part i - impacts of oil sands production - final july 2012

CANADIAN ENERGY RESEARCH INSTITUTE

PACIFIC ACCESS: PART I – LINKING OIL SANDS SUPPLY TO NEW

AND EXISTING MARKETS

Study No. 129 – Part I July 2012

Canadian Energy Research Institute | Relevant • Independent • Objective

PACIFIC ACCESS:

PART I – LINKING OIL SANDS SUPPLY TO NEW AND EXISTING MARKETS

Pacific Access: Part I – Linking Oil Sands Supply to New and Existing Markets

Copyright © Canadian Energy Research Institute, 2012 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute ISBN 1-927037-06-5 Authors: Dinara Millington Jon Rozhon

Acknowledgements:

The authors wish to acknowledge Dr. Afshin Honarvar of the Alberta Energy Resources Conservation Board for his economic modeling that forms the basis for the analysis of Oil Sands economic impacts, as well as those involved in the production, reviewing, and editing of the material, including but not limited to Peter Howard and Megan Murphy

CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca July 2012 Printed in Canada

Front Cover Photo Courtesy of the National Energy Board, 2012

http://www.ceri.ca/

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Table of Contents List of Figures .................................................................................................................. v

List of Tables ................................................................................................................... vii

Executive Summary ......................................................................................................... ix

CHAPTER 1 INTRODUCTION ......................................................................................... 1

Background ......................................................................................................................... 1 Report Methodology and Approach ................................................................................... 2

CHAPTER 2 OIL PIPELINE TRANSPORTATION ................................................................ 5

Regional Pipeline Capacity .................................................................................................. 5 Western Canadian Export Pipeline Capacity ...................................................................... 8

CHAPTER 3 WESTERN CANADIAN OIL SUPPLIES AND PIPELINE CAPACITY ..................... 11

Conventional Oil Supply ...................................................................................................... 13 Oil Sands Supply and Costs ................................................................................................. 13 Pipeline Capacities .............................................................................................................. 16

CHAPTER 4 ECONOMIC IMPACTS OF OIL SANDS DEVELOPMENT .................................. 19

Comparing the Results ........................................................................................................ 20 Existing Pipelines Operations Case ..................................................................................... 21 Keystone XL Case ................................................................................................................ 28 Trans Mountain Expansion Case ......................................................................................... 34 Northern Gateway Case ...................................................................................................... 40

CHAPTER 5 CONCLUSION ............................................................................................. 47

APPENDIX A US RESULTS ............................................................................................... 53

APPENDIX B CERI PROVINCIAL INPUT-OUTPUT MODEL .................................................. 61

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Pacific Access: Part I – Linking Oil Sands to v New and Existing Markets

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List of Figures 1 Incremental GDP Impacts by Case (2011-2035) ........................................................... xii 2 Incremental Employment Impacts by Case (2011-2035) ............................................. xii 3 Incremental Tax Revenue Impacts by Case (2011-2035).............................................. xiii 4 Oil Sands Royalties by Case (2011-2035) ...................................................................... xiv 2.1 Regional Existing and Proposed Pipeline ...................................................................... 5 3.1 Western Canadian Export Pipelines and Oil Supply ..................................................... 12 3.2 Bitumen Production by Method of Extraction – CERI Reference Case Scenario .......... 14 3.3 Total Capital and Operating Costs – CERI Reference Case Scenario ............................ 16 4.1 Capital Investment – Existing Pipelines Operations Case ............................................. 21 4.2 GDP Increase (2011-2035), Existing Pipelines Operations Case ................................... 22 4.3 GDP Impacts in Canada (excluding Alberta), Existing Pipelines Operations Case ........ 23 4.4 Employee Compensation (excluding Alberta), Existing Pipelines Operations Case ..... 24 4.5 Average Wages (2011-2035), Existing Pipelines Operations Case ............................... 24 4.6 Jobs Created and Preserved in Canada (2011-2035) Existing Pipelines Operations Case ............................................................................... 25 4.7 Total Oil Sands-related Taxes (excluding Alberta) Existing Pipelines Operations Case ............................................................................... 26 4.8 Alberta and Rest of Canada Total Taxes Paid (2011-2035) Existing Pipelines Operations Case ............................................................................... 27 4.9 Alberta Oil Sands Royalties (2011-2035), Existing Pipelines Operations Case ............. 28 4.10 Cumulative Capital Investment – Keystone XL Case (Includes Existing Pipelines Operations Case) .............................................................. 29 4.11 GDP Increase (2011-2035), Keystone XL Case .............................................................. 30 4.12 GDP Impacts in Canada (excluding Alberta), Keystone XL Case ................................... 30 4.13 Employee Compensation (excluding Alberta), Keystone XL Case ................................ 31 4.14 Cumulative Jobs Created and Preserved in Canada (2011-2035) Keystone XL Case .......................................................................................................... 32 4.15 Total Oil Sands-related Taxes (excluding Alberta), Keystone XL Case .......................... 32 4.16 Alberta and Rest of Canada Total Taxes Paid (2011-2035), Keystone XL Case ............ 33 4.17 Alberta Oil Sands Royalties (2011-2035), Keystone XL Case ........................................ 33 4.18 Cumulative Capital Investment, Trans Mountain Expansion Case (Includes Existing Pipelines Operations Case and KXL Case) ........................................ 35 4.19 GDP Increase (2011-2035), Trans Mountain Expansion Case ...................................... 35 4.20 GDP Impacts in Canada (excluding Alberta), Trans Mountain Expansion Case............ 36 4.21 Employee Compensation (excluding Alberta), Trans Mountain Expansion Case ......... 37 4.22 Cumulative Jobs Created and Preserved in Canada (2011-2035) Trans Mountain Expansion Case ................................................................................... 37 4.23 Total Oil Sands-related Taxes (excluding Alberta) Trans Mountain Expansion Case ................................................................................... 38 4.24 Alberta and Rest of Canada Total Taxes Paid (2011-2035) Trans Mountain Expansion Case ................................................................................... 39

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4.25 Alberta Oil Sands Royalties (2011-2035), Trans Mountain Expansion Case ................. 40 4.26 Cumulative Capital Investment, Northern Gateway Case (Includes Existing Pipelines Operations Case, KXL Case and TMX Case) ...................... 41 4.27 GDP Increase (2011-2035), Northern Gateway Case ................................................... 42 4.28 GDP Impacts in Canada (excluding Alberta), Northern Gateway Case ........................ 43 4.29 Cumulative Jobs Created and Preserved in Canada (2011-2035) Northern Gateway Case ................................................................................................ 44 4.30 Employee Compensation (excluding Alberta), Northern Gateway Case ...................... 44 4.31 Total Oil Sands-related Taxes (excluding Alberta), Northern Gateway Case ............... 45 4.32 Alberta and Rest of Canada Total Taxes Paid (2011-2035) Northern Gateway Case ................................................................................................ 46 4.33 Alberta Oil Sands Royalties (2011-2035), Northern Gateway Case .............................. 46 5.1 Incremental GDP Impacts by Case (2011-2035) ........................................................... 49 5.2 Incremental Employment Impacts by Case (2011-2035) ............................................. 49 5.3 Incremental Tax Revenue Impacts by Case (2011-2035).............................................. 50 5.4 Oil Sands Royalties by Case (2011-2035) ...................................................................... 51 A.1 Jobs Created and Preserved in the US, Existing Pipelines Operations Case ................. 53 A.2 Cumulative Jobs Created and Preserved in the US, KXL Case ...................................... 55 A.3 Cumulative Jobs Created and Preserved in the US, TMX Case ..................................... 57 A.4 Cumulative Jobs Created and Preserved in the US, Northern Gateway Case .............. 59 B.1 Overall Bi-National Multi-Regional I/O Modeling Approach ........................................ 64 B.2 Schematic of the Input-Output System ........................................................................ 77

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List of Tables 2.1 Existing and Potential Regional Pipeline Capacities .......................................................... 7 2.2 Existing Export Pipeline Capacity ...................................................................................... 8 5.1 Cumulative Economic Impacts by Case (2011-2035) ........................................................ 48 A.1 Total Economic Impacts by US PADD Region, Existing Pipelines Operations Case ........... 53 A.2 Total Economic Impacts by US State, Existing Pipelines Operations Case ........................ 54 A.3 Total Economic Impacts by US PADD Region, KXL Case .................................................... 55 A.4 Total Economic Impacts by US State, KXL Case ................................................................. 56 A.5 Total Economic Impacts by US PADD Region, TMX Case .................................................. 57 A.6 Total Economic Impacts by US State, TMX Case ............................................................... 58 A.7 Total Economic Impacts by US PADD Region, Northern Gateway Case ........................... 59 A.8 Total Economic Impacts by US State, Northern Gateway Case ........................................ 60 B.1 Sectors/Commodities in CERI US-Canada Multi-Regional I/O Model ............................... 68

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Pacific Access: Part I – Linking Oil Sands to ix New and Existing Markets

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Executive Summary

The production from conventional oil sources in Western Canada is growing as technology is able to unlock resources that were once thought to be difficult to extract. Nevertheless, oil sands will continue to dominate the future production growth in this region. The 25-year forecast1 suggests that total production could surpass 6 MMbpd by 2035 out of Western Canada, which begs the question of how this oil is going to be transported and where it will be destined for. Canadian crude oil supplies will continue to serve traditional markets in the US and Canada. The demand for Canadian crude oil to the US Midwest market still has some room to grow, as heavy oil refining capacity in the region is added. However, increasing volumes of Canadian bitumen supply means that new markets must be found.

At present, the crude pipeline capacity out of Western Canada is sufficient to transport production coming from on stream and under construction oil sands projects. Additional crude export capacity from Western Canada will be essential by as early as 2015. Significant pipeline investments will have to be considered. There are many considerations in making such decisions. The choice whether to ship bitumen or synthetic crude – the value of upgrading at the source in Alberta versus other locations has to be analyzed. Environmental issues concerning greenhouse gas emissions, tailings ponds, water consumption, land disturbance and reclamation will play an important role in the pace and scale of the oil sands project development. Differentials and how they are expected to change with access to new markets are important.2 Existing and potential crude competition can come into play, from such areas as Venezuela, Mexico and the deepwater Gulf of Mexico. Politics and the desire for supply security

and international dependence will play a role in decisions. Existing pipelines and routes, refinery configurations and any re-configurations, and demands in regions also must be considered.

All these elements will have an impact on oil sands growth, and in turn will affect the economic benefits that can be realized. This report presents the economic impacts of oil sands development, broken down into four separate cases, which represent the pipeline capacities of existing infrastructure, as well as capacities of pipelines that are not yet operating. The report showed significant economic benefits of oil sands development for Canadian and provincial economies.

Four such development cases are presented in this report:

Case 1 – Existing Pipelines Operations. This case examines the economic impacts of existing and under construction oil sands projects. It assumes no new pipeline capacity and serves as a baseline scenario.

1 The forecast period is 2011-2035, inclusive.

2 M.C. Moore, S. Flaim, D. Hackett, S. Grissom. D. Crisan, A. Honarvar. December 2011. “Catching the Brass Ring” Oil Market

Diversification Potential for Canada”. School of Public Policy, University of Calgary. Vol. 4, Issue 16.

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Case 2 – Keystone XL.* This case considers the economic impacts of Case 1 oil sands

projects in addition to production that will come on stream from projects that would benefit from KXL operations.

Case 3 – TMX Expansion.* This case considers the economic impacts of Case 2 oil sands projects in addition to production that will come on stream from projects that would benefit from increased capacity on the TMX system.

Case 4 – Northern Gateway.* This case considers the economic impacts of Case 3 oil sands projects in addition to production that will come on stream from projects that would benefit from Northern Gateway operations.

*This report assumes that these three new additions to the existing export pipeline capacity will eventually happen. It is not in the scope of this project to debate whether this actually becomes

a reality or not.

Table 1 presents the economic impacts on GDP, Employment, Compensation and Taxes paid for Canada and the top three beneficiaries of oil sands development: Alberta, Ontario and British Columbia. Given that all oil sands development takes place in Alberta, it is clear that Alberta will be the largest beneficiary. For example, of the $1.5 trillion GDP growth in Canada under the Existing Pipelines Case, 95% growth or $1.4 trillion is accounted for in Alberta from 2011 to 2035. Ontario will receive 3 percent of the total, or $44.3 billion, followed by British Columbia at 1.2 percent ($19.4 billion). Alberta will also have the highest shares of employee compensation benefits as well as paid tax revenues to the provincial and federal governments. All direct employment will be occurring in the province where oil sands are developed, with a larger spin-off effect in indirect and induced job categories happening outside of Alberta.

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Table 1: Cumulative Economic Impacts by Case (2011-2035)

GDP Employment Compensation Taxes Paid

(Billion 2010 CDN$)

(Thousand person-years)

(Billion 2010 CDN$)

(Billion 2010 CDN$)

Canada Existing Pipelines Case 1,520.8 8,349 444.1 323.4 Keystone XL Case 2,138.2 11,846 628.7 454.8 TMX Expansion Case 2,446.1 13,551 719.2 520.2 Northern Gateway Case 2,819.6 15,701 832.2 599.7 Alberta Existing Pipelines Case 1,439.9 7,209 398.9 297.9 Keystone XL Case 2,023.1 10,225 564.3 418.5 TMX Expansion Case 2,314.4 11,696 645.5 478.7 Northern Gateway Case 2,666.7 13,549 746.8 551.6 Ontario Existing Pipelines Case 44.3 602 25.4 14.6 Keystone XL Case 62.9 854 36.1 20.7 TMX Expansion Case 71.9 977 41.3 23.6 Northern Gateway Case 83.3 1,132 47.9 27.4 British Columbia Existing Pipelines Case 19.4 290 10.8 5.2 Keystone XL Case 27.7 413 15.4 7.4 TMX Expansion Case 31.7 472 17.6 8.4 Northern Gateway Case 36.8 548 20.4 9.8

Figures 1 to 3 show how economic impacts vary by case and by region. Figure 1 represents GDP growth for all four cases. The results indicate that the TMX case has the lowest economic impact on GDP for Canada and the three provinces. This could be explained by the fact that out of three proposed pipeline projects, TMX has the lowest capacity addition to the total export capacity, and hence the bitumen production volumes that will be transported via TMX are the lowest among the four cases, which translates into lower GDP additions. In all four cases Alberta takes the largest share of total GDP growth.

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Figure 1: Incremental GDP Impacts by Case (2011-2035)

Figure 2 shows employment results, measured in thousand person-years, by case and by region. Again, the same pattern occurs. Ignoring the Existing Pipelines Case, the second largest benefits in employment are received under the Keystone XL Case, followed by the Northern Gateway Case. The additional employment impacts under the TMX Case are the lowest among the four cases.

Figure 2: Incremental Employment Impacts by Case (2011-2035)

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Existing Pipelines 1,520.8 1,439.9 44.3 19.4

KXL 617.4 583.2 18.6 8.3

TMX 307.9 291.3 9.0 4.0

Gateway 373.5 352.3 11.4 5.1

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Gateway 2,150 1,853 155 76

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KXL

TMX

Gateway

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Figure 3 illustrates tax revenues paid by citizens and businesses of Canada, Alberta, Ontario and British Columbia. Again, Alberta’s residents and businesses pay the most taxes out of all the provinces and territories. Ignoring the Existing Pipelines Case, the second largest tax revenues are received from the Keystone XL Case, followed by the Northern Gateway Case. The additional taxes collected under the TMX Case are the lowest among the four cases.

Figure 3: Incremental Tax Revenue Impacts by Case (2011-2035)

Royalties from oil sands production are shown in Figure 4. Excluding the Existing Pipeline Operations Case, monies collected by Alberta’s government are the second highest under the Keystone XL Case, followed by Northern Gateway Case, and then TMX Case. On an annual basis, total royalty revenues from all cases will increase significantly from $3.4 billion in 2010 to just over $35 billion in 2035. Cumulatively, over the 25-year period there will be $585.7 billion collected in a form of oil sands royalties.

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Figure 4: Oil Sands Royalties by Case (2011-2035)

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Chapter 1 Introduction

Background Canadian bitumen has, from first commercialization, grown to become a major energy source, and the oil sands industry, an economic “engine”, that commands global attention. The vitality and vibrancy of the industry are testimony to the visionary thinking of early pioneers and application of the sharpest business and technical minds to make it a success story. The industry is poised for further significant growth with a flood of new projects that emerged in the last year. And yet, questions have been raised regarding the sustainability of the industry

and economic viability of many of the proposed projects, faced by an onslaught of factors that seemingly align themselves to put a damper on the projects’ attractiveness.

With expected significant growth in synthetic crude oil (SCO) and bitumen production, the need for expansion in existing oil pipeline capacity comes to the forefront of challenges that the oil sands industry is facing today. It is also important to mention how some excess capacity is crucial to be able to manage pipeline maintenance times and to provide flexibility for new market development. Not to mention that constraints in pipeline capacity and the lack of access to new demand centers have a severe impact on the netbacks realized by Canadian producers. With the recent failure of the Keystone XL (KXL) pipeline to the US Gulf Coast obtaining approval,1 Northern Gateway’s public hearings proceeding for the foreseeable future, Kinder Morgan’s Trans Mountain Expansion (TMX) facing opposition in Vancouver, and rail

emerging as an alternative to move bitumen to markets, the next couple of years promise to be years of transformation for shippers, operators and producers.

Historically, pipelines have served the purpose of shipping crude oil, natural gas, and natural gas liquids to destinations throughout the continent. But lately crude oil pipelines have been in the news, with recent spills in areas such as Alaska’s North Slope,2 northern Alberta,3 and southern Michigan4 raising public concern over hydrocarbon transport in general and pipeline transport specifically. In early 2012, the Obama Administration rejected the Keystone XL Pipeline project on the premise that it might pollute the Ogallala Aquifer if a spill occurs. However, a popular belief is that the pipeline will be approved in 2013 once the US State

1In May 2012, TransCanada re-applied for a US permit with a 32-kilometre detour from the original route to avoid the

environmentally fragile Sandhills region and the vast Ogallala Aquifer that underlies the area, which the state government of Nebraska wants to protect. 2“Third North Slope oil spill in a week”. Alaska Dispatch. July 2011. http://www.alaskadispatch.com/article/third-north-slope-

oil-spill-week. Accessed on May 25, 2012. 3Nathan Vanderklippe. “Costs for oil companies pile up after spill”. The Globe and Mail. May 2011.

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/alberta-school-closed-after-oil-spill-sparks-health-complaints/article2009886/. Accessed on May 25, 2012. 4Jaclyn Gallucci. “Michigan Oil Spill Update: Oil in Kalamazoo River”. Long Island Press. July 2010.

http://www.longislandpress.com/2010/07/28/michigan-oil-spill-update-july-28-oil-flows-in-kalamazoo-river/. Accessed on May 25, 2012.

http://www.alaskadispatch.com/article/third-north-slope-oil-spill-week

http://www.alaskadispatch.com/article/third-north-slope-oil-spill-week

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/alberta-school-closed-after-oil-spill-sparks-health-complaints/article2009886/

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/alberta-school-closed-after-oil-spill-sparks-health-complaints/article2009886/

http://www.longislandpress.com/2010/07/28/michigan-oil-spill-update-july-28-oil-flows-in-kalamazoo-river/

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Department is satisfied with a new proposed route, and full consideration is given to

environmental impacts of construction and operation of KXL. All of this controversy has led to debate among industry and governments on alternative means and destinations to move Western Canadian hydrocarbons to market.

Against this backdrop, on January 10, 2012, the Joint Review Panel (JRP) for the Enbridge Northern Gateway Pipeline Project began a series of hearings to be held in affected communities along the pipeline route. This project, if built, would be the first crude pipeline link between the Edmonton region and British Columbia’s (BC) port of Kitimat. It is designed to be a twin pipeline system with an eastbound line to transport condensate to Alberta, which will be used for blending purposes. The westbound line will carry the dilbit blend5 to Kitimat where it can be transferred to tankers and shipped to markets throughout the Pacific Rim. Over 4,000

people have applied to testify at the various JRP community hearings, indicating that, like the KXL pipeline, there are significant concerns about Northern Gateway. It is by no means certain that the project will go ahead as planned. If the project does proceed, it may well signal a revival of the Canadian petroleum industry, linking Canadian oil supplies with new markets outside of North America. If the project does not proceed, there will be no certainties concerning future oil sands projects or attendant crude transportation infrastructure.

In addition to KXL and Northern Gateway, Kinder Morgan has proposed an expansion to its existing TMX pipeline, which has been shipping hydrocarbons to the west coast since the 1950s. The TMX expansion is the second multi-billion dollar proposal aimed at opening up new markets in Asia for Canadian oil producers, which are currently selling their crude to US customers at heavy discounts. Both Northern Gateway and the TMX expansion are facing

opposition from environmental groups and native communities in BC. Vancouver city council is also against the Kinder expansion, which would increase tanker traffic in the city’s harbour.

CN, as well, is looking to develop its “Pipeline by Rail” service. The BC coast is in closer proximity than the US Gulf Coast to western Canadian resources, and transportation routes to BC would not cross the international border (therefore they would not be subject to US regulation or law), so it is logical to consider BC routes. Moreover, much infrastructure is already in place – there are extensive rail lines that exist today that could transport not only bitumen, but other hydrocarbons such as LNG and intermediate petrochemicals.

Report Methodology and Approach Given the array of proposed transportation options, this study examines the impacts of existing

and future oil sands development limited by pipeline export capacity. The study consists of two sections. In the first section, we examine upstream oil sands activity over the next twenty five years, and how new and existing pipelines could potentially align with the production forecast. Ramping up of activity in the oil sands and possible implementation of new technologies may 5Per the Alberta Oil Sands Bitumen Valuation Methodology, "Dilbit Blends" means Blends made from heavy crudes and/or

bitumen and a diluent, usually condensate, for the purpose of meeting pipeline viscosity and density specifications, where the density of the diluent included in the blend is less than 800 kg/m3. If the diluent density is greater than or equal to 800 kg/m3, the diluent is typically synthetic crude and accordingly the blend is called synbit.


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lead to capital cost overruns, labour shortages, and materials scarcity – in short, increased

supply costs.6 These challenges, in conjunction with potential increases in conventional oil supplies out of western Canada, may affect available capacity on the various export pipelines.

The second section is an economic Input-Output (I/O) analysis of the various stages of oil sands development according to pipeline development. CERI utilizes its proprietary Input-Output model to compare impacts by province in Canada and by PADD and state level in the US.7 The economic impacts on major macroeconomic variables are presented. These include GDP, employment, compensation, tax revenues and royalties.8

Four such development cases are presented in this report:

Case 1 – Existing Pipelines Operations. This case examines the economic impacts of

existing and under construction oil sands projects. It assumes no new pipeline capacity and serves as a baseline scenario.

Case 2 – Keystone XL.* This case considers the economic impacts of Case 1 oil sands projects in addition to production that will come on stream from projects that would benefit from KXL operations.

Case 3 – TMX Expansion.* This case considers the economic impacts of Case 2 oil sands projects in addition to production that will come on stream from projects that would benefit from increased capacity on the TMX system.

Case 4 – Northern Gateway.* This case considers the economic impacts of Case 3 oil sands projects in addition to production that will come on stream from projects that would benefit from Northern Gateway operations.

*This report assumes that these three new additions to the existing export pipeline capacity will eventually happen. It is not in the scope of this project to debate whether this actually becomes a reality or not.

The study is organized as follows:

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

Chapter 2 discusses existing and proposed pipeline infrastructure within Alberta and beyond.

Chapter 3 presents the production forecast for oil sands as well as conventional crude

oil, which is discussed in the context of pipeline capacity availability. Chapter 4 highlights the economic impacts of upstream oil sands production that will be

linked to new and existing markets by means of increased pipeline capacity. Chapter 5 draws key conclusions from the study.

6These upstream oil sands supply issues are discussed in detail in CERI Study 128, “Canadian Oil Sands Supply Costs and

Development Projects (2011-2045)”, March 2012. This report can be downloaded from www.ceri.ca 7 I/O results for the US are presented in Appendix A.

8CERI’s I/O model methodology and assumptions can be found in Appendix B.


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Appendices A and B include the I/O results for the US as well as detailed information

about CERI’s provincial I/O model.


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Chapter 2 Oil Pipeline Transportation

Prior to looking at the forecast of oil and oil sands production, it is important to discuss whether the current pipeline infrastructure is able to handle current production volumes coming from these projects. This chapter is broken down into two parts. The first part describes the current and proposed regional pipeline infrastructure development in Alberta as it pertains to oil sands projects. Secondly, existing and proposed export pipeline capacity out of Western Canada is discussed in the context of future oil and oil sands production.

Regional Pipeline Capacity Several existing pipelines within Alberta’s regional oil sands pipeline network bring diluted crude bitumen and SCO from producing regions. The product then moves to pipeline terminals in Alberta (Edmonton and Hardisty) or to local upgraders and refineries (see Figure 2.1). Owners/operators are pursuing expansion on many of these systems.

Figure 2.1: Regional Existing and Proposed Pipelines

SOURCE: ERCB, “Alberta's Energy Reserves 2010 and Supply/Demand Outlook 2011-2020”, ST98-2011, June 2011.


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As shown in Table 2.1, the current capacity of regional oil pipelines that transport SCO and non-

upgraded bitumen out of the Cold Lake and Athabasca regions is almost 3.2 million barrels per day (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 (247,000 barrels per day (bpd) to Edmonton and 787,000 bpd to Hardisty). The capacity of the Athabasca 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 2.1 MMbpd (1.7 MMbpd to Edmonton, 0.4 MMbpd to Hardisty). There is currently one pipeline out of the Peace River region, with a capacity of 0.2 MMbpd that delivers crude from Peace River as well as crude from Zama, Alberta – the connection point for crude coming from the Northwest Territories to Edmonton.

The Cold Lake West/South system, owned and operated by Inter Pipeline Fund, moves bitumen blend from the Cold Lake area to both Edmonton and Hardisty. The Cold Lake West pipeline to Edmonton has a capacity of 247,000 bpd, while the Cold Lake South option to Hardisty can move 221,000 bpd. Peace River has one pipeline transporting blended bitumen to Edmonton, with a total capacity of 200,000 bpd. Existing infrastructure will meet production needs beyond 2030 for all regions except Athabasca. For the Athabasca region, based on CERI’s Reference Case Scenario from the 2012 Oil Sands Update,2 bitumen production is expected to increase substantially, to almost four times current levels. Production from the region is expected to exceed existing pipeline capacity by 2015. Investment before 2015 is required in the regional pipeline infrastructure to meet increased production projections.

Future plans include expansion of diluent and feeder pipelines to transport condensate into the

region and growing bitumen volumes outward to the major hubs of Edmonton and Hardisty. These proposed pipelines are shown in Table 2.1.

A number of projects are proposed or under construction already. In response to increased production, and at the request of the shippers, the Corridor pipeline underwent an expansion in 2011, adding 165,000 bpd to the original 300,000 bpd. Other major pipeline projects in the Athabasca region include twinning of Enbridge’s Athabasca pipeline with a proposed initial capacity of 450,000 bpd and capacity expansion to 800,000 bpd. A new line is expected to start in 2015 with full initial capacity available by 2016. Enbridge will also be expanding the existing Athabasca line from 390,000 bpd to 570,000 bpd by the fall of 2013, and its Waupisoo line from 350,000 to 600,000 bpd by 2013. A pipeline solely dedicated to transport diluent to the Athabasca region is planned to be in service by late 2012, with firm shipping commitments of

90,000 bpd and with minimum planned capacity of 120,000 bpd. This Polaris diluent line will be operated by Inter Pipeline Fund and will service Imperial’s Kearl and Husky’s Sunrise oil sands projects.

1ERCB, “Alberta's Energy Reserves 2010 and Supply/Demand Outlook 2011-2020”, ST98-2011, June 2011.

2CERI Study 128, “Canadian Oil Sands Supply Costs and Development Projects (2011-2045)”. March 2012. Download the report

at www.ceri.ca


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Table 2.1: Existing and Potential Regional Pipeline Capacities

Source: ERCB, CAPP, various news releases.

In the Cold Lake region, continued efforts are being made to expand the existing Cold Lake pipeline system, which provides transportation for its founding shippers: Cenovus, Canadian Natural Resources Limited (CNRL), Imperial Oil, and Shell. According to Inter Pipeline Fund, the

ultimate capacity of the system could reach 700,000 bpd.

Several pipeline projects are planned for the Peace River area. Plains Midstream Canada (Plains) is proposing to build a new pipeline called the Rainbow Pipeline II. This line will be owned and operated by Plains and will supply condensate and butanes to heavy oil production areas near Nipisi, Alberta. The project is estimated to be completed in the second quarter of 2012 and will

Type Destination Capacity Start

Date

Enbridge - Athabasca Pipelines

Existing Product & bitumen Hardisty 390 570 Fall 2013

Athabasca pipeline twinning project Product & bitumen Hardisty 450 2015-2016

Inter Pipeline Fund -Corridor Pipelines 465

Corridor Pipeline Diluent, products 300 2011

Corridor Expansion DilBit 165 2011

Polaris Pipeline Diluent Athabasca 90 120 Late 2012

Pembina - Syncrude Pipeline SCO, crude oil Edmonton 389

Suncor - Oil Sands Pipeline SCO Edmonton 145

Devon/Meg Energy - Access Pipeline Diluted bitumen Edmonton 150

Enbridge - Waupisoo Pipeline SCO and heavy oil Edmonton 350 600 2013

Pembina - Horizon Pipeline SCO Edmonton 250

TOTAL 2,138

Inter Pipeline Fund - Cold Lake Pipeline System 468 700 unknown

Cold Lake West Edmonton 247

Cold Lake South Hardisty 221

Husky - Husky Oil Pipeline Hardisty 491

Lloydminster

Elan, Gibson - Echo Pipeline Heavy Oil Hardisty 76

TOTAL 1,034

Plains Midstream Canada - Rainbow Pipelines

Rainbow exisitng Condensate, sweet &

heavy crudeEdmonton 200

Rainbow Pipeline II Condensate, butane 33.4 2Q2012

Pembina - Nipisi Pipeline dilbit Edmonton 100 2011-2012

Pembina - Mitsue Pipeline diluent 22 2011-2012

TOTAL 200

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Edmonton

('000 bbl/d)

Expansion/New

Project

oil sands & condensate

From Peace River

From Cold Lake Region

From Athabasca Region

Heavy Oil and SCO


July 2012

run with a stream day throughput capacity of approximately 33,400 bpd.3 Pembina is nearing

the completion of its Nipisi and Mitsue lines, which will serve producers in the Pelican and Peace River regions. The two pipelines are initially being constructed to carry a combined 122,000 bpd of diluted heavy oil and condensate. The Nipisi line, which will transport diluted crude to Edmonton, will have initial capacity of 100,000 bpd with incremental phased expansion to an ultimate capacity of 200,000 bpd. The Mitsue line is a diluent pipeline, which will ship 22,000 bpd of condensate to the Peace River region, with a potential to be expanded to 45,000 bpd.

Western Canadian Export Pipeline Capacity The existing export crude oil pipeline infrastructure underwent much needed expansion in order to accommodate growing volumes of oil sands production. A number of pipeline

expansions were completed in 2009, and two major additional pipelines became operational at the end of 2010, namely TransCanada’s Keystone base4 and Enbridge’s Alberta Clipper, which ship crude to the US Midwest. Currently, there are several pipelines that are directly connected to the Canadian supply hubs, which are located in Edmonton and Hardisty, Alberta. These include: Enbridge Mainline, Kinder Morgan Trans Mountain, Kinder Morgan Express, Enbridge Alberta Clipper, and the TransCanada Keystone pipeline. The Alberta Clipper and Keystone pipelines have added 885,000 bpd of pipeline capacity out of western Canada, bringing the total export capacity to 3.5 MMbpd of crude oil, as shown in Table 2.2.

Table 2.2: Existing Export Pipeline Capacity

Name Type Destination Capacity ('000 b/d)

Enbridge Pipeline Crude oil Eastern Canada 1,868

US East coast

US Midwest

Kinder Morgan (Express) Crude oil US Rocky Mountains 280

US Midwest

Kinder Morgan (Trans Mountain) Crude oil and refined products

British Columbia 300

US West Coast

Offshore

Enbridge Alberta Clipper Heavy crude US Midwest 450

TransCanada Keystone Light/heavy crude US Midwest 435

Milk River Pipeline Light oil US Rocky Mountains 118

Rangeland Pipeline Cold Lake blend US Rocky Mountains 85

TOTAL 3,536

SOURCE: ERCB, CAPP.

3Bell, A., Project Manager, Plains Midstream Canada. Personal communication with Jon Rozhon. April 2012.

4It is important to make a distinction between Keystone base and Keystone XL. The Keystone base pipeline presently transports

diluted bitumen and synthetic crude oil to destinations in PADD II (Illinois and Oklahoma). The Keystone XL is a proposed new pipeline that would take Canadian crudes to the US Gulf Coast (PADD III).


July 2012

With a forecast of growing oil sands supplies, the industry’s approach is two-fold. First, since

supplies from both increasing local production in the US and increasing imports from Western Canada have pushed PADD II’s refining capacity to the limit,5 industry has been focusing on addressing the need to access available refining capacity in the US Gulf Coast. Secondly, the industry is looking at a long-term strategy to minimize the risk inherent in having only one customer for Canada’s exports through increased push for pipeline capacity to the west coast in Canada, which would open up growing Asian markets. A number of pipeline projects are being proposed to provide both market access and additional capacity that will be needed by Canadian producers in the future.

5The US Midwest is currently the primary export market for Western Canadian crude oil supplies due to its strong demand,

geographical proximity and established pipeline infrastructure.


July 2012


July 2012

Chapter 3 Western Canadian Oil Supplies and Pipeline Capacity

This chapter covers CERI’s forecasts1 of Western Canadian conventional crude supply and Alberta’s oil sands production against the backdrop of pipeline capacity availability. The authors of this study have updated the CERI oil sands supply cost database/model and investigated in detail the development timing of projects that may support any pipeline option. In addition, the CERI conventional oil supply database/model has been updated to account for any potential

increase or decrease in conventional oil supplies to the various pipelines.

The oil sands production projection profile under CERI’s Reference Case Scenario from the 2012 Oil Sands Update2 forecasts a significant increase; add to that the forecast for Western Canadian crude oil production, and it becomes apparent that the current pipeline infrastructure will not be sufficient to transport forecasted oil sands volumes. In fact, the current pipeline infrastructure out of Western Canada will be inadequate by 2015, and will need to be expanded – as seen in Figure 3.1. Capacity additions are required both to transport blended or upgraded bitumen to refineries outside of the region, and diluent/condensate necessary to operate oil sands projects within the oil sands region.

1The forecast period is 2011-2035, inclusive.

2CERI Study 128, “Canadian Oil Sands Supply Costs and Development Projects (2011-2045)”, March 2012. Download the report

at www.ceri.ca


July 2012


July 2012

Figure 3.1: Western Canadian Export Pipelines and Oil Supply

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AB Conventional Prodn SK ConventionalBC Conventional MB ConventionalNWT Conventional Diluent for Primary/EorExisting&Under Construction US Bakken prodnApproved Approved-on HoldAwaiting Approval AnnouncedExport Operational Capacity (w/KeystoneXL&Gateway) TMX ExpansionExport Operational Capacity(w/Keystone XL) Existing Export Operational Capacity

Note(s): 1)Operational Capacity is 95% of total design capacity. 2) Conventional crude volumes are net production volumes available for export (i.e ., net of domestic demand). 3) Oil Sands volumes comprise of net bitumen and SCO available for export and diluent volumes req'ed to mov e bitumen as per pipeline specifications. May 1, 2012

TMX (2017)

Keystone XL (2015)

Northern Gateway (2018)

Looping/Expanding Existing Pipelines


July 2012

Conventional Oil Supply Figure 3.1 also illustrates historical and forecasted production levels from conventional crude sources in Western Canada as well as primary and enhanced oil recovery (EOR) from oil sands areas, net of domestic demand. These include production volumes from Alberta and Saskatchewan conventional oil, which are set to increase at the beginning of the forecast period and level off in the latter part.1 Production volumes out of British Columbia, Manitoba, and the Northwest Territories are also included; however, these volumes are much smaller and may not be visible on the graph. Overall crude oil production out of Western Canada has slowed down in recent years. Despite that, the use of newer technology in mature fields in Saskatchewan, Alberta, and Manitoba is expected to increase light crude oil production from these provinces over the next few years. In particular, the industry is optimistic over the potential growth in production from the Cardium and Viking oil plays in Alberta, expecting results similar to those

of the Bakken formation in Saskatchewan. Even though conventional crude production in Western Canada will grow in the first decade of the forecast period, CERI estimates total exported volumes out of Western Canada will eventually decrease to 0.4 MMbpd by 2035.

CERI’s transportation analysis also includes Bakken production from North Dakota as seen in yellow on Figure 3.1. There will be additional volumes beyond what is shown on the graph when KXL becomes operational.2 For now, CERI estimates the Bakken volumes that will be moved by Enbridge’s mainline through the Bakken connection to Enbridge’s mainline. There are three projects that Enbridge is proposing and planning on operating: the Bakken Pipeline Project, reactivation and reversal of Enbridge Westspur Line EX-02 and Line 26 in the US, and expansion of Enbridge’s North Dakota System. 3 CERI included 120,000 bpd of Bakken production, starting in 2013, which is the proposed capacity of the Bakken Pipeline Project and

estimated date of service, respectively. The 120,000 bpd is extended for the remainder of the projection period to 2035. The rest of Bakken production is to be moved by other pipelines and rail.

Oil Sands Supply and Costs In addition, Figure 3.1 presents historical and forecast volumes available for export from oil sands production. These are dilbit and SCO volumes broken down by project status. A large portion of bitumen and SCO volumes will come from existing and under construction projects, with significant potential growth exhibited in projects that are approved, awaiting approval, and announced. Diluent volumes required to transport bitumen are also included in this forecast.

1For more information on conventional crude oil production, see CERI Study 124a, “Economic Impacts of Drilling, Completing

and Operating Conventional Oil Wells in Western Canada (2010-2035)”. June 2011. Download your copy at www.ceri.ca. 2TransCanada had signed contracts with Bakken producers to move crude via TransCanada’s Bakken Marketlink, connecting to

Keystone XL. However, the Marketlink project is dependent on the completion of Keystone XL. 3Enbridge’s website: http://www.enbridge.com/BakkenExpansionProgram.aspx


July 2012

Production from surface mining and in situ operations4 averaged 1.5 MMbpd in 2010, growing

to 1.6 MMbpd in 2011, which represents a year-on-year increase of 6.7 percent. Under CERI’s Reference Case Scenario, oil sands production is projected to increase from 1.5 MMbpd in 2010 to 3.3 MMbpd by 2020 and 5.3 MMbpd in 2030. Production from oil sands comprises an increasing share of Alberta and Canada total crude oil production. In 2010, non-upgraded bitumen and SCO production made up 52 percent of total Canadian crude production and 76 percent of Alberta total production. These shares are set to increase to 54 percent of total Canada production and 77 percent of total Alberta production in 2011.

Illustrated in Figure 3.2 are the production projections by extraction method. Total mined bitumen production is expected to increase from 0.85 MMbpd in 2010 to a peak of 2.1 MMbpd in 2023, at which point the production remains flat for the remainder of the projection period.

As well, in situ production is expected to increase from 0.6 MMbpd in 2010 to 3.2 MMbpd by 2035. Mined bitumen contributes a majority of oil sands volumes until 2023, when in situ production volumes overtake mined volumes.

Figure 3.2: Bitumen Production by Method of Extraction – CERI Reference Case Scenario

4Production forecast from primary and EOR methods within oil sands projects is included in the forecast of conventional heavy

production.

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('000 bpd)

In Situ Production Mining Production


July 2012

As previously stated, in situ production will eventually exceed production from mining,

indicating that most of the growth in oil sands production will require blending with diluent to be readily transported to markets. As domestic upgrading capacity only grows moderately up to a maximum of 1.5 MMbpd by 2027, diluents will increasingly become necessary. Diluent volumes, as projected in the Reference Case Scenario, are also included in this forecast. In Figure 3.1, the diluent requirements for oil sands are broken up by the oil sands project status and the appropriate volumes of diluent are added to each oil sands project status category. It is assumed that there will be adequate supply of diluent available and the industry will secure supplies when necessary. Consistent with other industry sources, diluent demand for 2010 was estimated to be 0.20-0.25 MMbpd. The Energy Resources Conservation Board’s (ERCB) forecast indicates that by 2020, demand will increase to about 0.70 MMbpd while CERI’s estimates are closer to 0.60 MMbpd. By 2026, CERI’s projection of diluent demand goes beyond the 1.0

MMbpd mark and by 2035 reaches 1.3 MMbpd and remains somewhat flat over the rest of the forecast period. This is consistent with Reference Case Scenario production.

Achieving any of the levels of production requires a substantial number of inputs, of which capital (both strategic and sustaining) is critical. Without the required capital, an oil sands project cannot be constructed. Once the facility is operating, there is an ongoing need for sustaining capital to ensure that production volumes stay at their design capacities, as well as the need for purchasing fuel, paying the workers, etc., in the form of operating costs. Relying on design assumptions from CERI’s Reference Case Scenario from the 2012 Oil Sands Update and the associated capital required to construct a facility and sustain operations, CERI has estimated the total capital and annual operating costs required for the oil sands.

In Figure 3.3, over the 25-year projection period, the total initial capital required for all oil sands projects, whose forecasted production is shown in Figure 3.2, is projected to be almost $281 billion under the Realistic Scenario. New investment dollars start to drop off by 2030. This does not reflect a slowdown in oil sands investments but instead CERI’s assumptions for project start dates and announcements from the oil sands proponents; CERI does not include in its scenarios any future projects unless publically announced by the companies involved. Ongoing investment, in the form of sustaining capital, will take place on an annual basis. The annual sustaining capital required for the oil sands (excluding royalty revenues, taxes, and fixed and variable operating costs) grows from a current amount of $2 billion in 2011 to almost $5 billion by 2035, with an annual average of $4 billion per year. Total operating costs have the largest share of total oil sands costs. Between 2011 and 2035, total operating costs will be $759.6 billion, with an annual average of $30.4 billion. The capital costs (initial and sustaining) make up the investment streams into CERI’s I/O model. These costs are broken up by the cases and presented in detail in Chapter 4.


July 2012

Figure 3.3: Total Capital and Operating Costs – CERI Reference Case Scenario

Pipeline Capacities The four solid lines in Figure 3.1 represent export operational capacities – the red line being existing capacity at 3.5 MMbpd, the blue representing KXL with additional capacity of 0.7 MMbpd, the purple line showing TMX expansion at 0.55 MMbpd,5 and the orange depicting the Northern Gateway pipeline with stated capacity of 0.53 MMbpd6. The area beyond the line that represents Gateway is the potential for looping and expanding pipelines. Some of those projects might include expanding KXL by an additional 0.2 MMbpd and/or expanding TMX even further. 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 some projects beyond an acceptable risk-adjusted level. Therefore it is possible that not all of the proposed pipeline projects will be completed. This risk is

represented in Figure 3.1 by the area (i.e., time lag) between when the pipeline becomes operational and when it gets filled to its designated capacity. However, another scenario is also

5At the time when I/O results were being calculated, TMX’s expansion stood at 550,000 bpd. However, at the end of May 2012

Kinder Morgan decreased its capacity addition by 100,000 bpd, bringing the total expansion to 450,000 bpd. 6For this analysis, CERI used an annualized factor of 95 percent for the pipeline capacities. Although pipelines operate at 100

percent in some months, individual lines generally do not operate at full capacity every day of the year. Not only do pipelines have outages, but crude oil producers and refineries have planned and unplanned outages, which cause pipeline deliveries to change, so the available capacity of each individual pipeline cannot be fully utilized 365 days a year.

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July 2012

possible, where upstream oil sands development could be advanced earlier than shown in the

graph to expedite the project development since there is extra export capacity in the pipe.

As seen in Figure 3.1, if no other pipeline is built, there is enough capacity to transport conventional production from Western Canada, US Bakken production, as well as exports from on-stream and under construction oil sands projects.7 In other words, if no other pipeline is constructed, the oil sands projects that are above the red line will not be built because there will be no take-away capacity to move their crude volumes to markets. The projects affected include those categorized as approved, approved – on hold, awaiting approval, and announced.

7Production from oil sands projects and EOR includes required diluent volumes to meet pipeline specifications.


July 2012

Chapter 4 Economic Impacts of Oil Sands Development

This Chapter provides a detailed overview of four hypothetical cases, which correspond to pipeline capacities and the associated oil sands production described in the previous chapter. The methodology and assumptions of CERI’s I/O model are presented in Appendix B.

The economic impacts of four such cases are presented in this chapter:

Case 1 – Existing Pipelines Operations. This case examines the economic impacts of production from existing and under construction oil sands projects. It assumes no new pipeline capacity and serves as a baseline scenario.

Case 2 – Keystone XL. This case considers the economic impacts of Case 1 production in addition to production that could come on stream from projects that would benefit from KXL operations.

Case 3 – TMX Expansion. This case considers the economic impacts of Case 2 production in addition to production that could come on stream from projects that would benefit from increased capacity on the TMX system.

Case 4 – Northern Gateway. This case considers the economic impacts of Case 3 production in addition to production that will come on stream from projects that would

benefit from Northern Gateway operations.

These cases form the basis on which the CERI I/O model estimates economic impacts. In each case, the pipeline capacity sets an upper limit on how much crude can be transported via pipelines. It is assumed that conventional crude from British Columbia, Alberta, Saskatchewan, Manitoba, and the US Bakken retain priority in the pipeline and, hence, might “push out” some volumes from oil sands production.

Economic impacts, excluding employment, are expressed in real 2010 dollars and include the following:

Canadian GDP, employee compensation, and employment impacts between 2011 and 2035 as a result of oil sands investments and operations;

The Canadian employment numbers broken down into direct, indirect, and induced employment resulting from oil sands investment and operations;

Total jobs created and preserved in Canada between 2011 and 2035;

Federal and provincial-municipal tax receipts in Canada between 2011 and 2035 that result from oil sands investment and operations over that period of time;


July 2012

Total royalties collected by the Alberta government between 2011 and 2035 as a result of oil sands investments and operations;

US GDP, employee compensation, and employment increases between 2011 and 2035 as a result of oil sands investments and operations – by PADD and by state; and

Total jobs created and preserved in the US between 2011 and 2035.

Comparing the Results This section of the report provides a comparison and an explanation of the differences in the results of CERI Study 125, “Economic Impacts of Staged Development of Oil Sands Projects in Alberta (2010-2035) (released in June 2011) and this report “Pacific Access: Part I – Linking Oil Sands Supply to New and Existing Markets”.

The latter report’s economic impact results are derived from the same internal Input-Output

model as were the results from Study 125 (June 2011). However, there were some changes

made to the assumptions of the input data that contributed to the results that are different from the June 2011 study, specifically the forecasted economic impacts in general were lower in the 2012 report.

The following reasons are cited as contributors to the change in the forecast:

1. The WTI/bitumen price ratio is lower in Case 1 for this report, given the assumption that in a pipeline- and market-constrained world bitumen would be heavily discounted. Cases 2, 3, and 4 use a higher price ratio, assuming increased pipeline capacity and access to other markets (i.e., other than Cushing), which would result in higher prices of bitumen-derived crude.

2. The WTI forecast used in this report is lower than the one used in the June 2011 study. 3. The assumed initial capital costs for oil sands projects are lower in this report. 4. The modelling of forecast diluent requirement to transport bitumen in this report has

been enhanced, which has resulted in a higher percentage of diluent required and hence a smaller volume of bitumen (per transported barrel) being transported, which in turn provides lower economic impacts.

5. The production forecast of primary recovery (EOR) projects within the oil sands areas were re-classified and placed under the conventional production forecast instead of oil sands production forecast, hence lowering the bitumen volumes, resulting in lower economic impacts.

6. The forecast period in the June 2011 study started in 2010 (with 2009 being the year of

historical data) and extended to 2035 inclusive. The forecast period of this report starts in 2011 (with 2010 being the year with historical data) and extends to 2035 inclusive. This contributed to i) a shorter forecast period by one year; and ii) 2010 actual historical data for oil sands production being lower than CERI’s forecast of 2010 production in the June 2011 study, due to an unforeseen fire at the Horizon project and shut-in of production from that mine.


July 2012

Existing Pipelines Operations Case This case represents existing export pipeline capacity out of Alberta, which is 3.5 MMbpd. If no other pipeline is built over the next twenty five years, current capacity is sufficient to transport conventional production from Western Canada, required diluent volumes, and exports from oil sands projects that are currently on-stream or under construction. As Figure 3.1 shows, a portion of approved projects fits under the existing pipeline capacity limit in the latter part of the forecast period. However, that portion is not included in the Existing Pipeline Operations Case – it is apportioned to the next case. This case also includes US Bakken production to be transported via Enbridge’s mainline. If no further take-away capacity is added, the oil sands projects above the red line will not be built. Affected projects include those categorized as approved, approved on-hold, awaiting approval, and announced.

The capital investment required to support the on-stream and under construction oil sands projects is shown in Figure 4.1. The total initial capital investment for 2011 to 2035 amounts to $8.3 billion, which is spent on under construction projects from 2011 to 2014, since the on-stream projects have already invested their initial capital in prior-years’ construction period. The sustaining capital averages a $2 billion on an annual basis and totals $50.4 billion for 2011-2035 period.

Figure 4.1: Capital Investment – Existing Pipelines Operations Case

There is no question that of all the Canadian provinces, Alberta stands to benefit the most in terms of oil sands-related GDP growth that will take place over the next quarter century. Assuming that there will be no further major transportation infrastructure built over that period, Alberta, nevertheless, will gain over $1.4 trillion in oil sands investment and operations GDP growth over the 2011-2035 time period as a result of on-stream and under construction projects. This represents 95 percent of the expected total national GDP impact of $1.5 trillion (see Figure 4.2).

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July 2012

Figure 4.2: GDP Increase (2011-2035) Existing Pipelines Operations Case

Figure 4.3 presents the GDP impacts throughout the rest of Canada, with growth totaling more than $80 billion. The chart shows that Ontario and Quebec, the centre of Canadian manufacturing and home to large populations, will see more than two-thirds of the nation’s GDP increase. Almost all of the rest of the GDP benefit will go to British Columbia,

Saskatchewan, and Manitoba, which are the three closest provinces to Alberta and benefit significantly from indirect and induced economic benefits.

Alberta $1,440 Billion

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July 2012

Figure 4.3: GDP Impacts in Canada (excluding Alberta) Existing Pipelines Operations Case

Employment impacts are felt the most in Alberta, which will see significant and sustained increases in job numbers and compensation. As demonstrated in Figure 4.4, well over $40 billion in wages will be paid out in provinces other than Alberta over the next quarter century. Again, the major industrial provinces stand to gain the most as they will be supplying some of

the specialized equipment and parts that will be required on an ongoing basis. Some equipment and materials are and will be provided by foreign sources outside of Canada. However, it is difficult to estimate the monetary value of foreign-sourced materials and equipment for the whole oil sands industry. Hence, we could not subtract that amount from the capital investment projections.

Ontario 55% British

Columbia 24%

Quebec 12%

Saskatchewan 4%

Manitoba 3%

Rest of Canada

2%

Total GDP Increase as a result of Oil Sands Investment & Operations 2011-2035 1. Ontario $44.30 billion 4. Saskatchewan $3.05 billion 2. BC $19.45 billion 5. Manitoba $2.93 billion 3. Quebec $9.59 billion 6. ROC $1.56 billion


July 2012

Figure 4.4: Employee Compensation (excluding Alberta) Existing Pipelines Operations Case

Figure 4.5 shows that wages for oil-sands related work in most provinces will average between $35,000 and $55,000. By far the most and the highest paying jobs will be within Alberta. The spread in compensation between provinces is high, with the non-industrial and distant

provinces seeing the lowest average wages.

Figure 4.5: Average Wages (2011-2035) Existing Pipelines Operations Case

25.41

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July 2012

In Figure 4.6, employment figures are separated into induced, indirect, and direct jobs, which

are classified as both created and preserved1. Direct jobs refer to those positions that are created and preserved directly – construction jobs, administrative jobs, or any other positions directly related to the development and ongoing operations of oil sands projects. As such, all direct effects (the blue bars in the chart) are felt solely within the province of Alberta. The red bars in the chart refer to indirect employment effects – these are jobs created in industries tangential to the oil sands industry. For example, these would include jobs in the service sector, jobs in companies that build trucks and shovels for mines, and other jobs where the work that is done serves the oil sands industry in some way. Finally, induced jobs are those which provide services, facilities, and other goods and services to the people directly employed in the oil sands industry. This is the largest category of employment, as the ripple effects of the oil sands spread far and wide throughout the North American economy; unlike the other

provinces, direct employment exceeds induced employment in Alberta.

In the Existing Pipeline Operations Case it is expected that employment will eventually decline as no new oil sands production is added beyond what the current export pipelines can ship. Direct, indirect, and induced employment is projected to peak around 2022 and decline thereafter. Despite this, employment will remain relatively stable over the 25-year period, with an annual average number of created and preserved jobs of 111,000.

Figure 4.6: Jobs Created and Preserved in Canada (2011-2035) Existing Pipelines Operations Case

Revenue Canada makes a distinction between two types of taxes paid. Income taxes are generally considered direct taxes. Taxes on expenditures (including GST, HST, and PST) and all taxes deducted by corporations (such as property taxes) for income tax purposes are

1The definition of created and preserved jobs is best explained by an example. For instance, if a new oil sands in-situ project

with a capacity of 10,000 bpd starts operations by hiring 60 people in the initial year, the employment is 60 jobs. If this facility adds 5,000 bpd capacity in the second year and hires 25 more employees, in the second year the project has created and preserved 85 jobs, of which 60 represent preserved jobs and 25 refers to created jobs.

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July 2012

considered indirect taxes. CERI has estimated tax receipts as a result of oil sands operations and

investments, determining direct and indirect taxes levied by provincial-municipal and federal levels of government.

Total oil sands-related taxes paid by citizens and corporations of each province excluding Alberta are noted in Figure 4.7. Ontarians will pay the most – almost $15 billion in total oil sands-related taxes over the next 25 years. This has to do with the large manufacturing base within that province that contributes, and will continue to contribute, equipment to the oil sands industry. British Columbia is second because of oil sands manufacturing in the province and the other economic benefits (both induced and indirect) that accrue due to BC’s geographic proximity to Alberta. The prairie provinces of Saskatchewan and Manitoba also benefit from geographic proximity, with their citizens earning considerable oil sands-related wages and

paying $0.95 billion and $0.82 billion in taxes, respectively – whereas the Maritime provinces and northern territories lack manufacturing base, population, and geographical advantages, consequently contributing little in the way of goods and services to the oil sands and paying only $0.43 billion in oil sands-related taxes over the next 25 years.

Figure 4.7: Total Oil Sands-related Taxes (excluding Alberta) Existing Pipelines Operations Case

Figure 4.8 demonstrates that just as Alberta receives the lion’s share of employment and GDP increases that result from continued oil sands activity, Albertans also pay the most taxes – more than 10 times the amount of oil-sands related taxes generated throughout the rest of the country. Over the next 25 years, Alberta will pay a total of $92.5 billion in indirect tax, $137 billion in personal income tax, and $68 billion in corporate tax. This compares to $12.6 billion in

Ontario $14.6 billon, 57% British Columbia

$5.2 billion, 20%

Quebec $3.6 billion,

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July 2012

indirect tax, $9.6 billion in personal income tax, and $3.4 billion in corporate tax in the rest of

the country.

Figure 4.8: Alberta and Rest of Canada Total Taxes Paid (2011-2035) Existing Pipelines Operations Case

Under the Existing Pipeline Operations Case, oil sands royalties collected by the Alberta government from 2011 to 2035 will total $352.8 billion (see Figure 4.9). Royalty revenues will grow to a peak of $17.7 billion in 2023 due to increased oil price forecast and advancement of some projects from pre- to post-payout phase. After 2023 royalties remain flat and start to decline slightly given that the royalties are calculated off the production that is coming from on-stream and under construction projects, not including the future potential production from other projects.

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Figure 4.9: Alberta Oil Sands Royalties (2011-2035) Existing Pipelines Operations Case

Keystone XL Case TransCanada’s proposed KXL pipeline will offer access to the Gulf of Mexico rather than the Pacific Rim. And though the project has been halted by the US government, there is a very good chance that it will be given the go-ahead once the 2012 US Presidential election is over. KXL is likely, therefore, to be moving Canadian bitumen before any of the other major pipeline projects considered in this report. In fact, with KXL in place and operating at capacity, bitumen

production could increase substantially and have a major effect on the overall supply/demand situation throughout the North American continent. For these reasons, CERI considers in this study KXL’s potential influence on GDP, employment, and taxes.

The KXL case is represented in Figure 3.1 by a blue line. With the US State Department’s approval of the project, Western Canada’s total pipeline capacity could expand by 700,000 bpd to 4.2 MMbpd in 2016. In 2015, it is assumed only half of KXL’s initial capacity will be available. The year 2016 is not an officially stated on-stream date. However, given the latest rejection of the pipeline and TransCanada’s subsequent decision to re-route the original course, CERI believes that crude will flow via KXL no earlier than 2015-2016. The KXL case includes all the crude volumes from the Existing Pipeline Operations Case, in addition, it takes into account a significant portion of volumes from oil sands approved projects that would fill KXL to

operational capacity.

In Figure 3.1, the area between the blue line that represents KXL, and the top of the red area, which denotes approved projects, is the volume of bitumen from approved projects that will be unable to move, even with KXL in service. Here we do not explicitly judge individual projects but derive our calculations from the aggregate industry level, where the projects are already summed accordingly, based on their project status. In fact, we assume one of two possibilities

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could occur: either some approved projects will be halted, or the entire supply will be

apportioned to pipeline capacity.

The capital investment required to support the construction of additional oil sands projects as well as capital for on-stream and under construction oil sands projects is shown in Figure 4.10. The total capital investment for the two cases is $78.7 billion in initial investment and $67.8 billion in sustaining capital from 2011 to 2035. The incremental initial capital investment from the additional oil sands projects alone, whose production will be able to move with KXL in service, amounts to $70.5 billion for the 2011 to 2035 period and incremental sustaining capital is $17.3 billion for the same time period.

Figure 4.10: Cumulative Capital Investment – Keystone XL Case (Includes Existing Pipelines Operations Case)

As all oil sands development happens to be in Alberta, the province will derive the most GDP

and employment benefit of any Canadian province. On top of the $1.4 trillion in GDP growth that the province stands to gain if no further pipeline infrastructure expansion occurs, oil sands production will contribute an additional $583 billion to GDP if KXL comes into service. The rest of Canada will see approximately $34 billion in increased GDP, as shown in Figure 4.11.

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Figure 4.11: GDP Increase (2011-2035) Keystone XL Case

As Figure 4.12 shows, outside of Alberta, Ontario stands to see the most GDP impact of $18.6 billion over the 25-year period, followed by British Columbia with $8.3 billion, Quebec – $4.1 billion, and the prairie provinces (with Saskatchewan and Manitoba) totaling $2.7 billion.

Figure 4.12: GDP Impacts in Canada (excluding Alberta) Keystone XL Case

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The biggest gain in job creation and wages occurs in Alberta, just as the province receives the

most GDP and pays the most taxes. However, Ontario, with its extensive manufacturing base, and large population, will see significant wages paid out to Ontario-based employees that work in oil-sands related positions as seen in Figure 4.13. At almost $11 billion in wages between 2011 and 2035, Ontario citizens benefit more than twice as much as the third most highly impacted province, British Columbia. Provinces with smaller populations take a lesser share of the pie, though it is notable that Manitoba fares rather well because of the manufacturing infrastructure in place in that province.

Figure 4.13: Employee Compensation (excluding Alberta) Keystone XL Case

When KXL becomes operational, the additional production from oil sands will stimulate steady employment growth to 2020, at which point the growth of created and preserved jobs is projected to remain relatively steady, increasing at a slower rate than the job growth of the first decade of the forecast period. It is interesting to note that the highest rate of growth in number of jobs is observed in the induced category, reflecting the spill-over effect of oil sands production in labour markets outside of Alberta (see Figure 4.14). Between 2011 and 2035, the

number of jobs in the induced category grows by 72 percent, whereas direct and indirect jobs grow by 60 and 66 percent, respectively.

Shown in Figure 4.14, under this case, the direct number of jobs in the first year is higher by 17,000 than in the first case with no additional pipeline capacity available (Figure 4.6). This can be explained by the fact that the oil sands projects that will come on stream as a consequence of KXL adding more room to the pipeline system, will have a prior construction period during which new jobs will be created.

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Figure 4.14: Cumulative Jobs Created and Preserved in Canada (2011-2035) Keystone XL Case

The tax burdens from the Keystone XL Case are distributed similarly (in terms of proportions) to the tax burdens created by the Existing Pipeline Operations Case. Alberta pays the most, followed by Ontario, with the rest of the nation contributing far less. In terms of dollar amounts paid, due to incremental oil sands production, Alberta will pay over $120 billion over the next quarter century; with Ontario paying $6.1 billion (see Figure 4.16). All other provinces and territories will pay $4.7 billion in oil-sands related taxes (see Figure 4.15).

Figure 4.15: Total Oil Sands-related Taxes (excluding Alberta) Keystone XL Case

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July 2012

Figure 4.16: Alberta and Rest of Canada Total Taxes Paid (2011-2035) Keystone XL Case

Oil sands royalties collected from 2013 to 2035 will increase by $117.9 billion as a result of additional oil sands production that will be transported when KXL comes into service. The total

royalty revenues from the two cases will increase from its current levels to $27.5 billion in 2035.

Figure 4.17: Alberta Oil Sands Royalties (2011-2035) Keystone XL Case

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Trans Mountain Expansion Case Kinder Morgan’s Trans Mountain pipeline was the first hydrocarbons pipeline to run to the BC coast. It came into operation in 1953, a time when oil supply in North America was tight, and the need for crude oil and refined petroleum products along the Pacific Coast was growing. It presently extends from Edmonton to Vancouver to Washington State and moves volumes approaching 300,000 bpd. Because the pipeline right-of-way is established, twinning Trans Mountain can be accomplished swiftly. It operates according to a flexible batch-shipping system that allows for different liquids – crude oil and refined petroleum products – to be shipped.

After a 2012 “open season” to gauge shipper interest, the company has secured weaker than anticipated commitments. Therefore, Kinder Morgan has revised a $5 billion expansion that

would have increased capacity to 850,000 bpd and substituted a $4.1 billion expansion with proposed capacity addition of 450,000 bpd, bringing the total anticipated capacity to 750,000 bpd.2

The Trans Mountain Expansion Case sees the addition of Kinder Morgan’s TMX expansion, represented by the purple line in Figure 3.1, to already existing and KXL capacities. The total pipeline capacity would then be expanded by 550,000 bpd in 20183 to over 4.5 MMbpd. The TMX case includes all the crude volumes from the Keystone XL Case; in addition, the remaining portion of approved and all approved – on hold oil sands projects that lie between the blue and purple lines will be added to the total volume of crude that can be transported.

The total crude volume that can be shipped via KXL, TMX, and all existing pipelines is

represented by the area under the purple line in Figure 3.1. The difference between the blue and purple lines is the additional volumes from oil sands projects that can be transported to markets by the TMX pipeline. Cumulatively, if KXL and the TMX expansion become operational, the additional volumes that can be transported lie between the red and purple lines.

The capital investment required to construct additional oil sands projects as well as oil sands projects from the previous two cases is shown in Figure 4.18. The total capital investment for the three cases from 2011 to 2035 is $90.4 billion in initial investment and $74.5 billion in sustaining capital. The incremental initial capital investment from the additional oil sands projects alone under the Trans Mountain Expansion Case from 2011 to 2035 amounts to $11.7 billion and incremental sustaining capital is $6.7 billion for the same time period.

2Oligram News. “Kinder Morgan revises plan for Trans Mountain capacity”. Platts. May 29, 2012.

3 At the time when I/O results were being calculated, TMX’s expansion stood at 550,000 bpd. However, at the end of May 2012

Kinder Morgan decreased its capacity addition by 100,000 bpd, bringing the total expansion to 450,000 bpd.


July 2012

Figure 4.18: Cumulative Capital Investment – Trans Mountain Expansion Case (Includes Existing Pipelines Operations Case and KXL Case)

As expected, Alberta will receive the most GDP and employment benefit from additional oil sands production that could come on stream once the TMX expansion takes place. In addition to $2.02 trillion in oil sands investment and operations GDP growth that the province stands to gain when KXL comes online, oil sands production will contribute an additional $291.3 billion to GDP in the province. The rest of Canada will see almost $17 billion in increased GDP as seen in

Figure 4.19.

Figure 4.19: GDP Increase (2011-2035) Trans Mountain Expansion Case

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Figure 4.20 presents the GDP impacts throughout the rest of Canada, broken down by province.

The chart shows that out of $16.6 billion Ontario and British Columbia will see the most of the nation’s GDP increase, $9.05 billion and $3.99 billion, respectively. The fourth largest receiver of GDP benefits is Quebec with $1.96 billion, followed by an almost equal split of benefits for Saskatchewan and Manitoba.

Figure 4.20: GDP Impacts in Canada (excluding Alberta) Trans Mountain Expansion Case

Just as the province receives the most GDP and pays the most taxes, Alberta will also experience the highest level of employee compensation. Over the next twenty five years, $81.2 billion will be paid out in wages as a result of incremental production from oil sands projects that can be transported via the expanded TMX pipeline. However, Ontario, with its extensive manufacturing base and large population, will see significant wages paid out to Ontario-based employees that work in oil-sands related positions (see Figure 4.21). At $5.2 billion in wages between 2011 and 2035, Ontario citizens benefit more than twice as much as the second most highly compensated province, British Columbia. Provinces with smaller populations take a lesser share of the pie, though it is notable that Manitoba fares better than Saskatchewan due to the presence of manufacturing infrastructure.


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July 2012

Figure 4.21: Employee Compensation (excluding Alberta) Trans Mountain Expansion Case

If the TMX expansion goes as planned and can carry the additional production from oil sands, there will be steady employment growth to a peak of 622,000 preserved and created jobs in 2025 (see Figure 4.22). The growth is projected to remain relatively flat over the following 6 years, after which it starts to decline for the remainder of the forecast period. Again, the distribution among the categories is skewed more towards the number of jobs in the induced

category, which grows by 79 percent. In comparison, between 2011 and 2035, the number of jobs in the direct and indirect groups grows by 65 and 72 percent, respectively.

Figure 4.22: Cumulative Jobs Created and Preserved in Canada (2011-2035) Trans Mountain Expansion Case

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Total taxes paid by citizens and businesses of each province excluding Alberta are presented in

Figure 4.23. Ontario will pay the most – almost $3 billion in total oil sands-related taxes over the next 25 years. British Columbia is second at $1.1 billion. The prairie provinces of Saskatchewan and Manitoba benefit from geographic proximity, with their citizens earning considerable oil sands-related wages and paying almost equal shares in taxes – whereas the Eastern Maritime provinces and northern territories lack manufacturing base, population, and geographical advantages, consequently contributing little in the way of goods and services to the oil sands and paying a small fraction in oil sands-related taxes over the next 25 years.

Figure 4.23: Total Oil Sands-related Taxes (excluding Alberta) Trans Mountain Expansion Case

Just as in the other cases, under the TMX Expansion Case Alberta also pays the most taxes – more than 10 times the amount of oil-sands related taxes generated throughout the rest of the country (see Figure 4.24). Over the next 25 years, Albertans will pay a total of $60.3 billion, broken down into indirect taxes of $18.7 billion, $27.8 billion in personal income taxes, and $13.7 billion in corporate taxes. This amount trumps in comparison to total taxes for the rest of

Canada: $2.6 billion in indirect tax, $2.0 billion in personal income tax, and $0.7 billion in corporate tax in the rest of the country, totaling $5.2 billion for the next twenty five years.



Quebec $0.7 billion


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July 2012

Figure 4.24: Alberta and Rest of Canada Total Taxes Paid (2011-2035) Trans Mountain Expansion Case

Under the Trans Mountain Expansion Case, royalties from additional oil sands production are

not as significant as royalties collected under the Keystone XL Case. Nevertheless, there will be $53.8 billion collected by the provincial government for the 2014-2035 period.

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Figure 4.25: Alberta Oil Sands Royalties (2011-2035) Trans Mountain Expansion Case

Northern Gateway Case The Enbridge Northern Gateway Pipeline is a proposed twin pipeline system that, if approved, will carry diluent from the Pacific coast to Alberta and dilbit/SCO from the oil sands to the coast. The diluent pipe will transport 193,000 barrels daily of condensate, and the bitumen pipe will have a capacity of 525,000 bpd. At the coast, in Kitimat, British Columbia, a marine terminal is proposed that will accommodate some of the largest oil tankers in the world. These

tankers will take the crude bitumen through the Kitimat Arm fjord to open waters and various destinations throughout the Pacific Rim.

The Northern Gateway Case sees the addition of the Northern Gateway pipeline’s capacity, represented by the orange line in Figure 3.1, to already existing, KXL, and TMX capacities. The total pipeline capacity would then be expanded by 525,000 bpd in 2019 to just over 5.1 MMbpd. In 2018, it is assumed only half of Gateway’s initial capacity will be available. The Northern Gateway Case includes all the crude volumes from the TMX case; in addition, a portion of awaiting-approval oil sands projects that lie between the purple and orange lines will be added to the total volume of crude that can be transported.

The total crude volume that can be shipped via Keystone XL, TMX, Northern Gateway, and all

existing pipelines is represented by the area under the orange line in Figure 3.1. The area between the purple and orange lines is the additional volumes from oil sands projects that can be transported to markets via Northern Gateway. Cumulatively, if KXL and Northern Gateway become operational and TMX is able to expand to its proposed capacity, the additional volumes that can be transported are depicted as the distance between the red and orange lines.

The oil sands projects above the orange line will not get built because there will be no take-away capacity to move these crude volumes to markets. This might happen as early as 2021

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when oil sands production could exceed total available pipeline capacity. However, the possible

solution might be looping and expanding the existing pipelines or finding other alternatives, such as rail.

The capital investment required to construct and sustain additional oil sands projects as well as oil sands projects from the previous three cases is shown in Figure 4.26. The total capital investment for all four cases from 2011 to 2035 is $157.3 billion in initial investment and $83.7 billion in sustaining capital. The incremental initial capital investment from the additional oil sands projects alone under the Northern Gateway Case from 2011 to 2035 amounts to $66.8 billion and incremental sustaining capital is $9.2 billion for the same time period.

Figure 4.26: Cumulative Capital Investment – Northern Gateway Case (Includes Existing Pipelines Operations Case, KXL Case and TMX Case)

Alberta will receive the largest share of GDP increase as a result of oil sands production from

additional projects whose volumes could be carried via Northern Gateway. In addition to $2.3 trillion (cumulative) in GDP growth that the province stands to gain from the above three cases, oil sands production will contribute an additional $352.4 billion in GDP in Alberta. The rest of Canada will see $21.1 billion in increased GDP as seen in Figure 4.27.

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Figure 4.27: GDP Increase (2011-2035) Northern Gateway Case

After Alberta, the most industrialized, heavily-populated provinces in Canada will see the most GDP impact. Ontario will lead the way with $11.4 billion in GDP growth, followed by British Columbia - $5.1 billion, and Quebec - $2.5 billion. Together, these provinces will collect slightly more than $19 billion in GDP contributions, while the remaining provinces will see about $2

billion in GDP additions over the 25-year period (see Figure 4.28).


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Figure 4.28: GDP Impacts in Canada (excluding Alberta) Northern Gateway Case

Cumulative direct, indirect, and induced employment is projected to grow substantially, surpassing 700,000 jobs by 2022 and remaining flat thereafter. Additional production volumes would give steady employment growth in all three categories (see Figure 4.29). The number of

jobs in the induced category grows from 116,000 in 2011 to 269,000 by 2035. In comparison, between 2011 and 2035, the number of jobs in the direct group will increase from 117,000 to 239,900, and indirect jobs grow from 106,000 to 226,000.


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Figure 4.29: Cumulative Jobs Created and Preserved in Canada (2011-2035) Northern Gateway Case

As can be expected, the provinces in which GDP grows the most will also see the most increase in wages. Over the next twenty five years, $101.2 billion will be paid out in wages in Alberta as a result of incremental production from oil sands projects that can be transported via the Northern Gateway pipeline. Figure 4.30 shows oil sands-related wages total more than $10 billion in the three major provinces of Ontario, British Columbia, and Quebec.

Figure 4.30: Employee Compensation (excluding Alberta) Northern Gateway Case

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As expected, taxes generated will be highest in the jurisdictions where GDP and employment

effects are greatest. Residents and businesses of Ontario, British Columbia, and Quebec will pay $6 billion in taxes over the 25 year period (see Figure 4.31) while Albertans will pay the largest share of federal and provincial-municipal taxes, totaling $72.8 billion over the 2011-2035 time period (see Figure 4.32). The largest share of Alberta’s taxes will come from personal income tax, amounting to $33.6 billion, followed by indirect tax at $22.6 billion and corporate tax at $16.6 billion.

Figure 4.31: Total Oil Sands-related Taxes (excluding Alberta) Northern Gateway Case



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Figure 4.32: Alberta and Rest of Canada Total Taxes Paid (2011-2035) Northern Gateway Case

The oil sands royalties from Northern Gateway Case accumulate to $61.2 billion over the forecast period. The total royalty revenue from all cases will increase significantly from $3.4 billion in 2010 to just over $35 billion in 2035.

Figure 4.33: Alberta Oil Sands Royalties (2011-2035) Northern Gateway Case

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Chapter 5 Conclusion

The production from conventional sources in Western Canada is growing as technology is able to unlock resources that were once thought to be difficult to extract. Nevertheless, oil sands will continue to dominate the future production growth in this region. The 25-year forecast suggests that the total production could surpass 6 MMbpd by 2035 out of Western Canada, which beg the question of how this oil is going to be transported and where it will be destined for. Canadian crude oil supplies will continue to serve traditional markets in the US and Canada. The demand for Canadian crude oil to the US Midwest market still has some room to

grow, as heavy oil refining capacity in the region is added. However, increasing volumes of Canadian bitumen supply mean that new markets must be found.

Presently, the crude pipeline capacity out of Western Canada is sufficient to transport production coming from on stream and under construction oil sands projects. Additional crude export capacity from Western Canada will be essential by as early as 2015. Significant pipeline investments will have to be considered. There are many considerations in making such decisions. The choice whether to ship bitumen or synthetic crude – the value of upgrading at the source in Alberta versus other locations has to be analyzed. Environmental issues concerning greenhouse gas emissions, tailings ponds, water consumption, land disturbance and reclamation will play an important role in the pace and scale of the oil sands project development. Differentials and how they are expected to change with access to new markets

are important.1 Existing and potential crude competition can come into play, from such areas as Venezuela, Mexico and the deepwater Gulf of Mexico. Politics and the desire for supply security and international dependence will play a role in decisions. Existing pipelines and routes, refinery configurations and any re-configurations, and demands in regions also must be considered.

All these elements will have an impact on oil sands growth, and in turn will affect the economic benefits that can be realized. This report presented the economic impacts of oil sands development, broken down into four separate cases, which represent the pipeline capacities of existing infrastructure, as well as capacities of pipelines that are not yet operating. The report showed significant economic benefits of oil sands development for Canadian and provincial

economies.

Table 5.1 presents the economic impacts on GDP, Employment, Compensation and Taxes paid for Canada and the top three beneficiaries of oil sands development: Alberta, Ontario and British Columbia. Given that all oil sands development takes place in Alberta, it is clear that Alberta will be the largest beneficiary. For example, of the $1.5 trillion GDP growth in Canada

1M.C. Moore, S. Flaim, D. Hackett, S. Grissom. D. Crisan, A. Honarvar. December 2011. “Catching the Brass Ring” Oil Market

Diversification Potential for Canada”. School of Public Policy, University of Calgary. Vol. 4, Issue 16.


July 2012

under the Existing Pipelines Case, 95% growth or $1.4 trillion is accounted for in Alberta from 2011 to 2035. Ontario will receive 3 percent of the total, or $44.3 billion, followed by British Columbia at 1.2 percent ($19.4 billion). Alberta will also have the highest share of employee compensation benefits as well as paid tax revenues to the provincial and federal governments. All direct employment will be occurring in the province where oil sands are developed, with a larger spin-off effect in indirect and induced job categories happening outside of Alberta.

Table 5.1: Cumulative Economic Impacts by Case (2011-2035)

GDP Employment Compensation Taxes Paid

(Billion 2010 CDN$)

(Thousand person-years)

(Billion 2010 CDN$)

(Billion 2010 CDN$)

Canada Existing Pipelines Case 1,520.8 8,349 444.1 323.4 Keystone XL Case 2,138.2 11,846 628.7 454.8 TMX Expansion Case 2,446.1 13,551 719.2 520.2 Northern Gateway Case 2,819.6 15,701 832.2 599.7 Alberta Existing Pipelines Case 1,439.9 7,209 398.9 297.9 Keystone XL Case 2,023.1 10,225 564.3 418.5 TMX Expansion Case 2,314.4 11,696 645.5 478.7 Northern Gateway Case 2,666.7 13,549 746.8 551.6 Ontario Existing Pipelines Case 44.3 602 25.4 14.6 Keystone XL Case 62.9 854 36.1 20.7 TMX Expansion Case 71.9 977 41.3 23.6 Northern Gateway Case 83.3 1,132 47.9 27.4 British Columbia Existing Pipelines Case 19.4 290 10.8 5.2 Keystone XL Case 27.7 413 15.4 7.4 TMX Expansion Case 31.7 472 17.6 8.4 Northern Gateway Case 36.8 548 20.4 9.8

Figures 5.1 to 5.3 show how economic impacts vary by case and by region. Figure 5.1 represents GDP growth for all four cases. The results indicate that the TMX case has the lowest economic impact on GDP for Canada and the three provinces. This could be explained by the fact that out of three proposed pipeline projects, TMX has the lowest capacity addition to the total export capacity, and hence the bitumen production volumes that will be transported via TMX are the lowest among the four cases. In all four cases Alberta takes the largest share of GDP growth.


July 2012

Figure 5.1: Incremental GDP Impacts by Case (2011-2035)

Figure 5.2 shows employment results, measured in thousand person-years, by case and by region. Again, the same pattern occurs. Ignoring the Existing Pipelines Case, the second largest benefits in employment are received under Keystone XL Case, followed by the Northern Gateway Case. The additional employment impacts under the TMX Case are the lowest among the four cases.

Figure 5.2: Incremental Employment Impacts by Case (2011-2035)

0

200

400

600

800

1,000

1,200

1,400

1,600


Existing Pipelines 1,520.8 1,439.9 44.3 19.4

KXL 617.4 583.2 18.6 8.3

TMX 307.9 291.3 9.0 4.0

Gateway 373.5 352.3 11.4 5.1

(Bln CDN$)

Existing Pipelines

KXL

TMX

Gateway

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000


Existing Pipelines 8,349 7,209 602 290

KXL 3,497 3,016 252 123

TMX 1,705 1,471 123 59

Gateway 2,150 1,853 155 76

('000 person-years)

Existing Pipelines

KXL

TMX

Gateway


July 2012

Figure 5.3 illustrates tax revenues paid by citizens and businesses of Canada, Alberta, Ontario

and British Columbia. Again, Alberta’s residents and businesses pay the most taxes out of all the provinces and territories. Ignoring the Existing Pipelines Case, the second largest tax revenues are received from the Keystone XL Case, followed by the Northern Gateway Case. The additional taxes collected under the TMX Case are the lowest among the four cases.

Figure 5.3: Incremental Tax Revenue Impacts by Case (2011-2035)

Royalties from oil sands production varies by case (see Figure 5.4). Excluding the Existing Pipeline Operations Case, monies collected by the Alberta government are the second highest under the Keystone XL Case, followed by the Northern Gateway Case, and then the TMX Case. On an annual basis, total royalty revenues from all cases will increase significantly from $3.4 billion in 2010 to just over $35 billion in 2035. Cumulatively, over the 25-year period, there will

be $585.7 billion collected in the form of oil sands royalties.

0

50

100

150

200

250

300

350


Existing Pipelines 323 298 15 5

KXL 131 121 6 2

TMX 65 60 3 1

Gateway 80 73 4 1

(Bln CDN$)

Existing Pipelines

KXL

TMX

Gateway


July 2012

Figure 5.4: Oil Sands Royalties by Case (2011-2035)

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TMX

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July 2012


July 2012

Thousand

Person Years

GDP Compensation of

Employees

Employment

PADD I 38,742 19,604 447

PADD II 50,550 24,983 580

PADD III 19,844 7,814 195

PADD IV 8,028 3,740 88

PADD V 24,474 11,412 258

Total US 141,638 67,554 1,568

2011-2035$CAD Million

Appendix A US Results

Appendix A contains the I/O results for the United States broken down by PADD region as well as at state level.

Existing Pipelines Operations Case

Table A.1: Total Economic Impacts by US PADD Region Existing Pipelines Operations Case

Figure A.1: Jobs Created and Preserved in the US Existing Pipelines Operations Case

0

10

20

30

40

50

60

70

80


July 2012

Table A.2: Total Economic Impacts by US State Existing Pipelines Operations Case

Thousand

Person Years

GDP Compensation of

Employees

Employment

Alabama 1,291 647 19

Alaska 521 113 3

Arizona 1,729 849 22

Arkansas 754 355 11

California 15,091 7,012 151

Colorado 3,305 1,563 35

Connecticut 1,703 839 15

Delaware 474 176 4

District of Columbia 475 292 4

Florida 5,139 2,498 69

Georgia 2,827 1,471 38

Hawaii 395 181 5

Idaho 378 193 6

Illinois 17,303 8,442 173

Indiana 2,446 1,216 30

Iowa 1,072 471 14

Kansas 2,008 977 24

Kentucky 1,216 599 18

Louisiana 3,493 1,115 27

Maine 340 178 6

Maryland 1,740 895 21

Massachusetts 2,567 1,463 28

Michigan 4,468 2,371 54

Minnesota 2,046 1,063 26

Mississippi 761 367 12

Missouri 1,728 918 25

Montana 3,176 1,504 32

Nebraska 593 280 9

Nevada 903 433 12

New Hampshire 430 238 6

New Jersey 3,545 1,801 35

New Mexico 610 214 7

New York 7,713 3,902 71

North Carolina 3,121 1,389 37

North Dakota 209 89 3

Ohio 6,662 3,358 77

Oklahoma 1,368 556 16

Oregon 1,382 650 18

Pennsylvania 4,058 2,097 50

Rhode Island 337 165 4

South Carolina 1,120 602 18

South Dakota 252 98 4

Tennessee 1,870 957 27

Texas 12,935 5,116 119

Utah 787 382 11

Vermont 173 90 3

Virginia 2,577 1,313 31

Washington 4,451 2,174 48

West Virginia 401 195 6

Wisconsin 7,308 3,590 79

Wyoming 382 98 3

Total US 141,638 67,554 1,568

$CAD Million


July 2012

Thousand Person

Years

GDP Compensation of

Employees

Employment

PADD I 76,438 37,839 863

PADD II 125,544 60,880 1,406

PADD III 40,194 17,045 411

PADD IV 20,779 9,780 228

PADD V 50,832 23,882 543

Total US 313,787 149,425 3,451


KXL Case

Table A.3: Total Economic Impacts by US PADD Region KXL Case

Figure A.2: Cumulative Jobs Created and Preserved in the US KXL Case

0

20

40

60

80

100

120

140

160

180

200


July 2012

Table A.4: Total Economic Impacts by US State KXL Case

Thousand Person

Years

GDP Compensation of

Employees

Employment

Alabama 2,541 1,250 34

Alaska 904 259 6

Arizona 3,484 1,690 42

Arkansas 1,460 689 20

California 29,829 13,974 307

Colorado 8,135 3,856 88

Connecticut 3,257 1,585 31

Delaware 921 376 8

District of Columbia 1,043 580 10

Florida 10,294 4,964 129

Georgia 5,575 2,812 69

Hawaii 826 384 10

Idaho 753 375 11

Illinois 48,173 23,172 507

Indiana 4,877 2,385 57

Iowa 2,035 918 26

Kansas 5,179 2,490 59

Kentucky 2,405 1,170 32

Louisiana 7,384 2,816 66

Maine 682 345 10

Maryland 3,557 1,777 41


Michigan 10,335 5,225 119

Minnesota 4,069 2,048 49

Mississippi 1,560 748 21

Missouri 3,384 1,731 45

Montana 9,606 4,558 102

Nebraska 1,151 545 15

Nevada 1,770 846 22


New Jersey6,936 3,444 71

New Mexico1,154 452 13

New York 15,088 7,469 148



Ohio 16,272 7,977 183

Oklahoma 2,612 1,122 30

Oregon 2,686 1,267 32



South Carolina 2,218 1,143 31


Tennessee 3,670 1,831 49

Texas 26,094 11,090 257

Utah 1,587 764 21

Vermont 344 173 5

Virginia 5,202 2,584 60

Washington 11,332 5,461 123


Wisconsin 20,473 9,878 223

Wyoming 698 226 6

Total US 313,787 149,425 3,451

$CAD Million


July 2012

TMX Expansion Case

Table A.5: Total Economic Impacts by US PADD Region TMX Case

Figure A.3: Cumulative Jobs Created and Preserved in the US TMX Case

Thousand

Person Years

GDP Compensation of

Employees

Employment

PADD I 84,519 41,926 956

PADD II 135,937 66,018 1,526

PADD III 44,319 18,669 451

PADD IV 22,414 10,541 246

PADD V 55,932 26,260 596

Total US 343,122 163,414 3,776


0

50

100

150

200

250


July 2012

Table A.6: Total Economic Impacts by US State TMX Case

Thousand

Person Years

GDP Compensation of

Employees

Employment

Alabama 2,812 1,386 38

Alaska 1,012 282 7

Arizona 3,846 1,868 47

Arkansas 1,618 764 22

California 32,984 15,440 339

Colorado 8,812 4,176 95


Delaware 1,019 412 9


Florida 11,364 5,484 143

Georgia 6,163 3,118 77

Hawaii 908 422 12

Idaho 833 416 12

Illinois 51,676 24,882 542

Indiana 5,394 2,642 64

Iowa 2,261 1,017 29

Kansas 5,589 2,689 63

Kentucky 2,661 1,296 35

Louisiana 8,104 3,044 72

Maine 752 383 12

Maryland 3,920 1,963 46


Michigan 11,267 5,719 130

Minnesota 4,497 2,270 54


Missouri 3,746 1,922 50

Montana 10,242 4,859 109

Nebraska 1,275 603 17

Nevada 1,957 936 24


New Jersey 7,672 3,818 78

New Mexico 1,282 497 14

New York 16,692 8,281 162



Ohio 17,646 8,669 199

Oklahoma 2,899 1,238 34

Oregon 2,985 1,408 36





Tennessee 4,064 2,032 54

Texas 28,785 12,154 282

Utah 1,751 844 23

Vermont 380 192 5

Virginia 5,739 2,857 67

Washington 12,240 5,904 132


Wisconsin 21,955 10,607 239

Wyoming 777 246 6

Total US 343,122 163,414 3,776

$CAD Million


July 2012

Northern Gateway Case

Table A.7: Total Economic Impacts by US PADD Region Northern Gateway Case

Figure A.4: Cumulative Jobs Created and Preserved in the US Northern Gateway Case

Thousand Person

Years

GDP Compensation of

Employees

Employment

PADD I 95,746 47,594 1,084

PADD II 149,325 72,643 1,680

PADD III 49,944 20,883 506

PADD IV 24,412 11,468 268

PADD V 62,986 29,550 670

Total US 382,413 182,138 4,209


0

50

100

150

200

250


July 2012

Table A.8: Total Economic Impacts by US State Northern Gateway Case

Thousand Person

Years

GDP Compensation of

Employees

Employment

Alabama 3,202 1,580 43

Alaska 1,157 313 7

Arizona 4,359 2,119 53

Arkansas 1,840 868 25

California 37,420 17,504 383

Colorado 9,659 4,576 105


Delaware 1,151 461 10


Florida 12,831 6,197 163

Georgia 6,975 3,539 88

Hawaii 1,016 471 13

Idaho 953 477 14

Illinois 55,807 26,905 584

Indiana 6,159 3,019 73

Iowa 2,595 1,165 33

Kansas 6,091 2,934 69

Kentucky 3,033 1,478 41

Louisiana 9,032 3,331 79

Maine 850 434 13

Maryland 4,422 2,220 52


Michigan 12,568 6,406 146

Minnesota 5,108 2,585 62


Missouri 4,257 2,192 58

Montana 10,937 5,188 116

Nebraska 1,451 686 19

Nevada 2,204 1,054 27

New Hampshire 1,075 570 14

New Jersey 8,676 4,328 88

New Mexico 1,463 562 16

New York 18,892 9,392 183



Ohio 19,449 9,579 220

Oklahoma 3,303 1,404 38

Oregon 3,469 1,636 42





Tennessee 4,640 2,325 62

Texas 32,468 13,611 315

Utah 1,980 955 26

Vermont 432 219 6

Virginia 6,476 3,232 75

Washington 13,360 6,453 145

West Virginia 1,008 486 14

Wisconsin 23,717 11,476 258

Wyoming 882 273 7

Total US 382,413 182,138 4,209

$CAD Million


July 2012

Appendix B CERI Provincial Input-Output Model

What is an Economic Input-Output Model? W. Leontief [1937] describes the Input-Output (I/O) model as a computable version of Walras General Equilibrium; this model is more often linked to classical theories, such as those of Quesnay’s Tableau Économique and Marx’s reproduction equations. The focus on the entire economy gives I/O analysis a macroeconomic flavour, but its technique and foundations are more microeconomic. The production and consumption functions are derived from microeconomic analysis. Therefore, some people argue that I/O is at the interface of the two

and categorize it as “mesoeconomics”.1 In Canada, the first national I/O table was published in 1969 for the reference year 1961. After 1996 Statistics Canada improved the provincial and economic statistics by using sub-national surveys and other improved sources and methods. The reliability of the tables was improved beginning with the reference year 1997. Since 1997, the Input-Output and the interprovincial trade flow tables have been compiled and published annually for each province and territory in Canada. The national level I/O table is the simple aggregation of the provincial and territorial tables. After 1996, industries in the I/O tables were classified using the North American Industry Classification System (NAICS). I/O accounts consist of three tables: Make (output), Use (input), and Final Demand. They are

available at four different levels:

1. Worksheet level: includes 299 industries, 170 final demand categories, and 725 commodities

2. Link level: includes 113 industries, 120 final demand categories, and 476 commodities 3. Medium level: includes 64 industries, 37 final demand categories, and 109 commodities 4. Small level: includes 25 industries, 13 final demand categories, and 57 commodities

At the W, L, and M levels of detail, some of the entries in national matrices are confidential. Consequently, data are provided to users after suppressing the confidential information at the S level.

The Final Demand table shows transactions in goods and services for final use in the economy, as well as for all exports (irrespective of whether those exports are reserved for final demand elsewhere). A transaction is considered to be for final use if the good or service is exported or purchased for final consumption or capital investment. While purchases by households (other than housing itself) are considered to be final use, businesses, government, and other entities

1The term is a combination of “meso” which means “middle” and “economics”.


July 2012

purchase services and commodities both for final and intermediate uses. Their intermediate

purchase is reflected in the Use table and their final use appears in the Final Demand table.

The Use table presents the intermediate purchases by industries for production of their goods and services. Such purchases are non-capital expenditures of the industries, and include property tax, indirect taxes, wages and salaries, and subsidies.

The Make table records the values of production of goods and services in each industry. The term industry covers all entities in the economy except for households.

The following simple equation illustrates the relationship between the products in the I/O matrices:

Products in Make matrix = Products in Use matrix + Products in Final Demand matrix

Impact Analysis Modeling Any activity that leads to increased production capacity in an economy has two components: construction (or development) of the capacity, and operation of the capacity to generate outputs. The first component is referred to as investment, while the second is either production or operation. Both activities affect the economy through purchases of goods and services, as well as labour. Figure B.1 illustrates the overall approach CERI uses to assess economic impacts resulting from these activities.

The first step is to estimate and forecast the value of investment (i.e., construction or

development expenditure) and production (sales). The total investment or development expenditures are then disaggregated into purchases of various goods and services directly involved in the production process (i.e., manufacturing, fuel, business services, etc.) as well as labour required, using the expenditure shares. Similarly, the value of total production (output or sales) from a production activity (i.e., conventional oil production, petroleum refinery, etc.) is allocated to the purchase of goods and services, payment of wages, payments to government (i.e., royalty and taxes), and other operating surplus (profits, depreciation, etc.).

The forecasted values of investment and production are then used to estimate demand for the various goods and services, and labour used in both development and production activities. These demands are met through two sources: (i) domestic production, and (ii) imports. Domestic contents of the goods and services are calculated using Statistics Canada’s (StatsCan)

data.

The estimated bi-national trade flow tables, developed by CERI, are used to derive import or export of each type of good and service for all 13 provinces and territories in Canada plus Government Abroad and the United States (US) at the national level. The value of goods and services used by a particular industry and produced in a different province or territory in Canada (or a state in the US) can then be calculated. This method captures the trade supply


July 2012

chains among all trading partners in Canada and the US, as well as their feedback effects. The

latter are changes in production in one region that result from changes in intermediate and final demand in another region, which are in turn brought about by demand changes in the first region.

In this exercise, the investment and operation dollars are initially determined on a project basis. For example, in the case of the oil sands industry, the dollars are allocated to Mining and Extraction, In Situ, Integrated Mining and Upgrading, and the Stand-Alone Upgrading categories. Investment and operations spending stimulate Alberta’s economy in various sectors simultaneously, including the Oil Sands, Construction, Refinery, and Manufacturing sectors. The relationship between the oil sands and the pipeline and refining industries is captured in the base economy, and thus inducement on the supply side results in impacts on these industries.

Investment in Alberta also impacts the US economy; these impacts can be identified at the sector level. The US Bureau of Economic Analysis (USBEA) data is used to link these impacts at both the state and industry levels in the US. Thus, refinery upgrades required in order to handle heavier oil sand crudes are not reflected in the model, but generic refinery upgrades are implicitly accounted for in the indirect impact of investment in oil sands development upon activity in the refinery sector (both in Canada and the US). No direct shocks are made to the US sectors.


July 2012

Figure B.1: Overall Bi-National Multi-Regional I/O Modeling Approach

Total Impact on Canada’s

Economy (GDP, Employment,

Demand for Goods & Services

Government Revenues)

Impacts on Alberta’s Economy (GDP, employment, demand for goods & services Government revenues) including trade flow impact of other provinces & Territories in Canada Impacts on Ontario’s Economy (GDP, employment, demand for goods & services Government revenues) including trade flow impact of other provinces & Territories in Canada

Impacts on Quebec’s Economy (GDP, employment, demand for goods & services Government revenues) including trade flow impact of other provinces & Territories in Canada

Total Impact on the US

Economy (GDP,

Employment, Demand for

Goods & Services

Government Revenues)

……………………………

……………………………

…

Projection of investment and value of output at

the provincial and territorial level

Allocation of investment and outputs to goods,

services that are directly involved in the

production/investment process

Increased demand for labour, goods and services

in each province and territory of Canada and the

US at the national level

Symmetric I/O models of

each of the 14 Canadian

tables and the US at the

national level

Provincial and Bi-

National trade

Multi-regional I/O

table of the

US-Canada

US symmetric

national I/O table

Alabama

Alaska

Wyoming


July 2012

CERI’s US-Canada Multi-Regional I/O Model (UCMRIO 2.0) This section discusses the multi-stage process to build the UCMRIO 2.0 model. An earlier version of the model was developed in 2008, as a Multi-regional I/O model for the US and Canada for examining the economic impacts of the Canadian petroleum industry on Canada’s provinces and territories. CERI’s UCMRIO 2.0 model builds on the Multi-regional I/O model for Canada. The models’ structures are defined in the System of National Accounts (SNA) terminology as industry-by-industry, or “industry technology”, and share the following advantages:

Compatibility with economic theory; Recognition of the institutional characteristics in each industry; Preservation of a high degree of micro-macro link;

Maximization of the use of detailed information from the Supply (Make) and Use Tables (SUTs);

Comparability with other types of statistics; and Transparency of compilation method, resource efficiency, support for a wider and more

frequent compilation of input-output tables internationally.

Further, the UCMRIO 2.0 is different from its predecessor in the following aspects:

The I/O tables have been updated to the most recent available base year of 2006; the previous update was from 2003 data. In particular, the oil and oil sands industries have been adjusted to represent more current conditions. In the new model, the manual method of constructing I/O tables was replaced by using the balanced symmetrical I/O

tables from StatsCan. This provides consistency between provincial I/O tables and interprovincial trade flow matrix. The ultimate source of all UCMRIO 2.0 input-output tables and trade flow matrix is StatsCan.

The new model also includes a new provincial table, labelled as Government Abroad,2 which accounts for the impacts of Canadian military bases, commercial offices, and embassies abroad, on the Canadian economy.

The trade flow matrix has been enhanced, thus allowing for more accurate mapping of the trade relations between Canadian provinces and the US. For instance, the oil sands industry, which is one of the industries in the Canadian I/O tables, does not exist in the US tables. Therefore, during mapping of the trade flow matrix, it was verified that Alberta’s exports of oil sands were delivered to refineries in the US, rather than to a non-existent US oil sands industry. Mapping the trade flow represents a significant

improvement in the model and it is an important contribution to ensure that the appropriate provinces/states and industries are impacted. Better mapping of the energy

2Government Abroad includes activities that are part of the Canadian economy but do not have a natural and unambiguous

spatial boundary. They are classified as a fourteenth region, for purposes of provincial and territorial input-output tables. Examples include activities of Canadian embassies, the armed forces stationed abroad, and activities relating to offshore oil and gas extraction. These activities form a part of Canadian GDP, but are not assigned to any of the 13 provinces and territories.


July 2012

industry trade flows creates better mapping of the impacted sectors and regions in

Canada and the US.

Overall, the model formulation and approach have been enhanced to capture the relations among various sectors and local economies of different regions with increased precision. This set of procedures is well documented, frequently cited, and commonly practiced in I/O literature. The new model’s structure is similar to the old version, however this latest edition of CERI’s I/O model allows for more flexibility, representing a more accurate picture and improved final results.

Building the Model

The following steps show how the bi-national UCMRIO 2.0 has been developed, and how one can trace direct, indirect, and induced effects of the Canadian energy sector on the Canadian

and US economies. The model provides insights at the provincial level for Canada and at the state level for the US.

Compilation of the bi-national UCMRIO 2.0 has the following steps:

1. StatsCan provides S level Symmetrical I/O tables (SIOTs) and Final Demand tables for 13 provinces and territories plus Government Abroad. Therefore, there are 14 regional tables for Canada plus one national table. Provincial data are only available at the S level due to confidentiality of more disaggregated data for some sectors in various provinces. The I/O tables used are at producer’s prices. CERI did not construct symmetrical tables from the Use and Make tables this time as the compiled tables were available. The base year for the I/O tables is 2006.3

2. SIOTs are balanced, so the use of inputs in the economy is equal to the production of outputs.

3. The US national Use and Make tables (2006) were sourced from the USBEA. These tables are at producer’s price, and consist of 67 sectors and 13 final demand categories. CERI compiled the US SIOT table and carefully combined industry sectors in order to arrive at 29 industry sectors, consistent with Canadian S-level aggregation.

The intermediate and final demand parts of the US SIOT table are constructed as follows:

B=V(diag(q-m))-1U and F=V(diag(q-m))-1Y

Where, B: Intermediate part of Use table transformed to symmetric I/O table format F: Final demand part of Use table transformed to symmetric I/O table format

3Use tables show the inputs to industry production and commodity composition of final demand. Make tables show the

commodities that are produced by each industry.


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V: Transpose of Make table excluding imports

U: Intermediate demand part of Use table Y: Final demand part of Use table q: Vector of total supply of products m: Vector of imports by products diag(q-m): Matrix with q-m on the diagonal By using these equations, the rectangular commodity by industry Use and Make tables are transformed to a symmetrical square I/O table and its corresponding final demand matrix.

4. In order to highlight the energy sectors in the US and Canadian provincial SIOTs, CERI disaggregated the “Mining and Oil and Gas Extraction’’ industry to five subsectors

including: Conventional Oil, Oil Sands, Natural Gas and LNG, Coal, and Other Mining. In the same fashion, the Manufacturing industry is broken into Refinery, Petrochemical, and Other Manufacturing.

5. Whereas the trade flow between Canadian provinces and territories was provided by StatsCan, the trade flow pattern between the individual provinces and the US was not. The data was gathered from a variety of sources and compiled by CERI into a trade flow pattern between the two countries. CERI is confident that the developed mapping portrays an accurate trade flow pattern, which is crucial for generating a credible impact analysis for the US in particular.

6. In the UCMRIO 2.0, an exchange rate is needed in order to link data from US and Canada to a common monetary basis. We use the average exchange rate between the US and Canadian dollar for the base year 2006 to convert the trade flow matrix to Canadian

dollars. However, parity is assumed for the exchange rate projection (see section on Exchange Rates in Chapter 2).

7. We combine 15 SIOTs (13 provincial tables, 1 for Government Abroad and 1 for the US at the national level) to compile one bi-national I/O matrix. The bi-national matrix is then merged with the trade flow matrix, and inverted to generate direct, indirect, and induced effect multipliers (see section on Multipliers).

Industries in the UCMRIO 2.0

The classification of industries in both the US and Canada is identical. Table B.1 provides a brief description of these sectors or commodities.


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Table B.1: Sectors/Commodities in CERI US-Canada Multi-Regional I/O Model

Serial No. Sector or Commodity Examples of activities under the sector or commodity

1 Crop and Animal Production Farming of wheat, corn, rice, soybean, tobacco, cotton, hay, vegetables and fruits; greenhouse, nursery, and floriculture production; cattle ranching and farming; dairy, egg and meat production; animal aquaculture

2 Forestry and Logging Timber tract operations; forestry products: logs, bolts, poles and other wood in the rough; pulpwood; custom forestry; forest nurseries and gathering of forest products; logging.

3 Fishing, Hunting and Trapping Fish and seafood: fresh, chilled, or frozen; animal aquaculture products: fresh, chilled or frozen; hunting and trapping products

4 Support Activities for Agriculture and Forestry

Support activities for crop, animal and forestry productions; services incidental to agriculture and forestry including crop and animal production, e.g., veterinary fees, tree pruning, and surgery services, animal (pet) training, grooming, and boarding services

5 Conventional Oil4 Conventional oil, all activities e.g., extraction and services incidental to conventional oil

6 Oil Sands Oil sands, all activities e.g., extraction and services incidental to oil sands

7 Natural Gas and NGL Natural gas, NGL, all activities e.g., extraction and services incidental to natural gas and NGL

8 Coal Coal mining, activities and services incidental to coal mining

9 Other Mining Mining and beneficiating of metal ores; iron, uranium, aluminum, gold and silver ores; copper, nickel, lead, and zinc ore. Mining; non-metallic mineral mining and quarrying; sand, gravel, clay, ceramic and refractory, limestone, granite mineral mining and quarrying; potash, soda, borate and phosphate mining; all related support activities

10 Refinery Petroleum and coal products; motor gasoline and other fuel oils; tar and pitch, LPG, asphalt, petrochemical feed stocks, coke; petroleum refineries

11 Petrochemical Chemicals and polymers: resin, rubber, plastics, fibres and filaments; pesticides and fertilizers; etc.

4Statistics Canada reports the oil, gas, coal, and other mining as one sector due to some confidentiality issues. CERI uses an in-

house developed approach to disaggregate this sector into five sectors: oil sands, conventional oil, natural gas + NGL, coal, and other mining.


July 2012


12 Other Manufacturing Food, beverage and tobacco; textile and apparel; leather and footwear; wood products; furniture and fixtures; pulp and paper; printing; pharmaceuticals and medicine; non-metallic mineral, lime, glass, clay and cement; primary metal, iron, aluminum and other metals; fabricated metal, machinery and equipment, electrical, electronic and transportation equipment, etc.

13 Construction Construction of residential, commercial and industrial buildings; highways, streets, and bridges; gas and oil engineering; water and sewer system; electric power and communication lines; repair construction

14 Transportation and Warehousing

Roads, railways; air, water & pipeline transportation services; postal service, couriers and messengers; warehousing and storage; information and communication; sightseeing & support activities

15 Transportation Margins Transportation margins

16 Utilities Electric power generation, transmission, and distribution; natural gas distribution; water & sewage

17 Wholesale Trade Wholesaling services and margins

18 Retail Trade Retailing services and margins

19 Information and Cultural Industries

Motion picture and sound recording; radio, TV broadcasting and telecommunications; publishing; information and data processing services

20 Finance, Insurance, Real Estate and Rental and Leasing

Insurance carriers; monetary authorities; banking and credit intermediaries; lessors of real estate; renting and leasing services

21 Professional, Scientific and Technical Services

Advertising and related services; legal, accounting and architectural; engineering and related services; computer system design

22 Administrative and Support, Waste Management and Remediation

Travel arrangements and reservation services; investigation and security services; services to buildings and dwellings; waste management services

23 Educational Services Universities; elementary and secondary schools; community colleges and educational support services

24 Health Care and Social Assistance

Hospitals; offices of physicians and dentists; misc. ambulatory health care services; nursing and residential care facilities; medical laboratories; child and senior care services

25 Arts, Entertainment and Recreation

Performing arts; spectator sports and related industries; heritage institutions; gambling, amusement, and recreation industries

26 Accommodation and Food Services

Traveler accommodation, recreational vehicle (RV) parks and recreational camps; rooming and boarding houses; food services and drinking establishments


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27 Other Services (Except Public Administration)

Repair and maintenance services; religious, grant-making, civic, and professional organizations; personal and laundry services; private households

28 Operating, Office, Cafeteria and Laboratory Supplies

Operating supplies; office supplies; cafeteria supplies; laboratory supplies

29 Travel, Entertainment, Advertising and Promotion

Travel and entertainment; advertising and promotion

30 Non-Profit Institutions Serving Households

Religious organizations; non-profit welfare organizations; non-profit sports and recreation clubs; non-profit education services and institutions

31 Government Sector Hospitals and government nursing and residential care facilities; universities and government education services; other municipal government services; other provincial and territorial government services; other federal government services including defence

US-Canada Trade Table and Model Structure

This section discusses the construction of the trade flow matrix, an important component to the modeling process. The trade flow matrix connects the US I/O table to the Canadian I/O tables, and depicts a trading pattern between each Canadian province or territory and the US. The trade flow table for UCMRIO depicts the export/import flows of each Canadian province with the entire US and with each other. In particular, the Alberta trade flow table shows the import (export) flows of Alberta from (to) other Canadian provinces and territories, as well as

the US. It is important to mention that the industry specification of this table is the same as SIOTs, and thus covers the trade flows among all sectors of the economies.

The following is a brief discussion of the modeling.

Based on a standard I/O model notation, and considering total gross outputs vector (X), and final demand vector (FD), the following relationship in I/O context holds as:

AX+FD = X→(I-A) × X=FD → X= (I-A)-1 × FD→ X= L×FD

Where; A is the matrix of input coefficients (n×n), I is identity matrix (n×n) and L is the Leontief inverse matrix (n×n). This is the core formula of the Leontief quantity model. This relationship estimates direct and indirect impacts for a single economy (i.e. no trade flow). We can expand

this model to include induced effects by endogenising the most important component of local final demand, namely private consumption. This captures the economic impact of increased consumption due to earned wages from new jobs. After endogenising the private consumption expenditure we arrive at the following relationship:

X= (I-A-PCE)-1 × FD*


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We use PCE for private consumption expenditure matrix and FD* for the exogenous part of the

final demand.

We can extend the model to involve other economies (regions) by incorporating the interregional trade flow matrix C(n×n). After several steps of calculation, we arrive at the final interregional formula:

X= (I-C × A-C × PCE)-1 × C × FD*

In order for the above equation to have a finite solution, (I-C × A-C × PCE) must be a nonsingular matrix.5 As is the case for standard I/O models, the impact of an industry, such as the oil sands industry, is calculated by modeling the relationship between total gross outputs and final demand as follows:

∆ X= (I-C × A-C × PCE)-1 × C × ∆FD* (Equation 1)

Where:

X -- Changes (or increases) in total gross outputs of the US and all provinces and territories, at the sectoral level, due to construction and operation of projects (i.e., oil sands). Dimension n=465 so this vector is a 465×1 vector.

I – is a 465×465 identity matrix, unity for diagonal elements and zero for off-diagonal elements.

A – is a 465×465 block diagonal matrix of technical coefficients at the sectoral level for the US

and Canada. It is composed of 15 blocks so that each block is a 31×31 matrix corresponding to the US and each province’s (or territory`s) input technical coefficient matrix.6 An element of such a matrix is derived by dividing the value of a commodity used in a sector by the total output of that sector. The element represents requirements of a commodity in a sector in order to produce one unit of output from that sector.

PCE – is a 465×1 vector at the sectoral level for Canada and the US. Each of its elements measures the private consumption expenditure share of a sector’s total gross output by jurisdiction (province, territory or the US).

C – is a 465×465 transposed matrix of multiregional trade coefficients. It includes import and export shares of a sector’s total output in the US and each province or territory. Each element

on the row of this matrix measures the share of export to a particular sector in the US or a province/territory from a given sector in another province/territory or the US.7

5For further information on Interregional I/O analysis please see Hertwich and Peters (2010), Miller and Blair (2009), CERI Study

No. 120 (2009), Oosterhaven and Stelder (2008), and Sim, Secretario, and Suan (2007). 6In other words, one can say all 14 Canadian tables (13 provinces and 1 Government abroad) and one US input technical

coefficients matrices are stacked together in construction of a diagonal block matrix at the national level. 7In particular, this matrix is a bridge matrix which connects the US, or any province, to other provinces through import and

export coefficients. See Miller and Blair (2009).


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FD* – is a 465×1 vector of changes (or increases) in the exogenous part of final demand at the

sectoral level. Outputs from Canada and the US resulted from any change in the final demand components in the US or any province or territory, including commodities directly demanded (or purchased) for the construction and development of any sector are captured in X.

The calculation of total impact is based on the multiplication of direct impact and the inverted matrix. Based on the direct impact on a sector, Equation 1 above is used to estimate all the direct, indirect, and induced effects on all sectors in all provinces, particularly in terms of changes in consumption, imports, exports, production, employment, and net taxes. The direct impact is referred to as ∆FD* in Equation 1. The change in final demand (∆FD*) consists of various types of investment expenditures, changes in inventories, and government expenditures. In the current model, the personal expenditures are not part of the final demand

and have been endogenised to accommodate the induced impact.

Direct impacts are quantitative estimations of the main impact of the programs, in the form of an increase in final demand (increase in public spending, increase in consumption, increase in infrastructure investment, etc). The assumption of increased demand includes a breakdown per sector, so that it can be translated into the following matrix notation:

Direct, indirect, and induced impacts:

∆ X= (I-C × A-C × PCE)-1 × C × ∆FD* (Equation 2)

Direct and indirect impacts:

∆ X= (I-C × A)-1 × C × ∆FD (Equation 3)

The difference between Equation 2 and 3 is referred to as the induced impact of any changes in final demand components.

Once the impact on output (change in total gross outputs) is calculated, the calculation of impacts on GDP, household income, employment, taxes, and so forth, are straightforward. In particular, as previously mentioned, the base year for the I/O tables used in this report is 2006.

CERI utilizes the tax information derived from these tables and federal and provincial tax information from the Finances of the Nation, where these numbers reflect the tax structure of the Canadian economy in the year 2006.8 CERI acknowledges that there have been changes, notably to the corporate income tax structure and the goods and services sales tax (GST) since 2006. The new tax regime will result in changes in tax impacts as business responds to the new incentives. Therefore tax estimates should be interpreted on a 2006 basis.

8Canadian Tax Foundation; Finances of the Nation; 2006, 2007 and 2008.


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These impacts are estimated at the industry level using the ratio of each (GDP, employment,

etc.) to total gross outputs. Using the technical Multi-Regional I/O table, CERI is able to perform the usual I/O analysis at the provincial and national levels.

Disaggregation of National Results for the US To report the US economic impacts down to the state level, CERI constructed a series of disaggregating coefficients. This process allows CERI to illustrate the economic impacts of the oil sands developments in Canada, on each US state’s economy.

The USBEA publishes detailed information on the sectoral GDP, employment, and compensation of employees for the US states.9 CERI used the base year data (year 2006) to establish a series of coefficients to disaggregate the national figures to state levels. For instance, to disaggregate national agricultural GDP among all states, CERI uses a set of 51 share

coefficients, one for each state and the District of Columbia, in order to disaggregate the national numbers. It is evident that the sum of these coefficients is equal to unity and they depict the share of each state in the GDP of the US economy.

This approach, which has been used in UCMRIO 1.0, is not without its flaws. The main concern was that the model splits the impact of the Canadian Energy Industry (Oil Sands, Conventional Oil, and Natural Gas) among the US states based on only the size of their economies. As a result, large economies such as California, Texas, New York, and Florida will be affected more than the rest of the states, and impacts on states like Illinois, Michigan, Ohio and Washington, which are smaller but have a larger share of total US-Canada energy trade, will be understated. CERI was able to address this problem in the new UCMRIO 2.0.

In UCMRIO 2.0, we employed a disaggregation method, which provides impacts for the states with the strongest ties to the Canadian energy sector through identifying who are the main Canadian partners among the US states. In particular, we map the supply of capital goods and services from the US states to the Canadian energy industry, as well as demand for Canadian natural gas and oil by state. As a result, CERI was able to disaggregate the indirect impacts of the Canadian energy sector on the US economy. For the induced effects in the US, we assume that the income earned by US employees who work for businesses that are involved with the Canadian oil and gas industry will be spent on commodities that will be produced uniformly throughout the US. Following this procedure, we use the relevant share coefficients to estimate the sectoral employment, and compensation of employees.

Interpretation of the US Impacts The impacts of the Canadian Energy Sector on the US economy consist of the amount of GDP, employment, government revenue, household income, and export volumes that is generated in the US as a result of new spending, or export in the Canadian energy sector. For example, one additional dollar in Canadian oil sands production which will be consumed in Canada or the US requires inputs from other linked industries and primary input sources like labor and capital.

9See http://www.bea.gov/regional/gsp and http://ww.bea.gov/regional/spi.

http://www.bea.gov/regional/gsp

http://ww.bea.gov/regional/spi


July 2012

These input sources and linked industries are either in Canada or the US.10 The linked industries

in the US also require inputs from other linked industries in Canada and the US in order to produce goods and services that were demanded in the first place. There will be further subsequent rounds of spending, and this will continue with the amount of money circulating getting smaller at each successive round of activity as money leaks out of the economy in the form of savings and imports, until the amount of money circulating in the economy as a result of the initial energy spending becomes negligible. However, during this process, jobs will be created in the US, and income earned from these jobs will be spent on all sorts of commodities. As a result, the impact on the US economy is the result of the initial one dollar of gross output in Canada.

The model assumes that a fraction of the new Canadian oil sands production will be imported

by US refiners. Thus, newly produced Canadian barrels either displace a fraction of the US import of crude oil from the rest of the world or constitute a supply that prevents US refining capacity from having to lie idle. In the latter case, the imported barrels from Canadian oil sands will create and/or support part of the GDP, jobs, etc., currently supported by the imported oil from other origins. This replacement support is not captured by the conventional I/O analysis to the full extent. The fixed economic structure of I/O tables in base year 2006 constrains the magnitude of impact. It implies that the marginal response of the US industries as a result of oil sands production in Alberta is equivalent to the average relationship observed in the base year. CERI finds that Canadian oil sands could essentially replace US imports of oil from offshore sources. This enhances oil trade between Canada and the US, and implies a different trade flow pattern in the future compared to the base year. As a result, CERI utilizes a procedure to capture this “upper bound support effect”, which recognizes the economic impacts of the

Canadian oil sands industry if all new bitumen/SCO barrels were exported to the US. This estimation only provides an upper limit for the impacts on US.

UCMRIO 2.0 Multipliers Table B.2 summarizes the I/O multipliers, which have been employed to investigate the impacts of the oil and gas industry on the US and Canadian economies. UCMRIO 2.0 multipliers are consistent with StatsCan, RIMS II and IMPLAN.11 Note that the UCMRIO 2.0 is a bi-national multiregional model, so it is capable of estimating the cross border spillover impacts. Therefore, we report two types of multipliers for our model. The UCMRIO 2.0 multipliers indicate that most of the economic impact from a new shock stays in the country of origin. One dollar investment in oil sands in Alberta has a relatively higher impact on the economy in the US compared to the impact on the Canadian economy of $1 investment in the US oil industry (i.e.

0.24 vs. 0.05). Almost 90 percent of the impact stays in Canada when the oil industry in Canada is stimulated; this compares to 98 percent of impacts remaining in the US when the oil industry in the US is shocked. This finding is consistent with existing literature. For Instance, Japan’s Ministry of Economy, Trade and Industry (METI) compiled a US-Japan I/O table in 2005 in order

10

We do not study impacts on Rest of the World (ROW), because it is exogenous according to our assumption. 11

For more information on Regional Input-Output Modeling System (RIMS II) see https://www.bea.gov/regional/rims/. For Impact Analysis for Planning (IMPLAN) see http://implan.com/V4/Index.php.

https://www.bea.gov/regional/rims/

http://implan.com/V4/Index.php


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to analyze interdependence among various industries in both countries. One of their findings

was that, on average, 98 percent of total economic impact of a change in final demand stays in the country of origin.12

Table B.2: Oil and Gas I/O Multipliers for Canada and the US

Country/State of the Original Shock

Output

Value Added (GDP)

Source

Alabama (Offshore Oil and Gas) 1.5 Joseph R. Mason - RIMS II

Kansas (Oil and Gas) 1.5 Timothy R. Carr - RIMS II

Louisiana (Offshore Oil and Gas) 1.79 Joseph R. Mason - RIMS II

Mississippi (Offshore Oil and Gas) 1.53 Joseph R. Mason - RIMS II

Ohio (Oil and Gas) 1.97 Kleinheinz & Associates

Oklahoma (Oil and Gas production) 1.61 1.03 (est.) Mark C. Snead - IMPLAN

Pennsylvania (Oil and Gas) 1.56 Pennsylvania Economy League - IMPLAN

Texas (Offshore Oil and Gas) 2.07 Joseph R. Mason - RIMS II

PADD II- United States (Oil and Gas) 2.12 1.16 BEA-RIMS II

United States (Offshore Oil and Gas) 2.39 Joseph R. Mason - RIMS II

Canada (Mining , Oil and Gas) 1.52 1.04 Statistics Canada

United States (Oil) - US national impact - Canada impact

2.78 0.05

1.5 0.03

CERI-UCMRIO 2.0

Canada - Canada impact (Oil/Oil Sands) - US national impact

1.77 0.24

1.00 0.11

CERI-UCMRIO 2.0

All multipliers are Type II, according to RIMS II definition and with respect to initial outlay.

Data Sources This section briefly reviews data sources used to compile data for Canada and the US. As previously mentioned, the annual US I/O tables are available through the USBEA. The Make, Use, and Final Demand tables are quite detailed at the industry level and have been available since 1947. The 85-industry, 365-industry, and 596-indusry are just a few examples of table formats issued by the USBEA. Statistics are in compliance with the definitions of the 1997 North American Industrial Classification System (NAICS).

The Use table shows the inputs to industry production and the commodities that are consumed by final users. The Make table, on the other hand, depicts the commodities that are produced

by each industry. In this report we use the Make and Use table to construct the US symmetric I/O table consistent with the Canadian Multi-provincial I/O tables developed by CERI.

The National Accounts and I/O tables in Canada were also developed at the end of the Second World War. Tables in the present format, however, were first published in 1969 for the base year 1961. The I/O accounts are one of four main accounts that are published by Canada’s

12

See http://www.meti.go.jp/english/statistics/tyo/kokusio/index.html

http://www.meti.go.jp/english/statistics/tyo/kokusio/index.html


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System of National Economic Accounts (CSNEA), the others being income and expenditure

accounts, financial and wealth accounts, and balance of payments accounts.

The I/O accounts are calculated at the national, provincial, and territorial level on an annual basis only.13 These tables are available at different levels of aggregation14 on the Canadian Socio-Economic Information Management System (CANSIM) Tables 381-0009 to 381-0014. Provincial I/O data are also available on an occasional basis.

The framework of both the US and the Canadian I/O system is complementary and consists of the following three basic tables:

Gross output of commodities (goods and services) by producing industries; Industry use of commodities and primary inputs (the factors of production, labour and

capital, plus other charges against production, such as net indirect taxes); and Final consumption and investment, plus any direct purchases of primary inputs by final

demand sectors.

Figure B.2 is a schematic of the I/O system, and combines features of both the US and Canadian system and the more traditional single matrix presentation.

13

The I/O tables and models, published annually by Statistics Canada, are entitled “The Input-Output Structure of the Canadian Economy”. This document covers the basic concepts related to the I/O tables. Each year, two years of data are reported; the latest year is considered preliminary and the previous one is considered final. There are also many documents which are available on request from the I/O division. 14

The I/O Tables of this publication are stored in CANSIM at the Small (S) level, Medium (M) level and Link (L) level of aggregation.


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Figure B.2: Schematic of the Input-Output System

Input-Output Tables

Industries

Industries

Final

purchasers G

ross O

utp

ut

Co

mm

od

ities

Commodities made by industry

Commodities used by industry

Commodities used by

final purchasers

+ =

+ +

Industry use of primary

factors +

Final use of primary

factors =

GDP

Gross

Output GDP

Source: A User Guide to the Canadian System of National Accounts, Statistics Canada, Catalogue No. 13-

589E, November 1989.

Assumptions and Limitations The main assumption of any I/O analysis is that the economy is in equilibrium. Despite partial equilibrium analysis, it is assumed in the general equilibrium (GE) approach that the economy as a whole is in equilibrium. This is a realistic assumption in the long run, as it is difficult to imagine an economy remaining in disequilibrium for a long period of time.

A second important assumption in I/O analysis is the linear relationship between inputs and outputs in the economy. Each sector uses a variety of inputs in a linear fashion in order to produce various final products under the assumption of fixed proportions. Though the form of the “Leontief production function” is simple, it could be viewed as an approximation of the real world’s production function. Unlike other production functions, the Leontief production function contains no provision for substitution among inputs. A very interesting aspect of this assumption is the constant return to scale (CRS) property of the Leontief production function,


July 2012

which turns out to be a proven property in the real world economy. Though the linearity of the

production function gives a constant average and marginal products, these are justified if the analysis focuses on the long run rather than the short run.

Although the I/O approach has been widely used around the world for economic impact assessment, there are certain limitations that should be noted. I/O matrices are limited to the estimation effect on demand, rather than supply. Therefore, they do not take into account important objectives such as lasting effects on productive potential. Most effects on supply, which are likely to lead to a sustainable increase in the growth rate of assisted sectors (or provinces/states) and enable them to catch up with more developed sectors (or provinces), are completely disregarded. Some of these overlooked points include: the creation of new productive capacity, improvement of the training and education of the workforce, construction

of infrastructure, productivity gains throughout the economy, spread of technological progress, and intensity of high-tech activities in the productive sector. All these effects on supply can transform productive capacity in a lasting and irreversible manner. These cannot be estimated using this multi-regional I/O tool.

In particular, several other well-known limitations of the I/O approach are discussed below:

Static relationships. I/O coefficients are based on value relationships between one sector’s outputs to other sectors. The relationship and, thus, the stability of coefficients, could change over time due to several factors including:

Change in the relative prices of commodities; Technological change;

Change in productivity; and Change in production scope and capacity utilization.

Since these attributes cannot be incorporated in a static I/O model, these models are primarily used over a short-run time horizon, where relative prices and productivity are expected to remain relatively constant. Hence, over a longer period, static I/O models are not the best tools for economic impact analysis. GE models or macroeconomic models accounting for the factors mentioned above could be more appropriate. Moreover, I/O models and other static macroeconomic models and general equilibrium models do not account for sectoral dynamics and adjustment in an economy.

Unlimited resources or supplies. The I/O approach simplistically assumes that there are no supply or resources constraints. In reality, increasing economic activities in a particular sector of the economy may put pressure on wages and salaries in the short run. However, in the long run, the economy adjusts through the mobility of the factors of production (i.e., labour and capital).

Lack of capacity to capture price, investment, and production interactions. An I/O model is incapable of representing the feedback mechanism among price change, investment, and


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production. For example, an increase in oil price provides a signal to investors to increase

investment. The increase in investment would add productive capacity (more drilling) and also the production. However, this type of interaction cannot be modeled in a simple I/O model.

part i - impacts of oil sands production - final july 2012

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