Canadian Energy Research Institute oilsands report - 2011

Canadian Energy Research Institute

Canadian Oil Sands Supply Costs and Development Projects (2010-‐2044) Dinara Millington Mellisa Mei Study No. 122 May 2011

CANADIAN OIL SANDS SUPPLY COSTS AND DEVELOPMENT PROJECTS (2010-‐2044)

Canadian Oil Sands Supply Costs and Development Projects (2010-‐2044)

Copyright © Canadian Energy Research Institute, 2011 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute Study No. 122 ISBN 1-‐896091-‐94-‐4 Authors: Dinara Millington Mellisa Mei Acknowledgements: The authors of this report would like to extend their thanks and gratitude to everyone involved in the production and editing of the material, including, but not limited to Megan Murphy and Peter Howard CANADIAN ENERGY RESEARCH INSITTUTE 150, 3512 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca May 2011 Printed in Canada

http://www.ceri.ca/

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Table of Contents LIST OF FIGURES .............................................................................................................................. v LIST OF TABLES ................................................................................................................................ vii EXECUTIVE SUMMARY .................................................................................................................... ix Assumptions and Scenarios ............................................................................................................ ix Supply Cost Results ........................................................................................................................ xii Projection Results ........................................................................................................................... xiii CHAPTER 1 INTRODUCTION ....................................................................................................... 1 Background..................................................................................................................................... 1 Approach and Methodology .......................................................................................................... 2 Organization of the Report ............................................................................................................. 2 CHAPTER 2 OIL SANDS REVIEW ................................................................................................. 3 Oil Sands, Background .................................................................................................................... 3 Oil Sands Development Scenarios ................................................................................................. 5 CHAPTER 3 OIL SANDS OVERVIEW SUPPLY COSTS .................................................................. 13 Methodology and Assumptions ..................................................................................................... 13 Light-‐Heavy Differential.................................................................................................................. 16 Estimating Inflation ........................................................................................................................ 18 Supply Cost Results ........................................................................................................................ 25 CHAPTER 4 OIL SANDS PROJECTIONS ........................................................................................ 29 Methodology .................................................................................................................................. 29 Oil Sands Projections Results and Analysis .................................................................................. 31 CHAPTER 5 TRENDS AND CHALLENGES IN THE OIL SANDS DEVELOPMENT ................................ 43 Environmental Issues ..................................................................................................................... 43 Tailings Management ..................................................................................................................... 50 Technology Options and Efficiency Improvements ........................................................................ 53 Oil Sands Merger and Acquisition Revival ...................................................................................... 59 CHAPTER 6 TRANSPORTATION .................................................................................................. 61 Current Transportation (Pipeline) Capacity.................................................................................... 61 Transportation Capacity Expansions .............................................................................................. 63 CHAPTER 7 CONCLUSION ........................................................................................................... 67

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List of Figures Figure 1 US and BRIC Oil Consumption Shares .............................................................................. xi Figure 2 Realistic Emissions Compliance Costs .............................................................................. xii Figure 3 Realistic Oil Sands Supply Costs ....................................................................................... xiii Figure 4 Bitumen Production Projections ...................................................................................... xiv Figure 5 Initial Capital Requirements ............................................................................................. xv Figure 6 Greenhouse Gas Emissions .............................................................................................. xvi Figure 7 Industry Compliance Costs ............................................................................................... xvii Figure 8 Provincial Bitumen Royalties............................................................................................ xviii Figure 2.1 ........................................................................................................... 3 Figure 2.2 Firebag, In Situ ................................................................................................................. 4 Figure 2.3 Suncor Mining Operations ............................................................................................... 5 Figure 2.4 US and BRIC Oil Consumption .......................................................................................... 6 Figure 2.5 Realistic Oil Prices ............................................................................................................ 7 Figure 2.6 Realistic Emissions Compliance Costs .............................................................................. 8 Figure 2.7 Protracted Slowdown Oil Prices ....................................................................................... 8 Figure 2.8 Protracted Slowdown Emissions Compliance Costs ........................................................ 9 Figure 2.9 Energy Security Oil Prices ................................................................................................. 10 Figure 2.10 Energy Security Emissions Compliance Costs .................................................................. 10 Figure 3.1 Electricity Price Projections .............................................................................................. 15 Figure 3.2 Natural Gas Price Projections ........................................................................................... 15 Figure 3.3 Light-‐Heavy Differential ................................................................................................... 17 Figure 3.4 Bitumen Royalty Rates ..................................................................................................... 18 Figure 3.5 Effect of the Oil Price on Refinery Construction Costs ..................................................... 20 Figure 3.6 Historic and Projected WTI Prices and Construction Cost Inflation Rates, 2007-‐2044 .... 20 Figure 3.7 Effect of the Oil Price on the Canadian-‐US Exchange Rate .............................................. 22 Figure 3.8 Historic and Projected WTI Prices and the Canadian-‐US Exchange Rate, 2007-‐2044...... 22 Figure 3.9 Effect of the Oil Price on Refinery Operating Costs ......................................................... 24 Figure 3.10 Historic and Projected WTI Prices and Operating Cost Inflation Rates, 2007-‐2044 ........ 25 Figure 3.11 Natural Gas and Oil Price Projection ................................................................................ 25 Figure 3.12 Realistic Oil Sands Supply Costs ....................................................................................... 26 Figure 3.13 Realistic Oil Sands Supply Costs (Contribution) ............................................................... 27 Figure 4.1 Bitumen Capacity Projections .......................................................................................... 31 Figure 4.2 Bitumen Production Projections ...................................................................................... 33 Figure 4.3 Initial Capital Requirements ............................................................................................. 34 Figure 4.4 Sustaining Capital Requirements ..................................................................................... 35 Figure 4.5 Natural Gas Requirements ............................................................................................... 35 Figure 4.6 Greenhouse Gas Emissions .............................................................................................. 36 Figure 4.7 Industry Compliance Costs ............................................................................................... 37 Figure 4.8 Provincial Bitumen Royalties............................................................................................ 38 Figure 4.9 Realistic Bitumen Production Projections ........................................................................ 39 Figure 4.10 Project Distribution .......................................................................................................... 40 Figure 4.11 Realistic Scenario Initial Capital Requirements ............................................................. 41 Figure 4.12 Realistic Scenario Sustaining Capital Requirements ..................................................... 41 Figure 4.13 Realistic Scenario Total Cost Requirements .................................................................. 42 Figure 5.1 States with GHG Emission Reduction Targets .................................................................. 46 Figure 5.2 Regional Cap-‐and-‐Trade Schemes.................................................................................... 47 Figure 5.3 Sources of Emissions Reductions Under the Cap Main Policy Case Relative to the Reference Case, 2012-‐2020 ......................................... 50 Figure 5.4 MFT Surface after 14 Days ............................................................................................... 51

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Figure 5.5 Well-‐to-‐Wheels GHG Emissions for Oil Sands and Other Crudes .................................... 53 Figure 5.6 -‐DSP Well Configuration ........................................................ 55 Figure 5.7 ET-‐DSP ................................................................................................ 56 Figure 5.8 ................................................................................................ 57 Figure 5.9 .................................................................................................................... 58 Figure 5.10 Oil Sands Mergers and Acquisitions ................................................................................. 60 Figure 6.1 Alberta Existing and Proposed Regional Pipelines ........................................................... 64 Figure 6.2 Existing and Proposed Export Pipelines ........................................................................... 64

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List of Tables Table 2.1 In-‐Place Volumes and Established Reserves of Crude Bitumen in Alberta ...................... 5 Table 3.1 Design Assumptions by Extraction Method ..................................................................... 14 Table 3.2 Crude Oil Characteristics .................................................................................................. 16 Table 4.1 Constraints by Scenario and Extraction Method ............................................................. 30 Table 5.1 Annual GHG Emission Caps .............................................................................................. 48 Table 6.1 Alberta Regional and Export Pipelines ............................................................................. 62 Table 6.2 Potential Pipeline Expansions .......................................................................................... 63

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Executive Summary The oil sands development exhibited moderate growth in 2010 relative to prior years, reflecting the resumption of the many oil sands projects that were deferred during the 2008-‐2009 economic recession. Since then, economic conditions have improved posting positive economic growth, credit is becoming available to oil sands proponents, mergers and acquisitions are ramping up, and West Texas Intermediate (WTI) oil prices increased to the US$70-‐85 per barrel range in 2010, a range in which oil sands greenfield projects currently become economic.

In response, several companies are now actively developing project phases that had previously been placed on hold. However, producers remain cautious about future oil price estimates and are proceeding at a more balanced pace in order to establish a better controlled cost environment. This approach should help producers avoid a repeat of the high cost inflation environment that resulted from the peak investment spending, in 2007 and 2008, associated with the concurrent development of several large oil sands projects. The past cancellation and deferral of projects should keep 2010 costs low, relative to the past few years.

The oil sands industry has attracted the attention of environmental activists who are concerned about the negative impact that oil sands development would have on land, water and air quality. All parties involved are currently working on minimizing these impacts through environmental policies, technological advancements and their implementation with one goal in mind: sustainable and socially acceptable development of an oil sands industry that is an integral part of the Canadian economy. The development, no matter how transparent, will be carefully monitored by other governments and environmental activists as this vast Canadian resource is developed.

The purpose of this report is twofold. First, modeling results for the potential paths of oil sands development and supply costs, out to 2044 are presented. T(CERI) oil sands projections and supply cost analysis have been valuable to industry, governments, and other stakeholders as part of their market analysis. This report relies upon the most up-‐to-‐date information available on project announcements (updated to November 3, 2010) and market intelligence

.

Secondly, CERI reviews the trends and challenges mostly on the environmental front, with GHG emissions, water use and tailings ponds being the most visible issues. These challenges are of critical importance because it is imperative to maintain a sustainable environment, regionally and globally, for present and future generations. It is also apparent that adequate pipeline infrastructure must be in place in order to move the bitumen to markets. Existing and potential pipeline systems are analyzed in the report as well.

Assumptions and Scenarios The current oil sands update analyzed four Scenarios. The Unconstrained Scenario, in which all oil sands projects proceeded on schedule, and as planned, was viewed as implausible, and hence was not evaluated in great detail. The three plausible scenarios are: Energy Security, Realistic, and Protracted Slowdown.

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The Protracted Slowdown Scenario represents a world in which the economic recovery is stalled in 2011, driven by protectionist policies, and aggressive emissions compliance costs that put an overly onerous burden on various hydrocarbon-‐based industries. Environmental activism pushes environmental policies

product restrictions across a wide variety of industries.

In the Energy Security Scenario, countries compete and try to secure the hydrocarbon resources as the world recovers from the recent economic recession. Specifically, the BRIC (Brazil, Russia, India and China) nations experience rapid economic growth. These countries expand exports of products, which drives up the demand for crude oil in those nations. The major demand centres for the exports, the US and other developed countries, also experience a period of rapid economic growth, and rising crude oil demand.

significantly offset the increase in demand for crude oil from the emerging economies. Faced with a surge in demand, the BRIC and other developed nations seek to secure access to physical supplies of oil, resulting in a bidding-‐up of the global oil price and a period of sustained growth in the oil sands. While plausible, both the Protracted Slowdown and the Energy Security Scenario are not likely to develop, which is why a Realistic Scenario was considered.

The Realistic Scenario assumes that the developed nations emerged from the recession and their economies continue to recover, experiencing modest economic growth in 2011, and bringing about a slow and steady growth in demand for crude oil. The growth is tempered somewhat by geopolitical concerns in the Middle East and economic setbacks in some European nations. The economic recovery in the developed nations coincides with that of BRIC nations, as well as other Asian countries. In this Scenario, oil prices begin a slow and steady climb, approaching $200/bbl of WTI,1 by the end of the projection period, 2044.2

1 2All values contained in this report are real dollars, unless otherwise stated.

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Figure 1 US and BRIC Oil Consumption Shares

Source: BP Statistical Review, 2010

The demand growth will be tempered by an ongoing push toward environmental protection, through modest emissions compliance costs. These emissions costs will be driven not by a global market, but a North American emissions pact that harmonizes compliance costs across the region.3 The November 2010 political shift in the US House of Representatives, along with a slow recovery from the recent recession has postponed the advancement of federal climate change legislation. As Canadian emissions compliance costs will be harmonized with the US, the compliance cost estimates used in this report have been adjusted, since the CERI 2009 update, to reflect a delay in the adoption of US climate change policy.

3Currently compliance costs are collected, set, and administered by the Government of Alberta. The costs are royalty deductible. In other words, the higher the compliance costs that are paid the lower is the provincial royalty income. This has a minimal impact on the costs of oil sands operators and total provincial income.

14%

16%

18%

20%

22%

24%

26%

28%

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Shares of world oil consumption by the US and BRIC

BRIC US

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Figure 2 Realistic Emissions Compliance Costs

Source: CERI.

Supply Cost Results Over the past year, CERI estimates that the capital costs for constructing oil sands projects have declined by 3.6 percent, while operating costs have increased by 5.8 assumed a three year construction period for oil sands projects, with construction commencing in 2011. Over the construction period (2011 to 2014), construction and operating costs are expected to rise by 19 percent, and slowly thereafter.

Under the Realistic Scenario, the oil sands are shown to be highly profitable, and an extremely good investment for oil sands operators, as well as the provincial and federal governments.

of oil prices, rates of return (ROR) for oil sands projects will range from 6 to 19 percent. Supply costs, illustrated in Figure 3, reflect a WTI equivalent price for steam assisted gravity drainage (SAGD) projects of $123/bbl, $128/bbl for integrated mining and upgrading projects, and $123/bbl for stand-‐alone mining projects; SAGD projects receive the highest ROR.4 The plant gate supply costs, which exclude transportation and blending costs, are $93/bbl, $100/bbl, and $93/bbl for SAGD, integrated mining and upgrading, and stand-‐alone mining, respectively. While capital costs and the return on investment5 account for a substantial portion of the total supply cost, the province s per barrel take is estimated at 18 to 22 percent.

4The calculated supply costs are for greenfield projects. The projects that are already on stream can be profitable at much lower costs, in the range of $40-‐$75/bbl. 5A substantial portion of the fixed capital includes the return on the investment.

$0

$10

$20

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$40

$50

$60

$70

$80

2010 2020 2030 2040

$/TRealistic Compliance Cost ProjectionExpect costs to rise in 35 years

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Figure 3 Realistic Oil Sands Supply Costs

SAGD(Realistic Oil Price

Projection19% ROR)

Mining & Upgrading (Realistic Oil Price

Projection6% ROR)

Mining (Realistic Oil Price

Projection14% ROR)

Fixed Capital (Initial & Sustaining) $39 $38 $44

Other $33 $43 $29Royalties $20 $18 $20Emissions Compliance Costs $1 $1 $1

-‐$10

$10

$30

$50

$70

$90

$110

$130

$/bblFixed Capital (Initial & Sustaining)

Other

Royalties

Emissions Compliance Costs

Supply Cost at the field $93 $100 $93

WTI Equivalent Supply Cost $123 $128 $123

Source: CERI.

Projection Results synthetic crude oil (SCO) production remains unchanged

from past reports. The projections are based upon the summation of all announced projects, with a wide variety of assumptions pertaining to the projects schedule and delays, technology, and state of development. The method by which projects are delayed, or the rate at which production comes on

The bitumen capacity projections are adjusted to account for the production profile of each extraction method, resulting in a peak production volume of 5.1 million barrels per day (MMBPD) by 2042, under the Realistic Scenario. By 2015, production under the Realistic Scenario is projected to reach 2.1 MMBPD, and by 2030 it is projected to increase to 4.8 MMBPD.

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Figure 4 Bitumen Production Projections

0

2,000

4,000

6,000

8,000

2010 2020 2030 2040

10^3 bpd

Bitumen Production VolumesBy 2020 bitumen production could reach 2.5 MMBPD, under a Realistic Scenario

Energy Security Realistic Protracted Slowdown

Source: CanOils, CERI.

Achieving any of the levels of production in the three scenarios requires a substantial number of inputs, of which capital (both strategic and sustaining) is critical. Illustrated in Figure 5 are initial capital costs.

Over the 35-‐year projection period, the total initial capital required is projected to be $302 billion under the Energy Security Scenario, $257 billion under the Realistic Scenario, and $213 billion under the Protracted Slowdown Scenario.

By 2044, natural gas requirements will increase by 2 to 3 times the current level. The Realistic projection indicates natural gas requirements of almost 4.5 billion cubic feet per day (BCFPD) by 2044. In such a scenario, Canada and the US could be engaged in an energy exchange Canadian oil for the US natural gas that further enhances the trade relationship between the two countries. The prospects for technology switching and efficiency improvements are substantial, and will likely put downward pressure

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Figure 5 Initial Capital Requirements

Source: CERI.

One of the by-‐products of natural gas consumption is the production of greenhouse gas (GHG) emissions. Without equipment to separate the emissions streams, the GHGs will be released into the atmosphere. While technological innovation within the oil sands industry (in addition to carbon capture and storage) is expected to help reduce these emissions, the figure below illustrates rising GHG emissions under current design assumptions.

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$40

2010 2020 2030 2040

billions

Initial, or Strategic, Capital Requirements


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Figure 6 Greenhouse Gas Emissions

Source: CERI.

GHG emissions are expected to rise in tandem with natural gas requirements. The emissions presented above reflect point source emissions, and do not take into account emissions associated with electricity purchases, or the benefits of cogeneration. In other words, these are the absolute GHG emissions that result from the production of marketable bitumen, and SCO, from the oil sands industry.

Based upon the emissions compliance cost projection, the industry would pay $142 billion in compliance costs over the next 35 years.6

6The estimation of these compliance costs is based upon the per barrel costs. As such, this will overestimate the initial years and underestimate the later years of the projection. Figure 7 should be used as an illustrative guide, with those caveats in mind.

0

20

40

60

80

100

120

2010 2020 2030 2040

MT/y

Greenhouse Gas EmissionsWithout new technologies and carbon capture, emissions are expected to rise to 91 million tonnes by 2044


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Figure 7 Industry Compliance Costs

Source: CERI.

Based upon the assumed oil price, as stated earlier, bitumen royalties collected by the province, under the Realistic Scenario, will exceed $1 trillion over the projection period.7

7The estimation of the royalties are based upon the per barrel costs. As such, this will overestimate the initial years and underestimate the later years of the projection. Figure 8 should be used as an illustrative guide, with those caveats in mind.

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billions billions

Realistic Compliance Cost ProjectionWithout improvments in technology/efficiency, industry will have paid $142 billion by 2044

Cummulative Annual Compliance Costs

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Figure 8 Provincial Bitumen Royalties

Source: CERI.

Trends and Challenges great economic potential, they also present

environmental challenges in the areas of greenhouse gas (GHG) emissions, air pollution, water, tailings ponds and land. In fact, many observers consider them impossible to overcome and advocate for a moratorium, if not a shutdown, of the industry. However, the oil sands experience has demonstrated that technology has the potential to "change the game". Today, a large number of concepts and technologies are under active development to address oil sands challenges. The portfolio is broad and diverse, addressing various sectors of the industry and allows a reasonable expectation that the next 35 years will see vast improvements in oil sands exploitation in a way that increases the size of the economic opportunity, creates high value local employment and dramatically reduces environmental impact.

Pipelines and Markets The existing crude oil pipeline infrastructure underwent a much needed expansion recently in order to accommodate the growing volumes of oil sands production. A number of pipeline expansions were completed in 2009, and 2 major additional pipelines became operational at the end of 2010, including TransCanada Keystone and Enbridge Alberta Clipper. Furthermore, additional pipeline capacity, to major traditional markets and the US Gulf Coast, will become available once other scheduled pipeline projects are built and begin operating in the next few years.

$2,411

$2,913

$2,973

$3,160

$3,293

$4,123

$4,961

$6,125

$7,418

$8,343

$9,673

$11,96

4

$13,89

5

$15,50

0

$18,02

2

$19,12

2

$21,72

1

$23,51

8

$25,26

9

$27,25

0

$30,37

9

$33,41

6

$35,98

6

$39,39

0

$41,24

1

$42,99

8

$44,10

8

$45,17

8

$46,43

9

$47,57

8

$49,74

0

$51,86

7

$54,34

0

$56,41

9

$58,56

8

$60,81

7

$62,93

5

$65,33

4

$67,47

7

$-‐

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$600,000

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$1,000,000

$1,200,000

$1,400,000

$-‐

$10,000

$20,000

$30,000

$40,000

$50,000

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$80,000

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

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2044

Cumulative

Annu

alRoyalties Collected from the Oilsands Industry ($ Millions), 2006 -‐ 2044

Cumulative Royalties

In Situ (Solvent) Projects

In Situ Projects

Mining Projects

Total Annual Royalties

Canadian Oil Sands Supply Costs and Development Projects (2010-‐2044) 1

May 2011

Chapter 1 Introduction Background The oil sands development exhibited moderate growth in 2010 relative to prior years, reflecting the resumption of themany oil sands projects that were deferred during the 2008-‐2009 economic recession, which resulted in lower oil prices. Since then, economic conditions have improved. economies are posting positive economic growth, credit is becoming available to oil sands proponents, mergers and acquisitions are ramping up, and WTI oil prices increased to the US$70-‐85/bbl range in 2010, a range in which oil sands Greenfield projects currently become economic.

In response, several companies are now actively developing project phases that were previously placed on hold. However, producers remain cautious about future oil price estimates, and are proceeding at a more balanced pace in order to establish a better controlled cost environment. This approach should help producers avoid a repeat of the high cost inflation environment that resulted from the peak investment spending in 2007 and 2008 associated with the concurrent development of several large oil sands projects. The past cancellations and deferrals of projects should keep 2010 costs low, relative to the past few years.1

The oil sands industry has attracted the attention of environmental activists who are concerned about the negative impact the oil sands development would have on land, water and air quality. All parties involved are currently working on minimizing these impacts through environmental policies, technological advancements and their implementation with one goal in mind: sustainable and socially acceptable development of oil sands industry that is an integral part of the Canadian economy.2 The development, no matter how transparent, will be carefully monitored by other governments and environmental activists as this vast Canadian resource is developed.

This is the sixth annual edition of the Canadian Energy Research Institute CERI) oil sands supply cost and development projects update report. Similar to past editions of the report, several scenarios for oil sands developments will be explored. In addition, given the assumptions for the current cost structure, an outlook for future supply costs will be provided.

The purpose of this report is to:

Provide the reader with a better understanding of the current status of Canadian oil sands projects, both existing and planned. The status assessment will cover the full spectrum of activities and

1

Sands project. The project has been broken into 5 separate categories -‐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 very deliberate and flexible to ensure projects can be started or stopped based on market conditions. Another example is Suncor entering into a strategic partnership with Total E&P Canada Ltd., to jointly develop the Fort Hills and Joslyn oil sands mining projects and restart construction of the Voyageur upgrader. This partnership promises to keep costs down while jointly developing the mines then going separate and bidding for same contractors. 2CERI Study No. 120, of the Petroleum Industry in Canada, July 2009.

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technologies, such as in situ, mining, and integrated production; and facilities for upgrading crude bitumen to SCO.

Explore the future direction of oil sands developments, including a projection of investments and production.

Understand the natural gas requirements of the industry, and the GHG emissions associated with the natural gas consumption.

Estimate the supply cost, including costs associated with carbon emissions, for greenfield projects consistent with in situ, mining and integrated production.

Review the current industry trends and challenges. Provide an overview of the existing and proposed pipeline infrastructure.

Approach and Methodology CERI has established itself as a leader in oil sands related market intelligence. 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 the most up-‐to-‐date information available on project announcements (updated to November 3, 2010), team.

The 2010 report presents project vintages and production capacities of existing and planned projects.

upgrading), location, and extraction technologies (including pilot projects). Similarly, upgrading facilities are characterized by technology, and by type (i.e., stand-‐alone facilities, 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 to reflect the stage of development.

This report also presents greenfield supply costs by type (i.e., mining, in situ and upgrading), and by technology (i.e., SAGD for in situ operation and integrated vs. stand-‐alone for upgrading facilities).

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

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

Chapter 3 presents the assumptions and methodology used in the supply cost assessment. Results for supply costs are presented.

Chapter 4 highlights the barriers and challenges to the oil sands industry, through the examination of several production projection scenarios.

Chapter 5 describes the current issues facing the oil sands industry, including the environmental concerns, and mergers and acquisitions.

Chapter 6 discusses existing and proposed pipeline infrastructure.

Chapter 7 draws key conclusions from the study.


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Chapter 2 Oil Sands Overview

Oil Sands, Background 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

which the Alberta Energy Resources Conservation Board (ERCB) will play an integral role. Eventually, the development of the resource will extend into the neighboring province of Saskatchewan. The development of the oil sands in both provinces, no matter how transparent, will be carefully monitored by other governments and environmental activists that are sure to keep the industry on its toes, as they wage an ongoing battle with the industry over the development of this extraordinarily valuable Canadian resource.

While the resources in Saskatchewan are not fully delineated, CERI is monitoring the ongoing

resources that exist in Alberta are contained within three oil sands areas (Peace River, Athabasca, and Cold Lake), as designated by the Government of Alberta, and illustrated in Figure 2.1.

Figure 2.1

SOURCE: ERCB.


May 2011

Together these regions cover an area over 14.5 million hectares (ha), with the remaining established reserves at 169.9 billion barrels of an extremely heavy crude oil, referred to as bitumen.1 Approximately 16 percent of 169.9 billion barrels is currently under active development.2

Mining and in situ production methods, both of which will be discussed later in the report, are the most widely accepted bitumen recovery methods that are currently employed in the oil sands. 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 2.3). More importantly, but less publicized however, is the fact that in situ production (illustrated in Figure 2.2) does not have the same visual impact, given the smaller footprint on a per project basis. The amount of surface area devoted to mining is only 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 Firebag, In Situ

SOURCE: Suncor Energy Inc. (Firebag).

1

includes the crude bitumen, minerals, and rocks that are found together with the bitumen (Source ERCB, 2010 ST98). 2The initial volume-‐in-‐place of bitumen has been estimated by the Alberta Energy Resources Conservation Board (ERCB) and is used to estimate the initial established reserves of bitumen bitumen that is estimated to be recoverable given current technology and knowledge. (While the ERCB made significant changes to the in-‐place resource in 2009, there are no changes to the estimate of the initial established reserves of crude bitumen. The

nitial established reserves are used throughout this report as our estimates for the resource size.) Source: Alberta Energy Resources Conservation Board. Supply/Demand Outlook 2010-‐


May 2011

Figure 2.3 Suncor Mining Operation

SOURCE: Suncor Energy Inc.

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. The remaining recoverable bitumen is anticipated to be recovered using mining techniques.

Table 2.1 provides a breakdown of the initial volume-‐in-‐place, initial established reserves, cumulative production, as well as the remaining established reserves, to help further illustrate the vast potential in the area.

Table 2.1 In-‐Place Volumes and Established Reserves of Crude Bitumen in Alberta

(10^9 barrels)3

Recovery Method Initial

Volume-‐in-‐Place Initial Established

Reserves Cumulative Production

Remaining Established Reserves

Total 1,802.7 176.7 6.9 169.8 Mining 130.8 38.7 4.5 34.2 In situ 1,671.9 138.0 2.4 135.5

Oil Sands Development Scenarios The extraction of bitumen from the oil sands will be driven by the forces of supply and demand, with extraction technologies being an integral component in ensuring that the oil sands remain competitive with other sources of crude oil. While there are indications that the developed economies have emerged from the recession, the rate at which they are recovering remains uncertain. Furthermore, there is 3Alberta Energy Resources Conservation Board. -‐


May 2011

uncertainty as to how the speed of their recovery could help, or hinder, the ongoing development of other nations. While the US share of world oil demand has been decreasing over the last ten years, the BRIC nations of Brazil, Russia,4 India and China have become the primary drivers of incremental non-‐OECD crude oil demand, as shown in Figure 2.4.

Figure 2.4 US and BRIC Oil Consumption

Source: BP Statistical Review, 2010

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 energy security.

The projection period for this analysis extends from end of year 2010 to end of year 2044, and in each scenario it has been assumed that the Canadian and the US other.5 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 dollars.

The first scenario is Realistic Scenario,6 which assumes that the developed nations emerged from the recession and continue to recover, experiencing modest economic growth in 2011, 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

4Even though Russia and Brazil are energy exporters, their domestic energy consumption has been increasing, just like China and India. 5While it is highly 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. 6

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May 2011

begin a slow and steady climb (see Figure 2.5), thus sending a signal to oil sands proponents to develop their projects to meet the demand for crude oil, which is assumed to be returning to its pre-‐recession growth, and a period of ongoing growth for the foreseeable future ensues.

Figure 2.5 Realistic Oil Prices

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

The emissions costs will be driven not by a global market, but by a North American emissions pact, that harmonizes compliance costs, and seeks to reduce emissions, while not being overly onerous to the public and industry which will pay a higher price for all goods and services. Furthermore, the emissions compliance costs could potentially slow down the economic recovery, and therefore are gradually implemented over the next 35 years (see Figure 2.6). While this might not satisfy international climate change activists, the modest emissions compliance costs act as a stimulant for technology development, as oil sands companies seek to differentiate themselves from the barrel.7

7T

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

http://www.environment.alberta.ca/.

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http://www.environment.alberta.ca/


May 2011

Figure 2.6 Realistic Emissions Compliance Costs

The next two scenarios provide alternative views of how the world could develop over the next 35 years. The Protracted Slowdown Scenario represents a world in which the economic recovery is stalled in 2011, driven by protectionist policies and aggressive emissions compliance costs that put an overly onerous burden on various hydrocarbon-‐based industries. Environmental policy trumps economic growth (and

variety of industries. These policies do not initially drive up oil prices, as seen in Figure 2.7, but instead raise the cost of living in developed economies, and negatively impact imports from the BRIC nations. This Scenario results in a minimal economic growth, until 2021, as trade is restricted.

Figure 2.7 Protracted Slowdown Oil Prices

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May 2011

With high compliance costs, as illustrated in Figure 2.8, and limited economic growth, the 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 the resumption in oil sands developments. The high compliance costs remain, which drive the overall costs for oil sands producers and hence have a negative impact on oil sands development over the projection period.

Figure 2.8 Protracted Slowdown Emissions Compliance Costs

The last scenario is driven by energy security concerns, where security for energy undermines environmental policies. Under the Energy Security Scenario , both developed and emerging, compete for hydrocarbon resources. The BRIC nations expand exports of products, which drives up their demand for energy, notably crude oil. The major demand centres for the exports, the US and other developed countries, also experience a period of rapid economic growth, and rising crude oil demand.

those policies do not offset the 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 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 being converted to process heavy oil, and those refineries that previously accepted heavy oil, i.e., Venezuelan heavy oil, turn to Canadian oil sands. Venezuela 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.

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May 2011

Figure 2.9 Energy Security Oil Prices

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 (see Figure 2.10) are introduced in North America, and new technologies are developed to reduce the environmental footprint of oil sands operations. The application of new technologies is driven by economics, and no subsidies are required. Carbon capture equipment is installed on some facilities, for the primary purpose of supporting enhanced oil recovery rather than to reduce emissions.

Figure 2.10 Energy Security Emissions Compliance Costs

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May 2011

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 production costs (including emissions compliance costs). The next Chapter of this report will explore the oil sands supply costs under the conditions described in the Realistic Scenario. This will set the stage for an examination of the paths for oil sands development under each of the three scenarios.


May 2011


May 2011

Chapter 3 Oil Sands Overview Supply Costs

method utilizes various technologies to extract valuable bitumen from the oil sands. The focus of this report is on commercial extraction technologies, which are defined as technologies being used in two or more oil sands projects, and by more than one oil sands operator. These technologies are mining and extraction,1 steam assisted gravity drainage (SAGD), and cyclic steam stimulation (CSS).2

This Chapter is organized as follows: a brief discussion of supply cost methodology will be followed by the assumptions used to support the CERI model. Once the assumptions have been provided, the supply costs are presented in a manner that is comparable to previous CERI results, followed by supply costs that reflect the Realistic Scenario. These results will be discussed in detail, along with their implication on oil sands development.

Methodology and Assumptions that used by industry, government, and

non-‐governmental organizations. The supply cost represents the constant dollar price needed to recover all capital expenditures, operating costs, royalties, taxes, and earn a realistic return on investment.

In past reports, (ROR) on an investment (10 percent, real), thereby, allowing the price of oil to vary by extraction method. This approach allowed CERI to estimate the price of oil required to bring forth new oil sands projects, by extraction method. When the Government of Alberta moved away from a royalty system that was fixed (by pre-‐and post-‐payout periods), to a system that takes into account oil prices, The new supply cost methodology takes into account oil prices, and solves for the constant real ROR that is needed to recover all capital expenditures, operating costs, royalties, and taxes, given an oil price projection. A forecast of

Outlook 2010 (EIA AEO 2010) and extended, at a rate of 3 percent per year, to cover the projection period (see Figure 3.2). As was the case in the previous model, the new model provides a constant dollar price that reflects the RORs.

The supply costs calculated in this report are presented as supply costs at the field, in addition to WTI equivalent supply costs. The WTI equivalent supply costs take into account transportation costs for either SCO or blended bitumen, in addition to an assumed light-‐heavy differential.

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 as part of previous public reports.


May 2011

The assumptions that underpin each production method are presented in Table 3.1. The project design parameters and energy requirements remain the same as in the 2009 report, however, capital and operating costs have been adjusted to reflect for deflation in capital and inflation in operating costs from 2009 to 2010.

Table 3.1 Design Assumptions by Extraction Method

Measurement Units SAGDMining and Extraction

Integrated Miningand Extractionand Upgrading

Stand Alone Upgrading

Project Design Parameters

Stream day capacity bbl of bitumen per day 30,000 100,000 115,000

Stream day capacity bbl of SCO per day 100,000

Production Life years 30 30 30 30Average Capacity Factor (over production life) percent 77.00% 92.00% 92.00% 92.00%

Capital Expenditures (2010 Constant Dollars)Initial Millions of dollars 1,091.4 7,988.0 11,238.9 5,131.9

Initial Dollars per bbl of capacity 36,381.0 79,879.8 97,729.9 51,319.1Sustaining (Annual Average) Millions of dollars 50.9 269.6 379.3 169.9

Operating Working Capital Days payment 45 45 45 45

Operating Costs

Fixed (Annual Average) Millions of dollars 75.0 177.4 362.7 198.7

Variable Dollars per bbl of capacity 7.2 8.9 14.0 5.1

Energy RequirementsNatural Gas

Royalty Applicable GJ per day 32,100 54,000 62,100

Non-‐Royalty Applicable GJ per day 20,871 81,436

Electricity Purchased

Royalty Applicable MWh/d 300 0 1,128

Non-‐Royalty Applicable MWh/d 448

Electricity Sold MWh/d 0 728 0 0

Other Project AssumptionsAbandonment and Reclamation percent of total capital 2% 2% 2% 2%

Notes: -‐ Capital costs for SAGD operations are an average of AOSC's Mackay project, Devon Energy Jackfish Phase 3 and Meg Energy Christina Lake Phase 2B. Other capital and operating oil sands study, and have been adjusted for deflation in capital and inflation in operating costs from 2009 to 2010.

-‐ SCO = Synthetic crude oil

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. In situ projects are assumed to purchase electricity from the Alberta grid. Within the next decade, it is anticipated that most in situ projelectricity load. In other words, most new in situ projects, within the next decade, are not likely to produce excess amounts of electricity.


May 2011

As illustrated in Figure 3.1, electricity prices are assumed to increase over the next three decades, at an average annual inflation rate of 2.5 percent, as higher fuel prices and emissions compliance costs results in a different generation mix within the province of Alberta.

Figure 3.1 Electricity Price Projection

Source: Clean Air Strategic Alliance (CASA), CERI

While oil sands production methods are continually improving, natural gas is still the primary fuel source for the oil sands industry. A forecast of natural gas prices was obtained from the U AEO 2011 Early Research Overview, and extended, at a rate of 3 percent per year, to cover the projection period. The natural gas prices as related to the oil price projection are presented in Figure 3.2.

Figure 3.2 Natural Gas Price Projections

Source: EIA, CERI.

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May 2011

Light-‐Heavy Differential

of the light-‐heavy differential. This differential reflects the price spread between a barrel of light oil, as measured by the benchmark WTI, and a barrel of heavy oil. One of the most widely accepted measures of the heavy oil price is the Western Canadian Select (WCS) price.

Launched in 2004 by EnCana Corporation (Cenovus Energy), Canadian Natural Resources Limited, Talisman, and Petro-‐Canada (Suncor), the WCS consists of conventional Western Canadian heavy oil, and bitumen that has been blended with sweet SCO and diluents. This heavy oil benchmark crude is used as a tool for hedging risks against North American heavy crude oil grades, and its benefits include: reduced infrastructure requirements, consistency of crude oil quality, reduced demand for conventional diluent, and greater market liquidity.3 The following table compares the characteristics of the WCS blend to two other crude oils.4

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

TAN (mo KOH/g) 0.7-‐1.0 0.3 0.68 Since the WCS represents a heavy sour barrel of oil, it is more difficult to refine than light sweet oil, and a different product slate results from the heavier barrel. Because of this, the WCS prices should be lower than the WTI price, producing a positive light-‐heavy differential (WTI minus WCS). The average daily light-‐heavy differential, for the period January 2, 2008 to January 18, 2011 was US$14.82. Movements in this differential tend to correlate positively, though not perfectly, with changes in the WTI price. Figure 3.3 displays changes in the light-‐heavy differential over this period.

3Western Canadian Select (WCS) fact sheet, Cenovus Energy, http://www.cenovus.com/operations/doing-‐business-‐with-‐us/marketing/western-‐canadian-‐select-‐fact-‐sheet.html.Accessed on January 10, 2011. 4

Corporation presentation to the Canadian Heavy Oil Association, February 3, 2005, http://www.choa.ab.ca/ documents/Feb0305.pdf. Accessed on January 11, 2011.

http://www.cenovus.com/operations/doing-business-with-us/marketing/western-canadian-select-fact-sheet.html

http://www.cenovus.com/operations/doing-business-with-us/marketing/western-canadian-select-fact-sheet.html

http://www.choa.ab.ca/%20documents/Feb0305.pdf




May 2011

Figure 3.3 Light-‐Heavy Differential

Source: Nickles, CERI

Based on the historical data, the light-‐heavy differential is assumed to be constant at US$15.00/bbl. This assumption reflects a scenario in which bitumen and SCO continue to penetrate the market proportionately, and refineries adjust accordingly. 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. In 2010, transportation costs from the field to Hardisty were $1.00/bbl, and $0.80/bbl to Oklahoma.

Within the supply cost model, federal and provincial corporate income taxes have been assumed constant at 19 percent and 10 percent, respectively. The provincial royalty rate, which applies to both pre-‐ and post-‐payout periods, is linked to the WTI (Canadian dollars), and is maximized when the oil price reaches $120/bbl. During the pre-‐payout period, oil sands projects are levied a royalty, based on gross revenue, while post-‐payout projects are levied a royalty that is allowable ROR before payout of 5.5 percent.

The royalty rates that are applied under the Realistic Scenario are illustrated in Figure 3.4.

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May 2011

Figure 3.4 Bitumen Royalty Rates

Source: Government of Alberta

The construction and operation periods for an oil sands project have been slightly adjusted from previous studies, in order to reflect somewhat longer construction periods. Oil sands operations are assumed to commence construction on January 1, 2011, and begin operating on January 1, 2014. The projects will continue to operate until end of year 2044.

Estimating Inflation Nelson-‐Farrar Inflation Refinery-‐Construction Cost Index (1946=100) and the WTI

A critical component in determining future oil sands supply costs is the cost of construction. Within the design assumptions are the capital and operating costs for each oil sands extraction method. These costs

Methodology

Estimating the inflation in oil sands construction costs can be a difficult endeavour due to the lack of available historical cost data. In order to approximate construction cost inflation in the oil sands, CERI studied the changes in the Nelson-‐Farrar Inflation Refinery-‐Construction Cost Index. There are two main reasons for using the Construction Cost Index in 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 of the Construction Cost Index.

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May 2011

The Nelson-‐Farrar Construction Cost Index was first introduced as a methodto estimate future oil sands construction cost inflation. This section will outline the process of estimating the inflation.

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 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 univariate statistical model was created using historical WTI spot prices and the Nelson-‐Farrar Inflation Refinery-‐Construction Cost Index.

If such a relationship is shown empirically, 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.

Data

Monthly Cushing, Oklahoma WTI spot price data (US$/bbl) and Nelson-‐Farrar Inflation Refinery-‐Construction Cost Index data were obtained from the EIA, and the Oil and Gas Journal, respectively, for the period March 1996 to July 2010.

Annual projections of the WTI price were obtained from the EIA, for the period 2010 to 2035. Between 2035 and 2044, it is assumed that the WTI price increases at an annual rate of 3 percent. Because the data is annual, we assume that it is an average value for the year, and set the monthly value equal to the annual WTI price over the projection period.

Results

The analysis revealed a strong, positive, and statistically significant relationship between the WTI spot 80 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 Construction Cost Index by 10. Figure 3.5 shows a scatter plot of historical WTI prices, and the Nelson-‐Farrar Refinery Construction Cost Index.


May 2011

Figure 3.5 Effect of the Oil Price on Refinery Construction Costs

Source: CERI, US EIA, Oil and Gas Journal

The Nelson-‐Farrar Refinery Construction Cost Index was projected to the end of the outlook period (2044), assuming that no future structural breaks occur in the relationship between the price of oil and construction costs. The model indicates that year-‐over-‐year (October 2009-‐October 2010) refinery construction costs have experienced a deflation of 3.6 percent. Between the end of 2010 and 2044, construction costs are estimated to increase by 51 percent. The average annual construction cost inflation rate, forecasted between October 2011 and October 2044, is 1.1 percent. Figure 3.6 displays projections of the WTI price, and the annual inflation in refinery construction costs.

Figure 3.6 Historic and Projected WTI Prices and Construction Cost Inflation Rates, 2007-‐2044


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May 2011

Canadian-‐US Exchange Rate(C$/US$) and the WTI

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, 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.

Methodology

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.

Data

The statistical analysis required data on historic and projected crude oil prices, and historic exchange rates. Monthly Cushing, Oklahoma WTI spot price data (US$/bbl) was obtained from the EIA for the period March 1996 to July 2010. Historical exchange rate data (C$/US$) was obtained for the same period from

extended, at a rate of 3 percent per year, to cover the projection period.

Results

There exists a negative and statistically significant relationship between the Canadian-‐US exchange rate and the price of crude oil, as illustrated in Figure 3.7factors, 78 percent of the variations in the exchange rate can be explained by changes in the price of crude oil.


May 2011

Figure 3.7 Effect of the Oil Price on the Canadian-‐US Exchange Rate

Source: CERI, US EIA, Statistics Canada

For each $1/bbl increase in the WTI price, the value of the US dollar, relative to the Canadian dollar, is estimated to decrease by 0.0061. That is, for every US$1/bbl increase in the price of oil, each US$1 can purchase 0.0061 fewer Canadian dollars. Figure 3.7 shows that over time, and left unconstrained by fiscal and monetary policies, the exchange rate declines to C$0.99/US$1 (US$1.01/C$1) in 2015, C$0.81/US$1 (US$1.23/C$1) in 2030, and C$0.50/US$1 (US$2.00/C$1) by 2044.

Figure 3.8 Historic and Projected WTI Prices and the Canadian-‐US Exchange Rate, 2007-‐2044

Source: CERI, US EIA, Statistics Canada

As the Canadian-‐US exchange rate ($C/$US) decreases, Canadian goods and services become relatively more expensive to purchase with US dollars, and Canadian exports to the US decline correspondingly.

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May 2011

Between 2004 and 2009, the value of Canadian exports to the US declined by approximately 23 percent. Over the same period of time, the Canadian-‐US exchange rate declined by 12 percent. In 2009, Canadian

5

The simple univariate 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 produc .6

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.

Nelson-‐Farrar Refinery-‐Operating Cost Index (1956=100) and the WTI

Methodology

The operating costs of an oil sands project contribute significantly to the total supply cost. 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 upgrader exactly, the two facilities are similar in that each consists of very energy intensive processing units.7 For this reason, the Nelson-‐Farrar Refinery Operating Cost Index is used in the examination of oil price impacts on oil sands operating costs. The Operating Cost Index 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 Nelson-‐Farrar Refinery Operating Cost Index can be produced, using an oil price projection. Year-‐over-‐year changes in the Operating Cost Index could then be used as a rough proxy for the rate of inflation in oil sands operating costs.

Data

Monthly Cushing, Oklahoma WTI spot price data (US$/bbl), and Nelson-‐Farrar Refinery Operating Cost Index data were obtained from the EIA, and the Oil and Gas Journal, respectively, for the period March 1996 to July 2010. Projections of the WTI price from the US EIA, and CERI are used to estimate exchange rates to 2044. 5Imports, 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 December 31, 2010. 6Cayen, Jean-‐

February 2010. 7While this relationship is weaker for an oil sands operation, it is still a relevant comparison until an alternative method is developed.

http://www40.statcan.gc.ca/l01/cst01/gblec02a-eng.htm


May 2011

Results

WTI spot prices have a positive and statistically significant effect on the value of the Nelson-‐Farrar Refinery Operating Cost Index. Eighty-‐two percent of observed changes in the Operating 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 Operating Cost Index value by 3.3. Figure 3.9 shows a scatter plot of historical WTI prices, and the Nelson-‐Farrar Refinery Operating Cost Index.

Figure 3.9 Effect of the Oil Price on Refinery Operating Costs


The forecast of the Nelson-‐Farrar Refinery Operating Cost Index estimates that refinery operating costs have increased by 5.8 percent, year-‐over-‐year (October 2009-‐October 2010).

Between December 2010 and December 2044, operating costs are estimated to increase by 58 percent. The annual average operating cost inflation rate forecasted between October 2011 and October 2044 is 1.2 percent. Figure 3.10 displays a projection of the WTI price, and the annual rate of inflation in refinery operating costs.

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May 2011

Figure 3.10 Historic and Projected WTI Prices and Operating Cost Inflation Rates, 2007-‐2044


Supply Cost Results To better understand th , a price projection was required in order to accurately account for the new royalty system. The Realistic Scenario is essential, as it allows CERI to compare each extraction method against the other with the same oil and natural gas price assumptions.

The oil price is again illustrated in Figure 3.11 to provide context to these results. Under the price projection, the oil sands are shown to be highly profitable, and an extremely good investment for oil sands operators, as well as the provincial and federal governments.

Figure 3.11 Natural Gas and Oil Price Projection

Source: EIA, CERI.

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May 2011

Figure 3.12 Realistic Oil Sands Supply Costs

SAGD(Realistic Oil Price Projection

19% ROR)

Mining & Upgrading (Realistic Oil Price Projection

6% ROR)

Mining (Realistic Oil Price Projection

14% ROR)

Electricity Sales 0.0 0.0 0.7Emissions Compliance Costs 1.4 1.2 0.8Income Taxes 8.3 5.1 8.6Royalties 19.6 18.0 20.1Abandonment Costs 0.0 0.2 0.0Electricity 1.0 0.8 0.0Other Operating Costs (Fixed & Variable) 16.2 31.5 15.9Fuel (Natural Gas) 5.5 4.6 2.8Operating Working Capital 1.5 0.6 1.3Fixed Capital (Initial & Sustaining) 39.3 38.1 43.9

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$/bbl

In situ projects reach payout in 4 years, mining projects in 5 years, and integrated projects in 5 years. The result is a substantial increase in oil sands royalties collected by the province, and in some cases, RORs for oil sands operators.

Figure 3.12 illustrates the supply costs for SAGD, mining and integrated mining. The plant gate supply costs, which exclude transportation and blending costs, are $93/bbl, $100/bbl, and $93/bbl for SAGD, integrated mining and upgrading, and stand-‐alone mining, respectively. The WTI equivalent supply cost for SAGD projects is $123/bbl, $128/bbl for integrated mining and upgrading projects, and $123/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 $18 to $20 in royalty revenues for each barrel of oil produced on average, over the life of an oil sands project. On a percentage basis, this ranges from 18 to 22 percent (see Figure 3.13).


May 2011

Figure 3.13 Realistic Oil Sands Supply Costs (Contribution)

SAGD(Realistic Oil Price Projection

19% rate of return)

Mining & Upgrading (Realistic Oil Price Projection

6% rate of return)

Mining (Realistic Oil Price Projection

14% rate of return)

Electricity Sales 0.0% 0.0% 0.8%Emissions Compliance Costs 1% 1% 1%Income Taxes 9% 5% 9%Royalties 21% 18% 22%Abandonment Costs 0% 0% 0%Electricity 1% 1% 0%Other Operating Costs (Fixed & Variable) 18% 31% 17%Fuel (Natural Gas) 6% 5% 3%Operating Working Capital 2% 1% 1%Fixed Capital (Initial & Sustaining) 42% 38% 47%

0%

10%

20%

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40%

50%

60%

70%

80%

90%

100%

Over the life of the oil sands project, in situ operations would appear to provide the highest RORs, at 19 percent. Stand-‐alone mining projects have a respectable ROR of 14 percent, while integrated operations would appear to have the lowest ROR, at 6 percent. In addition, the high ROR will be pushed down, as vendors raise prices (to capture the economic rent), and refineries may become more aggressive in contract negotiations.

Under Realistic Scenario, a harmonized emissions compliance cost projection has been included. Beyond harmonizing emissions costs with the USthat the compliance costs are harmonized with 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 the $1 to $1.5/bbl in emissions compliance costs would be collected by the federal government, and represents a wealth transfer from Alberta to Ottawa. As will be discussed in the next Chapter, this lost royalty revenue could amount to billions of dollars a year.


May 2011

Canadian Oil Sands Supply Costs and Development Project (2010-‐2044) 29

May 2011

Chapter 4 Oil Sands Projections Based upon Realistic Scenarioprofitable 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. The estimates are based upon a high quality oil sands project (either mining or in situ). Inevitably, some projects will experience delays from financing, and possibly regulatory hurdles.

develop the projections will be followed by the assumptions used to delay, and/or cancel oil sands l sands projections for bitumen, SCO, natural gas requirements, GHG emissions,

strategic and sustaining capital, and provincial royalty revenues will then be provided.

Methodology bitumen and SCO production volumes remains unchanged from past

reports. Projections are based on the summation of all announced projects, with a wide 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

unconstrained projections in past CERI will only be shown to provide context to the constraints, and represents a production, as currently defined by the collective announcements from the oil sands industry.

The three scenarios that were presented in the previous Chapters are used to guide oil sands development projections. To summarize, the scenarios are the Realistic, Protracted Slowdown, and Energy Security; the Unconstrained Scenario is not considered as a full scenario in this report. Each scenario contains an oil price and emissions compliance cost projection that underpins the potential expansion path for oil sands development.

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.

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.


May 2011

al 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.

Table 4.1 Constraints by Scenario and Extraction Method

Probability Delay Probability Delay Probability DelayFraction Years Fraction Years Fraction Years

Onstream 1.00 0 1.00 0 1.00 0Under Construction 1.00 1 1.00 1 1.00 1Suspended 1.00 2 1.00 2 1.00 2Approved 1.00 3 1.00 3 1.00 3Awaiting Approval 1.00 5 1.00 5 1.00 5Announced 1.00 9 1.00 9 1.00 9Cancelled 1.00 0 1.00 0 1.00 0





Mining Upgrading

Energy Security Scenario

Realistic Scenario

Protracted Slowdown Scenario

In Situ Mining Upgrading

In Situ Mining Upgrading

In Situ


May 2011

Oil Sands Projections Results and Analysis Based upon current announcements from oil sands proponents, capacity could peak at 6.8 MMBPD by the end of 2027 without delays or curtailments; for comparison, 2009 oil sands update under the Unconstrained Scenario, the peak was achieved in 2034 with 7.2 MMBPD. While this represents a bold target for the oil sands industry, the path towards the peak is not possible, 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 4.1 are the three scenarios, in addition to the Unconstrained Scenario. In each scenario, oil sands capacity exceeds 4MMBPD by 2044. However, the paths of development differ for each scenario.

Figure 4.1 Bitumen Capacity Projections

Source: CERI, CanOils

Under the Protracted Slowdown Scenario, the oil sands experience almost no capacity growth over the next decade, a direct result of low oil prices, and high emissions compliance costs, which lock the oil sands out of the market. The slight drop in production in 2017 is a result of the earliest mining projects in the oil sands reaching the end of the assumed production life. This dip is noticeable in each projection at various times as projects are retired. By 2020, the industry begins to anticipate higher oil prices, as trade barriers are reduced, and emissions compliance costs become more manageable. While the oil sands recover from the stagnation, capacity expansions do not Realistic Scenario before the end of the projection period.

0

2,000

4,000

6,000

8,000

2010 2020 2030 2040

10^3 bpd

Bitumen CapacityBeyond 2021, each projection experiences substantial capacity growth

Total Bitumen (Unconstrained Capacity Scenario)

Total Bitumen (Capacity, Energy Security Scenario)

Total Bitumen (Capacity, Realistic Scenario)

Total Bitumen (Capacity, Protracted Slowdown Scenario)


May 2011

In a world where energy security trumps all other concerns, driven by a robust economic growth in 2011, the oil sands return to a period of rapid and aggressive development. The Energy Security Scenario implicitly assumes that the rise in oil prices more than offset the inflation that would be experienced in Alberta, as oil sands developments grow at unprecedented rates. By 2020, bitumen capacity would reach 3.9 MMBPD, but not as bitumen capacity reaches 6.2 MMBPD by 2044.

While some may be skeptical about this Scenario coming to fruition, it is plausible that, by 2044, the oil sands could be the exclusive supplier 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 is finding the labour and capital to commission new oil sands projects at such a rate, in addition to the requirements for pipelines and refineries.

Realistic Scenario, where oil sands development is slow to rebound. It is not until 2016 that the oil sands industry experiences its first spike in bitumen capacity. Following this spike is a period of relatively steady capacity growth from 2018 to 2034, eventually slowing down by 2044. In 2016, capacity reaches 2.7 MMBPD, and by the end of 2030 the capacity increases to 5.3 MMBPD.

This scenario is in line with expectations for pipeline capacity additions, and it is quite 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) will introduce challenges to the Alberta economy, similar to those faced during the 2004 to 2008 period.

Figure 4.2 illustrates the possible paths for production under the three scenarios. Despite the recent slowdown, the prevailing view in the industry appears to be that, while a recessionary economic environment dictates caution on investment decisions, the future continues to look bright. All three scenarios show a significant growth in oil sands production for the 35-‐year projection period.

The bitumen capacity projections are adjusted to account for the production profile, resulting in a peak production volume by 2042 of 5.8 MMBPD under the Energy Security Scenario, or 5.1 MMBPD by 2042 under the Realistic Scenario. Under the Protracted Slowdown Scenario, peak production of 4.2 MMBPD is reached by 2044. Production under the Realistic Scenario is projected to reach 2.1 MMBPD by 2015, and 4.8 MMBPD by 2030.


May 2011

Figure 4.2 Bitumen Production Projections


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. And lastly, once the facility is operating there is an ongoing need for sustaining capital to ensure that production volumes stay at their design capacities.

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 4.3.

0

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8,000

2010 2020 2030 2040

10^3 bpd

Bitumen Production VolumesBy 2020 bitumen production could reach 2.5 MMBPD, under a Realistic Scenario



May 2011

Figure 4.3 Initial Capital Requirements

Over the 35-‐year projection period, the total initial capital required is projected to be $302 billion under the Energy Security Scenario, $257 billion under the Realistic Scenario, and $213 billion under the Protracted Slowdown Scenario.

required capital investment is 20.1 percent lower under the Energy Security Scenario, 16.8 percent lower under the Realistic Scenario and 13.4 percent lower under the Protracted Slowdown Scenario. With the exception of the Protracted Slowdown Scenario, new investment dollars start declining by 2030, 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 assumptions for project start dates, and announcements from the oil sands proponents. With careful planning, the Realistic Scenario could be a viable target. By 2015, $13.5 billion in capital investments will be required, and by 2030 the required investment reaches $3.4 billion, or a total of $241 billion between 2010 and 2030. Ongoing investment, in the form of sustaining capital will take place on an annual basis.

In each of the three scenarios, the annual sustaining capital required for the oil sands (excluding royalty revenues, taxes, and fixed and variable operating costs) exceeds $2 billion by 2044. The Realistic projection shows an annual investment, by 2040, of $2.9 billion, and is estimated to average $2.3 billion over the projection period. Figure 4.4 presents the sustaining capital costs under the three scenarios.

$0

$10

$20

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billions

Initial, or Strategic, Capital Requirements



May 2011

Figure 4.4 Sustaining Capital Requirements

The amount of natural gas required to sustain the oil sands industry is substantial, and is illustrated in Figure 4.5.

Figure 4.5 Natural Gas Requirements

$0

$1

$2

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$4

2010 2020 2030 2040

billions

Sustaining Capital RequirementsUnder the Realistic Scenario, sustaining capital averages $2.1 billion per year (vs. 2.4 in 2009)


1,000

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mmcf/d

Natural Gas RequirementsExpect natural gas requirements to surge, unltil alternatives are brought to market



May 2011

By 2044, natural gas requirements will increase by 2 to 3 times the current levels. The Realistic Scenario indicates natural gas requirements of almost 4.5 BCFPD by 2044. Considering how aggressively shale gas production in the US has come on stream, and the potential for shale production in Canada, meeting the

In such a scenario, Canada and the US could be engaged in an energy exchange Canadian oil for US natural gas that further enhances the trade relationship between the two countries.The prospects for technology switching and efficiency

requirements.

One of the by-‐products of natural gas consumption is the production of GHG emissions. Without

released into the atmosphere. While technological innovation within the oil sands industry (in addition to carbon capture and storage) is expected to help reduce these emissions, Figure 4.6 below illustrates the

Figure 4.6 Greenhouse Gas Emissions

GHG emissions are expected to rise in tandem with natural gas requirements. The emissions presented above reflect point source emissions, and do not take into account emissions associated with electricity purchases, or the benefits of cogeneration. In other words, these are the absolute GHG emissions that result from the production of marketable bitumen, and SCO, from the oil sands industry.

Large industrial emitters within Alberta that exceed their emissions reduction target, have the option to purchase Alberta-‐based carbon offset credits, or contribute $15 per tonne of carbon dioxide equivalent

0

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MT/y

Greenhouse Gas EmissionsWithout new technologies and carbon capture, emissions are expected to rise to 91 million tonnes by 2044



May 2011

(CO2e) exceeding the target into the Climate Change and Emissions Management Fund. Within the supply cost model, it is assumed that the oil sands projects pay the $15 compliance cost in full.

Using the previously presented emissions compliance cost projection from the Realistic Scenario, a projection of annual and total compliance costs paid to the Alberta Government can be calculated. The revenues collected from this compliance cost are distributed by the Climate Change and Emissions Management Corporation, an organization that is independent of the Government of Alberta, to projects or initiatives that support GHG reducing technologies.

As illustrated in Figure 4.7, the compliance costs increase over the projection period. By 2044, it is estimated that the industry will pay $5.2 billion per year in compliance costs, a rather hefty incentive to innovate. Over the projection period the industry is projected to pay almost $145 billion in compliance costs.

The estimation of these compliance costs is based upon the per barrel cost. As such, this will overestimate costs in the initial years, and underestimate costs in the later years of the projection. The figure below should be used as an illustrative guide, with those caveats in mind.

Figure 4.7 Industry Compliance Costs

$0

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billions billions

Realistic Compliance Cost ProjectionWithout improvments in technology/efficiency, industry will have paid $142 billion by 2044

Cummulative Annual Compliance Costs


May 2011

The previous Chapter concluded with a brief discussion about the possibility of a compliance cost program functioning as a wealth transfer mechanism, moving funds from the Government of Alberta to the Government of Canada. Under the current system, royalties are calculated after accounting for the compliance costs on a per project basis, resulting in a lower royalty paid to the provincial government. However, since the lower royalty is partially offset by collecting the compliance costs, this may not be that serious of an issue; the provincial government has decided how to use those revenues as part of a clean technology fund.

If the compliance costs were levied by the federal government, and the province continues to allow compliance costs to be deductable from royalties, then the 145 billion dollars collected could be transferred from the province of Alberta to the federal government. On the other hand, if the compliance costs are not deductable, but calculated on after tax income (or after provincial taxes), the wealth transfer would be mitigated, but liance cost program in favour of a federal program.

Based upon the assumed oil price, as stated earlier, the cumulative amount of bitumen royalties collected by the province is estimated to reach over one trillion over the projection period. By 2044, the royalties collected annually could reach $67.5 billion, as illustrated in Figure 4.8.

Figure 4.8 Provincial Bitumen Royalties

Illustrated in Figure 4.9 are the production projections under the Realistic Scenario, by extraction type, used to estimate royalty revenues, emissions, and natural gas requirements. Mined bitumen maintains a majority status of oil sands volumes until 2025, when in situ production volumes overtake mined bitumen. By the end of the projection period, in situ bitumen accounts for 57 percent of total production volumes, or just fewer than 3 MMBPD, as compared to mined bitumen which produces 2.2 MMBPD.

$2,411

$2,913

$2,973

$3,160

$3,293

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$8,343

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Annu

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Royalties Collected from the Oilsands Industry ($ Millions), 2006 -‐ 2044

Cumulative Royalties

In Situ (Solvent) Projects

In Situ Projects

Mining Projects

Total Annual Royalties


May 2011

Figure 4.9 Realistic Bitumen Production Projections


Given the production projection under the Realistic Scenario, the distribution of projects across various development stages is shown in Figure 4.10. The Figure illustrates that a large proportion of total projects are made up of projects that are currently on stream, approved and awaiting approval. As the proportion of on stream projects starts to decline from 86 percent in 2015 to 24 percent by 2044, the total proportion of approved and awaiting approval projects increases from 3 percent in 2015 to just over 50 percent by the end of the projection period.

0

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2010 2020 2030 2040

10^3 bpd

Realistic Production VolumesIn situ volumes grow to 57% of total bitumen by 2044

Total In Situ Bitumen Volumes Total Mined Bitumen Volumes


May 2011

Figure 4.10 Project Distribution

Currently, all mined bitumen and a portion of in situ production is upgraded to SCO. In 2009, 12 percent of in situ production was upgraded to SCO. Given the suspension of five upgrader projects with total capacity of 710,000 barrels per day (BPD), it is uncertain what amount of bitumen will be upgraded to SCO. This supports supply cost analysis, which indicates strong support for bitumen production; while upgrading did not appear to generate a substantial ROR.

Initial (or strategic), and sustaining capital requirements are broken down by extraction method under the Realistic Scenario, and are illustrated in Figures 4.11 and 4.12, respectively. Integrated projects include integrated in situ operations, which make up, on average, 11 percent of total integrated projects. Compared to figures from the 2009 update, the capital investment for stand-‐alone upgrading has decreased by 40 percent, and has increased by 38 percent for in situ projects, on average.

Total cost requirements for the oil sands industry are presented in Figure 4.13. These include the initial and sustaining capital and operating costs for all types of projects. Under the Realistic Scenario, the total costs will peak in 2023 at $53.4 billion.

0

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Onstream Under Construction Approved Suspended Awaiting Approval Announced

'000 b/d


May 2011

Figure 4.11 Realistic Scenario Initial Capital Requirements

Figure 4.12 Realistic Scenario Sustaining Capital Requirements

$0

$5

$10

$15

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2010 2020 2030 2040

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Initial, or Strategic, Capital RequirementsIn situ expansions take place throughout the projection period

In Situ MiningIntegrated Projects Stand Alone Upgrading

$0

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2010 2020 2030 2040

billions

Sustaining Capital RequirementsIn situ expansions take place throughout the projection period

In Situ Mining

Integrated Projects Stand Alone Upgrading


May 2011

Figure 4.13 Realistic Scenario Total Cost Requirements

Source: CAPP, CERI

0

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2007 2012 2017 2022 2027 2032 2037 2042

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Initial and Sustaining Capital and Operating Requirements

Initial Operating

Sustaining Historical Capital

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May 2011

Chapter 5 Trends and Challenges in the Oil Sands Development North America has returned to positive economic growth, and oil sands developers are returning to pre-‐recession activity levels. As the activity slowly ramps up, current trends and challenges in the oil sands development need to be considered by governments and industry. The scope of this chapter is to review four such trends and challenges in the oil sands industry. They are: uncertainty surrounding future environmental policies; the management of tailings ponds associated with mining operations; the technological advancements that are currently being developed and/or tested in pilot projects; and the revival of mergers and acquisitions. These topics are addressed here solely to provide context, hence this work does not represent an analysis of economic, social, environmental or public health impacts.

Environmental Issues

reput

and are insignificant when compared in a global context. GHG emissions from the oil sands only exceed that of other crude oils, refined in the US, by 6 percent, on average.1 Additionally, on a per-‐barrel of oil basis, GHG emissions from the oil sands have declined by an average of 39 percent since 1990.2 Advancements in technology will continue to improve the energy efficiency, and thus reduce GHG

policies. The Government of Canada has stated that federal climate change policy will follow that of the US. In 2010, Canada harmonized its GHG emissions reduction target with the US, committing to reduce GHG emissions by 17 percent below 2005 levels by 2020.3

Future climate change legislation will increase the cost of production for oil sands operators. The cost associated with any potential climate change policy, however, is an unknown element given the current uncertainty in federal policy development, and this presents a risk to oil sands investments. Although Alberta has GHG emission regulations in place, industry could face a host of new regulations if the

circumstance, Alberta may have no choice but to adopt the federal standards.

1 2 http://environment.alberta.ca/ documents/Oilsands_provincial_action_December17_2010.pdf. Accessed on December 31, 2010. 3News Release, Canada Lists Emissions Target under the Copenhagen Accord, Environment Canada, February 1, 2010, http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-‐1&news=EAF552A3-‐D287-‐4AC0-‐ACB8-‐A6FEA697ACD6. Accessed on December 31, 2010.

http://environment.alberta.ca/%20documents/Oilsands_provincial_action_December17_2010.pdf



http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-1&news=EAF552A3-D287-4AC0-ACB8-A6FEA697ACD6


May 2011

To provide a better idea of the direction that federal climate change policy may follow, this section of the report will discuss climate change developments from recent international negotiations, as well as the US.

United Framework Convention on Climate Change The goal of the 16th annual United Nations (UN) Climate Change Conference in Cancun, Mexico (November 26, 2010 to December 10, 2010) was to tackle some of the outstanding issues from the Copenhagen Conference, and to set the groundwork for what may lead to a post-‐2012 agreement. Although the decision of whether or not to extend the Kyoto Accord beyond the first commitment period (2008-‐2012), a contentious issue for many nations, including Australia, Canada, Japan, and Russia, was deferred to the 2011 UN Conference in Durban, South Africa, successful multilateral negotiations between developed and developing nations led to the advancement of key aspects of the Copenhagen Accord, and the inclusion of the pillars of the Copenhagen Accord in the official UN process.

The Cancun Agreements encompass a balanced package of decisions from the Ad Hoc Working Group on Long-‐Term Cooperative Action under the Convention,4 and the Ad Hoc Working Group on Further Commitments for Annex I Parties under the Kyoto Protocol.5 Achievements of the Cancun Agreements include: the incorporation of emission reduction pledges from the Copenhagen Accord into the United Nations Framework Convention on Climate Change (UNFCCC) process; progress in the area of reducing emissions from deforestation and forest degradation, conservation of forest carbon stocks (REDD+); establishing a process to design a Green Climate Fund, through which long-‐term funding of US$100 billion per year may be distributed; the establishment of a technology mechanism to facilitate cooperation in the development and deployment of new adaptation and mitigation technologies to developing countries; the expansion of the Clean Development Mechanism (CDM) to include carbon capture and storage (CCS) projects; and improved transparency measures that call for the monitoring, reporting, and verification of emission reductions in countries that receive financial support for emissions mitigation efforts.

ed in Copenhagen, was reiterated at the Cancun conference.6 The concept of recognizing national circumstances is as significant for developing nations as it is for developed energy exporting nations, and will no doubt be included in the next round of negotiations, which are scheduled to take place between November 28, 2011 and December 9, 2011.

By focusing on areas that developed and developing nations were willing to compromise, international climate change negotiators were able to make meaningful progress at the UN Conference in Cancun. With

4Outcome of the work of the Ad Hoc Working Group on long-‐term Cooperative Action under the Convention, The Conference of the Parties, United Nations Framework Convention on Climate Change, December 11 2010, http://unfccc.int/files/meetings/cop_16/application/pdf/cop16_lca.pdf, Accessed on December 15, 2010. 5Outcome of the work of the Ad Hoc Working Group on Further Commitments for Annex I Parties under the Kyoto Protocol and its fifteenth session, The Conference of the Parties, United Nations Framework Convention on Climate Change, December 11, 2010, http://unfccc.int/files/meetings/cop_16/application/pdf/cop16_kp.pdf. Accessed on December 15, 2010. 6Outcome of the work of the Ad Hoc Working Group on long-‐term Cooperative Action under the Convention, The Conference of the Parties, United Nations Framework Convention on Climate Change, December 11 2010, http://unfccc.int/files/meetings/cop_16/application/pdf/cop16_lca.pdf. Accessed on December 15, 2010.

http://unfccc.int/files/meetings/cop_16/application/pdf/cop16_lca.pdf,%20Accessed%20on%20December%2015,%202010

http://unfccc.int/files/meetings/cop_16/application/pdf/cop16_kp.pdf

http://unfccc.int/files/meetings/cop_16/application/pdf/cop16_lca.pdf


May 2011

that being said, however, it remains unlikely that the world will reach a new agreement on legally binding GHG emission targets next year.

The United States As the UNFCCC conference in Copenhagen came to a close in 2009, it was questionable whether or not the US Congress would be able to pass climate change legislation, and meet its stated GHG emission reduction pledge of 17 percent below 2005 levels by 2020. As expected, proposed energy and climate change bills, which included cap-‐and-‐trade programs, were not passed in 2010 as such legislation would have increased operating costs and impeded job creation while the US remained in a delicate economic situation. Furthermore, it is not expected that federal climate change legislation will be enacted during the 112th Congressional session, given the results of the November 2010 US mid-‐term elections. This will likely prevent the US from entering into a potential legally-‐binding international agreement at the 2011 UN Conference in Durban, South Africa.

On December 7, 2009, the EPA issued two findings which stated that the emissions of 6 GHG emissions (carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydro fluorocarbons (HFCs), per fluorocarbons (PFCs), and sulfur hexafluoride (SF6)), and the combination of the 6 GHG emissions from new motor vehicle and motor vehicle engines, endanger the health and welfare of current and future generations.7 With these findings, the EPA is obliged, under the Clean Air Act, to regulate the emissions of the 6 aforementioned GHGs, according to a 2007 US Supreme Court ruling.

As the EPA is attempting to show, through GHG standards, mandatory GHG reporting, and permitting rules, the regulation of GHG emissions need not result from federal legislation. In July 2011 and December 2011, the EPA is anticipated to propose new GHG emission standards for fossil fuel-‐fired power plants and oil refineries, respectively, and issue final emission standards in 2012.8

Circumventing the US Congress, however, may not be an easy task for the EPA, as the Republican controlled US House of Representatives could simply restrict the activities of the EPA through budgetary constraints. Additionally, members of the US Congress have called for a delay of the EPA regulations for two years,9 endangerment finding and proposed rules.10 A previous attempt to prevent the EPA from regulating GHG

7Environmental Protection Agency 40 CFR Chapter 1 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act; Final Rule, Federal Register, Vol. 74, No. 239, December 15, 2009, http://www.epa.gov/climatechange/endangerment/downloads/Federal_Register-‐EPA-‐HQ-‐OAR-‐2009-‐0171-‐Dec.15-‐09.pdf. Accessed on December 27, 2010. 8EPA to Set Modest Pace for Greenhouse Gas Standards/Agency stresses flexibility and public input in developing cost-‐effective and protective GHG standards for largest emitters, United States Environmental Protection Agency, December 23, 2010, http://yosemite.epa.gov/opa/admpress.nsf/d0cf6618525a9efb85257359003fb69d/ d2f038e9daed78de8525780200568bec!OpenDocument. Accessed on December 27, 2010. 9West Virginia Senator Jay Rockefeller, Press Release, December 17, 2010, http://rockefeller.senate.gov/press/ record.cfm?id=300339&. Accessed on December 27, 2010. 10Upton, Frank a2010, http://online.wsj.com/article/SB10001424052748703929404576022070069905318.html. Accessed on December 28, 2010.

http://www.epa.gov/climatechange/endangerment/downloads/Federal_Register-EPA-HQ-OAR-2009-0171-Dec.15-09.pdf

http://www.epa.gov/climatechange/endangerment/downloads/Federal_Register-EPA-HQ-OAR-2009-0171-Dec.15-09.pdf

http://yosemite.epa.gov/opa/admpress.nsf/d0cf6618525a9efb85257359003fb69d/%20d2f038e9daed78de8525780200568bec!OpenDocument



http://rockefeller.senate.gov/press/%20record.cfm?id=300339&



http://online.wsj.com/article/SB10001424052748703929404576022070069905318.html


May 2011

-‐47) in the U.S. Senate in June 2010.11

Although climate change legislation may be stalled at the federal level, efforts to reduce GHG emissions at the state and regional levels are moving full steam ahead. At the state level, GHG emission reduction targets have been established in 24 states,12 including California, where an economy wide cap-‐and-‐trade program was approved on December 16, 2010, to aid the state in reaching GHG emission reduction

32).13 -‐and-‐trade scheme will begin in 2012, and cover electricity (including imports), and large industrial facilities, and will be extended to cover distributors of transportation fuels, natural gas and other fuels in 2015.14 Figure 5.1 displays the states that have set GHG emission reduction targets.15

Figure 5.1 States with GHG Emission Reduction Targets

Source: Pew Center on Global Climate Change

With the exception of Hawaii and Florida, states with GHG emission reduction targets are also either participants or observers in regional climate change programs. There exist three regional programs, which include Canadian provinces and one territory, that have established, or intend to establish, GHG emission reduction targets, and supporting cap-‐and-‐trade schemes to enable participating states and provinces to meet those targets. Additionally, the three regional programs (Regional Greenhouse Gas Initiative, Midwestern Greenhouse Gas Reduction Accord, and Western Climate Initiative) have developed a forum, referred to as the Three-‐Regions process, to discuss regional cap-‐and-‐trade design and implementation 11 -‐US Senate defeats move to stop EPA CO2 regulation, Reuters, June 10, 2010, http://www.reuters.com/article/idUSN1012304420100610. Accessed on December 27, 2010. 12

http://www.pewclimate.org/sites/default/modules/usmap/pdf.php?file=5902. Accessed on December 21, 2010. 13Under AB 32, GHG emissions are to be reduced to 1990 levels by 2020. 14 Board, October, 27, 2010, http://www.arb.ca.gov/newsrel/2010/capandtrade.pdf. Accessed on December 21, 2010. 15Greenhouse Gas Emission Targets, Pew Center on Global Climate Change, June 24, 2010, http://www.pewclimate.org/what_s_being_done/in_the_states/emissionstargets_map.cfm. Accessed on December 21, 2010.

http://www.reuters.com/article/idUSN1012304420100610

http://www.pewclimate.org/sites/default/modules/usmap/pdf.php?file=5902

http://www.arb.ca.gov/newsrel/2010/capandtrade.pdf

http://www.pewclimate.org/what_s_being_done/in_the_states/emissionstargets_map.cfm


May 2011

issues, as well as the possibility of integrating the regional programs in the future.16 Figure 5.2 displays the states and provinces that are involved in existing or proposed cap-‐and-‐trade schemes.17

Figure 5.2 Regional Cap-‐and-‐Trade Schemes

Source: Pew Center on Global Climate Change

Regional Greenhouse GasInitiative The Regional Greenhouse Gas Initiative (RGGI) was the first mandatory cap-‐and-‐trade scheme implemented in the US to reduce GHG emissions from power plants. The 10 Northeast and Mid-‐Atlantic member states of the RGGI (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont) have committed to reduce GHG emissions by 10 percent below 2009 levels by the end of 2018.18 Observing states and provinces include New Brunswick, Ontario, Pennsylvania, and Quebec. Table 5.1 displays annual GHG emission limits for each of the participating states between 2009 and 2018.

16 -‐ -‐Regions Offset Working Group, May 2010, http://www.rggi.org/docs/3_Regions_Offsets_Announcement_05_17_10.pdf. Accessed on December 26, 2010. 17North American Cap-‐and-‐Trade Initiatives, Pew Center on Global Climate Change, June 24, 2010, http://www.pewclimate.org/what_s_being_done/in_the_states/NA-‐capandtrade. Accessed on December 21, 2010. 18

http://www.rggi.org/docs/RGGI_Fact_Sheet.pdf. Accessed on December 27, 2010.

http://www.rggi.org/docs/3_Regions_Offsets_Announcement_05_17_10.pdf

http://www.pewclimate.org/what_s_being_done/in_the_states/NA-capandtrade

http://www.rggi.org/docs/RGGI_Fact_Sheet.pdf


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Table 5.1 Annual GHG Emission Caps

Annual GHG Emissions Cap (Tons/Year)

2009-‐2014 2015 2016 2017 2018

Connecticut 10,695,036 10,427,660 10,160,284 9,892,908 9,625,532

Delaware 7,559,787 7,370,792 7,181,798 6,992,803 6,803,808

Maine 5,948,902 5,800,179 5,651,457 5,502,734 5,354,012

Maryland 37,504,000 36,566,400 35,628,800 34,691,200 33,753,600

Massachusetts 26,660,204 25,993,699 25,327,194 24,660,689 23,994,184

New Hampshire 8,620,460 8,404,949 8,189,437 7,973,926 7,758,414

New Jersey 22,892,730 22,320,412 21,748,094 21,175,775 20,603,457

New York 64,310,805 62,703,035 61,095,265 59,487,495 57,879,725

Rhode Island 2,659,239 2,592,758 2,526,277 2,459,796 2,393,315

Vermont 1,225,830 1,195,184 1,164,539 1,133,893 1,103,247 Individual states auction a majority of RGGI CO2 allowances, and invest the proceeds in programs that improve energy efficiency, increase renewable energy, and develop clean energy technologies. During the

ded the supply by 39.2 million allowances. Allowances sold at a market clearing price of US$3.07, generating a total of US$38.6 million.19 10thquarterly carbon credit auction generated US$48.2 million from the sale of 24.8 million CO2 allowances for the current three-‐year compliance period (2009-‐2011), and 1.2 million allowances for the following compliance period (2012-‐2014).20 All CO2 allowances were sold at the minimum reserve price of US$1.86 per allowance.21

In June 2010, RGGI member states, along with the state of Pennsylvania and the District of Columbia, established the Transportation and Climate Initiative, with the intent to develop regional low carbon fuel standards, in order to reduce GHG emissions from fuels used in the transportation sector.22

Midwestern Greenhouse Gas Reduction Accord Illinois, Iowa, Kansas, Manitoba, Michigan, Minnesota, and Wisconsin signed an agreement the Midwestern Greenhouse Gas Reduction Accord (MGGRA) in November 2007, to set GHG emission reduction targets in participating states and provinces. To meet these targets, a regional multi-‐sector cap-‐and-‐trade scheme is to be developed, along with various supporting climate change policies (e.g., energy efficiency, renewable electricity, advanced CCS, low carbon fuel standards), and a GHG registry to ensure compliance. Observing states and provinces include Indiana, Ohio, Ontario, and South Dakota.

19

http://www.rggi.org/docs/rggi_press_9_29_2008.pdf. Accessed on December 27, 2010. 20Pierce Emilee, 2010, http://www.rggi.org/docs/Auction_10_Release_Report.pdf. Accessed on December 27, 2010. 21

2010, http://www.rggi.org/docs/Auction_10_Release_Report.pdf, Accessed on December 27, 2010. 22Regional Low Carbon Fuel Standard Program, State of New Jersey, December 30, 2009, http://www.nj.gov/globalwarming/pdf/lcfs_factsheet.pdf. Accessed on December 26, 2009.

http://www.rggi.org/docs/rggi_press_9_29_2008.pdf

http://www.rggi.org/docs/Auction_10_Release_Report.pdf

http://www.rggi.org/docs/Auction_10_Release_Report.pdf

http://www.nj.gov/globalwarming/pdf/lcfs_factsheet.pdf


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In May 2010, the MGGRA Advisory Group, consisting of representatives from government, industry, academia, and environmental groups, released its final recommendations for introducing regional GHG

-‐and-‐trade scheme. GHG emission reduction targets of 20 percent below 2005 levels by 2020 and 80 percent below 2005 levels by 2050 have been recommended by the MGGRA Advisory Group.23 Sectors covered by the cap-‐and-‐trade scheme will include: electricity generators and importers; industrial combustion sources; industrial process sources; fuels serving residential, commercial, and industrial buildings, with some exceptions, and excluding Manitoba until the second compliance period; and transportation fuels, excluding Manitoba until the second compliance period.24 It was recommended that the cap-‐and-‐trade scheme begin at least twelve months after an implementation memorandum of understanding is signed by the seven participating members.25

Western Climate Initiative The Western Climate Initiative (WCI) is a collaboration between 7 US states (Arizona, California, Montana, New Mexico, Nevada, Utah, Washington), and 4 Canadian provinces (British Columbia, Manitoba, Ontario,

Cap-‐and-‐Trade Program and complimentary climate change policies in each of the participating jurisdictions. The multi-‐sector cap-‐and-‐trade scheme, which is set to commence in January 2012, will cover 90 percent of total GHG emissions in WCI member states and provinces by the time the program is fully implemented in 2015.26 Cumulative GHG emissions reductions, over the three compliance periods, have been estimated at 719 million metric tonnes of CO2e.

27 Carbon allowance prices were forecast by the WCI to reach US$33 per metric tonne of CO2e by 2020, under the

-‐and-‐trade scenarios produced 2020 carbon allowance prices ranging from a minimum of US$13 per metric tonne of CO2e to more than US$50 per metric tonne of CO2e.

28 As shown in Figure 5.3, 32 percent of total GHG emissions reductions are expected to result from GHG offsets, while the remaining 68 percent of reductions will be sourced from the covered sectors.29

23Advisory Group Final Recommendations, Midwestern Greenhouse Gas Reduction Accord, May 2010, http://midwesternaccord.org/Accord_Final_Recommendations.pdf. Accessed on December 26, 2010. 24 Ibid. 25 Ibid. 26The WCI Cap & Trade Program, The Western Climate Initiative, http://www.westernclimateinitiative.org/the-‐wci-‐cap-‐and-‐trade-‐program. Accessed on December 27, 2010. 27Updated Economic Analysis of the WCI Regional Cap-‐and-‐Trade Program, Western Climate Initiative, July 2010. 28 Ibid. 29 Ibid.

http://midwesternaccord.org/Accord_Final_Recommendations.pdf

http://www.westernclimateinitiative.org/the-wci-cap-and-trade-program

http://www.westernclimateinitiative.org/the-wci-cap-and-trade-program


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Figure 5.3 Sources of Emissions Reductions Under the Cap

Main Policy Case Relative to the Reference Case, 2012-‐2020

Source: WCI

Observing US states, Canadian provinces, and Mexican states in the WCI are Alaska, Baja California, Chihuahua, Coahuila, Colorado, Idaho, Kansas, Nevada, New Brunswick, Nova Scotia, Nuevo Leon, Saskatchewan, Sonora, Tamaulipas, Wyoming, and the Yukon Territory.

Tailings Management Water plays a crucial role in the development of the oil sands. Mining operations use approximately 4 barrels of fresh water per barrel of bitumen produced (about 2 to 3 barrels of which are sourced from the Athabasca River), and about 1/2 a barrel of fresh water per barrel of oil produced is required by in situ operations (none of which is sourced directly from the Athabasca River). Current oil sands fresh water use is approximately 171 million cubic meters (m3) per year.30

Tailings ponds are a part of operations common to various types of surface mining, including oil sands, coal, metals, diamonds and others. With oil sands mining, once the oil sands have been mined, it is separated from the sand and clay by mixing it with water. The oil is sent for further processing, and the leftover mixture of water, sand, clay, and residual oil (referred to as tailings) is transported for storage in large ponds often built in discontinued mine pits, where solids will settle and water will be recycled. Coarse solids settle rapidly, while the fine solids remain suspended in the pond.31 These fine solids, also known as mature fine tailings (MFT), represent a significant challenge to the reclamation of tailings ponds. As a result, mining operators have needed more, and larger, oil sands tailings ponds over the years.

30 31


May 2011

Existing tailings ponds cover an area of 170 square kilometers (km2)32 and can have a long life, remaining part of an active tailings management system for up to 30 or 40 years, either for tailings deposits, or for storage and water recycling. Given this long life cycle, no tailings ponds have yet been reclaimed.33

Presently, consolidated tailings (CT) technology is being used at existing oil sands operations to solidify fluid tailings.34 With the CT process, fluid fine tailings are mixed with coarse sand, and a chemical agent (e.g., gypsum), forming a non-‐segregating mixture in order to transform the fluid tailings into a solid deposit. Extensive research on tailings has been conducted, with the goal of developing technologies and approaches that reduce the volume of fine tailings generated, and increase the rate of solidification.

One such innovation is the Tailings Reduction Operation (TRO ) process, introduced by Suncor Energy, and approved in June 2010 by the ERCB.35 During the TRO process, MFT are mixed with a polymer flocculent before it is deposited, in thin layers, over sand beaches with shallow slopes. This drying process occurs over a matter of weeks, allowing reclamation to occur more rapidly. The resulting product is a dry material that can be reclaimed in place, or moved to another location for contouring, and replanting with native vegetation. The new process is expected to improve tailings management in the future, and can also be used to reduce existing tailings inventory. Figure 5.4 shows MFT that have been converted to a dry, solid surface after only 14 days.

Figure 5.4 MFT Surface after 14 Days

Source: Suncor Energy

32 ERCB, April 2010. 33Simieritsch,

December 2009. 34 Directive: Tailings Performance Criteria and Requirements for Oil Sands Mining

35 http://www.suncor.com/en/newsroom/2418.aspx?id=1278055, Accessed on December 27, 2010.

http://www.suncor.com/en/newsroom/2418.aspx?id=1278055


May 2011

Another example of an innovative tailings practice is being fine-‐tuned at Canadian Natural Resources project. CO2 is captured from the facility, and mixed with silts in the tailings, which

causes a reaction that forms a solid, and allows the silts to settle more quickly. This process reduces GHG emissions in two ways: the CO2 is permanently trapped in the silts, and most of the water can be recycled while it is still hot which reduces the energy required to reheat the water.

ERCB Directive 74 Reducing the volume and accelerating the solidification of fine tailings are essential to improving the pace of the tailings pond reclamation process. Achieving this objective is precisely the intent of the new Tailings Performance Criteria Directive 074, issued by the ERCB in February 2009.36

The Directive outlines performance criteria for the reduction of fluid tailings, and the formation of .37 These criteria are required to ensure that the ERCB can hold mineable oil sands

operators accountable for tailings management. Companies were required to submit a tailings management plan to the ERCB on September 30, 2009, indicating plans to meet the Drequirements.

The ERCB allows companies to phase-‐in the implementation of the proportion of fluid tailings that must be sent to Dedicated Disposal Areas (DDAs).38 The percentage of total fines in the tailings feed that must be reported to the DDAs is:

20 percent from July 1, 2010, to June 30, 2011 30 percent from July 1, 2011, to June 30, 2012 50 percent from July 1, 2012, to June 30, 2013, and annually thereafter.

These percentages are in addition to the fines that will be captured in coarse sand deposits, which are used to build dikes and beaches. Companies are to provide the ERCB with progress reports on a quarterly and annual basis.

Although the above criteria must be met by all oil sands mining operators, the ERCB recognizes that fluid tailings management is still in the development stages, and that operators may need flexibility to apply technologies and techniques that best suit the circumstances of particular projects. As such, the ERCB will consider submissions by operators, and determine project-‐specific requirements related to the Directive.39

36 2009. 37 t have been created through consolidation, drying, drainage and or capping must have a minimum shear strength. 38 technologies. The material deposited each year must achieve minimum undrained shear strength of 5 kPa

39 http://www.edmontonjournal.com/business/Shell+CNRL+miss+target+tailings+standards/3995941/story.html. Accessed on December 27, 2010.

http://www.edmontonjournal.com/business/Shell+CNRL+miss+target+tailings+standards/3995941/story.html


May 2011

Technology Options and Efficiency Improvements When the oil sands resource is considered in a global context, the myth that it is the dirtiest resource becomes blurred, as evidenced by a host of lifecycle analyses (LCAs) that have been performed. In 2010, Cambridge Energy Research Associates (CERA) provided an excellent summary analysis of approximately 13 LCA studies, which examined oil sands production methods, in addition to other oil extraction techniques and locations.40 The results further confirm that, while the oil sands extraction is energy intensive, it is by no means the most energy intensive. Furthermore, the vast majority of GHG emissions come from the end user.

While this information could allow the industry to become complacent, it is continuing to explore new extraction techniques which, if successful, could transform the oil sands industry from an emissions

hat generates lower GHG emissions per barrel of output, relative to current production methods.

Figure 5.5 Well-‐to-‐Wheels GHG Emissions for Oil Sands and Other Crudes

Source: IHS CERA

bitumen extraction technology options with improved energy efficiency and/or reduced GHG emissions. This section will provide a brief overview of some of these technology options, excluding SAGD and CSS, in addition to an update on the status of the technologies. Unfortunately, due to the proprietary nature of new technology research and development, there is insufficient data available to perform a detailed cost analysis on each technology.

40


May 2011

Nuclear Although the low natural gas prices environment has effectively muted the discussion on nuclear energy in the oil sands, it is still worth commenting on from a steam generation perspective. Nuclear energy can act as an excellent hedge against high natural gas prices, and GHG emissions compliance costs. However, it is a technology option that would require a long-‐term commitment from an oil sands operator. Such a commitment introduces substantial financial risks that may not be offset, given the current abundance of natural gas in North America. With the low price of natural gas, nuclear energy is not viewed as a viable option for the oil sands within the projection timeframe of this report.

Solvent Based Extraction Solvent based extraction has been widely tested, and is considered a viable alternative to traditional in situ extraction methods for reducing the viscosity of the bitumen.41 There are a wide variety of processes that utilize a mixture of different types of solvents and quantities of steam.

With the vapour extraction process (VAPEX), which relies upon the basic principle that the viscosity of bitumen can be reduced not only by heat, but by solvents as well,42 the solvents are selected by molecular weight (lower than bitumen), the reservoir temperature and pressure, the ability of the solvent to remain as a vapour during extraction, the ability of the solvent to partially upgrade the bitumen, the availability and cost of the solvent, the solubility of the solvent, and the solvents ability to generate high extraction rates.43 In other words, it is unlikreservoir specific.

A vapourized solvent is injected through an upper injection well to dissolve the oil sands, separating the bitumen from the sand, without the use of steam. The solvent-‐diluted bitumen drains, by gravity, to the lower production well, where it is then pumped to the surface.

The VAPEX process holds several potential advantages over traditional thermal processes: reduced capital cost by eliminating steam generating facilities (estimated to be 30 percent of capital costs);44 a complete or partial elimination of water recycling and disposal facilities; an ability to recover larger quantities of the original oil/bitumen in place (SAGD recovery factors are close to 45 percent, while the recovery factors with CSS at least 25 percent);45 and a substantial (if not complete) elimination of GHG emissions associated with the production (and partial upgrading) of the bitumen.

Conventional produced bitumen contains large quantities of asphaltenes, which can reach approximately 22 percent by weight.46 The VAPEX process has the ability to partially upgrade the bitumen in place by deasphalting the bitumen if the solvent is of a sufficiently low molecular weight. This results in partially

41 -‐International Petroleum Conference June 16-‐18, 2009, Petroleum Society of Canada, 2009, Paper No. 2009-‐115. 42

(SPE), Petroleum Recovery Institute, September 1998. 43Ibid. 44Ibid. 45Athabasca Oil Sands Corp. Preliminary Prospectus. Calgary: Athabasca Oil Sands Corp., 2010. 46

(SPE), Petroleum Recovery Institute, September 1998.


May 2011

upgraded bitumen with a higher value than non-‐upgraded bitumen, and could be of sufficient quality to meet pipeline specifications. Therefore, VAPEX could offer a regional benefit of reduced demand for diluents (such as condensate). The most notable drawback is that the deasphalting process leaves asphaltenes in the reservoir, which could plug the reservoir, and dramatically curtail production.

Electric Thermal Dynamic Stripping Process E-‐ -‐Thermal Dynamic Stripping Process (ET-‐DSPTM) is an in situ technology that uses electromagnetic energy to heat the bitumen, causing the viscosity to decrease. Electricity and water travel down the electrodes, which are inserted into vertical wells, in a grid-‐like pattern. The heated bitumen is then produced through vertical extraction wells, which follow the same configuration as the electrode wells. Figure 5.6 illustrates the ET-‐DSPTM well configuration.

Figure 5.6 -‐DSPTM Well Configuration

Source: E-‐T Energy Ltd.

E-‐T Energy is currently conducting a field test of the ET-‐DSPTMtechnology in the McMurray Formation of the Athabasca oil sands region, and has applied to expand the field test. In the initial field test, 25 wells (16 electrode wells and 9 extraction wells) were drilled 8 meters apart. The expanded field test, lasting between 1 to 2 years, will focus on optimal well spacing and reducing the ratio of extraction wells to electrode wells. Once approved, the E-‐T Energy will drill a total of 64 wells (46 electrode wells and 16


May 2011

be the Polar Creek ET-‐DSPTM Project, expected to commence operation sometime after 2011. This project has planned production volumes of 10,000 BPD, expanding in phases to 110,000 BPD beyond 2013.

As shown in Figure 5.7, the majority of the Athabasca oil sands resource is located at depths that are

accessed and produced using E-‐ -‐DSPTM technology. The potential implications on the total size of the oil sands resource could be staggering if this technology can unlock the vast potential in the Athabasca region that is currently not amenable to SAGD, CSS, mining, and likely solvent extraction.

Figure 5.7 ET-‐DSPTM Production Area

Source: E-‐T Energy Ltd.

A range of potential benefits exists with this new technology. Unlike other production methods, natural gas is not needed with the ET-‐DSPTM production process. Though the company expects a bitumen recovery rate of 75 percent, the thermal efficiency of the ET-‐DSPTM process could reduce GHG emissions compared to other extraction methods, but this is highly dependent upon the source of electricity.

The water requirements are minimal, as produced water is recycled, heated, and re-‐injected into the reservoir. E-‐T Energy has reported the reservoir energy oil ratio to be 62 kWh/bbl, equivalent to a steam oil ratio (SOR) of 0.56,47 which is 37 percent lower than the SOR from solvent extraction. The CO2e emissions, on a per barrel basis, are estimated to be 31.9 kg of CO2e/bbl of bitumen produced. However, if the majority of the electricity is generated with coal, the emissions from the project would be about twice as much.

47E-‐T Energy Ltd., http://www.e-‐tenergy.com/London January2009.pdf, Accessed on March 17, 2009.

http://www.e-tenergy.com/London%20January2009.pdf


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Toe-‐to-‐Heel Air Injection Petrobank Energy and Resources Ltd. has introduced a thermal in situ combustion technique, referred to as Toe-‐to-‐Heel Air Injection (THAITM), which combines a vertical injection well with a horizontal production well to recover the bitumen. The company is continuing to report successful THAI operations, and the possibility that higher reserve estimates could be provided, based upon higher THAI recovery rates, relative to conventional thermal in situ production methods. In November 2010, a month after receiving

Dawson project.48

During the Pre-‐Ignition Heating Cycle (PIHC) phase, 80 percent quality steam is injected into both the vertical injection well and the horizontal production well, in order to heat and mobilize the bitumen between the two wells.49 Once the PIHC phase is complete, air is injected into the vertical well, and a combustion front is created, with peak temperatures of more than 700 degrees Celsius.50 Ahead of the combustion front is the coke (fuel) zone, where the high temperature coke oxidization occurs. The hot combustion gases, coming into contact with the bitumen, result in thermal cracking and upgrading of the bitumen. With reduced viscosity, the bitumen is able to drain, by gravity, to the horizontal production well. The remaining coke functions as a fuel source for further combustion as the process moves through the reservoir. Figure 5.8 depicts the THAITM extraction process.

Figure 5.8 THAITM Extraction Process

Source: Petrobank Energy and Resources Ltd.

48News Release: Petrobank Receives Final Regulatory Approval for Dawson, Petrobank Energy and Resources Ltd., November 29, 2010. 49WHITESANDS Insitu Ltd., WHITESANDS Project Expansion Integrated EUB/AENV Application, December 2007, http://www.petrobank.com/webdocs/whitesands/WHITESANDS_Project_Expansion_Application.pdf, Accessed on March 10, 2009. 50

Combustion Operations at Whitesands THAITM Project. http://www.petrobank.com/webdocs/news_2006/ 2006_09_12_WHITESANDS_Update.pdf, Accessed on March 10, 2009.

http://www.petrobank.com/webdocs/whitesands/WHITESANDS_Project_Expansion_Application.pdf

http://www.petrobank.com/webdocs/news_2006/%202006_09_12_WHITESANDS_Update.pdf




May 2011

The combustion front sweeps the bitumen from the toe to the heel of the horizontal production well, efficiently recovering an estimated 70 to 80 percent of the bitumen in place, while partially upgrading the bitumen in situ. Other potential benefits of the THAITM production process include minimal natural gas and fresh water usage, partially upgraded oil quality, lower capital and operating costs, 50 percent less GHG emissions, reduced diluent requirements for transportation, and the ability to operate in lower pressure, lower quality, thinner, and deeper oil sands reservoirs than current steam-‐based production methods.51 Assuming a 50 percent reduction in emissions, THAITM would emit approximately 26.5 kg of CO2e/bbl, slightly more than emissions from solvent extraction. Given the lack of data available to provide a more detailed estimate, this should be viewed as illustrative in terms of its relative ranking in emissions reductions, versus solvent extraction and ET-‐DSPTM.

TM process applies a layer of catalysts to the horizontal production well in a second TM bitumen, which is already partially upgraded with the THAITM

technology to an API of 11.5 degrees,52 passes through the sleeve of catalysts (hydrodesulphurization catalysts), further cracking occurs, and the resulting oil that is produced is ready for transportation through standard oil pipelines, following water separation. The CAPRITM process was able to improve the API by 7 degrees, according to laboratory tests.53 Figure 5.9 TM liner.

Figure 5.9 CAPRI Liner

Source: Petrobank

One of the shortcomings of bitumen recovery with the THAITMprocess is the associated sand production. A buildup of sand at the bottom of the reservoir can have an adverse impact on the combustion front. This

51 he THAITM http://www.petrobank.com/hea-‐thaiprocess.html. Accessed on March 13, 2009. 52 TM/CAPRITM ProductionSeptember 22, 2008. http://www.petrobank.com/webdocs/ news_2008/PBG_2008_09_22.pdf. Accessed on March 13, 2009. 53Ibid.

http://www.petrobank.com/hea-thaiprocess.html

http://www.petrobank.com/webdocs/%20news_2008/PBG_2008_09_22.pdf


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TM/THAITM test well, the P-‐3B. The narrow slotted liner that was introduced significantly decreased the amount of produced sand. Any additional sand will be removed at the on-‐site processing facility, which also separates the water from the oil.

Oil Sands Merger and Acquisition Revival Although the US recession officially came to an end in June 2009, the ramifications of the global recession are still being felt, as countries such as Spain and Ireland are starting to come to grips with troubling balance sheets. Since the last edition of the oil sands update in 2009, CERI has stated that the resumption in oil sands activity was markeand that it would still take a couple of years for capital spending in the oil sands to return to pre-‐recession levels.

When 2010 came to a close, the level of activity in the oil sands began to pick up, as indicated by increased oil sands related capital spending announcements in 2011 capital budgets. While this increase in capital spending will produce positive economic benefits in Alberta, and across Canada, the focus of this section is on the level of merger and acquisition (M&A) activity (including joint ventures). After reaching a peak of $12.4 billion in 2006, M&A activity declined to a mere $2.0 billion in 2008.54 The merger of Royal Dutch Shell and Shell Canada is estimated to add an additional $5.5 billion to the 2007 oil sands M&A activity, pushing the 2007 total to $9.1 billion.55

As the recession took hold, M&A activity remained weak during the 2008 to 2009 trough, at an average of $2.4 billion, or just below 2005 levels.56 While the Suncor/Petro-‐Canada merger created a significant increase in the value of M&As in 2009, it was an outlier, and reflects the undervalued nature of Petro-‐Canada. Including the Suncor/Petro-‐Canada merger, M&A activity in 2009 is estimated at $12.1 billion.

Oil sands M&A activity surged in 2010 to $13.2 billion, as a result of over a dozen mergers and joint ventures announced, including the PTT Exploration and Production (Thailand) joint venture with Statoil,

l with Total, the of UTS Energy, and other sub $1 billion transactions.57 Additionally, the level of activity in 2010 has set new pricing points for oil sands resources, estimated at $1.37/bbl of recoverable reserves (Statoil deal),58 as companies seeking a position in the oil sands are willing to pay a premium to secure one of the most politically stable oil resources in the world. Although it is difficult to estimate the level of activity in 2011, it is expected that the oil sands may take center stage in North American non-‐shale gas related M&A activity.

54CanOils 55Peters, Terry, Asad Rawra, Canaccord Adams, Daily Letter, October 24, 2006. 56CanOils, CERI 57CanOils 58Ibid.


May 2011

Figure 5.10 Oil Sands Mergers and Acquisitions

$0

$2

$4

$6

$8

$10

$12

$14

$16

2005 2006 2007 2008 2009 2010

Total 2010 -‐ Q4 2010 -‐ Q3 2010 -‐ Q2 2010 -‐ Q1 Petro-‐CanadaOil Sands

Shell CanadaOil Sands

C$ Billions

Source: CanOils, CERI


May 2011

Chapter 6 Transportation The existing crude oil pipeline infrastructure underwent a much needed expansion recently, in order to accommodate the growing volumes of oil sands production. A number of pipeline expansions were completed in 2009, and 2 major additional pipelines became operational at the end of 2010. Furthermore, additional capacity to major traditional markets and the US Gulf Coast will be available once other scheduled pipeline projects are built and operating in the next few years. This chapter describes the existing major crude oil pipeline network, and proposed expansions on the major pipeline routes (export and domestic).

Current Transportation (Pipeline) Capacity Given the production projection under the Realistic Scenario, the current pipeline infrastructure in Alberta will not be sufficient to transport the forecasted oil sands volumes by 2024, and will need to be expanded. Capacity additions are needed to both transport blended or upgraded bitumen to refineries, and supply diluent/condensate necessary to operate the oil sands projects. Currently, as shown in Table 6.1, the capacity of regional oil pipelines that transport SCO and non-‐upgraded bitumen out of the Cold Lake and Athabasca regions is almost 3.0 MMBPD.1 The Cold Lake pipeline system delivers SCO and heavy oil from the Cold Lake region to Edmonton, Lloydminster and Hardisty with a capacity of 1.0 MMBPD. The capacity of the Fort McMurray pipeline system, which delivers crude oil from the Fort McMurray region to Hardisty and Edmonton, is greater than that of the Cold Lake system, at 1.9 MMBPD.

There are 5 major pipelines that are directly connected to the Canadian supply hubs, which are located in Edmonton and Hardisty, Alberta: Enbridge Mainline, Kinder Morgan Trans Mountain, Kinder Morgan Express, Enbridge Alberta Clipper and the TransCanada Keystone pipeline. The Alberta Clipper and Keystone pipelines commenced operations in 2010, adding 885,000 BPD of pipeline capacity out of western Canada, and bringing the total export capacity to 3.5 MMBPD of crude oil, as shown in Table 6.1. The bitumen production forecast, under the Realistic Scenario, suggests that excess pipeline capacity will exist until 2024.

1 -‐ -‐2010, June 2010.


May 2011

Table 6.1 Alberta Regional and Export Pipelines

Name Type Destination Capacity

(106bbl/d) Cold Lake Area pipelines

Cold Lake Pipeline Heavy Oil Hardisty 459.3 Edmonton

Husky Oil Pipeline Heavy Oil and SCO Hardisty 490.8 Lloydminster

Echo Pipeline Heavy Oil Hardisty 75.5

TOTAL 1,025.6 Fort McMurray Area pipelines

Athabasca Pipeline Semi-‐processed product & bitumen blends

Hardisty 390.1

Corridor Pipelines Diluted bitumen Edmonton 300.1

Syncrude Pipeline SCO Edmonton 388.8

Oil Sands Pipeline SCO Edmonton 144.7

Access Pipeline Diluted bitumen Edmonton 149.7

Waupisoo Pipeline Blended bitumen Edmonton 349.8

Horizon Pipeline SCO Edmonton 249.8

TOTAL 1,973.2 Export Pipelines

Enbridge Pipeline Crude oil Eastern Canada 1,868.0 U.S. East coast U.S. Midwest

Kinder Morgan (Express) Crude oil U.S. Rocky Mountains

280.0

U.S. Midwest Kinder Morgan (Trans Mountain) Crude oil & Refined

Products British Columbia 300.0 U.S. West Coast Offshore

Enbridge Alberta Clipper Heavy crude US Midwest 450.0 TransCanada Keystone Light/heavy crude US Midwest 435.0 Milk River Pipeline Light oil U.S. Rocky

Mountains 118.3

Rangeland Pipeline Cold Lake blend U.S. Rocky Mountains

84.9

TOTAL 3,536.2

Sources: (1) -‐ST98-‐2010, June 2010.


May 2011

Transportation Capacity Expansions Future plans include the expansion of diluent and feeder pipelines, as well as export pipelines, to carry crude oil to various markets. Diluent and feeder pipelines in Alberta are expanding to transport diluent to the region and growing bitumen volumes to the major hubs of Edmonton and Hardisty. These proposed pipelines are shown in Table 6.2.

By 2016, the additional export pipeline capacity could reach approximately 2.3 MMBPD of crude oil, on top of the current capacity of 3.5 MMBPD. The rate of expansion will greatly depend on market conditions and regulatory approvals. In the end, producers will support the pipeline projects that will provide the highest netbacks.

It is possible that pipeline companies may take on excess throughput risk in order to advance the development of individual projects, and to provide shippers with attractive terms, thus reducing the return on the project beyond an acceptable risk-‐adjusted level. Hence, not all of the proposed projects will be completed.

Table 6.2 Potential Pipeline Expansions

Pipeline Type

Capacity Increase (MBPD)

Estimated Completion

Date Market Proposed Alberta Pipeline Projects

Inter Pipeline Corridor Dilbit 165 2010-‐2011 Edmonton Enbridge Fort Hills Diluted bitumen 250 N/A Sturgeon

Diluent 70 Edmonton Total 485 Proposed Export Pipeline Projects

Kinder Morgan TMX2

Crude oil &RPPs 80 2015 US West coast/Offshore/Far East TMX3 320 2016

TMX Northern leg expansion Crude oil &RPPs 400 2015 British Columbia/US West coast/ Far East

Enbridge Gateway Crude oil 525 2015-‐2016 US West coast/Offshore/Far East

TCPL Keystone XL expansion 700 2012 US Midwest/US Gulf Coast

Altex Energy Crude oil 252 2013-‐2014 US Gulf Coast Total 2,277

Sources: -‐ -‐2010, June 2010.


May 2011

Figure 6.1 Alberta Existing and Proposed Regional Pipelines

s Energy Reserves 2009 and Supply/Demand Outlook 2010-‐ -‐2010, June 2010.

Figure 6.2 Existing and Proposed Export Pipelines

-‐ -‐2010, June 2010.


May 2011

Canadian crude oil supplies will continue to serve traditional markets in the US and Canada. The demand for Canadian crude oil the US Midwest market will grow, as heavy oil refining capacity in the region is added. However, growing volumes of Canadian bitumen supply means that new markets for these volumes must be found. The US Gulf Coast is one such market, and the TransCanada Keystone XL pipeline project, which is expected to be in service in 2012, will provide Canadian producers with increased access to this market. The growing demand for crude oil in Asia could potentially create a new market for Canadian crude oil. The Northern Gateway Project from Edmonton, Alberta to the deepwater port located in Kitimat, British Columbia is being designed to provide 525,000 BPD of crude oil export capacity. Crude oil would be loaded on tankers for delivery to the US West coast and Far East markets. Enbridge submitted an application to the National Energy Board at the end of May 2010.


May 2011


May 2011

Chapter 7 Conclusion

great economic potential, they also present environmental challenges in the areas of greenhouse gas (GHG) emissions, air pollution, water, tailings ponds and land. This may result in greater regulatory oversight, and an attempt to balance the economic benefits associated with oil sands development, and the environmental impacts. Of the environmental impacts, GHG emissions have received significant attention over the past few years, as projections of natural gas use rise with production estimates. Applying emissions compliance costs to oil sands projects can be viewed as one way to balance the environmental concerns and economic benefits associated with the oil sands development. Another environmental impact, which has received negative media attention, is the management of tailings ponds at mining operations. Environmental opposition to the oil sands could potentially create a barrier to investment, and interfere with its future development prospects, however, this is unlikely, as oil sands investments have been shown to be extremely profitable for oil sands operators, as well as the provincial and federal governments. Additionally, given the growing

robust.

CERI Realistic Scenario strikes a balance between the environment and oil sands development, through the inclusion of a modest emissions compliance cost. However, under the current method for calculating compliance costs, the costs have little impact on total supply costs since they are royalty deductible.

Natural gas costs, construction, and other operating costs are estimated to have a significant impact on oil sands developments. These costs, however, will be offset by higher oil prices which will ensure profitability for most oil sands ventures, and substantial royalty revenues for the Government of Alberta.

10 percent, with the exception of integrated mining and upgrading projects, and as high as 19 percent. The WTI equivalent price for SAGD projects is $123/bbl, $128/bbl for Integrated Mining and Upgrading projects, and $123/bbl for stand-‐alone Mining projects; SAGD projects receive the highest ROR. The plant gate supply costs, which exclude transportation and blending costs, are $93, $100, and $93/bbl for SAGD, Integrated Mining and Upgrading, and stand-‐alone Mining, respectively. While capital costs and the return on investment account for a substantial portion of the total supply cost, the province s per barrel take is estimated at 18 to 22 percent.

The favourable project economics are expected to continue well into the future, and help drive oil sands investment dollars by 2044. The investment will support the expansion of the oil sands, such that production volumes will reach 2.1 MMBPD by 2015, and 4.8 MMBPD by 2030. By the end of the projection period, raw bitumen production from the oil sands could exceed 5.0 MMBPD.

The environmental challenges to the oil sands have come into focus during the last 10 years. In that short time span, the industry has started to implement gradual changes towards lowering GHG emissions,


May 2011

water consumption and minimizing the tailings ponds. Uncertainty and time remain key characteristics of research and innovation. It is not known when and which of the technologies presently in the pilot stage will become commercial successes. Given time, a continued steady pace of investments in research and innovation, and sound government policy, it is reasonable to expect that the next 35 years will see the implementation of new oil sands technologies that will dramatically reduce the environmental impact while maintaining economic growth and the creation of high value employment in Alberta and Canada.

Canadian crude oil supplies will continue to serve traditional markets in the US and Canada. The demand for Canadian crude oil in the US Midwest market will grow, as heavy oil refining capacity in the region is added. However, growing volumes of Canadian bitumen supply means that new markets for these volumes must be found. The US Gulf Coast is one such market, and the TransCanada Keystone XL pipeline project, which is expected to be in service in 2012, will provide Canadian producers with increased access to this market.

The growing demand for crude oil in Asia could potentially create a new market for Canadian crude oil. The Northern Gateway Project from Edmonton, Alberta to the deepwater port located in Kitimat, British Columbia is being designed to provide 525,000 BPD of crude oil export capacity. Crude oil would be loaded on tankers for delivery to the US West coast and Far East markets.

Canadian Energy Research Institute oilsands report - 2011

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