a profitable long-term investment that is worth nurturing. This does not imply that every oil sands project will move from concept to reality. Nor does it imply that every oil sands project should go forward. Inevitably, some projects will experience delays for a variety of reasons, including but not limited to those related to financing and transportation. Another major risk that is resurfacing is the cost inflation within the industry and service industry that provides ancillary goods and services to the upstream oil sands sector.

This Chapter presents CERI’s view of where oil sands production might be heading. A discussion of the methodology used to develop the projections is followed by the assumptions used to delay, and/or cancel oil sands projects. CERI’s oil sands projections for bitumen, SCO, natural gas requirements, GHG emissions, strategic and sustaining capital, operating costs, and provincial royalty revenues are then provided. A special focus is paid to the Reference Case Scenario and discussed in more detail at the end of the chapter.

Methodology and Assumptions CERI’s methodology for projecting bitumen and SCO production volumes remains unchanged from past reports. Projections are based on the summation of all announced projects, with a variety of assumptions pertaining to 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 past experience from monitoring the progress of various oil sands projects.

A scenario without any constraints applied to oil sands capacity announcements would reflect CERI’s unconstrained projections in past reports. In this year’s report, the unconstrained bitumen capacity will only be shown to provide context to the constraints, and represents a “ceiling” on oil sands production, as currently defined by the collective announcements from the oil sands industry.

The three scenarios that were presented in Chapter 2 are used to guide CERI’s oil sands development projections. To summarize, the scenarios are the Reference Case, High Case, and Low Case; the Unconstrained scenario is not considered as a full scenario in this report. Each scenario contains its own assumptions as to delays in the on stream date and the rates of capacity/production additions.

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The impact that these scenarios could have on oil sands developments was translated into two constraints: project startup delays, and capacity curtailments. These constraints were a function of the scenarios and their impact on a project’s ability to move through the regulatory and internal corporate approval processes.

Delay Assumptions Projects further along the regulatory process are given shorter delays, and have higher probabilities of proceeding to their announced production capacity. Projects that have been announced, but have not yet entered the regulatory process with a disclosure document receive lower probabilities of proceeding and longer delays.

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. The delays and probabilities are different for each scenario to represent the economic environment of each individual scenario. As compared to delay years and capacity curtailments of last year’s update, this year sees an increase in the number of delay years for some categories and a decrease in probabilities of reaching full capacity. This is especially true for mining and upgrading projects, given the recent history of these projects experiencing significant delays and cancelations. Another factor that is contributing to this increase in delays and capacity curtailments is the fact that the 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 proposals to expand the export pipeline capacity, many projects are facing challenges in moving ahead. Producers have responded to this by starting to ship oil by rail, which in itself is remarkable, given how quickly the rail industry was able to respond, and today there are outbound terminals being built in Northern Alberta with producers committing future volumes to be shipped on rail cars. The outbound terminal capacity is set to grow to anywhere from 0.75 to 1.0 MMBPD by 2015-2017. Nevertheless, in the long run, pipelines will still be a preferred option to ship crude for cost and safety reasons.

Estimating Royalty Revenues and Blending Requirements Due to their importance to the provincial economy as well as the complexity of their calculation, it is important to develop accurate estimates of royalty revenues in the context of this report. Further, while various organizations such as the Canadian Association of Petroleum Producers (CAPP), the AER, and the National Energy Board (NEB) develop estimates for production, supply, and associated costs, none of them provide estimates for royalties. Two reports provide oil sands royalty estimates over the short term (five years or less), including a report by ARC Financial Corp. prepared for CAPP in 2011 and Alberta Finance in its latest budget revenue outlook. The results of these projections are compared with CERI’s own projection in the Results section of this chapter.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 43

Generally speaking, bitumen royalties are a function of royalty rates and producers’ revenues (either gross or net revenues, depending on project payout status). However, while that seems simple enough, there are various channels through which both upside and downside pressures are exerted on total bitumen royalties collected, as illustrated in Figure 4.1.

Figure 4.1: Bitumen Royalty Drivers

Source: CERI

CERI developed a cash flow methodology on a project phase by project phase basis in order to calculate royalties from oil sands projects. CERI has been publishing long-term oil sands royalty forecasts for a number of years. More information on the cash flow methodology is provided in Appendix A of CERI Study 133.1

Blending requirements are determined through the bitumen valuation methodology together with evaluation of each individual crude slate from various oil sands projects. Further details are described in the Cash Flow and Bitumen Valuation Methodology in Appendix A of CERI Study 133.

Oil Sands Projections – 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

1 CERI Study No. 133, “Canadian Oil Sands Supply Costs and Development Projects (2012-2046)”, May 2013.

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reports, investor presentations and press releases. The projections include production from existing projects as well as new projects that are under construction, approved, awaiting approval and announced. The projection period is from 2014 to 2048, inclusive.

Oil Sands Capacity Based upon current information collected from oil sands proponents, capacity could peak at 8.6 million barrels a day (MMBPD) by the end of 2031 without delays or curtailments; for comparison, in CERI’s 2013 oil sands update under the Unconstrained Scenario, the peak was achieved in 2027 with 8.3 MMBPD capacity.2 While this represents a bold target for the oil sands industry, the path towards the peak is not viable, given the wide array of constraints faced by industry (e.g., labour, capital, limited transportation capacity, and declining oil demand). The three scenarios developed by CERI provide three plausible paths of oil sands and SCO development.

Illustrated in Figure 4.2 are the capacity projections for the three scenarios, in addition to the Unconstrained Scenario. In each scenario, oil sands capacity grows significantly, exceeding 4 MMBPD by end of the forecast period, 2048. The rate of expansion is robust at the front end of the forecast period, and becomes more or less flat post-2035.

Under the Low Case Scenario, the oil sands experiences restrained capacity growth over the next decade, a direct result of Low Case Scenario assumptions, which state that the economic growth is minimal, energy demand is stagnant, and the environmental policy comes to the forefront of policy making. With high compliance costs and limited economic growth, oil sands are still growing but at a much slower pace than in the other two cases. By 2020, capacity reaches 3.3 MMBPD. While this Scenario shows growth in capacity additions, capacity expansions do not approach CERI’s Reference Case Scenario before the end of the projection period, reaching levels of 5.4 MMBPD by 2048, 0.7 MMBPD less than in last year’s update. Ongoing increasing overall costs for oil sands producers and lack of export pipeline were the main reasons for revising the Reference Case Scenario’s capacity forecast. Under this Scenario, it is assumed that eventually, protectionist policies are relaxed, which helps spur a period of economic growth, and in turn, brings forth the resumption in oil sands development.

2 The last eight years of forecast show a decline in capacity, this is due to lack of further information on project capacities and not to say that the capacity will be curtailed.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 45

Figure 4.2: Bitumen Capacity Projections

('000bpd)

10,000

9,000

8,000

7,000

6,000

5,000

4,000

Total Bitumen (Unconstrained Capacity Scenario) 3,000 Total Bitumen (Capacity, High Case Scenario)

Total Bitumen (Capacity, Low Case Scenario) 2,000 Total Bitumen (Capacity, Reference Case Scenario)

1,000

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI, CanOils

In a world where energy security trumps all other concerns, driven by robust economic growth in 2014, the oil sands return to a period of rapid and aggressive development. The High Case Scenario implicitly assumes that the rise in oil prices more than offsets the inflation that would be experienced in Alberta and export pipeline capacity becomes available through the addition of new lines and expansion of existing ones, as oil sands developments grow at unprecedented rates. By 2020, bitumen capacity reaches 5.1 MMBPD, and by 2048 – 6.3 MMBPD.

While some may be skeptical about this Scenario coming to fruition, it is plausible that, by 2048, the oil sands could be the exclusive exporter of crude oil to the US and become an important supplier of crude oil to other nations as well. This scenario does face immense hurdles, the least of which are finding the labour and capital to commission new oil sands projects at such a rate.

The more reasonable path for oil sands development follows CERI’s Reference Case Scenario, where oil sands development grows steadily. The slight drop in capacity in 2017 and again around 2027 is a result of some projects in the oil sands reaching the

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end of the assumed production life. Another dip around 2034 has to do with revised assumptions on delays and probability curtailments for projects that fall under “awaiting approval” and “announced” categories – in both categories the delays and curtailments on capacity were increased in comparison to last year’s update. The period from 2014 to 2027 experiences a rapid growth phase in the capacity additions and it is not until 2028 that the growth levels off and by 2035 it slows down. In 2020, capacity reaches 4.3 MMBPD (as opposed to 3.9 MMBPD, which was last year’s estimate for year 2020), but only grows to 5.4 MMBPD by 2048, with a peak capacity of 5.7 MMBPD occurring in 2027.

This scenario is in line with expectations for pipeline capacity additions (assuming they all come on stream), and it is possible that the labour and capital markets in Alberta will be capable of handling this expansion without causing undue stress on the local economy. The pace of pipeline expansion will depend on decisions with respect to the markets to be served and the necessary regulatory approvals. The period of sustained growth (2018 to 2034) might introduce challenges to the Alberta economy, similar to those faced during the 2004 to 2008 period.

Oil Sands Production Figure 4.3 illustrates the possible paths for production under the three scenarios. For an oil sands producer, a project’s viability relies on many factors, such as but not limited to the demand-supply relationship between production, operating and transportation costs (supply side) and the market price for blended bitumen and SCO (demand). Despite the current outlook for the light-heavy differential, escalating construction costs, probability of construction and regulatory delays, and availability of suitable and accessible refinery capacity, the prevailing view in the industry appears to be cautiously optimistic. All three scenarios show a significant growth in oil sands production for the 35-year projection period.

Total production from oil sands areas totaled 2.1 MMBPD in 2013, comprised of in situ and mining production of 1.9 MMBPD and 0.3 MMBPD of primary and enhanced oil recovery (EOR) production within the boundaries of oil sands areas. Total production in 2012 was 1.9 MMBPD, meaning the oil sands production grew 10.9 percent year-over- year. Production from oil sands comprises an increasing share of Alberta’s and Canada’s crude oil production. In 2013, non-upgraded bitumen and SCO production made up 54 percent of total Canadian crude production and 73 percent of Alberta’s total production.

In the High Case Scenario, production from mining and in situ thermal and solvent extraction (excluding primary recovery) is set to grow from 1.9 MMBPD in 2013 to 3.8 MMBPD by 2020 and 5.7 MMBPD by 2048. In the Low Case Scenario production rises to 4.2 MMBPD by 2030 and 4.3 MMBPD by the end of forecast period. CERI’s Reference Case Scenario provides a more plausible view of the oil sands production. Projected

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 47

production volume will increase to 3.4 MMBPD by 2020 and 4.8 MMBPD in 2048 (see Figure 4.3 and Table 4.1). Cold bitumen production from primary and EOR wells is forecasted to increase from 0.27 MMBPD in 2013 to its peak of 0.35 MMBPD by 2020 and then slowly tapers off to just above 0.2 MMBPD by the end of forecast period.

Table 4.1: Oil Sands Production Forecast*

2013 2020 2030 2048 MMBPD High Case 1.86 3.83 5.78 5.68 Reference Case 1.86 3.44 4.93 4.83 5 Low Case 1.86 2.79 4.17 4.28

*Excludes primary bitumen production. Source: CERI

Peak production volume of 5.8 MMBPD in the High Case Scenario is reached in 2037. Peak production volumes for the other two cases are lower and reach their peak later in the projection period. Under the Low Case Scenario, the highest production of 4.4 MMBPD is reached in 2041. Production under the Reference Case Scenario peaks at 5.0 MMBPD in 2039. The differences in magnitude of production growth among the three scenarios can be explained by a combination of the acceleration/deceleration of the startup of projects and capacity curtailments.

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Figure 4.3: Bitumen Production Projections

('000bpd)

7,000

6,000

5,000

4,000

3,000

(Production, High Case Scenario)

(Production, Low Case Scenario) 2,000

(Production, Reference Case Scenario)

1,000

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI, CanOils

Achieving any of the levels of production outlined in the three scenarios requires a substantial number of inputs, of which capital (both strategic and sustaining) and natural gas are critical. Without the required capital, an oil sands project cannot be constructed. The project, with current technologies, cannot operate without an abundant and affordable supply of natural gas. Lastly, once the facility is operating there is an ongoing need for sustaining capital to ensure that production volumes stay at their design capacities.

Oil Sands Capital Investment Relying on the previously stated design assumptions, and the associated capital required to construct a facility and sustain operations, CERI has estimated the total and annual financial commitments required for the oil sands. Total capital costs, including initial and sustaining capital, under the three scenarios, are illustrated in Figure 4.4.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 49

Figure 4.4: Total Capital Requirements

(Million CDN$) $50,000

$45,000

Total Capital Investments (Capacity, High Case Scenario) $40,000

Total Capital Investments (Capacity, Low Case Scenario)

$35,000 Total Capital Investments (Capacity, Reference Case Scenario)

$30,000

$25,000

$20,000

$15,000

$10,000

$5,000

$0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI, CanOils

Over the 35-year projection period from 2014 to 2048 inclusive, the total capital required is projected to be C$636.6 billion under the High Case Scenario, C$597.9 billion under the Reference Case Scenario, and C$590.2 billion under the Low Case Scenario.3 These projections do not include capital investment required for primary and EOR oil sands projects that lie within oil sands areas. The forecast for cold bitumen capital spending is calculated under CERI’s conventional oil model and those results are presented in the next section of this chapter and discussed only in the context of the Reference Case Scenario.

New investment dollars start declining half way through the forecast period, and approach zero by the end of the projection period. This, however, does not indicate a slowdown in the oil sands, merely a lack of information on new capacity that will be coming on stream, and relates back to CERI’s assumptions for project start dates, and announcements from the oil sands proponents. With careful planning, the Reference Case Scenario could be a viable target. Ongoing investment, in the form of sustaining

3 The total capital spending on primary and EOR wells is estimated to be C$8.4 billion.

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capital will take place on an annual basis. In each of the three scenarios, the annual sustaining capital required for the oil sands (excluding royalty revenues, taxes, and fixed and variable operating costs) exceeds C$6 billion by 2048. The Reference Case Scenario projection shows an annual investment of C$9.2 billion in 2048, and is estimated to average C$8.7 billion over the projection period. Under the High Case Scenario, the sustaining costs reach an all-time high of C$10.7 billion dollars in 2048, averaging C$9.9 billion over the 35-year window. In the Low Case Scenario, C$8.2 billion will be spent on sustaining costs in 2046, with an average of C$7.5 billion over the projection period.

Natural Gas Requirements More than the conventional oil and gas industries, the oil sands industry is a large consumer of energy. Given that most in situ projects generate steam using natural gas- fired steam generators, the single highest operating cost for these in situ thermal projects is the cost of natural gas. Although mining, extraction and upgrading projects use proportionately less natural gas than in situ projects, the industry’s demand for natural gas is still substantial.

For a SAGD project, dry steam-oil ratios typically range from 2.0-2.5, while for CSS, wet steam-oil ratios are between 3.0-3.5. The natural gas requirement for mining and extraction is much lower than that for in situ development. Significant quantities of natural gas are used to provide fuel and meet the hydrogen requirements of the upgrading process. Geological formations with different pressure, steam, and temperature requirements cause natural gas usage to vary because energy requirements vary. When estimating the gas required for oil sands production projections, CERI used the historical steam-oil ratios where they are provided, otherwise default values are assigned for gas use for different technologies. In reality, however, steam-oil ratios are not constant, and the volume of gas used can vary significantly due to varying temperature and pressure requirements. The amount of natural gas required to sustain the oil sands industry is substantial, and is illustrated in Figure 4.5.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 51

Figure 4.5: Natural Gas Requirements

(MMcf/d)

4,000

3,500

3,000

2,500

2,000

Total Natural Gas Requirements (Production, High Case Scenario) 1,500

Total Natural Gas Requirements (Production, Low Case Scenario)

Total Natural Gas Requirements (Production, Reference Case Scenario) 1,000

500

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI

By 2048, natural gas requirements will increase by 2 to 3 times the current levels. Given the robust production projection, natural gas use is estimated to rise from the current 1,474 MMcf/d in 2013 to 3,753 MMcf/d in 2046 under the High Case Scenario, 3,170 MMcf/d in the Reference Case Scenario, and 2,870 MMcf/d under the Low Case Scenario. This year’s forecast of natural gas demand is a half percent lower overall for the Reference Case Scenario. Though not a significant change, the prospects for technology switching to use less natural gas and efficiency improvements are substantial. The technological innovation driven by human ingenuity and environmental push towards “greener” technologies will likely put downward pressure on the industry’s natural gas requirements. Also, considering how aggressively shale gas production in the US has come on stream, and the potential for shale production in Canada, meeting the oil sands industry’s future demand for natural gas should not be a concern.4

4 For more information on natural gas production forecast, please see CERI Study 138, “North American Natural Gas Pathways”, June 2013.

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Oil Sands Emissions In this year’s update, CERI continues to estimate emissions based on bitumen produced as introduced in last year’s update. This way CERI is able to capture emissions from mining operations as well. The emission factor, expressed in carbon dioxide equivalent per barrel produced (CO2eq. tonne/bbl), includes the total emissions from the facility, which might include cogeneration capability, if the facility is equipped with such a unit. The barrel designation has not been differentiated between emissions associated with the production and sale of electricity, and emissions directly associated with the barrel of oil produced. Barrels are assumed to be barrels of raw bitumen produced or received by the facility; i.e., upgrading is not per barrel of SCO but per barrel of raw bitumen. Table 4.2 presents the emission factors used for each technology.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 53

Table 4.2: Emission Factors

Project Type Technology Emission Factors

(CO2eq.tonne/ bbl bitumen) In Situ In Situ/integrated In situ 0.07/0.2 In Situ CSS 0.08 In Situ CSS / Top Down Steam Drive 0.08 In Situ CSS / SAGD 0.07 In Situ CSS, LASER, CSP, Steam Flood, SAGD & SA-SAGD 0.05 In Situ CSS / VSD 0.03 In Situ SAGD 0.06 In Situ COGD 0.02 In Situ THAI 0.02 In Situ HSAGD 0.06 In Situ SAGD, Thermal Conduction Process and Cold 0.06 production In Situ LP-SAGD 0.07 In Situ SAGD & ES-SAGD 0.03 In Situ ET-DSP 0.03 In Situ HCS 0.05 In Situ SAGD & SAGD+™ 0.06 In Situ SAGD & SAGP 0.06 In Situ Steam over Solvent 0.06 In Situ THAI™, CAPRI™ & Modified Wet Combustion 0.02 In Situ Solvent SLP-SAGD 0.05 In Situ Solvent SAP or SAGD 0.03 In Situ Solvent SAGD & SC-SAGD 0.05 In Situ Solvent SAGD & Solvent 0.05 In Situ Solvent SAGD & SAP 0.04 In Situ Solvent N-SolvTM 0.01 Mining Mining/Integrated Mining 0.03/0.09 Mining Mining & ESEIEH 0.03 Upgrader Upgrader 0.06 Upgrader Coker or Hydrocracker 0.06 Upgrader Delayed Coker 0.06 Upgrader Fluid Coker/Hydro Conversion 0.06 Upgrader HTL 0.06 Upgrader Hydro conversion 0.06 Upgrader Orcrude 0.06 Upgrader USP/ADC™ 0.06 Source: CERI Study 126, “Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands”.

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Without equipment to sequester emissions, the GHG emissions grow proportionately to the increases in production. While technological innovation within the oil sands industry (in addition to carbon capture and storage) is expected to help reduce these emissions, the emissions are still expected to rise.5 The following forecast of emissions is based on emission factors estimated and presented in CERI Study 1266 and are presented in Table 4.3 for ease of reference. Figure 4.6 illustrates the GHG emissions under CERI’s emissions factor assumptions. GHG emissions are expected to rise in tandem with oil sands production.

Figure 4.6: Greenhouse Gas Emissions

(CO2 eq. MT/year)

180

160

140

120

100

80

Total Greenhouse Gas Emissions (Production, High Case Scenario) MT/Year

Total Greenhouse Gas Emissions (Production, Low Case Scenario)MT/Year 60

Total Greenhouse Gas Emissions (Production, Reference Case Scenario) MT/Year

40

20

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047 Source: CERI

5 The emission forecast from Scotford Upgrader is reduced by a proposed 1 million ton of CO2 per year, starting in 2015 to be captured and stored by the Shell’s CCS Quest project. 6 For full details on how the emission factors were estimated please refer to CERI Study 126 “Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands”. You can download the study at www.ceri.ca

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 55

Emissions will rise from 55 Mt/year in 2012 to 144 Mt/year in 2048 under the Reference Case Scenario, to 165 Mt/year in 2048 in the High Case Scenario, and to 129 Mt/year under the Low Case Scenario. The historic emission numbers are consistent with Environment Canada’s “National Inventory Report 1990-2011: Greenhouse Gas Sources and Sinks in Canada”, where it states that emissions from oil sands activities, including mining, upgrading and in situ amount to 55 Mt/year in 2011-2012.7 However, the oil sands industry has been reducing its per unit emissions, and in 2011 per barrel emissions intensity was 26 percent lower than in 1990.8 This reduction in GHG intensity is significant, as oil sands production share of total crude oil production is increasing. Cumulative emissions in the Reference Case Scenario are projected to be 4,587 Mt from 2014 to 2048, which is 3.3 percent higher than last year’s 35-year cumulative emissions projection.

Oil Sands Royalties Figure 4.7 illustrates the bitumen royalty estimates under the Low, Reference, and High Case Scenarios both on an annual and cumulative basis (2014-2048). Royalty revenues rise in all three cases with the production as expected. Under the Low and High Case Scenarios annual royalty revenues reach (in 2013 dollars) C$39.6 billion and C$52.2 billion, respectively by 2048. Annual revenues amount to C$44.6 billion by 2048 in the Reference Case Scenario. The shaded area represents the difference in estimates between scenarios which is equal to over C$318 billion between the High and Low Case Scenarios. The cumulative royalty revenues over the 35-year forecast will amount to $1.2 trillion under the High Case Scenario, C$1.0 trillion under the Reference Case Scenario, and C$0.9 trillion under the Low Case Scenario.

7 Environment Canada. “National Inventory Report 1990-2011: Greenhouse Gas Sources and Sinks in Canada”, 2013. 8 Ibid.

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Figure 4.7: Oil Sands Royalties

Annual ($MM) Cummulative ($MM) $60,000 $1,300,000

Estimated Royalties Range $55,000 $1,200,000 CERI-Low Case

$50,000 CERI-Reference Case $1,100,000 CERI-High Case $1,000,000 $45,000 Cumulative-Low Case Scenario (Right Scale) Cumulative-Reference Case Scenario (Right Scale) $900,000 $40,000 Cumulative-High Case Scenario (Right Scale) $800,000 $35,000 $700,000 $30,000 $600,000 $25,000 $500,000 $20,000 $400,000

$15,000 $300,000

$10,000 $200,000

$5,000 $100,000

$0 $0

2012 2017 2045 2007 2008 2009 2010 2011 2013 2014 2015 2016 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2046 2047 2048

Source: CERI

Oil Sands Projections – Reference Case Scenario This section will focus on the results of CERI’s Reference Case Scenario. Projections of production, costs, diluent and royalties are included in the discussion.

Oil Sands Production – Historic and Forecast A comparison is presented between CERI’s Reference Case Scenario production and other agencies’ forecasts, such as CAPP,9 the AER,10 and the NEB11 that report oil sands forecasts. Figure 4.8 illustrates the comparison of bitumen production between CERI and the three agencies. The AER’s forecast goes out to 2023, CAPP’s to 2030 and the NEB’s to 2035. CERI’s forecast is truncated in 2035 for comparison purposes. CERI’s total production projection from oil sands areas (including primary and EOR projects) is consistent with the AER’s forecast up to 2021 and steeper than CAPP’s and NEB’s estimates. In the latter part of the forecast, production increases faster in CERI’s forecast due to inclusion of some announced projects, which were not included in the

9 CAPP, “Canadian Crude Oil Forecast and Market Outlook”, June 2014 10 AER ST98, “Alberta’s Energy Reserves 2013 and Supply/ Demand Outlook (2014-2023)”, May 2014. 11 NEB, “Canada’s Energy Future: Energy Supply and Demand Projections to 2035 – Energy Market Assessment 2013”, November 2013.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 57

other forecasts. Currently, all mined bitumen and a portion of in situ production is upgraded to SCO. According to the AER, in 2013, 12 percent of in situ production was upgraded to SCO. The 2013 production of SCO amounted to 0.9 MMBPD and is expected to increase to over 1.0 MMBPD in 2016, averaging at 1.3-1.4 MMBPD of production from 2014 to 2048.

Figure 4.8: Bitumen Production Forecast – Comparison

6,000

5,000

4,000

kb/d 3,000

CERI CAPP 2,000

NEB AER 1,000

-

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 2007 Source: CERI, ERCB, CAPP, NEB

Illustrated in Figure 4.9 are the production projections by extraction type. Total mined bitumen production is expected to increase from 1.0 MMBPD in 2013 to its peak of just over 1.8 MMBPD by 2021, at which point the production dips until it reaches 1.7 by 2036. The decrease in mining production is explained by some of the legacy mines coming offline. The remainder of the projection period remains flat. In situ production continues to be higher than mining since 2012. The production is expected to increase from 1.1 MMBPD12 in 2013 to 3.4 MMBPD in 2048 due to the addition of new proposed projects, the expansion of existing and construction of approved projects. The share of bitumen production from mining will continue to decrease – from 48 percent in 2013 to a third in 2048. By the end of the projection period in 2048, in situ bitumen accounts for more than 65 percent of total production volumes.

12 Including Primary and EOR projects.

July 2014 58 Canadian Energy Research Institute

Figure 4.9: Bitumen Production by Extraction Type – Reference Case Scenario

('000 bpd)

4,000

Total In Situ Volume

3,500 Total Mining Volume

3,000

2,500

2,000

1,500

1,000

500

0 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI, CanOils

Given the production projection, the net bitumen and SCO production by proportion of total is shown in Figure 4.10. The Figure illustrates that a large share of total projects are made up of on stream, approved, and awaiting approval projects. The portion attributable to the announced category has been revised downward from last year’s update as a result of a lower oil price forecast and lack of clearness on what will happen to all the proposed pipeline projects. The risk of these projects not proceeding is high. As the proportion of on stream projects starts to decline from 100 percent in 2012 to just a third in 2048, the total proportion of approved, awaiting approval and announced projects increases to 55 percent by the end of the projection period. The remaining portion is represented by projects that are under construction.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 59

Figure 4.10: Net Bitumen and SCO Production by Project Status – Reference Case Scenario 13

100%

Announced 90% Awaiting Approval

Approved 80% Under Construction Onstream 70%

60%

50%

40%

30%

20%

10%

0% 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047

Source: CERI, CanOils

Diluent Demand, Supply, and Transportation Diluent is an important component of oil sands operations for transportation purposes. Adding diluent brings that barrel of bitumen to the pipeline specifications and allows bitumen to flow, otherwise non-upgraded bitumen is too viscous to flow.

In addition to oil sands production, diluent demand is also driven (although to a much lesser extent) by conventional heavy crude oil production both in Saskatchewan and Alberta. In oil sands operations, demand for diluent is driven by non-integrated projects whose primary output is a crude bitumen blend such as WCS rather than SCO. The diluent pool in turn is made up of various components including light crudes such as SCO and condensates (ultra-light crude), but also natural gas liquids (NGLs) such as butanes, but most importantly, pentanes plus. While the choice of diluent used by different project operators is based on economic and technical considerations,14 pentanes plus

13 This graph does not include the forecast of primary and EOR projects. 14 See CERI Study 133.

July 2014 60 Canadian Energy Research Institute

remains the diluent of choice for oil sands operators. Figure 4.11 displays the estimated demand for diluent by project type and by diluent type to 2030.15

Figure 4.11: Western Canada Heavy Oil and Oil Sands Diluent Demand by Project Type and Type of Diluent (MBPD), 2007-2030

1,400 Butanes Diluent Demand SCO Diluent Demand OS Thermal + Mining Project (C5+/Condensate Demand) 1,200 EOR/Primary Bitumen (C5+/Condensate) Demand Conventional Heavy (C5+/Condensate) Demand Total Oil Sands/Heavy Conventional Diluent Demand 1,000 C5+/Condensate Demand

800 kb/d 600

400

200

- 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 HISTORICAL/ACTUAL OUTLOOK

Source: AER, CERI Total demand for diluent in Western Canada for 2013 is estimated at 422 thousand barrels per day (MBPD) including 69 MBPD of pentanes plus and condensate for conventional heavy crude oil, 81 MBPD for primary/EOR bitumen projects, 182 MBPD for SAGD/CSS/Mining projects, 41 MBPD of SCO for synbit and dilsynbit blends, and 19 MBPD of butanes used as a diluent.

Oil sands operations are estimated to account for 84 percent of total diluent demand, while pentanes plus and condensate (combined) are estimated to account for 86 percent of the diluent used in Western Canada. Going forward this is expected to remain being the case and total diluent demand is estimated to reach over 1.2 MMBPD by 2030, out of which 1.1 MMBPD are expected to be pentanes plus/condensate.

In regards to the supply of diluent, given the small portion of SCO and butanes used as diluent, those sources are not discussed in great detail here. On the pentanes

15 The 2030 timeline is used here as the supply side projections are derived from a different CERI model (NGLs model) whose timeframe does not reach beyond 2030. However, it is important to note that total oil sands production, the main driver for diluent demand, peaks in 2030 and thus demand for diluent will flatten and decrease beyond that point (according to the current modeling assumptions), and thus the maximum peak demand levels for diluent, the focus of this section, is reached within the timeframe displayed.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 61

plus/condensate side, Figure 4.12 illustrates the supply and demand balance, which shows that diluent imports will continue to be the norm going forward.

Figure 4.12: Pentanes Plus/Condensate Supply and Demand Balance (MBPD) 2007-2030

1,200 Required Imports WCSB Condensate WCSB Pentanes Plus 1,000 Total WCSB C5+/Condensate Production Total Pentanes+/Condensate Demand

800

822 817 798 813 767 600 731 kb/d 692 649 604 564 533 400 485 390 446 337 285 210 220 176 200 74 81 92 116 142

- 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 HISTORICAL/ACTUAL OUTLOOK

Source: AER, CERI

While import levels are expected to remain high, the overall estimated levels of required imports are lower when compared to previous reports’ estimates, primarily due to changes in the local production profile. CERI believes that the domestically produced volumes of pentanes plus and condensate will continue to be sold in Western Canada given a prevailing price premium compared to other markets. Meanwhile, production of pentanes plus and condensate are estimated to be higher during the forecast period given a combination of factors including the continued focus of gas producers on liquids-rich and “oily” gas plays like the Duvernay, but also overall increasing levels of gas production due to the commissioning of liquefied natural gas projects (LNG) in British Columbia.

Meanwhile, it is important to consider that diluent import requirements are not only a function of local production volumes but of overall demand levels as well. In previous reports we have discussed the fact that CERI’s demand projections are based on the premise that crude bitumen would be blended primarily as dilbit, that is, no field upgrading will occur, but also that it will be moved primarily via pipeline.

Alternatively, crude bitumen could be moved by rail (and this will increasingly be the case under continued market access and pipeline logistics constraints), and depending

July 2014 62 Canadian Energy Research Institute

on how the bitumen would be moved,16 there is a potential for diluent demand to decrease. Figure 4.13 illustrates a simple example of this.

First, the grey area illustrates the rail terminal crude loading capacity expected to be built in Western Canada and estimated to reach 1,000 MBPD by 2017. Granted, not all rail capacity is being built to move heavy or oil sands crude, thus a conservative approach of half of the rail capacity to be dedicated to move bitumen (this is represented by the green bars) is reasonable. The red lines in turn estimate the amount of diluent required for such shipments if they were done as dilbit, railbit, or cleanbit. The main idea is to illustrate that with the scale of the rail terminal crude loading capacity build out expected to occur over the coming years, there is a potential for such development to lead to lower diluent demand levels and thus lower diluent import requirements. The scale of such reduction is, however, up for debate.

Figure 4.13: Potential Diluent Demand Reduction from Moving Bitumen via Rail (MBPD), 2007-2030

1,200

1,000

Western Canada Rail Loading Capacity 800 Bitumen Terminals @ 50% of Total Loading Capacity Diluent Required: Dilbit Diluent Required: Railbit

600 Diluent Required: Cleanbit kb/d

400

200

-

2022 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2023 2024 2025 2026 2027 2028 2029 2030 HISTORICAL/ACTUAL OUTLOOK

Source: CERI

Last but not least, in the context of diluent import requirements it is important to consider the infrastructure required to move such volumes to the Alberta diluent market. Figure 4.14 displays the required level of diluent imports as estimated above (without accounting for potential diluent demand reduction due to rail transportation or field upgrading) against the backdrop of existing and planned import infrastructure.

16 Dilbit via rail would use the same amount of diluent as dilbit in pipelines or around 30%. Railbit will require about 17% diluent and cleanbit would require no diluent at all. Railbit and cleanbit would require coil and insulated (C&I) rail cars for transportation purposes.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 63

Diluent import infrastructure includes pipelines such as the existing Southern Lights pipeline (for which capacity is expected to be expanded over the coming years), the Cochin pipeline which is currently being reversed and switched over from propane to diluent service, and the proposed Northern Gateway diluent line. Other infrastructure includes rail terminals dedicated to diluent service in the Edmonton/Fort Saskatchewan area, as well as a terminal on the Kitimat coast that moves diluent via rail to Alberta.

Up until 2024, the import infrastructure seems to be sufficient to accommodate the needed import volumes. Beyond that, a combination of factors could help ease any infrastructure shortage including any further expansion of existing pipelines or the building of new pipelines, but also the use of rail. The increased use of rail can play different roles in fulfilling the increased diluent import needs. For one, as discussed above, it has the potential to reduce diluent demand depending on how the bitumen is transported. Additionally, increasingly available rail tank cars can also be used for diluent haul-backs; that is, once the shipped crude reaches its destination, rather than sending an empty car back to Alberta, that same tank car could be sent back with diluent available for the market.

Figure 4.14: Diluent Import Requirements and Import Infrastructure (MBPD) 2007-2030

900 Diluent via Rail Haulbacks / New Pipelines / Demand Reduction / Potential Shortfall Northern Gateway Diluent Line 800 Southern Lights Pipeline Expansion Cochin Pipeline Reversal Southern Lights Pipeline 700 Kitimat Import Terminal Alberta Diluent Terminal 600 Redwater Nexus Terminal Required Imports 500

kb/d 400

300

200

100

- 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 HISTORICAL/ACTUAL OUTLOOK

Source: AER, CERI

Overall, diluent demand levels will be driven by the increasing production of crude bitumen blends rather than synthetic crude from oil sands operations. Given that demand is well above and beyond local production levels, diluent will continue to be imported in large volumes. Rail transportation of bitumen has the potential to reduce diluent demand depending on the type of blend/product transported but also to add to

July 2014 64 Canadian Energy Research Institute

the diluent pool supply by making use of diluent haul-backs. Last but not least, given the high level of import requirements it is important to survey the required infrastructure, which appears to be sufficient at the moment and until later in the projection period.

Capital Investment and Operating Costs Total capital spending requirements are broken down by project type and are illustrated in Figures 4.15. Over the 35-year projection period from 2014 to 2048 inclusive, the total initial and sustaining capital required for all projects is projected to be C$606.24 billion (11 percent higher than last year’s estimate) under the Reference Case Scenario. Capital investment in in situ projects surpasses the capital spent for mining projects, which is consistent with the ongoing trend to invest more into in situ projects rather than mining. From 2014 to 2048, it is projected that C$212.1 billion (initial and sustaining) will be invested into mining projects and C$339.9 billion in in situ thermal and solvent as well as primary and EOR cold bitumen projects. Upgrading projects see the least amount of capital spent from 2014 to 2048, amounting to C$54.3 billion.

Figure 4.15: Total Capital Invested (2014-2048) by Project Type – Reference Case Scenario

(Million CDN$) $350,000

$325,000

$300,000

$275,000

$250,000

$225,000

$200,000

$175,000

$150,000

$125,000

$100,000

$75,000

$50,000

$25,000

$0 Total In situ Thermal & Solvent Total Primary and EOR projects Total Mining Total Upgrading

Source: CERI, CanOils

Total cost requirements for the oil sands industry are presented in Figure 4.16. These include the initial and sustaining capital and operating costs for all types of projects. The total costs increase from the beginning of the forecast period, 2012 until 2019, at which

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 65

point initial capital starts to fall significantly, and hence the total costs flatten for the remainder of the forecast. As mentioned before, initial capital starts to decline by the end of the projection period. This does not reflect a slowdown in the oil sands, merely a lack of new capacity coming on stream, and relates back to CERI’s assumptions for project start dates, and announcements from the oil sands proponents. Under the Reference Case Scenario, the total annual costs peak in 2017 at C$68.4 billion. The total operating costs average C$39.9 billion a year and over the forecast period cumulatively add up to C$1,396 billion.

Figure 4.16: Total Cost Requirements – Reference Case Scenario

(Million CDN$)

75,000

70,000 Total Capital Costs Total Operating Costs

65,000

60,000

55,000

50,000

45,000

40,000

35,000

30,000

25,000

20,000

15,000

10,000

5,000

0 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 Source: CERI, CanOils

Alberta Oil Sands Royalty Revenues Figure 4.17 displays the breakdown of royalties collected by project type under the reference case over the 2014 to 2048 timeframe (on an annual and cumulative basis) and compares the results to the last published version of this study.17 Annual revenues amount to C$44.6 billion by 2048 in the Reference Case Scenario and cumulatively over C$1.0 trillion will be collected over the 35-year window.

17 CERI Study No. 133, May 2013: Canadian Oil Sands Supply Costs and Development Projects (2012-2046): http://ceri.ca/images/stories/2013-06-10_CERI_Study_133_-_Oil_Sands_Update_2012-2046.pdf

July 2014 66 Canadian Energy Research Institute

The Figure also illustrates a zoomed-in 10-year forecast of royalties from 2014 to 2024. Royalties are set to increase from 4.4 billion in 2013 to 19.6 in 2024, cumulatively adding to just over $120 billion by the end of 2024, all things being equal.

On a cumulative basis, bitumen royalties collected are 21 percent lower compared to last’s years study for a number of reasons. Let’s recall that changes in royalties are related to changes in project cash flows implying changes on the costs and revenues side of the ledger. On the cost side, overall operating and capital costs are higher compared to last year’s report, even though a lower condensate premium was observed in 2013 compared to 2012. On the revenues side, not only are overall production levels lower, but so are forecasted prices, while the WTI-WCS differential also widened further in 2013 compared to 2012 levels. Thus a combination of lower production levels, lower revenues, and higher project costs lead to overall lower royalty payments.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 67

Figure 4.17: Bitumen Royalties Collected by Project Type (2014-2048, $MM)

Annual ($MM) Cumulative ($MM) $60,000 $1,300,000 Primary/ EOR Mining $1,200,000 $55,000 In Situ Total Oil Sands Royalties $50,000 2013 Royalty Curve (Study No. 133) $1,100,000 Cumulative (2014 - 2048) (Right Scale) $1,000,000 $45,000 2013 Cumulative (Study No. 133) $900,000 $40,000 $800,000 $35,000 $700,000 $30,000 $600,000 $25,000 $500,000 $20,000 $400,000 $15,000 $300,000

$10,000 $200,000

$5,000 $100,000

$- $0

2015 2038 2007 2008 2009 2010 2011 2012 2013 2014 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 Historical/ Actual Outlook

Annual ($MM) Cumulative ($MM) $26,000 $130,000 $25,000 $24,000 Primary/ EOR $120,000 $23,000 $22,000 Mining $110,000 $21,000 In Situ $19,588 $20,000 $100,000 $19,000 Total Oil Sands Royalties $18,242

$18,000 $90,000 $16,603 $16,603 $17,000 Cumulative (2014 - 2048) (Right Scale) $16,000 $80,000 $15,000 $14,222 $14,000 $70,000

$13,000 $11,632 $11,632 $12,000 $60,000

$11,000 $10,005

$10,000 $50,000 $8,573 $8,573 $9,000

$8,000 $7,343 $40,000 $6,633 $6,633

$7,000 $5,581 $5,581

$6,000 $4,948 $30,000

$4,442 $4,442 $4,049 $4,049

$5,000 $3,718

$3,637 $3,637 $3,350 $3,350 $4,000 $3,009 $20,000

$3,000 $2,069 $2,000 $10,000 $1,000 $- $0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Historical/ Actual Outlook

Source: CanOils, CERI

Some important recent developments have been brought into consideration for this latest version of the oil sands update including volumes committed by the Government of Alberta’s Bitumen Royalty in Kind Program (BRIK). Given the fact that the provincial government may opt to take royalty payments in physical bitumen barrels (through

July 2014 68 Canadian Energy Research Institute

Alberta’s Petroleum Marketing Commission (APMC)) as opposed to monetary payments, it is important to consider the extent to which such an approach can have on the total dollar value of royalties collected by the province.

The top portion of Figure 4.18 displays the maximum volumes of BRIK supply available to the APMC which is calculated as the sum of the government’s royalty share of production from all non-integrated projects. While currently the government does not receive BRIK volumes, the potential volumes it could be receiving as royalty payments are estimated to be in the order of between 200 and 250 MBPD of bitumen. These volumes are estimated to reach a total of 1,266 MBPD by 2040, which implies that as a percentage total of the bitumen extracted, these volumes could account for about 25 percent of the total in the later part of the projection period. Currently, committed volumes under the BRIK program are estimated to reach about 138 MBPD by 2020 including 38 MBPD to the Redwater Refinery and 100 MBPD to the TCPL Energy East project.

Having an understanding of the potential volumes available to the provincial government and the expected volumes based on current commitments under the BRIK program in turn allows us to identify the potential in bitumen royalties collected in dollar terms. The bottom portion of Figure 4.18 displays the value of the total BRIK available volumes as well as the monetary value of the BRIK barrels committed to the Redwater Refinery and the Energy East project.

As a percentage of the potential royalties collected, the value of the available BRIK volumes could account for 60 percent of the total, while the 138 MBPD of BRIK volumes currently committed would account for about 7 percent of the total later in the decade.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 69

Figure 4.18: BRIK Volumes Availability and Commitments (MBPD) (Top) and Royalty Value ($MM) (Bottom) (2014-2048)

1,400 30%

1,200 25%

1,000 20%

800

15% %

kb/d Primary/EOR 600 Mining In Situ Non-integrated Projects Royalty Share = Max. BRIK Supply 10% 400 Committed BRIK Volumes Max BRIK Volumes % of Total Extracted Bitumen Committed BRIK Volumes % of Total Extracted Bitumen 5% 200

- 0%

2007 2024 2041 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2042 2043 2044 2045 2046 2047 2048 Historical/ Actual Outlook $30,000 70%

60% $25,000

50% $20,000

40%

$15,000 % ($MM) Primary/EOR 30% Mining $10,000 In Situ Non-integrated Projects Max. BRIK Supply Royalty Value 20% BRIK Committed Volumes Royalty Value Max. BRIK Volumes Royalty Value % of Total Royalties $5,000 Committed BRIK Volumes % of Total Royalties 10%

$- 0%

2021 2040 2046 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2041 2042 2043 2044 2045 2047 2048 Historical/ Actual Outlook Source: CanOils, CERI

The next step of this analysis is to understand the effect of taking in a given level of BRIK barrels as physical volumes rather than in the form of royalty payments on the total royalty payments collected by the province. Figure 4.19 displays the royalties collected by the provincial government under three different alternatives. The first case is one in which the government continues to receive all of its royalty payments in monetary form. The second case is one in which most royalties continue to be collected as monetary

July 2014 70 Canadian Energy Research Institute

payments, while 138 MBPD of BRIK barrels are received later in the decade. The final case assumes the government takes in all available BRIK volumes in kind.

Figure 4.19: Total Bitumen Royalties Collected Based on Different Levels of BRIK Volumes (2014-2048), $MM

Annual ($MM) Cumulative ($MM)

$50,000 OS Royalties w/o BRIK volumes (annual) $1,200,000 OS Royalties Net of Committed BRIK volumes (annual) $45,000 OS Royalties Net of Max. BRIK volumes (annual) $1,000,000 $40,000 OS Royalties w/o BRIK volumes (cumulative) OS Royalties Net of Committed BRIK volumes (cumulative) $35,000 OS Royalties Net of Max. BRIK volumes (cumulative) $800,000 $30,000

$25,000 $600,000

$20,000 $400,000 $15,000

$10,000 $200,000 $5,000

$- $0

2007 2012 2017 2008 2009 2010 2011 2013 2014 2015 2016 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 Historical/ Actual Outlook

Source: CanOils, CERI

The first case yields the same results displayed in Figure 4.17, which is the forecast of royalty revenues under the Reference Case Scenario, cumulatively adding up to C$1 trillion. Under the second case, about C$0.95 trillion in royalties is collected or 7 percent less than in the first case. In the last case, C$0.4 trillion is collected in royalties or 60 percent less than in the first case. It is important to highlight that this does not imply that the government will be foregoing 60 percent of the royalties collected in the latter case, but rather 60 percent of the royalties would not be collected in the form of direct payments from the producers, but instead in the form of bitumen barrels (over 1,200 MBPD in this case). In turn, the government will market those barrels and collect the revenue from such transactions. How much money will the government collect under such an alternative is difficult to estimate and beyond the scope of this report. Such a task would entail knowing what the government would do with those barrels, how much money would it get from each barrel and the cost to get those barrels to market. It is thus expected that if the government was to maximize the value of the resource for the owners (Albertans and Canadians) the government would take BRIK barrels and market them only if they can collect more money than the alternative of simply taking royalty payments, otherwise there is no incentive for the government to undertake such a task.

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 71

Chapter 5 Environmental Considerations for Oil Sands

Air and Emissions Greenhouse gas (GHG) emissions are a major 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 in 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 a number of potentially adverse outcomes such as changing climate patterns (for example, increased or decreased precipitation) and rising sea levels.

When placed in a global context, oil sands themselves are a relatively minor GHG 1 contributor. Globally in 2011, 34 billion tonnes of CO2 were emitted, while total Canadian emissions of CO2 were 556 Mt, or 1.6 percent of this value (EC 2013 NIR report). Overall, including non-CO2 gases such as methane (CH4) and nitrous oxide (N2O), Canada emitted 702 Mt of CO2 equivalents (CO2e) in 2011, and of these emissions, 55 Mt (7.8 percent) came from the oil sands sector.2 Thus, decreasing the emissions from the oil sands sector will do relatively little to GHG emissions on a global scale. However, the effects of the sector on Canada’s total emissions and ability to meet international commitments to GHG abatement are substantial. Canada has committed under the Copenhagen Accord of 2009 to decrease emissions to 17 percent below 2005 levels by year 2020. By 2020, oil sands emissions are projected to nearly double to 101 Mt, and total share of the oil sands sector to Canadian emissions are projected to increase from 4.6 percent in 2005 to 13.8 percent in 2020. Environment Canada currently estimates that emissions in 2020 will only be 0.4 percent below 2005 levels, compared to 9.5 percent below 2005 in the absence of GHG emissions growth in the oil sands sector. Increasing production in this sector makes the meeting of international commitments increasingly difficult, and thus there is interest in reducing the amount of GHG emitted to extract bitumen from the oil sands and generate synthetic crude oil.

There are two methods for looking at emissions performance. The first is to look at GHG emission intensity, which is the mass of emissions in CO2 equivalents per barrel of bitumen or synthetic crude oil produced. Emissions intensity is valuable for examining

1 Trends in Global CO2 Emissions: 2012 Report (2012), PBL Netherlands Environmental Assessment Agency. http://edgar.jrc.ec.europa.eu/CO2REPORT2012.pdf 2 Canada’s Emission Trends (2013), Environment Canada, Cat. No. EN81-18/2013E-PDF. http://www.publications.gc.ca/site/eng/449695/publication.html

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whether changes in operating conditions at a project level have been effective in light of changing production volume. The second is to look at the 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, but this metric is important to examine since the climate response of emissions will not depend on how much resource was extracted during the emission of these gases.

GHG data discussed hereafter is from the Environment Canada greenhouse gas reporting system3 and is available from years 2004 to 2011, while production data is obtained from the ERCB/AER statistical reports for mining and in situ oil sands production (ST394 and ST535, respectively).

Mining and Upgrading Emissions for the mining of bitumen and upgrading to synthetic crude oil (SCO) are shown in Figure 5.1. Between 2004 and 2011, reported GHG emissions have risen from 21.6 Mt CO2 equivalents to 28.8 Mt at an average rate of 1.2 Mt per year, or about 5.4 percent per year based on 2004 emissions.

However, production of mining operations has increased during this period, from about 219 million barrels of SCO in 2004 to 304 million barrels in 2011. Over this time, the GHG emission intensity has remained relatively constant; emission intensity in 2004 was about 99 kg CO2e per barrel of SCO and about 95 kg CO2e per barrel in 2011. Emission intensity has fallen by approximately 0.7 percent per year on average, which is indistinguishable from the year-to-year variability in emissions intensity (the relative standard deviation of emissions intensity is about 3 percent).

3 Facility Greenhouse Gas Reporting, Environment Canada. http://www.ec.gc.ca/ges- ghg/default.asp?lang=En&n=040E378D-1 4 http://www.aer.ca/data-and-publications/statistical-reports/st39 5 http://www.aer.ca/data-and-publications/statistical-reports/st53

July 2014 Canadian Oil Sands Supply Costs and Development Projects (2014-2048) 73

Figure 5.1: Bulk GHG Emissions and GHG Emission Intensities for Oil Sands Mining Projects, 2004 – 2011

35 140

30 120

eq)

2

25 100

20 80

eq/bbl SCO) eq/bbl

15 60 2

10 40 CO (kg GHG GHG emissionintensity

Total GHG emissions CO (Mt 5 20

0 0 2004 2005 2006 2007 2008 2009 2010 2011

Total GHG Emission intensity

Source: Environment Canada (Facility Greenhouse Gas Reporting), AER (ST 39).

Due to the method of Suncor reporting, these GHGs are not entirely restricted to emissions from mining activities. Between 2004 and 2008, emissions from the Firebag SAGD project are included with the Suncor base mine values, while the project emissions also include GHGs associated with the upgrading of Firebag bitumen and, as of 2009, MacKay River SAGD bitumen. It is difficult to isolate the impact, but it could be significant; between 2004 and 2008, Firebag contributed between 4 and 13 percent of the bitumen upgraded at Suncor, and between 2009 and 2011, Firebag and MacKay River contributed between 21 percent and 24 percent of the upgraded bitumen. The Suncor base mine was responsible for a sizable portion (between 29 percent and 40 percent) of all emissions from mining and upgrading in the 2004 to 2011 period. The extraction process for obtaining bitumen from oil sands ore is relatively mature, and as such, there have been many practices already adopted to decrease the amount of energy used, and thus the amount of greenhouse gases emitted. The use of hydro transport has reduced the amount of energy required to transport mined ore to the central processing facilities, and over time the temperature required for the Clark hot water extraction process used to separate bitumen from the oil sands ore has fallen, reducing the amount of energy required for heating extraction water. The solvent used for bitumen froth treatment can also affect energy requirements. Using paraffinic solvents rather than the typical naphtha allows separation of contaminants such as

July 2014 74 Canadian Energy Research Institute

asphaltenes during the froth treatment, which reduces or eliminates the requirement for energy intensive upgrading prior to pipeline shipment.

Further reductions in emissions are expected as the Shell Quest carbon capture and storage (CCS)6 project comes online. The project is expected to capture up to 35 percent of the Shell Scotford upgrader emissions (more than 1 Mt of CO2) to be stored permanently underground.

In Situ Emissions from in situ oil sands projects are shown in Figure 5.2. The discussion of in situ emissions that follows excludes emissions from the Nexen/CNOOC Long Lake integrated in situ extraction and upgrading project. The technology used at Long Lake differs significantly from that used by other in situ projects and is significantly more emissions intensive than the average in situ producer (290 kg CO2e per barrel of SCO during 2011).

Reported greenhouse gas emissions for commercial in situ bitumen have risen, on average, by about 1.3 Mt CO2 eq per year between 2004 and 2011, or about 16 percent per year based on 2004 emissions. Emissions intensity, however, fell during this time by an average of 1.8 kg CO2 eq per barrel of bitumen extracted each year, or 3 percent of the 2004 emission intensity.

Figure 5.2: Bulk GHG Emissions and GHG Emission Intensities for Oil Sands In Situ Projects, 2004-2011

20 125

eq)

2 16 100

12 75 eq/bblbitumen)

8 50

2 GHG GHG emissionintensity

4 25 CO (kg Total GHG emissions CO (Mt

0 0 2004 2005 2006 2007 2008 2009 2010 2011

Total GHG Emission intensity

Source: Environment Canada (Facility Greenhouse Gas Reporting), AER (ST 53).

6 Details on the Quest CSS project may be found at http://www.shell.ca/en/aboutshell/our-business- tpkg/upstream/oil-sands/quest.html

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Much of the reduction in GHG emissions intensity has come during the 2009 through 2011 period. This time period coincides with several new commercial SAGD projects coming online. However, the emissions intensities for old (production commencing prior to the beginning of GHG reporting in 2004) and new (production commencing after 2004) during this time period are quite similar, indicating that the drop in emissions intensity is a general trend and not the result of new, lower-emissions projects coming online.

GHG emissions for in situ projects arise primarily from fuel burning to generate steam for the thermal extraction process. Thus, any action that reduces the steam-oil ratio (SOR; the amount of cold water required to generate steam to extract one unit of bitumen) will serve to reduce the emissions intensity of the project. The recent drop in GHG emission intensities has been accompanied by a fall in the average SOR of all commercial in situ projects; the production-weighted average SOR was 3.6 in 2008 compared to 2.8 in 2011. Much of what determines SOR is simply a matter of finding a high quality reservoir, but changes in the extraction technologies have also aimed to either reduce steam requirements or increase oil recovery.

Vapour extraction (VAPEX) and solvent-assisted SAGD make the use of low-viscosity solvents miscible with bitumen to increase the flow rate of in situ bitumen, eliminating or reducing the need for steam. This technique has been shown to be effective in some cases, such as test wells used at Cenovus’ Christina Lake project, but there are currently few solid examples of the efficacy of using solvents in the SAGD process. Whether or not it becomes commercially viable depends heavily on factors such as solvent cost and recovery of the solvent from the reservoir. Another Cenovus technique, the use of wedge wells, uses additional recovery wells located in between producing well pairs to increase the area of oil recovery and thus increase the amount if bitumen recovered from the same amount of steam injection. Other methods, such as Toe-to-Heel Air Injection (THAI), have been piloted, but results suggest these techniques are far from being reliable enough for commercial applications at this point.

While step-changes in extraction methods are likely necessary for a drastic reduction in GHG emissions, more efficient use of energy within the existing SAGD process can reduce emissions in the short term. One common method is the use of cogeneration at in situ projects. Cogeneration involves using natural gas to both generate electricity to be used onsite and heat for steam generation. Cogeneration facilities can generate electricity and heat more efficiently than separate generator and steam facilities. In addition, it reduces demand for electricity from the Alberta grid, which relies heavily on carbon-intensive coal-fired generators. Canada’s Oil Sands Innovation Alliance (COSIA)

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also reports the testing of gas-turbine once through steam generators, which generate electricity and steam more efficiently than cogeneration facilities.7 Water Use and Tailings Ponds Management Both mining and in situ oil sands projects rely on water for the extraction of bitumen. The different processes used lead to unique challenges in fluid management. While oil sands mining water management is primarily concerned with the treatment of solid tailings, in situ water management is primarily an issue of water treatment for feed to steam generators. Water usage data is obtained from Alberta Environment and Sustainable Resource Development8 and production data is obtained from AER ST39 and ST53.

Mining The process of extracting bitumen from raw oil sands ore requires a substantial amount of water. Although water used in processing bitumen ore can be recycled, loss of water through evaporation and non-reusable water associated with some mine tailings lead to a requirement for fresh water use. Based on reported water consumption from all oil sands mines and reported synthetic crude oil production rates, an average of 3.2 barrels of fresh water were consumed for every barrel of synthetic crude oil produced between 2005 and 2013 (see Figure 5.3).

Figure 5.3: Fresh Water Usage by Oil Sands Mining Operations, 2005-2013

4.00 5.00

3.00 3.75

2.00 2.50

1.00 1.25

Wateruse intensity(bbl/bbl) Freshwater use (million perbbl day) 0.00 0.00 2005 2006 2007 2008 2009 2010 2011 2012 2013

Fresh water usage Water use intensity

Source: Alberta Environment and Sustainable Resource Development (Oil Sands Operators: Water Use History), AER (ST 39).

7 http://www.cosia.ca/initiatives/greenhouse_gases/gas-turbine-once-through-steam-generator 8 Oil Sands Operators: Water Use History, Alberta Environment and Sustainable Resource Development. http://environment.alberta.ca/apps/OSIPDL/Dataset/Details/56

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The amount of water that can be recycled in mining operations is related to the management of fluid tailings. Tailings are the spent water mixture that results from the bitumen extraction process, and consists of a mixture of water, sand, fine clay particles, and residual oil and organic matter from the bitumen. The extraction process results in the formation of fine clay particles with high negative surface charges. Fine clay particles tend to settle very slowly initially due to their small size, and tend to stop settling and compacting over time due to electrostatic repulsion of like charges on the surface of the particles.9 As a result, when tailings are discharged to ponds, large sand particles tend to settle to the bottom relatively quickly, while clay particles tend to form a sludge-like mixture referred to as mature fine tailings or MFT.10 Around 1.5 barrels of MFT are generated for each barrel of bitumen produced.11

MFT present an important environmental management issue from the perspectives of water usage, land usage, and land reclamation. The time period from the initial formation of MFT to total consolidation is estimated to be in the range of several decades or longer. In addition to the water contained within these tailings, a large water cap is needed to prevent the tailings from being disturbed in the event of mixing from winds. As of 2013, according to tailings management plans, approximately 950 million cubic metres (about 6 billion barrels) of MFT are present in tailings ponds, containing a large volume of water that could otherwise be recycled back into the extraction process. Furthermore, the consistency of MFT is such that they lack the physical strength to support capping by sand or soil, which prevents dry reclamation of land covered with fluid tailings. The longer it takes for fluid tailings to consolidate into a form that can be reclaimed, the more land will be needed to be covered with tailings ponds to contain the volume of fines (defined as solids less than 44 micrometres in diameter) and water prior to final reclamation.

The AER (formerly known as the ERCB) put forth Directive 74 (Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes)12 in 2009 to address tailings management by oil sands mines. The directive requires oil sands mines to form designated disposal areas for the capture of fine tailings and reduce the amount of fines released to tailings ponds. Captured fines are required to be trafficable; that is, the fines must be sufficiently load-bearing to support eventual dry reclamation. Required fines capture rates were 20 percent in the July 2010-June 2011 period, increasing to 30 percent for the July 2011-June 2012 period and 50 percent annually thereafter. The techniques or technologies used to meet the directive are decided by the individual

9 Taylor M. L. et al. (2002). Kinetics of adsorption of high molecular weight anionic poloacrylamide onto kaolinite: the flocculation process. Journal of Colloid and Interface Science 250, 28-36. 10 Allen E. W. (2008). Process water treatment in Canada’s oil sands industry: I. Target Pollutants and treatment objectives. Journal of Environmental Engineering and Science 7, 123-138. 11 Tailings, a Lasting Oil Sands Legacy (2010), WWF Canada. http://awsassets.wwf.no/downloads/tailings__a_lasting_oil_sands_legacy___wwf.pdf 12 http://www.aer.ca/rules-and-regulations/directives/directive-074

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operators. Annual reports are to be submitted to the regulator to determine compliance.

The AER released an update assessing the performance of Directive 74 in 2013.13 For the first two reporting periods, four mining projects were required to capture fines. Three projects were allowed reduced targets as tailings management was implemented. Table 5.1 summarizes the tailings reduction performance for the first two reporting periods.

Table 5.1: Required Fines Disposal Under Directive 74 and Mine Performance July 2010 – June 2011 July 2011 – June 2012

Project Requirement Performance Requirement Performance

Suncor 20.0 10.7 30.0 8.5

Syncrude Mildred Lake 9.2 17.7 12.0 8.8

Shell Muskeg River 8.5 1.9 23.5 8.8

Shell Jackpine 9.5 0.0 15.5 0.0

Source: AER (2012 Tailings Management Assessment Report).

With the exception of the first reporting period for Syncrude Mildred Lake, all mines have significantly underperformed in comparison to the required fines capture rates at this time. The report notes some of the issues that the industry has come across at this point and has opted not to utilize enforcement measures until the success of mitigating measures can be assessed. The next report on tailings management from the AER is expected in 2015, at which point the regulator notes that enforcement options will be examined if fines capture continues to underperform.

Directive 74 does not prescribe any particular method for fines capture, and as such there are multiple methods by which mines have gone about achieving these directives. Consolidated or composite tailings (CT) mixes mature fine tailings with sand from extracted ore and gypsum, which speeds up the release of water and the thickening of fine tailings, and is used at Syncrude, Shell Muskeg River, and previously by Suncor. Polymer flocculents (agents which cause fine clay particles to aggregate) are also used, such as Suncor’s Tailings Reduction Operation (TRO) and Shell Muskeg River’s atmospheric fines drying (AFD). The polymer flocculents thicken the fine clay particles, allowing the tailings to be dried using thin lifts. Shell Jackpine uses a thickened tailings (TT) process, using a thickening agent before disposing of fine tailings. Large-scale

13 2012 Tailings Management Assessment Report: Oil Sands Mining Industry (2013), Energy Resources Conservation Board. http://www.aer.ca/documents/oilsands/tailings-plans/TailingsManagementAssessmentReport2011-2012.pdf

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centrifuges are also used to mechanically thicken MFT; this process is in use at Syncrude and Shell Muskeg River.

In Situ In situ oil sands extraction relies on the use of steam to heat bitumen in the reservoir, decreasing its viscosity to the point that it can be pumped to the surface. The amount of water required for the extraction process is dictated by the steam-to-oil ratio; the weighted average from 2004 through 2011 for in situ commercial projects is about 3.4 barrels of cold water equivalents in steam for every barrel of bitumen produced. The source water for steam production has three primary sources: fresh water, which may be taken from surface water or groundwater sources; brackish water, which is saline groundwater with total dissolved solids (TDS) higher than 4000 milligrams per litre; and produced water, which is water extracted from the oil production well that is a combination of condensed steam and existing groundwater in the oil reservoir. As produced water can be recycled, the actual makeup water required from fresh and brackish sources is considerably less than the amount of steam required. As tailings are not an issue for in situ extraction, the amount of process water that can be recycled is also higher than for mining, reducing the amount of required makeup water. Between 2002 and 2013, an average of 0.93 barrels of makeup water were used for every barrel of bitumen produced by commercial SAGD and CSS operations. As with GHG emissions, the discussion of in situ water usage will exclude data from the Nexen/CNOOC Long Lake project due to the different production techniques used at that facility and focus on non-integrated commercial bitumen production.

Makeup water usage is shown in Figure 5.4. Although bitumen production by in situ methods was roughly 4.5 times higher in 2013 than in 2002 (the first year that water usage is reported by Alberta Environment), total makeup water usage was only 2.2 times higher in 2013 compared to 2002. Most of this increase in makeup water has come from a greater reliance on brackish water, as fresh water use was only 1.1 times higher in 2013 compared to 2002. While almost all makeup water was fresh in 2002, brackish water now accounts for about half of the total makeup water used for in situ projects.

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Figure 5.4: Fresh and Brackish Water Use by In Situ Oil Sands Producers

600 1.50

500 1.25

400 1.00

300 0.75

200 0.50

100 0.25

Makeupwaterintensity use (bbl/bbl) Makeupwater usage (thousands bbl/day) 0 0.00 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Fresh used Brackish Used Fresh intensity Brackish intensity

Source: Alberta Environment and Sustainable Resource Development (Oil Sands Operators: Water Use History), AER (ST 53).

In addition to increased reliance on brackish water, the overall use of makeup water has dropped considerably for each barrel of bitumen produced. In 2013, 0.53 barrels of makeup water were required to extract one barrel of bitumen, down from a maximum of 1.23 barrels of makeup water during the 2002-2013 period.

In Situ Water Regulations The AER and the former ERCB have sought to encourage the reduction of water use, and in particular the amount of fresh water required for steam generation at in situ sites. In previous years, recycling of process water was required through IL 89-5 for in situ producers requiring more than 500,000 m3 of fresh water per year. Water recycle rates were determined based on the amount of produced water and fresh makeup water used compared to the total steam injected into the well. The recycle rate was calculated using the following formula:14

14 Formula obtained from http://www.pembina.org/pub/612.

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Recycle rates can be calculated using publicly available data as of 2009 when the then- ERCB started reporting produced water and steam volumes with the statistical report ST 53 (Alberta Crude Bitumen In Situ Production Monthly Statistics) combined with fresh water use from Alberta Environment. Recycle rates, shown in Table 5.2 have fallen slightly from 96 percent in 2009 to 94 percent in 2012.

Table 5.2: IL 89-5 Based Recycle Rates and Directive 81 Based Disposal Limits and Rates Year Recycle Rate Disposal Limit Overall Disposal Rate (%) (%) (%)

2009 96.1 10.7 8.9

2010 94.8 10.6 9.3

2011 92.2 10.3 10.9

2012 93.7 10.8 --

2013 93.6 10.4 --

Source: AER (In Situ Performance Presentations, ST 53); Alberta Environment and Sustainable Resource Development (Oil Sands Operators: Water Use History); and CERI.

Currently, regulations to curb the use of makeup water (that is, additional surface or ground water to generate steam beyond recycled produced water) take the form of a water disposal limit. Water usage is addressed in Directive 81: Water Disposal Limits and Reporting Requirements for Thermal In Situ Oil Sands Schemes.15 This directive sets a limit on the volume of liquid disposal based on the amount of fresh, brackish, and produced water used by a facility. The disposal limit is calculated from the following formula:

Df, Db, and Dp are disposal factors given for fresh, brackish, and produced water, respectively. Disposal factors are specified for SAGD and CSS operations and are listed in Table 5.3. Produced water recycle requirements for SAGD are slightly less stringent than for CSS since the former uses dry steam for well injection (that is, steam free of liquid water). Since blowdown water, the term for liquid water that remains after steam

15 http://www.aer.ca/rules-and-regulations/directives/directive-081

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production, must be recycled by SAGD operators and contains relatively high concentrations of dissolved solids, the disposal requirements for produced water are set lower than for CSS operators (see Table 5.3).

Table 5.3: Disposal Factors for Thermal In Situ Oil Sands Producers Disposal Water Type SAGD CSS Factor

Df Fresh water 0.03 0.03

Db Brackish water 0.35 0.35

Dp Produced water 0.10 0.07

Source: AER Directive 81.

The actual disposal rate is calculated by dividing the volume of water disposal by the total fresh, brackish, and produced water input into a facility. The directive applies only to operations requiring greater than 500,000 cubic metres of makeup water per year in absence of produced water recycle, as to exclude pilot projects. Although Directive 81 does not mandate an overall disposal rate for in situ producers, for the interest of this discussion the average disposal limit and disposal rate are shown in Table 5.2. Disposal rates are calculated using data obtained from in situ annual progress reports.16 In 2011, the actual disposal rate slightly exceeded the limit determined using the Directive 81 formula.

The calls for both higher water recycling rates and increased use of brackish water have led to a change in the steam and water treatment and steam generation processes. Water treatment was typically accomplished using warm-lime softening, followed by steam generation using once through steam generators (OTSGs). OTSGs are typically used in conjunction with warm lime softening as they can handle the higher solids content in the water characteristic of this treatment process. However, the higher solids content also leads to a greater amount of high-solids wastewater, and thus lower water recycle rates. Recycle rates can be higher when treating water using an evaporator, which produces cleaner distilled feedwater for steam generation. An additional advantage is that feedwater from an evaporator has a low enough solids content to be used in conventional drum boilers, which can significantly lower the capital cost of SAGD operations. While the evaporator-boiler setup can increase water recycle rates, it does have the tradeoff of being more energy intensive than warm lime softening and OTSGs, and thus will have adverse effects on GHG emissions in SAGD operations.

16 http://www.aer.ca/data-and-publications/activity-and-data/in-situ-performance-presentations

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Update on Monitoring Programs Environmental effects monitoring has been a somewhat contentious issue in the oil sands region. Monitoring has been carried out by a number of different entities, including the Cumulative Effects Management Association (CEMA), the Wood Buffalo Environmental Association (WBEA), and the Regional Aquatic Monitoring Program (RAMP). Monitoring under CEMA has typically taken the form of short-term sponsored studies to support environmental management frameworks in the region, while WBEA and RAMP have supported long-term monitoring of air and water in the region, respectively.

Criticisms of the state of monitoring, particularly in the case of RAMP,17 have led to the recent agreement between the provincial and federal governments to coordinate efforts. The Joint Oil Sands Monitoring (JOSM) implementation plan was announced in February 2012 and is to be fully implemented by 2015. The JOSM has its roots in a December 2010 report to the federal Minister of the Environment from an Oil Sands Advisory Panel charged with examining the state of environmental monitoring in the Lower Athabasca River Basin.18 The Panel reported that significant monitoring activities were carried out in the region for the purpose of studying air quality, water quality, land disturbance and biodiversity. However, the activity was substantially lower than previous large scale monitoring efforts such as the effects of acid deposition in eastern Canada, and that existing monitoring failed to create any consensus on the degree of environmental impact in the region. Their recommendation was to create a management framework for the coordination of monitoring activities with “aligned priorities, policies and programs” that is integrated across environmental media, time, and agencies.

Detailed documents outlining the scope of the expanded monitoring program were released in 2011. The first, the Lower Athabasca Water Quality Monitoring plan,19 outlines plans with respect to the monitoring of surface and groundwater quantity and quality. This was followed by the Integrated Oil Sands Monitoring Plan,20 which includes components on expansion of the water monitoring program, aquatic effects and

17 RAMP 2010 Scientific Peer Review. http://www.ramp- alberta.org/ramp/results/ramp+2010+scientific+peer+review.aspx 18 A Foundation for the Future: Building an Environmental Monitoring System for the Oil Sands (2010). Oilsands Advisory Panel, Environment Canada, Cat. No. EN4-148/2010E-PDF. http://publications.gc.ca/site/eng/392384/publication.html 19 Lower Athabasca Water Quality Monitoring Plan Phase 1 (2011), Environment Canada, Cat. No. EN14-42/2011E- PDF. http://publications.gc.ca/site/eng/390667/publication.html 20 An Integrated Oil Sands Monitoring Plan (2011), Environment Canada, Cat. No. EN14-47/2011E-PDF. http://publications.gc.ca/site/eng/396679/publication.html

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biodiversity, and acid sensitive lakes,21 air quality monitoring,22 and terrestrial biodiversity.23 These documents outline the future scope of the adaptive monitoring program such as sampling sites, physical and chemical measurements needed, and intensive monitoring campaigns required to expand current knowledge. The program is designed to integrate different environmental media together during monitoring and is designed to meet three core results: assessment of accumulated environmental conditions; assessment of the relationship between environmental response and drivers within the system; and assessment of cumulative ecological and environmental effects. The documents were written and reviewed by an extensive list of scientists from government, academia, and monitoring agencies, and are quite detailed in scope.

In 2012, the governments of Alberta and Canada released the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring.24 In the document, a three-year timeline outlining the establishment of the integrated plan is detailed, with full implementation to be achieved by 2015. The agencies responsible for the particular monitoring projects are unclear in the document, but overall current and developing monitoring arrangements were to be co-led by the provincial and federal governments. Annual reports were to be published about the status of the implementation process, with a peer review to occur after implementation is complete.

While the integrated monitoring plan itself is detailed and comprehensive, the status of implementation is somewhat difficult to assess. A data portal has been established for the program,25 although there is currently little data available as the data management system is still being established. Neither the data portal nor the provincial of federal government websites have any evidence of annual reports detailing the progress on implementation of the monitoring program, as was suggested in the implementation plan. News releases on the data portal are limited to announcements of a Queen’s University/Environment Canada study finding increasing lake contamination in the oil sands region,26 announcement of the data portal itself,27 and an intensive ground- and aircraft-based air monitoring study in August-September 2013 as part of the air quality component of the plan.28

21 Integrated Monitoring Plan for the Oil Sands: Expanded Geographic Extent for Water Quality and Quantity, Aquatic Biodiversity and Effects, and Acid Sensitive Lake Component (2011), Environment Canada, Cat. No. EN14-49/2011E- PDF. http://publications.gc.ca/site/eng/396888/publication.html 22 Integrated Monitoring Plan for the Oil Sands: Air Quality Component (2011), Environment Canada, Cat. No. EN14- 45/2011E-PDF. http://publications.gc.ca/site/eng/394253/publication.html 23 Integrated Monitoring Plan for the Oil Sands: Terrestrial Biodiversity Component (2011), Environment Canada, Cat. No. EN14-48/2011E-PDF. http://publications.gc.ca/site/eng/396865/publication.html 24 Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring (2012), Government of Canada and Government of Alberta. http://www.jointoilsandsmonitoring.ca/default.asp?lang=En&n=D876B1A8-1 25 www.jointoilsandsmonitoring.ca 26 Smol study on PAH contamination 27 http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-1&news=859F236E-422D-4678-9067-FE4C31CFC856 28 http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-1&news=D1490330-B65A-4711-8A89-DE917ACCBD29

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While there is a lack of direct communication on the progress of monitoring implementation, this is not to say that no progress has been made. The information portal includes an interactive map29 that shows monitoring sites established under the program and, eventually, should link to data collected at each site. Certainly, a number of sites related to water, sediments, benthic invertebrates, fish monitoring, biological contamination, and air quality have been established since 2011, and there are a number of sites listed as planned on the map as well. However, in the absence of a transparent update, it is currently difficult to determine to what extent the monitoring program has been established.

One recent area of progress for the JOSM has been the establishment of a funding mechanism with the passing of Bill 21: the Environmental Protection and Enhancement Amendment Act in 2013. The bill allows for the provincial government to collect from industry the $50 million per year required for the initial expansion of monitoring in the region.

AEMERA In March 2012, the Alberta government formed the Alberta Environmental Monitoring Working Group to provide recommendations for the governance and funding of a new provincial environmental monitoring, evaluation and reporting system. The report30 recommended the establishment of a science-based, neutral, and arm’s length provincial agency charged with establishing province-wide environmental monitoring under Alberta’s Land Use Framework. The arm’s length model was recommended based on the potential for the greatest amount of legitimacy, credibility, and stakeholder support. The working group made twelve recommendations for the monitoring system, including its mandate, values and principles, arm’s length structure, funding, and implementation.

To carry out the provincial portion of the monitoring activities, the Alberta Environmental Monitoring, Evaluation and Reporting Agency (AEMERA) was established. The agency came into existence by the passing of Bill 31: Protecting Alberta’s Environment Act, which came into effect in April 2014. The current status of AEMERA is that it has been officially established and a Board of Directors has been appointed. The success of the implementation will need to be examined as the agency establishes itself and takes over monitoring activities from the Ministry of Environment and Sustainable Resource Development.

29 http://www.jointoilsandsmonitoring.ca/flex/index.html 30 Implementing a World Class Environmental Monitoring, Evaluation and Reporting System for Alberta: Report of the Working Group on Environmental Monitoring, Evaluation and Reporting (2012), Alberta Environmental Monitoring Working Group. http://environment.gov.ab.ca/info/library/8699.pdf

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