Study No. 133 May 2013

CANADIAN CANADIAN OIL SANDS SUPPLY ENERGY RESEARCH COSTS AND DEVELOPMENT INSTITUTE ROJECTS P (2012-2046)

Canadian Energy Research Institute | Relevant • Independent • Objective

CANADIAN OIL SANDS SUPPLY COSTS AND DEVELOPMENT PROJECTS (2012-2046)

Canadian Oil Sands Supply Costs and Development Projects (2012-2046)

Copyright © Canadian Energy Research Institute, 2013 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute

ISBN 1-927037-12-6

Authors: Dinara Millington Carlos A. Murillo

Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to Paul Kralovic of Kralovic Economics Inc., 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

May 2013 Printed in Canada

Front Cover Photo Courtesy of Cenovus Energy Canadian Oil Sands Supply Costs and Development Projects (2012-2046) iii

Table of Contents

LIST OF FIGURES ...... vii LIST OF TABLES ...... xi EXECUTIVE SUMMARY ...... xiii Supply Cost Results ...... xiii Supply Cost Sensitivities ...... xiv Projection Results – Three Scenarios ...... xvii Oil Sands Production ...... xvii Oil Sands Capital Investment ...... xix Natural Gas Requirements ...... xxi Oil Sands Emissions ...... xxii Oil Sands Royalties ...... xxiii Pipeline Transportation ...... xxv Markets ...... xxv CHAPTER 1 INTRODUCTION ...... 1 Background ...... 1 Approach ...... 2 Organization of the Report ...... 3 CHAPTER 2 OIL SANDS OVERVIEW ...... 5 Oil Sands, Background ...... 5 Oil Sands Development Scenarios ...... 8 CHAPTER 3 OIL SANDS SUPPLY COSTS ...... 15 Introduction ...... 15 Methodology and Assumptions ...... 15 Design Assumptions ...... 16 Light-Heavy Differential...... 21 Crude Oil Transportation Costs ...... 26 Economic and Taxation Assumptions...... 26 Royalty Assumptions ...... 29 Canadian-US Exchange Rate ...... 30 Supply Cost Results ...... 31 Supply Cost Sensitivities ...... 34 CHAPTER 4 OIL SANDS PROJECTIONS ...... 39 Methodology and Assumptions ...... 39 Delay Assumptions ...... 40 Estimating Inflation ...... 41 Estimating Royalty Revenues and Blending Requirements ...... 42 Oil Sands Projections – Three Scenarios ...... 43 Oil Sands Capacity ...... 43

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Oil Sands Production ...... 45 Oil Sands Capital Investment ...... 47 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 ...... 67 Alberta Oil Sands Royalty Revenues ...... 69 CHAPTER 5 TRANSPORTATION ...... 73 West Coast and the Gulf Coast ...... 73 Bottlenecks in the System ...... 74 Enbridge Lakehead System South of Clearbrook/Superior ...... 75 TransCanada Keystone XL ...... 76 Kinder Morgan Express-Platte ...... 76 Continental Inland Expansions, Extensions, and Conversions...... 76 Rail, Rail and More Rail ...... 79 CHAPTER 6 MARKET DIVERSIFICATION ...... 83 Potential Netbacks for Oil Sands Crudes and Pricing Dynamics ...... 83 APPENDIX A METHODOLOGY AND ASSUMPTIONS ...... 93 Canadian-US Exchange Rate ...... 93 Cost Inflation ...... 95 Oil Sands Construction Cost Inflation ...... 95 Oil Sands Operating Cost Inflation ...... 97 Cash Flow Methodology ...... 99 APPENDIX B EXISTING CRUDE OIL PIPELINES IN WESTERN CANADA ...... 103 Export Pipelines ...... 104 Keystone Pipeline – TransCanada Pipelines ...... 104 Trans Mountain Pipeline (TMX) – Kinder Morgan Canada ...... 105 Express-Platte Pipeline – Spectra Energy ...... 107 Enbridge Canadian Mainline – Enbridge ...... 108 Alberta Clipper and Southern Lights Pipelines – Enbridge ...... 112 Rangeland Pipeline – Plains Midstream ...... 115 Bow River Pipeline – Inter Pipeline Fund ...... 116 Cochin Pipeline – Kinder Morgan Canada ...... 117 Regional Pipelines ...... 119 Pembina Oilsands Pipelines – Pembina Pipeline Corporation ...... 119 Inter Pipeline Oilsands – Inter Pipeline Fund ...... 122 Enbridge Athabasca Pipeline – Enbridge ...... 126 Enbridge Waupisoo Pipeline – Enbridge ...... 129 Access Pipelines – Devon/MEG ...... 130

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Suncor Oil Sands Pipeline – Suncor Energy ...... 132 Norealis Pipeline Project – Enbridge Pipelines and Husky Oil ...... 133 Woodland Pipeline Project – Enbridge Pipelines ...... 134 Wood Buffalo Crude Pipeline Project – Enbridge Pipelines and Suncor ...... 135 ECHO Pipeline – Canadian Natural Resources Ltd...... 135 Husky Pipelines – Husky Energy ...... 137 Rainbow Pipeline I and II – Plains Midstream ...... 138 Pembina Conventional Pipelines – Pembina Pipeline Corporation ...... 140 Conventional Oil Pipelines – Inter Pipeline Fund ...... 142 Enbridge (NW) System – Enbridge ...... 144 Enbridge Saskatchewan System – Enbridge ...... 145

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List of Figures

E.1 Total Field Gate Bitumen/SCO Supply Costs – Reference Case Scenario ...... xiv E.2 Supply Cost Sensitivity – 50-well Primary Recovery Project ...... xv E.3 Supply Cost Sensitivity – 30 MBPD SAGD Project ...... xv E.4 Supply Cost Sensitivity – 100 MBPD Integrated Mining, Extraction and Upgrading Project ...... xvi E.5 Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project ...... xvi E.6 Supply Cost Sensitivity – Carbon Prices ...... xvii E.7 Bitumen Production Projections ...... xix E.8 Initial Capital Requirements ...... xx E.9 Sustaining Capital Requirements ...... xxi E.10 Natural Gas Requirements ...... xxii E.11 Greenhouse Gas Emissions ...... xxiii E.12 Oil Sands Royalties – Three Scenarios ...... xxiv E.13 Alberta Oil Sands Royalties – Reference Case Scenario ...... xxv 2.1 Alberta’s Oil Sands Areas ...... 6 2.2 Mining and Extraction ...... 7 2.3 In Situ – SAGD ...... 7 2.4 US and BRIC Oil Consumption, Shares of Total Oil Consumption ...... 9 2.5 Oil Price Forecast – Reference Case Scenario ...... 10 2.6 Emissions Compliance Costs – Reference Case Scenario ...... 11 3.1 Henry Hub Natural Gas Price Forecast ...... 20 3.2 Average Wholesale Electricity Price in Alberta Power Pool Forecast ...... 21 3.3 Densities and Sulfur Content of Crude Oils ...... 22 3.4 Estimated Refinery Yields by Crude and Refinery Complexity ...... 23 3.5 Light-Heavy Differentials ...... 25 3.6 Alberta Bitumen Royalty Rates ...... 30 3.7 Total Field Gate Bitumen/SCO Supply Costs – Reference Case Scenario ...... 32 3.8 Oil Sands Supply Costs – Reference Case Scenario ...... 33 3.9 Supply Cost Sensitivity – 50-well Primary Recovery Project ...... 35 3.10 Supply Cost Sensitivity – 30 MBPD SAGD Project ...... 35 3.11 Supply Cost Sensitivity – 100 MBPD Integrated Mining, Extraction and Upgrading Project ...... 36 3.12 Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project ...... 36 3.13 Supply Cost Sensitivity – Carbon Prices ...... 37 4.1 Bitumen Royalty Drivers ...... 42 4.2 Bitumen Capacity Projections ...... 44 4.3 Bitumen Production Projections ...... 47 4.4 Initial Capital Requirements ...... 48 4.5 Sustaining Capital Requirements ...... 50 4.6 Natural Gas Requirements ...... 51

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4.7 Greenhouse Gas Emissions ...... 54 4.8 Oil Sands Royalties ...... 56 4.9 Bitumen Production Forecast – Comparison ...... 57 4.10 Bitumen Production by Extraction Type – Reference Case Scenario ...... 58 4.11 Net Bitumen and SCO Production by Project Status Reference Case Scenario ...... 59 4.12 Non-upgraded Bitumen and SCO Shares of Total Volumes to Market ...... 60 4.13 Diluents Demand Projection – Reference Case Scenario ...... 61 4.14 Oil Sands Blend Diluent Requirements and per Barrel Net Revenues ...... 63 4.15 Pentanes Plus/Condensate Supply and Demand in the WCSB ...... 64 4.16 Current and Proposed Pipeline Capacities for Diluent Imports ...... 65 4.17 Railbit Transportation Options and changes to Diluent Import Requirements ...... 67 4.18 Total Capital Invested by Project Type – Reference Case Scenario ...... 68 4.19 Total Cost Requirements – Reference Case Scenario ...... 69 4.20 Alberta Oil Sands Royalties, Revenues Collected and Outlook ...... 70 4.21 Alberta Oil Sands Royalties, 2007-2046 ...... 72 5.1 Enbridge’s Mainline Enhancement – US ...... 75 5.2 Enbridge – Gulf of Mexico Expansion ...... 77 5.3 Enbridge – Eastern Expansion ...... 78 5.4 TransCanada’s Energy East Pipeline Project ...... 79 6.1 Canadian Heavy Crude Oil Supply and Disposition, 2011 ...... 83 6.2 Canadian Heavy Crude Oil Exports by Region, 2011 ...... 84 6.3 Dilbit Pricing Dynamics, 2011 ...... 91 A.1 Effect of the Oil Price on the Canadian-US Exchange Rate ...... 94 A.2 Historic and Projected WTI Prices and the Canadian-US Exchange Rate, 2007-2046 ...... 94 A.3 Effect of the Oil Price on Refinery Construction Costs ...... 96 A.4 Historic and Projected WTI Prices and Construction Cost Inflation Rates, 2007-2046 ...... 97 A.5 Effect of the Oil Price on Refinery Operating Costs ...... 98 A.6 Historic and Projected WTI Prices and Operating Cost Inflation Rates, 2007-2046 ...... 99 B.1 Canadian and US Crude Liquids Pipelines ...... 103 B.2 TransCanada’s Keystone Pipeline ...... 104 B.3 Trans Mountain Pipeline ...... 106 B.4 Express-Platte Pipeline...... 107 B.5 Enbridge Liquids Pipelines ...... 109 B.6 Enbridge’s Lakehead System ...... 110 B.7 Enbridge’s Mainline System Configuration ...... 111 B.8 Alberta Clipper Pipeline ...... 113 B.9 Southern Lights Pipeline ...... 114 B.10 The Rangeland Pipeline ...... 115

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B.11 Inter Pipeline Conventional Pipelines ...... 117 B.12 Cochin Pipeline ...... 118 B.13 Pembina Oil Sands and Heavy Oil Pipelines ...... 120 B.14 Inter Pipeline Oilsands Pipelines ...... 122 B.15 The Athabasca Pipeline ...... 127 B.16 Athabasca Pipeline Twinning Project ...... 128 B.17 The Waupisoo Pipeline ...... 129 B.18 The Access Pipeline ...... 131 B.19 The OSPL System Map ...... 132 B.20 The Proposed Norealis Pipeline Project ...... 133 B.21 The ECHO Pipeline ...... 136 B.22 Husky Oil Pipelines ...... 138 B.23 The Rainbow Pipeline ...... 139 B.24 The Rainbow Pipeline II ...... 140 B.25 Pembina Conventional Pipelines ...... 141 B.26 Inter Pipeline Conventional Pipelines ...... 143 B.27 The Enbridge (NW) Pipeline ...... 145 B.28 Enbridge Saskatchewan System ...... 146

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List of Tables

2.1 In-Place Volumes and Established Reserves of Crude Bitumen in Alberta ..... 8 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 ...... 32 3.5 Supply Costs Comparison – WTI Eq. Supply Costs ...... 34 3.6 Assumptions for Sensitivity Analysis ...... 34 4.1 Constraints by Scenario and Extraction Method ...... 40 4.2 Oil Sands Production Forecast ...... 46 4.3 Emission Factors ...... 53 6.1 US Refining and Coking Capacity, 2011 ...... 86 B.1 Pembina’s Conventional Pipelines ...... 142

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Executive Summary

This is the eighth annual edition of the Canadian Energy Research Institute’s (CERI) 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 cost for the production of crude bitumen using primary recovery, steam assisted gravity drainage (SAGD), surface mining and extraction, and integrated mining and upgrading has been calculated for a hypothetical project. Under the Reference Case Scenario, the oil sands are shown to be profitable, and a good investment for oil sands operators, as well as the provincial and federal governments.

Figure E.1 illustrates the supply costs for primary recovery, SAGD, mining and integrated mining. The plant gate supply costs, which exclude transportation and blending costs, are $30.32/bbl, $47.57/bbl, $99.02/bbl, and $68.30/bbl for primary recovery, SAGD, integrated mining and upgrading, and stand-alone mining, respectively. A cost comparison with last year’s estimates indicate that the cost for a SAGD producer had risen by 6.3 percent, 10.9 percent for an integrated mine, and by 13.2 percent for a stand-alone mine.

After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing, Oklahoma for primary recovery is $58.61/bbl; for SAGD projects – $77.85/bbl; $103.16/bbl for integrated mining and upgrading projects; and $99.49/bbl for stand- alone mining projects. While capital costs and the return on investment account for a substantial portion of the total supply cost, the province stands to gain $6.4 to $12.9 in royalty revenues for each barrel of oil produced on average, over the life of an oil sands project.

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

$110 $99.02 $100

$90

$80 $68.30 $70

$60

$47.57 $50

$40 2011CDN$/bbl Real $30.32 $30

$20

$10

$0 Primary Mining & SAGD 10% Mining 10% Recovery 10% Upgrading ROR (a) ROR (a) ROR (a) 10% ROR (a) Fixed Capital (Initial & Sustaining) $14.31 $19.87 $51.03 $32.00 Operating Working Capital $0.45 $1.01 $0.69 Fuel (Natural Gas) $3.23 $2.55 $1.60 Other Op. Costs (Fixed, Variable, Elec) $8.38 $11.44 $23.62 $17.00 Royalties $6.40 $8.83 $12.89 $12.76 Income Taxes $1.23 $2.98 $7.20 $4.31 Emissions Compliance Costs $0.73 $0.65 $0.40 Abandonment Costs $0.03 $0.07 $0.05

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 primary recovery, SAGD, integrated mining, extraction and upgrading, and stand-alone mine projects are represented graphically in Figures E.2-E.5.

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Figure E.2 Supply Cost Sensitivity – 50-well Primary Recovery Project

Initial Capital Cost (25% change)

Operating Costs (25% change)

Discount Rate (2% change)

$20.00 $22.50 $25.00 $27.50 $30.00 $32.50 $35.00 $37.50 2011CDN$/bbl

Source: CERI

Figure E.3 Supply Cost Sensitivity – 30 MBPD SAGD Project

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Op. Costs (25% change)

Sustaining Capital Cost (25% change)

Natural Gas Use (25 change)

Nat. Gas and Elec. Prices (25% change)

$40.00 $42.50 $45.00 $47.50 $50.00 $52.50 $55.00 2011CDN$/bbl Source: CERI

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Figure E.4 Supply Cost Sensitivity – 100 MBPD Integrated Mining, Extraction and Upgrading Project

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Op. Costs (25% change)

Sustaining Capital Cost (25% change)

Nat. Gas and Elec. Prices (25% change)

Natural Gas Use (25 change)

$85 $90 $95 $100 $105 $110 $115 2011CDN$/bbl Source: CERI

Figure E.5 Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Op. Costs (25% change)

Sustaining Capital Cost (25% change)

Natural Gas Use (25 change)

Nat. Gas and Elec. Prices (25% change)

$60 $63 $65 $68 $70 $73 $75 $78 $80 2011CDN$/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 $15.58/bbl. The supply cost for a SAGD producer will increase

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by $5.90/bbl and a stand-alone mine would experience a $10.21/bbl increase from its base supply cost. A cold bitumen project’s cost will go up by $4.88/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 natural gas and electricity prices than the supply costs of the other two projects.

The carbon tax sensitivity was prepared using three different carbon price increases and is shown in Figure E.6. The results indicate that the supply cost will increase as the carbon levy increases. If the carbon tax is doubled from $15/tonne of CO2eq to $30/tonne, a SAGD project’s supply cost goes up by $0.70/bbl, followed by an integrated project increasing by $0.66/bbl, and a $0.41/bbl jump will be experienced by a stand-alone mine. In the case of the highest increase ($45/tonne increase) in carbon tax, supply costs go up by $2/bbl or more for a SAGD and an integrated project and by almost $1.25/bbl for a stand-alone mine.

Figure E.6 Supply Cost Sensitivity – Carbon Prices

Mining

Integrated

SAGD

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2011CDN$/bbl Emissions Tax ($45 increase) Emissions Tax ($30 increase) Emissions Tax ($15 increase)

Source: CERI Projection Results – Three Scenarios Oil Sands Production Figure E.7 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

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three scenarios show a significant growth in oil sands production for the 35-year projection period.

Total production from oil sands areas totaled 1.7 million barrels per day (MMBPD) in 2011, comprised of in situ and mining production of 1.5 MMBPD and 0.2 MMBPD of primary and enhanced oil recovery (EOR) production within the boundaries of oil sands areas. Total production is estimated to grow to 1.9 MMBPD in 2012, which represents a year-on-year increase of 13 percent. Production from oil sands comprises an increasing share of Alberta’s and Canada’s crude oil production. In 2011, 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 is set to grow from 1.5 MMBPD in 2011 to 4.1 MMBPD by 2020 and 6.7 MMBPD by 2046. In the Low Case Scenario production rises to 4.1 MMBPD by 2030 and 4.7 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 from 1.5 MMBPD in 2011 to 3.1 MMBPD by 2020 and 5.6 MMBPD in 2046. Cold bitumen production from primary and EOR wells is forecast to increase from 0.2 MMBPD in 2011 to its peak of 0.4 MMBPD by 2017 and then slowly tapering off to just above 0.1 MMBPD by the end of forecast period.

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Figure E.71 Bitumen Production Projections

('000bpd)

8,000

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

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.8.

Over the 35-year projection period from 2012 to 2046 inclusive, the total initial capital required is projected to be $270.4 billion under the High Case Scenario, $229.7 billion under the Reference Case Scenario, and $176.7 billion under the Low Case Scenario. In comparison with CERI’s 2011 update, the required capital investment is 6.9 percent higher under the High Case Scenario, 4.4 percent higher under the Reference Case Scenario and 7.0 percent lower under the Low Case Scenario. 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

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

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CERI’s conventional oil model and those results are presented in Chapter 4 and discussed only in the context of the Reference Case Scenario.

Figure E.8 Initial Capital Requirements

(Million CDN$) $35,000

$30,000

Total Strategic Investments (Capacity, High Case Scenario)

Total Strategic Investments (Capacity, Low Case Scenario) $25,000 Total Strategic Investments (Capacity, Reference Case Scenario)

$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

Source: CERI, CanOils

Ongoing investment, in the form of sustaining capital will take place on an annual basis. Figure E.9 presents the sustaining capital costs under the three scenarios. Sustaining capital (excluding royalty revenues, taxes, and fixed and variable operating costs) exceeds $6 billion by 2046. The Reference Case Scenario projection shows an annual investment of $10.2 billion in 2046, and is estimated to average $8.7 billion over the projection period. Under the High Case Scenario, the sustaining costs reach an all-time high of $12.1 billion dollars in 2046, averaging $10.6 billion over the 35-year window. In the Low Case Scenario, $8.4 billion will be spent on sustaining costs in 2046, with an average of $7.1 billion over the projection period.

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Figure E.9 Sustaining Capital Requirements

(Million CDN$)

$14,000

$12,000

$10,000

$8,000

$6,000

Total Sustaining Capital Investments (Capacity, High Case Scenario)

Total Sustaining Capital Investments (Capacity, Low Case Scenario) $4,000 Total Sustaining Capital Investments (Capacity, Reference Case Scenario)

$2,000

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

The amount of natural gas required to sustain the oil sands industry is substantial, and is illustrated in Figure E.10. By 2046, 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 1,259 MMcf/d in 2011, to 3,753 MMcf/d in 2046 under the High Case Scenario, 3,183 MMcf/d in the Reference Case Scenario, and 2,693 MMcf/d under the Low Case Scenario.

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Figure E.10 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

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.11 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.11 Greenhouse Gas Emissions

(CO2 eq. MT/year) 200

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

Source: CERI

Emissions will rise from 47 Mt/year in 2011 to 55 Mt/year in 2012 to 156 Mt/year in 2046 under the Reference Case Scenario, to 190 Mt/year in 2046 in the High Case Scenario, and to 137 Mt/year under the Low Case Scenario. Cumulative emissions in the Reference Case Scenario are projected to be 4,442 Mt from 2012 to 2046, which is 1.2 percent lower than the last year’s 35-year cumulative emissions projection. This can partially be attributed to Shell’s Quest project, starting in late 2015, which will capture 2 and store more than one million tonnes per year of CO2 produced in Scotford Upgrader.

Oil Sands Royalties Figure E.12 illustrates the bitumen royalty estimates under the Low, Reference, and High Case Scenarios both on an annual and cumulative basis (2012-2046). Royalty revenues rise in all three cases with the production as expected. Under the Low and High Case Scenarios by 2046 annual revenues reach $49 billion and $70.0 billion,

2 Northwest Upgrader is also set to capture and store carbon. It is estimated that 3,500 tonnes of CO2eq per year will be captured.

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respectively. Annual revenues amount to $58.6 billion by 2046 in the Reference Case Scenario.

Figure E.12 Oil Sands Royalties – Three Scenarios

Annual ($MM) Cummulative ($MM) $75,000 $1,700,000

$70,000 Estimated Royalties Range $1,600,000 CERI-Low Case $1,500,000 $65,000 CERI-Reference Case $1,400,000 $60,000 CERI-High Case Cumulative-Low Case (Right Scale) $1,300,000 $55,000 Cumulative-Reference Case (Right Scale) $1,200,000 $50,000 Cumulative-High Case (Right Scale) $1,100,000

$45,000 $1,000,000

$40,000 $900,000

$35,000 $800,000

$30,000 $700,000 $600,000 $25,000 $500,000 $20,000 $400,000 $15,000 $300,000 $10,000 $200,000

$5,000 $100,000

$- $0

2010 2021 2007 2008 2009 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 2040 2041 2042 2043 2044 2045 2046 Historical/ Outlook Actual

Source: CERI

Under the Reference Case Scenario, royalties collected from the oil sands industry are expected to exceed $10 billion by 2017 and $30 billion by 2026 when the number of project phases in post-payout (175) surpasses the number in pre-payout (60). The pivot year when there are more project phases in post-payout (107) than in pre-payout (101) is 2022. After 2025, 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 $58 billion. Between 2012 and 2046 a total of over $1.2 trillion are estimated to be collected by the Alberta Government from oil sands operators, a figure just below the equivalent of the current value of Canada’s GDP (see Figure E.13).

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Figure E.13 Alberta Oil Sands Royalties – Reference Case Scenario

Annual ($MM) Cumulative ($MM) $65,000 $1,400,000 Primary/ EOR $60,000 $1,300,000 In Situ Solvent $55,000 In Situ $1,200,000 Mining $1,100,000 $50,000 Total Oil Sands Royalties $1,000,000 $45,000 2012 Royalty Curve (Study No. 128) Cumulative (2012 - 2046) (Right Scale) $900,000 $40,000 2012 Cumulative (Study No. 128) $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

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

Source: CERI Pipeline Transportation The US and Canadian crude oil logistics system is changing rapidly as it seeks to adapt to a new reality of steadily growing oil production, both north and south of the border. There is appreciable uncertainty, however, over how the system will evolve in the longer term. It will depend in part on whether (and when) a few major pipeline projects are brought online, as well as on how much Western Canadian crude ends up moving west and to Asia versus south into the US and east into Eastern Canada. By 2014, WTI discounts could be partially alleviated, but we are witnessing a race between production growth and infrastructure restructuring. Crude oil discounts could persist to 2020 – and even beyond – if US shale production rises at optimistic rates. The emergence of rail is an important new factor. Although rail car availability is a constraint in the short-term, terminals are low cost compared to pipelines, can be put online within 12-18 months, and offer shorter payback times. Markets Furthermore, as pipeline transportation remains one of the most economic means to transport crude it will continue to be the dominant transportation mode. Tying into this is the fact that stronger prices at other market locations translate into better prices at

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the production basin via the lowest transportation costs, thus pipeline connections to new markets remains the best means for improving pricing for Canadian oil sands producers. This is important because as prices are lifted companies can realize better returns and re-invest in order to grow the industry. This further translates into more economic activity, higher taxation revenue for provincial and federal governments, but most importantly, it improves the economic value of the resource being extracted (bitumen) for the resource owner, that is, Albertans and Canadians.

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Chapter 1 Introduction

Background Another year has passed and 2012 was a year of growth for the oil sands. The fact remains that the oil sands is and will be one of the primary drivers of growth in the Canadian oil and gas industry. Over the past year, as per the Energy Annual Report by the Government of Alberta, the oil sands industry has drilled 2,171 wells, produced 1.7 million barrels per day of crude bitumen and contributed $4.5 billion to provincial coffers.1 All in all, 2012 marked a year of growth for oil sands producers amid transportation issues, lack of market diversification, increasing production of tight oil in the US and Canada, and on-going skilled labour shortages and rising project costs. It is clear that among all these themes, one dominated the most – transportation challenges.

While the skilled labour shortage remains a significant concern, the new oil sands projects will not come online due to pipeline constraints regardless of whether or not there are enough skilled personnel to work on these projects. Hence, when the US government rejected TransCanada’s Keystone XL project, originally intended as a 700,000-900,000 barrels per day (BPD) line to carry mainly oil sands streams from Hardisty, Alberta to the Gulf Coast via Cushing, it was a major impediment for the industry and provincial economy and has become a focal point of the political and environmental pro- and anti-oil sands debate in the US. In the meantime, the future of Enbridge’s Northern Gateway project that would initially take 525,000 BPD of heavy oil sands streams west to British Columbia’s port of Kitimat – and then to markets mainly in Asia – has become the center of heated support and intense resistance in Canada.

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 150,000 BPD. It will be expanded to a capacity of 400,000 BPD from Cushing to the Gulf Coast by early 2013 and 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, is expected to start operations by late 2013. A Seaway reversal and expansion, with the Keystone XL southern leg, will add over 1.65 million barrels per day (MMBPD) of capacity out of Cushing to the Gulf by 2014.2 This will substantially alleviate the ‘Cushing congestion’ but given the oil sands production forecast, pipeline capacity might still be an issue.

1Government of Alberta. “Energy Annual Report 2011-2012”. http://www.energy.alberta.ca/Org/Publications/AR2012.pdf. Accessed on March 29, 2013. 2 Chapter 5 contains more information related to pipeline constraints.

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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 seems that producers have come full circle, returning to shipping crude in rail cars. While rail is emerging as a serious option to pipeline transportation, it is subject to limited availability of rail cars, terminals, and storage capacity, not to mention that rail, as pipelines, has a finite capacity along with safety and environmental concerns.

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.

Last year’s report concluded that collaboration within the industry as well as with other stakeholders is of paramount importance to see this industry flourish. This year we would like to add that the future growth of provincial and federal economies as well as the industry’s growth may become increasingly uncertain if market opportunities are seized or strained, social license to operate is revoked, and the debate over the future of oil sands among Canadians, governments and industry is unproductive.

Over the last decade, oil sands were the engine that drove the provincial economy ahead. Overall, going forward, certain trends in the oil sands are developing:

 In situ projects will lead the growth in the oil sands production, not mining projects;  Best performing in situ projects will generate attractive economic returns;  Upgrading projects will be deferred indefinitely unless subsidized or market conditions become favourable;  Technological advancements on the extraction as well as the processing side of bitumen will drive future emissions down and could result in less diluent demand; and  Smaller producers will be challenged to grow.

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.

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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, GHG emissions, and compliance costs.  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 the existing and proposed pipelines and determine where the bottlenecks are in the system.  Share CERI’s perspective on existing and potential markets for Canadian crude bitumen and available netbacks to oil sands producers.

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 November 3, 2012), and market intelligence gathered by CERI’s oil sands team.

The 2012 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., stand-alone 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.

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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.

Chapter 5 discusses proposed export pipeline infrastructure and current bottlenecks in the system.

Chapter 6 provides a high-level overview of market access within North America and presents estimated netbacks for producers.

Appendix A includes additional information on methodologies, assumptions and calculations. Appendix B provides an extensive description of existing oil and liquids pipelines in Western Canada.

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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 169 billion barrels of crude bitumen, Alberta’s oil sands are one the largest hydrocarbon deposits in the world, placing third on the world scale after Saudi Arabia and Venezuela.1

The ongoing development of Canada’s oil sands will initially be within the confines of Alberta’s world class and transparent regulatory regimes, of which the Alberta Energy Resources Conservation Board (ERCB) will play an integral role. Eventually, the development of the resource will extend into the neighbouring 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.2

While the resources in Saskatchewan are not fully delineated, 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 bitumen3 are designated as three distinct oil sands areas (OSAs) – Athabasca, Cold Lake and Peace River, and are 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 geological plays containing the oil sands, with the remaining established reserves at 168.7 billion barrels of an extremely heavy crude oil, referred to

1In 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. 2Centre for the Study of Living Standards (CSLS). “The Valuation of the Alberta Oil Sands”. CSLS Research Report No. 2008-7. November 2008. 3Crude 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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as bitumen. Approximately 15 percent of the 168.7 billion barrels is currently under active development.4

Figure 2.1 Alberta’s Oil Sands Areas

Source: ERCB.

Mining and in situ production are the two bitumen recovery methods that are currently employed in the oil sands.5 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

4Alberta Energy Resources Conservation Board (ERCB). “Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012-2021”. June 2012. 5 It is assumed that the reader is familiar with current technologies. For a detailed overview of technologies implemented in the oil sands refer to past issues of CERI’s oil sands update. 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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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.

Figure 2.2 Mining and Extraction

Source: Suncor Energy Inc.

Figure 2.3 In Situ - SAGD

Source: Suncor Energy Inc. (Firebag project).

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The ERCB 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, 2011.

Table 2.1 In-Place Volumes and Established Reserves of Crude Bitumen in Alberta (10^9 barrels)7 Recovery Initial Initial Cumulative Remaining Method Volume-in- Established Production Established Place Reserves Reserves Total 1,843.6 176.8 8.1 168.7 Mining 130.8 38.8 5.2 33.6 In situ 1,712.8 138.0 2.9 135.0 Note: Any discrepancies are due to rounding. Source: ERCB. “Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012-2021”. June 2012.

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 This report is based on three plausible scenarios that take into account possible paths for 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 extraction of bitumen from the oil sands will be driven by the 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 there are positive signs that large developed economies have emerged from the recession, the rate at which they are recovering remains uncertain, given persistent high unemployment in the US, the continued economic crisis in Europe, 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

7Alberta Energy Resources Conservation Board. “Alberta’s Energy Reserves 2011 and Supply/Demand Outlook 2012-2021”. June 2012.

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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 2011 demand growth of BRIC nations continued to increase and reached the same level of demand growth of the world’s largest oil consuming nation, the US.

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

28%

26%

24%

22% BRIC US 20%

18%

16%

14% 1998 2000 2002 2004 2006 2008 2010

Source: BP Statistical Review of World Energy, June 2012

The impact that these scenarios could have on oil sands developments was translated into 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 projection period for this analysis extends from 2012 to 2046, and in each scenario it has been assumed that Canadian and US currencies are trading at “par” with each other.9 For this reason, all monetary values in this report are assumed to be in Canadian dollars, unless otherwise stated. Lastly, all values in this report are presented as real 2011 dollars, unless otherwise stated.

8Even though Russia and Brazil are energy exporters, their domestic energy consumption has been increasing, just like China and India. 9While it is probable that the Canadian dollar will trade above par with the U.S. dollar, it is assumed that the Bank of Canada would intervene, to put downward pressure on the relative value of the Canadian dollar. More will be discussed in the next Chapter, as it relates to this assumption.

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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 2012-2013, 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 (see Figure 2.5).

Figure 2.5 Oil Price Forecast – Reference Case Scenario

$/bbl $350 Nominal CDN$/bbl $300 Real 2011 CDN$/bbl $250

$200

$150

$100

$50

$0 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044

Source: EIA, CERI.

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

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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, as shown in Figure 2.6. While this might not satisfy environmental activists, the modest emissions compliance costs act as a stimulant for technology development, as oil sands companies seek to differentiate themselves from the competition by producing a “greener” barrel.10 More recently, the provincial Minister of Environment, Diana McQueen, made an announcement that she, together with the provincial government, are looking at revising that policy.11 While not yet finalized, the proposal calls for a 40 percent reduction in per barrel emissions for both mining and in situ projects and a $40 per tonne of CO2eq levy when the limit is exceeded. However, it is unclear what year will be picked as a base year from which the 40 percent reduction will be calculated or by what year the 40 percent reduction needs to happen.

Figure 2.6 Emissions Compliance Costs – Reference Case Scenario

$/T $45.00 Nominal CDN$/T $40.00

Real 2011CDN$/T $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044

Source: CERI.

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/ 11 Globe and Mail. “Alberta’s bold plan to cut emissions stuns Ottawa and oil industry”. Accessed April 3, 2013 at http://www.theglobeandmail.com/report-on-business/industry-news/energy-and- resources/albertas-bold-plan-to-cut-emissions-stuns-ottawa-and-oil-industry/article10762621/

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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 2012-2013, and demand for crude oil and its products is stagnant. In addition, environmental policy becomes a priority for policy makers. 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. 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

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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 supply and demand), 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 stand-alone mine or integrated with an upgrader. Within in situ and mining methods, various technologies to extract valuable bitumen from the oil sands are utilized.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 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 2011 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 assumes a fixed discount rate (10 percent, real), thereby allowing the price of oil to vary by extraction method and solves for the supply cost. This approach allowed

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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CERI to estimate the supply cost by extraction method required to bring forth new oil sands projects. In past reports, from the time when the Government of Alberta moved away from a royalty system that imposed fixed rates to a system that takes into account oil prices, as measured by WTI, the supply cost model solved for the constant real rate of return (ROR) needed to recover all capital expenditures, operating costs, royalties, and taxes, given an oil price projection.

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 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, mining project, and mining integrated with an upgrader. The supply cost for the production of crude bitumen using primary recovery has also been calculated for a hypothetical project.3 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 except for primary recovery are presented in Table 3.1. The assumptions for primary recovery are presented separately, since the supply cost calculation was done separately from the other three costs. The project design parameters and energy requirements remain the same as in last year’s update. However, capital and operating costs have been adjusted. The data for capital and operating costs is collected from public sources, such as company annual reports, investor presentations, company announcements, etc., and is

3 The supply cost calculation for primary recovery was done using CERI’s conventional supply cost modeling, whose methodology will be described in full in CERI’s forthcoming study. For the purposes of this study, we will just evaluate production of crude bitumen using primary recovery.

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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; Suncor entered into a strategic partnership with Total E&P Canada Ltd. to jointly develop the Fort Hills and Joslyn oil sands mining projects. This partnership promises to keep costs down through engineering, procurement, and construction cost savings.  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 Horizon Oil Sands Project. The project has been broken into 5 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.  Thermal and integrated mining, extraction and upgrading projects have been devoting considerable effort (and have made considerable progress) towards reducing operating costs.  While the Reference Case Scenario 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.

Historically, the majority of the primary bitumen has been produced from the Cold Lake oil sands area, using vertical wells and progressive cavity pumps that tolerate the large volumes of sand produced with the bitumen.4 More recently, with improvements in horizontal and multilateral drilling technology, primary bitumen is being produced from the Athabasca and Peace River oil sands areas. The supply cost of primary bitumen production has been evaluated by considering the areas listed below where production occurs and averaging across those locations:

4 CHOPS (Cold Heavy Oil Production with Sand).

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 Central-eastern Alberta, from Bens Lake to Calling Lake  Central Alberta, Heart River Creek area, including the Slave Point formation  Central Alberta, Darling Creek to Slave Lake Compressor  Fort McMurray area.

Assumed parameters for one vertical well operation are summarized below:

 Average production rate 21 BPD  Project Life 25 years  Capital Cost: - G&G5 and Land $0.22 - Drilling and Completion $0.46 - Tie-in $0.74  Total Capital Cost $1.41  Total Operating Cost $0.07

Table 3.1 Design Assumptions by Extraction Method

Integrated Mining and Extraction and Mining and Measurement Units SAGD Upgrading Extraction

Project Design Parameters Stream day capacity bbl of bitumen per day 30,000 115,000 100,000 Production Life years 30 30 30 Average Capacity Factor (over production life) percent 75.00% 89.00% 89.00% Capital Expenditures Initial Millions of dollars 974 14,849 7,612 Initial Dollars per bbl of capacity 32,482 129,122 76,122 Sustaining (Annual Average) Millions of dollars 43.8 243 218.3 Operating Working Capital Days payment 45 45 45 Operating Costs Non-energy total (Annual Average) Millions of dollars 79 725 544 Non-energy total Dollars per bbl 9.6 22 16.8 Energy Requirements Natural Gas Royalty Applicable GJ per day 32,100 62,100 54,000 Non-Royalty Applicable GJ per day 20,871 Electricity Purchased Royalty Applicable MWh/d 300 1,128 0 Non-Royalty Applicable MWh/d Electricity Sold MWh/d 0 0 728 Other Project Assumptions Abandonment and Reclamation percent of total capital 2% 2% 2% Source: CanOils, CERI

5 Costs associated with geological and geophysical studies and surveys.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 19

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;6 however, if oil prices further strengthen, CERI expects the pace of development to increase in response.

The initial capital costs have increased for SAGD producers by 1.7 percent from 2011 to $32,482/bbl per day of capacity; and for mining by 4.4 percent, to $76,122/bbl per day of capacity. The sustaining capital costs have doubled across all producers, indicating a stronger cost inflation and the fact that a large number of projects are mature and in need of more maintenance. The greenfield projects might exhibit lower sustaining capital requirements, however, the cost inflation will be present for all new and existing projects, and hence this assumption of higher sustaining capital costs is applied to new projects as well. The non-energy total operating costs have increased to $9.60/bbl of production for SAGD producers and mining saw an increase to $16.80/bbl of produced bitumen. These costs reflect the fact that ongoing labour, materials and equipment costs have seen the greatest escalation in recent years.

The energy-related operating costs are very dependent on the cost of natural gas and electricity used as energy feedstock. The energy requirements remain the same as in the previous update, however, natural gas and electricity prices have been updated, and the new forecasts are presented below.

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) 2013, Early Release for the period 2008 to 2040, and extended, at an inflation rate of 2.5 percent per year, to cover the projection period as seen in Figure 3.1. 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.

6 Suncor Annual Statement

May 2013 20 Canadian Energy Research Institute

Figure 3.1 Henry Hub Natural Gas Price Forecast

$/MMBtu $16 Nominal CDN$/Mmbtu $14 Real2011 CDN$/Mmbtu $12

$10

$8

$6

$4

$2

$0 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044

Source: EIA, CERI

The price of natural gas has dropped significantly from its previous level of $10.00/MMBTU in 2008, to a level where the price hovered close to $4.00/MMBTU in 2011. According to the EIA’s forecast, in 2012 the annual gas price is estimated to be $2.60/MMBTU, which is 50 percent lower than the $3.91/MMBTU price experienced in 2011. This ongoing decline in prices might suggest that the price of gas will be depressed longer than originally anticipated. The remainder of the forecast indicates that prices will remian flat (in real terms) for the first decade of the forecast, gradually increasing and surpassing the $6/MMBTU mark, but never reaching the levels seen during the 2007-2008 period. This has created favourable near-term conditions for thermal oil sands production, such as SAGD or CSS. As natural gas is required to create steam, producers are benefiting from lower energy-related operating costs and wider operating margins.

Contributing to soft gas prices over the past few years has been the 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. More recently though, natural gas prices have fallen due to weak demand. An unusually warm winter and a still struggling US economy has limited demand for natural gas this winter, so prices are hitting multi-year lows.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 21

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 average wholesale electricity prices at the Alberta Power Pool was used for the time period 2008 to 2021 and then escalated at an annual average inflation rate of 2.5 percent. As illustrated in Figure 3.2, real-dollar electricity prices are gradually decreasing from $76.22/MWh in 2011 to $70.31/MWh by the end of the projection period.

Figure 3.2 Average Wholesale Electricity Price in Alberta Power Pool Forecast

$/MWh $180 Nominal CDN$/MWh $160 Real 2011CDN$/MWh $140 $120 $100 $80 $60 $40 $20 $0 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044

Source: ERCB ST-98, June 2012; 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.

May 2013 22 Canadian Energy Research Institute

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 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 3.3 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 3.3 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

Figure 3.4 represents the estimated refinery product yields from a light sweet crude such as Arab Light (32 API, 1.7 percent sulfur) and a heavy sour crude such as Western Canadian Select (21 API, 3.5 percent sulfur), both for a simple or complex refinery (without a coker) as well as for a ‘very complex’ refinery (one with a coker). In general, a light sweet crude yields higher proportions of higher value products, while a better

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 23

yield of such products is obtained from heavier sour grades through the use of a coker (very complex refinery).

Figure 3.4 Estimated Refinery Yields by Crude and Refinery Complexity

Source: University of Calgary School of Public Policy7

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 Western Canadian Select (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.8 Table 3.2 compares the characteristics of the WCS blend with two other heavy crude oils.9

7 Pacific Basin Heavy Oil Refining Capacity, available at: http://www.policyschool.ucalgary.ca/sites/default/files/research/pacific-basic-refining-capacity.pdf 8 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) 9Paterson, 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.

May 2013 24 Canadian Energy Research Institute

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.

Currently, WCS prices are closely linked to West Texas Intermediate (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.

As the US 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 global benchmarks. 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 3.5.10 As a point of reference, Mexican Maya crude oil prices have also been provided in the Figure. 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. Syncrude prices are provided for reference purposes and are representative of a SCO price.

The data series for WCS prices comes from the Cenovus website,11 SCO prices are sourced from Canadian Oil Sands’ website,12 while Brent, WTI and Maya prices are sourced from the US EIA from January 2005 to February 2013. Figure 3.5 illustrates the selected historical benchmark price series and differentials between various types.

As seen in Figure 3.5, prices have been volatile in recent years. WTI (North American benchmark) prices have dislocated from Brent (global benchmark) prices due to an oversupply of crude oil in the US Midwest and an inadequate pipeline capacity that essentially renders crude supplies captive in that area. Furthermore, while WCS has

10 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. 11 http://www.cenovus.com/operations/doing-business-with-us/marketing/crude-oil-pricing.html 12 http://www.cdnoilsands.com/energy-marketing/Pricing/default.aspx

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 25

tended to trade at a discount to Maya,13 on a long-term basis, at between US$8-11/bbl (mainly reflecting transportation costs), the discount has reached as much as US$39/bbl in April 2012. Syncrude has traditionally traded at a premium to WTI, but price volatility has sent the differential as low as a US$15/bbl discount (April 2012) and as high as a US$15/bbl premium (September 2011) to WTI over the time period surveyed.

Figure 3.5 Light-Heavy Differentials (US$/bbl)

$140.00 $135.00 Brent - WCS Differential ($/b) WTI - WCS Differential ($/b) $130.00 Maya - WCS Differential ($/b) $125.00 Europe Brent Spot Price FOB ($/b) $120.00 West Texas Intermediate (WTI) @ Cushing ($/b) $115.00 Western Canadian Select (WCS) @ Hardisty ($/b) $110.00 Syncrude Stream (SYN) @ Edmonton ($/b) $105.00 Maya (US Landed) ($/b) $100.00 $95.00 $90.00 $85.00 $80.00 $75.00 $70.00 $65.00 $60.00 $55.00 $50.00 $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $- $(5.00)

$(10.00)

Jul-2005 Jul-2006 Jul-2007 Jul-2008 Jul-2009 Jul-2010 Jul-2011 Jul-2012

Jan-2005 Jan-2006 Jan-2007 Jan-2008 Jan-2009 Jan-2010 Jan-2011 Jan-2012 Jan-2013

Oct-2011 Oct-2005 Oct-2006 Oct-2007 Oct-2008 Oct-2009 Oct-2010 Oct-2012

Apr-2006 Apr-2007 Apr-2008 Apr-2009 Apr-2010 Apr-2011 Apr-2012 Apr-2005 Source: EIA, Cenovus, Canadian Oil Sands, CERI

WCS prices are not immune to price volatility and fell from a high of US$115/bbl in July 2008 to nearly US$20/bbl in December 2008. Since WCS has historically traded based on WTI, and given the high correlation coefficient of 94 percent with WTI, it is reasonable to say that WTI prices have also exhibited periods of large fluctuation. 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 almost US$40/bbl in December 2012, with average and median differentials at about US$18/bbl.

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

13 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)

May 2013 26 Canadian Energy Research Institute

average WTI-WCS differential of US$15/bbl. This is in turn is consistent with an average historical light-heavy US$9/bbl crude quality differential that has been observed between LLS ($10/bbl) and WTI ($8/bbl) versus Maya at the USGC, as well as a WTI-WCS historical crude quality differential of $18/bbl14 in the US Midwest (USMW). Therefore, based on the historical data and our assumptions within the Reference Case Scenario, the light-heavy differential (not including transportation costs) is assumed to be constant at US$15.00/bbl. This assumption also reflects a condition in which 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, and refineries adjust accordingly.

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 West Texas Intermediate (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 cost C$4.51/bbl: 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.

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.

14 WCS @ USMW = WTI – WCS Historical Quality Differential = $18/bbl WCS @ USGC = WTI/LLS – Maya Historical Quality Differential = $9/bbl On a pure crude quality basis the differential should be between $18/bbl and $9/bbl, yet as the USMW will remain a large market for WCS the differential is likely to remain at the upper end of the range, meanwhile as more Canadian oil sands heavy blends reach the USGC market, the quality differential should move towards the lower end of the range. A long-range estimate of $15/bbl was assigned.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 27

Within the supply cost model, federal and provincial corporate income taxes have been assumed constant at 15 percent15 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.16 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 in computing income for a taxation year up to 100 percent of the remaining cost of the eligible assets, not exceeding the taxpayer's income for the year from the project (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.17 The regular 25 percent CCA rate will remain 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

15 Effective January 1, 2012, the federal rate dropped to 15 percent from 16.5 percent. 16 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. 17 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.

May 2013 28 Canadian Energy Research Institute

 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, 2012, and begin operating on January 1, 2014. The projects will continue to operate until end of year 2043, based on a 30-year project life.

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”. This plan involves taxing large final emitters – as defined as those emitting over 100,000 tonnes of carbon dioxide per year – a sum of C$15.00/tonne. This is one compliance option. Other two options are reduction in carbon intensity or a purchase of carbon offset credits. 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.18 The resulting impact on the overall cost of an oil sands project is minimal. However, as the market develops and with it carbon tax/price will rise, the resulting impact will increase over time.

18 CERI assumes that the reduction in carbon intensity and/or purchase of carbon offset credits more or less equates to carbon tax.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 29

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).19 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 3.6.

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 regulations and with termination of a project, abandonment and reclamation of a project site.20

19 Assumed to be 5.5 percent. 20 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.

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Figure 3.6 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 account for the new royalty system. The forecast of the WTI price was obtained from the EIA’s AEO 2013, Early Release for the period 2008 to 2040. Between 2040 and 2046, it is assumed that the WTI price increases at an annual average assumed inflation rate of 2.5 percent. The oil price is illustrated in Figure 2.5 in Chapter 2 in both nominal and real 2011 dollars.

Canadian-US Exchange Rate (C$/US$) The purpose of this section is not to provide a detailed forecast of Canadian-US exchange rates over the long projection period covered in this study, but rather to simply illustrate the effect that one variable could have on the exchange rate, ignoring all other factors, and left unconstrained by government policy. It is true that many factors can have an impact on the exchange rate, including political changes, productivity, inflation, and debt. However, there is one factor that has had an undeniable influence on the Canadian-US exchange rate, and has become more important over time. This factor is the price of crude oil. Appendix A includes the details about modeling such a relationship.

Exchange rate parity will be assumed throughout the projection period, as fiscal and monetary policies would likely be implemented, over the long-term, to prevent excessive appreciation of the Canadian dollar against the US dollar.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 31

Supply Cost Results Based on these assumptions, the supply cost for the production of crude bitumen using primary recovery, SAGD, surface mining and extraction, and integrated mining and upgrading has been calculated for a hypothetical project. Figure 3.7 illustrates the supply costs for primary recovery, SAGD, mining and integrated mining. The plant gate supply costs, which exclude transportation and blending costs, are $30.32/bbl, $47.57/bbl, $99.02/bbl, and $68.30/bbl for primary recovery, SAGD, integrated mining and upgrading, and stand-alone mining, respectively. Comparison of costs from last year’s update indicates that the cost for a SAGD producer has risen by 6.3 percent, 10.9 percent for an integrated miner, and by 13.2 percent for a stand-alone mine.

After adjusting for blending and transportation, the WTI equivalent supply costs at Cushing for primary recovery is $58.61/bbl; for SAGD projects – $77.85/bbl, $103.16/bbl for integrated mining and upgrading projects, and $99.49/bbl for stand-alone mining projects. A summary of costs are presented in Table 3.4.

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Figure 3.7 Total Field Gate Bitumen/SCO Supply Costs – Reference Case Scenario

$110 $99.02 $100

$90

$80 $68.30 $70

$60

$47.57 $50

$40 2011CDN$/bbl Real $30.32 $30

$20

$10

$0 Primary Mining & SAGD 10% Mining 10% Recovery 10% Upgrading ROR (a) ROR (a) ROR (a) 10% ROR (a) Fixed Capital (Initial & Sustaining) $14.31 $19.87 $51.03 $32.00 Operating Working Capital $0.45 $1.01 $0.69 Fuel (Natural Gas) $3.23 $2.55 $1.60 Other Op. Costs (Fixed, Variable, Elec) $8.38 $11.44 $23.62 $17.00 Royalties $6.40 $8.83 $12.89 $12.76 Income Taxes $1.23 $2.98 $7.20 $4.31 Emissions Compliance Costs $0.73 $0.65 $0.40 Abandonment Costs $0.03 $0.07 $0.05

aReturn on capital included. Source: CERI.

Table 3.4 Supply Costs Summary

Project SC at Field Gate WTI Equivalent SC (C$2011/bbl) (C$2011/bbl) Primary Recovery 30.32 58.61 SAGD 47.57 77.85 Integrated Mining & Upgrading 99.02 103.16 Stand-Alone Mine 68.30 99.49

Source: CERI

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 33

While capital costs and the return on investment account for a substantial portion of the total supply cost, the province stands to gain $7.1 to $12.9 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 13 to 21 percent (see Figure 3.8). The reason that the royalty share of the total cost is the lowest (13 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 stand-alone mining are normalized to blended bitumen.

Figure 3.8 Oil Sands Supply Costs – Reference Case Scenario (% Contribution)

100%

90%

80%

70%

60%

50%

40% Real 2011 2011 Real CDN$/bbl

30%

20%

10%

0% Primary Mining & SAGD Mining Recovery Upgrading (Realistic Oil (Realistic Oil (Realistic Oil (Realistic Oil Price Projection Price Projection Price Projection Price Projection 10% ) 10% ) 10% ROR) 10% ) Fixed Capital (Initial & Sustaining) 47% 42% 52% 47% Operating Working Capital 0% 1% 1% 1% Fuel (Natural Gas) 0% 7% 3% 2% Other Op. Costs (Fixed, Variable, Elec) 28% 24% 24% 25% Royalties 21% 19% 13% 19% Income Taxes 4% 6% 7% 6% Emissions Compliance Costs 0% 2% 1% 1% Abandonment Costs 0% 0% 0% 0% Source: CERI.

How CERI’s estimates of supply costs compare to others21 is presented in Table 3.5, CERI’s supply costs are within ERCB’s range for a SAGD project and 9 percent higher (from the maximum value in the range) for a stand-alone mining project. This is due to CERI’s assumption of higher capital costs for a mining project than the ERCB’s estimate.

21 ERCB ST-98, June 2012

May 2013 34 Canadian Energy Research Institute

Table 3.5 Supply Costs Comparison – WTI Eq. Supply Costs

Project CERI ERCB (2012 US$/bbl) SAGD 77.85 50-78 Integrated Mining & Upgrading22 103.16 Stand-Alone Mine 99.49 70-91

Source: CERI, ERCB.

Under CERI’s Reference Case Scenario, a harmonized emissions compliance cost projection has been included. It is explicitly assumed that within CERI’s oil sands model the compliance costs are harmonized with Alberta’s current compliance cost framework. While this is not intended to indicate that a technology fund would exist under the harmonized plan, it does assume 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. 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% +CDN$15/bbl Carbon Tax +CDN$30/bbl +CDN$45/bbl

22 There was no supply cost estimate presented for an integrated project in the ERCB’s ST-98, 2012.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 35

Bitumen supply cost sensitivities for a hypothetical primary recovery, SAGD, integrated mining, extraction and upgrading and a stand-alone mine projects are represented graphically in Figures 3.9-3.12.

Figure 3.9 Supply Cost Sensitivity – 50-well Primary Recovery Project

Initial Capital Cost (25% change)

Operating Costs (25% change)

Discount Rate (2% change)

$20.00 $22.50 $25.00 $27.50 $30.00 $32.50 $35.00 $37.50 2011CDN$/bbl

Source: CERI

Figure 3.10 Supply Cost Sensitivity – 30 MBPD SAGD Project

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Op. Costs (25% change)

Sustaining Capital Cost (25% change)

Natural Gas Use (25 change)

Nat. Gas and Elec. Prices (25% change)

$40.00 $42.50 $45.00 $47.50 $50.00 $52.50 $55.00 2011CDN$/bbl Source: CERI

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Figure 3.11 Supply Cost Sensitivity – 100 MBPD Integrated Mining, Extraction and Upgrading Project

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Op. Costs (25% change)

Sustaining Capital Cost (25% change)

Nat. Gas and Elec. Prices (25% change)

Natural Gas Use (25 change)

$85 $90 $95 $100 $105 $110 $115 2011CDN$/bbl Source: CERI

Figure 3.12 Supply Cost Sensitivity – 100 MBPD Mining and Extraction Project

Initial Capital Cost (25% change)

Discount Rate (2% change)

Non-energy Op. Costs (25% change)

Sustaining Capital Cost (25% change)

Natural Gas Use (25 change)

Nat. Gas and Elec. Prices (25% change)

$60 $63 $65 $68 $70 $73 $75 $78 $80 2011CDN$/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 $15.58/bbl. The supply cost for a SAGD producer will increase

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 37

by $5.90/bbl and a stand-alone mine would experience a $10.21/bbl increase from its base supply cost. A cold bitumen project’s cost will go up by $4.88/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 natural gas and electricity prices than the supply costs of the other two projects.

The carbon tax sensitivity was prepared using three different carbon price increases and is shown in Figure 3.13. The results indicate that the supply cost will increase as the carbon levy increases. If the carbon tax is doubled from $15/tonne of CO2eq to $30/tonne, a SAGD project’s supply cost goes up by $0.70/bbl, followed by an integrated project increasing by $0.66/bbl, and a $0.41/bbl jump will be experienced by a stand-alone mine. In the case of the highest increase ($45/tonne increase) in carbon tax, resulting in a $60/tonne carbon tax, supply costs go up by $2/bbl or more for a SAGD and an integrated project and by almost $1.25/bbl for a stand-alone mine.

Figure 3.13 Supply Cost Sensitivity – Carbon Prices

Mining

Integrated

SAGD

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2011CDN$/bbl Emissions Tax ($45 increase) Emissions Tax ($30 increase) Emissions Tax ($15 increase)

Source: CERI

May 2013 38 Canadian Energy Research Institute

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 39

Chapter 4 Oil Sands Projections

Based upon CERI’s Reference Case Scenario, the last chapter concludes that Canada’s oil sands will be 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.

This Chapter presents CERI’s projection results as follows. 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.

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.

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.

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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. Projects that are suspended are assumed to be already approved but not yet constructed. While CERI’s projection model has the capability to cancel individual projects, the probabilities are used to proxy project cancellations at the aggregate extraction method level.

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, and are illustrated in Table 4.1. 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. Another factor that is contributing to this increase in delays and capacity curtailments is the fact that the existing export pipeline capacity is soon to be maxed out without definitive plans to expand the system.

Table 4.1 Constraints by Scenario and Extraction Method

High case Scenario Reference case Scenario Low case Scenario

Probability Delay Probability Delay Probability Delay Project Type Project Status Fraction Years Fraction Years Fraction Years In Situ Onstream 1.00 0 1.00 0 1.00 0 In Situ Under Construction 1.00 0 1.00 1 0.90 2 In Situ Suspended 1.00 1 0.90 2 0.80 4 In Situ Approved 0.95 1 0.80 3 0.70 5 In Situ Awaiting Approval 0.90 2 0.70 4 0.60 6 In Situ Announced 0.80 5 0.60 7 0.40 15 In Situ Solvent Onstream 1.00 0 1.00 0 1.00 0 In Situ Solvent Under Construction 1.00 0 1.00 1 0.90 2 In Situ Solvent Suspended 1.00 1 0.90 2 0.80 4 In Situ Solvent Approved 0.95 1 0.80 3 0.70 5 In Situ Solvent Awaiting Approval 0.90 2 0.70 4 0.60 6 In Situ Solvent Announced 0.80 5 0.60 7 0.40 15 Mining Onstream 1.00 0 1.00 0 1.00 0 Mining Under Construction 1.00 0 0.95 2 0.70 4 Mining Suspended 1.00 1 0.90 3 0.60 5 Mining Approved 0.95 2 0.70 4 0.50 6 Mining Awaiting Approval 0.90 3 0.60 5 0.40 7 Mining Announced 0.80 5 0.50 7 0.30 15 Upgrader Onstream 1.00 0 1.00 0 1.00 0 Upgrader Under Construction 1.00 0 0.95 2 0.70 4 Upgrader Suspended 1.00 1 0.90 3 0.60 5 Upgrader Approved 0.95 2 0.70 4 0.50 6 Upgrader Awaiting Approval 0.90 3 0.60 5 0.40 7 Upgrader Announced 0.80 5 0.50 7 0.30 15 Source: CERI

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 41

Estimating Inflation Estimating future capital investment and operating costs required CERI to develop an estimate for construction and operating costs inflation. Estimating the inflation in oil sands construction and operating costs can be a difficult endeavour due to the lack of available historical cost data.

Oil Sands Construction Cost Inflation In order to approximate construction cost inflation in the oil sands, CERI studied the changes in the Nelson-Farrar Inflation Refinery Construction Cost Index (NFCCI). The NFCCI was first introduced in CERI’s 2009 oil sands update study as a method to estimate future oil sands construction cost inflation. Appendix A outlines the process of estimating the inflation.

The historic data indicates that year-over-year (October 2011-October 2012) refinery construction costs have experienced no change. The average annual construction cost inflation rate, forecasted between October 2012 and October 2046, is 1.9 percent, which is lower than the assumed annual inflation rate of 2.5 percent. Figure A.4 displays forecasts of the WTI price, and the annual inflation in refinery construction costs. This forecast of the annual inflation rate in refinery construction costs (used to proxy the oil sands construction cost inflation) is used to inflate the projected initial and sustaining capital costs in the oil sands industry.

Oil Sands Operating Cost Inflation The operating costs of an oil sands project contribute significantly to the total cost of a project. As with capital costs, however, no index currently exists to capture changes in oil sands operating costs over time. In order to estimate the inflation rate of oil sands operating costs, a feasible alternative measure must be obtained. While the operating costs of an oil refinery do not mirror those of an oil sands project exactly, the two facilities are similar in that each consists of very energy-intensive processing units.1 For this reason, the Nelson-Farrar Refinery Operating Cost Index (NFOCI) is used in the examination of oil price impacts on oil sands operating costs. The NFOCI accounts for the following refinery operating costs: fuel, power, labour, investment, maintenance, and chemicals. Appendix A outlines the process of estimating the inflation.

The historical data implies that the refinery operating costs have decreased by 1.0 percent, year-over-year (October 2011-October 2012). The annual average operating cost inflation rate forecasted between October 2012 and October 2046 is 2.03 percent, which is lower than the annual inflation rate of 2.5 percent. Figure A.6 displays forecasts of the WTI price, and the annual inflation in refinery operating costs. This forecast of the annual inflation rate in refinery operating costs (used to proxy the oil sands operating cost inflation) is used to inflate the projected operating costs in the oil sands industry.

1While this relationship is weaker for an oil sands operation, it is still a relevant comparison until an alternative method is developed.

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Estimating Royalty Revenues and Blending Requirements Due to their importance to the provincial economy as well as to 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 Energy Resources Conservation Board (ERCB), 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 (5 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.

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.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 43

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.

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 reports, investor presentations and press releases. The projections include production from on stream projects as well as new projects that are under construction, approved, awaiting approval and announced. The projection period is from 2012 to 2046, inclusive.

Oil Sands Capacity Based upon current information collected from oil sands proponents, capacity could peak at 8.3 million barrels a day (MMBPD) by the end of 2027 without delays or curtailments; for comparison, in CERI’s 2011 oil sands update under the Unconstrained Scenario, the peak was achieved in the same year with 7.1 MMBPD. 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, and 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, 2046. The rate of expansion is higher at the front end of the forecast period, and becomes more or less flat past 2035.

Under the Low Case Scenario, the oil sands experience 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 development becomes sluggish over the next decade. By 2020, the industry begins to anticipate higher oil prices as trade barriers are reduced, and emissions compliance costs become more manageable; capacity reaches 2.9 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 6.1 MMBPD by 2046. 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. However, increasing overall costs for oil sands producers and lack of export pipeline capacity might hinder the rate at which the oil sands projects come on stream.

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Figure 4.2 Bitumen Capacity Projections

('000bpd)

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

Source: CERI, CanOils

In a world where energy security trumps all other concerns, driven by robust economic growth in 2013, 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 5.5 MMBPD, and by 2046 – 7.2 MMBPD.

While some may be skeptical about this Scenario coming to fruition, it is plausible that, by 2046, 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

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 45

2017 and again around 2027 is a result of some projects in the oil sands reaching the end of the assumed production life. The period from 2012 to 2027 experiences a rapid growth phase in the capacity additions and it is not until 2027 that the growth levels off and by 2034 it slows down. In 2020, capacity reaches 3.9 MMBPD (as opposed to 4.1 MMBPD, which was last year’s estimate for year 2020), and grows to 6.1 MMBPD by 2046, with a peak capacity of 6.3 MMBPD occurring in 2034.

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 1.7 MMBPD in 2011, comprised of in situ and mining production of 1.5 MMBPD and 0.2 MMBPD of primary and enhanced oil recovery (EOR) production within the boundaries of oil sands areas. Total production is estimated to grow to 1.9 MMBPD in 2012, which represents a year-on-year increase of 13 percent. Production from oil sands comprises an increasing share of Alberta’s and Canada’s crude oil production. In 2011, 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 1.5 MMBPD in 2011 to 4.1 MMBPD by 2020 and 6.7 MMBPD by 2046. In the Low Case Scenario production rises to 4.1 MMBPD by 2030 and 4.7 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 3.1 MMBPD by 2020 and 5.6 MMBPD in 2046 (see Figure 4.3 and Table 4.2). Cold bitumen production from primary and EOR wells is

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forecasted to increase from 0.2 MMBPD in 2011 to its peak of 0.4 MMBPD by 2017 and then slowly tapering off to just above 0.1 MMBPD by the end of forecast period.

Table 4.2 Oil Sands Production Forecast*

2011 2020 2030 2046 MMBPD High Case 1.5 4.1 6.5 6.7 Reference Case 1.5 3.1 5.3 5.6 Low Case 1.5 2.5 4.1 4.7

*Excludes primary bitumen production. Source: CERI

Peak production volume is reached the earliest in the High Case Scenario – 6.7 MMBPD in 2038. 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 4.7 MMBPD is reached in 2045. Production under the Reference Case Scenario peaks at 5.6 MMBPD in 2040. 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)

8,000

7,000

6,000

5,000

4,000

3,000

(Production, High Case Scenario) (Production, Low Case Scenario) (Production, Reference Case Scenario) 2,000

1,000

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

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. Initial capital costs, under the three scenarios, are illustrated in Figure 4.4.

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Figure 4.4 Initial Capital Requirements

(Million CDN$) $35,000

$30,000

$25,000

$20,000

Total Strategic Investments (Capacity, High Case Scenario) $15,000 Total Strategic Investments (Capacity, Low Case Scenario)

Total Strategic Investments (Capacity, Reference Case Scenario) $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

Source: CERI, CanOils

Over the 35-year projection period from 2012 to 2046 inclusive, the total initial capital required is projected to be $270.4 billion under the High Case Scenario, $229.7 billion under the Reference Case Scenario, and $176.7 billion under the Low Case Scenario.2 In comparison with CERI’s 2011 update, the required capital investment is 6.9 percent higher under the High Case Scenario, 4.4 percent higher under the Reference Case Scenario and 7.0 percent lower under the Low Case Scenario. 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.

2 This projection does not include the capital investment on primary and EOR cold bitumen projects. The forecast of capital spending on those projects is discussed only in the context of the Reference Case Scenario in the next section of Chapter 4.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 49

New investment dollars start declining half way through the forecast period, and approach zero 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. 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 this year’s update, the per barrel estimate of sustaining capital for all oil sands projects increased substantially to reflect increasing cost to sustain the level of desired production among oil sands producers.

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 $6 billion by 2046. Figure 4.5 presents the sustaining capital costs under the three scenarios. The Reference Case Scenario projection shows an annual investment of $10.2 billion in 2046, and is estimated to average $8.7 billion over the projection period. Under the High Case Scenario, the sustaining costs reach an all-time high of $12.1 billion dollars in 2046, averaging $10.6 billion over the 35-year window. In the Low Case Scenario, $8.4 billion will be spent on sustaining costs in 2046, with an average of $7.1 billion over the projection period.

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Figure 4.5 Sustaining Capital Requirements

(Million CDN$)

$14,000

$12,000

$10,000

$8,000

$6,000

Total Sustaining Capital Investments (Capacity, High Case Scenario)

Total Sustaining Capital Investments (Capacity, Low Case Scenario) $4,000 Total Sustaining Capital Investments (Capacity, Reference Case Scenario)

$2,000

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

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

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 51

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 4.6.

Figure 4.6 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

Source: CERI

By 2046, 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 1,259 MMcf/d in 2011 to 3,753 MMcf/d in 2046 under the High Case Scenario, 3,183 MMcf/d in the Reference Case Scenario, and 2,693 MMcf/d under the Low Case Scenario. The prospects for technology switching and efficiency improvements are substantial. This year’s forecast of natural gas demand is 1.0 percent lower overall for the Reference Case Scenario and 2.0 percent for the Low Case Scenario. 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

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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.3

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 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 facility; i.e., upgrading is not per barrel of SCO but per barrel of raw bitumen. Table 4.3 presents the emission factors used for each technology.

3 For more information on natural gas production forecast, please see CERI’s forthcoming study “Natural Gas Pathways”.

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Table 4.3 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”.

May 2013 54 Canadian Energy Research Institute

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.4 The following forecast of emissions is based on emission factors estimated and presented in CERI Study 1265 and again presented in Table 4.3 for ease of reference. Figure 4.7 illustrates the GHG emissions under CERI’s emissions factor assumptions. GHG emissions are expected to rise in tandem with oil sands production.

Figure 4.7 Greenhouse Gas Emissions

(CO2 eq. MT/year) 200

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

Source: CERI

4 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. 5 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

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 55

Emissions will rise from 47 Mt/year in 2011 to 55 Mt/year in 2012 to 156 Mt/year in 2046 under the Reference Case Scenario, to 190 Mt/year in 2046 in the High Case Scenario, and to 137 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 2011-2012.6 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 1990.7 This reduction in GHG intensity is significant, as larger and larger portions of production are derived from oil sands. Cumulative emissions in the Reference Case Scenario are projected to be 4,442 Mt from 2012 to 2046, which is 1.2 percent lower than last year’s 35-year cumulative emissions projection. This can partially be attributed to Shell’s Quest project, starting in late 2015, which will capture and store more than one million tonnes per year of CO2 produced at the Scotford Upgrader.

Oil Sands Royalties Figure 4.8 illustrates the bitumen royalty estimates under the Low, Reference, and High Case Scenarios both on an annual and cumulative basis (2012 – 2046). Royalty revenues rise in all three cases with the production as expected. Under the Low and High Case Scenarios by 2046 annual revenues reach $49 billion and $70.0 billion, respectively. Annual revenues amount to $58.6 billion by 2046 in the Reference Case Scenario. The shaded area represents the difference in estimates between scenarios which is equal to over $248 billion between the Low and Reference Case Scenarios, and about $264 billion between the High and Reference Case Scenarios. This difference is also evident in the cumulative estimates of $1.02 trillion versus $1.53 trillion for the Low and High Case Scenarios, respectively. The difference amounts to approximately $512 billion.

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

May 2013 56 Canadian Energy Research Institute

Figure 4.8 Oil Sands Royalties

Annual ($MM) Cummulative ($MM) $75,000 $1,700,000

$70,000 Estimated Royalties Range $1,600,000 CERI-Low Case $1,500,000 $65,000 CERI-Reference Case $1,400,000 $60,000 CERI-High Case Cumulative-Low Case (Right Scale) $1,300,000 $55,000 Cumulative-Reference Case (Right Scale) $1,200,000 $50,000 Cumulative-High Case (Right Scale) $1,100,000

$45,000 $1,000,000

$40,000 $900,000

$35,000 $800,000

$30,000 $700,000 $600,000 $25,000 $500,000 $20,000 $400,000 $15,000 $300,000 $10,000 $200,000

$5,000 $100,000

$- $0

2010 2021 2007 2008 2009 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 2040 2041 2042 2043 2044 2045 2046 Historical/ Outlook Actual

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 forecast and other agencies’ forecasts, such as CAPP,8 the ERCB,9 and the NEB10 that report oil sands forecasts. Figure 4.9 illustrates the comparison of bitumen production between CERI and the three agencies. The ERCB’s forecast goes out to 2021, CAPP’s to 2030 and the NEB’s to 2035. CERI’s forecast is truncated in 2035 for comparison reasons. CERI’s total production projection from oil

8 CAPP, 2012. Canadian Crude Oil Forecast and Market Outlook. http://www.capp.ca/forecast/Pages/default.aspx#sxhmTy33S4T1 9 ERCB, 2012. ST98: Alberta’s Energy Reserves and Supply/ Demand Outlook http://www.ercb.ca/portal/server.pt/gateway/PTARGS_0_0_308_0_0_43/http;/ercbContent/publishedco ntent/publish/ercb_home/publications_catalogue/publications_available/serial_publications/st98.aspx 10 NEB, 2011. Canada’s Energy Future: Energy Supply and Demand Projections to 2035 – Energy Market Assessment (http://www.neb.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/nrgyftr/2011/nrgsppldmndprjctn2035- eng.html

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 57

sands areas (including primary and EOR projects) is consistent with the other forecasts up to 2021. 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 other forecasts. Currently, all mined bitumen and a portion of in situ production is upgraded to SCO. According to the ERCB, in 2011, 9 percent of in situ production was upgraded to SCO. The 2011 production of SCO amounted to 865,000 BPD and is expected to increase to 965,000 BPD in 2012, averaging at just over a million barrels per day of production from 2012 to 2046.

Figure 4.9 Bitumen Production Forecast – Comparison

('000 b/d) 6,500

6,000 Total Bitumen Extraction - CERI Total Bitumen Extraction - ERCB 5,500 Total Bitumen Extraction - NEB 5,000 Total Bitumen Extraction - CAPP 4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

-

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

Actual/ Historical Outlook

Source: CERI, ERCB, CAPP, NEB

Illustrated in Figure 4.10 are the production projections by extraction type. Total mined bitumen production is expected to increase from 0.9 MMBPD in 2011 to its peak of just over 2 MMBPD by 2038, at which point the production remains flat for the remainder of the projection period. As well, in situ production is expected to increase from 0.8 MMBPD11 in 2011 to 3.7 MMBPD by 2046 due to the addition of new proposed projects and the accelerated development schedules for existing and approved projects. The increase in projected production is a result of relatively high oil prices and the availability of foreign capital investment. Mined bitumen maintains a majority status of oil sands volumes until 2014, when in situ production volumes overtake mined volumes. The share of bitumen production from mining is estimated to decrease from 51 percent

11 Including Primary and EOR projects.

May 2013 58 Canadian Energy Research Institute

in 2011 to 35 percent in 2046. By the end of the projection period in 2046, in situ bitumen accounts for 65 percent of total production volumes, or 3.7 MMBPD, compared to mined bitumen production at just over 2.0 MMBPD.

Figure 4.10 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

Source: CERI, CanOils

Given the production projection, the distribution of projects across various development stages is shown in Figure 4.11. The Figure illustrates that a large proportion of total projects are made up of on stream, approved, awaiting approval, and announced projects. As the proportion of on stream projects starts to decline from 100 percent in 2012 to 25 percent by 2046, the total proportion of approved, awaiting approval and announced projects increases to 65 percent by the end of the projection period. The remaining portion is represented by projects that are under construction.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 59

Figure 4.11 Net Bitumen and SCO Production by Project Status – Reference Case Scenario 12

('000 b/d) 6,000

5,500 Announced Awaiting Approval 5,000 Approved Approved - on Hold Under Construction 4,500 Onstream

4,000

3,500

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

Source: CERI, CanOils

Diluent Demand, Supply and Transportation As previously stated, in situ oil sands production will eventually exceed the production from oil sands mining extraction, indicating that most of the growth in oil sands production will be non-upgraded bitumen (as seen on Figure 4.12) blended with some type of diluent in order to be readily transported to markets.13

12 This graph does not include the forecast of primary and EOR projects. 13 Alternatively, given current pipeline takeaway constraints, companies have started to move bitumen by rail, which depending on the form being shipped can reduce the potential demand for diluent.

May 2013 60 Canadian Energy Research Institute

Figure 4.12 Non-upgraded Bitumen and SCO Shares of Total Volumes to Market

% of OS Product to Marlet 100%

90%

80%

70%

60%

50%

40% Non-Upgraded Bitumen (kb/d) 30% SCO Production (kb/d)

20%

10%

0%

2019 2034 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 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 Historical/ Outlook Actual

Source: CERI

Diluents are necessary in order to transport crude bitumen to markets via pipeline, and more recently via rail in the form of dilbit or railbit. Upgrading capacity only grows moderately up to a maximum of 1.3 MMBPD by 2027 and leveling off at 1.1 MMBPD from 2030 onwards;14 consequently, under the Reference Case Scenario, diluents will increasingly become necessary.

Figure 4.13 displays CERI’s outlook for diluent demand split between SCO, as used by companies that produce Synbit blends such as Long Lake Heavy and Surmont Heavy Blend as well as Dilsynbit blends such as Albian Heavy Synthetic; butanes used for heavy oil blending as reported by the ERCB, and pentanes plus/condensate (C5+ stream) assumed to be used by all other producers. This figure also displays non-upgraded bitumen production to illustrate that demand for diluent is consistent with increases in production. Finally, this figure provides a comparable projection for diluent demand as developed by the ERCB. CERI’s diluent demand projection is consistent with and comparable to the ERCB’s. The methodology for calculation of diluent demand is presented in the Cash Flow methodology section of Appendix A and is based on requirements for 21 API WCS of stream quality for movement via pipeline.

14 In this instance upgrading capacity refers to the total SCO volume production potential rather than the upgrading bitumen input capacity.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 61

Figure 4.13 Diluents Demand Projection– Reference Case Scenario

('000 b/d) ('000 b/d) 1,400 5,000 1,300 4,500 1,200 1,100 4,000

1,000 3,500 900 3,000 800 700 C5+/ Condensate (Thermal & Mining) 2,500 600 C5+/ Condensate (Primary & EOR) Butanes (CERI 2012 NGLs Report/ERCB) 2,000 500 SCO (Synbit/ DilSynbit) 400 Alberta Oil Sands Diluent Demand - CERI (kb/d) 1,500 Alberta Oil Sands Diluent Demand - ERCB (2012) (kb/d) 300 Non-Upgraded Bitumen (kb/d) (Right Axis) 1,000 200 500 100

- -

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

% of Diluent Demand 100%

90%

80%

70%

60%

50% C5+/ Condensate (Thermal & Mining) 40% C5+/ Condensate (Primary & EOR) Butanes (CERI 2012 NGLs Report/ERCB) 30% SCO (Synbit/ DilSynbit) 20%

10%

0%

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

Source: CERI, ERCB, CAPP, NEB

May 2013 62 Canadian Energy Research Institute

Consistent with other industry sources, diluent demand for 2011 was estimated to be under 0.3 MMBPD. The ERCB’s forecast indicates that by 2021, demand will increase to about 0.89 MMBPD while CERI’s estimate is 0.73 MMBPD. By 2026, CERI’s projection of diluent demand goes beyond the 1.0 MMBPD mark and by 2029 demand reaches 1.2 MMBPD and remains somewhat flat over the rest of the forecast period. This is consistent with Reference Case Scenario production projections. As seen in Figure 4.13, currently about 90 percent of the demand for diluent is made up of pentanes plus/condensate (C5+ stream) and that is expected to be the case moving forward as well.

Figure 4.14 illustrates examples of using different types of diluents for blending and the corresponding per barrel estimated net revenues based on 2011 market prices and CERI’s supply cost for a SAGD project at Hardisty. While it can be argued that the economics of blending butanes with crude bitumen are better than those of using pentanes plus/condensates, it must be taken into account that butanes have a higher vapour pressure than the C5+ stream and there might be pipeline restrictions in regards to the allowed butanes contents in the heavy oil blend. Meanwhile, it is also known that butanes added in the condensate pool incur a penalty, and there might also be issues with excess butane content in the crude blend at the refining end. The higher prices for SCO and light crudes, coupled with a larger per barrel diluent blending requirement makes the economics of synbit and light crude oil dilbits less compelling. Lastly, rail provides an option to ship bitumen without dilution in a heated rail car.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 63

Figure 4.14 Oil Sands Blend Diluent Requirements (%) and per Barrel Net Revenues

100% $16.00 95% $15.00 90% 17% 22% $14.00 85% 28% $13.00 80% 43% 75% 47% $12.00 70% $11.00 65% $10.00 60% 55% $9.00 50% 100% $8.00 45% $7.00 83% 40% 78% 72% $6.00

% of% Heavy Blendbbl 35% $5.00 30% 57%

25% 53% $4.00 Heavy BlendNet Revenue ($/bbl) 20% $3.00 15% Diluent Required per Barrel of Blend (%) $2.00 10% Bitumen Required per Barrel of Blend (%) $1.00 5% SAGD Heavy Blend Net Revenue ($/bbl) @ Hardisty (2011 Prices) 0% $- Clean Bitumen Railbit (17 API) Dilbit (21 API) Dilbit (21 API) Synbit (21 API) Dilbit (21 API) (9 API) No Diluent Pentanes Plus/ Butanes @ Pentanes Plus/ Synthetic Light Crude Oil (Heated Rail Condensate 600kg/m^3 = Condensate @ Crude Oil @ @ 840kg/m^3 Car) (Heated Rail 104 API 717kg/m^3 = 825kg/m^3 = = 37 API Car) 66 API 39 API Rail Pipeline Transportation Means/ Diluent Source: CERI Given the fact that a barrel of non-upgraded bitumen must be diluted (for pipeline transportation) and different types of diluent result in different composition of dilbits, it is of paramount importance to look at the availability of various diluents for oil sands. In that context, a look at the supply-demand balance for pentanes plus and condensate in the WCSB is shown in Figure 4.15.

May 2013 64 Canadian Energy Research Institute

Figure 4.15 Pentanes Plus/Condensate Supply and Demand in the WCSB

('000 b/d) 1,400 1,350 1,300 1,250 1,200 1,150 1,100 1,050 1,000 950 900 850 800 750 700 650 600 550 500 450 Required C5+ Diluent Imports (kb/d) 400 WCSB Pentanes Plus/ Condensate/ Upgrader Diluent Naphtha Supply (kb/d) 350 300 Alberta Oil Sands Diluent Demand - CERI (kb/d) 250 200 150 100 50

-

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Historical/ Outlook Actual Source: CERI As seen in Figure 4.15, pentanes plus/condensates have been imported to the WCSB as early as 2007. In 2011, the ERCB estimated that over 170,000 barrels per day of pentanes plus/condensates were imported into Alberta.15 According to the EIA, the US exported approximately 100,000 BPD of pentanes plus via pipeline into Canada in 2011.16 Other sources include overseas markets, for example, Cenovus brings in condensate imports from overseas markets through a diluent import port terminal in Kitimat. Based on CERI’s analysis the C5+ diluent imports will start to increase from their current level to over 1.0 MMBPD to meet the diluent demand by 2029. Given the outlook for increased liquids production in the United States from areas such as the Eagle Ford and Marcellus (as well as possibly the Utica), a large part, if not most of these diluent import requirements are expected to be met by supplies from these areas.

Figure 4.16 illustrates the existing and forecasted pipeline capacity for diluent imports into the WCSB. The pipeline capacity includes the existing Southern Lights pipeline, which moves diluent from the Chicago area to Alberta and its potential future expansions in two stages to bring up the capacity to 400,000 BPD. The current infrastructure also includes the Kitimat diluent import terminal with a small capacity of 25,000 BPD, which is expected to come off service once the Shell LNG project is commissioned around 2020; the Cochin pipeline reversal which is expected to be in full

15 CERI’s 2011 estimate is 120,000 b/d. 16 EIA only tracks pipeline and not rail movements. Some volumes could have been imported via rail from the US.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 65

service by 2014 with the ability to move 75,000 BPD, and the possible diluent line associated with the construction of the Northern Gateway pipeline.

Figure 4.16 Current and Proposed Pipeline Capacities for Diluent Imports

('000 b/d) 1,200 1,150 1,100 1,050 1,000 950 900 850 800 750 700 650 600 550 500 450 400 350 300 250 200 150 100 50

-

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Historical/ Actual Outlook Diluent via Rail/ New Pipelines/ Demand Reduction/ Potential Shortfall Northern Gateway Diluent Line (kb/d) (Risked) Southern Lights Pipeline Expansion 1 (Full Looping) (kb/d) (Risked) Southern Lights Pipeline Expansion 1 (Minor Looping) (kb/d) (Risked) Cochin Pipeline Reversal (kb/d) Southern Lights Pipeline (kb/d) Kitimat Import Terminal (kb/d) Required C5+ Diluent Imports (kb/d) Source: CERI

Of the infrastructure depicted in Figure 4.16 only the Southern Lights and Cochin pipelines can be expected to proceed as planned. These pipelines will have connections to the Explorer and Capline pipelines (USGC to Chicago area), thus connecting USGC condensates and pentanes plus supplies to Alberta oil sands producers and effectively acting as diluent recycling lines once Canadian oil sands blends are able to reach the USGC refining hub in significant volumes. The start dates for the Southern Lights pipeline expansions 1 and 2 were assigned based on market need and requirements. The same applies for the Northern Gateway diluent line, indicating this capacity is highly speculative and risked.

It can be observed that past 2022, there is not going to be enough pipeline capacity to carry the C5+ stream diluent imports. If the Northern Gateway diluent line will not materialize, the date, by which pipeline capacity becomes inadequate, shifts to 2020. In the absence of new diluent pipelines, rail availability, use of alternative diluents, or an overall demand reduction for C5+ streams, there will be a diluent shortfall in which case, alternatives will be needed. Some alternatives include technological advancements on the bitumen processing side such as partial bitumen upgrading in the reservoir or the

May 2013 66 Canadian Energy Research Institute

field such as Ivanhoe Energy’s “Heavy-to Light” (HTL) process17 or the Meg Energy’s HI-Q project18 or producers can increase SCO production, thus reducing the need for diluent.

Yet another alternative is to move bitumen crude by rail. Moving diluted bitumen or dilbit by rail makes no difference to the overall diluent requirements to oil sands producers, however, other options such as railbit and clean bitumen by rail do. Railbit is a version of dilbit with a lower diluent requirement, generally in the range of 15 to 20 percent as opposed to about 30 percent in dilbit. Clean bitumen by rail, as the name implies, means transporting crude bitumen without any diluent or blending agent. Despite reduced diluent requirements, railbit and clean bitumen shipping requires expensive specialized coiled and heated tank cars for shipping. Additionally, at the refiners’ offloading facilities, steam capabilities are required in order to move the railbit or crude bitumen from the coiled tank cars to the refining facility. Nonetheless, if rail were to move large volumes of bitumen crude, the potential reduction in incremental diluent imports would be significant. In the case of clean bitumen by rail, for every 2.6 barrels of clean bitumen transported via rail (as opposed to pipeline), demand for diluent drops by 1 barrel of C5+ diluent stream. In the case of railbit, one barrel of railbit, which requires 17.5 percent of diluent blending, would result in 46 percent less diluent needed per barrel of railbit than in the dilbit case.19

Figure 4.17 demonstrates the potential for post-2012 incremental diluent import reductions if railbit was used to replace dilbit transport for 25, 50, 75, or 100 percent of the post-2012 incremental oil sands production. As shown earlier, the diluent imports are set to grow by an additional 900,000 BPD by 2030 if all the new oil sands production volumes after 2012 were to be shipped in dilbit form, either via pipeline or rail (i.e., the red line in the Figure). Alternatively, if the same volumes were moved as railbit, only 400,000 BPD of diluent imports would be required above 2012 levels. If all volumes were moved as clean crude bitumen by rail, there will not be a need for any incremental imports of diluent.

By any measure, the amount of C5+ stream diluent required to move oil sands production to market is expected to be very large over the long-term. These volumes are increasingly expected to be sourced as imports from the United States, for which various diluent import infrastructure projects are planned but are not guaranteed. The potential for large scale diluent movement by rail is possible later in the forecast period or in the absence of timely pipeline development. Meanwhile, diluent demand could be

17 Ivanhoe Energy. http://www.ivanhoeenergy.com/index.php?page=htl_process_overview. Accessed on March 29, 2013. 18 Oil & Gas Inquirer. “MEG files for 3,000-barrel-per-day partial upgrading technology facility” http://www.oilandgasinquirer.com/index.php/news/regional/northeastern-alberta/436-meg-files-for-3- 000-barrel-per-day-partial-upgrading-technology-facility. Accessed on March 29, 2013. 19 That is, at 28% blending (dilbit) 2.56 barrels of bitumen need 1 barrel of diluent, at 17.5%, 4.72 barrels of bitumen require 1 barrel of diluent. Barrel/ barrel diluent reduction =1-(2.56/4.72) = 0.457 or ~46%

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 67

curtailed significantly if partial upgrading, full upgrading, solvent aided processes, or railbit and clean bitumen movements by rail are implemented as alternatives to the increasing outlook for non-upgraded bitumen production over the long term. These are all alternatives that should be considered in case diluent availability becomes an issue.

Figure 4.17 Railbit Transportation Options and Changes to Diluent Import Requirements

('000 b/d) 1,100

1,000

900

800

700

600

500

400

300 Potential Diluent Import Demand Reduction from Incremental Railbit Transportation Alberta Oil Sands Diluent Import Demand @ 25% of Post-2012 Incremental OS Volumes as Railbit 200 Alberta Oil Sands Diluent Import Demand @ 50% of Post-2012 Incremental OS Volumes as Railbit Alberta Oil Sands Diluent Import Demand @ 75% of Post-2012 Incremental OS Volumes as Railbit 100 Alberta Oil Sands Diluent Import Demand @ 100% of Post-2012 Incremental OS Volumes as Railbit Post-2012 Required C5+ Incremental Diluent Imports (kb/d)

-

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

Source: CERI

Capital Investment and Operating Costs Initial (or strategic) and sustaining capital requirements are broken down by project type and are illustrated in Figures 4.18. Over the 35-year projection period from 2012 to 2046 inclusive, the total initial and sustaining capital required for all projects is projected to be $546.7 billion under the Reference Case Scenario, comprised of $240.7 billion in initial capital costs and $306 billion in sustaining capital. 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 2012 to 2046, it is projected that $229.3 billion (initial and sustaining) will be invested into mining projects and $283.1 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 2012 to 2046, amounting to $34.3 billion.

May 2013 68 Canadian Energy Research Institute

Figure 4.18 Total Capital Invested (2012-2046) by Project Type – Reference Case Scenario

(Million CDN$) $300,000 Strategic Capital Sustaining Capital $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 4.19. 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 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 and approach zero 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 2019 at $55.6 billion. The total operating costs average $34 billion a year and over the forecast period cumulatively add up to $1,195.5 billion.

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 69

Figure 4.19 Total Cost Requirements – Reference Case Scenario

(Million CDN$)

65,000 Total Operating Costs (Production, Reference Case Scenario)

Total Sustaining Capital Investments (Production, Reference Case Scenario) 60,000

Total Strategic Investments (Production, Reference Case Scenario) 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 4.20 presents a comparison between CERI’s Reference Case Scenario projection of royalties and those of ARC Financial/CAPP (2011) as well as the latest estimates from Alberta Finance (Budget 2013). The Figure also provides last year’s estimates from both CERI (Study No. 12820) and Alberta Finance (Budget 2012). The large year-over-year revisions to the royalties’ forecasts21 are indicative of how sensitive royalties are to changes in market conditions and market prices.

Revisions to this year’s bitumen royalty estimates by CERI amount to a combination of lower royalty rates going forward (lower WTI price forecast), a wider than previously assumed light-heavy differential, higher condensate costs, higher operating and capital costs, slower production levels, as well as short- to medium-term infrastructure constraints on local crude markets.

20 CERI Study No. 128, “Oil Sands Supply Costs and Development Projects (2011-2045)”, March 2012. 21 As an example, Alberta Finance estimated 2013 royalties to be $7.6 billion in Budget 2012 versus $3.7 billion in Budget 2013, that is, a $3.9 billion difference or a 51% reduction. CERI’s estimates are $6.2 (last year’s update) and $5 billion (this year’s update) respectively, or a $1.2 billion difference (20% reduction).

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Figure 4.20 Alberta Oil Sands Royalties, Revenues Collected (2007-2010) and Outlook (2011-2015)

$MM (Nominal) $11,500 $11,000 CERI (Current) $10,500 CERI (Study No. 128) $10,000 CAPP/ ARC (2011) $9,500 $9,000 GOA (Budget 2012) - Calendar Year $8,500 GOA (Budget 2013) - Calendar Year $8,000 $7,500 $7,000 $6,500 $6,000 $5,500 $5,000 $4,500 $4,000 $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $- 2007 2008 2009 2010 2011 2012 2013 2014 2015

Sources: Government of Alberta, ARC Financial Corp., CERI

CERI’s estimates developed in Study No. 12822 were lower than those from Alberta Finance (Budget 2012). This year’s estimates are higher than those provided by Alberta Finance in Budget 2013, which are significantly more conservative than their previous projections. Over the short-term, CERI’s royalty projections are consistent with both ARC’s and Alberta Finance’s projections. Note that for the historical years (2007-2011), CERI’s results are estimated whereas ARC’s results come from CAPP statistics. The Alberta Finance numbers come from the Alberta Department of Energy and provincial budgets. CERI’s estimates are on target with actual data. Note that differences between CAPP/ARC’s numbers and those for the Alberta Government have to do with differences in annual reporting, as the government reports results according to a fiscal year (April- March) whereas CAPP’s numbers are given on a calendar year basis (January- December).

Figure 4.21 presents the results of CERI’s royalty calculations for this year’s update and compares the results with the previous edition of this study (dotted lines).23 For the first time, this year’s update includes royalty revenues collected from primary and EOR projects that fall within the defined oil sands areas.

22 CERI Study No. 128, “Oil Sands Supply Costs and Development Projects (2011-2045)”, March 2012. 23 Ibid.

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Under the Reference Case Scenario, royalties collected from the oil sands industry are expected to exceed $10 billion by 2017 and $30 billion by 2026 when the number of project phases in post-payout (175) surpasses the number in pre-payout (60). The pivot year when there are more project phases in post-payout (107) than in pre-payout (101) is 2022. After 2025, 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 $58.6 billion. Between 2012 and 2046 a total of over $1.2 trillion is estimated to be collected by the Alberta Government from oil sands operators, a figure just below the equivalent of the current value of Canada’s GDP.

The Figure also illustrates a zoomed-in 10-year forecast of royalties from 2012 to 2022. Royalties are set to increase from 4.3 billion in 2012 to 22.1 in 2022, cumulatively adding to $133 billion by the end of 2022, all things being equal.

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Figure 4.21 Alberta Oil Sands Royalties, 2007-2046

Annual ($MM) Cumulative ($MM) $65,000 $1,400,000

$60,000 Primary/ EOR $1,300,000 In Situ Solvent $55,000 In Situ $1,200,000 Mining $1,100,000 $50,000 Total Oil Sands Royalties 2012 Royalty Curve (Study No. 128) $1,000,000 $45,000 Cumulative (2012 - 2046) (Right Scale) $900,000 $40,000 2012 Cumulative (Study No. 128) $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

2014 2007 2008 2009 2010 2011 2012 2013 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 Historical/ Outlook Actual Annual ($MM) Cumulative ($MM) $26,000 $140,000 $25,000

$24,000 Primary/ EOR $130,000 $22,111 $22,111 $23,000 In Situ Solvent $22,000 $120,000 $21,000 In Situ $20,190 $110,000

$20,000 Mining $18,467 $19,000 Total Oil Sands Royalties $100,000

$18,000 $16,468 $17,000 Cumulative (2012 - 2046) (Right Scale) $90,000 $16,000

$15,000 $13,433 $80,000 $14,000

$13,000 $11,420 $70,000 $12,000 $11,000 $60,000

$10,000 $8,663 $9,000 $50,000

$8,000 $6,743

$7,000 $6,280 $40,000 $4,960 $4,960

$6,000 $4,535

$4,271 $4,271 $30,000 $3,978 $3,978 $5,000 $3,711

$4,000 $2,695 $20,000 $3,000 $2,000 $2,000 $10,000 $1,000 $- $0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Historical/ Actual Outlook

Source: CERI

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Chapter 5 Transportation

This chapter focuses on the proposed development of export pipeline infrastructure relating to Alberta’s oil sands.1 With expected significant growth in both SCO and bitumen production, the need for expansion in existing oil pipeline capacity comes at the forefront of challenges that the oil sands industry is facing today. It is also important to stress how some excess capacity is crucial to be able to manage pipeline maintenance times and to provide flexibility for new market development. Not to mention that constraints in pipeline capacity and the lack of access to new demand centers have deepened the discount between WTI and Western Canadian crudes and hence have had a severe impact on the netbacks realized by Canadian producers. With the recent failure to obtain approval of the Keystone XL pipeline to the US; Northern Gateway’s public hearings being tied up for the near-foreseeable future; Kinder Morgan’s extended open season for Trans Mountain (TMX) expansion; and rail emerging as an alternative to move bitumen to markets; 2013-2014 promises to be a period of transformation for producers and shippers.

Prior to the shale and tight oil boom in the US and significant expansion of oil sands in Canada, the US and Canadian system for delivering crude oil to market was stable and relatively predictable. In general, the US and Canadian crude oil pipeline networks were originally designed for taking crude oil into the US Midwest. Then matters started to change as production started to rise, and pricing for WTI at the Cushing, Oklahoma hub, which had always run in close parity with Brent, started to disconnect. Discounts deepened, affecting essentially all inland lower-48 crude grades, as well as Canadian crude oils (since these are also priced off WTI). Since January 2011, these discounts have been steep and have been considered ‘structural’. West Coast and the Gulf Coast Expanding crude production in Western Canada, as well as the Bakken and other shale plays in the US have challenged the North American pipeline infrastructure. As a result, pipelines are operating at near full capacity and delivering crudes to hubs where lack of capacity leads to congestion, as seen at Cushing, which continues today. It has become a race between expanding supply and attempts to put adequate capacity in place in order to move crude oil to markets beyond the US interior and inland Western Canada.

Two such pipeline projects are currently being reviewed. However, no one would have anticipated that these projects would become the focus of ‘political heat’ at the highest levels. The TransCanada Keystone XL project, originally intended as a 700,000–900,000

1 Existing pipeline infrastructure is described in the Appendix.

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BPD line to mainly carry oil sands streams from Hardisty, Alberta, to the Gulf Coast via Cushing, has become a focal point of the political and environmental pro- and anti-oil sands debate in the US. Likewise, the Enbridge Northern Gateway project that would initially take 525,000 BPD of heavy oil sands streams west to British Columbia’s port of Kitimat – and then to markets mainly in Asia – has become the centre of heated support and intense resistance in Canada.

Since then, the Keystone XL project has been split into two parts: a southern leg project from Cushing to the Gulf that has received all the permissions necessary to proceed, and which is expected to start operations by late 2013; and a northern segment from Hardisty to Steele City, Nebraska (where there is an existing line on to Cushing), which hasn’t yet received the US presidential permit. Start-up would likely be no earlier than 2015. For the Northern Gateway project, Enbridge has filed an application with the Canadian National Energy Board (NEB), but a review will take at least until the end of 2013. The expected start-up for this is around 2017, but some delays are likely.

The response to the delays on these two headline projects from the midstream industry has been an almost ever-changing array of new developments and proposals. There are already several project proposals related to modifying existing pipelines and/or taking advantage of existing rights-of-way to construct new parallel pipelines. A leading example is the 300,000 BPD Trans Mountain pipeline from Edmonton to Vancouver, which has recently been heavily over-subscribed. Currently, a spur pipeline carries the bulk of the crude to US refineries in Washington State and another 50,000 BPD has consistently gone to a refinery at Burnaby near Vancouver. As a result, historically, less than 50,000 BPD of crude has been exported over the one and only export dock that currently exists for Western Canadian crudes. Operator Kinder Morgan has obtained sufficient shipper commitments to support expanding the Trans Mountain capacity by 400,000 BPD. Much of the increased throughput would be moved over the Vancouver (Westridge) dock, with destinations mainly in Asia. The expansion has a start-up date of 2016, although this could slip because of concerns over the resulting increase in tanker movements in the already busy Port Metro Vancouver harbour. Bottlenecks in the System The Northern Gateway and the Trans Mountain expansion represent the only pipeline projects that would take Western Canadian crude west to the Pacific. All other pipeline capacity moves Western Canadian crudes south into the US Rocky Mountain and Midwest regions, from which there is an onward pipeline to Sarnia in Ontario. After recent expansions, which include the base Keystone system and Alberta Clipper, there is more than 3.5 MMBPD of cross-border capacity from Alberta into the US interior. There are, however, bottlenecks in moving Canadian crudes through and out of the Midwest. We have identified such pinch points along these crucial oil sands export routes. They are listed below.

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Enbridge Lakehead System South of Clearbrook/Superior Enbridge’s Mainline moves a variety of crude types from Edmonton and Hardisty to Superior, Wisconsin. From Superior, crude is delivered to the Pine Bend refinery and Line 5 moves product further east to Sarnia, but the bulk of the throughput is moved south to refineries in the Chicago area via the Lakehead System. These southern legs are capable of transporting 1.3 MMBPD, but also have accommodated increasing amounts of Bakken production at the Clearbrook connection point, northwest of Superior. Enbridge’s Southern Access project added 400,000 BPD of capacity south of Superior when it came online in 2009, and the addition of further pumping stations is planned that will raise the line’s throughput. Nevertheless, growing oil sands and Bakken volumes will keep this route near its stated capacity. Beyond the Lakehead System, Enbridge’s Spearhead System transports crude from Flanagan, Illinois to Cushing, Oklahoma. Spearhead’s capacity is 193,300 BPD. Enbridge is moving ahead with the Flanagan South project, which would add an initial 585,000 BPD of capacity (expandable to 800,000 BPD) along the route of Enbridge’s existing Spearhead Pipeline between the Flanagan, Illinois Terminal, southwest of Chicago, to Enbridge’s Cushing, Oklahoma Terminal.2 Other company proposals, such as the reversal of the existing 1.2 MMBPD Capline pipeline to Louisiana, would also help transport oversupplied Midwest markets south.

Figure 5.1 Enbridge’s Mainline Enhancement – US

Source: Enbridge

2Enbridge News Release. http://www.enbridge.com/~/media/www/Site%20Documents/Investor%20Relations/2012/2012_ENB_In vestment_Community_Booklet.ashx. Accessed on November 1, 2012.

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TransCanada Keystone XL TransCanada operates the Keystone base pipeline which began operations in June 2010 after converting a gas pipeline from Hardisty, Alberta west to Manitoba and constructing a new pipeline from Manitoba south to Steele City, Nebraska and then east to Patoka, Illinois. In 2011, the line’s capacity was expanded to 591,000 BPD, and the pipeline’s southern path from Steele City to Cushing was extended. The proposed Keystone XL project would establish a direct route from Hardisty to its existing Steele City connection point, but US government approval is needed. Keystone XL also includes plans to construct a new pipeline from Cushing to the Nederland, Texas terminal, allowing access to the Gulf Coast market. Approval for the Gulf Coast portion has been granted.

Kinder Morgan Express-Platte3 Kinder Morgan’s Express Pipeline, with a stated capacity of 280,000 BPD, feeds into Casper, Wyoming where the Platte system moves the crude south and east to Wood River, Illinois. Platte capacity shrinks to 145,000 BPD past Guernsey, Wyoming while also adding volumes from the Rocky Mountain region, including Bakken oil. The constrained capacity on this leg of the pipeline limits the amount of volumes capable of moving south on the Express line. Kinder Morgan’s Pony Express, which will be converted from the existing gas to an oil line, has secured sufficient project support in earlier open seasons to transport up to 230,000 BPD from Guernsey, Wyoming to Ponca City and Cushing, Oklahoma starting in the 3rd quarter of 2014.

These potential pinch points are in addition to the current and well-publicized shortfall in capacity to move crude out of Cushing. Increasing supplies from Western Canada, the Bakken, the Permian Basin region (West Texas), as well as from Oklahoma and Kansas, are all creating pressure to move crudes mainly from the north into Cushing and out in multiple directions, but especially south to the large refining centres on the Gulf Coast. As well, the lack of capacity to move oil supply directly to the US Gulf Coast is leading to increased volumes arriving at Cushing and adding to the oversupply problem there. Continental Inland Expansions, Extensions, and Conversions Until recently, there was only one pipeline that flowed south to the Gulf Coast – the Pegasus line (up to 93,000 BPD) – which runs from the Chicago area to the Gulf and carries mostly Western Canadian crude. This pipeline was reversed in 2006 and expanded to its current capacity in 2009. The Seaway line used to flow north to Cushing, but this has recently been reversed with original capacity of 150,000 BPD. It is now expanded to a capacity of 400,000 BPD from Cushing to the Gulf Coast and by mid-2014 further expansion to 600,000 BPD.

3Spectra Energy Corp. bought the Express-Platte Pipeline System for $1.25 billion in cash; the deal is set to close in the first half of 2013.

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Associated with these expansions is a new Flanagan South line that will use the right-of- way of the existing Spearhead line to add nearly 585,000 BPD of initial capacity4 from Chicago to Cushing with an in-service date of mid-2014. This will help relieve the bottleneck in the Chicago area and will enable Canadian and Bakken crudes to flow via Seaway to the Gulf Coast. A Seaway reversal and expansion, with the Keystone XL southern leg, will add over 1.65 MMBPD of capacity out of Cushing to the Gulf by 2014. This will substantially alleviate the ‘Cushing congestion’ and should, consequently, narrow the WTI-Brent spread, as well as Western Canadian-WTI differentials, at least in the short-term.

Figure 5.2 Enbridge – Gulf of Mexico Expansion

Source: Enbridge Inc.

Growing Western Canadian and Bakken supplies have also led Enbridge to propose modifying its existing pipeline through Eastern Canada. The system already carries Western crudes east as far as the refining complex at Sarnia. Another line (Line 9) originally used to run east from Sarnia to Montreal, but was reversed; is now bringing imported crudes west via Montreal and a connecting Portland, Maine to Montreal Pipeline (PMPL) into Sarnia. Enbridge has now proposed to re-reverse Line 9 with a stated capacity of 240,000 BPD so that it runs east to Montreal, where there is access to two refineries in Montreal and Quebec City. This could also tie-in with a possible reversal of the PMPL to take Western Canadian and Bakken crudes out to the Atlantic,

4 Expandable to 800,000 BPD.

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from where they could reach refineries in the Canadian Maritimes, the US East Coast and potentially beyond. Enbridge has already reversed a short section of the line and has applied for permits that would allow full reversal. This project, like Northern Gateway and Keystone XL, is meeting some resistance on the environmental basis, and so its timing is uncertain.

Figure 5.3 Enbridge – Eastern Expansion

Source: Enbridge Inc.

TransCanada’s Energy East Pipeline Project will switch one or more existing gas pipelines that run from Alberta to Quebec into crude service if the proposal comes to fruition. The concept is attracting interest and a possible capacity range of 500,000-850,000 BPD is being proposed.5 The main objective would be to carry Western Canadian crudes, including oil sands, synthetic crude and/or diluted bitumen, through to Quebec and then to the 340,000 BPD Irving refinery in New Brunswick. TransCanada is holding a binding open season from April 15 to June 17, 2013 to obtain firm long-term commitments from interested parties for their Energy East Pipeline Project. This is the next step in the process in determining the commercial viability of converting more of the capacity of the Canadian mainline from natural gas to crude oil service, in order to supply Eastern Canadian markets with oil produced in the West. Part of the impetus behind this

5 TransCanada Inc. Energy East Pipeline Project. http://www.transcanada.com/6246.html. Accessed on March 29, 2013.

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possible gas line conversion and the Enbridge Line 9 project is uncertainty over the major projects that would move Western Canadian crudes to the west, and south to the Gulf Coast. To the extent that either the TransCanada or Line 9 projects go ahead, they will enable light sweet and medium sour crude oils to move to Eastern Canada and possibly also to refineries on the US East Coast and free up some room on the pipelines heading south to the US.

Figure 5.4 TransCanada’s Energy East Pipeline Project

Source: TransCanada Inc. Rail, Rail and More Rail Uncertainties over key pipeline projects, and steep discounts in US lower-48 and Western Canadian crude prices, have spurred the above-mentioned proposals to modify and expand existing pipeline infrastructure, but they have also led to a growing role for rail. This is especially visible in the Bakken.

The year 2012 was the point in time when crude movement via rail started to catch on as a means to move Western Canadian crudes. Small volumes of Western Canadian crudes have recently moved to the Western US, the Gulf Coast and the East Coast, as well as Ontario via rail. What is new is that longer term commitments and unit train

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developments are starting to surface – for instance, for the movement of Bakken crudes at scale to the Irving refinery in New Brunswick.

Rail movement via ‘manifest’ train can be three times the cost of pipeline. However, unit trains narrow the gap and shorten the delivery time. Moving oil sands bitumen by rail can come even closer to pipeline costs as less diluent is needed; even bitumen with no diluent can be carried if the rail cars are heated. Given the severe price discounts on heavy Canadian crudes, rail looks to be an attractive option. Both pipeline and rail are also tying in with barge movements, notably from the Midwest to the Gulf Coast, using rail or pipeline for part of the way and then barges down the Mississippi River for the last leg. Within the Gulf Coast, midstream companies are also expanding their options to move crudes along the coast (for example, Eagle Ford crude east along the Gulf and also via tanker up to the East Coast) and to move crude west to rail terminals in St. James, Louisiana.

The end result is that the combination of pipeline expansion, and rail and barge transportation options will enable US lower-48 and Western Canadian crudes to flow in an increasingly less restricted way to coastal markets. Data shows that as of the third quarter of 2012, US and Canadian oil movements by rail have already increased by 650,000 BPD, compared to their historical level.6 This is consistent with the surge in rail loading and offloading capacity that, by the end of 2012, was over 700,000 BPD of receiving capacity in operation: with over 200,000 BPD on the Eastern coast (US and Canada), 450,000 BPD on the Gulf Coast and 50,000 BPD on the West Coast. By the end of 2013 and into 2014, this rail capacity will have essentially doubled to over 1.4 MMBPD, with nearly 600,000 BPD of receiving terminals on the Eastern Seaboard, close to 750,000 BPD on the Gulf Coast and around 110,000 BPD on the West Coast.

By 2015/2016, this new capacity may well have grown further and will have been joined by 1.65 MMBPD of new pipeline capacity to the Gulf Coast from Cushing. Hence, a total of over 3 MMBPD of capacity will exist to take US and Western Canadian crudes to coastal markets in the US and Canada. This capacity growth is well under way; it is developing rapidly and is substantial.

The net effect of all these developments is that the US and Canadian crude oil logistics system is changing rapidly as it seeks to adapt to a new reality of steadily growing oil production, both north and south of the border. There is appreciable uncertainty, however, over how the system will evolve in the longer term. It will depend in part on whether (and when) a few major pipeline projects are brought online, as well as on how much Western Canadian crude ends up moving west and to Asia versus south into the US and east into Eastern Canada. By 2014, WTI discounts could be partially alleviated, but we are witnessing a race between production growth and infrastructure

6 EIA. The estimate might include some volumes of NGLs.

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restructuring. Crude oil discounts could persist to 2020 – and even beyond – if US shale production rises at optimistic rates. The emergence of rail is an important new factor. Although rail car availability is a constraint in the short-term, terminals are low cost compared to pipelines, can be put online within 12-18 months, and offer shorter payback times.

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Chapter 6 Market Diversification

Potential Netbacks for Oil Sands Crudes and Pricing Dynamics While the supply costs chapter presented the cost of producing a barrel of bitumen and SCO at the field level as well as a blended barrel (dilbit) at Cushing (US PADD II: Midwest), this chapter will describe how accessing other markets might potentially change the netbacks for dilbit crudes.1 The markets that in CERI’s view are the most feasible over the coming years are the US PADD III - Gulf Coast, and the US PADD V - US West Coast.

Figure 6.1 presents Canadian heavy crude oil supply and disposition in 2011, which is the latest actual data used in this analysis.

Figure 6.1 Canadian Heavy Crude Oil Supply and Disposition, 2011

Source: Background images from RASC and EIA,2 data from NEB,3 analysis and figure by CERI.

1 The focus will be on dilbit-type crudes since our analysis indicates that going forward, the largest share of oil sands production will be non-upgraded or diluted bitumen as opposed to upgraded or synthetic crude oil. Furthermore, Western Canadian Select (WCS) will be used as the representative price for dilbit. While WCS is not technically a pure dilbit blend, CERI’s analysis indicates that between 2005 and 2013 WCS prices exhibit a 0.999 correlation with Cold Lake Blend (CLB), which is in turn a dilbit blend representative of oil sands crudes. 2 Canada Map: Royal Astronomical Society of Canada (RASC), Education: http://www.rasc.ca/astro-canada US Map: US Energy Information Administration (EIA), Gasoline and Diesel Fuel Update, Petroleum Administration for Defense Districts (PADDs): http://www.eia.gov/petroleum/gasdiesel/diesel_map.cfm 3 National Energy Board (NEB), Statistics, Crude Oil and Petroleum Statistics: http://www.neb- one.gc.ca/clf-nsi/rnrgynfmtn/sttstc/crdlndptrlmprdct/crdlndptrlmprdct-eng.html

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In 2011, dilbit accounted for over 1,000 MBPD (or 60 percent) of Canadian heavy crude oil supplies,4 or 33 percent of the total (light and heavy: 3,176 MBPD) Canadian crude oil supply, a significant amount by any measure. Furthermore, only about 12 percent of the total heavy crude oil supplied in Canada was used within the country while the remaining 88 percent was accounted for by exports (87 percent) and a statistical difference (1 percent). This is the case both as a function of crude oil transportation (pipeline) infrastructure but also downstream or refining capabilities for processing heavy crudes.

The size of the US market for Canadian heavy crude supplies is quite significant at about 84 percent of the total. In turn, the US receives 97 percent of Canadian heavy crude oil exports. Within the US, the most important markets for Canadian heavy crudes are the US Midwest (PADD II, 72 percent of total exports), followed by the Rockies region (PADD IV, 12 percent), US Gulf Coast (PADD III, 6 percent), West Coast (PADD V, 4 percent), and the East Coast (PADD I, 2 percent). Within these areas, the top five sub-regions for Canadian heavy crude oil exports include the Chicago area (23 percent of total exports), followed by the Wood River area (18 percent), Twin Cities (17 percent), Billings (8 percent), and Toledo (7 percent), as seen on Figure 6.2.

Figure 6.2 Canadian Heavy Crude Oil Exports by Region, 2011

Source: NEB data, analysis and figure by CERI

4 Within this context, dilbit supply includes non-upgraded bitumen produced volumes as reported by the NEB plus diluent volumes estimates by CERI

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Given that the majority of Canadian heavy crude oil supplies are destined to PADD II in the US, the main price for Canadian heavy crudes, and oil sands crude for that matter, at Hardisty (AB), is dictated by the refiner’s value of the crude in the US Midwest. The value of the crude to the refiner is in turn dictated by a series of factors including the crude’s gross product worth (GPW), or the value of the refined petroleum products (RPPs) yield from the crude, processing cost, transportation costs, refinery margins, and the availability and price of competing crudes. Given that the vast majority of heavy crudes processed in PADD II are Canadian crudes,5 the price of Canadian heavy crudes is then dictated by the availability of required refining capacity in the area for such crudes.

CERI estimates that between 2005 and 2011 the price differential between West Texas Intermediate (WTI, North America’s light sweet crude benchmark) and WCS at the US Midwest, was reflective of differences between WCS refining margins for a ‘very complex’ (coking) refinery and a ‘complex’ (cracking) refinery. In 2012, the WTI-WCS differential in the US Midwest has become more reflective of differences in refining margins between coking6 and simple refineries, which resulted in a wider differential. This means that Canadian heavy crude volumes are exhausting the required refining capacity in this market. If this situation persists, Canadian heavy crudes will need to be sold at steep discounts in order to access the simple refinery market. This supports the ongoing debate of opening new markets for oil sands crudes.

Going forward, given the US proximity and long-standing trading relationship, CERI believes that the closest markets will be accessed first and the US will continue to be the largest market for such crudes. Within that context, and based on the information presented in Table 6.1, CERI believes that beyond PADDs II and IV (the current largest markets for Canadian heavy crudes), PADDs III and V7 represent the best market prospects for Canadian oil sands producers in the coming years.

5 Hart Energy, Refining Unconventional Oil, US Resource Invigorate Mature Industry: http://www.hartenergy.com/Upstream/Research-And-Consulting/Refining-Unconventional-Oil/ 6 Coking capacity is a good measure of the type of refineries which are able to handle heavy crude types such as Canadian dilbits. 7 Various reports argue that biggest challenge to enter this market is California’s Low Carbon Fuel Standards (LCFS)

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Table 6.1 US Refining and Coking Capacity, 20118 Region Refining US Refining Coking/Refining Capacity Capacity Coking Capacity Capacity (kb/d) (%) (kb/d) (%)

PADD I 1,205 7 94 8

PADD II 3,648 22 374 10

PADD III 8,516 50 1,318 15

PADD IV 620 4 80 13

PADD V 2,948 17 530 17

Total US 16,937 100 2,396 14

Source: EIA data,9 analysis and table by CERI.

While CERI is aware of the expansions to refining and coking capacities in existing markets, our view is that going forward the supply will exceed demand in those markets and new markets will be needed for oil sands expansion to be feasible. Within this context, CERI has developed an analysis of possible prices that could be realized by oil sands producers in such markets together with their respective transportation options and an analysis of what that means to local prices for heavy crudes in the Western Canadian Sedimentary Basin (WCSB).

This analysis is based on data for 2011, but we believe it to be an accurate reflection of what the future could represent for WCS based prices. To be clear, that is not in terms of absolute prices but rather the different pricing relationships established in this analysis.

8 Refining Capacity = Atmospheric Crude Oil Distillation Operating Capacity, barrels per Calendar Day as of January 1, 2011 Coking Capacity = Downstream Charge Capacity of Operable Petroleum Refineries, Thermal Cracking (Coking), barrels per Calendar day as of January 1, 2011 A good rule of thumb is that for each barrel of coking capacity available, about 2-3 barrels of heavy crude can be processed. Therefore, if a refinery has a coking capacity of 33 kb/d, it is estimated that it could absorb about 66-99 kb/d of heavy crude. This a simple generalization and it will vary from refiner to refiner and from region to region. 9 EIA, Petroleum & Other Liquids, Data, Refining and Processing: http://www.eia.gov/petroleum/data.cfm#refining

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Figure 6.3 shows the basis for this analysis. The first component of the analysis is the red bar which represents the average annual WCS price for 2011 in $/bbl10 (~$78/bbl) at Hardisty, Alberta. This is in effect, a reflective price for oil sands producers. Meanwhile, it is important to note that this price is not reflective of all the oil sands crude produced for two reasons. First, various oil sands producers have upgrading operations which turn crude bitumen to synthetic crude oil (SCO) and the average price for Syncrude Stream’s SCO11 in 2011 was $103.67/bbl compared to WTI at $94.87/bbl. Second, various oil sands producers also have downstream refining assets which means that their equity diluted bitumen crudes are transferred to their refining assets (subject to pipeline transportation availability/capacity and refining capacity) and it is refined into petroleum products. Therefore, not all bitumen production should be assumed to receive WCS prices, and not all dilbit/synbit supplies are subject to WCS price exposure.12

Another part of the analysis is the price for crudes which are of similar quality to WCS/dilbit crudes in the target market region (PADDs III and IV, blue bars).13 For the US Gulf Coast (USGC) market, a median landed cost14 for various waterborne imported heavy sour crudes (mainly from Latin America)15 was used, as it is estimated that in 2011, 87 percent of the total 2,200 MBPD of heavy crudes to the USGC were from Latin America.16 For California (US West Coast, [USWC]), a median price for Kern River and Midway-Sunset Crudes first purchase prices in PADD V was used.17 A quality adjustment ($2.50/bbl for the USGC, and $8.00/bbl for the USWC) was calculated for each of this representative crude versus WCS quality crude in order to better reflect the potential

10 All figures in US dollars per barrel unless otherwise specified. 11 Not all SCO is priced at this level as some SCO producers also produced a heavy sour SCO which is priced lower. 12 CERI’s analysis indicates that in 2011, of the total primary/ EOR, thermal, and mining oil sands projects producing dilbit/synbit supplies, about 30 percent of the volumes were estimated to have exposure to WCS based prices. 13 This assumes that Canadian heavy crudes compete for space in refineries with other crudes for which pricing benchmarks exist in the target market. While in various markets benchmark prices are determined by spot prices and market transactions, prices for Maya crude are based on a formula which Pemex could use to lower the price if the threat of significant volume displacement from Canadian heavy crudes exists in the USGC 14 Landed costs are used as they reflect the actual price of the crude once is delivered to the market area, in this case the USGC market. 15 These include Mexican Maya (API: 21.5, Sulfur: 3.4%), Venezuelan Merey (16, 2.5%), Venezuelan BCF-17 (13.5, 2.3%), Ecuadorian Napo (19.2, 2.0%), Brazilian Marlim (19.6, 0.7%), and US landed costs for API < 20, and API> 20 & < 25, all retrieved from EIA: http://www.eia.gov/dnav/pet/pet_pri_land2_k_a.htm 16 Hart Energy, Refining Unconventional Oil, US Resource Invigorate Mature Industry: http://www.hartenergy.com/Upstream/Research-And-Consulting/Refining-Unconventional-Oil/ 17 Midway-Sunset (API: 13, Sulfur: 1.6%), and Kern River (13.3, 1.1%). These crudes represent the largest share of California’s crude oil production according to the California Energy Commission: http://www.energy.ca.gov/2006publications/CEC-600-2006-006/CEC-600-2006-006.PDF

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prices for WCS/dilbit crudes in the respective market,18 which is given by the lighter red bars (USGC: $95.79/bbl; USWC: $93.98/bbl).

The difference between WCS at Hardisty, and the estimated dilbit equivalent price (after a quality adjustment) at the target market, is the gross possible price uplift to oil sands producers (USGC: $17.80/bbl; USWC: $15.99/bbl). Gross because it represents dilbit prices at Hardisty versus the potential dilbit price at the target market. This, in turn, is the maximum possible uplift to WCS prices but also the maximum transportation costs that an oil sands producer will be willing to pay in order to be indifferent between selling at Hardisty or the target market.

Netting transportation costs19 (given for various transportation options) from the maximum price uplift, yields the estimated netback price the oil sands producer receives in Alberta for selling its crude at the target market. As an example, if a producer has access to pipeline capacity to the USGC under a 10-year toll commitment at a cost of $9.95/bbl, then $17.80/bbl (gross possible price uplift) - $9.95/bbl (transportation costs) = $7.85/bbl (price uplift) + $77.99 (WCS @ Hardisty) = $85.84/bbl, which is the price the producer receives for selling its crude in the USGC versus Hardisty, Alberta. The $7.85/bbl is the price improvement for the Canadian producer versus the price at Hardisty, which is in turn reflective of the refiner’s willingness to pay for Canadian heavy crude in the existing PADD II and IV markets.

This part of the analysis stresses the fact that under a scenario where enough transportation capacity is developed to the target market, the difference between WCS at Hardisty and similar crudes at the potential market should strictly be a function of quality adjustment and transportation costs. However, this part of the analysis also stresses and reflects on the fact that producers are willing to spend more on various alternate (non-pipeline) transportation means such as rail, barges, ships, and any combination of those, as long as the price at the target market minus the transportation costs exceeds the market price at Hardisty (see Figure 6.3). A simple example illustrates

18 For the USGC, since the price for Mexican Maya was almost identical ($98.81/bbl) to the median USGC heavy sour landed crude ($98.29), a quality/ price adjustment was done based on the total acid number (TAN) for WCS being higher than that of Maya API and sulfur parameters for WCS and Maya are almost identical. For the USWC, the adjustment was based on WCS having a higher sulfur content that California heavy sour crudes, TAN levels are about the same while API or California crudes tend to be lower than for WCS. Adjustment based on an econometric model developed by the UNDP/ World Bank: http://www.esmap.org/sites/esmap.org/files/08105.Technical%20Paper_Crude%20Oil%20Price%20Differ entials%20and%20Differences%20in%20Oil%20Qualities%20A%20Statistical%20Analysis.pdf 19 Transportation costs are based on various costs presented on the US Department of State Keystone XL Draft Environmental Impact Statement (DEIS), as well as a recent analysis performed by IHS CERA, and a presentation from Gibsons: http://keystonepipeline-xl.state.gov/draftseis/index.htm http://www.ihs.com/images/Future-Markets-for-Oil-Sands-Jan-2013.pdf http://www.gibsons.com/Doc/Gibson%20Presentation%20- %20TD%20Rail%20Forum%20October%202012.pdf

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that if a producer with a project producing 100 MBPD could realize a price that is $1/bbl higher at a different market, it could be improving profits by $100,000 per day or $36.5 million per year.

This part of the analysis has various economic implications and considerations for the outlook worth discussing. The first one is what prices will look like for dilbit equivalent or heavy sour crudes at these markets in the future. This is a complex question that could in itself require its own report, but in CERI’s view, the simple answer is that these crudes, given that they are priced at coastal locations in large refining centers, will continue to be influenced by global crude oil prices, and as long as global prices remain strong, these locations will remain attractive markets to Canadian producers.

Another factor is that of infrastructure development and transportation costs. As long as the heavy crude oil price differentials between locations remain wide, there will be an incentive for producers to use non-traditional transportation avenues to access markets. That is, producers will not stop producing if prices are lower at their location, rather they will find new ways to get to better/premium markets.

Furthermore, as pipeline transportation remains one of the most economic means to transport crude it will continue to be the dominant transportation mode. Tying into this is the fact that stronger prices at other market locations translate into better prices at the production basin via the lowest transportation costs, thus pipeline connections to new markets remains the best means for improving pricing for Canadian oil sands producers. This is important because as prices are lifted companies can realize better returns and re-invest in order to grow the industry. This further translates into more economic activity, higher taxation revenue for provincial and federal governments, but most importantly it improves the economic value of the resource being extracted (bitumen) for the resource owner, that is, Albertans and Canadians.

The last part of the analysis on Figure 6.3 relates the pricing dynamics for different types of oil sands producers – SAGD versus mining producers. This part of the analysis uses CERI’s supply costs for these project types and places them in the context of the pricing dynamics discussed above. The black (mining) and green (SAGD) dots in Figure 6.3 represent the supply cost for a project at a specific location and subject to transportation costs. The first observation is that the estimated dilbit supply costs20 at the Alberta hub for SAGD projects is lower than the 2011 WCS price at Hardisty. The implication of this is that if the producer was to sell its barrel at Hardisty under these

20 Calculated as bitumen field supply costs + diluent costs (including diluent prices and transportation costs to the field) + dilbit transportation costs from the field (project fence) to the Alberta marketing hub (Hardisty or Edmonton)

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pricing/market conditions, it would receive a positive margin above its supply costs21 (green bars), or simply put, it would realize a better rate of return on each barrel of dilbit. Alternatively, as is the case with the mining producer, since the Alberta hub supply costs (black dot) is above the market price, thus yielding a negative margin below the supply costs (black bars), indicating that the rate of return is lower than that of the supply cost calculation.

Using the above discussion of the potential prices for dilbit equivalent crudes at the new markets, and the transportation costs analysis, we can estimate the margins above or below the supply costs for a project type, according to the targeted market and the transportation costs incurred. As an example, consider the case of oil sands producers selling in the United States West Coast (USWC) market and using an intermodal (Pipeline to BC coast/tanker or barge to the California Coast). The total supply cost for a SAGD producer (supply cost at Alberta Hub + transportation costs to PADD V) is estimated at $72.32/bbl, given the expected price of $93.98/bbl for dilbit equivalent crude in that market, the SAGD producer improves his margins from $11.66/bbl selling at the Alberta hub to $21.65/bbl in the USWC or in other words, the difference between two margins – $9.99/bbl. In the case of the mining producer the margin improves from - $3.25/bbl at the Alberta hub, to $6.74/bbl in the USWC market, or by $9.99/bbl as well.

The main implication here is that while some projects could be deemed as uneconomic (mining project) due to prices at the local market (Alberta), diversifying or marketing to a new area such as the USWC or USGC, improves the overall economics of the project. Thus market diversification allows marginal projects to be more competitive. This is important for industry growth as it allows projects that would have been otherwise postponed or canceled to proceed by improving marketing conditions.

This can in turn have a positive effect on local market prices as refiners in existing markets (PADDs II & IV) will bid up dilbit prices to the point where they are equal to the next alternative (higher cost crude) in order to keep their supplies from going to other markets and in order to maintain their margins. As dilbit prices rise, the value of the resource for both the industry and the other resource owners improves.

21 This is a hypothetical situation as the supply costs is in fact the price that allows the producer to cover all its costs (capital, operating, royalties, taxes, etc.) plus a 10 percent real return on investment. Therefore, an actual realized price above the supply cost results in a higher rate of return.

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Figure 6.3 Dilbit Pricing Dynamics, 2011 ($/bbl)88

$105.00 $105.00

$100.00 $100.00 $2.50 $8.00 $95.00 $95.00

$90.00 $9.95 $10.00 $9.00 $6.00 $90.00 $14.05 $17.80 $16.62 $17.70 $18.50 $13.00 $85.00 $15.99 $16.00 $85.00 $7.85 $7.80 $8.80 $9.99 $80.00 $3.75 $2.99 $80.00 $1.18 $0.10 $75.00 $75.00

$70.00 $70.00

$65.00 $65.00

$60.00 $60.00 Costs ($/bbl) $55.00 Netback Improvement ($/bbl) $55.00 SAGD Net Revenues ($/bbl) $101.98 $50.00 $98.29 Mining Net Revenues ($/bbl) $50.00 $95.79 Estimated Dilbit Netback ($/bbl) $93.98 $/bbl $45.00 SAGD Supply Costs ($/bbl) $45.00 Mining Supply Costs ($/bbl) $40.00 $77.99 WCSB Parity $40.00 $35.00 $35.00

$30.00 $30.00

$25.00 $25.00

$20.00 $21.65 $20.00 $19.52 $19.47 $20.47 $15.00 $15.00 $15.42 $14.65 $10.00 $12.85 $10.00 $11.66 $11.77 $10.97 $11.65 $5.00 $5.00 $4.60 $4.55 $0.50 $5.55 $6.74 $0.00 $0.00 $(2.07) $(3.15) $(3.25) $(3.95) $(0.26) $(3.26) -$5.00 -$5.00

-$10.00 -$10.00 WCS @ Hardsity Median USGC USGC Heavy Estimated Dilbit Estimated Dilbit Pipeline (10-YR Intermodal: Pipeline Rail (Unit Train) Intermodal: Intermodal: Proposed Median USWC USWC Heavy Estimated Dilbit Estimated Dilbit Intermodal: Rail (Unit Train) Rail (Manifest Heavy Sour Sour Crude - Eq. Price @ Price Uplift @ Committed Pipeline/ Tanker (Uncommitted Rail/ Tanker Rail/ Barge Pipeline Heavy Sour Sour Crude - Eq. Price @ Price Uplift @ Pipeline/ Tanker Train) Crude Landed Dilbit Quality USGC (No USGC (No Tolls) Tolls) Crude Dilbit Quality USWC (No USGC (No or Barge Costs Adjustment Transportation Transportation Acquisition Adjustment Transportation Transportation Costs) Costs) Costs Costs) Costs) USGC Pricing Dynamics AB -> USGC Transportation Costs USWC Pricing Dynamics AB -> USWC Transportation Costs Sources: Data from EIA, IHS CERA, Gibsons, and US Department of State, figure and analysis by CERI.

88 Pipeline transportation costs to the USGC are given by Keystone/ Seaway combination for the existing option and Keystone XL for the proposed pipeline option. Intermodal to USGC: Pipeline/ Tanker = Transmountain to Vancouver + Panama/ Suezmax tanker via Panama Canal. Rail to USGC = Alberta hub to Lloydminster, SK + Rail to Port Arthur, TX via CPRS-St.Paul-UP. Intermodal to USGC: Rail/ Tanker = Rail to Prince Rupert + Panama/ Suezmax tanker via Panama Canal. Intermodal to USGC: Rail/ Barge = Alberta hub to Lloydminster, SK + Rail to Wood River, Ill + Barge. Intermodal to USWC: Pipeline/ Tanker/ Barge = Transmountain to Vancouver + Tanker or Barge to USWC.

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May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 93

Appendix A Methodology and Assumptions

Canadian-US Exchange Rate (C$/US$) The purpose of this section is not to provide a detailed forecast of Canadian-US exchange rates over the long projection period covered in this study, but rather to simply illustrate the effect that one variable could have on the exchange rate, ignoring all other factors, and left unconstrained by government policy. It is true that many factors can have an impact on the exchange rate, including political changes, productivity, inflation, and debt. However, there is one factor that has had an undeniable influence on the Canadian-US exchange rate, and has become more important over time. This factor is the price of crude oil.

The statistical relationship between crude oil prices and the Canadian-US exchange rate is estimated with an ordinary least squares approach. A simple exchange rate forecast is then produced using a forecast of crude oil prices. In this exercise, it is assumed that the exchange rate is left unconstrained by central bank interventions.

The statistical analysis required data on historic and projected crude oil prices, and historic exchange rates. Historical monthly WTI spot price data (US$/bbl) was obtained from the EIA for the period March 1996 to December 2012. Historical exchange rate data (C$/US$) was obtained for the same period from Statistics Canada. A forecast of WTI prices was obtained from the EIA’s Annual Energy Outlook, and extended, at an annual average inflation rate of 2.5 percent per year, to cover the projection period.

The results of the regression analysis on historical data are illustrated in Figure A.1. There exists a negative and statistically significant relationship (adjusted R2= 84 percent) between the Canadian-US exchange rate and the price of crude oil. This indicates that as WTI prices increase, the exchange rate decreases. That is, for every US$1/bbl increase in the price of oil, each US$1 can purchase $0.0062 fewer Canadian dollars.

Figure A.2 shows the forecast of the exchange rate based on the derived coefficients from the regression analysis. The exchange rate declines to C$0.93/US$1 in 2017, and C$0.48/US$1 by 2030, basically suggesting that if the exchange rate is left unconstrained by fiscal and monetary policies, the Canadian dollar would be excessively appreciated against the US dollar.

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Figure A.1 Effect of the Oil Price on the Canadian-US Exchange Rate

C$/US$ 1.8 ExRate = 1.59+ (-0.0062)*WTI 1.6 Adjusted R2 = 84% 1.4

1.2

1.0

0.8

0.6

0.4

0.2

0.0 0 20 40 60 80 100 120 140 160 WTI (US$/barrel)

Source: CERI, US EIA, Statistics Canada

Figure A.2 Historic and Projected WTI Prices and the Canadian-US Exchange Rate, 2007-2046

WTI (US$/barrel) C$/US$ 350 1.4

1.2 300 WTI 1.0

250 0.8

0.6 200 0.4 150 0.2

100 0.0 Exchange Rate -0.2 50 -0.4

0 -0.6

Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 Jan-27 Jan-28 Jan-29 Jan-30 Jan-31 Jan-32 Jan-33 Jan-34 Jan-35 Jan-36 Jan-37 Jan-38 Jan-39 Jan-40 Jan-41 Jan-42 Jan-43 Jan-44 Jan-45 Jan-46

Source: CERI, US EIA, Statistics Canada

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 95

As the Canadian-US exchange rate decreases, Canadian goods and services become relatively more expensive to purchase with US dollars, and Canadian exports to the US decline correspondingly. Between 2007 and 2012, the Canadian-US exchange rate declined by 7 percent (i.e., Canadian dollar appreciated against the US dollar). Over the same period of time, the value of Canadian exports to the US declined by approximately 5 percent. In 2012, Canadian exports to the US accounted for 73.2 percent of the nation’s total exports.1

The simple uni-variate model utilized in this exercise ignores important factors that could have an impact on the Canadian-US exchange rate, and therefore suffers from under-specification bias. To better determine the effect of crude oil prices on the exchange rate, other relevant variables should also be considered. One such variable, as suggested by recent Bank of Canada research, is the US debt to gross domestic product (GDP) ratio, relative to Canada’s debt to GDP ratio.2 Cost Inflation Estimating future capital investment and operating costs required CERI to develop an estimate for construction and operating cost inflation. Estimating the inflation in oil sands construction and operating costs can be a difficult endeavour due to the lack of available historical cost data.

Oil Sands Construction Cost Inflation In order to approximate construction cost inflation in the oil sands, CERI studied the changes in the Nelson-Farrar Inflation Refinery-Construction Cost Index (NFCCI). The NFCCI was first introduced in CERI’s 2009 oil sands update study as a method to estimate future oil sands construction cost inflation.

There are two main reasons for using the Construction Cost Index in CERI’s analysis. First, such a cost index is not currently produced by any organization for the oil sands. Second, many of the costs associated with the construction of refineries are also applicable to the construction of oil sands projects. Labour costs (skilled and common labour) make up 60 percent of the Construction Cost Index, while materials and equipment (iron and steel, building materials, and miscellaneous equipment) account for the remaining 40 percent.

CERI hypothesized that a direct and positive relationship exists between the price of oil and construction costs. Qualitatively, this is plausible because the strength of oil prices

1Imports, exports and trade balance of goods on a balance-of-payments basis, by country or country grouping, Statistics Canada, http://www40.statcan.gc.ca/l01/cst01/gblec02a-eng.htm, Accessed on March 25, 2013. 2Cayen, Jean-Philippe, Donald Coletti, Rene Lalonde, and Philipp Maier, “What Drives Exchange Rates? New Evidence from a Panel of U.S. Dollar Bilateral Exchange Rates”, Canadian Economic Analysis Department, Bank of Canada, February 2010.

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is dependent on robust economic activity, and economic growth has a tendency to lead to capital cost inflation. To test this theory quantitatively, a simple uni-variate statistical model was created using historical WTI spot prices and the NFCCI. If such a relationship exists, then a forecast of the value of the Construction Cost Index, and thus oil sands construction costs, can be produced, using an oil price projection. The change in the construction cost index over time can be interpreted as the inflation in oil sands construction costs.

Monthly WTI spot price data (US$/bbl) and NFCCI data were obtained from the EIA, and the Oil and Gas Journal, respectively, for the period March 1996 to October 2012. The analysis revealed a strong, positive, and statistically significant relationship between the WTI spot price and the Construction Cost Index, as shown in Figure A.3. According to CERI’s model, 85 percent of observed changes in the Construction Cost Index can be explained by changes in the price of oil. A US$1/bbl increase (decrease) in the WTI spot price is estimated to increase (decrease) the NFCCI value by 10.9.

Figure A.3 Effect of the Oil Price on Refinery Construction Costs

Construction Cost Index 3000.0

2500.0

2000.0

1500.0 NF Construction Index = 1324.4 + 10.9*WTI 1000.0 Adjusted R2 = 85%

500.0

0.0 0 20 40 60 80 100 120 140 160 WTI (US$/barrel) Source: CERI, US EIA, Oil and Gas Journal

Based on the regression results and a given forecast of WTI, CERI extrapolated a forecast of the NFCCI. The index was projected to the end of the outlook period (2046), assuming that no future structural breaks occur in the relationship between the price of oil and construction costs. The historic data indicates that year-over-year (October 2011- October 2012) refinery construction costs have experienced no change. The average annual construction cost inflation rate, forecasted between October 2012 and October 2046, is 1.9 percent, which is lower than the assumed annual inflation rate of 2.5 percent. Figure A.4 displays forecasts of the WTI price, and the annual inflation in

May 2013 Canadian Oil Sands Supply Costs and Development Projects (2012-2046) 97

refinery construction costs. This forecast of the annual inflation rate in refinery construction costs (used to proxy the oil sands construction cost inflation) is used to inflate the projected initial and sustaining capital costs in the oil sands industry.

Figure A.4 Historic and Projected WTI Prices and Construction Cost Inflation Rates, 2007-2046

WTI (US$/barrel) Construction Cost Inflation (%) 350.00 10.0%

8.0% 300.00

WTI 6.0% 250.00 4.0% Inflation 200.00 2.0%

150.00 0.0% -2.0% 100.00 -4.0% 50.00 -6.0%

0.00 -8.0%

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

Source: CERI, US EIA, Oil and Gas Journal

Oil Sands Operating Cost Inflation The operating costs of an oil sands project contribute significantly to the total cost of a project. As with capital costs, however, no index currently exists to capture changes in oil sands operating costs over time. In order to estimate the inflation rate of oil sands operating costs, a feasible alternative measure must be obtained. While the operating costs of an oil refinery do not mirror those of an oil sands project exactly, the two facilities are similar in that each consists of very energy-intensive processing units.3 For this reason, the Nelson-Farrar Refinery Operating Cost Index (NFOCI) is used in the examination of oil price impacts on oil sands operating costs. The NFOCI accounts for the following refinery operating costs: fuel, power, labour, investment, maintenance, and chemicals.

With a linear estimation approach, CERI is able to test the impact of changes in the price of oil on refinery operating costs. Given a statistical relationship between refinery operating costs and the price of oil, a forecast of the value of the NFOCI can be produced, using an oil price projection. Year-over-year changes in the Operating Cost

3While this relationship is weaker for an oil sands operation, it is still a relevant comparison until an alternative method is developed.

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Index could then be used as a rough proxy for the rate of inflation in oil sands operating costs.

Monthly WTI spot price data (US$/bbl) and NFOCI data were obtained from the EIA, and the Oil and Gas Journal, respectively, for the period March 1996 to October 2012. WTI spot prices have a positive and statistically significant effect on the value of the NFOCI. Eighty-five percent of observed changes in the NFOCI can be explained by changes in the price of oil. A US$1/bbl increase (decrease) in the WTI spot price is estimated to increase (decrease) the Operating Cost Index value by 3.1. Figure A.5 shows a scatter plot of historical WTI prices, and the NFOCI.

Figure A.5 Effect of the Oil Price on Refinery Operating Costs

Operating Cost Index 900.0

800.0

700.0

600.0

500.0

400.0 NF Operating Index = 362.9 + 3.1*WTI 300.0 Adjusted R2 = 85%

200.0

100.0

0.0 0 20 40 60 80 100 120 140 160 WTI (US$/barrel)

Source: CERI, US EIA, Oil and Gas Journal

The historical data implies that the refinery operating costs have decreased by 1.0 percent, year-over-year (October 2011-October 2012). The annual average operating cost inflation rate forecasted between October 2012 and October 2046 is 2.03 percent, which is lower than the annual inflation rate of 2.5 percent. Figure A.6 displays forecasts of the WTI price, and the annual inflation in refinery operating costs. This forecast of the annual inflation rate in refinery operating costs (used to proxy the oil sands operating cost inflation) is used to inflate the projected operating costs in the oil sands industry.

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Figure A.6 Historic and Projected WTI Prices and Operating Cost Inflation Rates, 2007-2046

WTI (US$/barrel) Operating Cost Inflation (%) 350.00 12.5%

10.0% 300.00

WTI 7.5% 250.00 5.0% Inflation 200.00 2.5%

150.00 0.0%

-2.5% 100.00 -5.0% 50.00 -7.5%

0.00 -10.0%

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

Source: CERI, US EIA, Oil and Gas Journal

Cash Flow Methodology CERI developed a cash flow methodology on a project phase by project phase basis in order to calculate royalties from oil sands projects. This section will describe in detail the methodology used to estimate future royalty revenues.

The bitumen valuation methodology (BVM) as used both by CAPP and the Alberta Department of Energy (DOE) was used by CERI in order to estimate the gross revenues. Data for the bitumen deposit/formation being targeted by a project operator was obtained from CERI’s database together with the density (kg/m3) and API degrees of the type of bitumen being extracted. Using ERCB files, the deposits were grouped by oil sands areas (OSA) and location allowing for identification of characteristics of specific types of bitumen in each deposit within each area. This enabled us to assign density values for projects for which the quality of the bitumen produced is not provided.

CERI’s database further identifies those projects that are integrated, which allows us to determine which projects will upgrade their crude bitumen into synthetic crude oil (SCO). Meanwhile, sorting the projects by company helps to identify which companies own integrated projects that could supply their own non-integrated projects with SCO as diluents while cross checking against CERI’s database information on the product types (diluted bitumen vs. synthetic bitumen) as well as considering infrastructure (pipeline) limitations. The remaining projects are those projects which are not operated by a company with an existing integrated operation in the Athabasca area and are

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assumed to produce dilbit as their main marketable product and thus require condensate for blending purposes.

At this stage it is clear which projects will require blending and what type of diluent (SCO or condensate) will be used to make the project consistent with both WCS blend specifications and pipeline specifications as outlined by the main pipeline operators who transport a variety of different crudes. The next step is then to calculate the blending required for each barrel of blended bitumen (dilbit or synbit) produced from each non- integrated project. For this purpose, CERI developed its own bitumen valuation and blending calculator based on a tool provided by crudemonitor.ca4 as well as the DOE’s BVM.5 This model uses a series of mathematical iterations to calculate the amount of diluents required for blending in order to reach a target density while minimizing any discrepancies due to shrinkage. Once this is completed we know exactly how much of each type of diluent is required for each barrel produced at each project and thus we are able to calculate the overall diluent requirement for the oil sands industry.

With blending requirements known for each project the next step is to calculate the royalty value of the bitumen at Hardisty, Alberta. For this CERI used the BVM components used by CAPP and the DOE for pricing the condensate pool and WCS for 2011. As well, a regression was run on a series of price postings, DOE par prices, and local crudes to determine a formula that will price different crudes based on their API gravity in relation to 2011 prices for WCS and WTI. This in turn was used to price SCO of different qualities and condensates, as well as dilbits and synbits. This allowed CERI to determine the cost of the diluent used in each blend and thus the royalty value of the marketable product. Prices for moving the marketable product from the field to Hardisty, Alberta as well as the price of transporting the condensate to the project location were added to this calculation. This results in the royalty value of the bitumen which is then expressed as a ratio to WTI going forward, as WTI is the reference price used in the forecast period.

The next step dealt with the cash flow itself. To make sure that the calculation was done in accordance with DOE procedures and thus be a closer reflection of a real project, an economic evaluation (cash flow) model was obtained from the DOE’s website, which calculates the crown’s royalty payable based on a series of inputs.6 The calculation methods and formulas used in this model were incorporated into CERI’s oil sands forecasting model. The results for a given new project as calculated with the DOE’s

4 Crude Monitor, 2012. Blend Calculator (http://www.crudemonitor.ca/tools/blend_calculator/blendcalc.php), accessed on January 26, 2012 5 Alberta Department of Energy, 2012. Bitumen Valuation Methodology (BVM) Components, BVM Model Calculator, available at (http://www.energy.gov.ab.ca/OilSands/1542.asp), accessed on January 26, 2012 6 Alberta Department of Energy, 2012. Our Business, Oil Sands, Forms, Royalty Project Application Forms, Economic Evaluation Data Requirement, available at (http://www.energy.alberta.ca/OilSands/582.asp), accessed on January 26, 2012

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model vs. CERI’s model were then compared for due diligence purposes and are presented in Chapter 4.

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Appendix B Existing Crude Oil Pipelines in Western Canada

There are approximately 38,000 kilometres of crude oil pipelines in Canada, transporting 3.2 million barrels per day (MMBPD).1 In addition there are approximately 72,000 kilometres of natural gas pipelines in Canada, transporting 14.6 billion cubic feet per day (BCFPD). This Appendix briefly explores over two dozen existing crude oil pipelines that either originate in or operate within Western Canada. As such, it does not discuss natural gas pipelines. Unless explicitly mentioned, natural gas liquids (NGLs) are not included in this discussion.

Figure B.1 illustrates the complex web of liquids pipelines in North America. To simplify the discussion, this section is divided into 2 parts: export pipelines and regional/ gathering pipelines.

Figure B.1 Canadian and US Crude Liquids Pipelines

Source: CEPA Presentation.

1 CEPA website, CEPA Member Statistics, http://www.cepa.com/industry-info/cepa-member-statistics (accessed on September 28, 2012)

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Export Pipelines This section briefly discusses liquids pipelines that originate in Western Canada that are utilized for export. More specifically, it will review the Keystone Pipeline, the Trans Mountain Pipeline, the Express-Platte, Enbridge’s Canadian Mainline and the Alberta Clipper, the Rangeland, the Bow River Pipeline and the Cochin Pipeline (the Cochin Condensate Pipeline Reversal project).

Keystone Pipeline – TransCanada Pipelines TransCanada Pipelines Keystone Pipeline transports heavy crude from Alberta’s oil sands to refineries in Illinois and Oklahoma. The Keystone Pipeline is their largest and newest crude oil, or liquids, pipeline. Figure B.2 illustrates the existing Keystone Pipeline, as well as the proposed Keystone XL expansion.

Figure B.2 TransCanada’s Keystone Pipeline

Source:http://gs-press.com.au/images/news_articles/cache/KeystoneXL_Map_hd-0x600.jpg

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The pipeline is 3,456 kilometres in length and serves the US market exclusively.2 The diameter of the pipeline ranges between 30 and 36 inches.3 The existing Keystone has been operating since June 2010.4 The original pipeline was expanded (Phase I) to 590,000 barrels per day (BPD), shortly after commencing operation in June 2010.5 The expansion included approximately 864 kilometres of the Canadian section of pipeline to be converted from its Canadian Mainline natural gas pipeline to carry oil. The Keystone Cushing section of the pipeline, from Steele City to Cushing, Oklahoma, went into service in February 2011.6 This section of the Keystone Cushing is 480 kilometres and utilizes 36” pipe.7 The latter is a major crude oil marketing, refining and pipeline hub.

Trans Mountain Pipeline (TMX) – Kinder Morgan Canada Since 1953 Kinder Morgan and previous owners have been operating its Trans Mountain pipeline, which is currently the only pipeline link between Alberta’s oil sands and the west coast. It was expensive to construct, and a considerable feat of engineering for the time; it crossed much more challenging terrain than the Interprovincial pipeline that had been built a few years earlier to move oil from Alberta to eastern Canada. The Trans Mountain pipeline has undergone expansion since 1953, both in terms of capacity and in terms of length. Completed in 2008, the Anchor Loop expanded the pipeline through Jasper National Park and Mount Robson Provincial Park. The Anchor Loop project increased capacity from 260,000 BPD to the current 300,000 BPD. In spite of the expansion, it is important to note that most recently Kinder Morgan reported that the pipeline is oversubscribed by 30 percent.8

The line runs 1,156 km in length from Edmonton to Vancouver to Anacortes, Washington (see Figure B.3). Trans Mountain can be easily expanded because the pipeline right-of-way is well established. As a batch pipeline, it is capable of shipping a variety of hydrocarbons.

2 TransCanada website, Keystone, http://www.transcanada.com/keystone.html (accessed on September 28, 2012) 3 CEPA website, http://www.cepa.com/ (accessed on September 28, 2012) 4 "NEB Okays Keystone XL". National Energy Board (Downstream Today). 2010-03-11. http://www.downstreamtoday.com/news/article.aspx?a_id=21604. 5 ibid 6 ibid 7 CEPA website, http://www.cepa.com/ (accessed on September 28, 2012) 8Bloomberg website, “Kinder Morgan Trans Mountain Line Oversubscribed by 30%”, April 21, 2011, http://www.bloomberg.com/news/2011-04-21/kinder-morgan-trans-mountain-line-oversubscribed-by- 30-1-.html (accessed on December 16, 2011)

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Figure B.3 Trans Mountain Pipeline

Source: http://www.kindermorgan.com/business/canada/TMX_Documentation/ TMX_Expansion_Map.pdf

Kinder Morgan plans to file, in 2014, a regulatory review application with the National Energy Board (NEB) for the TMX; the expansion, if approved, will be a 490,000 BPD capacity addition to the current Trans Mountain pipeline. The company should benefit from a recent decision by the Federal Government of Canada to set a time limit of two years on energy project reviews and thereby expedite decisions.9

Now that Kinder Morgan has finished its open season, the company has to begin an environmental assessment and then seek regulatory approval. Kinder Morgan will likely face opposition from environmental groups in the Vancouver area in respect of the pipeline expansion itself as well as with regard to expanding the size of the terminal, and subsequently the size of the tankers using the facility. The opposition will likely be centered on the increased size and frequency of tanker traffic in Vancouver. Safety

9Davidson, A. CBC News. “Ottawa to slash environment review role”. http://www.cbc.ca/news/politics/story/2012/04/17/environmental-reviews.html. Accessed on June 18, 2012.

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measures and the role of Port Metro Vancouver are discussed in CERI’s report “Pacific Access: Part V – Overview of Transportation Options”.10 How strong the stakeholder opposition will be to the Trans Mountain expansion remains to be seen. The proposed expansion will have to overcome various obstacles similar in nature to Enbridge’s Northern Gateway Pipeline project. But because there is an existing right of way, the situation is different for Trans Mountain than it is for Northern Gateway. The stakeholders are different, too, since the twinned pipeline is set to pass through a more densely populated part of Canada. Besides First Nations, fishermen, and farmers, stakeholders on the TMX route include residents of various municipalities – people that hold their own sets of concerns.

Express-Platte Pipeline – Spectra Energy The Express-Platte Pipeline System is comprised of two separate crude oil pipelines. The 2,700 kilometre Express-Platte runs from Hardisty, Alberta to terminals in Wood River, Illinois. The crude oil pipeline crosses through Montana, Wyoming, Nebraska, Missouri and Illinois.11 Figure B.4 illustrates the Express-Platte Pipeline (yellow line).

Figure B.4 Express-Platte Pipeline

Source: http://www.spectraenergy.com/Operations/Crude-Oil-Transportation/ExpressPlatte/

The Express-Platte Pipeline delivers heavy crude oil from Hardisty to refineries in the Rocky Mountains, Montana, Wyoming, Utah and Colorado. The Express utilizes 24 inch diameter pipe and is 1,283 kilometres in length.12 It has a capacity of 280,000 BPD and is regulated by the NEB and the United States Department of Transportation Office of Pipeline Safety and the FERC.13 The NEB regulates the pipeline from Hardisty to Wild

10Available for download at www.ceri.ca, http://ceri.ca/images/stories/2012-02- 07_Pacific_Access_Overview_of_Transportation_Options.pdf 11 ibid 12 ibid 13 ibid

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Horse, the international border between Alberta and Montana. The American regulatory counterpart regulates the Express from Wild Horse to Casper, Wyoming, where the Express interconnects with the much older Platte pipeline. The Express Pipeline began operation in 1997 and was owned by the Alberta Energy Company and TCPL, in a 50-50 arrangement.

The Platte pipeline began operation in 1952.14 The pipeline begins in Casper, Wyoming and delivers the heavy crude oil to Wood River, Illinois; where it is refined.15 The Platte is 1,500 kilometres in length and uses 20 inch pipe.16 The capacity from Casper to Guemsey is 164,000 BPD while the capacity from Guemsey to Wood River is approximately 145,000 BPD.17 The pipeline was oversubscribed in May 2012, indicating that demand was exceeding capacity.18 The pipeline is entirely regulated by the United States Department of Transportation Office of Pipeline Safety and the FERC.19

On March 14, 2013 Spectra Energy announced that it has acquired the Express-Platte Pipeline System, purchasing 100 percent interest in the crude oil system for US$1.49 billion.20 The pipelines were previously owned by Kinder Morgan Energy Partners, Borealis Infrastructure and the Ontario Teachers’ Pension Plan.

Enbridge Canadian Mainline – Enbridge Enbridge’s Canadian Mainline, sometimes referred to as the Enbridge System, begins in Edmonton and runs to Montreal. It is 2,306 kilometres in length.21 It is important to note that the Canadian Mainline ends at Gretna, Manitoba, where the pipeline enters the United States and starts again in Sarnia, Ontario, where it runs through Toronto and onto Montreal.22

Figure B.5 illustrates the Canadian Mainline, as well as other Enbridge liquids pipelines in North America. The Canadian Mainline is represented by the red line. The yellow

14 Kinder Morgan website, Express-Platte Pipeline, http://www.kindermorgan.com/business/canada/Express_Platte.cfm (accessed on September 28, 2012) 15 ibid 16 ibid 17 ibid 18 Bloomberg website, Kinder Morgan’s Platte Pipeline 85% Oversubscribed for May, April 27, 2012, http://www.bloomberg.com/news/2012-04-27/kinder-morgan-s-platte-pipeline-85-oversubscribed-for- may-1-.html (accessed on September 28, 2012) 19 Kinder Morgan website, Express-Platte Pipeline, http://www.kindermorgan.com/business/canada/Express_Platte.cfm (accessed on September 28, 2012) 20 Spectra Energy website, Spectra Energy Acquires Express-Platte Pipeline system, http://www.spectraenergy.com/Newsroom/News-Archive/Spectra-Energy-Acquires-ExpressPlatte- Pipeline-System/ (accessed on May 13, 2013) 21 Enbridge website, Enbridge Liquids Pipelines, http://www.enbridge.com/DeliveringEnergy/OurPipelines/LiquidsPipelines.aspx (accessed on September 28, 2012) 22 ibid

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dotted line illustrates Enbridge’s Lakehead System, or the US Mainline. The latter connects the western portion of the Canadian Mainline from Edmonton to Gretna, Manitoba and the eastern portion of the mainline that runs between Montreal and Sarnia, Ontario. It is important to mention that Enbridge’s Alberta Clipper (now Line 67), which transports heavy crude from Hardisty to Superior, Wisconsin, is not shown in this particular graphic. The Alberta Clipper and Southern Lights pipeline are discussed on their own, although some observers consider them part of the complex Mainline.

Figure B.5 Enbridge Liquids Pipelines

Source: http://www.pipelinesinternational.com/news/new_oil_pipeline_on_the_horizon_at_sunrise_oil_sands/ 043796/

The Canadian Mainline transports crude oil and diluted bitumen, while the Enbridge Lakehead transports crude oil, condensate and NGLs.23 In combination with the

23 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012)

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Enbridge Lakehead System the capacity of the pipeline is 2,500,000 BPD.24 Figure B.6 illustrates the Lakehead System in greater detail. The US Mainline is 3,057 kilometres in length and is owned by Enbridge Energy Partners LP.25 The latter runs roughly from Neche, North Dakota to Chicago, Illinois.26 The Lakehead System loops around Lake Michigan, as far north as Lewiston and runs southward through Bay City, Michigan and northwards to Sarnia, Ontario.

Figure B.6 Enbridge’s Lakehead System

Source: Enbridge website27

Figure B.7 shows Enbridge’s Canadian Mainline system’s configuration. The schematic includes 14 lines, or pipelines, as of 1Q2012. The Canadian Mainline system comprises of Lines 1, 2, 3, 4, 7, 9, 10 and 11. The US Mainline, on the other hand, comprises of Lines 5, 6, 14/64, 61 and 62. It is important to note that Line 55 (Flanagan to Cushing) and Line 17 (Stockbridge to Toledo) are not part of the Enbridge Mainline system. Line 67 is better known as the Alberta Clipper and runs between Hardisty and Superior, Michigan. It is discussed separately.

Lines 4, 6, 7, 10, 11, 62, 14/64, 61 and 67 are able to transport heavy crude. Lines 2, 3, 5, 7, 10, 11 and 14/64 are utilized, in part, to transport condensates. All of the lines, except

24 ibid 25 ibid 26 ibid 27Enbridge website, http://ar.enbridge.com/ar2007/management-discussion-analysis/sponsored- investments/enbridge-energy-partners/ (accessed on September 28, 2012)

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for Lines 62 and 67 are used to transport various products (i.e., Line 2 is used to transport, condensates, light synthetics, sweet crude and light and high sour crude).

Figure B.7 Enbridge’s Mainline System Configuration

Source: Enbridge website28

Enbridge is in the process of expanding and replacing several lines. Among the various projects: Line 6b Phase 2 Replacement Project plans to replace approximately 210 miles of pipeline between Indiana and Michigan, Line 62 (Spearhead North Pipeline) is being expanded between Flanagan, Illinois and Griffith, Indiana from 135,000 BPD to 235,000 BPD and Lakehead System Expansion (Line 61 and Line 67).29 The Lakehead System Expansion is expected to be complete by mid-2014.30 In addition, Line 5 is being expanded, while Line 9B is being re-reversed, from Westover, Ontario to Montreal.31 The latter will cost C$100 million and will complement the plan to reverse Line 9A between Sarnia and Westover.32 The mandate is to provide refineries in Montreal crude oil from Western Canada and the Bakken region in North Dakota. The pipeline currently ships oil from the North Sea, West Africa and the Middle East from Montreal to refineries in Sarnia.

28 Enbridge website, Pipeline System Configuration, Quarter 1, 2012, http://www.enbridge.com/DeliveringEnergy/OurPipelines/~/media/www/Site%20Documents/Delivering %20Energy/2012_Q1%20System%20Config.ashx (accessed on September 28, 2012) 29 Enbridge website, US Operation Growth Projects, http://www.enbridgeus.com/Delivering- Energy/Growth-Projects/ (accessed on September 28, 2012) 30 ibid 31 Enbridge website, Enbridge and Enbridge Energy Partners project expansions May 2012, http://www.enbridge.com/EEP-and-ENB-project-expansions-May-2012.aspx (accessed on September 28, 2012) 32 ibid

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Alberta Clipper and Southern Lights Pipelines – Enbridge As previously mentioned, the Alberta Clipper Pipeline, often referred to as Line 67, is a pipeline that runs from Hardisty, Alberta to Superior, Wisconsin. More specifically, the 1,604 kilometre crude oil pipeline runs through Alberta, Saskatchewan, Manitoba, North Dakota, Minnesota and Wisconsin. The 450,000 BPD capacity pipeline follows the Canadian Mainline to Gretna, Manitoba. The capacity is expandable to 800,000 BPD.33 It is important to mention that the Alberta Clipper is integrated, and forms a part of the existing Canadian Mainline.34

The capital cost for the Canadian segment is approximately C$2 billion while the stretch of pipeline in the United States costs approximately US$1 billion.35 The project was in service in mid-2010 and deliveries crude to the US Midwest markets. The system can accommodate heavy bitumen crudes as well as synthetic crude oil (SCO).36

The pipeline utilizes 36 inch diameter pipeline and was approved by the NEB in February 2008.37 The Canadian portion of Line 67 is 1,078 kilometres in length. Figure B.8 illustrates the Alberta Clipper. Other existing Enbridge pipelines are also illustrated on the graphic.

33 Enbridge website, Alberta Clipper and Southern Lights, http://www.enbridge- expansion.com/expansion/main.aspx?id=1228&tmi=1720&tmt=5 (accessed on September 28, 2012) 34 ibid 35 ibid 36 Enbridge website, Alberta Clipper and Southern Lights, http://www.enbridge- expansion.com/expansion/main.aspx?id=1228&tmi=1720&tmt=5 (accessed on September 28, 2012) 37 CBC website, Enbridge gets approval for $2B Alberta Clipper pipeline, February 25, 2008, http://www.cbc.ca/news/canada/saskatchewan/story/2008/02/25/enbridge-alberta-clipper.html (accessed on September 28, 2012)

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Figure B.8 Alberta Clipper Pipeline

Source: Enbridge website38

Enbridge announced on May 16, 2012 that it is expanding the Canadian portion of the Alberta Clipper pipeline, as well upgrading the pump stations.39 The expansion will add 120,000 BPD in capacity and is expected to be completed by mid-2014.40 On the US portion of the Alberta Clipper (from the US-Canada border to Superior), capacity is also being expanded from 450,000 to 570,000 BPD.

Enbridge’s Southern Lights Pipeline runs from Chicago to Edmonton. The C$2.2 billion line pumps diluents from US refineries located in Manhattan, Illinois, near Chicago northwards to Edmonton, along the same route as the Alberta Clipper.41 In fact, between Hardisty and Gretna they will share the same right-of-way. The diluents are

38 Enbridge website, http://www.enbridge.com/~/media/www/Site%20Images/Projects/Maps/Clipper_Lights_Map.ashx (accessed on September 28, 2012) 39Marketwire website, Enbridge to Undertake $0.2 Billion Canadian Mainline Expansion, May 16, 2012, http://www.marketwire.com/press-release/enbridge-to-undertake-02-billion-canadian-mainline- expansion-tsx-enb-1658355.htm (accessed on September 28, 2012) 40 Enbridge website, Enbridge and Enbridge Energy Partners project expansions May 2012, http://www.enbridge.com/EEP-and-ENB-project-expansions-May-2012.aspx (accessed on September 28, 2012) 41 Enbridge US website, Liquids Pipelines, http://www.enbridgeus.com/Main.aspx?id=12765&tmi=12765&tmt=1 (accessed on September 28, 2012)

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used to mix with the much heavier oil sands to make transportation easier. The capacity of the pipeline is 180,000 BPD and went into service on July 1, 2010.42

The Southern Lights Pipeline consists of 2 interconnected pipelines. The US portion extends from Manhattan, Illinois to Neche, North Dakota, while the Canadian portion extends from Neche to Edmonton.

Figure B.9 illustrates the 1,086 kilometre Southern Lights Pipeline. It also includes the 504 kilometre pipeline, the LSr Project, from Cromer, Manitoba to Clearbrook, Minnesota. The LSr was brought into operation in February 2009 and refers to transporting light sour crude.43

Figure B.9 Southern Lights Pipeline

Source: http://www.enbridgeus.com/Main.aspx?id=12765&tmi=12765&a

42 Enbridge website, Alberta Clipper and Southern Lights, http://www.enbridge.com/Alberta-Clipper-and- Southern-Lights.aspx (accessed on September 28, 2012) 43 ibid

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Rangeland Pipeline – Plains Midstream Plains Midstream Rangeland pipeline begins at Edmonton and ends at Carway, Alberta.44 The approximately 1,500 kilometre pipeline transports crude oil, butane and condensate.45 The pipeline’s diameter is between 12 and 16 inches.

The route of the Rangeland Pipeline is illustrated in Figure B.10, circled in green. The pipeline, shown in red, begins in Edmonton and ends at the US border.

The Rangeland passes through Sundre and Hartnell, both of which have truck terminals.46 Sundre handles low sulphur crude oil, while Hartnell handles both high and low sulphur crude oil.47 There are 2 other pipelines operated by Plains Midstream Canada that are also illustrated in Figure B.10. The first is the 50 kilometre Milk River Pipeline, located in Milk River, Alberta and runs to the US border. The second is the Manito System, which originates near Lloydminster, Alberta and runs south to Kerrobert, Saskatchewan, and then northwest to Cactus Lake, Saskatchewan.

Figure B.10 The Rangeland Pipeline

Source: Plains Midstream Canada

44 CEPA website, Pipeline map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012) 45 ibid 46 Plains Midstream website, Asset Map, http://www.plainsmidstream.com/ops_assetmap.html (accessed on September 28, 2012) 47 ibid

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Portions of the Rangeland were shut down in early June 2012 due to a leak near Sundre.48 An estimated 1,000 to 3,000 barrels were released from the pipeline.49

The Rangeland Pipeline is owned and operated by the Rangeland Pipeline Company, which is under the Plains Midstream Canada umbrella.50 All Canadian entities are a subsidiary of Plains All American Pipeline LP (PAA).51 PAA operates approximately 16,000 miles of crude oil and refined petroleum pipelines.52

Bow River Pipeline – Inter Pipeline Fund Inter Pipeline’s conventional oil pipeline system is comprised of three pipeline systems: Bow River Pipeline, Central Alberta Pipeline and Mid-Saskatchewan Pipeline. The three systems make up over 3,600 kilometres of operating pipeline and nearly 1,000,000 barrels of storage capacity.53 The transportation capacity is approximately 165,000 BPD of crude oil across their Alberta and Saskatchewan pipelines and is connected to 143 producer-owned facilities.54,55 As of March 31, 2013, the total throughput on the pipeline system is 185,300 BPD, up from 179,300 BPD year-over-year.56 This section will only discuss the Bow River Pipeline, as it is an export pipeline. These conventional oil pipelines are illustrated in Figure B.11.

48 Oil and Gas Journal, Canada's ERCB responds to Rangeland pipeline leak in Alberta, June 8, 2012, http://www.ogj.com/articles/2012/06/canada-ercb-responds-to-rangeland-pipeline-leak-in-alberta.html (accessed on September 28, 2012) 49 ibid 50 Plains Midstream website, Changes at Plains, http://www.plainsmidstream.com/changes_at_plains.html (accessed on September 28, 2012) 51 Business Week website, Rangeland Pipeline Company snapshot, http://investing.businessweek.com/research/stocks/private/snapshot.asp?privcapId=9145325 (accessed on September 28, 2012) 52 Reuters website, Profile: Plains All American Pipeline LP, http://www.reuters.com/finance/stocks/companyProfile?symbol=PAA.N (accessed on September 28, 2012) 53 Inter Pipeline Fund website, Conventional Oil Pipelines Fact Sheet 2012, http://www.interpipelinefund.com/pdf/operations/Conventional%20pipelines%20fact%20sheet%202012. pdf (accessed on September 28, 2012) 54 ibid 55 Inter Pipeline Fund website, Investor Relations Presentation, June 2011, http://www.interpipelinefund.com/pdf/investor/presentation/IPF%20IR%20Presentation%20- %20June.pdf, pp. 11. (accessed on September 28, 2012) 56 Inter Pipeline 2012 Annual Report, The Strength of our Word, pp. 33

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Figure B.11 Inter Pipeline Conventional Pipelines

Source: Inter Pipeline Fund57

The Bow River Pipeline transports crude oil from Hardisty to Milk River, Alberta, where the crude crosses the US border and is delivered to refineries in Montana. The pipeline is 2,774 kilometres in length. This number includes not only the pipeline but the gathering system.58 Storage capacity of the Bow River Pipeline system is 464,500 barrels of crude.59 Its 2012 throughput was 106,800 BPD, down slightly from its 2011 throughput of 107,700 BPD and its 2010 throughput of 109,600 BPD.60,61

Cochin Pipeline (and the Cochin Reversal Project) – Kinder Morgan Canada With oil sands activity expected to increase, there is a need for diluent to Canadian oil sands producers. Kinder Morgan Energy Partners launched a binding open season to

57 Inter Pipeline fund website, Conventional Pipelines, http://www.interpipelinefund.com/operations/conventional.php (accessed September 28, 2012) 58 Inter Pipeline Fund website, Conventional Oil Pipelines, http://www.interpipelinefund.com/operations/conventional-oil-pipelines.cfm (accessed on May 14, 2013) 59 Ibid 60 Inter Pipeline 2012 Annual Report, pp. 33 61 Inter Pipeline 2011 Annual Report, pp. 33

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gauge interest in moving about 75,000 BPD of light natural gas condensates to the oil sands by reversing its Alberta-to-Illinois Cochin pipeline.

Kinder Morgan’s Cochin Pipeline began operations in 1979.62 The 3,057 kilometre Cochin runs from Fort Saskatchewan, Alberta to terminals in Sarnia, Ontario. The pipeline crosses through North Dakota, Minnesota, Iowa, Illinois, Indiana, Ohio and Michigan before crossing back into Canada.63 The Cochin pipeline is illustrated as a red line in Figure B.12.

The Cochin Pipeline System utilizes 12 inch diameter pipeline and is currently regarded as a multi-product pipeline. The pipeline was designed to transport propane, butane and NGLs to petrochemical markets in Midwest states and Ontario – but this may soon change.64 While the Cochin is predominantly used for transporting NGLs, Kinder Morgan plans to modify and expand the Cochin pipeline, including transporting condensate from Illinois to Alberta.

Figure B.12 Cochin Pipeline

Source: Kinder Morgan65

62 Kinder Morgan website, Cochin, http://www.kindermorgan.com/business/canada/cochin.cfm (accessed on September 28, 2012) 63 ibid 64 Kinder Morgan Energy Partners to Own 100% of Cochin Pipeline, January 15, 2007, http://news.thomasnet.com/companystory/Kinder-Morgan-Energy-Partners-to-Own-100-of-Cochin- Pipeline-505182 (accessed on September 28, 2012) 65 Kinder Morgan website, Cochin Reversal Project, http://www.kindermorgan.com/business/ products_pipelines/cochin_open_season.cfm (accessed on September 28, 2012)

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The Cochin Reversal is also illustrated in Figure B.12. The source of the westbound condensate is Kankakee County, Illinois and its destination is Fort Saskatchewan, Alberta. The Cochin will connect to the Explorer Pipeline in Kankakee County. The Explorer Pipeline is also owned and operated by Kinder Morgan and runs from Illinois to Pasadena, Texas, situated on the Gulf of Mexico. The Explorer transports refined petroleum products, feedstock and diluent from the Gulf to the Midwest.66 The Cochin Pipeline will have to be modified and expanded to transport the condensate, approximately 95,000 BPD, to Fort Saskatchewan.67 The pipeline’s capacity is expandable to 175,000 BPD.68

It is important to note that Kinder Morgan successfully completed binding open season for the Reversal project, in which more than 100,000 BPD of commitments were received.69 The company suggests that provided regulatory approvals, the first condensate shipments could begin as early as July 1, 2014.70

Kinder Morgan Energy Partners (KMP) acquired a 50 percent stake in the Cochin Pipeline System from BP Canada Energy Company in January 2007.71 Kinder Morgan is now the sole owner and operator of the pipeline.72 Prior to the acquisition, Kinder Morgan owned almost a 50 percent stake and was the operator of the Cochin.73 Kinder Morgan initially purchased a 32.5 percent stake in October 2000, and it was the company’s first foray into the WCSB.74 Regional Pipelines This section discusses briefly regional liquids pipelines in Western Canada.

Pembina Oilsands Pipelines – Pembina Pipeline Corporation Pembina’s oil sands and heavy oil pipelines include the Syncrude, Horizon, Cheecham Lateral Pipelines, and the new Mitsue Pipeline and Nipisi Pipeline. The Calgary-based

66 Oil and Gas Journal website, KMEP to reverse Cochin Pipeline, ship diluent to Alberta, June 6, 2012, http://www.ogj.com/articles/2012/06/kmep-to-reverse-cochin-pipeline-ship-diluent-to-alberta.html (accessed on September 28, 2012) 67 Kinder Morgan Announces Cochin Pipeline Expansion Plans, June 2010, http://pipelineandgasjournal.com/kinder-morgan-announces-cochin-pipeline-expansion-plans (accessed on September 28, 2012) 68 ibid 69 Kinder Morgan website, Cochin Reversal Project, http://www.kindermorgan.com/business/products_pipelines/cochin_open_season.cfm (accessed on September 28, 2012 70 ibid 71 Kinder Morgan Energy Partners to Own 100% of Cochin Pipeline, January 15, 2007, http://news.thomasnet.com/companystory/Kinder-Morgan-Energy-Partners-to-Own-100-of-Cochin- Pipeline-505182 (accessed on September 28, 2012 72 ibid 73 ibid 74 ibid

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company manages and transports synthetic crude from upgrading facilities. In total, the company has over 1,000 kilometres of oil sands pipeline infrastructure in Alberta.

Figure B.13 illustrates the aforementioned existing pipelines. The figure also shows the Peace Pipeline, which is not discussed in this section, as it is categorized in Pembina’s conventional pipeline operations.

The Syncrude Pipeline, formerly the Alberta Oil Sands Pipeline (AOSPL), was acquired in December 2001.75 The purchase initiated Pembina’s entry into the oil sands industry. The 434 kilometre pipeline has been operating since 1977 and has increased its committed throughput up to 389,000 BPD, from 275,000 BPD in 2003.76 The pipeline was built by AEC Pipelines and has a diameter of 22 inches.77 It is under long-term contract with its namesake, Syncrude Canada, until 2035.78 The agreement is extendable past 2035. The exclusive pipeline runs between Syncrude oil sands operations north of Fort McMurray and an upgrading facility in Fort Saskatchewan. The project has large expansion plans that mirror expansion plans of Syncrude Canada’s oil sands operations.

Figure B.13 Pembina Oil Sands and Heavy Oil Pipelines

Source: Pembina website79

75 Pembina Pipeline Income Fund, Rating Report, February 29, 2008, pp. 2. 76 ibid 77 Alberta Government, Oil Sands Discovery Centre: Facts about Alberta’s oil sands and its industry, http://history.alberta.ca/oilsands/docs/facts_sheets09.pdf (pp. 30) (accessed on September 28, 2012) 78 Pembina Pipeline Income Fund, Rating Report, February 29, 2008, pp. 3. 79 Pembina website, Oil Sands and Heavy Oil Business, http://www.pembina.com/pembina/webcms.nsf/AllDoc/363F20F628DC30D4872578D4005B3989/$File/O il%20Sands%20and%20Heavy%20Oil%20Business.jpg?OpenElement (accessed on September 28, 2012)

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Similar to its long-term agreement with Syncrude Canada, Pembina has an agreement with Canadian Natural Resources Limited (CNRL) to ship its product exclusively on the Horizon Pipeline.80 The pipeline runs between CNRL’s Horizon’s oil sands project approximately 70 kilometres north of Fort McMurray and Fort Saskatchewan. The pipeline began operating in mid-2008 and has a capacity of 250,000 BPD.81 The estimated cost of construction was approximately C$400 million.82 The pipeline runs along the Syncrude Pipeline for approximately 129 kilometres and has a diameter of between 24 and 30 inches.83

The Cheecham Lateral began operating in December 2006 and has a capacity of 136,000 BPD.84 The pipeline cost C$42 million and is used to ship product from the Syncrude Pipeline to a new terminal near Cheecham, Alberta.85 The pipeline is fully contracted for 25 years with fixed returns.86 The pipeline is 56 kilometres and transports SCO from the Algar Pump Station, located along the Syncrude Pipeline, to the terminating facility near Cheecham.87

Pembina’s two newest pipelines are the Nipisi and Mitsue pipelines. Both pipelines transport heavy oil from the Pelican and Peace River regions. The Nipisi Pipeline is designed to transport 100,000 BPD of diluted heavy oil, but can be expanded to 200,000 BPD.88 The pipeline runs from the Nipisi Terminal, north of Slave Lake, Alberta to the Judy Creek pump station, South of Swan Hills, Alberta. It is 190 kilometres in length. The Mitsue Pipeline is a diluent pipeline and runs from Pembina’s Whitecourt pump station to the Nipisi Terminal.89 The initial transport capacity is 22,000 BPD of condensate, but can be expanded to a capacity of 45,000 BPD.90 The Mitsue pipeline is 155 kilometres in length, slightly shorter than its counterpart. Construction was completed and went into

80 Pembina Pipeline Income Fund, Rating Report, February 29, 2008, pp. 10. 81 ibid 82 ibid 83 Pembina proceeds with Horizon pipeline construction, November 13, 2006, http://www.scandoil.com/moxie-bm2/news/pipeline/pembina-proceeds-with-hor.shtml (accessed on September 28, 2012) 84 Pembina Pipeline Income Fund, Rating Report, February 29, 2008, pp. 9. 85 ibid 86 ibid 87 Pembina website, Pembina Undertakes Synthetic Crude Oil Diluent Pipeline Project, September 30, 2005, http://phx.corporate-ir.net/phoenix.zhtml?c=63581&p=irol-newsArticle&ID=763017&highlight= (accessed on September 28, 2012) 88 Pembina website, Growth Projects, http://www.pembina.com/pembina/webcms.nsf/AllDoc/B967D125D3EB2D948725791F005B7A57?Open Document (accessed on May 13, 2013) 89 ibid 90 ibid

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service in August 2011.91 Cost of the 2 pipelines is estimated to be approximately C$400 million.92

Inter Pipeline Oilsands – Inter Pipeline Fund Inter Pipeline’s Oilsands system is comprised of three pipeline systems: Cold Lake, Corridor and Polaris. The three systems make up nearly 2,500 kilometres of operating pipeline and approximately 3.8 million barrels of storage – the largest gathering business in Canada.93 The capacity is also currently the largest at 813,000 BPD of blended bitumen.94 Figure B.14 illustrates the routes of the three oil sands pipelines.

Figure B.14 Inter Pipeline Oilsands Pipelines

Source: Inter Pipeline Fund95

91 Pembina website, History, http://www.pembina.com/pembina/webcms.nsf/AllDoc/33956BD6B0EAB59687257788006F4F9A?OpenD ocument (accessed on September 28, 2012) 92 Pembina website, Pembina Pipeline Corporation Brings Nipisi and Mitsue Pipeline On-Stream, August 3, 2011 (accessed on May 14, 2013) 93 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil-sands-transportation.cfm (accessed on May 14, 2013) 94 ibid 95 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil_sands.php (accessed on September 28, 2012)

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The Corridor Pipeline transports diluted bitumen, diluent, feedstock and products from the Athabasca Oil Sands Project (AOSP), near Fort McMurray to Edmonton.96 The AOSP is a major mining and bitumen upgrading project that is owned by Shell Canada, Chevron Canada and Marathon Oil Corporation.97 Storage capacity of the Corridor Pipeline system is 3,500,000 barrels and its 2012 throughput is 318,200 BPD.98 Throughput in 2011 was 295,800 BPD.99 The pipeline system is 1,046 kilometres in length, and is the longest of the Inter Pipeline Fund’s Oilsands pipelines.100 The current capacity of the Corridor Pipeline is 465,000 BPD.101 Capacity was expanded from 300,000 BPD. The C$1.8 billion project was completed and commenced operations on January 1, 2011.102 Pipe transporting diluted bitumen, or DilBit, was expanded to 42 inches from Muskeg River Mine to the Scotford upgrader, near Edmonton, for 467 kilometres; the remaining 43 kilometres of pipe are 20 inches in diameter.103 An additional 900,000 barrels of storage have been added in the expansion project.104 Inter Pipeline Fund purchased the Corridor pipeline from Kinder Morgan Canada for C$760 million in March of 2007.105 The sale did not involve Kinder Morgan’s Trans Mountain or its Express-Platte pipelines.

Cold Lake Pipeline transportation system transports oil from Cold Lake to Hardisty, Alberta. It is the only transporter of Cold Lake-area bitumen, accommodating Encana Corporation, Imperial Oil Limited, CNRL and Shell Energy Canada’s in situ projects.106 The pipeline is 990 kilometres in length and is used to transport oil sands bitumen and

96 Inter Pipeline Fund website, Oil Sands Transportation 2011, http://www.interpipelinefund.com/pdf/operations/Oil%20sands%20pipelines%20fact%20sheet%202011. pdf 97 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil_sands.php (accessed on September 28, 2012) 98 Inter Pipeline Fund website, Oil Sands Transportation 2012, http://www.interpipelinefund.com/operations/oil-sands-transportation.cfm 99 Inter Pipeline Fund 2012 Annual Report, pp. 26. 100 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil-sands-transportation.cfm (accessed on May 13, 2013) 101 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil_sands.php (accessed on September 28, 2012) 102 Inter Pipeline Fund website, Investor Relations Presentation, June 2011, http://www.interpipelinefund.com/pdf/investor/presentation/IPF%20IR%20Presentation%20- %20June.pdf (pp. 5) 103 Inter Pipeline Fund Provides Update on Corridor Pipeline Capacity Expansion Project, August 10, 2009, http://www.marketwire.com/press-release/Inter-Pipeline-Fund-Provides-Update-on-Corridor-Pipeline- Capacity-Expansion-Project-1028113.htm (accessed on September 28, 2012) 104 Inter Pipeline Fund, Corridor Pipeline, Expansion Project, http://www.interpipelinefund.com/pdf/news_release/2007/Corridor_spec_sheet.pdf 105 Corridor pipeline sold for $760M, March 6, 2007, http://www.canada.com/calgaryherald/news/calgarybusiness/story.html?id=2784d220-c6ba-47dd-96c8- 6f3cff5b13b0 (accessed on September 28, 2012) 106 ibid

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condensate.107 The latter is transported from the Strathcona area to the Cold Lake region.108 Storage capacity of the Cold Lake system is 376,000 barrels and its 2012 throughput is 494,400 BPD.109 Throughput in 2011 was 490,400 BPD, up from 2010’s throughput of 447,600 BPD.110,111 The Cold Lake Pipeline capacity is 650,000 BPD of bitumen blend.112

Inter Pipeline announced plans on July 31, 2012 for a C$2.2 billion expansion of their pipeline network, more specifically, the Cold Lake and Polaris systems.113 The expansion will add nearly 850 kilometres of new pipe.114 The Cold Lake Expansion will include a new pipeline connection to the Narrows Lake oil sands development, 2 new pump stations at Foster Creek, the Foster Creek extension will be twinned with 36 inch pipeline and the Cold Lake mainline from La Corey to Hardisty will also be twinned with 42 inch diameter pipeline.115 The total estimated costs of the expansion to the Cold Lake system is C$1.1 billion.116

Encana Corporation sold 70 percent interest in the Cold Lake Pipeline system for approximately C$425 million to Inter Pipeline Fund in 2003.117 It is important to note that Inter Pipeline is not the sole owner, but 85 percent.

The Polaris Pipeline transports diluent, from Edmonton to the Fort McMurray area.118 The pipeline went on stream in August 2012.119 As suggested by Inter Pipeline, with the completion of the Corridor expansion, the existing 12 inch pipeline running between Muskeg River Mine and the Scotford upgrader is available for alternative service.120 The pipeline system is 495 kilometres in length and is used to transport diluent to the Kearl and Sunrise oil sands projects.121 The company has 90,000 BPD in firm shipping

107 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil-sands-transportation.cfm (accessed on May 13, 2013) 108 Ibid 109 Ibid 110 Inter Pipeline Fund Annual Report 2012, pp. 26. 111 Inter Pipeline Fund Annual Report 2011, pp. 27. 112 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil_sands.php (accessed on September 28, 2012) 113 Inter Pipeline Fund 2012 annual Report, pp. 24 114 ibid 115 ibid 116 ibid 117 EnCana, Annual Information Form, February 25, 2004, http://www.encana.com/news/newsreleases/2003/P1161617082859.html (pp. 8) (accessed on September 28, 2012) 118 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil-sands-transportation.cfm (accessed on May 13, 1013) 119 ibid 120 ibid 121 Inter Pipeline Fund website, Oil Sands Transportation, http://www.interpipelinefund.com/operations/oil-sands-transportation.cfm (accessed on May 13, 2013)

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commitments and the Polaris has a total current capacity of 120,000 BPD.122 The Polaris pipeline provides 60,000 BPD of diluent for the Kearl oil sands project and in 2013 will provide 30,000 BPD capacity for the Sunrise project.123 The Kearl connection is estimated to cost approximately C$135 million while the Polaris connection to the Sunrise is estimated to cost C$15 million.124 The Kearl Project is owned by ExxonMobil and Imperial Oil, while the Sunrise Project is owned by Husky Oil and BP Energy Canada.125 Demand for diluent is expected to be strong and is currently the only diluent transportation system to the Athabasca oil sands region.126 The company has 90,000 BPD in firm shipping commitments and the Polaris has a total current capacity of 120,000 BPD.127

Of the total C$2.2 billion expansion to the Cold Lake and Polaris systems, the latter will cost an estimated C$1.1 billion. A new 30 inch diameter, 290 kilometre pipeline is planned from the Edmonton area to the Christina Lake oil sands project.128 The Edmonton Extension includes the installation of 50 kilometres of 24 inch pipe from the Edmonton area to the Polaris Lamont pump station.129 The capacity of both pipelines is 700,000 BPD.130 The company also plans to build approximately 100 kilometres of smaller pipelines to connect to oil sands projects at Foster Creek and Narrows Lake.131

Inter Pipeline Fund is the sole owner of the Polaris pipeline system.132

122 Inter Pipeline Fund website, Investor Relations Presentation, June 2011, http://www.interpipelinefund.com/pdf/investor/presentation/IPF%20IR%20Presentation%20- %20June.pdf (pp. 9). 123 Inter Pipeline to invest in oil sands pipelines, January 25, 2011, http://pipelinesinternational.com/news/inter_pipeline_to_invest_in_oil_sands_pipelines/054349/# (accessed on September 28, 2012) 124 Inter Pipeline Fund website, Investor Relations Presentation, June 2011, http://www.interpipelinefund.com/pdf/investor/presentation/IPF%20IR%20Presentation%20- %20June.pdf (pp. 8). (accessed on September 28, 2012) 125 Inter Pipeline Fund Announces 2011 Capital Expenditure Program, January 20, 2011, http://m.theglobeandmail.com/globe-investor/news- sources/?date=20110120&archive=ccnm&slug=201101200667973001&service=mobile (accessed on September 28, 2012) 126 Inter Pipeline Fund website, Investor Relations Presentation, June 2011, http://www.interpipelinefund.com/pdf/investor/presentation/IPF%20IR%20Presentation%20- %20June.pdf (pp. 20). 127 Ibid, pp. 9 128 Inter Pipeline website, New Projects, http://www.interpipelinefund.com/operations/new-projects.cfm (accessed on May 14, 2013) 129 ibid 130 ibid 131 ibid 132 ibid

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Enbridge Athabasca Pipeline – Enbridge Enbridge’s Athabasca Pipeline begins at Suncor’s oil sands operation north of Fort McMurray and ends in Hardisty, Alberta.133 The 540 kilometre pipeline has a capacity of 345,000 BPD and makes up a part of Enbridge’s Regional Oil Sands System.134 The other is the Waupisoo Pipeline, discussed in a subsequent section. Figure B.15 illustrates the Athabasca Pipeline.

The Athabasca Pipeline transports heavy crude oil and synthetic crude.135 The pipeline is 30 inches in diameter and is wholly-owned by a subsidiary of Enbridge, EPAI.136 The Calgary-based company is undertaking two separate expansions of the pipeline that was built in 1999.137 The first expansion will cost approximately C$185 million and is proposed for the 2012-13 timeline.138 The second expansion is scheduled be completed in 2014-2015.139 The latter expansion will help accommodate new volumes for Cenovus Energy’s Christina Lake oil sands project. Both expansions will increase capacity to 570,000 BPD.140

133 Enbridge Pipelines (Athabasca), GHG Emissions Inventory and Management Plan, 2005, http://www.ghgregistries.ca/registry/out/rf_4760_5453.pdf (pp. 7) 134 Enbridge website, Liquids Pipelines, http://www.enbridge.com/DeliveringEnergy/OurPipelines/LiquidsPipelines.aspx (accessed on September 28, 2012) 135 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf 136 Enbridge Pipelines (Athabasca), GHG Emissions Inventory and Management Plan, 2005, http://www.ghgregistries.ca/registry/out/rf_4760_5453.pdf (pp. 7) 137 Journal of Commerce. Enbridge to expand Athabasca pipeline, http://www.joconl.com/article/id42368 (accessed on September 28, 2012) 138 Alberta Government, Pipeline Projects, http://albertacanada.com/SP_IMAP_pipelines1.pdf (accessed on May 13, 2013) 139 Alberta Government, Pipeline Projects, http://albertacanada.com/SP_IMAP_pipelines1.pdf (accessed on May 13, 2013) 140 Journal of Commerce. Enbridge to expand Athabasca pipeline, http://www.joconl.com/article/id42368 (accessed on September 28, 2012)

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Figure B.15 The Athabasca Pipeline

Source: Enbridge website

Figure B.16 shows the twinning of the Athabasca Pipeline in greater detail. The twinning begins at Kirby Lake Terminal, near Winifred Lake, and ends at Battle River Terminal, located near Hardisty. The new pipeline will run approximately 345 kilometres and will have a diameter of 36 inches.141 In addition to the pipeline, the project will also require 2 new pump stations at Kirby Lake Terminal and Bonnyville Station, as well as several modifications to existing pump stations.142

141 Enbridge website, Athabasca Twinning Information, http://www.enbridge.com/AthabascaTwinning.aspx (accessed on September 28, 2012) 142 ibid

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Figure B.16 Athabasca Pipeline Twinning Project

Source: Enbridge website143

143 Enbridge website, Map, http://www.enbridge.com/AthabascaTwinning/~/media/www/Site%20Images/Projects/Maps/APTPMap Notification.ashx (accessed on September 28, 2012)

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Enbridge Waupisoo Pipeline – Enbridge Enbridge’s Waupisoo Pipeline begins in Cheecham Terminal, Alberta and ends at the Edmonton Mainline Terminal, Alberta (via Stonefell Terminal near Bruderheim, Alberta). The Waupisoo Pipeline transports heavy crude oil and synthetic crude.144 The pipeline is illustrated in Figure B.17. The graphic also show Enbridge’s Athabasca Pipeline.

Figure B.17 The Waupisoo Pipeline

Source: Journal of Commerce145

144 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012) 145 Journal of Commerce. Enbridge to expand Athabasca pipeline, http://www.joconl.com/article/id42368 (accessed on September 28, 2012)

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The 385 kilometre pipeline has a capacity of 350,000 BPD and makes up a part of Enbridge’s Regional Oil Sands System.146

Enbridge is planning a C$400 million expansion to the regional pipeline.147 The expansion will require 4 new pump stations and modifications to existing pump stations at Cheecham Terminal and Small Benn Station.148 The capacity expansion received full approval from the Alberta Energy Resources Conservation Board (ERCB) on November 16, 2010.149 The pipeline was expanded by 65,000 BPD in the second half of 2012 and will add approximately 190,000 BPD by the second half of 2013. Capacity will be expanded up to approximately 550,000 BPD.

Access Pipelines – Devon/MEG The Access Pipeline is a joint project between MEG Energy Corporation and Devon Canada Corporation.150 Both entities have a 50 percent interest in the dual pipeline.151 The Access Pipelines are dual pipelines that run between Christina Lake and Sturgeon Terminal, Edmonton.152 The Sturgeon Terminal is a regional upgrading, refining and transportation hub, while Christina Lake is the site of a Steam Assisted Gravity Drainage (SAGD) operation owned by Devon Canada and MEG.153

Blended bitumen flows from Christina Lake to Edmonton while diluents and condensate flow in the other direction.154 The diluent pipeline is 345 kilometres in length and has a diameter of 16 inches. The condensate pipeline is received at Provident Redwater Facility and the Enbridge Terminal, located at Sherwood Park, and is stored at 3 storage tanks at the Sturgeon Terminal.155 The pipeline currently operates at 90,000 BPD.156 The bitumen pipeline operates at 200,000 BPD and originates at the northern section of the

146 Enbridge website, Liquids Pipelines, http://www.enbridge.com/DeliveringEnergy/OurPipelines/LiquidsPipelines.aspx (accessed on September 28, 2012) 147 Journal of Commerce. Enbridge to expand Athabasca pipeline, http://www.joconl.com/article/id42368 (accessed on September 28, 2012) 148 Enbridge website, Waupisoo Capacity Expansion, http://www.enbridge.com/WaupisooCapacityExpansionProject.aspx (accessed on September 28, 2012) 149Enbridge website, Regulatory Information, http://www.enbridge.com/WaupisooCapacityExpansionProject/RegulatoryInformation.aspx (accessed on September 28, 2012) 150 http://www.oilandgasinquirer.com/profiler.asp?article=profiler%2F080601%2FPRO2008_U10043.html (accessed on September 28, 2012) 151 MEG website, Access Pipeline, http://www.megenergy.com/operations/access-pipeline (accessed on September 28, 2012) 152 ibid 153 Access website, About, http://www.accesspipeline.com/about.php (accessed on September 28, 2012) 154 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012) 155 Access website, http://www.accesspipeline.com/ (accessed on September 28, 2012) 156 MEG website, Access Pipeline, http://www.megenergy.com/operations/access-pipeline (accessed on September 28, 2012)

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Access pipeline, near Conklin, and terminates in Edmonton.157 The blended pipeline has a diameter of 24 inches for 295 kilometres and a 30 inch diameter for a 50 kilometre section.158

Figure B.18 illustrates the route of the Access Pipeline. The diluent pipeline is shown in green while the blend is shown in red.

Figure B.18 The Access Pipeline

Source: Access Pipeline website159

157 Access website, http://www.accesspipeline.com/ (accessed on September 28, 2012) 158 ibid 159 Access website, Pipeline Map, http://accessexpansion.com/about-access/pipeline-map (accessed on September 28, 2012)

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The graphic also illustrates the proposed expansion. Access Pipeline is proposing a new 42 inch diameter pipeline originating near Conklin down to Sturgeon Terminal.160 The project is called the Northern Expansion and will have an initial capacity of 350,000 BPD.161 Pending the regulatory process, the C$1 billion project could be completed by 2014.-162

Suncor Oil Sands Pipeline (OSPL) – Suncor Energy Suncor Energy owns and operates the Oil Sands Pipeline (OSPL) system. The pipeline was constructed in 1966 and is used to transport synthetic crude oil and high vapour pressure products.163 The OSPL runs 426 kilometres from the site of Suncor’s oil sands operation, north of Fort McMurray, to Edmonton.

Figure B.19 illustrates the route of the Suncor’s OSPL.

Figure B.19 The OSPL System Map

Source: Pinnacle Energy164

160 Access website, Construction, http://www.accesspipeline.com/construction.php (accessed on September 28, 2012) 161 ibid 162 MEG Energy website, Access Pipeline, http://www.megenergy.com/operations/access-pipeline (accessed on May 14, 2013) 163 Alberta Government, Oil Sands Discovery Centre: Facts about Alberta’s oil sands and its industry, http://history.alberta.ca/oilsands/docs/facts_sheets09.pdf (pp. 29) (accessed on September 28, 2012) 164 Pinnacle Energy, SCC inspection & mitigation program on Suncor OSPL pipeline, http://www.pinnacleeng.ca/newsAndArticles/sccInspection_Mitigation.pdf (pp. 2)(accessed on September 28, 2012)

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The pipeline has a diameter of 16 inches and a potential capacity of 150,000 BPD.165 The products transported include heavy crude oil, SCO, naphtha and diesel.166 The pipeline can also be used to transport NGLs.

Norealis Pipeline Project – Enbridge Pipelines and Husky Oil The Norealis Pipeline was approved by the ERCB in April 2011, and is currently under construction. The pipeline’s stakeholders are Husky Oil and Enbridge, and begin at Husky’s Sunrise oil sands facility and terminate at Enbridge Athabasca’s existing Cheecham Terminal. Figure B.20 illustrates the route of the proposed Norealis Pipeline, which is shown by the red-dotted line.

Figure B.20 The Proposed Norealis Pipeline Project

Source: Pipelines International167

165 Alberta Government, Oil Sands Discovery Centre: Facts about Alberta’s oil sands and its industry, http://history.alberta.ca/oilsands/docs/facts_sheets09.pdf (pp. 29) (accessed on September 28, 2012) 166 Pinnacle Energy, SCC inspection & mitigation program on Suncor OSPL pipeline, http://www.pinnacleeng.ca/newsAndArticles/sccInspection_Mitigation.pdf (pp.2) 167 Enbridge set to expand North America’s crude oil pipeline network, http://pipelinesinternational.com/news/enbridge_set_to_expand_north_americas_crude_oil_pipeline_n etwork/053579/# (accessed on September 28, 2012)

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The proposed Woodland Pipeline is shown by the dark blue line. The latter is discussed in a subsequent section. The aforementioned Waupisoo and Athabasca pipelines are also illustrated, by the light blue and green lines.

The 112 kilometre Norealis Pipeline will transport blended bitumen, or bitumen blended with a diluent. Once the product is delivered to Cheecham Terminal, it will be transported to facilities in Edmonton or Fort Saskatchewan, utilizing Enbridge’s Regional Oil Sands System. The pipeline has a diameter of 24 inches.168

As previously mentioned, the project is under construction, with the first phase to begin operations in winter 2013.169 The initial capacity of the pipeline is 90,000 BPD at an estimated cost of US$475 million.170 The Norealis is expandable to 270,000 BPD.171 With increased flow, the facilities at Cheecham Terminal need to be expanded, including a new 200,000 barrel bitumen tank.172

Woodland Pipeline Project (& Woodland Pipeline Extension) – Enbridge Pipelines Construction of the Woodland Pipeline project was completed in April 2013.173 The pipeline’s stakeholders are Imperial Oil and Enbridge, and begin at the former’s Kearl oil sands mine site/facility and terminate at Enbridge Athabasca’s existing Cheecham Terminal.

The route of the Woodland Pipeline is illustrated in Figure B.20, shown by the dark blue line. The pipeline is 140 kilometres in length and has a diameter of 36 inches.174 The pipeline’s initial capacity is approximately 200,000 BPD.175 Construction also includes two 300,000 barrel tanks and related facilities, as well as a new pump station at the Kearl oil sands project.176

168 ibid 169 Enbridge website, Norealis Timeline, http://www.enbridge.com/Norealis/Timeline.aspx (accessed on September 28, 2012) 170 Enbridge set to expand North America’s crude oil pipeline network, http://pipelinesinternational.com/news/enbridge_set_to_expand_north_americas_crude_oil_pipeline_n etwork/053579/# (accessed on September 28, 2012) 171 ibid 172 Enbridge website, Norealis, http://www.enbridge.com/Norealis (accessed on September 28, 2012) 173 Enbridge website, Woodland Pipeline Project, http://www.enbridge.com/WoodlandPipelineProject.aspx, (accessed on May 13, 2013) 174 Enbridge website, Woodland Pipeline Project, http://www.enbridge.com/WoodlandPipelineProject.aspx (accessed on May 13, 2013) 175 ibid 176 ibid

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The Woodland Pipeline Extension project was approved on September 27, 2012.177 Enbridge is the pipeline’s builder. The pipeline begins at its Cheecham Terminal facility and runs to the Edmonton mainline hub.178 The 385 kilometre pipeline will have a diameter of 36 inches, and will cost between C$1 and C$1.4 billion.179 The pipeline is an extension of the under-construction Woodland Pipeline and will follow the existing Waupisoo Pipeline. The initial capacity of the pipeline will be 400,000 BPD, but will be expandable to 800,000 BPD.180 The project is scheduled to be completed by 2014.

Wood Buffalo Crude Pipeline Project – Enbridge Pipelines and Suncor The Wood Buffalo Pipeline project was completed in 2012. The pipeline’s stakeholders are Suncor and Enbridge. The 95 kilometre pipeline runs parallel with the existing Athabasca Pipeline, and connects the Athabasca Terminal to the Cheecham Terminal.181 The pipeline has a diameter of 30 inches.182 The pipeline is estimated to cost approximately C$370 million.183 Construction also included 2 new pump stations, one at the initiation point, Athabasca Terminal, and the second at the midpoint, located in the Lynton area.184 The Wood Buffalo Pipeline is sometimes referred to as Line 18 Extension.

ECHO Pipeline – Canadian Natural Resources Ltd. (CNRL) The ECHO (East Central Heavy Oil) Pipeline is owned and operated by CNRL. The original length of the pipeline was 153 kilometres, but was extended 57 kilometres in 2001.185 The pipeline begins in Beartrap, Alberta and terminates at the Hardisty Terminal.186 Midstream Rainbow pipeline begins at Rainbow Lake, Alberta and ends at Edmonton.187 Elan Energy and Gibson Petroleum constructed the ECHO in 1997, which originally

177 Enbridge receives approval for Woodland pipeline project, September 27, 2012, http://www.foxbusiness.com/news/2012/09/27/enbridge-receives-approval-for-woodland-pipeline- project/ (accessed on September 28, 2012) 178 ibid 179 ibid 180 ibid 181 Enbridge to Construct $370 Million Wood Buffalo Pipeline, August 26, 2010, http://www.marketwire.com/press-release/Enbridge-to-Construct-370-Million-Wood-Buffalo-Pipeline- TSX-ENB-1310041.htm (accessed on September 28, 2012) 182 Enbridge website, Wood Buffalo Pipeline, http://www.enbridge.com/WoodBuffalo.aspx (accessed on September 28, 2012) 183 Alberta Government, Pipeline Projects, http://albertacanada.com/SP_IMAP_pipelines1.pdf (accessed on September 28, 2012) 184 Enbridge website, Wood Buffalo Pipeline, http://www.enbridge.com/WoodBuffalo.aspx (accessed on September 28, 2012) 185 NEB, Canada’s Oil Sands: Opportunities and Challenges to 2015, http://www.neb.gc.ca/clf- nsi/rnrgynfmtn/nrgyrprt/lsnd/pprtntsndchllngs20152004/pprtntsndchllngs20152004-eng.pdf (pp. 52) (accessed on September 28, 2012) 186 ibid 187 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012)

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commenced in Elk Point.188 The initial capacity of the 12 inch diameter pipeline was 54,000 BPD.189 Currently, the capacity is 57,000 BPD, but is expandable to 75,000 BPD.190

It is interesting to note that the ECHO Pipeline is insulated, eliminating the need for condensate blending. To meet downstream requirements, the bitumen is, however, blended at Hardisty.191

Figure B.21 illustrates the route of the ECHO Pipeline, with the red line. The yellow patches show CNRL’s producing properties, while the white regions show CNRL’s leaseholds. The black vertical line illustrates the provincial border between Alberta and Saskatchewan.

Figure B.21 The ECHO Pipeline

Source: CNRL Website192

188 ECHO Pipeline started up, May 11, 1997, http://www.gasandoil.com/news/n_america/ dcdcb6d11c8ee511aac1403092d41822 (accessed on September 28, 2012) 189 ibid 190 Oil and Gas Journal, Canadian Natural Resources to curtail some heavy oil activity in 2002, December 2001, http://www.ogj.com/articles/2001/12/canadian-natural-resources-to-curtail-some-heavy-oil- activity-in-2002.html (accessed on October 15, 2012) 191 NEB, Canada’s Oil Sands: Opportunities and Challenges to 2015,http://www.neb.gc.ca/clf- nsi/rnrgynfmtn/nrgyrprt/lsnd/pprtntsndchllngs20152004/pprtntsndchllngs20152004-eng.pdf (pp. 53) (accessed on September 28, 2012) 192 Primary Heavy Oil Canadian Natural Investor Open House, May 2012, http://www.cnrl.com/upload/media_element/516/02/08_primary-heavy_open-house-2012.pdf (Slide 5)

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Husky Pipelines – Husky Energy Husky Energy owns and operates Husky Pipelines. The companies gathering pipelines can be divided into the Alberta system and the Saskatchewan system. The web of pipelines transports heavy crude oil and bitumen from Cold Lake, Lloydminster and Saskatchewan and delivers the product to upgrading and refining facilities at Lloydminster.193 From the latter, the Husky Synthetic and Lloydminster blends are transported to the hub at Hardisty.194 This segment is called the Mainline Pipeline System.

The Alberta system consists of approximately 1,445 kilometres of pipelines, while the Saskatchewan system consists of approximately 580 kilometres.195 The Alberta system transports crude, diluent and SCO. Figure B.22 illustrates the Husky Pipelines, shown in green. The graphic also shows other pipelines in the area, including the IPF, ECHO, Manito and the Athabasca Pipeline. Hardisty is the source of trunkline pipelines such as Keystone, Enbridge Mainline and Kinder Morgan’s Express-Platte.

193 NEB, Canada’s Oil Sands: Opportunities and Challenges to 2015,http://www.neb.gc.ca/clf- nsi/rnrgynfmtn/nrgyrprt/lsnd/pprtntsndchllngs20152004/pprtntsndchllngs20152004-eng.pdf (pp. 53) 194 ibid 195Husky Energy website, Pipeline Operations, http://www.huskyenergy.com/operations/midstream/pipelineinfrastructure/pipelineoperations.asp (accessed on September 28, 2012)

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Figure B.22 Husky Oil Pipelines

Source: http://google.brand.edgar-online.com196

Rainbow Pipeline (I & II) – Plains Midstream Plains Midstream Rainbow pipeline begins at Rainbow Lake, Alberta and ends at Edmonton.197 The approximately 1,000 kilometre pipeline transports crude oil and condensate.198 The pipeline’s diameter is between 20 and 24 inches. The Rainbow has a capacity of 220,000 BPD.199 The operator of the 45-year old pipeline, Plains Midstream Canada, is a subsidiary of Houston-based All American Pipeline.200

Figure B.23 illustrates the route of the Rainbow Pipeline, shown in red running from Zama to Edmonton and is circled in green. The pipeline running from Edmonton, south

196http://google.brand.edgar- online.com/EFX_dll/EDGARpro.dll?FetchFilingHtmlSection1?SectionID=7785534-252013- 355999&SessionID=ziG7FHHAD_nnds7 (accessed on September 28, 2012) 197 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012) 198 ibid 199 ibid 200 ibid

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through Sundre down to the US is the Plains Midstream’s Rangeland Pipeline. The latter was previously discussed. Pipelines in blue are other main pipelines in Alberta.

Figure B.23 The Rainbow Pipeline

Source: Plains Midstream Canada

Plains Midstream Canada is building the Rainbow Pipeline II, running from Northern Sunrise County to Strathcona County.201 The Rainbow Pipeline II will run alongside the existing Rainbow Pipeline from Nipisi Terminal, near Utikuma Lake, through Flatbush Meter Station, to an Enbridge Terminal Tie-in in Edmonton.202 The 301 kilometre pipeline is estimated to cost around C$200 million and is on schedule to be completed by mid-2013.203 The pipeline will transport butane and condensate to heavy oil producing areas.204

The route of the Rainbow Pipeline II is shown in Figure B.24.

201 Plains Midstream website, http://www.plainsmidstream.com/content/new-projects-rainbow-pipeline- ii (accessed on September 28, 2012) 202 ibid 203 Alberta Government, Pipeline Projects, http://albertacanada.com/SP_IMAP_pipelines1.pdf (accessed on September 28, 2012) 204 ibid

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Figure B.24 The Rainbow Pipeline II

Source: UPI Website205

Pembina Conventional Pipelines – Pembina Pipeline Corporation Pembina’s conventional pipeline network spins across Alberta and British Columbia like a complex web. In total there are over 7,500 kilometres of pipelines.206 The pipelines transport both crude oil and NGLs, depending on the pipeline.207 Pembina’s conventional crude oil pipelines transport approximately half of Alberta’s crude oil production and 30 percent of NGLs produced in Western Canada.208

Figure B.25 illustrates Pembina’s conventional pipeline network. The spotted lines are other existing pipelines. For instance, the pipeline crossing British Columbia, through Kamloops to Vancouver, is Kinder Morgan’s previously discussed Trans Mountain Pipeline. The system includes transportation nodes at Edmonton, Kamloops and Taylor.

205 UPI website, Image Rainbow II, http://www.upi.com/r/m/story/13045143314932/ (accessed on September 28, 2012) 206 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012) 207 ibid 208 Pembina website, Our Business, http://www.pembina.com/pembina/webcms.nsf/AllDoc/023585C87690673D8725778800596E97?OpenD ocument (accessed on May 14, 2013)

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The Cutbank Complex was acquired from Talisman Energy on June 2, 2009 for C$300 million. The latter is made up of 3 gas plants: Cutbank, Musreau and Kakwa, 9 compressor stations and a 300 kilometre gathering system. The facility processes NGLs and is in proximity to the Montney Shale.

Figure B.25 Pembina Conventional Pipelines

Source: Pembina website209

The collection of pipelines is best discussed as the Alberta System and the British Columbia System. Table B.1 shows Pembina’s conventional pipelines in both provinces. The Alberta System comprises of 3 wholly-owned systems and the Wabasca River pipeline, of which Pembina has 10 percent interest. The British Columbia Systems are comprised of Western and three gathering systems (Blueberry, BC Light and Boundary Lake).

209 Pembina website, Conventional Pipelines graphic, http://www.pembina.com/pembina/webcms.nsf/AllDoc/3FA98250784CFFCE872578D4005B445A/$File/C onventional%20Pipelines.jpg?OpenElement (accessed on September 28, 2012)

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Table B.1 Pembina’s Conventional Pipelines

In-Service Production Products Capacity Date Source Transported (BPD) ALBERTA PIPELINES Peace System 1955 NE BC/NW AB CO; Cd; NGL 300,000 Drayton Valley System 1954 Pembina field CO; Cd 160,000 Other Alberta System 1959 NE BC/NW CO; Cd; NGL 379,000 AB/Swan Hills/Judy Creek/mid-AB Non-operated systems; 1959 Delivers crude CO; Cd 110,000 Bonnie Glen oil and condensate to Edmonton Wabasca River 1987 Northern AB CO 20,000 BC PIPELINES BC Systems (Western and 3 1960 NE BC & Taylor CO 80,000 gathering systems) to Kamloops pipeline Source: Pembina System Description;210 CO – Crude Oil, Cd – Condensate, NGL – Natural Gas Liquids

Conventional Oil Pipelines – Inter Pipeline Fund While oil sands transportation generates 36 percent of Inter Pipelines cash flow and conventional oil pipelines generate 21 percent, the latter plays an important role for the Calgary-based company.211

Similar to Inter Pipeline’s Oilsands system, its conventional oil pipeline system is comprised of three pipeline systems: Bow River Pipeline, Central Alberta Pipeline and Mid-Saskatchewan Pipeline. The three systems make up over 3,600 kilometres of operating pipeline and nearly 1,000,000 barrels of storage capacity.212 Recall that the Bow River Pipeline was discussed previously as an export pipeline. As such, this part will only review the Central Alberta Pipeline and the Mid-Saskatchewan Pipeline system. These conventional oil pipelines are illustrated in Figure B.26.

210 Pembina Pipeline Income Fund Rating Report, February 29, 2008, pp.9. 211 Inter Pipeline Find website, Investor Relations Presentation, June 2011, http://www.interpipelinefund.com/pdf/investor/presentation/IPF%20IR%20Presentation%20- %20June.pdf (pp. 16) 212 Inter Pipeline Find website, Conventional Oil Pipelines, 2012, http://www.interpipelinefund.com/pdf/operations/Conventional%20pipelines%20fact%20sheet%202012. pdf

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Figure B.26 Inter Pipeline Conventional Pipelines

Source: Inter Pipeline Fund213

The Central Alberta Pipeline transports crude oil from various central Alberta locations to Edmonton. Stations are located at New Norway, Duhamel, Stettler, Drumheller and Hussar Junction.214 The pipeline is 553 kilometres in length. This number includes not only the pipeline but the gathering system.215 Storage capacity of the Central Alberta Pipeline system is 113,700 barrels and its 2012 throughput was 27,600 BPD,216 up from 26,000 BPD in 2011217 and 22,400 BPD in 2010.218

213 Inter Pipeline Fund, Conventional Oil Pipelines Map, http://www.interpipelinefund.com/operations/conventional.php (accessed on October 11, 2012) 214 Inter Pipeline Fund, Central Alberta Pipeline System, Toll Schedule, http://www.interpipelinefund.com/pdf/operations/pipeline_business/toll_sheets/11CATRF1.pdf 215 Inter Pipeline Find website, Conventional Oil Pipelines, http://www.interpipelinefund.com/operations/conventional-oil-pipelines.cfm (accessed on May 13, 2013) 216 ibid 217 Inter Pipeline Fund Annual Report 2012, pp. 33. 218 Inter Pipeline Fund Annual Report 2011, pp. 33.

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The Mid-Saskatchewan Pipeline system transports crude oil from various southwestern Saskatchewan locations to the delivery point at Kerrobert, Saskatchewan. The pipeline is 437 kilometres in length.219 Storage capacity of the Mid-Saskatchewan Pipeline system is 397,600 bbls and its 2012 throughput was 41,100 BPD,220 up from 36,300 BPD in 2011221 and 32,500 BPD in 2010.222

Enbridge (NW) System – Enbridge The Norman Wells to Zama Pipeline, sometimes referred to as the Norman Wells Pipeline, stretches approximately 870 kilometres between the town in the Northwest Territories and the northwestern Alberta-located Zama.223 The pipeline has a capacity of 39,400 BPD.224 The pipeline is owned by Enbridge Pipeline (NW) Inc. and was officially opened in May 1985. The pipeline is the first completely buried oil pipeline in a permafrost environment, and is often regarded as a precursor in terms of technology of northern pipelines such as the future Mackenzie Valley Pipeline.225

Figure B.27 illustrates the Norman Wells to Zama Pipeline. It is important to note that the pipeline feeds into the northern portion of Plain Midstream Canada’s Rainbow Pipeline.226

219 Inter Pipeline Fund website, Conventional Oil Pipelines, http://www.interpipelinefund.com/operations/conventional-oil-pipelines.cfm (accessed on May 13, 2013) 220 ibid 221 Inter Pipeline Fund Annual Report 2012, pp. 33. 222 Inter Pipeline Fund annual Report 2011, pp. 33. 223 Enbridge website, Liquids Pipelines, http://www.enbridge.com/DeliveringEnergy/OurPipelines/LiquidsPipelines.aspx (accessed on September 28, 2012) 224 ibid 225 http://198.103.48.70/permafrost/pipeline_e.php (accessed on September 28, 2012) 226 Enbridge website, , Restarts Norman Wells Pipeline, http://ca.news.yahoo.com/enbridge-restarts- norman-wells-pipeline-small-leak-cleanup-235127791.html (accessed on September 28, 2012)

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Figure B.27 The Enbridge (NW) Pipeline

Source: http://198.103.48.70/permafrost/pipeline_e.php

Enbridge Saskatchewan System – Enbridge The Saskatchewan System starts in Midale and runs to Cromer, Manitoba. The system, including the gathering lines, is 388 kilometres in length.227 The system is comprised of the Saskatchewan Gathering, Westspur, Virden and Weyburn Pipeline systems.228 All pipelines were built between 1955 and 1957.229

Figure B.28 illustrates the Enbridge Saskatchewan System.

227 Enbridge website, Liquids Pipelines, http://www.enbridge.com/DeliveringEnergy/OurPipelines/LiquidsPipelines.aspx (accessed on September 28, 2012) 228 ibid 229 Enbridge Income Fund website, Assets, http://www.enbridgeincomefund.com/about/assets.php#sask (accessed on September 28, 2012)

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Figure B.28 Enbridge Saskatchewan System

Source: http://www.enbridgeincomefund.com/ar2008/operations/crude-oil-and-liquids-transportation/

The system transports crude oil and is owned by the Enbridge Income Fund.230 At year end-2012, the operating highlights (in thousands of barrels per day) of the Saskatchewan System include: Westspur System (182.4); Saskatchewan Gathering System (129.8); Weyburn System (31.5); and the Virden System (23.2).231 The Saskatchewan Gathering System and the Westspur System have a capacity of 255,000 BPD while the Weyburn System and Virden System have capacities of 47,000 BPD and 37,000 BPD, respectively.232

Saskatchewan’s network of crude oil pipelines connects producing fields to the Enbridge Canadian Mainline.233 The Bakken Formation is a target for Enbridge. Production from the Bakken and the Three Forks formations are the impetus for the Bakken Expansion Program, where new capacity can be expanded from an initial 145,000 BPD to 325,000 BPD by 2013.234 The Bakken Expansion Project went into service in March 2013.235

230 CEPA website, Pipeline Map, http://www.cepa.com/map/pipeline-map.swf (accessed on September 28, 2012) 231 Enbridge Income Fund Holdings Annual Review 2012, pp. 10. 232 Enbridge Income Fund website, Assets, http://www.enbridgeincomefund.com/about/assets.php#sask (accessed on September 28, 2012) 233 Enbridge Income Fund website, Saskatchewan System, http://www.enbridgeincomefund.com/ar2010/saskatchewan-system/ (accessed on September 28, 2012) 234 ibid 235 Enbridge Income Fund Holdings Annual Review 2012, pp. 4.

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