CANADIAN ENERGY RESEARCH INSTITUTE

PACIFIC ACCESS: PART II – ASIA-DIRECTED OIL PATHWAYS AND

THEIR ECONOMIC IMPACTS

Study No. 129 – Part II July 2012

Canadian Energy Research Institute | Relevant • Independent • Objective

PACIFIC ACCESS PART II – Asia-Directed Oil Pathways and Their Economic Impacts

Pacific Access: Part II – Asia-Directed Oil Pathways and Their Economic Impacts

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 1-927037-07-2 Authors: Thorn Walden Jon Rozhon Zoey Walden Dinara Millington 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 pipeline economic impacts; Paul Kralovic of Kralovic Economics Inc.; 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.

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Table of Contents List of Figures .................................................................................................................. v List of Tables ................................................................................................................... vii Executive Summary ......................................................................................................... ix Trans Mountain Pipeline Expansion ................................................................................... ix Northern Gateway .............................................................................................................. x Chapter 1 Introduction .............................................................................................. 1 Background ......................................................................................................................... 1 Burgeoning Supply in a Constrained World .................................................................. 1 Crude Quality Issues ..................................................................................................... 3 The Shift in US Crude Bulk Movements ........................................................................ 3 Solving the American Dilemma and the Case for Pacific Access ........................................ 5 Increasing Asian Energy Demand.................................................................................. 5 Transportation to the Pacific Coast .............................................................................. 7 Trans Mountain Pipeline Expansion ............................................................................. 7 Northern Gateway Pipeline .......................................................................................... 9 Canadian National Railway’s (CN’s) “Pipeline on Rail” ................................................. 12 Research and Report Organization ..................................................................................... 14 Chapter 2 Transportation Options and Markets ......................................................... 17 General Background ........................................................................................................... 17 The Roles of Rail and Trucking ............................................................................................ 17 Crude Oil by Railway ........................................................................................................... 23 Canadian Railway Company Interests........................................................................... 23 US Railway Transport and US Bakken ........................................................................... 25 Other Routes and Other Markets ....................................................................................... 28 Canada’s East Coast ...................................................................................................... 28 Atlantic Coast of the United States ............................................................................... 29 Gulf Coast of the United States .................................................................................... 30 California ....................................................................................................................... 31 Chapter 3 Regional Input-Output Methodology and Assumptions .............................. 33 Provincial and Regional I/O Methodology .......................................................................... 33 Capital Costs and Operation Investment Assumptions ...................................................... 37 Kinder Morgan TMX ...................................................................................................... 37 Northern Gateway ........................................................................................................ 39 Chapter 4 Economic Impacts of Pipeline Construction and Operation ........................ 45 TMX Pipeline Economic Impacts ......................................................................................... 45 TMX Provincial I/O Impacts .......................................................................................... 45 TMX Regional I/O Impacts ............................................................................................ 49 Northern Gateway Pipeline Economic Impacts .................................................................. 53 Northern Gateway Provincial I/O Impacts .................................................................... 53 Northern Gateway Regional I/O Impacts...................................................................... 57

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Chapter 5 Conclusions ............................................................................................... 61 Appendix A Economic Impacts in the US – TMX and Northern Gateway Pipelines Construction and Operation ........................................................................ 63 Appendix B Development of CERI Input-Output (I/O Models) ....................................... 67 What is an Economic Input-Output Model? ....................................................................... 67 Impact Analysis Modeling ................................................................................................... 68 CERI’s US-Canada Multi-Regional I/O Model (UCMRIO2.0) ............................................... 71 Building the Model ........................................................................................................ 72 Industries in the UCMRIO 2.0 ....................................................................................... 73 US-Canada Trade Table and Model Structure .................................................................... 76 Disaggregation of National Results for the US ................................................................... 79 Interpretation of the US Impacts ........................................................................................ 79 UCMRIO 2.0 Multipliers ...................................................................................................... 80 Data Sources ....................................................................................................................... 81 Assumptions and Limitations .............................................................................................. 83 Appendix C Regionalization of Data for Regional I/O Model ......................................... 87 Appendix D Oil Pipeline Capacities in Western Canada and Elsewhere in North America ....................................................................................................... 89 Appendix E Alternative Transportation Companies and Tolls ....................................... 95 CN Rail ................................................................................................................................. 96 Canadian Pacific .................................................................................................................. 98 BNSF Railway ....................................................................................................................... 98 Union Pacific ....................................................................................................................... 98 Appendix F Refinery Capacity and Requirements ......................................................... 101

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List of Figures 1.1 Western Canadian Export Pipelines and Oil Supply ..................................................... 2 1.2 Projected US Domestic Production as Estimated by the Annual Energy Outlook 2012 ........................................................................................ 5 1.3 Trans Mountain Expansion ........................................................................................... 8 1.4 Proposed Route of Northern Gateway ......................................................................... 10 1.5 CN’s Diluent “Pipeline on Rail” ..................................................................................... 13 1.6 Map of Transportation Options to the West Coast ...................................................... 14 1.7 Alberta Land-Use Framework Regions ......................................................................... 15 1.8 British Columbia Development Regions ....................................................................... 16 2.1 Transportation Mode, Cost and Flexibility ................................................................... 19 2.2 Rail and Pipeline Network Connecting Alberta to Gulf Coast and West Coast ............ 22 2.3 Major Pipelines Connecting Alberta to Gulf Coast and West Coast ............................. 22 2.4 US Weekly Rail Transportation of Petroleum and Petroleum Products ....................... 26 2.5 Projected Bakken Pipeline and Rail Capacity Relative to Forecast Oil Production ...... 27 3.1 Regional Mapping ......................................................................................................... 36 4.1 TMX Pipeline, Impact on Provincial GDP – Investment and Operations ...................... 46 4.2 TMX Pipeline, Jobs Created and Preserved in Canada through Pipeline Construction and Operation ......................................................................................... 47 4.3 TMX Pipeline, Impact on Employment – Investment and Operations ......................... 48 4.4 TMX Pipeline, Impact on Employee Compensation – Investment and Operations ..... 48 4.5 TMX Pipeline, Taxes Paid – Investment and Operation................................................ 49 4.6 TMX Pipeline, GDP by Region, BC – Investment and Operations ................................. 50 4.7 TMX Pipeline, Employment by Region, BC – Investment and Operations ................... 51 4.8 TMX Pipeline, GDP by Region, AB – Investment and Operations ................................. 52 4.9 TMX Pipeline, Employment by Region, AB - Investment and Operations .................... 52 4.10 Northern Gateway Pipeline, Impact on Provincial GDP – Investment and Operations .......................................................................................... 53 4.11 Northern Gateway Pipeline, Jobs Created and Preserved in Canada through Pipeline Construction and Operation ............................................................. 54 4.12 Northern Gateway Pipeline, Impact on Employment –

Investment and Operations .......................................................................................... 55 4.13 Northern Gateway Pipeline, Impact on Employee Compensation – Investment and Operations .......................................................................................... 55 4.14 Northern Gateway Pipeline, Taxes Paid – Investment and Operation ......................... 56 4.15 Northern Gateway Pipeline, GDP by Region, BC – Investment and Operations .......... 57 4.16 Northern Gateway Pipeline, Employment by Region, BC – Investment and Operations .......................................................................................... 58 4.17 Northern Gateway Pipeline, GDP by Region, AB – Investment and Operations .......... 59 4.18 Northern Gateway Pipeline, Employment by Region, AB – Investment and Operations .......................................................................................... 59

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A.1 TMX Pipeline, Jobs Created and Preserved in the US through Pipeline Construction and Operation ........................................................................... 63 A.2 Northern Gateway Pipeline, Jobs Created and Preserved in the US through Pipeline Construction and Operation ............................................................. 65 B.1 Overall Bi-National Multi-Regional I/O Modeling Approach ........................................ 70 B.2 Schematic of the Input-Output System ........................................................................ 83 D.1 Existing Pipeline Capacities and Production, Alberta ................................................... 90 E.1 North American Railway Map ....................................................................................... 95 E.2 Change in Direction of Oil in the United States ............................................................ 96 E.3 CN’s North American Railway Network ........................................................................ 97 E.4 Union Pacific’s Railway Network .................................................................................. 98 F.1 Generic Process Stream for a Refinery to Run Bitumen ............................................... 102 F.2 US Refineries ................................................................................................................. 105 F.3 Asia-Pacific Refineries ................................................................................................... 106

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List of Tables 1.1 Production Forecast of US Shale Production ................................................................ 4 1.2 Oil Demand Forecast by Country .................................................................................. 6 2.1 Comparison of Different Oil Transportation Types in the United States ..................... 20 2.2 Capacities and Required Fleet to Replace a 150,000 b/d Pipeline

1,000 Miles Long ........................................................................................................... 21 2.3 US Refinery Receipts by Method of Transportation for the Year 2010 ........................ 23 2.4 Distances in Nautical Miles to Shanghai from Various Ports ........................................ 28 2.5 Atlantic Coast Refineries with Asphalt or Coking Capability ........................................ 30 3.1 TMX Expenditures by Project Component.................................................................... 37 3.2 TMX Pipe Length Ratios by Region ............................................................................... 38 3.3 TMX Material Sources ................................................................................................... 38 3.4 TMX Capital Investments by Region and Year .............................................................. 39 3.5 TMX Operating and Sustaining Capital Expenditures by Region .................................. 39 3.6 Kilometres in Each Region as Defined by the Northern Gateway Application and Regions as Defined for CERI’s Regional Model ...................................................... 40 3.7 Northern Gateway Other Region Estimates ................................................................. 42 3.8 Northern Gateway Capital Expenditures by Region and Year for Alberta and BC ....... 42 3.9 Northern Gateway Capital Expenditures Outside of Alberta and BC ........................... 43 3.10 Northern Gateway Operating and Sustaining Capital for Each Region ........................ 43 A.1 TMX Pipeline, Total Economic Impact of Pipeline Construction and Operation by US PADD ........................................................................................... 63 A.2 TMX Pipeline, Total Economic Impact by US State through Pipeline Construction and Operation ........................................................................... 64 A.3 Northern Gateway Pipeline, Total Economic Impact of Pipeline Construction and Operation by US PADD ..................................................................... 65 A.4 Northern Gateway Pipeline, Total Economic Impact by US State through Pipeline Construction and Operation ............................................................. 66 B.1 Sectors/Commodities in CERI US-Canada Multi-Regional I/O Model .......................... 74 B.2 Oil and Gas I/O Multipliers for Canada and the US ...................................................... 81 D.1 Existing and Proposed Regional Pipeline Capacity in Alberta ...................................... 89 D.2 Existing Export Pipelines ............................................................................................... 91 D.3 Cushing Pipelines and Rail Into and Out of Existing and Proposed .............................. 92 E.1 Comparison of Tolls ...................................................................................................... 99 F.1 Crude Distillation Yields as Estimated from the TIAX Report of Different Crudes ....... 103 F.2 US Refinery Utilization Rate 2010 and API’s ................................................................. 104

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Executive Summary This study examines alternative transportation modes and markets. CERI’s Regional Input-Output (I/O) model is introduced in this study and used to calculate the potential economic impacts of construction and operation of two major proposed crude pipeline projects in Western Canada: the Trans Mountain Pipeline Expansion (TMX) and the Northern Gateway Pipeline.

• With the addition of the Keystone XL, the TMX, and the Northern Gateway Pipeline, Canadian overall crude export capacity would move from approximately 3.5 million barrels per day (MMbpd) in 2011 to more than 5 MMbpd by 2019.

• Alternative transportation networks are emerging in the North American market to relieve constraints at Cushing, Oklahoma and at rapidly developing shale oil plays in North Dakota, Colorado and Kansas. However, these options are more expensive than pipeline alternatives. Moreover, these markets have ready access to alternative supplies from either imported or shale oil crudes. A pipeline to tidewater on the Pacific Coast is the most economic way of reaching Asian refineries which are capable of accepting both bitumen and synthetic crude oil (SCO), as both pipeline and tanker distances to East Asian destinations are significantly shorter than can be achieved using other ports.

Trans Mountain Pipeline Expansion (TMX)

• Construction and operation of the TMX pipeline will bring more than $8 billion in total additional GDP to the Canadian economy over the next 25 years; $4.4 billion of that amount will go to BC, $2.4 billion to Alberta, and $523 million to Ontario.

• Of all regions in BC, Thompson/Okanagan will see the most direct GDP benefit from TMX construction and operation – with $980 million over the next 25 years.

• Of all Alberta regions, Upper Athabasca will see the most direct GDP benefit from TMX construction and operation – over $500 million during the next 25 years.

• Employment in Canada (direct, indirect and induced) is expected to ramp up to 35,000 jobs at the peak of construction and settle down to 2,500 jobs during the operation phase.

• TMX will generate over $2 billion in tax revenues over the 25-year period, with $1.31 billion going to the Government of Canada, $522 million to provincial and municipal governments in BC, $134 million to provincial and municipal governments in Alberta, and $72 million to provincial and municipal governments in Ontario.

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Northern Gateway

• Construction and operation of the Northern Gateway pipeline will bring more than $8.9 billion in total additional GDP to the Canadian economy over the next 25 years; $4.7 billion of that amount will go to BC, $2.9 billion to Alberta, and $608 million to Ontario.

• Of all regions in BC, Nechako, closely followed by North Coast, will see the most direct GDP benefit from Northern Gateway construction and operation – Nechako earning $655 million over the next 25 years; North Coast – $575 million.

• Of all Alberta regions, Upper Peace will see the most direct GDP benefit from Northern Gateway construction and operation – $502 million over the next 25 years.

• Employment in Canada (direct, indirect and induced) is expected to ramp up to 30,000 jobs at the peak of construction and settle down to 2,500 jobs during the operation phase.

• Northern Gateway will generate over $2.3 billion in tax revenues over the 25-year period, with $1.45 billion going to the Government of Canada, $545 million to provincial and regional governments in BC, $162 million to provincial and municipal governments in Alberta, and $83 million to provincial and municipal governments in Ontario.

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Chapter 1 Introduction Background

Burgeoning Supply in a Constrained World Canada has proven reserves third only to Venezuela and Saudi Arabia, and in recent years the need has become apparent to find new markets and/or expand existing markets for growing crude supplies. The first of CERI’s Pacific Access reports, “Linking Oil Sands Supply to New and Existing Markets” (Study No. 129 – Part I) examined economic ramifications of increased oil/oil sands supply following the development of Western Canadian crude pipeline infrastructure projects. The report was based on the assumption that the Keystone XL (KXL) will go ahead after a delay and that the next generation of oil sands projects will be dedicated to that pipeline. Bitumen supply to the Pacific Rim would therefore need to come from the remaining approved projects and some of the announced ones. The analysis started with these upstream oil sands supply issues in conjunction with potential increase in conventional oil supplies that could affect capacity utilization on the various export pipelines. Figure 1.1 shows CERI’s forecast of production from all Western Canadian sources over the next 25 years and export pipeline capacity, both existing and proposed, out of Western Canada.1 The current pipeline capacity of 3.5 million barrels per day (MMbpd) will see the addition of KXL, and this will allow for 4.2 MMbpd of bitumen to be exported; with TMX online, the capacity will increase to almost 4.7 MMbpd, and with Northern Gateway operational, export capacity will reach close to 5.2 MMbpd. If all three pipelines are built, crude supply as forecast will reach pipeline capacity limits around 2021. With only KXL and TMX built, the limits will be reached by 2019, and if KXL is the only pipeline constructed, there will be no excess export capacity by 2018. With the current infrastructure, capacity would not be sufficient to carry growing crude volumes beyond 2015, less than three years from now; this would effectively stall new oil sands projects because there would simply be no room in existing pipelines to ship greater volumes of crude. If growth in the Canadian oil industry is to be continued, additional transportation is required.

1For an overview of Canadian pipeline systems, see Appendix D, “Oil Pipeline Capacities in Western Canada and Elsewhere in North America”.

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Figure 1.1: Western Canadian Export Pipelines and Oil Supply

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Note(s): 1)OperationalCapacity 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 move bitumen as per pipeline specifications.May 1, 2012

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Crude Quality Issues The lower quality of Alberta oil sands crudes has made it difficult to find existing markets in the US. Furthermore, despite Canada being well positioned, both geographically and politically, as a supplier to US markets, the reality is that refineries in the US Midwest (PADD II) that are served by the Enbridge pipeline cannot absorb significant additional imports of heavy feedstock without substantial investment in heavy feedstock upgrading capacity. Moreover, refineries are becoming obligated to meet clean fuel initiatives and other regulatory requirements, which further inhibit the addition of heavy crude refining capacity (because of their higher GHG and sulphur emission rates).2 As well, demand for petroleum products has been decreasing, which in turn provides little incentive to build more refining capacity in North America. This decrease has been attributed to increasing fuel efficiencies in cars and trucks, and higher product prices, partly due to the aforementioned stringent environmental standards.

The Shift in US Crude Bulk Movements Transportation options to serve markets beyond PADD II, as in the US Gulf Coast (PADD III), California (PADD V) and Asia are limited. Keystone and Keystone XL were designed to release some of the glut at Cushing en route to PADD III, but environmental issues such as impacts on the Ogallala aquifer in Nebraska have created significant delays. Without the addition of new pipeline capacity or other options to export crude oil, Canadian producers will continue to see severe discounts until the bottleneck at Cushing is relieved.3 In short, Western Canadian crude oil suffers from the difficulties of making a landlocked resource accessible to coastal and overseas markets where the crude could be priced based on other water borne imports into the US and not on the discounted WTI price.

In addition to the logistical problems of mobilizing land-locked bitumen, there has been an increase in conventional and shale oil production in North America. Oil shale production in the US has grown rapidly due to technological advances such as horizontal drilling and multi-fracing. This growth is expected to continue. Table 1.1 presents one production forecast. This dramatic change has pushed against the limits of current pipeline infrastructure. In response, industry has adapted by putting forth a number of project proposals, including new pipelines, expansions or modifications to existing systems and increased use of alternative transportation methods have been proposed in order to have sufficient capacity to move liquid hydrocarbons from producing regions to demand centers. These demand centers include traditional markets for Canadian crude, such as Eastern Canada, the US Midwest, and Washington State.

2 Laureshen, C, du Plessis, D.; Xu, C.; Chung, K. (2006) Asian-Pacific Markets – A New Strategy for Alberta Oil. Journal of Canadian Petroleum Technology. 45(1): 16-22. 3 CAPP (2011) Crude Oil Forecast, Market & Pipelines, June 2012.

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Table 1.1: Production Forecast of US Shale Production (Mbpd)

2011 2012 2015 2020 2030 Bakken/Three Forks 375 650 1040 1450 1250 Eagle Ford 125 180 420 520 580 Anadarko 67 130 230 420 560 Permian 56 80 260 480 820 Others 33 60 380 600 860 Total 656 1100 2330 3470 4070

Source: Advanced Resources International Inc.4

The EIA’s Annual Energy Outlook 2012 projects increased domestic production from the tight oil plays in the US on-shore and off-shore (see Figure 1.2). This contribution is significant and is expected to continue for at least a couple of decades. This, combined with increased Canadian unconventional production coming into the US, has resulted in a surplus of onshore supply displacing imported oils arriving by tanker. This has resulted in the decline of movements of crude from the Gulf of Mexico and imported crudes from PADD III to PADD II and pressure to move crude from PADD II to PADD III.5 PADD III is considered the ideal refining center for Canadian crudes due to its ability to handle heavy Mexican Mayan (a traditional import in PADD III) and Venezuelan Orinoco crudes. Since conventional crude movements, until recently, were northward, there has been a lack of takeaway capacity at Cushing to move crudes further south, so oil in storage at Cushing has reached record highs, creating a discount relative to coastal and overseas crude spot prices. PADD I and PADD V can be considered to a certain degree outside the crude oil pipeline network. PADD I has traditionally imported crudes or received refined products from PADD III while PADD V (with the partial exception of Washington State) has traditionally received oil from Californian heavy oil production, Alaskan North Slope6 production, or off-shore sources.

4 Van Leeuwen, T. 2012. The Revolution will be Quantified: Understanding the Tight Oil/Liquids Revolution. NCAC 16th Annual Energy Policy Conference. Accessed April 20th 2012 from http://www.ncac-usaee.org/pdfs/ 2012_04VanLeeuwen.pdf 5 EIA. (Feb 7 2012) PADD regions enable regional analysis of petroleum product supply and movements. Today In Energy. Accessed Feb 7th 2012 from http://www.eia.gov/todayinenergy/detail.cfm?id=4890&src=email 6 Trench, C.K. (2001) How Pipelines Make the Oil Market Work – Their Networks, Operation and Regulation. Allegro Energy Group.

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Figure 1.2: Projected US Domestic Production as Estimated by the Annual Energy Outlook 2012

Source: EIA

Solving the American Dilemma and the Case for Pacific Access

Increasing Asian Energy Demand Once oil makes it to tide water the cost of tanker movement is essentially uniform throughout the world (i.e. it costs approximately $1.50/bbl if one ships from America to Europe or America to the Middle East). There is a reason Asia is attractive as an export option because it houses some of the fastest-growing economies and expects increases in energy demand for decades to come. Asian energy demand reflects the region’s transition to developed-country status with developing countries such as China, India, Vietnam, Thailand and Malaysia contributing to the main share of demand growth. With limited proven oil reserves, Asia’s import capacity has increased. An estimate by the Institute of Energy Economics, Japan (IEEJ) of demand to 2015 is summarized below in Table 1.2.

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Table 1.2: Oil Demand Forecast by Country (Mbpd)

Country Oil Demand

2003 2010 2015 % Change 2003-2015

Japan 5,389 5,072 5,034 -7 Korea 2,313 2,399 2,560 11 China 5,304 8,722 10,791 103 Hong Kong 279 310 339 22 Taiwan 949 1,237 1,286 36 Singapore 742 909 1,036 40 Brunei 12 14 16 33 Indonesia 1,320 1,708 1,973 49 Malaysia 514 740 889 73 Philippines 328 378 474 45 Thailand 785 1,070 1,289 64 Vietnam 222 300 393 77 India 2,483 3,135 3,784 52 Other Asia 635 868 1,092 72 Total 21,274 26,856 30,955 46

Source: Zhang, Yue. 2008. An analysis of Asia’s Petroleum Refining Industry: Changes and Challenges. IEEJ; and CERI.

According to the IEEJ’s report, most of the refining capacity expansion plans in Asia are for primary distillation units, which would be incapable of upgrading and cracking bitumen to the more desirable middle distillates. Also, in light of stringent sulphur standards the units must also be equipped with hydro-desulphurization units. As Asia’s imports become heavier and contain more sulphur, Asian refineries will be required to expand the capacities of secondary distillation units to meet their demand under the required regulations.

However, China is unique in that its refining configuration has a large amount of cracking capacity (combined cat cracking to CDU of 47 percent). This high cracking/CDU ratio is due to the domestic crudes often being heavy and waxy. China’s ability to handle sour crudes has also increased in recent years, mostly through Sinopec. Of the above-mentioned capacities, 3.3 million b/d is sour crude refining capacity and 7 million is sweet. Furthermore, some of China’s current capacity has been idle in the last couple of years due to scale inefficiencies of “teapot” refineries relative to the refineries owned by China’s national energy corporations.7

The ideal oil barrel for Chinese refiners is a slate of the Middle Eastern (ME) crudes. With the ME increasing refining of heavy crudes, this decreases their availability to export markets,

7 Wu, Kang. 2011. “Capacity, complexity expansions characterize China’s refining industry past, present, future”. Oil & Gas Journal. 10: 78.

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leaving opportunities for Canadian crudes to compete in Chinese markets.8 Furthermore, China has always been concerned with securing resources for domestic consumption. With volatility in the ME, Iran’s threats on the Strait of Hormuz, pressures to utilize clean energy, the Fukushima disaster, and many other factors, China is looking to secure a long-term reliable source of oil9. This, combined with China’s extensive heavy crude processing capabilities suggests a fit between Canada’s unconventional crude sources and China’s energy demands.

Transportation to the Pacific Coast Non-OECD countries (especially Asia) have been contributing extensively to the global energy demand. The addition of extensive refining capacity in China as well as premium oil prices have led Canadian producers to seek transportation options that provide access to Asian markets via British Columbia’s West Coast. The proposals to move crude oil out of oil-producing regions of Western Canada through British Columbia to its western ports are Enbridge’s Northern Gateway and Kinder Morgan’s Trans Mountain Expansion (TMX). Both are drawing a lot of attention – from industry, environmental groups, First Nations and various governments.

Trans Mountain Pipeline Expansion Since 1953 Kinder Morgan and previous owners have been operating its Trans Mountain pipeline, which is currently the only pipeline link between Alberta’s oil sands and the west coast. It was expensive to construct, and a considerable feat of engineering for the time; it crossed much more challenging terrain than the Interprovincial pipeline that had been built a few years earlier to move oil from Alberta to eastern Canada. The Trans Mountain pipeline has undergone expansion since 1953, both in terms of capacity and in terms of length. Completed in 2008, the Anchor Loop expanded the pipeline through Jasper National Park and Mount Robson Provincial Park. The Anchor Loop project increased capacity from 260,000 bpd to the current 300,000 bpd. In spite of the expansion, it is important to note that most recently Kinder Morgan reported that the pipeline is oversubscribed by 30 percent.10

The line runs 1,156 km in length from Edmonton to Vancouver to Anacortes, Washington (see Figure 1.3). Trans Mountain can be easily expanded because the pipeline right-of-way is well established. As a batch pipeline, it is capable of shipping a variety of hydrocarbons.

8 Asian Refining Industry – New Paradigm. 2011. Hydrocarbon Asia. Jan-Mar 2011 Issue. 9 CanadaWest. 2012. Securing Canada’s Energy Future. Report of the Canada-Asia Energy Futures Task Force. 10Bloomberg website, “Kinder Morgan Trans Mountain Line Oversubscribed by 30%”, April 21, 2011, http://www.bloomberg.com/news/2011-04-21/kinder-morgan-trans-mountain-line-oversubscribed-by-30-1-.html (accessed on December 16, 2011)

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Figure 1.3: Trans Mountain Expansion

Kinder Morgan, plans to file, in 2014, a regulatory review application with the National Energy Board (NEB) for the TMX; the expansion, if approved, will be a 450,000 barrel per day (bpd) capacity addition to the current Trans Mountain pipeline. The company should benefit from a recent decision by the Federal Government of Canada to set a time limit of two years on energy project reviews and thereby expedite decisions.11

Now that Kinder Morgan has finished its open season, the company has to begin an environmental assessment and then seek regulatory approval. Kinder Morgan will likely face opposition from environmental groups in the Vancouver area in respect of the pipeline expansion itself as well with regard to expanding the size of the terminal, and subsequently the size of the tankers using the facility. The opposition will likely be centered on the increased size and frequency of tanker traffic in Vancouver. Safety measures and the role of Port Metro Vancouver are discussed in CERI’s report “Pacific Access: Overview of Transportation

11Davidson, A. CBC News. “Ottawa to slash environment review role”. http://www.cbc.ca/news/politics/story/2012/04/17/environmental-reviews.html. Accessed on June 18, 2012.

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Options”.12 How strong the stakeholder opposition will be to the Trans Mountain expansion remains to be seen. The proposed expansion will have to overcome various obstacles similar in nature to Enbridge’s Northern Gateway Pipeline project. But because there is an existing right of way, the situation is different for Trans Mountain than it is for Northern Gateway. The stakeholders are different, too, since the twinned pipeline is set to pass through a more densely populated part of Canada. Besides First Nations, fishermen, and farmers, stakeholders on the TMX route include residents of various municipalities – people that hold their own sets of concerns.

Added to the mix is the Government of Canada’s April 2012 announcement that environmental assessment processes for major energy projects will be streamlined. Instead of as many as 40 government agencies being involved in assessments, only 3 will be involved in the future – the National Energy Board, The Canadian Nuclear Safety Commission, and the Canadian Environmental Assessment Agency (CEAA). All projects must still meet standards as delineated by the Canadian Environmental Assessment Act, but applying organizations must demonstrate that their projects meet these standards within a review time limit of 24 months. As of this writing, it is unclear how the new government reforms will affect projects that are already under review, such as Northern Gateway. But for Kinder Morgan, which has yet to apply for a review of TMX, it appears that it will fall under the new system and have its review completed within 2 years after applying.13

Northern Gateway Pipeline The proposed Enbridge Northern Gateway Pipeline is a system of two pipelines running parallel but flowing in opposite directions. The east-flowing line will carry diluent from the Pacific coast of Canada to the Alberta oil sands and the west-flowing line will take bitumen mixed with the diluent from the oil sands to Kitimat on the BC coast (see Figure 1.4). The lines will run a total 1,172 km in length. The diluent pipe will be 20” in diameter with a daily capacity of 193,000 barrels of diluent. The bitumen pipe, which will carry diluted bitumen to meet pipeline specifications, will be 36” in diameter with a daily capacity of 525,000 barrels. In Kitimat a marine terminal is proposed that will accommodate very large crude carriers (VLCCs). These tankers will carry crude bitumen through the Kitimat Arm fjord to the open Pacific and international destinations.

12To download the study, go to http://ceri.ca/images/stories/2012-02-07__Pacific_Access_Overview_of_Transportation_Options.pdf 13Fekete, Jason. “Conservatives to consolidate, speed environmental reviews: video”. April 18, 2012. http://www.canada.com/technology/Conservatives+consolidate+speed+environmental+reviews+video/6472120/story.html Accessed June 18, 2012.

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Figure 1.4: Proposed Route of Northern Gateway

This project has a decade-long history, and even if all the required government approvals are issued, it could be several more years before the pipeline becomes fully operational. First proposed as a 400,000 bpd pipeline in the early 2000s, the project has been marked by delay ever since. In 2006, Enbridge announced a postponement of 2 to 4 years in order to serve other markets.14 Matters were complicated in 2007 when PetroChina pulled out of an agreement with Enbridge, which would have assigned half of the volumes as exports to China. PetroChina voiced frustration at the slow pace of development and perceived lack of commitment – both from Enbridge and from the Government of Canada.15 Now, in 2012, the project has been presented to the NEB/CEAA Joint Review Panel, which has begun an 18-month-long community hearing process. Enbridge hopes to break ground on the project by 2014, with commissioning and start-up occurring by mid-2017.

The Northern Gateway application is by far the largest application ever received by the NEB. And with more than 4,000 applicants to testify before the JRP – another record – it is clear that there is much public concern to be addressed. These issues boil down to environmental integrity and aboriginal rights. Within British Columbia, the pipelines will cross three major watersheds in a mountainous landscape under harsh northern conditions – concern is high over a potential spill occurring along the pipeline route. Furthermore, the Port of Kitimat is at the end of a close-to-100-kilometer-long fjord, through which large oil tankers would travel; risk of a major oil spill in the fjord or along the Pacific coast is also causing public worry. A pipeline would affect over 100 Aboriginal communities inland and along the coast; these groups are

14Primarily to the US Midwest through development of the Alberta Clipper Pipeline, which became fully operational at the end of 2010. 15The Canadian Press. “PetroChina dropping $3B pipeline, Enbridge still online. July 13, 2007. http://www.cbc.ca/news/canada/calgary/story/2007/07/13/enbridge-gateway.html Accessed June 18, 2012.

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anxious not only about the flora and fauna that are essential to sustaining their lifestyles, but also about relinquishing their traditional role as custodians of the land.16

What are the views of the governments of British Columbia, Alberta, and Canada? The federal government has made it clear that it supports the development of a pipeline. Prime Minister Stephen Harper has stated the JRP is a fair process that will result in the voice of the Canadian people being heard but also warned of foreign interests “hijacking the process”.17 Natural Resources Minister Joe Oliver has been even more explicit, writing an open letter critical of “environmental and other radical groups that would seek to block this opportunity to diversify our trade”.18 In a recent television interview, he elaborated on the extent of economic impact a pipeline could bring: “We're looking at the possibility of well over $3 trillion in economic development, hundreds of billions of dollars in revenue in the form of taxes and royalty payments to help finance our social programs, like health care and education and to create well over 600,000 jobs”.19 On the matter of the voluntary tanker exclusion zone of the Alaskan crudes, Minister Oliver has asserted that the Government of Canada would support increased tanker traffic in this zone to enable bitumen to be shipped to overseas markets.

The Alberta provincial government is also supportive of the Northern Gateway project. Premier Alison Redford has traveled to Washington to express to US lawmakers the importance to both Canadian and US economies of continued pipeline infrastructure development. She has also questioned the length of the Northern Gateway review process, and stated that her government will exert a “full court press” to advocate for a pipeline: “We’re going to have to respond to [environmental activists] and we will. We’ve begun to do that, we’re going to continue to do it and we’re going to work hard to get this through. It’s important for Alberta.”20 More quiet on the issue is the Premier of British Columbia, Christy Clark, who has remained neutral, likely weighing the complex and conflicting interests of the various stakeholders within her province.

16For more information see CERI’s February 2012 Report “Oil Spills and First Nations: Exploring Environmental and Land Issues Surrounding the Northern Gateway Pipeline” for a discussion of First Nations Issues. www.ceri.ca 17Payton, Laura. “Radicals working against oilsands, Ottawa says.” January 9, 2012. http://www.cbc.ca/news/politics/story/2012/01/09/pol-joe-oliver-radical-groups.html Accessed June 18, 2012. 18Oliver, Joe. “An open letter from Natural Resources Minister Joe Oliver”. January 9, 2012. http://www.theglobeandmail.com/news/national/an-open-letter-from-natural-resources-minister-joe-oliver/article2295599/ Accessed June 18, 2012. 19CTVNews.ca. “Pipeline critics hit back after Oliver warns of ‘radicals’. January 9, 2012. http://www.ctv.ca/CTVNews/TopStories/20120109/Pipeline-critics-hit-back-after-Oliver-warns-of-radicals-120109/ Accessed June 18, 2012. 20Wood, J., and R. Penty. “Premier Alison Redford promises ‘full-court press’ to move Keystone project forward”. January 19, 2012. Calgary Herald. http://webcache.googleusercontent.com/search?q=cache:_xxnC8lLVeYJ:www.calgaryherald.com/business/Premier%2BAlison%2BRedford%2Bpromises%2Bfull%2Bcourt%2Bpress%2Bmove%2BKeystone%2Bproject/6019880/story.html+&cd=8&hl=en&ct=clnk&gl=ca Accessed June 18, 2012. http://www.calgaryherald.com/business/Premier+Alison+Redford+promises+full+court+press+move+Keystone+project+forward/6019880/story.html#ixzz1kPW7dLdR

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Industry has done its part to rally around Enbridge. Prior to 2012, only one company, Sinopec, had announced publically its intentions to take capacity on the line. But in January five more companies – Cenovus, Total, Nexen, Suncor, and MEG – stated that they became “funding participants” in 2007 and 2008, at that time contributing towards a $100 million development fund for the project’s preconstruction and engineering work – and ensuring their own proportions of pipeline capacity once the project is built and fully operational.21

Canadian National Railway’s (CN’s) “Pipeline on Rail” While the planned Northern Gateway project has received the most media attention, many industry pundits find CN’s proposal of shipping oil by rail the most creative and intriguing.22 CN joined the race to supply oil to the Asian markets in early 2009 but their “pipeline on rail” idea has really gained steam in the past year. This could be fueled by a combination of greater than C$100/bbl oil or the various challenges and issues regarding the Enbridge and Kinder Morgan proposals. Besides the existing Trans Mountain pipeline, there are obstacles to build a pipeline through BC to the west coast. The process is time consuming, expensive and slow. CN’s “pipeline on rail” concept is being marketed to industry as “unprecedented connectivity, scalability, flexibility, reliability and speed – all with minimum impact on the environment”.23

On the CN network, crude oil can be transported to three west coast ports: Prince Rupert, Kitimat and Vancouver. While the Ridley Terminal at Prince Rupert is the closest to Asian markets, CN has access to three terminals at Port Metro Vancouver (PMV) (Squamish Terminals, Fraser Surrey Docks and Lynnterm Terminal). The former is exclusive to CN while the Fraser Surrey and Lynnterm terminals are able to handle vessels that are Panamax and post-Panamax size, respectively.24

CN already transports diluents, liquefied petroleum gases (LPG), coal, diesel, sulphur and petroleum coke to the west coast and various other parts of North America.25 The logistical framework already exists for various commodities. Figure 1.5 illustrates CN’s diluent “pipeline on rail”. CN partnered with EnCana, Provident and Methanex and was ramping up to 14,000 cars per year, or the equivalent of 23,000 bpd.26

21Vanderklippe, Nathan. ”Oil giants back Gateway pipe”. January 4, 2012. http://www.theglobeandmail.com/report-on-business/oil-giants-back-gateway-pipe/article1357505/. Accessed on June 19, 2012. 22 Refer to Appendix E for the full list of railway companies that are involved in shipping crude in North America. 23CN Railway website, Ship Your Crude Oil Products on CN's PipelineOnRail™, http://www.cn.ca/en/shipping-north-america-alberta-pipeline-on-rail.htm (accessed on December 14, 2011) 24 CN Rail, Alberta Oil Sands, http://www.cn.ca/en/shipping-north-america-alberta-oil-sands.htm (accessed on December 17, 2011) 25 Ibid. 26 CN Rail, Transportation Solutions for Oil Sands Production Phase, Randy Meyer Presentation, The Van Horne Institute, May 13, 2009, http://www.vanhorne.info/files/vanhorne/2%20CN.pdf (pp. 16).

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CN’s coal “pipeline on rail” moves 13 million MT of coal, an equivalent of 210,000 bpd.27

Figure 1.5: CN’s Diluent “Pipeline on Rail”

Source: CN Rail28

That being said, CN would most likely have to build a new terminal on the west coast at a cost of C$200 to C$500 million, which could exclusively handle the necessary large tanker shipments.29 This marine terminal and its proposed tanker routes could be susceptible to a potential ban of VLCC traffic and other environmental restrictions that could affect the Enbridge and Kinder Morgan proposals.

27 CN Railway website, Ship Your Crude Oil Products on CN's PipelineOnRail™, http://www.cn.ca/en/shipping-north-america-alberta-pipeline-on-rail.htm (accessed on December 14, 2011) 28 CN Rail, Transportation Solutions for Oil Sands Production Phase, Randy Meyer Presentation, The Van Horne Institute, May 13, 2009, http://www.vanhorne.info/files/vanhorne/2%20CN.pdf (pp. 16) 29 The Globe and Mail, CN & CP eye shipping oil to west coast, January 24, 2011, http://www.theglobeandmail.com/globe-investor/cn-cp-eye-shipping-oil-to-west-coast/article1881460/page2/ (accessed on December 14, 2011)

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Figure 1.6: Map of Transportation Options to the West Coast

Source: CERI

Research and Report Organization The primary emphasis of this report is to determine the economic impacts of pipeline developments derived over the next 25 years from construction and operation of the TMX and Northern Gateway pipeline systems. These pipelines are considered in isolation from other infrastructure and oil sands projects, and the economic effects are measured on regional, provincial, and federal levels.

To estimate economic benefits on federal and provincial levels, CERI utilized its provincial Input-Output (I/O) model, whose detailed methodology and assumptions are described in Appendix B of this report. For the regional-level estimation, CERI has developed a Regional I/O (RIO) model that analyzes for economic impacts on GDP, employment, and tax revenues broken down by region within the two most affected provinces, British Columbia and Alberta.30 The regional categories are as follows:

• British Columbia: Cariboo, Kootenay, Mainland/Southwest, Nechako, North Coast, Northeast, Thompson/Okanagan, Vancouver Island/Coast;

30See Appendix C, “Regionalization of Data for Regional I/O Model” for a more detailed discussion of the model and assumptions.

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• Alberta: Lower Peace, Lower Athabasca, Upper Peace, Upper Athabasca, North Saskatchewan, South Saskatchewan, and Red Deer.

Figure 1.7 and 1.8 shows the areas of Alberta’s land-use framework regions and BC’s development regions, respectively.

Figure 1.7: Alberta Land-Use Framework Regions

Source: North Saskatchewan Watershed Alliance31

31 Accessed June 24th 2012 from http://nswa.ab.ca/content/land-use-framework

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Figure 1.8: British Columbia Development Regions

Source: BC Stats32

32 Accessed June 24th 2012 from http://www.bcstats.gov.bc.ca/StatisticsBySubject/Geography/ReferenceMaps/DRs.aspx

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Chapter 2 Transportation Options and Markets General Background Several considerations govern the development of transportation arrangements for a bulk commodity such as bitumen or conventional crude: the quality of crude, the cost of a transportation mode, the availability of transportation options, the refinery margins for different crudes, the demand for refined petroleum products, the configurations of refineries, etc. Ultimately, transportation networks connect suppliers to their potential markets; therefore, factors that tie into the economics of transporting a good from a supply center to a demand center will dictate the rate, amount, and type of transportation mode. With the potential advent of constrained pipeline capacity, producers and distributors have needed to analyze the impact of alternative modes and their role in the entire distribution network. These alternative modes are subject to cost considerations such as trade-offs among investment costs, transport costs and any other costs. If the cost of these alternatives becomes too high there may be unintended consequences such as the curtailing of production. Conversely, a strong demand for these alternatives may make these alternative modes more economical. The following is a brief discussion of some of the aforementioned factors.

The Roles of Rail and Trucking Traditionally, rail and trucking costs have been broken out into terminal (independent of distance) and line-haul (proportional to distance). For most commodities, rail is understood to have higher terminal costs than trucking, but lower line-haul costs. Consequently, trucks tend to be employed for short hauls and rail tends to be employed for long hauls. Large-diameter oil pipelines are most often compared to super-tankers, the latter normally being cheaper over comparable distances. A conceivable expectation to this general rule would be a very short haul, perhaps from one end of a harbour to the other, in which case the time and cost associated with loading and unloading a vessel might make pipe the economic choice.

Freight rates are not the shipper’s only concern. Loading and unloading costs may be different from mode to mode. In some cases these costs are the responsibility of the carrier, and in some cases they are borne by the shipper. If rates are generally comparable between rail and pipeline to link an oil product with a refinery complex, the advantage of simplicity would tend to favour pipe, because oil production, pipeline movement and primary distillation at a refinery are all continuous processes, minimizing the need for inventory and storage facilities. Rail transportation, in contrast, is inherently a batch operation. If the oil is to be transported overseas subsequently by super-tanker, this advantage diminishes because the “batches” in terms of unit trainloads are much smaller than the “batches” comprising the super-tanker’s cargo.

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Yet another consideration is whether the transportation arrangements are to be point-to-point, area-to-area, point-to-area or area-to-point. Pipelines work best with point-to-point transportation of large quantities. Trucking works best on an area-to-area basis. The demise of the freight elevator system reflects the inability of branch lines to compete with trucking in gathering relatively small quantities from a vast number of shipping points. Trucks have available a dense highway network, whereas pipelines are generally built with a particular commodity, an origin and a destination in mind. Railroads are an intermediate case. Although railroad tracks and track-beds are almost as inflexible as pipe in the ground, rolling stock can be rerouted according to changing circumstances. The assets of a trucking company are even more flexible in terms of redeployment.

Non-pipeline alternatives for moving large volumes of liquid hydrocarbons are generally considered uneconomic for long-distance transportation due to system complexity as well as the rising variable costs accompanying congestion. Moreover, transportation modes such as trucks and railways are more strongly affected by changes in energy prices because they are more energy-intensive. Truck line costs are generally higher than those of rail and pipeline. Waterborne shipments are geographically specific but can be considered somewhat comparable in cost to pipelines.1 However, pipelines have a limited amount of flexibility compared to their truck and rail counterparts and shippers may opt to pay higher prices for delivery to markets that are not accessible by pipeline but command a better commodity price. Moreover, there is flexibility at network logistics hubs where multiple modes may access different regions and allow shippers to choose among them. These hubs are generally characterized by a large amount of storage and transportation capacity. Some examples of major Hubs are Los Angeles, CA; Cushing, OK; New York Harbour; Houston Harbour; and Chicago, IL. Figure 2.1 shows the relationships among cost, mode, and flexibility for various modes of transportation.

1 Trench, C.J. (2001) How Pipelines Make the Oil Market Work – Their Networks, Operation and Regulation. Allegro Energy Group.

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Figure 2.1: Transportation Mode, Cost and Flexibility

Source: CERI

Table 2.1, while somewhat dated, also helps to compare transportation modes in relation to crude transport and the respective infrastructure associated with each. Truck and rail have substantial mileage for infrastructure but need to transport several commodities. Of note is that pipelines transport a substantial tonnage with minimal fatality rates compared to other modes.

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Table 2.1: Comparison of Different Oil Transportation Types in the United States

Crude and Products Pipeline

Water Rail Truck Air

Infrastructure in the Year 2000 (miles)

84,480 crude 91,516 prods

22,577 inland, intra-coastal

120,950 Class I track

114,511 Nat. Highways (incl. 46,677 interstate)

N/A

2001 Mileage (billions of ton miles)

616 400 canal/rivers 94 lakes

1,558 1,051 15

2001 Average Length of Haul (miles)

766 crude 418 prods

484 canals/ rivers 510 lakes 1,644 coastal

735 752 LTL 292 TL

973

2001 Nation’s Freight bill 2001 (%)

1.6 4.8 6.3 80.6 4.4

2001 Revenue per ton mile

1.42 0.72 (barge) 2.24 (class I) 26.6 LTL 52.92 (excluding FedEx)

Petroleum Transport (% of total ton miles) 2001 (2009)*

68.3 (70.2) 27.7 (23.1) 1.6 (2.6) 2.5 (4.2) 0 (0)

2001 Fatalities

7 including gas lines

744 680 including commuter

41,730 1,157

*Association of Oil Pipelines

Source: Hull2

It is not simple to switch from one mode of transportation to another to overcome bottlenecks. Table 2.2 is provided to illustrate what it would take to replace a 150,000 bpd pipeline by another transportation mode.

2 Hull, B. (2005) Oil Pipeline Markets and Operations. Journal of Transportation Research Forum. 44(2):111-125.

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Table 2.2: Capacities and Required Fleet to Replace a 150,000 bbl/d Pipeline 1,000 Miles Long

Mode Capacity per Unit (bbls)a

Capacity Constraints/avg speeds

Approximate cost per thousand barrel miles

Required Tank Fleet

Avg. Eng. Eff. (KJ/tonne*km)3

Rail - Unit Cond.b - 801 Light – 697 Dilbit - 620 Bit. - 576

1 week 90 tank cars

Cond. – 5-6 Light – 5-6 Dilbit – 6-7 Bit – 7-8

Cond – 2620 Light – 3012 Dilbit – 3387 Bit. - 3643

280

Rail -Manifest Cond.b - 801 Light - 697 Dilbit - 620 Bit. - 576

Up to 30 tank cars 12 daysc to cover distance

15 Cond. – 4490 Light – 5164 Dilbit – 5807 Bit. - 6244

280

Truck 200 500 miles/day 25 3000 2640 Barge 45,0004 7 mi/hrd (max)5 Catoosa. OK-

St.James. LAe 5-76

26 (double linked barges)

420

Pipeline 150,000 3-8 miles/hr 1-4 None 1407 aassume 92 tonnes per tank car for trains bDensity assumptions are 719 kg/m3 condensate; 827 kg/m3 light; 930 kg/m3 dilbit; 1000 kg/m3 bitumen cManifest trains are assumed to take longer than unit trains due to multiple stops. Also due to the increased variability of manifest trains a more detailed look of cost per bbl by crude type could not be completed. dThis is a very generous speed as typically due to safety, especially in populous areas, the actual speed may be markedly lower (sometimes 1 mile/hr) eApproximately 650 mile distance

Source: Various sources, Bakken 2012 Market Conference, CERI

Figure 2.2 and 2.3 show the network of rail and pipe from Alberta to the immediate major hubs of Chicago, the Gulf Coast and the West Coast.

3 Office of Energy Efficiency (2009). Energy Efficiency Trends Analysis Tables Canada. Retrieved Feb 9th 2012 from http://oee.nrcan.gc.ca/corporate/statistics/neud/dpa/analysis_ca.cfm?attr=0 4 EnSys Energy & Systems Inc. (2011). Keystone XL Assessment – No Expansion Update August 2011 Report. Prepared for US Department of Energy & US Department of State. Retrieved Dec 6th 2011 from http://cdn.theatlantic.com/static/mt/assets/business/Ensys_August_Report.pdf 5 What is a barge?. The Barge Association. Retrieved Feb 9th 2012 from http://www.barges.org/main.php?section=1701 6 McGurty, J. (June 14th 2011) Oil moving by barge as Midwest discount deepens. Reuters. Retrieved Feb 8th 2012 from http://www.reuters.com/article/2011/06/14/us-midwest-cushing-barges-idUSTRE75D6FP20110614 7 Van Essen, H. Croezen, H.J., Nielsen, J.B. 2003. Emissions of pipeline transport compared with those of competing modes: Environmental analysis of ethylene and propylene transport within the EU. CE Solutions for environment, economy and technology.

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Figure 2.2: Rail and Pipeline Network Connecting Alberta to Gulf Coast and West Coast

Source: CERI, CAPP, American Association of Railways, CN, CP, BNSF, UP

Figure 2.3: Major Pipelines Connecting Alberta to Gulf Coast and West Coast

Source: CAPP

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Most oil arrives by pipeline and tanker to refineries with alternative transportation modes making only a small contribution as shown in Table 2.3

Table 2.3: US Refinery Receipts by Method of Transportation for the Year 2010 (Mb)

Mode PADD United States

I II III IV V Pipeline Domestic 2,259 712,212 794,891 86,714 241,655 1,837,731 Foreign 19,322 478,606 349,230 78,034 49,600 974,792 Tanker Domestic 0 0 2,211 0 209,350 211,561 Foreign 309,505 0 1,500,256 0 338,339 2,148,100 Barge Domestic 3,128 207 41,955 0 820 46,110 Foreign 65,128 40 14,720 0 22,208 102,096 Tank Cars Domestic 0 0 793 0 3,535 4,328 Foreign 0 0 0 0 0 0 Trucks Domestic 5,021 5,915 22,323 32,470 6,511 72,240 Foreign 0 0 0 0 0 0 Source: EIA Annual Refinery Report

Crude Oil by Railway Pipeline is the preferred, cheapest, and most efficient way of transporting oil over land; however, in light of the recent constraints on pipeline capacity, railway has emerged as an alternative to transport crude. It is not expected that pipelines will be replaced by rail but that rail could end up with a higher percentage of transport volume than in the past. Railway has recently garnered interest due to the following:

1. Railway track is already in place and hence investment is minimal 2. Rail does not require the long-term contract commitments of prospective pipelines 3. Rail is very versatile and capable of accessing multiple markets

Canadian Railway Company Interests Canadian shipping companies are primarily interested in moving oil out of the Canadian and US Bakken due to the inability of pipelines to keep up with growing Bakken production. The rail moves oil mostly from the Bakken to refineries in the Gulf Coast, bypassing the lower prices at Cushing, but have been increasing movements to the East and West Coasts. Both CN and Canadian Pacific Railway (CPR) have seen increases in their crude oil volumes, but the largest increases according to their annual reports are within the metals and minerals sector.

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According to CN’s 2010 Annual Report, the drivers for this increase are mining, oil and gas development, and non-residential construction. Canadian companies have traditionally not shipped crude oil, but fuel and crude oil products have increased by 1 percent since 2000. The result is that fuel oil and crude product shipments now make up 1.8 percent of total freight tonnage.

According to the EnSys report, rail companies are shipping the following: light Bakken to points along Eastern and Western Canada, the US Midwest and the US Gulf Coast; heavy conventional from Lloydminster to the US Gulf Coast; dilbit from Fort McMurray to California; undiluted bitumen from Fort McMurray to California and Washington State; and conventional oil from Alberta to various destinations.8 While CP is primarily focused on upgrading track for Bakken transport, Altex energy has paired with CN to promote “pipeline on rail”. According to the Oil Inquirer as well as personal discussions with Procor, the amount currently being shipped by rail from Western Canada appears to be minimal (approximately 5,000 bpd) compared to the 2 million or so that may be shipped by pipeline. There are now 7-8 companies moving heavy oil by rail and 5 moving bitumen in diluted form. There are also storage constraints because the terminals are not built to handle heavy oil; however, CN remains optimistic that 1,000-200,000 bpd can be transported to the US Gulf Coast and to refineries on the East and West coasts.9 Although there is a noticeable increase in rail traffic in the US for crude and petroleum products according to data from the American Association of Railroads (AAR), there has been only a slight increase in Canadian rail traffic. Thus most crude transportation by rail has been a US phenomenon whereas transport of Canadian crudes is still primarily through pipelines.

Even so, Canadian companies are starting to build terminals to enable the transport of diluents and heavy crudes and installing handling facilities for supplies required for production (fracing sand, steel, concrete, etc.). CP has announced that it plans to increase its oil-by-rail operation out of Lloydminster, SK with NuStar Energy, and touts that it is the only railway capable of shipping crude from Alberta’s Industrial Heartland, the Bakken and the Marcellus to markets in the northeastern and Midwestern US.10 Connacher expects to increase its fleet from 290 cars to 2,500 cars in the years 2012/2013.11 Lastly, Keyera and Enbridge have recently partnered to build a rail and truck terminal at Enbridge’s Cheecham terminal near Fort McMurray to allow for the receipt of diluents and solvents by rail and shipment of dilbit to refineries. It is hoped

8 EnSys Energy & Systems Inc. (2011). Keystone XL Assessment – No Expansion Update August 2011 Report. Prepared for US Department of Energy & US Department of State. Retrieved Dec 6th 2011 from http://cdn.theatlantic.com/static/mt/assets/business/Ensys_August_Report.pdf 9 Harrison, Lynda. (Sept. 12 2011). Riding the Rails: Oil Companies climb aboard potential alternative to pipelines. Oil and Gas Inquirer. Accessed Dec 8th 2011 from http://www.oilandgasinquirer.com/article.asp?article=magazine%5C110912%5Cmag2011_sc0000.html 10 Canadian Pacific expands its oil by rail operation to Lloydminster, SK. Feb 2nd 2012. Accessed February 15th from http://www.cpr.ca/en/news-and-media/news/Pages/oil-by-rail.aspx 11 Crude by rail: Temporary or Long-Term Fix? December 20th 2011. Calgary Herald. Accessed December 21st from http://blogs.calgaryherald.com/2011/12/20/crude-by-rail-temporary-or-long-term-fix/

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that this terminal will be in operation by mid-2013 and will later gear up (when presumably there will be expanded pipeline capacity) to provide other services.12

US Railway Transport and US Bakken According to the AAR, shipment of crude by rail in the US has increased dramatically (see Figure 2.4). In the year 2012 the number of weekly car movements with crude and petroleum products went up from approximately 8,400 in January to 10,000 by May. Most US crude that is shipped by rail comes from the Bakken oil play in North Dakota. Rapidly increasing production13 and lack of available pipeline capacity in the region is said to be the reasons for increased rail use to ship oil to markets. (Although movement of oil by rail from Cushing to the Gulf of Mexico is believed to be a reality, a news release from the EIA suggests that this is not yet happening.) This is because a rail terminal at Stroud, Oklahoma does not quite connect to where the pipelines terminate. Since there is a shortage of trucks available, the cost to move crude from the pipeline terminal to the rail terminal renders this transportation option uneconomic. Until further pipeline infrastructure can be built, demand for tank cars to transport crude will grow: Economic Planning Associates Inc. predicts 11,000 deliveries of tank cars in 2012, up from 4,839 last year.14 BNSF claims that of the 464,000 bpd produced in Nebraska about a quarter is being shipped by rail and they expect that fraction to keep increasing.15 Overall, liquefied natural gas and crude oil make up 11 percent of US carloads in 2011, up from 2 percent in 2008.16

12 Keyera Pursuing Diluent Transportation Initiative. Jan 4th 2012. Canada Newswire. Accessed February 16th from http://www.newswire.ca/en/story/901771/keyera-pursuing-diluent-transportation-initiatives 13 Production increased from 343,000 bpd in January 2011 to 464,000 bpd by September of that year and is forecasted to reach 1 MMbpd over the next decade. 14 Rail delivery of crude oil and petroleum products rising. Nov 16th 2011. EIA. Accessed Nov. 16th from http://www.eia.gov/todayinenergy/detail.cfm?id=3930 15 Why rail is moving crude these days. 2011. CTV News. Accessed Nov 17th 2011 from http://www.ctv.ca/generic/generated/static/business/article2213588.html. 16 Ibid footnote 17.

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Figure 2.4: US Weekly Rail Transportation of Petroleum and Petroleum Products

Source: America Association of Railroads

Figure 2.5 illustrates that rail has taken advantage of the slowness of pipeline companies to participate in the Bakken boom (see years 2010-2013). However, there is excess rail capacity and it is not expected that this capacity will be filled. Most Bakken producers believe that while rail is still more expensive than pipeline once the entire infrastructure is in place (i.e., terminals, tracks, agreements with Class I railways, etc.) for large unit trains transporting crude, the economics of modal choice would be much closer to breakeven (although at the moment pipeline costs are about $6/bbl compared to $15/bbl for rail).17 Figure 2.5 compares the expected production from the Bakken to capacity of rail and pipe.

17 Bakken Markets Conference 2012. The manifest train service may be around $15/bbl while a large unit train may be able to transport crude for approximately $6/bbl.

5000

6000

7000

8000

9000

10000

11000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Wee

kly C

ar M

ovem

ents

Pet

role

um an

d Pe

trol

eum

Pro

duct

s

2008

2009

2010

2011

2012

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Figure 2.5: Projected Bakken Pipeline and Rail Capacity Relative to Forecast Oil Production

Source: True Energy Presentation.

Until pipeline capacity is increased, growth in Bakken crude production will be limited by the ability of railways to move it. The ability and willingness of railways to accommodate this growth is a function of both the capacity of the line and the expected growth and destination of other commodities. A rapid expansion of either crude or another commodity may constrain the existing system and necessitate capacity expansion, at a significantly higher cost than the mere addition of a terminal. Currently, in light of very slow recovery from the recession, rail traffic has not reached its 2006 peak, so it can be assumed that there is excess railway capacity. As the economy recovers, so does rail traffic, and it can be surmised that eventually growth of railway traffic will strain capacity and additional infrastructure requirements will be needed. Congestion as capacity limits are approached leads to an increase in total logistics costs,18 which eventually could be recovered through freight rate increases.

Currently there are approximately 18 months of back log to build new tank cars. Also, rail is still more expensive than pipelines as a transportation option – although unit trains and increased network capacity help to make the economics more favourable. Various companies are investing in rail, and slowly a crude-by-rail network is being set-up around North America, but most view it as an “interesting, but short-term solution”.19 However, with the tank car

18 Cost of managing, moving and storing goods. 19Accessed June 28th 2012 from http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/rail-makes-big-inroads-in-oil-transport/article4198192/

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shortage as well as investment into loading and offloading facilities for unit trains, it is likely that rail works as a secondary option to pipeline transportation. The exception is the East Coast where it may be difficult to obtain a right-of-way permit.

Other Routes and Other Markets It was noted earlier that supertanker rates make up a very small part of a refiner’s crude oil acquisition cost. The main problems for inland oil going to coastal overseas export markets are to get it to port and to seek out customers with a suitable refinery configuration. East Asia stands out as a large and growing market, in contrast to shrinking markets for refined petroleum products in Europe and North America. If British Columbia’s ports were to be unavailable to expanded tanker traffic, one could look to refiners on Canada’s East Coast, or to US refiners on the Atlantic Coast, the Gulf Coast or in California as alternative markets. (In principle, one could also consider the ports located within these regions as alternatives to Kitimat and Vancouver but the distances to East Asia by land and by sea would be considerably longer than through BC ports.) Table 2.4 shows some of the distances between various ports and Shanghai, China.

Table 2.4: Distances in Nautical Miles to Shanghai from Various Ports

Prince Rupert, BC 4,762 Kitimat, BC 4,875 Vancouver, BC 5,103 San Francisco, CA 5,407 Boston, MA 10,603 Houston, TX 9,883

Source: Sea Rates,20 CERI

Canada’s East Coast Canada’s Atlantic Provinces have three refineries, one each in New Brunswick, Newfoundland, and Nova Scotia.

The Imperial refinery at Dartmouth, NS is the smallest of the three at 88,000 bpd.21 It was recently put up for sale and found itself in competition with nine other refineries seeking buyers. Gilles Courtemanche, vice-president of Imperial Oil Limited, explained that Imperial “had no choice but to look for a buyer because Europe is buying less gasoline than it did in the 1970s”.22

20 Distances calculated from http://www.searates.com/reference/portdistance/?country1=143&country2=127&fcity1=20193&fcity2=706&speed=14 Accessed June 28th 2012. 21 Imperial Oil Limited website, http://www.imperialoil.ca/Canada-English/operations_refineries_dartmouth.aspx, accessed on 26 June 2012. 22 CBC news article dated 17 March 2012, accessed at http://www.cbc.ca/news/canada/nova-scotia/story/2012/05/17/pei-dartmouth-refinery-for-sale-584.html, accessed on 28 June 2012.

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The North Atlantic refinery at Come-by-Chance, NL, and the Irving refinery at St. John, NB, continue to operate. Both are able to refine heavy sour crudes and both have harbours that accommodate VLCCs. The former, serving markets on both sides of the Atlantic Ocean, is essentially beyond the possibility of pipeline access as it is on an island and far from an existing pipeline. The latter is Canada’s largest refinery at 300,000 bpd,23 and serves markets in both Canada and the United States. The nearest oil pipeline is at Portland, ME, almost 400 km away. While there is a lack of oil pipeline infrastructure, Irving has arranged a 104-car trainload of Bakken light oil crude.24

In general it is easier to finance a pipeline to growing markets than to shrinking ones. Fortunately a cheaper solution than laying new pipe all the way from Alberta to the Atlantic coast is available in the reversal of Enbridge’s 240,000 bpd Line 9 between Sarnia and Montreal.25 Also, underutilized capacity on the TransCanada main line could be converted from natural gas use to moving oil sands output. Beyond Montreal, oil sands crude could move to the East Coast by rail, truck or new pipeline. It could also move from Montreal to tidewater at Portland, ME if flow through the Portland-Montreal Pipeline were reversed.

Atlantic Coast of the United States As discussed above, reversal of Enbridge’s Line 9 and the 140,000 bpd Portland-Montreal Pipeline could provide pipeline access to Atlantic tidewater from Sarnia, ON. In principle it could move 70,000 bpd of synthetic crude oil (SCO) and 70,000 bpd of bitumen as synbit. This is only a fraction of the 450,000 bpd capacity of the proposed TMX or the 525,000 bpd capacity of the proposed Northern Gateway pipeline; moreover, some of this capacity will be used to move Bakken crude, and some of it will surely be utilized to serve east-of-Sarnia refineries in Ontario and Quebec. Although most Atlantic coast refineries are designed to process light, sweet crude, Table 2.5 identifies almost twice as much apparently suitable refining capacity in Atlantic coast refineries as can be accommodated in the reversed Portland-Montreal Pipeline. This looks like more than enough, but about one-third of apparently suitable capacity currently stands idle or is slated for closure. Moreover, refineries do not typically operate at 100 percent of capacity (nor do pipelines). In order to keep the reversed Portland-Montreal Pipeline reasonably full with synbit, this blend would have to be priced to capture most of the identified Atlantic Coast market for it. In any case, serving this market would not significantly diversify oil sands exports, essentially all of which now go to the United States.

23 Irving oil website, http://irvingoil.com/operations_and_partners/operations/refining/, accessed on 28 June 2012. 24 Bakken Crude Oil Train Heading for New Brunswick…June 26th 2012. Accessed June 28th from http://www.easternrailroadnews.com/2012/05/25/bakken-crude-oil-test-train-heading-for-new-brunswick/ 25 Enbridge website, http://www.enbridge.com/Line9ReversalProject.aspx, accessed on 28 June 2012.

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Table 2.5: Atlantic Coast Refineries with Asphalt or Coking Capability (PADD I excluding West Virginia)

Name of Refinery

Location

Status

Parent Company

Primary Distillation

Capacity (kb/d)

Asphalt Capacity

(kb/d)

Coking Capacity

(kb/d)

Potentially Suitable Delaware City Ref Delaware City DL restarted PBF Holding Co 182 0 54

Nustar Asphalt Ref Savannah GA 50/50 op/idle Nustar Energy 32 32 0 Paulsboro Ref Paulsboro NJ operating PBF Holding Co 160 16 27 Paulsboro Asphalt Ref Paulsboro NJ operating Nustar Energy 51 51(?) 0 Trainer Ref Trainer PA operating* ConocoPhillips 185 0 73 Warren Ref Warren PA operating United Ref 65 12 0 Western Ref Yorktown Yorktown VA idle Western Ref 66 0 22

Not Potentially Suitable Perth Amboy Ref Perth Amboy NJ idle Chevron USA inc 80 0 0

Linden Ref Linden NJ operating ConocoPhillips 238 0 0 Port Reading Ref Port Reading NJ operating Hess Corp 0 0 0 Bradford Ref Bradford PA operating Am Ref Group inc 10 0 0 Marcus Hook Ref Marcus Hook PA operating** Sunoco 194 0 0 Philadelphia Ref Philadelphia PA operating** Sunoco 355 0 0 Kingshill Ref Kingshill VI operating*** Hovensa LLC 500 0 55

Total Capacity

2,118 Idle Capacity

162

Operating, but for sale or closure

1,234 Continuing Operations

722

*ConocoPhillips had announced that it would sell or close its Trainer refinery, which it managed to sell to Delta airlines. **Sunoco has announced that it will exit the refinery business, and will sell or close its Marcus Hook and Philadelphia refineries. ***Hovensa has announced that it intends to close its Kingshill, Virgin Islands refinery.

Source: CERI, EIA Refinery Capacity Report, Various Sources

Gulf Coast of the United States The Gulf Coast has a vast refining complex with enormous upgrading ability and is ideally suited to take bitumen. The rejection of the initial KXL application has prompted a move to diversify export markets. Devoting all of a commodity’s exports to a single country exposes it to unfavourable events that, in various ways, could adversely affect both market/transportation access and producer prices. Building the KXL would not, however, fully exhaust potential markets for oil sands in the Gulf Coast. Any new pipeline route from the oil sands areas to the

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Gulf Coast would be much longer than Northern Gateway or TMX, and would face similar opposition.

California Although there are products pipelines that cross into California, that state has supplied its refineries from oil wells within the state and from distant supplies arriving by tankers. California could most economically be reached by oil pipeline, but none currently exists. Such a new pipeline would be much longer than either Northern Gateway or TMX, and is the home of environmental organizations that have vocally opposed pipeline projects in more distant places. Although one could surmise that an organization opposing a pipeline to BC based on potential tanker oil spills would welcome a pipeline to California that would reduce tanker traffic in that state, no such proposal is likely to get an easy ride. The prospect of moving new crude supplies into California also faces the harsh reality of a shrinking market for refined petroleum products and ever harsher emission limits spearheaded by the California Air Resources Board.

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Chapter 3 Regional Input-Output Methodology and Assumptions This chapter explains the Regional Input-Output (RIO) Methodology and the capital costs assumptions on how the pipelines’ investments and operations that feed into the model are broken down by region within the boundaries of Alberta and British Columbia, the two provinces that will be affected the most if the pipelines become operational.

Provincial and Regional I/O Methodology Input-output analysis addresses the way economic circumstances in one part of an economy can ripple through the rest of it. In particular, it is concerned with inter-industry relationships, notably the use output from one industry as an input into another industry’s production process. The demand for such inputs is called intermediate demand, which is distinct from the final demand categories of personal consumption expenditures, government current expenditures, gross fixed capital formation (acquisition of machinery and equipment, construction of housing and other structures), net increases in inventories, and net exports. As these relationships are highly data-intensive, input-output analysis makes the following important simplifying assumptions:

• Fixed proportions – no scope for substitution among inputs: even if coal becomes cheaper relative to iron ore, for example, under fixed proportions one cannot take advantage of this price change by using more coal and less iron ore to make steel.

• No economies or diseconomies of scale – an increase or decrease in an industry’s output

entails proportionate increase or decrease to each of its inputs.

The following example requires the reader to have some knowledge of matrix algebra. Consider an economy with no external trade, no government, no need for transportation or wholesale/retail trade and therefore no resource cost in getting the product from producer to customer, and just three industries. Each of these industries satisfies both intermediate and final demands for its products. In this example, inputs and outputs could be measured in dollars or in physical units; in realistic cases physical units would be impractical. Given a set of final demands (f1 for industry 1, f2 for industry 2 and f3 for industry 3) and a set of input coefficients (a12 , for example, is the fraction of a dollar’s worth of input from industry 1 required to make a dollar’s worth of industry 2’s output), the objective is to find the total (gross) output from industries 1, 2 and 3 (labelled x1, x2 and x3 respectively) required to satisfy both intermediate and final demands. The outputs to satisfy each of the final demands are specified in the following equations:

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a11 x1 + a12 x2 + a13 x3 + f1 = x1

a21 x1 + a22 x2 + a2 3x3 + f2 = x2

a31 x1 + a32 x2 + a33 x3 + f3 = x3

Letting x and f respectively be vectors of total demand x1 and final demand f1 ; and letting A be the x2 f2 x3 f3

A be the matrix of input coefficients a11 a12 a13 we can write the foregoing set of equations as A x + f = x. a21 a22 a23 a31 a32 a33

According to the rules of matrix algebra, one may pre-multiply x by the identity matrix I (whose elements are ones along the main diagonal and zeros elsewhere), giving

A x + f = I x, or

f = (I – A) x.

Pre-multiplying both sides of the equation by the inverse of I – A gives

(I – A)-1 f = (I – A)-1 (I – A) x = x

The term (I – A)-1 is called the Leontief Inverse, named after the economist who first formalized input-output analysis in computable form. The Leontief Inverse is the starting point for I/O multiplier analysis.

In general, a shock to an economic system in terms of a change to final demand can be written as Δf, and in this example the change in gross outputs required to meet the change in final demand plus the associated changes in intermediate demand can be written

Δx = (I – A)-1 Δf

One of the early applications of I/O was to explore ways of coping with the switch between wartime and peacetime economies, given that the war effort itself would make up a large part of final demand.

Real economies are more complicated than the example developed above. They have more industries, they engage in external trade, and they have governments that levy taxes and provide certain services. They also employ workers, who receive remuneration from which they finance personal consumption expenditures, taxes and savings; and capital, the returns to which, in an I/O framework, are not normally assumed to be spent. Real economies also have producer prices that are lower than the price paid by the purchaser because there are

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wholesale, retail and transportation “margins” to pay. Moreover, instead of a simple square I/O matrix like A, national statistical agencies more often resort to a rectangular matrix, in which outputs are from industries as before but inputs are classed as commodities that are more numerous than industries. For example, the agriculture industry produces both meat and crops. Unfortunately, only square matrices have inverses. In order to compute something comparable to a Leontief Inverse, one must first somehow transform a rectangular matrix into a square matrix. CERI employs a square industry-by-industry matrix similar to A above.

In place of the (I – A)-1 Δf, the CERI provincial I/O model (also known as UCMRIO2.0) computes direct plus indirect impacts on gross output as (I – C A)-1 C ΔF where C is the matrix of trade flows among pairs of provinces or territories, F is a matrix of shocks to final demand by region and industry, and A is now augmented with an extra row and column for households. Similarly, the provincial I/O model computes direct plus indirect plus induced impacts on gross output as (I – C A – C P)-1 C ΔF, where P is a matrix containing the fraction of the output of each region and industry devoted to satisfying personal consumption expenditure. Impacts on GDP, wages and salaries, and employment are calculated on the basis that the ratio of any of the foregoing variables to the gross output of an industry within a province or territory remains constant. The entire United States is accommodated within UCMRIO2.0 as if it were a province or territory. The relationship between CERI’s I/O models and the I/O tables of Statistics Canada and the US Bureau of Economic Analysis is described in Appendix D.

The Regional I/O model takes impacts at the provincial level as determined by the interprovincial model and allocates them to eight different regions in British Columbia and seven in Alberta. These regions are shown in Figure 3.1. Direct impacts are assigned to the region in which they occur. Indirect and induced impacts to an industry at the provincial level are assigned to each of the regions in proportion to their respective shares of the industry’s provincial output in the base year 2006. As there is no direct measure of output by region and industry, CERI had to rely largely on 2006 census division and subdivision data for experienced labour force by industry to impute a regional split of provincial output by industry. This procedure is described in more detail in Appendix C.

Input-output models were originally constructed for entire nations. Sub-national models have been developed in recognition of the fact that there are local peculiarities making a region different from the nation as a whole. For example, an increase in final demand for electricity in Saskatchewan or Alberta, that generate primarily using fossil fuels would have quite different impacts than at the national level where hydro predominates. Also, the smaller an economic area, the more prominent trade with “outside areas” becomes. At the other extreme, a model of the entire world economy would have no exports or imports. An interregional or multiregional I/O model looks at economic interactions among the various regions that it models. The emergence of regional science as a discipline distinct from geography has also fostered the development of regional and interregional I/O models, and pushed statistical agencies to collect and disseminate more of the relevant data.

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One of the uses of the regional I/O model is to help regional jurisdictions and municipalities plan for socio-economic implications. This can aid in helping in physical and social services planning such as future requirements for hiring personnel such as police, housing, hospitals, etc. and predict future loads on municipal services.

Figure 3.1 depicts the regional areas the pipelines and CN northern rail/line pass through.

Figure 3.1: Regional Mapping

Source: CERI, Google Earth, Kinder Morgan, Northern Gateway, CN

EdmontonKitimat Terminal

Vancouver

North Coast

Nechako

North East

Cariboo

Main-land

Thompson/Okanagon

Upper Peace Upper

Athabasca

North Sask.

Kinder Morgan TMXNorthern GatewayCN Rail

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Capital Costs and Operation Investment Assumptions

Kinder Morgan TMX If the expansion project goes ahead as planned, Kinder Morgan expects construction costs to be less than those that would be incurred on the Northern Gateway project. After a 2012 “open season” to gauge shipper interest, the company has secured 15- and 20-year shipper commitments and as a result, approved a $4.1 billion expansion that would increase capacity to as much as 750,000 bpd.1

The proposed expansion will run along the existing line (for the most part) and pass through two regions in Alberta and three in British Columbia as seen in Figure 3.1. In the Figure the pipeline is represented by a bright green line, which will pass through North Saskatchewan and Upper Athabasca regions in Alberta and Cariboo, Thompson/Okanagan and Mainland/ Southwest regions in BC.

TMX is assumed to come in service with full available capacity in 2018, with a two-year construction period spanning 2015 to 2016. In 2017 it is assumed that the company will spend some time debottlenecking and air testing the pipe, hence only 90 percent of available capacity is assumed to be online in that year. CERI used a $5 billion cost estimate for the TMX as the capital injection into the provincial and regional I/O models. The project capital costs were disaggregated into various project expenditure components and by year, in which investment is made. These estimates are based on the Oil & Gas Journal’s Pipeline Report,2 the Northern Gateway Application Table 2.3 in Volume 1 of the regulatory application, and various Kinder Morgan investor presentations and open season documentation. The results are shown in Table 3.1.

Table 3.1: TMX Expenditures by Project Component ($CDN Million)

Project Component % 2009 2010 2011 2012 2013 2014 2015 2016 2017

Pipeline Materials 19 0 0 0 0 0 0 522.5 380 47.5

Pump Materials 5 0 0 0 0 0 0 137.5 100 12.5

Regulatory/ Consultancy

5 0 0 0 59.2 65.8 72.4 52.6 0 0

Construction and Other Costs

71 0 0 0 0 0 0 1,952.5 1420 177.5

Total 100 0 0 0 59.2 65.8 72.4 2665.1 1900 237.5

*Totals may not balance due to rounding. 1At the time when I/O results were being estimated, the expansion was at 550,000 bpd and initial investment was $5 billion. However, at the end of May 2012 Kinder Morgan decreased capacity addition by 100,000 bpd, bringing the total expansion to 450,000 bpd. 22010 US Pipeline Costs Study – Onshore. November 1st 2010. Oil and Gas Journal.

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Alberta and BC regional disaggregation for construction and operation was dependant on the ratio of regional pipe length to be built to the total twinned pipe length to be built for the construction phase; and the ratio of regional pipe length to the entire TMX length for the operational phase. These ratios were obtained by mapping the pipe onto Google maps and measuring the approximate distances within each region. Kinder Morgan investor presentations and NEB filings indicated the length and location of segments already built; these segments were removed from the total length for the construction phase. Table 3.2 summarizes the ratios.

Table 3.2: TMX Pipe Length Ratios by Region

Region Ratio Construction Phase Ratio Entire Length Operational Phase

Alberta Land Use Frame Work Regions North Saskatchewan 0.14 0.10 Upper Athabasca 0.16 0.25

British Columbia Regional Developmental Regions Cariboo 0.05 0.10 Thompson/Okanagan 0.40 0.36 Mainland/Southwest 0.25 0.18

*may not total 1 due to rounding

Given that not all the required material and equipment could be locally sourced, pipeline and pump materials were considered to be manufactured in different regions of Canada and the US. The split is presented in Table 3.3

Table 3.3: TMX Material Sources

Pipeline Materials Pump Materials Alberta (N. Sask Reg) – 20% Alberta (N. Sask Reg) – 15% Saskatchewan – 80% Ontario – 30% BC (Mainland Region) – 30% United States – 30%

The construction phase assumes that 50 percent of capital is spent in Year 1 of construction and 45 percent of expenditures in Year 2, with the remaining 5 percent in the year of commissioning. To estimate economic impacts of constructing and operating TMX within various regions of two provinces, CERI needed to split the capital injections by region. Table 3.4 summarizes these capital injections for affected regions in Alberta and BC.

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Table 3.4: TMX Capital Investments by Region and Year ($CDN Million)

Year Alberta British Columbia Saskatchewan Ontario US Total

North Saskatchewan

Upper Athabasca

Cariboo Thompson/ Okanagan

Mainland/ Southwest

2009 0 0 0 0 0 0 0 0 0 2010 0 0 0 0 0 0 0 0 0 2011 0 0 0 0 0 0 0 0 0 2012 59.2 0 0 0 0 0 0 0 59.2 2013 65.8 0 0 0 0 0 0 0 65.8 2014 72.4 0 0 0 0 0 0 0 72.4 2015 455.0 314.0 99.8 776.3 519.6 418.0 41.3 41.3 2665.1 2016 292.6 228.4 72.6 564.6 377.9 304.0 30.0 30.0 1900.0 2017 36.6 28.5 9.1 70.6 47.2 38.0 3.8 3.8 237.5 Total 981.6 570.9 181.5 1411.4 944.7 760.0 75 75 5000.0

*totals may not add due to rounding

The expanded Trans Mountain pipeline is expected to be 90 percent of full capacity in 2017 and to reach full capacity in 2018. The operating cost per year is assumed to be nearly 2.3 percent of initial capital expenditures. Sustaining capital (i.e., capital spent on the pipeline to maintain desired operations) is an annual average of 0.1 percent of initial capital expenditures, applicable to all years of operation. Table 3.5 breaks down the operating and sustaining capital costs by region in the first two years of operation.

Table 3.5: TMX Operating and Sustaining Capital Expenditures by Region ($CDN Million)

Operation North Saskatchewan

Upper Athabasca

Cariboo Thompson/ Okanagan

Mainland/ Southwest

2017 Operating 10.37 24.70 9.86 35.94 18.14 Sustaining Capital

0.52 1.25 0.50 1.82 0.92

2018 Operating 11.52 27.44 35.94 39.93 20.16 Sustaining Capital

0.52 1.25 1.82 1.82 0.92

*totals may not add due to rounding

Northern Gateway The capital expenditures are sourced from Enbridge’s regulatory application for the Northern Gateway project. Enbridge stated that the capital cost of the pipeline will be $5.54 billion, which CERI converted from assumed-to-be 2009 real dollars into 2010 real dollars making total construction expenditures $5.71 billion. Total expenditures were split by year from 2009 to 2017, according to Figure 4-1 from the updated portion of Volume 6C in the Enbridge

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Regulatory Application.3 These total numbers were then split depending on region and whether the project was still in “pre-planning”, construction, or post-construction (operational) phase. A number of assumptions were needed and are described in this section.

The regions were generally split according to estimated physical length per region. These results are shown in Table 3.6.

Table 3.6: Kilometres in Each Region as Defined by the Northern Gateway Application and Regions as Defined for CERI’s Regional Model

Northern Gateway Application

Approximate Kilometres

Alberta Land-Use and BC Development Regions

Approximate Kilometres

Edmonton Region 70 (0-70) North Saskatchewan 70 (0-70) Central Alberta Region

170 (70-240) Upper Athabasca 170 (70-240)

Northwest Alberta Region

277.7 (240-517.7) Upper Peace 277.7 (240-517.7)

Northeast BC Region 104.2 (517.7-621.9) Northeast Region 104.2 (517.7-621.9) Central BC Region 441.1 (621.9-1063.0) Cariboo & Stikine4

- Cariboo Region

- Nechako Region

172.1 (621.9-794.0) 269.0 (794.0-1063.0)

Coastal BC Region 107.2 (1063.0-1170.2) North Coast Region 107.2 (1063.0-1170.2)

For the pre-construction period it was assumed for the years 2009-2012 that the splits were the same as described in Tables 4.4-14 in the updated Volume 6C of the regulatory application.5 However, CERI assumes the project will be slightly delayed in comparison to this time frame and consequently the 2012 costs have been split over the years 2012/2013 with construction commencing in 2014. 2014 has construction costs in it that would most likely encompass finalized engineering studies and landscaping.

Determination of the capital costs during the construction period was completed internally by CERI. The first step was determining the number of workers for pipelines, pump stations,

3Enbridge Regulatory Application, Volume 6C. May 2010. http://www.northerngateway.ca/assets/pdf/application/Master_Vol%206C_Final_12May10.pdf. Accessed on June 19, 2012. 4The Cariboo & Nenchako regions were split from the Central BC Region numbers by a ratio of the kilometres of each region to the total region. 5Enbridge Regulatory Application, Volume 6C. May 2010. http://www.northerngateway.ca/assets/pdf/application/Master_Vol%206C_Final_12May10.pdf. Accessed on June 19, 2012.

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tunnels, tank terminal and marine terminal for each year of the project. Then the ratio of these workers to the total number of workers for each respective region was determined. These ratios were then multiplied by the estimated expenditures for pipelines and tunnels, pump stations, initiating stations, tank terminal and marine terminal, as portrayed in Tables 4.4-13 from the updated Volume 6C.6 These estimated costs by year and region were expressed as a percentage of their annual total to constrain them in order to sum to the total project capital cost (see Table 3.8). Pipeline expenditures in the Cariboo and Stikine regions were allocated by distance, whereas the pump station expenditures were split by the number of pump stations in each region (0.25 for Cariboo, 0.75 for Stikine). This type of apportionment was necessary due to the discrepancy in the breakdown of expenditures from one application and table to the next (e.g., project execution costs in Table 2.3 of Volume I of the application excluded from the project construction costs by region in Tables 4.4-13 of the updated Volume 6C). However, there were some issues with this methodology – one is evident in the year 2015 for the North Coast Region as the total calculated expenditures per year drop although the construction schedule as described by the application would imply that they should have remained more or less unchanged. Capital expenditures made outside of Alberta and British Columbia are shown in Table 3.9. Approximately $1 billion will be spent in the provinces of Saskatchewan and Ontario, the US and some offshore.

For post-construction, it was assumed that the year 2018 will be a “ramp-up” time for the project with full operations beginning in 2019. Consequently, for operations and maintenance7 only 50 percent of the fully operational number was utilized for 2018. The monetary value of Northern Gateway’s operation was based on information from Table 4.1 in Volume 2 of the application,8 which showed estimated expenditures for each year from 2016-2020. All of the nominal numbers were converted into constant 2010 dollars. Other post-construction costs include sustaining capital, split by kilometres of pipe in each region. This number is the same for each year on the idea that this is a rolling reserve and is estimated at 0.1 percent of the initial capital expenditures (see Table 3.10).

In addition to the above assumptions, Table 3.7 includes estimates for materials purchased in regions other than Alberta and BC that were subtracted from the total.

6Ibid. 7Operations and Maintenance do not include Property or Corporate Taxes. 8Enbridge Regulatory Application, Volume 2. May 2010. http://www.northerngateway.ca/assets/pdf/application/Master_Vol%202_Final_11May10.pdf. Accessed on June 19, 2012

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Table 3.7: Northern Gateway Other Region Estimates

Pipeline Materials Pump Materials Kitimat Terminal Materials Alberta (N. Sask Reg) – 20% Alberta (N. Sask Reg) – 15% Alberta (N. Sask Reg) – 15% Saskatchewan – 80% Ontario – 30% BC (Mainland SW Reg) – 25% BC (Mainland SW Region) –

30% Ontario – 30%

United States – 30% Offshore – 30%

Table 3.8: Northern Gateway Capital Expenditures by Region and Year for Alberta and BC (million $CDN 2010)9

Alberta British Columbia Total Year N. Sask

Region Upper Atha.

Upper Peace

North East

Cariboo Nechako North Coast

Mainland/ Southwest

2009 99.3 5.0 10.1 3.3 14.8 23.1 15.6 0 171.2 2010 16.5 0.8 1.7 0.6 2.5 3.8 2.6 0 28.5 2011 33.1 1.7 3.4 1.1 4.9 7.7 5.2 0 57.1 2012 41.4 2.1 4.2 1.4 6.2 9.6 6.5 0 71.3 2013 41.4 2.1 4.2 1.4 6.2 9.6 6.5 0 71.3 2014 159.3 7.9 24.8 5.2 25.2 39.4 88.0 3.8 353.6 2015 36.8 16.5 125.2 17.0 47.4 89.4 334.1 31.7 698.1 2016 223.0 162.5 215.7 40.6 300.8 492.3 223.6 52.1 1710.4 2017 82.4 74.0 152.8 222.3 221.9 359.7 338.5 18.7 1470.2 2018 0.6 - - - - - 52.9 1.0 54.6 Total 733.7 272.6 541.9 292.9 629.9 1034.6 1073.6 107.4 4686.5

*Totals may not add up due to rounding errors

Source: CERI (RIO).

9Split using expenditures as described by Figure 4-1 Volume 6C, Table 4.4 in Volume 6C update (specifically Project Engineering/Design and Management Costs by Region, Peak Workforce Requirements during Construction by Region, Project Construction Costs by Region, Capital Expenditures).

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Table 3.9: Northern Gateway Capital Expenditures Outside of Alberta and BC (million $CDN 2010 dollars)

Year Saskatchewan Ontario US Offshore Total 2009 0 0 0 0 0 2010 0 0 0 0 0 2011 0 0 0 0 0 2012 0 0 0 0 0 2013 0 0 0 0 0 2014 8.1 4.6 0 4.6 17.3 2015 53.3 38.1 17.6 20.5 129.5 2016 418.9 62.5 42.8 19.7 543.9 2017 282.8 22.4 15.3 7.1 327.6 2018 0 1.2 0 1.3 2.5 Total 763.1 128.8 75.7 53.2 1020.8

*Totals may not add up due to rounding errors

Source: CERI (UCMRIO 2.0).

Table 3.10: Northern Gateway Operating and Sustaining Capital for Each Region10 (million $CDN 2010 dollars)

Year North Sask.

Upper Atha.

Upper Peace

N.E. BC Cariboo Nenchako N.C.

2018 Operating 8.35 11.22 13.74 5.10 6.22 12.13 6.93 Sustaining Capital

0.35 0.84 1.38 0.52 0.86 1.34 0.53

2019+ Operating 16.70 22.45 27.48 10.20 12.44 24.27 13.86 Sustaining Capital

0.35 0.84 1.38 0.52 0.86 1.34 0.53

Source: CERI (RIO).

10Sustaining capital numbers split by kilometers of pipe in each one of the proposed regions. Operating expenditures were estimated from Table 4-6 in Volume 6C (Annual Project Operating Expenditures). Taxes were removed from this total; power was divided by power requirements as required by the pump stations in each region. Operating wages were split by people employed in each region. All other operations and maintenance were split by kilometers of pipe.

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Chapter 4 Economic Impacts of Pipeline Construction and Operation This chapter describes economic impacts derived from expenditures on both construction and operation of the TMX and Northern Gateway pipeline systems. These pipelines are considered in isolation from other infrastructure and oil sands projects, and are the product of CERI’s proprietary economic models, including a newly-developed Regional Input-Output (RIO) model that considers impacts within regions of British Columbia and Alberta. Appendix C provides a detailed description of CERI’s Regional I/O methodology. Estimated impacts from these two pipeline systems include the following:

• Provincial and regional GDP, employee compensation, and employment increases between 2011 and 2035 as a result of pipeline construction and operation.

• Direct, indirect, and induced employment, at the provincial and regional levels, resulting from pipeline construction and operation.

• Provincial and regional tax receipts between 2011 and 2035 that result from pipeline construction and operation during that time.

Listed in Appendix A are economic impacts felt in the United States over the next 25 years as a result of the construction and operation of these two crude oil pipeline projects. As most of the equipment procurement and work is carried out within Canada, economic impacts felt in the US are relatively minor in comparison. Nevertheless, it is interesting to note that significant GDP and employment will be generated in the larger, more industrialized states such as California, Texas, Ohio, and New York.

It is important to emphasize that the projected impacts described in this report do not include any impacts on economies caused by increased oil sands supply. Those specific impacts are presented in Part I of the Pacific Access report, ”Linking Oil Sands Supply to New and Existing Markets”.

TMX Pipeline Economic Impacts

TMX Provincial I/O Impacts Over the next 25 years, construction and operation of the TMX pipeline will affect the provincial economy of British Columbia the most – more impact within that one province than in the rest of the Canadian provinces combined (see Figure 4.1). Almost all remaining pipeline construction1 will take place within BC now that pipeline looping in two of the national parks that border Alberta and BC (Jasper and Mount Robson) has been completed. And as BC is

1There is a 120 km stretch of line in the North Saskatchewan region of Alberta that is also being expanded.

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mountainous – with the pipeline cutting through remote areas – construction, operations, and maintenance will be expensive.

BC will see the largest GDP impact of $4.4 billion over the next 25 years, which includes construction and operation phases. Alberta stands to gain almost CDN$2.4 billion – 30 percent of the total – in additional GDP growth. The Kinder Morgan Canadian head office is located in Calgary, for example, creating a revenue hub in that city; there are also several pipe mills within the province that will generate more revenue during the construction phase of the project. It is notable that Saskatchewan, with a much smaller manufacturing base than Ontario, almost matches the Eastern province in terms of total GDP generated over 25 years: $483 million vs. $523 million. Saskatchewan benefits are associated with that provinces’ centre for pipe manufacturing.

Figure 4.1: TMX Pipeline, Impact on Provincial GDP – Investment and Operations

SOURCE: CERI.

Figure 4.2 shows total employment created and preserved during the construction and operation of the Trans Mountain pipeline expansion. The figure highlights that the highest number of jobs will be experienced during the construction phase of the project. A spike occurs when shovels hit the dirt in 2015, with 16,000 direct jobs being created in that year. Over 11,000 direct jobs are either created or maintained the following year, with the construction wrapping up in 2017 and most employment (2,500 jobs) from that time forward reflecting ongoing operations and maintenance to the line. Indirect and induced employment follows a

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similar trend, with maximum impacts being seen in 2015, declining in 2016, and modest employment being sustained in the last year of construction.

Figure 4.2: TMX Pipeline, Jobs Created and Preserved in Canada through Pipeline Construction and Operation (thousands of jobs)

SOURCE: CERI.

On a provincial basis, employment impacts follow GDP impacts, with British Columbia seeing the largest share of job creation and employee compensation, 59 percent and 58 percent, respectively (see Figures 4.3 and 4.4). Alberta will also benefit from the construction and operation of the Trans Mountain pipeline expansion. The province stands to gain 27 percent of all job creation and 30 percent of all employee compensation (see Figures 4.3 and 4.4). A good number of managerial jobs, many of which will be longer-term and operations-related, will be established in Alberta. British Columbia will see more of the short-term construction jobs, though operations employment within the province will also increase. Outside of Alberta and British Columbia, there will be far less employment impact – only about 14 percent of all pipeline-related employment will be created east of Alberta, and almost all of that will be investment/construction related work.

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Figure 4.3: TMX Pipeline, Impact on Employment (Thousand person-years Investment and Operations

SOURCE: CERI.

Figure 4.4: TMX Pipeline, Impact on Employee Compensation Investment and Operations

SOURCE: CERI.

TMX will generate a total of $2.13 billion in tax revenues over the 25 year period, with $1.31 billion collected by the government of Canada (62 percent), $522 million (24 percent) by the provincial and municipal governments in BC, $134 million (6 percent) by Alberta, $72 million (3

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percent) by Ontario, and the rest, $93 million (4 percent), spread throughout the remaining provinces. Figure 4.5 shows that the two provinces through which the pipeline runs (BC and Alberta), are the jurisdictions in which most taxes are paid. While Alberta pays only 36 percent indirect taxes, BC pays 52 percent indirect taxes; the higher taxes in BC are due to the Harmonized Sales Tax (HST); while Albertans pay GST only.

Figure 4.5: TMX Pipeline, Taxes Paid Investment and Operations

SOURCE: CERI.

TMX Regional I/O Impacts In BC, the expanded Trans Mountain pipeline will pass through a small portion of the Cariboo region, and then cut through the middle of Thompson/Okanagan, before running mostly parallel to the US border in the Mainland/Southwest region as seen in Figure 1.3. Direct GDP therefore occurs in these three regions of BC, with Thompson/Okanagan seeing $980 million (56 percent) in direct GDP growth, the Mainland/Southwest benefiting by $588 million (34 percent), and Cariboo impacted by $182 million (10 percent) over the 25-year period. As shown in Figure 4.6, these areas see considerable indirect and induced impacts as well. The Vancouver Island/Coast receives no direct GDP impact, but by virtue of its significant population and highly developed interregional trade, generates greater overall GDP than the sparsely populated

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Cariboo region. Employment impacts follow a similar pattern as GDP impacts, with Mainland/Southwest, Thompson/Okanagan and Vancouver Island/Coast regions experiencing the highest employment impacts, as seen in Figure 4.7.

Figure 4.6: TMX Pipeline, GDP by Region, BC Investment and Operations

SOURCE: CERI.

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Figure 4.7: TMX Pipeline, Employment by Region, BC Investment and Operations

SOURCE: CERI.

Within Alberta, there are three regions that see the majority of GDP impact: North Saskatchewan will have the greatest GDP impact of all the regions totaling $928 million over the 2011-2035 time period, followed by Upper Athabasca with $594 million of which $535 million is direct GDP impact, and South Saskatchewan closely following with $558 million in additional GDP. The pipeline begins in Sherwood Park, which is within the North Saskatchewan region. Then it moves into the Upper Athabasca region, and stays in that region until reaching the BC border. Direct GDP impacts are thus felt in these two regions. Figure 4.8 shows that North Saskatchewan sees much more indirect and induced GDP than Upper Athabasca simply because the City of Edmonton is located there and economic activity is more pronounced than in the more rural Upper Athabasca region. North Saskatchewan is also notable because of the pipe mills in the Camrose area that will be manufacturing pipe for the TMX project. Employment trends, as indicated in Figure 4.9, follow the GDP trends in all Alberta regions.

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Figure 4.8: TMX Pipeline, GDP by Region, AB Investment and Operations

SOURCE: CERI Figure 4.9: TMX Pipeline, Employment by Region, AB

Investment and Operations

SOURCE: CERI

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Northern Gateway Pipeline Economic Impacts

Northern Gateway Provincial I/O Impacts As with the TMX, the Northern Gateway Pipeline will impact British Columbia more than any other province over the next 25 years. All of the direct economic impacts occur in British Columbia and Alberta, primarily the former, and over half of the GDP impacts occur in British Columbia ($4.7 billion), where most of the pipe will be laid; another one-third of impacts will be felt in Alberta ($2.9 billion), home of the control system and Enbridge corporate head office, followed by 7 percent in industrial Ontario. Saskatchewan is close behind at 5.5 percent, reflecting its proximity to the pipeline and its steel and line pipe manufacturing industries, followed by Quebec at 2 percent and Manitoba at 1 percent. Figure 4.10 depicts the total economic impacts in terms of GDP over the 25-year period.

Figure 4.10: Northern Gateway Pipeline, Impact on Provincial GDP Investment and Operations

SOURCE: CERI.

It is noteworthy that Figure 4.11, which forecasts jobs created and preserved by the Northern Gateway project, demonstrates spikes in employment in five different years. In comparison, Figure 4.2, which forecasts jobs created and preserved by the TMX project, shows that spikes in employment occur over three different years, with most of the effect being felt in 2015 and 2016. There are several reasons for this difference. Firstly, the Northern Gateway project will

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break ground – with surveying being done and largely undisturbed areas of vegetation being cleared along an entirely new pipeline corridor. TMX, on the other hand, is being built on an existing corridor, with many of its access roads having been in place for over half a century. In addition, two major tunnels will need to be built for Northern Gateway, whereas there will be no need for this kind of work on TMX. Northern Gateway will require entirely new pipe from the Edmonton area to the BC coast, but sections of the TMX have already been completed. These are two very different projects with completely different employment requirements. Northern Gateway will need more time to complete than TMX, and that will result in jobs being preserved over a longer time span. The total number of jobs created and preserved (just over 5,000 in 2014) starts to ramp up during the construction phase. In 2016 the number of jobs reaches a peak of 30,000 and declines thereafter. During the operation phase, the estimated number of jobs drops significantly and averages approximately 2,500 per year thereafter.

Figure 4.11: Northern Gateway – Jobs Created and Preserved in Canada through Pipeline Construction and Operation (thousands of jobs)

SOURCE: CERI.

As expected British Columbia will see the highest employment impacts, with 70,000 person years of employment created and preserved in that province (see Figure 4.12). The second largest impacts will be felt in Alberta, followed by Ontario and Saskatchewan.

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Figure 4.12: Northern Gateway Pipeline, Impact on Employment (Thousand person-years) – Investment and Operations

SOURCE: CERI.

As with number of jobs, the workers in British Columbia will be highly compensated, with almost $3 billion paid out to employees of BC over the next 25 years (see Figure 4.13). This represents 55 percent of the total $5.1 billion in employee compensation across Canada.

Figure 4.13: Northern Gateway Pipeline, Impact on Employee Compensation – Investment and Operations

SOURCE: CERI.

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Of the $2.3 billion in tax revenues generated over the 25-year period, $1.452 billion (62 percent) would be collected by the Government of Canada, $545 million (23 percent) by the provincial and municipal governments in British Columbia, $162 million (7 percent) by Alberta provincial and municipal governments, and $83 million (4 percent) by Ontario provincial and municipal governments; the rest will be distributed to the remaining provinces. In terms of the jurisdictions that will contribute the most tax, Figure 4.14 shows that the areas in which the pipeline is located are the areas in which most tax will be paid. CERI has broken down the tax totals in Alberta and BC to indicate the different ways taxes are paid in those jurisdictions. Alberta does not have HST, so indirect taxes account only for 37 percent of total taxes paid. Residents of BC, on the other hand, pay a higher percentage of their taxes through HST than through personal income taxes or corporate taxes.

Figure 4.14: Northern Gateway Pipeline, Taxes Paid Investment and Operations

SOURCE: CERI.

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Northern Gateway Regional I/O Impacts Figures 4.15 and 4.16 depict British Columbia’s regional economic impacts from pipeline’s investment and operations on GDP and employment over the same 25-year period. Although there is very little direct impact in the Mainland/Southwest Region of BC, this highly urbanized region captures the lion’s share of spin-off effects and experiences the highest total economic impact of almost $1.8 billion of GDP growth and 25,200 person-years of employment created and preserved. Vancouver Island/Coast and Thompson/Okanagan, which receive no direct impact, capture smaller but significant shares of total regional GDP and employment impacts. The impacts on other regions that the pipeline passes through are mostly direct impacts, generally proportional to the number of kilometres of pipe that needs to be laid down during the construction phase.

Figure 4.15: Northern Gateway Pipeline, GDP by Region, BC Investment and Operations

SOURCE: CERI.

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Figure 4.16: Northern Gateway Pipeline, Employment by Region, BC (Thousand person-years) – Investment and Operations

SOURCE: CERI.

Figures 4.17 and 4.18 depict Alberta’s regional economic impacts on GDP and employment, respectively. Compared to its western neighbour, Alberta’s share of GDP and employment growth as a result of constructing and operating Northern Gateway is far lower for both variables. The largest impacts are experienced in the North Saskatchewan Region, where the pipeline begins and where system control is located. There will be $952 million generated in additional GDP and 12,600 person-years of employment created and preserved in this region. The South Saskatchewan Region, which contains the corporate head office but receives no direct impact, ranks second in total GDP impact and is in a virtual tie with Upper Peace for total employment impact. Not surprisingly, the two highly urbanized regions capture the greatest share of spin-offs.

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Figure 4.17: Northern Gateway Pipeline, GDP by Region, AB Investment and Operations

SOURCE: CERI.

Figure 4.18: Northern Gateway Pipeline, Employment by Region, AB Investment and Operations

SOURCE: CERI.

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Chapter 5 Conclusions In addition to the advantage of proximity, East Asia stands out as one of the few parts of the world where refining capacity and demand for refined petroleum products are rising.

Other possible outlets, such as the East Coast and, to a lesser extent, the US Gulf Coast are experiencing shrinking demand and refinery closures. They also have access to diverse supply sources that do not generally experience transportation capacity constraints.

While rail is emerging as a serious option to pipeline transportation, the former is subject at the present time to limited availability of rolling stock and storage capacity.

The least-cost way to move oil sands output to East Asian markets is by pipeline to Pacific port and super-tanker across the Pacific Ocean.

The lion’s share of economic impacts from pipeline construction and operation would occur in the provinces of British Columbia and Alberta, where the pipelines would be located. Of the other provinces, Ontario and Saskatchewan would experience the greatest economic impacts.

Within British Columbia and Alberta, the regions that experience the greatest impact are the regions in which the metropolitan areas of Vancouver, Edmonton and Calgary are located, followed by the other regions that the pipelines would cross, together with the Vancouver Island/Coast Region in which Victoria is located. The major exception is the Upper Athabasca Region that would experience stronger GDP impacts than the South Saskatchewan Region in which Calgary is located.

Regional impacts, as identified by CERI’s Regional I/O model, are a starting point in enabling municipal governments and other institutions to assess what is needed to accommodate the anticipated influx in terms of making available housing, schooling, social services, etc.

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Appendix A: Economic Impacts in the US–TMX and Northern Gateway Pipelines Construction and Operation

Table A.1: TMX Pipeline, Total Economic Impact of Pipeline Construction and Operation by US PADD

SOURCE: CERI.

Figure A.1: TMX Pipeline, Jobs Created and Preserved in the US through Pipeline Construction and Operation (thousands of jobs)

SOURCE: CERI.

Thousand Person Years

GDP Compensation of Employees

Employment

PADD I 387 194 4 PADD II 452 233 5 PADD III 182 79 2 PADD IV 50 24 1 PADD V 256 122 3 Total US 1,328 654 15

$CAD Million2010-2035

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Table A.2: TMX Pipeline, Total Economic Impact by US State through Pipeline Construction and Operation

SOURCE: CERI.

Thousand Person Years

GDP Compensation of Employees

Employment

Alabama 15 8 0Alaska 4 1 0Arizona 20 10 0Arkansas 8 4 0California 165 78 2Colorado 23 11 0Connecticut 18 9 0Delaware 4 1 0District of Columbia 4 2 0Florida 50 24 1Georgia 26 13 0Hawaii 3 1 0Idaho 6 3 0Illinois 97 50 1Indiana 59 33 1Iowa 14 7 0Kansas 13 6 0Kentucky 15 8 0Louisiana 23 8 0Maine 3 2 0Maryland 17 9 0Massachusetts 31 17 0Michigan 55 28 1Minnesota 24 12 0Mississippi 8 4 0Missouri 19 10 0Montana 11 5 0Nebraska 6 3 0Nevada 7 3 0New Hampshire 6 3 0New Jersey 31 15 0New Mexico 7 3 0New York 73 37 1North Carolina 35 17 0North Dakota 3 1 0Ohio 61 32 1Oklahoma 15 7 0Oregon 29 14 0Pennsylvania 43 22 1Rhode Island 3 2 0South Carolina 14 7 0South Dakota 3 1 0Tennessee 24 12 0Texas 122 54 1Utah 8 4 0Vermont 2 1 0Virginia 24 12 0Washington 28 14 0West Virginia 4 2 0Wisconsin 44 23 1Wyoming 3 1 0Total US 1,328 654 15

$CAD Million

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Table A.3: Northern Gateway Pipeline, Total Economic Impact of Pipeline Construction and Operation by US PADD

SOURCE: CERI.

Figure A.2: Northern Gateway Pipeline, Jobs Created and Preserved in the US through Pipeline Construction and Operation (thousands of jobs)

SOURCE: CERI.

Thousand Person Years

GDP Compensation of Employees

Employment

PADD I 426 214 5 PADD II 491 253 6 PADD III 200 87 2 PADD IV 54 26 1 PADD V 282 135 3 Total US 1,453 716 17

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Table A.4: Northern Gateway Pipeline, Total Economic Impact by US State through Pipeline Construction and Operation

SOURCE: CERI.

Thousand Person Years

GDP Compensation of Employees

Employment

Alabama 17 8 0Alaska 4 1 0Arizona 22 11 0Arkansas 9 4 0California 182 87 2Colorado 25 12 0Connecticut 19 10 0Delaware 4 2 0District of Columbia 4 2 0Florida 55 26 1Georgia 29 15 0Hawaii 3 2 0Idaho 6 3 0Illinois 103 53 1Indiana 63 35 1Iowa 16 8 0Kansas 14 7 0Kentucky 17 8 0Louisiana 24 8 0Maine 4 2 0Maryland 19 10 0Massachusetts 35 19 0Michigan 60 31 1Minnesota 26 13 0Mississippi 8 4 0Missouri 21 11 0Montana 11 5 0Nebraska 7 3 0Nevada 8 4 0New Hampshire 7 4 0New Jersey 34 17 0New Mexico 7 3 0New York 80 40 1North Carolina 39 19 0North Dakota 3 1 0Ohio 67 35 1Oklahoma 17 7 0Oregon 32 16 0Pennsylvania 47 24 1Rhode Island 4 2 0South Carolina 15 8 0South Dakota 4 2 0Tennessee 27 14 0Texas 135 59 1Utah 9 4 0Vermont 2 1 0Virginia 26 13 0Washington 30 15 0West Virginia 4 2 0Wisconsin 47 24 1Wyoming 3 1 0Total US 1,453 716 17

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Appendix B: Development of CERI Input-Output (I/O) Models 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 (StatsCan) 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”.

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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 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 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

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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.

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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

th i & T it i

Impacts on Quebec’s Economy (GDP, employment, demand for goods & services Government revenues)

Total Impact on the US

Economy (GDP,

Employment, Demand for

Goods & Services

Government Revenues)

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Projection of investment and value of output at

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Allocation of investment and outputs to goods,

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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.

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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.

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

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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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 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 the 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.

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.

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

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

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.

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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

∆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

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

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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.

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

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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. 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 the 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 multi-regional 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. 10We do not study impacts on Rest of the World (ROW), because it is exogenous according to our assumption. 11For 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.

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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 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 12See http://www.meti.go.jp/english/statistics/tyo/kokusio/index.html

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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 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.

13The 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. 14The 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

Gross Output

Comm

odities

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

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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, 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).

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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 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.

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Appendix C: Regionalization of Data for Regional I/O Model CERI’s Regional I/O model divides Alberta into seven regions and British Columbia into eight. The eight in BC are called Development Regions by the British Columbia government and Economic Regions by Statistics Canada. They contain whole census divisions. Alberta’s seven regions were set forth in the province’s recently-published Land Use Framework; their boundaries were unknown at the time of the 2006 census of population, and in many cases they contain parts of census divisions. It was necessary to aggregate information at the census subdivision level to derive census data for each of the seven Alberta regions. An extra step was required to transform Alberta census division data into regional data by applying the percentage split of each census division’s population among the regions that it belongs to.

Information by census division in E-stat’s cumulative profiles for each province from the 2006 census in respect of population, employment, unemployment rate, and experienced labour force by industry, among other things, is given in somewhat finer detail than in StatsCan’s community profiles on the latter’s public website. Experienced labour force is identified in community profiles for the following categories of industries: agriculture and other resource-based industries, construction, manufacturing, wholesale trade, retail trade, finance and real estate, health care and social services, educational services, business services, and other services. The experienced labour force information by industry on E-stat’s cumulative profiles, in contrast, conforms more closely to the format of CERI’s Regional I/O model as it also includes utilities, transportation and warehousing, information and cultural industries, professional scientific and technical services, management of companies and enterprises, administrative and support, arts, entertainment and recreation, accommodation and food services, other services (except public administration), and public administration.

The corresponding information for gross output, GDP, and wages and salaries was not available by census division from the 2006 census, and therefore had to be estimated by assuming that the percentage split among regions would mirror that of experienced labour force. CERI’s Regional I/O model requires that resource-based industries be broken down into crop and animal production, forestry, fishing/hunting/trapping, oil, oil sands, natural gas and liquids, coal, and other mining. It also requires that “manufacturing” be broken down into petrochemicals, oil refining, and other manufacturing. Information on other industrial categories separately identified in CERI’s Regional I/O model is available from Statistics Canada at provincial levels but not in community profiles. CANSIM matrix 282-0008 contains provincial labour force information, and has the additional virtue that it separately identifies agriculture, fishing, and hunting/trapping. CANSIM matrix 281-2003 contains the corresponding provincial information on employment; matrix 397-0026, on GDP; and matrix 381-0016, on gross output.

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Even at a provincial level, statistics on refining and petrochemicals are lacking for British Columbia because it has only two oil refineries and no sizeable petrochemical facility. (A methanol plant and an ammonia plant at Kitimat were shut down in 2005 and have been almost completely dismantled. They are slated to be shipped to China.) Similarly, the Atlantic Provinces have three refineries, each located in a different province. Statistics Canada keeps information on individual facilities confidential in order to avoid disclosing it to potential competitors, so it will publish aggregate information only if it encompasses at least three reporting entities. The only information CERI could find on a facility-by-facility basis is emissions data available through Environment Canada, and even that database excludes small facilities whose emissions are below a threshold number. Refinery GDP, employment, labour income and gross output were allocated among the provinces in proportion to physical output of refined petroleum products (RPPs). Saskatchewan and British Columbia RPP output data were combined due to the residual disclosure problem, so a further allocation of GDP, employment, labour income and gross output was done among the three refineries in those two provinces in proportion to capacity. The Prince George refinery owned by Husky is located in the Cariboo Region; the Burnaby refinery owned by Chevron is located in the Mainland/Southwest Region. All operating refineries in Alberta are located in the North Saskatchewan Region. (The idle refinery at Bowden is in the Red Deer Region.) Economic activity in all forms for the petrochemical industry of British Columbia was taken to be 1 percent of manufacturing, and was assigned to the Mainland/Southwest Region; economic activity by region for “petrochemicals” (excluding fertilizer) was estimated by apportioning the corresponding Alberta provincial number based on Environment Canada’s greenhouse gas emissions data by facility, aggregated by region; economic activity by region for “fertilizers excluding potash” was estimated by apportioning the corresponding Alberta provincial number based on published ammonia capacity by plant, aggregated by region. There are no fertilizer manufacturing plants in British Columbia.

Farm revenue figures by census division for agriculture and forestry were obtained from the 2006 Census of Agriculture. Provincial totals for employment, labour income, GDP and gross output for agriculture and for forestry were allocated regionally based on each region’s percentage of provincial farm agricultural revenue and farm forestry revenue. In Alberta, an additional step was required because a few census divisions’ farm forestry revenues were not disclosed. The sum of their farm forestry revenues (obtained residually) was allocated among them in proportion to the number of farms in each. British Columbia’s fishing/trapping gross output, GDP, labour income and employment were allocated among its three coastal regions on a per capita basis. The commercial fishing/trapping industry in Alberta is minute. Based on a casual review of the literature, the assumption was made that 65 percent of the industry is located in the North Saskatchewan Region, 20 percent in the South Saskatchewan Region, and the remaining 15 percent in the Red Deer Region.

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Appendix D: Oil Pipeline Capacities in Western Canada and Elsewhere in North America This section briefly explores 20 existing liquids pipelines in Western Canada. The list of pipelines includes pipelines that either originate in or operate within in the Western Canadian Sedimentary Basin (WCSB).

Table D.1: Existing and Proposed Regional Pipeline Capacity in Alberta

Source: CERI

Type Destination Capacity Start Date

Enbridge - Athabasca PipelinesExisting Product & bitumen Hardisty 390 570 Fall 2013Athabasca pipeline twinning project Product & bitumen Hardisty 450 2015-2016

Inter Pipeline Fund -Corridor Pipelines 465Corridor Pipeline Diluent, products 300 2011Corridor Expansion DilBit 165 2011Polaris 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 unknownCold Lake West Edmonton 247Cold Lake South Hardisty 221

Husky - Husky Oil Pipeline Hardisty 491Lloydminster

Elan, Gibson - Echo Pipeline Heavy Oil Hardisty 76

TOTAL 1,034

Plains Midstream Canada - Rainbow PipelinesRainbow 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

To Edmonton: 2,195 To Hardisty: 1,177

From Peace River

Name Expansion/New Project

('000 bbl/d)From Athabasca Region

Edmonton

From Cold Lake Region

oil sands & condensate

Heavy Oil and SCO

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Figure D.1: Existing Pipeline Capacities and Production, Alberta

Source: CERI

PipelineCapacity to Edmonton:

2.19 MMbpdPipeline

Capacity to Hardisty:

1.18 MMbpd

0

2,000

4,000

6,000

2010

2015

2020

2025

2030

2035

Athabasca Region('000bpd)

0

500

1,000

1,500

2010

2015

2020

2025

2030

2035

Cold Lake Region ('000bpd)

0

100

200

300

400

2010

2015

2020

2025

2030

2035

Peace River Region('000bpd)

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Table D.2: Existing Export Pipelines

Source: CERI

Name Type Destination Capacity ('000b/d)

Eastern CanadaU.S. East coastU.S. Midwest

Kinder Morgan Express) Crude oil U.S. Rocky Mountains/U.S. 280British ColumbiaU.S. West Coast

OffshoreEnbridge Alberta Clipper Heavy crude US Midwest 450TransCanada Keystone Light/heavy crude US Midwest 435

TOTAL 3,536

Enbridge Mainline Crude oil 1,868

Kinder Morgan (Trans Mountain) Crude oil & Refined Products

300

Milk River Pipeline Light oilU.S. Rocky Mountains

118

Rangeland Pipeline Cold Lake blendU.S. Rocky Mountains

85

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Table D.3: Cushing Pipelines and Rail Into and Out of Existing and Proposed

Transportation Project Destination Capacity (bpd)

Date Online Capital

Existing Into Cushing Enbridge Spearhead

(Flanagan) Flanagan, IL to

Cushing, OK 193,300

Magellan Cushing to Tulsa, OK

Unknown

Occidental Petroleum

Centurion Permian Basin to Cushing, OK

350,000

Plains Red River Sabine, TX to Cushing, OK

22,000

Plain Basin Pipeline System

Colorado City, TX to Cushing,

OK

400,000

Plains Cheyenne 55,000 Plains Med-Ford to

Cushing 25,000

Plains Cashion Unknown Unknown Plains Cherokee Unknown Unknown TransCanada Keystone

Phase II Hardisty, AB to

Cushing, OK 591,000

Western Gas White Cliffs Pipeline

Denver, CO to Cushing, OK

30,000

Proposed Pipelines Into Cushing Enbridge Flanagan

Expansion Flanagan, IL to

Cushing, OK 585,000 Possible 800,000

Mid-2014 2.8 billion

Kinder Morgan Pony Express Guernsey, WY to Cushing, OK

210,000 First Quarter 2014

ONEOK Bakken Stanley, ND to Cushing, OK

200,000 2015 1.5-1.8 billion

Parnon Gathering

Create Salt Plains

Pipeline

Cherokee to Cushing

35,000 (Expansion full

capacity)

Plains Mississippian Lime

Alva, OK to Cushing, OK

175,000 Mid-2013

Plains Basin Expansion

50,000 First half 2012

Western Gas White Cliffs Denver, CO to Cushing, OK

50,000 (Expansion full

capacity)

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Existing Pipelines out of Cushing Blue Knight Energy

Cushing, OK to Valero Refinery in Ardmore, OK

20,000

BP Cushing, OK to Whiting, IN

175,000

ConocoPhillips Cushing, OK to Ponca City, OK

130,000

ConocoPhillips Line 0 Cushing, OK to Borger, TX

37,000

Enbridge Ozark Cushing, OK to Wood River, IL

215,000

Enbridge Osage Cushing, OK to 2 Refineries KS

110,000

Enbridge/Exxon Pegasus Cushing, OK to Nederlands, TX

66,000

Enbridge West Tulsa 55,000 Occidental Petroleum

Centurion Cushing, OK to Slaughter, TX

60,000

Plains Cushing, OK to Broome

~200,000 (16 inch pipe)

Proposed Expansions out of Cushing Enbridge Seaway

Reversal Cushing, OK to

Valero 150,000 400,000 850,000

June 6th 2012 2013 2014

1 billion

TransCanada Gulf Coast Pipeline

Cushing, OK to Nederland, TX

700,000 830,000

Mid 2013

Rail Into Cushing Existing EOG Resources Stroud, OK 90,000 Rail Out of Cushing Unknown Out 5,000-10,000 Unknown Movements Total

32,000

Proposed Rail Into Cushing Watco 110,000

Source: Various Sources.

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Appendix E: Alternative Transportation Companies and Tolls

Figure E.1 North American Railway Map

Source: Wikipedia

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Figure E.2 Change in Direction of Oil in the United States

Source: CERI, Various Sources

CN Rail Given its continental network of existing rails, oil from Alberta can be transported from Fort McMurray to marine terminals in Vancouver, Kitimat and Prince Rupert, as well as to refineries in the southern US and US Gulf Coast (USGC) (see Figure E.3). CN operates in 8 provinces and 16 US States.1

1CN Rail, Transportation Solutions for Oil Sands Production Phase, Randy Meyer Presentation, The Van Horne Institute, May 13, 2009, http://www.vanhorne.info/files/vanhorne/2%20CN.pdf (pp. 3)

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Figure E.3: CN’s North American Railway Network

Source: CN Rail2

While CN connects directly, or with various affiliations with other railways, with refineries in the USGC, this study only focuses on the organizations linked to the BC west coast. And with their purchase of the Athabasca Northern Railway and Lakehead & Waterways Railway, CN now has access from Fort McMurray to three west coast terminals, passing directly through Alberta’s Industrial Heartland.3 The latter is illustrated in Figure E.3. In addition CN has pumped C$135 million to improve the old line, built on permafrost land.4 The track is now able to take heavy

2 CN Rail website, http://www.cn.ca/en/shipping-map-oil-sand-opportunities.htm 3 Canadian National Reinvents Oil Sands Transport, May 8, 2009, http://www.investingdaily.com/ce/17289/canadian-national-reinvents-oil-sands-transport.html (accessed on December 17, 2011) 4 Ibid.

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trains carrying bitumen. CN hopes to be transporting 10,000 bpd on the revitalized line by year-end, with the objective of ramping up to between 300,000 to 400,000 bpd in the near future.5

Canadian Pacific (CP) CP claims that it sees 80 percent of the cars go to the Gulf of Mexico and the rest to north-eastern US. Due to the lack of infrastructure near the Bakken oil field they have found their carloads increase by 50 percent. Currently, they have an estimated 13,000 carloads per year but expect the potential for Bakken oil to reach 70,000.6 They hope to be capable of exporting 320,000 bpd from the Bakken to New York.

BNSF Railway BNSF is primarily concerned with moving oil from the Bakken and claims to have capabilities of moving around 700,000 bpd on their network.7

Union Pacific Union Pacific, in relation with its partners, is hoping to ship 274,000 bpd on their networks.

Figure E.4: Union Pacific’s Railway Network.

Source: Union Pacific

5 Ibid. 6 CPR sees potential boom transporting oil by rail: 80% of cars go to Gulf of Mexico; rest to northeast. Oct. 26th 2011. Edmonton Journal. Accessed Nov. 17th 2011 from http://www.edmontonjournal.com/business/sees+potential+boom+transporting+rail/5610811/story.html 7 Bakken Oil Conference 2012.

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Table E.1: Comparison of Tolls

Company Toll ($/bbl) Route

Pipelines Westward Northern Gateway8 3.21 Oil

4.88 Condensate Bruderheim, AB to Kitimat, B.C.

TMX9 4.85-5.35 Heavy Oil Edmonton to WestRidge Dock Pipelines USA Enbridge Systems (mainline, mustang, spearhead) (all tolls for heavy oil)

2.13 0.90 2.81 2.33 3.92 4.83 3.90 5.90 5.25

Neche, ND to Flanagan, IL Neche, ND to Superior, WI Hardisty, AB to Superior WI Hardisty, AB to Clearbrook, MN Hardisty, AB to Flanagan, IL Hardisty, AB to Nanticoke, ON Hardisty, AB to Chicago, IL Hardisty, AB to Cushing, OK Hardisty, AB to Wood River, IL

Express-Platte System 1.77 heavy oil10 1.84 super heavy oil 2.25 heavy oil 2.34 super heavy oil

Hardisty, AB to Guernsey, WY Hardisty, AB to Wood River, IL

Plains Pipeline 0.73 0.39

St. James, LA to Wood River, IL Cushing, OK to Montgomery, KS

Seaway 0.55 0.33

Houma, LA to Cushing, OK Nederland, TX to Cushing, OK

TransCanada Keystone 5.85-6.20 5.30

Hardisty, AB to Cushing, OK Hardisty, AB to Wood River, IL

Railway Pacific Coast CN 6.80-8.89 (dilbit)

7.31-9.55 (undiluted bit) 5.45-7.64 (dilbit) 5.87-8.22 (undiluted bit) 5.79-7.81 (dilbit) 6.22-8.40 (undiluted bit) 4.52-6.26 (dilbit) 4.85-6.73 (undiluted bit) 6.94 (condensate) 5.07 (condensate)

Ft. McMurray, AB to Kitimat, BC Edmonton, AB to Kitimat, BC Ft. McMurray, AB to Van., BC Edmonton, AB to Vancouver, BC Kitimat, BC to Fort McMurray, AB Kitimat, BC to Edmonton, AB

8 From Northern Gateway Application; real 2009 dollars. 9 Numbers depend on length of commitment. Kinder Morgan Regulatory Application. Accessed January 12th 2012 from http://www.kindermorgan.com/business/canada/TMX_Documentation/OSPOct20.pdf 10 Heavy oil is assumed to have a density of 904-927 kg/m^3 and super heavy oil 927-990 kg/m^3

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Railway US & Other CN 7.84-9.71 (dilbit)

8.43-10.43 (undiluted bit) 7.13-9.00 (dilbit) 7.67-9.67 (undiluted bit) 5.66 (condensate) 10.02 (condensate) 18.83-22.31 (dilbit) 20.23-23.98 (undiluted bit) 9.38-10.76 (dilbit) 10.08-11.56 (undiluted bit)

Ft. McMurray, AB to Chicago, IL Edmonton, AB to Chicago, IL Chicago, IL to Hardisty, AB Chicago, IL to Ft. McMurray, AB Ft. McMurray, AB to Baton Rouge, LA Edmonton, AB to Baton Rouge, LA

BNSF 7.01 (dilbit) 7.58 (undiluted bit) 7.02 (dilbit) 7.54 (undiluted bit) 5.31 (dilbit) 5.71 (undiluted bit)

Vancouver, B.C. to Bakersfield, CA Chicago, IL to Port Arthur, TX Chicago, IL to Houston, TX

Tanker Tolls Petro Strategies Estimates11 2.22

1.60 2.27 2.08 1.61 1.51

North Europe to Houston, TX West Africa to N. Europe West Africa to Houston Persian Gulf to Houston, TX Persian Gulf to Japan Persian Gulf to N. Europe

Avg. Dirty Spot Oil Price 2011 (Jan to Jul)12

2.15

Source: FERC, CAPP, BNSF, CN

11Numbers are in real 2009 dollars. Accessed Dec 14th 2011 from http://www.petrostrategies.org/Learning_Center/oil_transportation.htm 122011. Oil and Energy Trends: 36(11)

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Appendix F: Refinery Capacity and Requirements The following Figures and Tables provide an overview of the existing refinery capacity. Note the required units to refine heavier crudes and the composition of crudes from around the world. Also portrayed is the general composition of crudes refined in each area of the US and refining capacity in the US and the Asia Pacific.

The modifications required to process heavy crudes depend on the existing configuration of the refinery, characteristics of the crude and the desired refined petroleum products. Bitumen blends require the use of coking and hydrocracking to upgrade the heavier components. The lighter segments are separated using conventional distillation methods. While petroleum coke is not a valuable product it can be gasified to produce hydrogen and energy to the refinery. Figure F.1 shows the required units. Table F.1 depicts the typical composition of the crudes. Table F.2 shows the type of crudes that are processed in each PADD. Figure F.2 and F.3 show the capacities of the units in each country. Of note from Figure F.2 and F.3 is the extensive coking and hydrocracking capacity in PADD III of the US and China. This makes both markets ideal destinations for bitumen. Most of the Asia Pacific and the East and West Coasts of the US are better suited towards lighter crudes or synthetic crude oil.

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Figure F.1: Generic Process Stream for a Refinery to Run Bitumen (adapted from The Oil and Gas Journal, Vol. 107, Issue 30)

H2 Potential New Unit

Expanded Existing Unit

Existing Unit

Optional Unit

Heavy Gas

Dilbit

Diluent Recovery Unit

Recovered Diluent

Bitumen

Conventional

Atmospheric Distillation

Vacuum Distillation

Naphtha Hydrotreater

Catalytic Reformer

Delayed Coker

Gas Oil Hydrotreater

Fluid Catalytic Convertor Gasoline

Hydrotreater

Distillate Hydrotreater

Sulphur Plant Hydrocracker

Gasifier Pet Coke

Steam Power

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Table F.1: Crude Distillation Yields as Estimated from the TIAX Report of Different Crudes

Boiling Range (F)

US Crudes Imported Crudes Canadian Crudes

WTI SJV Heavy

ANS Saudi Med.

Iraq Basrah Med.

Nig. Ven Bach 17

Mex. Maya

Bow River

Mining SCO

In Situ SCO

Synbit Dilbit

General Prop

API 39.6 13.6 32.0 30.3 31.0 35.3 16.7 21.1 20.7 32.2 39.4 21 21.2

S (Wt %) 0.49 1.38 0.90 2.57 2.58 0.16 2.40 3.38 2.85 0.16 0.00 2.53 3.69

Fractions

Gases C3 0.5 0.0 0.4 0.7 0.7 0.4 0.3 0.0 0.1 0.1 -- 0.1 0.0 C4 1.6 0.0 3.1 2.0 1.5 1.2 0.5 0.0 1.0 1.9 -- 0.9 0.9 Naphtha’s Straight 5-160 6.0 0.0 5.2 4.8 5.4 4.5 1.8 3.2 4.5 5.1 -- 2.6 13.4 Light 160-250 11.6 0.3 8.5 7.1 7.8 8.1 2.3 5.3 4.0 6.0 -- 3.1 5.5 Medium 250-325 9.8 0.7 9.2 6.9 6.9 7.8 2.6 5.0 3.5 5.6 -- 2.9 3.0 Heavy 325-375 5.6 1.1 4.3 4.9 4.6 8.8 2.0 3.5 3.1 3.8 -- 2.0 1.5 Distillate Kerosene 375-500 13.7 7.5 11.0 11.3 11.5 17.1 6.7 10.0 9.7 12.0 -- 8.6 5.0 Diesel 500-620 12.2 11.

9 11.5 10.9 11.3 15.1 10.4 9.3 9.2 19.7 -- 15.0 8.0

VGO Light 620-800 15.5 21.9

15.5 14.3 15.1 18.2 18.1 13.2 13.9 29.7 -- 22.8 12.0

Heavy 800-1050 14.3 26.2

16.5 16.1 16.1 13.0 22.5 16.5 19.8 16.3 -- 19.4 16.9

VR Resid. 1050+ 9.2 30.5

14.8 20.8 19.1 5.7 32.8 34.0 31.1 0.0 -- 22.5 33.8

Source: TIAX

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Table F.2: US Refinery Utilization Rate 2010 and API’s

PADD I PADD II PADD III PADD IV

PADD V US Total

E. Coast

App. No. 1

IN, IL, KY

MN, WI, ND, SD

OK, KS, MO

TX Inland

TX GC LA GC North LA, AR

NM Rocky Mtn

West Coast

Utilization Rate (%)

78.7 85.8 87.9 94.3 88.1 87.3 90.0 88.5 78.9 73.5 87.0 80.6 86.4

Weighted API

33.45 33.88 33.64 27.82 35.52 36.24 28.82 29.74 31.46 37.43 33.42 27.69 30.71

Weighted Sulfur Content (%)

0.59 1.37 1.23 1.99 0.94 0.85 1.79 1.51 1.43 0.81 1.33 1.33 1.39

Source: EIA Petroleum Supply 2010 Report

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Figure F.2: US Refineries

Source: EIA Refining Capacity Report, CERI

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Figure F.3: Asia-Pacific Refineries

Source: Oil and Gas Journal, CERI