An Economic Assessment of the Opportunities & Risks of Government-Supported Heavy Oil Refining in Alberta

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2019-09 Sweet Dreams: An Economic Assessment of the Opportunities & Risks of Government-Supported Heavy Oil Refining in Alberta

Hardie, Shamus

Hardie, S. (2019). Sweet Dreams: An Economic Assessment of the Opportunities & Risks of Government-Supported Heavy Oil Refining in Alberta (Unpublished master's project). University of Calgary, Calgary, AB. http://hdl.handle.net/1880/111838 report

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MASTER OF PUBLIC POLICY CAPSTONE PROJECT

Sweet Dreams: An Economic Assessment of the Opportunities & Risks of Government-Supported Heavy Oil Refining in Alberta

Submitted by: Shamus Hardie

Approved by Supervisor: Jeffrey Church, September 2019

Submitted in fulfillment of the requirements of PPOL 623 and completion of the requirements for the Master of Public Policy degree

Capstone Approval Page

The undersigned, being the Capstone Project Supervisor, declares that

Student Name: Shamus Hardie

has successfully completed the Capstone Project within the

Capstone Course PPOL 623 A&B

Signature

Acknowledgements

A dear family friend who passed left a memorable quote that provided inspiration over this past year: “the best gift anyone could give a person is the gift of time.” I am sincerely grateful to all of those who shared their time with me throughout this endeavor.

I offer my sincerest gratitude for the guidance and discipline from Dr. Jeffrey Church for this project, whose earlier courses instilled my passion in economics and continuously challenged me to think several steps ahead. I am also appreciative for the professors at the School of Public Policy who were willing to discuss my research interests and provided opportunities to explore beyond the program; in particular, thank you to Professors Fellows, Flanagan, Rioux, Tombe, and Winter. Special thanks are also due to certain colleagues at the Alberta Energy Regulator and professional acquaintances within the industry willing to share ideas over coffee.

The importance of friends and family over this past year cannot be emphasized enough. Thank you, especially, to Ollie, Dale, and Liz who listened to my stories, helped me decompress, and reminded me which day of the week it was with Sunday dinners. Most importantly, I am forever indebted to my wife, Jennifer, who had an infinite patience for my countless late nights, endless stubbornness, and time spent away from home. Upon submission of this report, I look forward to returning to a more relaxed lifestyle, getting caught up on the outdoors and raising Amelia (and Kona).

Table of Contents Executive Summary ...... 9 Key Findings ...... 10 Recommendations ...... 12 1.0 Introduction ...... 13 1.1 Background ...... 14 1.2 Purpose ...... 18 1.3 Methodology ...... 19 1.4 Results ...... 22 1.4.1 Price Decomposition ...... 22 1.4.2 Policy Considerations ...... 23 1.4.3 Project Economics ...... 25 2.0 Price Decomposition ...... 30 2.1 Feedstock ...... 33 2.2 Transportation ...... 34 2.3 Refining ...... 34 2.4 Marketing ...... 37 2.5 Taxes ...... 38 2.5.1 Federal ...... 40 2.5.2 Provincial ...... 41 2.5.3 Carbon ...... 42 2.6 Other Factors ...... 42 3.0 Policy Considerations ...... 44 3.1 Temptation – Costs of Intervention ...... 45 3.1.1 Regulatory Failures ...... 45 3.1.2 Market Failures ...... 47 3.1.3 Price Regulation ...... 52

3.2 Translation – Communicating Value & Compliance ...... 54 3.2.1 Assessing Economic Viability...... 54 3.2.2 Federal Requirements ...... 56 3.2.3 Provincial Requirements ...... 58 3.3 Transformation – Anatomy of a Barrel ...... 62 3.3.1 Upstream Production ...... 64 3.3.2 Upgrading in Between ...... 65 3.3.3 Downstream Marketing ...... 74 3.4 Transportation – From Here to There ...... 81 3.4.1 Balancing Supply & Demand ...... 81 3.4.2 Pipelines ...... 84 3.4.3 Alternative Modes ...... 88 3.5 Termination – End Use & End Date ...... 91 3.5.1 Energy Transition ...... 91 3.5.2 Industrial Emitters ...... 93 3.5.3 Blending Requirements ...... 95 4.0 Project Economics ...... 99 4.1 Cost-Benefit Analysis ...... 101 4.1.1 Costs ...... 102 4.1.2 Benefits ...... 105 4.1.3 Scenarios ...... 107 4.1.4 Monte Carlo Simulation ...... 110 4.2 Economic Impact Assessment ...... 112 4.3 Limitations ...... 113 5.0 Conclusions ...... 115 5.1 Findings ...... 116 5.2 Recommendations ...... 118 5.3 Further Considerations ...... 120 6.0 Appendix A – Monte Carlo Simulation Results ...... 121 6.1 New Refinery ...... 122 6.2 Expansion ...... 123 6.3 Acquisition ...... 124 7.0 Bibliography ...... 125

Figure 1: Alberta Non-Renewable Resource Revenue, 1970-2018 ...... 14 Figure 2: Canadian Northern Corridor Concept ...... 16 Figure 3: Opportunity Cost of Raw Production & Refinery Options in Alberta ...... 30 Figure 4: Vancouver Gasoline Margins, 2009-2019 ...... 32 Figure 5: Edmonton Gasoline Margins, 2009-2019 ...... 32 Figure 6: Western Canadian Oil & Fuel Prices, 2009-2019 ...... 33 Figure 7: Western Canadian Refining Margins, 2009-2019 ...... 35 Figure 8: Vancouver-Edmonton Refining Margin Differentials, 2009-2019 ...... 36 Figure 9: Average Capacity per Refinery & Number of Refineries, 1947-2016 ...... 37 Figure 10: Taxation of Automotive Fuels (US₵ per liter), 2017 ...... 38 Figure 11: Alberta & BC Fuel Taxes, 2019 ...... 40 Figure 12: Seasonal RVP Requirement for BC Coastal & Western Canada ...... 43 Figure 13: Westcoast Mainline & Washington Refineries ...... 44 Figure 14: WTI & WCS Prices & Differentials (US$ per barrel), 2005-2019 ...... 51 Figure 15: Alberta Petrochemical Facility Regulatory Roadmap ...... 59 Figure 16: A Simplified Application Review Process for Oil Sands Projects ...... 61 Figure 17: USGC Gasoline & Distillate Crack Spreads (US$ per barrel) ...... 63 Figure 18: Alberta Total Primary Energy Production, 2008-2028 ...... 64 Figure 19: Sturgeon Refinery Process Flow Schematic ...... 68 Figure 20: Benefits & Risks of Sturgeon Toll Payment ...... 69 Figure 21: Input to Refineries by Crude Type – Alberta and British Columbia, 2017 ...... 75 Figure 22: PADD II Refining Capacity, 2018 ...... 78 Figure 23: PADD III Refining Capacity, 2018 ...... 78 Figure 24: Simplified Illustration of a Petroleum Refinery ...... 80 Figure 25: Alberta & BC Refining Capacity & Product Demand, 2017 ...... 82 Figure 26: Major Existing & Proposed Canadian & U.S. Crude Oil Pipelines ...... 84 Figure 27: Trans Mountain Tolls Edmonton-Westridge (Cdn$ per barrel), 2009-2019 ...... 86 Figure 28: Trans Mountain Pipeline System ...... 87 Figure 29: Trans Mountain Pipeline Throughput & Capacity (Thousand barrels per day at Burnaby, Sumas, & Westridge), 2009-2019 ...... 88 Figure 30: Canadian Crude Oil Exports by Rail, 2012-2019 ...... 89 Figure 31: Crude Oil Transportation Costs (Approximations), 2011 ...... 90 Figure 32: Energy Density Comparison of Transportation Fuels (Indexed to Gasoline = 1), Energy Content per Unit Weight ...... 92 Figure 33: IEA World Oil Demand under New Policies Scenario, 2000-2040 ...... 93 Figure 34: Current Canadian Carbon Pricing Policies, 2015-2025 ...... 95 Figure 35: Western Canadian Biofuel Industry Map...... 96 Figure 36: Changes to WTI & WCS Prices Due to the IMO Regulation (2017 US$) ...... 99 Figure 37: Opportunity Cost of Raw Production & Refinery Options in Alberta ...... 110 Figure 38: New Refinery NPV Monte Carlo Simulation Results ...... 122 Figure 39: New Refinery NPV Sensitivity Analysis ...... 122 Figure 40: Expansion NPV Monte Carlo Simulation Results ...... 123 Figure 41: Existing NPV Sensitivity Analysis ...... 123 Figure 42: Acquisition NPV Monte Carlo Simulation Results ...... 124 Figure 43: Acquisition NPV Sensitivity Analysis ...... 124

Abbreviation Definition AEP Alberta Environment & Parks AER Alberta Energy Regulator AFNEC Alberta First Nations Energy Centre APMC Alberta Petroleum Marketing Commission APPL Alberta Product Pipe Line bbl Barrel of Oil BC British Columbia BCOGC British Columbia Oil & Gas Commission BCUC British Columbia Utilities Commission BRIK Bitumen Royalty In Kind CAPP Canadian Association of Petroleum Producers CBA Cost-Benefit Analysis Cdn$ Canadian Dollars CEA Agency Canadian Environmental Assessment Agency CEAA Canadian Environmental Assessment Act CERI Canadian Energy Research Institute CFS Clean Fuel Standard CME Chicago Mercantile Exchange CNOOC China National Offshore Oil Corporation CNR Canadian National Railway CNRL Canadian Natural Resources Limited CTS Competitive Tolling System EconIA Economic Impact Assessment EIA Energy Information Administration FCA Federal Court of Appeals FCC Fluid Catalytic Cracking GDP Gross Domestic Product GST Goods & Services Tax IAA Impact Assessment Agency IEA International Energy Agency IMO International Maritime Organization IRR Internal Rate of Return LCFS Low Carbon Fuel Standards LNG Liquefied Natural Gas mmbbl/d Million Barrels of Oil per Day NEB National Energy Board NPV Net Present Value OECD Organization of Economic Cooperation and Development PADD Petroleum Administration Defense District

PST Provincial Sales Tax PUP Partial Upgrading Program RBOB Reformulated Blendstock for Oxygenate Blending RFR Renewable Fuel Regulations RFS Renewable Fuel Standards RPP Refined Petroleum Product SCO Synthetic Crude Oil tCO2e Tonne of carbon dioxide equivalent TIER Technology Innovation and Emission Reduction TMX Trans Mountain Expansion ULSD Ultra Low Sulphur Diesel US United States US$ United States Dollars USGC United States Gulf Coast WACC Weighted Average Cost of Capital WCS Western Canadian Select WTI West Texas Intermediate VCI Value Creation Incorporated

Executive Summary Alberta and its abundant bitumen resources have faced a barrage of regulatory and economic challenges in recent years. These problems have been compounded by limited takeaway capacity and a concentrated dependence on markets in the United States (US). The acute risks of these constraints became apparent through 2018, where restricted pipeline access and refinery outages in key markets led to a historic discount for Alberta’s oil and royalties collected by the province. As one of the policy responses to the widening price differentials and an extension of its “Made-in-Alberta” diversification strategy, the Government of Alberta issued a

Request for Expressions of Interest in December 2018 to determine if the private sector would have an appetite to refine more heavy oil in the province (Alberta, 2018a).

With inadequate takeaway capacity for Alberta’s bitumen and seemingly endless legal and regulatory hurdles for new transportation projects, heavy oil refineries have been marketed as a panacea to alleviate the province’s energy problems. However, given the province’s contentious history getting involved with refining ventures and questionable economics, this raises the question of whether Alberta should support expanded refining capacity within the province to maximize the value of its petroleum resources. To address the opportunities and risks of such proposals, this report is separated into three sections:

1. Price Decomposition – provides a technical background for the components and issues with fuel prices in Western Canada to isolate and understand refining margins; 2. Policy Considerations – details regulatory and policy implications across the energy supply chain with the potential to affect refinery proposals; and, 3. Project Economics – applies information collected from the previous sections to test the commercial viability and identify sensitivities of hypothetical refineries in Alberta.

Key Findings Constrained takeaway capacity and widened oil price differentials have motivated the Alberta government to explore refining options to add value to its raw resources. Refined products would also enable the optimization of existing transportation infrastructure, filling them with lower density products to make the most out of finite pipeline capacity. Given the challenges faced by Alberta’s bitumen resources, the benefits of refineries seem to be obvious; however, it is critical to recognize the significant costs to determine the net societal value of such projects, especially with government backing. Additional refining capacity in Alberta carries substantial risks and opportunity costs, often requiring government supports to make proposals viable, which have traditionally been in the form of long-term feedstock supplies and loan guarantees.

As a result, there is an inconsistency between the net economic value of additional refining capacity in Alberta and gross benefits touted by proponents and politicians. Although proponents typically use input-output models to demonstrate gross economic benefits of a project, the economic impact assessment approach neglects the net costs and commercial viability of proposals. This misalignment of valuations is particularly concerning for Albertans, where such propositions can lead to inefficient government supports that lack consideration for cost overruns and ignores the opportunity cost of its resources. While proponents prefer to demonstrate only the perceived benefits of a project, they are often reluctant to provide proprietary information and robust scenario planning to illustrate the net value on public record. In order for Albertans to maximize the value of their resources, transparency is essential to determine the true value of projects and contribution to the public interest.

Undoubtedly, the economic viability of a refinery proposal can be increased with many different types of supports from the government. However, intervention can have unexpected effects and needs case-by-case analysis to find the most effective applications. The hypothetical refineries assessed in this report were found to have varying areas that could have supports tailored to their unique needs. Interventions that influence feedstock costs matter most to all types of refineries, while cost inflation and the cost of capital can significantly affect new refineries; expansion and acquisition projects were found to also be highly sensitive to the cost of capital, processing costs, and exchange rates.

Governments eager to force expanded refining capacity and capture the ensuing economic benefits are susceptible to overlooking the costs and limitations of processing heavy oil into finished products in Alberta. Based on the economic modelling of hypothetical refinery proposals in this report, an inverse relationship was identified between the commercial viability and local economic benefits retained (e.g., jobs, gross domestic product, and taxes). The following are a summary of the results of the applied discounted cash flow modelling and supporting probabilistic Monte Carlo simulations for the hypothetical refineries:

 An expansion of an existing refinery in Alberta with the addition of heavy oil processing capacity was found to be the most efficient option, requiring the least government intervention, and found to deliver a net positive value about 65 per cent of the time;  While larger and costlier greenfield projects can deliver higher macroeconomic benefits based on greater expenditures, such projects had a very low probability (less than 5 per cent) of being economically viable based on the scenarios presented in this report;  An acquisition of an existing heavy oil refinery beyond Alberta was the most likely to generate net positive economic returns (about 95 per cent), but provided limited local economic benefits and did not relieve transportation limitations.

Recommendations 1. Consider whether Alberta refineries are the most efficient option to supply markets for finished petroleum products. Alberta should assess market fundamentals and opportunity costs of crude oil and refined products, transportation options and alternatives, and account for relevant policies that would affect the viability of refinery proposals. 2. Assess the potential effects of relieved transportation constraints in Western Canada on refineries’ economic viability. Alberta should consider the effects of looming long-term transportation solutions that can expand market access and generate value for the province’s petroleum resources, including both raw and refined products. 3. Apply a consistent evaluation of the opportunities and risks of refinery proposals to evaluate their net societal benefit. Alberta should develop a standardized cost-benefit framework for proposals to demonstrate net value, as compared to only gross macroeconomic effects commonly reported by proponents that increase alongside expenditures. 4. Maximize the return on supports and limit the risks of government intervention by focusing on incremental expansion projects. Alberta should tailor and cap project supports based on project merits and sensitivities; existing refineries with the addition of equipment capable of handling bitumen is the most reasonable option to increase heavy oil refining capacity within the province. 5. Ensure ongoing transparency and communication of the value of supported projects. Alberta should require proponents to submit ongoing detailed information for approved proposals, regularly report operating results of any projects supported by the government, and highlight challenges and successes to understand the return on investment.

1.0 Introduction

The role of policymaking and the value of government-supported refining ventures have been debated in Alberta, especially with regards to the recent start-up of the contentious North West

Redwater Sturgeon refinery (Livingston, 2018). Additional heavy oil refining capacity would enable more of the province’s bitumen resources to be processed and produce more value- added products, such as gasoline and diesel. The lower density products would also free up pipeline capacity and generate local economic benefits. However, new and expanded refineries carry multibillion-dollar price tags and can take decades before costs are recovered.

Refineries are also highly sensitive to feedstock discounts, inflation, and costs of capital that can affect the viability of proposals. These characteristics can make refineries a challenging investment for companies to advance suddenly. Although calls for a new refinery and other diversification propositions are not new to Alberta during times of an energy downturn, the business case is often lacking for the private sector to individually take on all the risk without some support from the government. This report explores options for expanding refining capacity in Alberta and models which types would warrant government support.

With Alberta, once again, interested in addressing the refining question, it is valuable to investigate what roles the government can take to strategically and efficiently expand refining capacity within the province. To limit the scope of research, this report focuses on heavy oil refining opportunities in Alberta to produce gasoline and diesel; other Western Canadian energy projects and refined products are briefly discussed in limited contexts to reference relevant information for modelling. While a number of refineries have already been proposed

13 within Western Canada, it remains unclear how much additional Alberta oil could be consumed domestically to clear the backlog of production and how economically viable such proposals would be without government supports. Although assumptions and changing market factors can sharply affect the economics of such projects, one thing is certain: intervention does not come without its costs and can create lasting unintended consequences.

1.1 Background Over the last decade, technological improvements have lowered production costs for oil and gas, making supplies more easily and readily accessible internationally (International

Association for Energy Economics, 2018). In turn, this has led to a sustained downturn in global energy prices and resulted in restrained capital investment, slowed economic growth, and job losses in the upstream sector. As Canada’s largest energy producing province, Alberta has experienced (another) shock to its economy, which is greatly dependent on the benefits and subject to the cycles that the energy sector provides (Figure 1).

Figure 1: Alberta Non-Renewable Resource Revenue, 1970-2018

12,000 10,000

8,000 6,000 4,000 Million Million Cdn$ 2,000 0 1970/71 1971/72 1972/73 1973/74 1974/75 1975/76 1976/77 1977/78 1978/79 1979/80 1980/81 1981/82 1982/83 1983/84 1984/85 1985/86 1986/87 1987/88 1988/89 1989/90 1990/91 1991/92 1992/93 1993/94 1994/95 1995/96 1996/97 1997/98 1998/99 1999/00 2000/01 2001/02 2002/03 2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18

Conventional Gas Conventional Oil Oil Sands

Data Source: (Alberta, 2018b)

As natural gas activity wound down from its peak in 2008, the oil sands became a leading economic driver in Alberta, delivering more than Cdn$25 billion in royalties from 2008 to the subsequent 2015 downturn. As such, Alberta’s energy ambitions have relied upon expanding bitumen production and finding ways to access markets beyond its provincial boundaries to sustain its hydrocarbon revenues. With scaled back royalties, the province now faces challenging policy decisions to diversify its revenue and rein in spending on various programs.

In an effort to benefit from low energy prices, Alberta has revisited the idea of capturing value from lower feedstock costs resulting from the market downturn. There have been several controversies associated with previous Alberta governments’ intervention in energy markets in the past, including those under Premiers Lougheed, Stelmach, and Notley. Examples of these governments’ interventions in the energy sector included threatening to restrict exports of hydrocarbon products to other parts of Canada, directly investing in select projects, and alleviating depressed prices by ordering production restrictions. These policy interventions created winners and losers, providing additional benefits for some and costs for others. Any action for current or future governments need to make efficient use of Alberta’s resources, especially if they are to be in the public interest, promoting growth, or generating economic benefits in the form of jobs, royalties, or taxes.

Current provincial and federal governments in Canada have advocated increasing energy market access and ensuring self-reliance, with plans that would involve virtually every province, from the West Coast to the Eastern Maritimes. Some of these proposals to cross Canada have questionable fates, especially once project economics and the magnitude of federalist

15 cooperation are considered – such as restarting TC Energy’s Energy East pipeline proposal or embarking on the Cdn$100 billion Canadian Northern Corridor concept (Figure 2). While many trans-Canadian energy projects have been touted for political ambitions rather than economic viability, it remains uncertain for the near future how Alberta will be able to increase its energy exports throughout North America and further abroad, considering current limitations.

Conversely, it remains unclear how the private sector, including pipeline and refining companies, can be encouraged to build infrastructure that can handle additional heavier

Western Canadian supplies given current market conditions and regulatory uncertainties.

Figure 2: Canadian Northern Corridor Concept

Source: (School of Public Policy, 2019)

16 Recently, the Governments of Alberta and BC have expressed concerns over refining capacity within each of their respective provinces, albeit for different reasons. In Alberta, oil and natural gas prices have been too low; in BC, gasoline and diesel prices have been argued to be too high

(Bennett, 2019). In response to these issues, both the Alberta and BC governments have looked to address their respective problems. As Alberta sought interest from the private sector to build or expand a heavy oil refinery within the province, the BC Utilities Commission (BCUC) completed its own inquiry into gasoline and diesel prices within the province at the end of

August 2019. As a result of these proceedings, there may be an opportunity for Alberta to fulfil policy objectives and subsequently support BC with additional streams of refined products. The federal government has also seemingly supported refining solutions in Western Canada, appearing to be willing to listen to private sector proposals and business cases for what the

Prime Minister calls a “complex situation [that] does not have a simplistic answer to it”

(Canadian Press, 2019). As such, it remains to be seen how governments will support such projects, especially without providing direct funding or taking on excessive. risk

Historically, Alberta has sent sizeable volumes of crude oil and refined products to its neighbors in BC and Eastern Canada; however, this all pales in comparison to how much oil is sent to the

US Gulf Coast (USGC) and Midwest. In 2018, nearly 3 million barrels per day (mmbbl/d) was sent to these regions from Western Canada (CAPP, 2019). Much of the oil migration to the US has been determined by available pipeline capacity and refining complexities, which have the scale and ability to handle the vast amounts of heavy oil produced in Alberta. BC, on the other hand, relies on imports of both light crude oil and finished products from Alberta and limited volumes from the US Pacific Northwest, namely Washington State (Parkland Fuel Corporation,

2019). With increased production in Alberta and an expansion of pipeline capacity reaching

Canada’s West Coast, it may be possible to relieve some of the price pressures for consumers in

BC and for oil producers in Alberta.

Without sufficient takeaway capacity, pipelines cannot offer the sole resolution to alleviate low crude oil prices and high fuel prices in Western Canada. Additional refining capacity in Alberta could offer supplemental relief to address these complex issues, but it is not likely to occur without coordinated government actions across the entire supply chain and tailored supports for unique proposals, otherwise perceived to be too costly or risky. In light of persistently constrained transportation for petroleum products, governments should be open to expanded refining capacity in Western Canada, but should also focus on regulatory shortfalls and market failures over costly policy interventions in Alberta’s downstream sector.

1.2 Purpose Considering the opportunity costs of marketing raw production versus expanding domestic refining, the question then is, should the Alberta government support expanded heavy oil refining capacity in the province? To answer this question, the ‘why’ and ‘how’ for whether proposals would warrant government intervention needs to first be addressed. This report provides an economic analysis of various options for expanded refining capacity able to process

Alberta’s abundant and challenging resources. The research assesses which options would be most feasible, identifies the factors that would be most sensitive to the projects’ economics, and discusses how policymakers can effectively shape the viability of proposals.

1.3 Methodology This report explores the policies and issues with government supporting additional refining capacity in Alberta. To determine whether a refinery would be viable, the overarching analysis considers factors for fuel prices and margins, market conditions, and policies that can shape a project’s economics. This report compares opportunities and challenges for refining projects in

Western Canada as reference case studies for expanded capacity, with an emphasis on Alberta.

The assessments consider proposals for new and existing refining capacity that could utilize more bitumen and discusses the governments’ roles across such projects’ supply chains.

Saskatchewan and Manitoba have been excluded from this analysis due to the current policy undertakings related to surplus bitumen supply in Alberta, a perceived shortage of refined products in neighboring BC, and relevant proposed projects to use as case studies.

Although Saskatchewan has two of its own refineries, the province is a net exporter of crude oil and refined products that supply central and eastern markets. Due to its limited oil production,

Manitoba does not have any refining capacity of its own and relies on imports from Alberta and

Saskatchewan (National Energy Board, 2019). According to the Canadian Energy Research

Institute (CERI), Eastern Canadian refineries have opportunities to increase their intake of

Canadian crudes, but were found to largely benefit by drawing on lighter, closer, and less expensive-to-process sources of crude oil (CERI, 2018). This would suggest Alberta will continue to have a stockpile of heavier oil, which will either continue to supply feedstock to refineries in the US or await new opportunities to be processed into higher-value refined products for BC and Asian markets.

This report is separated into three sections: Price Decomposition, Policy Considerations, and

Project Economics. The first section breaks down the components of fuel prices to understand perceived issues with downstream markets. As there are several components factored into final fuel prices, it is important to understand how these elements are determined and whether there is an economic opportunity to expand refining capacity in Western Canada, let alone

Alberta. Although refining margins do not necessarily represent profits, they may provide clues towards the value of producing refined products in Alberta versus exporting abroad to other markets. Regional markets of interest for this section focus on Vancouver and Edmonton to limit the scope of analysis. These markets were chosen due to their populations, proximity to refining hubs, and data availability. The Vancouver area represents more than half of the BC market and has a unique fuel tax structure; the greater Edmonton area is located near Alberta’s major refining hub, providing a benchmark floor for margins based on wholesale prices, feedstock and transportation costs. Regardless of which jurisdiction was explored, the approach used for the price decompositions can be applied to other regions or cities with sufficient data, including international markets beyond the scope of this research.

The second section of this report accounts for policies and regulations that can influence prices and the economic viability of refinery projects. These considerations are used to identify areas where governments can intervene efficiently to enable accelerated development and lower costs. An examination of the supply chain, from well to wheels, outlines operational and policymaking complexities of building refineries, which can be used to consider the economics of future projects and justify policy interventions. This report references publicly available information for existing and proposed projects, company and government strategies, and

20 production and price outlooks. Information collected for the second section is interpreted and factored into the subsequent modelling section to assess the value of refining projects and identify sensitivities to input factors.

The third section derives and discusses an economic model for hypothetical refineries suitable to handling Alberta’s bitumen as feedstock. Following a similar approach as proposed by

Fellows et al. (2017) for a public interest evaluation of partial upgrading technologies, this report attempts to determine the economic viability and macroeconomic impacts associated with additional heavy oil refining in Alberta. Although a profitable project would suggest that no government intervention is necessary, a negative net present value would means a private firm would be unlikely to advance a project on its own without support. The models in this report are used to understand how projects could best be supported by governments and identify tradeoffs by testing regulatory, physical, and other economic sensitivities.

To demonstrate commercial viability and economic efficiency, a discounted cash flow model was produced to evaluate three types of refinery projects: new, expansion, acquisition. A net present value was determined to understand what type of project could be viable on its own and to factor in the effects of market and policy considerations discussed in other sections of this report. Direct and indirect macroeconomic effects (gross domestic product, labor income, and jobs) were estimated based on the projects’ respective expenditures and using the Alberta

Treasury Board and Finance’s input-output model for the province. The proposed framework is intended to identify the net value of refinery proposals and highlight the tradeoffs of government supports with different options to process Alberta’s bitumen.

1.4 Results From the three sections in this report, each provided a unique perspective to address what role the government should take in supporting heavy oil refining capacity in Alberta. The first section focused on fundamentals of Western Canadian oil and fuel markets, followed by effects of policies and regulation on refinery economics in the second section. Information from these first two sections were incorporated into the third section, which modelled project economics of hypothetical refineries in Alberta consistent with real-world applications. The following are summarized results realized from each of the sections.

1.4.1 Price Decomposition The Price Decomposition provided a foundation for how refineries in Western Canada operate and generate a profit. The fundamental elements of fuel prices include taxes, retailer and refiner margins, and crude feedstock costs. In Western Canada, crude oil accounts for about 30 per cent of final fuel prices, such as diesel and gasoline. Interestingly, taxes also account for about the same portion as oil (including federal, provincial, municipal and carbon, where applicable). Refineries remain in business if the wholesale prices of the products produced exceed operating costs in addition to recovering significant capital costs. Although a number of short-term factors can affect crude oil feedstock and wholesale fuel prices, retailer margins and taxes are largely fixed components. With supplies already exceeding demand in Alberta, resulting in narrower refiner margins locally, any expanded capacity will need to find markets beyond the province. With sufficient transportation for refined products, this has the potential to lower BC’s high fuel prices and supply growing fuel demand elsewhere in the world.

1.4.2 Policy Considerations The Policy Considerations section offers an in depth analysis of how policies and regulations can affect refinery economics by considering the entire energy supply chain in Western Canada.

Additionally, perceived regulatory and market failures are discussed to understand why governments may be tempted to intervene and support refinery proposals in Alberta.

Regulatory failures highlighted in this report include governments' lack of understanding of markets, inconsistent rules creating uncertainty, and the private sector offloading risk to the government to lower costs. Market failures elsewhere in the energy sector were discussed that warranted intervention and economic regulation, including pipeline companies exercising market power over shippers with limited transportation options, hold-up problems in rail and pipelines that lead to underinvestment, as well as oil production curtailment to stem depreciated prices resulting from output exceeding available takeaway capacity.

Unlike the examples above, there are no apparent market failures related to refineries that would require government intervention in Alberta. Private firms have not advanced new refineries in the province due to being economically unviable, which should not be the sole merit of government supports for the sake of creating jobs. As explored further in the modelling section, expanding refining in Alberta does not maximize the value of resources and the opportunity cost of intervention must be recognized. With the costs outweighing benefits generated, supports for refinery proposals do not create net benefits for Albertans and instead lead to an inefficient use of resources and targeted subsidies.

Beyond government intervention, this section also introduces the federal and provincial regulatory requirements used to assess project proposals. In particular, economic impact

23 assessments and cost-benefit analyses are discussed for their flaws and merits. These modelling techniques are later used to assess the hypothetical refineries presented in this report.

Economic impact assessments were found to produce easy-to-understand gross macroeconomic benefits, including jobs, gross domestic product, and taxes. Flaws with this approach include lagged data, effects based on one snapshot in time, and linear benefits increasing with costs. On the other hand, cost-benefit analyses can provide net values of projects. Although cost-benefit analyses are sensitive to the input assumptions, this is a generally better tool to use to determine net value, especially if public supports are involved.

Beyond the regulatory processes, it was valuable to explain the oil supply chain within the context of Alberta’s resources. Alberta currently produces about 3.5 million barrels per day of oil, of which bitumen accounts for more than 85 per cent. Despite having abundant reserves, bitumen is costly to produce, process, and transport. Beyond Alberta, most demand for bitumen comes from costly and complex refineries capable of handling the heavier oil that are located in the US Midwest and Gulf Coast. Coupled with pipeline limitations, outages at these few, large-scale refineries can have tremendous negative impacts on prices in Alberta. Although additional refining in Alberta could reduce pipeline volumes by reducing the density of products shipped, refined products would still need to reach markets and would also need to compete based on transportation costs and satisfying local preferences. In addition to these considerations, potential refineries would benefit from assessing the market effects of environmental policies, such as industrial emissions, renewable fuel blending requirements, and even the International Maritime Organization’s (IMO) sulphur standards for shipping fuels.

1.4.3 Project Economics The Project Economics section takes the key elements of the previous sections and model the net present value (NPV) of different types of refineries that could emerge in Alberta.

Assumptions for the base case scenario are provided below (Table 1). Alternative scenarios (on the following page) adjust the base elements to examine the effects of capital cost inflation, effects of the International Maritime Organization’s (IMO) sulphur standards that could depress

Alberta’s oil prices and raise global diesel prices, recreate a large-scale refinery similar to those proposed in BC, and different costs of capital applying differing discount rates.

Table 1: Base Scenario Assumptions Category Assumed Rate

Capital Costs & Capacities New Refinery - Cdn$10 billion with 100,000 bbl/d Expansion – Cdn$2 billion with 50,000 bbl/d Acquisition – Cdn$1 billion with 50,000 bbl/d Utilization Rate 90% Operating Cost Cdn$10/barrel of oil Annual Maintenance Cost Cdn$25 million Major Turnaround Cdn$100 million (Every 4 Years) Feedstock Differentials US$15/barrel of oil (WTI-WCS) Exchange Rate 130% (US$ to Cdn$)

TIER Compliance Cost Cdn$20/tonne CO2e in excess of 100,000 tonnes/year

Refinery Emission Intensity 0.03 tonne CO2e/barrel of oil Alberta Corporate Income Tax Rate 8% (Post 2022) Federal Corporate Income Tax Rate 15% Project Life 30 Years

Relying on actual proposals of projects predominately in Western Canada, three models were derived for the different types of refineries capable of handling bitumen. The cost-benefit analyses provide deterministic cash flow models that estimated NPVs based on various scenarios for costs and revenues, including capital and operating costs, maintenance, oil price discounts, diesel and gasoline prices, emission costs, and taxes. Building on the cost-benefit modelling, Monte Carlo simulations offer a probabilistic approach to test distribution of inputs on NPVs, accounting for risk and uncertainty to model chances of success (NPV>Cdn$0). Finally, an economic impact assessment was used to demonstrate how capital and operating costs applied to the Alberta Treasury Board’s input-output model produce gross macroeconomic benefits, regardless of the net effects or viability of proposals. Results for the different modelling exercises are shown in Table 2.

Table 2: Summarized Economic Modelling for Hypothetical Refineries in Alberta

Expansion Acquisition Methodology Scenario/Metric New Refinery Refinery Refinery

Base -$2.12 $1.75 $2.75

Capital Cost Inflation

Low +50% -$7.12 $0.75 $2.25

High +100% -$12.12 -$0.25 $1.75 Deterministic NPV IMO Standards $5.09 $5.35 $6.35 (Cdn$ billion) Refining Titan $5.80 N/A N/A

Discount Rate

Low 3% $2.90 $4.10 $5.10 High 10% -$3.30 -$1.19 $2.19

Maximum $16.47 $1.69 $13.50

Mean -$7.63 $0.72 $2.31 Probabilistic NPV (Cdn$ billion) Minimum -$21.19 -$6.89 -$3.80

Probability of Non-Negative 4.1% 64.4% 94.7% NPV

Gross Domestic Product $14.63 $5.82 N/A (Cdn$ billion 2013)

Economic Impact Labor Income Assessment (Cdn$ billion $5.34 $1.46 N/A 2013)

Jobs (Fulltime 6,100 1,680 N/A Equivalent)

Under the base scenario, which reflects a project’s ability to achieve its planned cost, new refineries were found to be the most uneconomic in Alberta, with a negative NPV of Cdn$2.12 billion. Expansion and acquisition projects were found to deliver positive NPVs of Cdn$1.75 billion and Cdn$2.75 billion, respectively. Coupled with the Monte Carlo simulation, which simultaneously tested a range of scenarios for inputs, found that new refineries also had the lowest probability of delivering a positive NPV, with less than a 5 per cent chance of being successful. While acquisitions of heavy oil refineries were found to be the most likely to continue to be profitable, expansions found success just over 60 per cent of the time, which could warrant supports to make projects viable. The alternative scenarios, including adjustments to the cost of capital, demonstrate how supports could improve such economics.

The economic impact assessment was used to estimate gross economic impacts that could be purported for such projects based on size and expenditures. As explained further within the report, these types of assessments are flawed due to macroeconomic benefits linearly increasing alongside costs. This modelling ignores how viable a project would be, suggesting that regardless of if a refinery can stay in business it would continue to create jobs and other economic benefits. In the results tabled above, gross domestic product, labor income, and jobs were found to be higher for the more expensive project, despite the new refineries actually delivering a negative NPV. Results from acquisition projects were withheld from this part of the analysis due to the assumption that an acquired refinery would need to be beyond Alberta and would therefore generate most of the benefits for that locale.

Alternative scenarios tested various facets where markets and governments could affect project economics. Increasing capital costs by 50 and 100 per cent for all scenarios demonstrated an adverse effect on project viability. Doubling the capital cost showed that new refineries would lose an additional Cdn$10 billion and expansions would decrease in value by

Cdn$2 billion; acquired refineries were found to still be economically viable due to the initial capital cost being sunk prior to the purchase. Regional planning with staggered development would be the most likely option for governments to be able to influence such inflationary pressures.

Under the IMO sulphur standards scenario, which assume lower oil prices for Alberta’s heavy, high-sulphur oil and increased fuel prices, price differentials widen dramatically and strengthen the value proposition for refineries; Alberta is unlikely able to directly intervene or influence

28 the market responses of these standards. This scenario was largely used to demonstrate how drastic widening of differentials could make uneconomic projects look attractive if market conditions persist long-term, which is the common trap for governments, including the response by the Alberta government in December 2018.

Building on base assumptions, an even larger and costlier new refinery (300,000 barrels per day at a cost of Cdn$21 billion), similar to ones proposed in BC, show potential to deliver a net benefit based on economies of scale. However, Alberta would likely need to collaborate with the federal government on a number of issues to ever come close to replicating the capital costs suggested by proponents in BC. Refinery proposals in BC intend to source lower cost construction materials produced overseas, which would also have lower delivery costs being on the coast. In order to match these competitive cost advantages, Alberta would need to gain waivers and subsidize the transportation to bring these materials inland, which may not make sense logistically or economically. Further, the significant increase in output of finished goods from this one refinery would need sufficient market access options or would be stranded within

Alberta, depressing prices for fuel prices.

Lastly, adjustments to the discount rate demonstrated that projects unviable at higher costs of capital could be made economic at lower rates. Even new refineries became viable, delivering a positive NPV of almost Cdn$3 billion when the cost of capital is 3 per cent. The higher discount rate can also reflect the private cost of capital, which would be higher than what a government with a high credit rating could receive. Lower cost financing could be achieved with loan guarantees and long-term feedstock supply contracts that ensure the operation of a refinery.

Considering the opportunity costs of marketing raw production versus expanding refining capacity in Alberta, new refineries were found to generate a net loss of Cdn$2.12 billion dollars over 30 years under the base assumptions modelled; an expansion project would create a net benefit of Cdn$1.75 billion (Figure 3). These values respectively translate to a net cost of about

Cdn$2.15 per barrel for new refineries and a net benefit of Cdn$3.50 per barrel for expansions within Alberta; acquisitions were found to generate positive returns and economic benefits beyond Alberta, suggesting the province would not support such opportunities.

Figure 3: Opportunity Cost of Raw Production & Refinery Options in Alberta

2.0 Price Decomposition

Before policies and projects can be addressed, it is important to first understand how prices at the pumps are determined. This section outlines the fundamental components of what goes into the price of liter of gasoline and diesel. The primary Western Canadian markets of interest for this study are near existing major refining markets in both Alberta and BC, which are

Edmonton and Vancouver, respectively for each province. This section is used to understand the current determinants of fuel prices and identify the differences in margins realized by refineries and retailers (Table 3).

Table 3: Fuel Price Components & Margins

Price Difference Between Difference Components Price Components Definition Retail Price with Taxes Retail Price with Taxes less Retail Price Without Taxes Taxes Retail Price without Taxes Retail Price without Taxes less Wholesale Price Retail Margin Wholesale Price Wholesale Price less Crude Oil Price (and other costs) Refining Margin Crude Oil Price

The status quo for prices is used as a benchmark for the later sections of this report, which considers the effects of policy measures compared to this baseline scenario. As shown in Figure

4 and Figure 5, the following charts aggregate the margins for total fuel prices in terms of cents per liter for gasoline and diesel, which include:

 Taxes – the difference between final prices paid at the pump and retail prices without taxes;  Retailer Margins – the difference between retail prices without taxes and wholesale prices charged by refiners, with the latter also referred to as the ‘rack’ price;  Refinery Margins – the difference between the rack price of fuel sold by refineries and the cost of crude oil as an input (the following charts assume transportation and other operating costs are captured in the refinery margins); and,  Crude Oil – the fundamental feedstock cost, which is converted at a ratio of about 159 liters per barrel of oil.

Figure 4: Vancouver Gasoline Margins, 2009-2019

180 160

140 120 100 80 60 40 Cents perLiter (Cdn₵/l) 20 0 Jul 2011 Jul 2016 Jan 2009 Jan 2014 Jan 2019 Jun 2009 Jun 2014 Jun 2019 Oct 2012 Oct 2017 Oct Apr 2010 Apr 2015 Sep 2010 Sep 2011 Feb 2015 Sep 2016 Feb Dec 2011 Dec 2016 Dec Aug 2013 Aug 2018 Aug Nov 2009 Nov 2014 Nov Mar 2013 Mar 2018 Mar May 2012 May 2017

Taxes Retailer Margin Refining Margin Crude Price

Data Source: (Kent Group, 2019)

Figure 5: Edmonton Gasoline Margins, 2009-2019

140

120

100

Cents perLiter (Cdn₵/l) 20

0 Jul 2011 Jul 2016 Jan 2009 Jan 2014 Jan 2019 Jun 2009 Jun 2014 Jun 2019 Oct 2012 Oct 2017 Oct Apr 2010 Apr 2015 Sep 2010 Sep 2011 Feb 2015 Sep 2016 Feb Dec 2011 Dec 2016 Dec Aug 2013 Aug 2018 Aug Nov 2009 Nov 2014 Nov Mar 2013 Mar 2018 Mar May 2012 May 2017

Taxes Retailer Margin Refining Margin Crude Price

Data Source: (Kent Group, 2019)

2.1 Feedstock One of the largest components of gasoline and diesel prices is the crude oil used as feedstock.

Depending on which market is examined, crude oil can account for about 30 to 40 per cent of the final price of fuel (Figure 6). Although global oil prices hit historic lows in 2015, fuel prices did not necessarily reflect the same relative changes. Price changes in crude oil can have a lagged effect on retail fuel prices, which can be due to a number of factors, including refiners adjusting to stockpiles of higher cost crude oil. However, over the long-term prices typically do move in tandem and respond to fluctuations in crude oil inputs.

Figure 6: Western Canadian Oil & Fuel Prices, 2009-2019

180 160

140 ₵/l) 120 100 80 60 40 Cents (Cdn perLiter 20 0 Jan 2009 Jan 2010 2011 Jan Jan 2012 Jan 2013 Jan 2014 Jan 2015 Jan 2016 Jan 2017 Jan 2018 Jan 2019 Sep 2009 Sep 2010 Sep 2011 Sep 2012 Sep 2013 Sep 2014 Sep 2015 Sep 2016 Sep 2017 Sep 2018 Sep May 2009 May 2010 May 2011 May 2012 May 2013 May 2014 May 2015 2016 May May 2017 May 2018 May 2019

Vancouver Gasoline Retail Price Edmonton Gasoline Retail Price Vancouver Diesel Retail Price Edmonton Diesel Retail Price Crude Price

Data Source: (Kent Group, 2019)

2.2 Transportation Transportation costs can take the shape of many different modes, including pipelines, railcars, trucks, as well as ships and barges. Each of these unique costs are shaped by their own market factors and availability. Pipelines provide the lowest transportation costs on land and over longer distances. Pipeline tolls are a function of the system’s cost of service, density of product moved, and other requirements, such as diluents used as a blending agent to reduce the viscosity and drag of heavier oils. Distances traveled are also reflected in the price of feedstocks paid by refineries, regardless of which mode is chosen. Longer distances and volumes can make certain options uneconomic, especially trucking. In addition to feedstock costs, the wholesale rack price at refineries includes transportation costs for crude oil before delivery of finished product to retailers.

2.3 Refining Refiners are expected to recover substantial, often multi-billion dollar capital costs and recurring operating costs to generate a profit over the useful life of the refinery. Refinery margins have been used by some as a relative proxy for profits, but this is an imperfect approach without knowing refineries’ costs (Wolinetz, 2018). The appropriate function for profits not only captures margins and quantity, but also accounts for other fixed costs (Equation

1). Refining margins for both gasoline and diesel have been on the rise in Western Canada, more than doubling over the past decade in part to rising costs (Figure 7). Unfortunately, the exact profit margins and sources of cost inflation are difficult to determine as the information is considered confidential and commercially sensitive by companies; Shell, Suncor, and Husky provided such responses to the BCUC’s current Inquiry into Gasoline and Diesel Prices in BC

(British Columbia Utilities Commission, 2019). A number of fixed and variable costs factor into

34 margin calculations, including the facility’s natural gas and electricity utilities, financing and debt obligations, labor and maintenance, chemicals and catalysts, and insurance for catastrophic events. As refiners focus on minimizing their operating costs, often by realizing economies of scale, it starts to make sense why the number of refineries in Canada has decreased over the past several decades. With supply shortages and regional preferences for particular fuels, this helps explain the regional differences in margins (Figure 8).

Equation 1: Profit Function

�

� = ∑(�� − ��)�� − � �=1

�: Profit �: Price of Product � �: Marginal Cost of Product � �: Quantity of Product � �: Fixed Cost

Figure 7: Western Canadian Refining Margins, 2009-2019

160

140 120 100 80 60 40 20 Cents perLiter (Cdn₵/l) 0 Jan 2009 Jan 2010 Jan 2011 Jan 2012 Jan 2013 Jan 2014 Jan 2015 Jan 2016 Jan 2017 Jan 2018 Jan 2019 Sep 2009 Sep 2010 Sep 2011 Sep 2012 Sep 2013 Sep 2014 Sep 2015 Sep 2016 Sep 2017 Sep 2018 Sep May 2009 May May 2010 May 2011 May 2012 2013 May May 2014 May 2015 May 2016 May 2017 May 2018 May 2019

Vancouver Diesel Retail Price Retail Price Excluding Taxes Wholesale Price Crude Price

Data Source: (Kent Group, 2019)

Figure 8: Vancouver-Edmonton Refining Margin Differentials, 2009-2019

Data Source: (Kent Group, 2019)

Interestingly, there are fewer refineries in Canada today than there were 60 years ago as operators consolidated assets and found efficiencies to remain competitive in an ever-changing market. In fact, there were a peak of 45 refineries in Canada in 1958, decreasing to under 30 during the 1980s, and reaching 18 in 2018 (Figure 9). Most recently, three refineries shut down in Central and Eastern Canada with the closures of Petro-Canada’s Oakville in 2005, Shell’s

Montreal in 2010, and Imperial Oil’s Dartmouth in 2013. Age and complexity were leading factors in the closures, in addition to changing environmental regulations, slowed regional demand, and rising crude oil costs (National Energy Board, 2018). As explored in the second part of this report, the Sturgeon refinery is the first to be built in over 30 years, which had different market conditions and government supports to bolster its start, including a long-term supply of feedstock through Alberta’s royalty program that enabled lower costs of capital.

Figure 9: Average Capacity per Refinery & Number of Refineries, 1947-2016

Source: (National Energy Board, 2018)

2.4 Marketing Branded and unbranded fuels can have different prices, as well as independent retailers that can set prices independently compared to chains. Marketing costs captures advertising and blending expenses, as well as contracts to ensure fuel supplies are delivered. Advertising, especially for retail chains, provides brand recognition and can attract a number of customers for specialty products, like higher-octane fuels. Retailers can provide niche fuel products that include certain blending specifications for environmental standards and performance, such as ethanol and detergents. The final fuel price paid by consumers also covers a narrow margin for retailers’ costs, including their own operating costs and credit card transaction fees – convenience store and carwash elements complement fuel revenue streams. Further, retailers need to factor in costs that vary across provinces with different income taxes and even different parts of a city due to real estate costs and property taxes. Despite the number of gas stations increasing across Canada, retailers in Vancouver have started to realize the opportunity costs of running a gas station versus the value of the land it sits on. As a result, more retailers have sold their properties to real estate developers in the Vancouver area (Healing, 2017).

2.5 Taxes Another significant differentiator in prices across Canada are the taxes built into the price of fuel. Fascinatingly, the BCUC was prohibited from examining taxes in its inquiry, even though BC has several additional layers of taxes that result in a greater burden on fuel prices relative to other jurisdictions in Canada. Despite the perceived high taxes charged on fuel, especially in BC,

Canada, overall, is among the lowest of Organization of Economic Cooperation and

Development (OECD) countries for fuel tax burdens (Figure 10).

Figure 10: Taxation of Automotive Fuels (US₵ per liter), 2017

100

90 80 ₵/l) 70 60 50 40 30 20 Cents (US perLiter 10 0 Italy Chile Israel Spain Japan Korea Latvia France Turkey Poland Ireland Austria Greece Iceland Mexico Finland Estonia Canada Norway Sweden Belgium Slovenia Hungary Portugal Australia Denmark Germany Lithuania Switzerland Netherlands Luxembourg New Zealand New United States Czech Republic Czech Slovak Republic Slovak United Kingdom United

Diesel Gasoline

Data Source: (OECD, 2017)

Although taxes represent a substantial portion of fuel prices paid by consumers, it is improbable that a government would unwind taxes to make fuel prices lower for consumers.

Although sustained high fuel prices over longer terms may make other transportation options look more attractive, such as public transit or electric vehicles, consumer fuels are fairly

38 inelastic goods in the short-run (Energy Information Administration, 2014). Inelasticity implies that an increase of one per cent in prices translates to a less than one per cent decrease in quantities demanded (Equation 2) – where the ratio is less than one. Eliminating a tax on an inelastic good like fuel means that the respective government will need to find alternative sources of funding for specific programs, like maintaining infrastructure or subsidizing transit. If taxes were increased on other, less inelastic goods, there would be a greater distortionary effect to make up the revenue shortfall.

Equation 2: Price Elasticity of Demand %∆ �� = %∆ ��

Once all taxes are aggregated, they have about as much of an impact on fuel prices at the pumps as crude oil – typically representing about 30 per cent of the price. Taxes on gasoline and diesel in Vancouver are more than double than those in Edmonton, with a further breakdown of federal, provincial, and carbon taxes summarized below (Figure 11). Provinces in

Canada have higher taxes than states in the US, but these revenues are typically reinvested into building and maintaining infrastructure, especially considering the effects of gravel and salt applied to roads during winter. The Canadian Taxpayers Federation estimates that Canada generated about Cdn$24.1 billion in total gasoline and diesel tax revenues in 2018; Alberta accounted for about Cdn$3.3 billion and Vancouver represented Cdn$1.7 billion out of BC’s total Cdn$2.8 billion (Canadian Taxpayers Federation, 2018).

Figure 11: Alberta & BC Fuel Taxes, 2019

20 Cents perLiter (Cdn₵/l) 10

0 Alberta Alberta Vancouver Vancouver Victoria Victoria Rest of BC Rest of BC Gasoline Diesel Gasoline Diesel Gasoline Diesel Gasoline Diesel

GST (Ex-Fuel Price) Federal Excise Alberta Excise BC PST (Ex-Fuel Price) BC Dedicated Motor Fuel Tax BC Provincial Motor Fuel Tax TransLink Fuel Tax BC Transit Fuel Tax Carbon Tax

Data Sources: (Governments of Alberta, BC, and Canada)

2.5.1 Federal All provinces in Canada are subject to a flat 10 cents per liter excise tax on gasoline and 4 cents per liter on diesel. A goods and services tax (GST) of 5 per cent is collected on top of all other taxes, which adjusts the cents per liter tax calculation depending on the current price of fuel.

The Canadian Taxpayers Federation estimates the GST on gasoline and diesel generates over

Cdn$5 billion annually in Canada, including more than Cdn$550 million from BC and about

Cdn$800 million from Alberta (Canadian Taxpayers Federation, 2018). Removing this tax on fuel would mean that the federal government would need to replace these revenues with other sources. Taxing higher elasticity sources of revenues to make up the shortfall would result in greater tax inefficiencies, where higher taxes on other goods would reduce the net social welfare.

2.5.2 Provincial In Alberta, there is a 13 cents per liter excise tax for both gasoline and diesel (Alberta, 2019a).

This tax is flat across the province and is the same rate for ethanol and biofuels; jet fuel, propane and liquefied petroleum gas, and locomotive fuel are charged at different rates. BC has a more complicated system with different rates for different zones, treating Vancouver and the

South Coast BC Transportation Region with a higher tax rate. Throughout the entire province, there is a 6.75 cents per liter Dedicated Motor Fuel Tax for both gasoline and diesel that goes towards the BC Transport Financing Authority.

While Alberta does not have any municipal or regional taxes on fuels, BC has several in addition to its provincial sales tax (PST) of 7 per cent. BC also has the Provincial Motor Fuel Tax that goes towards general revenues, which is an additional 1.75 cents per liter of gasoline for those in the

Vancouver area and 7.75 cents per liter for all other regions in the province. Diesel charges an additional half cent per liter on top of this tax for both Vancouver and elsewhere in the province (British Columbia, 2019a). Vancouver is one of three cities in Canada that has an additional municipal fuel tax, along with Victoria and Montreal. The TransLink fuel tax adds 18.5 cents per liter tax on gasoline and diesel sold in the Vancouver area, which rose from 17 cents per liter in July 2019; Victoria has a similar tax, but charges 5.5 cents per liter (British Columbia,

2019a).

2.5.3 Carbon The current Alberta government formally unwound the consumer carbon pricing scheme in

June 2019. This translated to savings of 6.73 cents per liter on gasoline and 8.03 cents per liter for diesel, which was effectively realized at the pumps overnight when retailers were no longer required to collect the levy. However, it remains to be seen if the federal backstop will take over and impose its own pricing scheme in 2020. At its current carbon price, BC continues to charge 8.89 cents per liter on gasoline and 10.23 cents per liter for diesel at the pump (British

Columbia, 2019).

2.6 Other Factors Several other and unpredictable factors can shock the price of fuels. Isolated markets with specific preferences and standards can set consumers up for higher prices and volatility without adequate supply. With inelastic demands and limited substitution opportunities, drivers are more exposed to short-term shortages and corresponding price increases. Everything from temperature, natural gas and electricity utilities for refineries, and exchange rates affect prices to some extent. In consideration of climates, Reid Vapor Pressures (RVP) matter for ignition and efficiency purposes, but also affect the price with products blended in. Seasonal maintenance for refineries usually involves reconfiguring operations and blending different agents into the fuel to manage evaporation, such as lower-cost butanes blended in colder winter months. More temperate climates, such as those in BC, have higher efficiency and costlier fuels suited for warmer weather versus the frigid temperatures experienced in Alberta during winter months

(Figure 12).

Figure 12: Seasonal RVP Requirement for BC Coastal & Western Canada

Source: (Deetken Group, 2019)

In October 2018, Enbridge’s Westcoast Mainline ruptured and cut natural gas supplies to homes, commercial businesses, and refineries in BC and Washington (Figure 13). As a result, several refineries in the area shut down without fuel gas for operations, raising refined product margins and prices in the region (Marino & Adams-Heard, 2018). More commonly, refineries temporarily shut down to do maintenance and reconfigure operations over several weeks during turnarounds. Depending on volumes in storage, this can also create shortages and price spikes in the wholesale market. It is often during these times that the public and governments believe refiners are colluding and fixing prices, despite the market paradoxically reflecting volatility with the temporary decrease in supply. With local shortages, imported sources from abroad are subject to exchange rates, which typically put Canadian importers at a disadvantage by paying a premium for spot contracts based in US dollars. There are endless possibilities for acute price shocks, but many of those are beyond the scope of this research due to their short- term nature.

Figure 13: Westcoast Mainline & Washington Refineries

Source: (Marino & Adams-Heard, 2018) 3.0 Policy Considerations

Governments can have significant influences on refineries, whether with regulations for environmental standards or policies for economic growth. Building on the factors of the preceding Price Decomposition section, the Policy Considerations section discusses key elements related to developing a refining project and understanding what role governments can have across the supply chain. Relevant policies are evaluated to understand potential socioeconomic impacts and indirect consequences, including international sulphur requirements for shipping transportation that are expected to impact feedstock costs and fuel prices.

Policymaking can have effects on all stages of a refinery’s supply chain, affecting quality of feedstocks, availability of transportation, and long-term demands for refined products. Each subsection provides a discussion of the key components considered in the evaluation of

Western Canadian refining projects. The subsections address fundamental considerations in intervention, regulation, supply, transportation, and demand. Insights and considerations from this section are subsequently used to shape the economic modelling and analysis in the Project

Economics section.

3.1 Temptation – Costs of Intervention Although there are a seemingly endless number of ways governments have negatively affected energy projects in Canada, there are several ways they can positively influence how such businesses operate. While it is not always certain or transparent as to how the public gets a positive return on investment; government interventions can either increase revenues or lower costs for the private sector, especially when a project is compared to its industry peers. This support can come in the form of financial instruments and subsidies, with the most common options discussed below. As the old adage goes, though, “there ain't no such thing as a free lunch,” especially when public dollars are on the line.

3.1.1 Regulatory Failures Regulatory failures have played a significant role for energy and infrastructure projects in recent times. In particular, there are issues with “states of knowledge”, where a government does not fully understand the market or the participants it regulates (Black, n.d.). Without a government that fully comprehends how refining and markets work, provinces attempting to solve a problem may start by looking at an incorrect root cause. With a lack of data provided by refiners, authorities in BC have no way of fully understanding the cause of higher refining margins in the province, which appears to be the crux of its inquiry to consider solutions to alleviate high fuel prices.

As explored in later sections, there is a current lack of rules in BC that may deter new projects, which gives Alberta a regulatory-certainty advantage to expand refining capacity. Although the two existing BC refineries have grandfathered rules for their operations, new operations are at a disadvantage without established regulations for refineries. Regulations that have yet to be developed by the BC oil and gas regulator means that companies may be hesitant to risk billions of dollars to develop a new refinery in the province. With limited supply available from the current refineries and lack of regulatory certainty, BC will remain more exposed to outages than other jurisdictions in Canada, including Alberta.

To motivate the creation of downstream activity in Alberta, former provincial governments supported projects with royalty incentive programs for petrochemicals, assuming risk with loan guarantees, and providing long-term supply contracts to enable lower interest rates. With government-backed projects, proponents are able to get attractive financing options for projects that lower the cost of capital, but leave the province liable for debt obligations, cost overruns, and bankruptcies. Although due diligence and sharing proprietary information is required to understand the project’s viability, having a cap on total financing is a difficult task to limit the public’s exposure to risk, especially if the government abides by a sunk cost fallacy.

As experienced with the Sturgeon refinery, the government can be obligated for many decades to supply feedstock and pay processing fees. In this case, capital and financing cost escalations translated into higher processing costs, which the government is also responsible for with its feedstock commitment for 75 per cent of the refinery’s nameplate capacity. While the project had significant cost overruns and a blurred path to viability in the public eye, the refinery was

46 still expected to deliver a net positive economic value to the province. In 2017, the Alberta government provided an updated assessment of the project, which was estimated to deliver a net profit just under $200 million over the life of the project; however, this estimate is down from the range of $200 million to $700 million previously expected in 2011 (Varcoe, 2019).

Unlike BC, there is a lack of information and transparency with agencies responsible for overseeing and supporting refinery proposals in Alberta. With previous publicly supported projects, it is largely unclear how projects deliver economic returns, especially under ever- changing market conditions relative to initial assumptions. The Alberta Petroleum Marketing

Commission’s (APMC) partnership with the Sturgeon refinery has been controversial due to how little information has been publicly released regarding economic benefits and whether the resources provided have delivered the best value for Albertans. One of the findings from the

Alberta Auditor General’s review of the Sturgeon refinery found that the APMC requires the

“right people, with the right skills” to facilitate the “complex and impactful” arrangement

(Auditor General of Alberta, 2018). With the right knowledge and skillset, the government should be able to demonstrate how it is managing risks and making the most out of Alberta’s resources; however, there continues to be a failure to communicate with a lack of details available at the time of writing this report.

3.1.2 Market Failures Before a government intervenes, it is important to consider the various types of market failures that exist for oil producers and refiners in Western Canada. Market failures can take the form of uncaptured surplus resulting from information asymmetries, imperfect markets, inadequately priced risks, and externalities. Market failures affect how much oil is produced, how much is

47 dispatched on transportation infrastructure, and how new downstream infrastructure is financed. Public interest justifications can be made for regulatory interventions that would remedy market failures that exist when there is an inefficient allocation of resources. However, ensuing price distortions can send the wrong signal to market participants, which can lead to inefficient outcomes.

Characteristics of optimal market outcomes include allocative, rationing, and cost efficiencies

(Church & Ware, 2000). Allocative efficiencies are described as an efficient level of output, where social marginal benefits equal social marginal costs. Inefficiencies in this form are usually due to market power or externalities, whose effects are not appropriately captured or priced. In the case of increased refining margins, some have argued that refineries have been able to profitably raise prices above competitive levels based solely on this factor, despite being unable to substantiate these claims with any cost information that would determine profit (Lee, 2019).

Rationing efficiencies have become a prominent subject for transportation systems, which matter for pipeline service to remove refined products from Alberta. Under efficient rationing, those willing to pay the most will acquire the capacity to move their product. A concept related to this is Enbridge’s 2.85 mmbbl/d Mainline system is planning to switch from its current

Competitive Tolling Settlement (CTS) agreement once it expires at the end of June 2021

(Enbridge, 2019a). With the next CTS, Enbridge is seeking to make long-term contracts, which last up to 20 years, more attractive and offer priority access – likely to ensure commitment before other systems become available into the 2020s, such as Canada’s Trans Mountain

Expansion and TC Energy’s Keystone XL pipelines.

The updated, longer-lasting agreements will take up 90 per cent of the Mainline’s capacity, leaving 10 per cent for the uncommitted portion. Although there was concern this would disproportionately affect smaller shippers against larger oil producers and US refineries,

Enbridge lowered its minimum volume commitment volumes from 6,000 bbl/d to 2,200 bbl/d

(Williams & Nickel, Enbridge eases oil volume terms for Mainline pipeline in response to small producers' fears, 2019). This long-term contracting system could limit the capacity available for refined products to be moved by pipeline, especially for refineries planned to start in the mid-

2020s.

Cost efficiencies involve output produced at a minimum opportunity cost, especially with extensive economies of scale. There is usually a tradeoff between more market power and lower average costs with a fewer number of firms. If average costs with multiple firms exceed prices over the long run, firms will not profit and will go out of business. Before firms exit the market, they may forgo interim expenditures that can result in risks to quality and safety – such as operating and maintenance costs for refineries. While there are several competing refineries operating in Alberta, it is worth pointing out the advantages with a natural monopoly, such as avoiding duplicative fixed costs, regulatory processes, and infrastructure proliferation on the environment. Although the NEB has jurisdiction over regulating tolls and interprovincial pipelines in Canada, there are no such bodies to carry out economic regulation functions for refineries in Alberta or BC – these provinces do have regulatory requirements, but are subject to energy and environment agencies that have mandates other than rate setting.

Considering the preceding characteristics across the modern energy system, Alberta’s abundant oil reserves face two main challenges: sufficient processing and getting to market. The

Government of Alberta has taken steps with its Partial Upgrading Program to incentivize new technology to convert heavy oil into a lighter, medium grade that requires less diluent to move and can access more refineries. Similar to the early development of the oil sands with funding available for both academic research and development, these types of programs have been justified by investing public money to develop technology that will deliver greater benefits in the future. Partial upgrading technologies and refineries have the potential to create positive externalities for oil producers, where they do not necessarily own the processing capacity but will be beneficiaries of lower transport costs and greater market access.

Partially upgraded oil, which goes from an ultra-heavy density to a heavy to medium grade, allows volumes to access additional refineries that have less complex operations. The benefits of lighter oil produced by these emerging processes have yet to be reflected in pipeline tolls or royalties, which could be optimized to incentivize producers to pursue further on their own if rates reflected the processing costs. Unlike more raw products that can more flexibly be transformed into finished product that meet local preferences, refined goods are more rigid.

With refined goods produced in Alberta, any products made locally may not necessarily meet the standards or demand of the export destinations. While refiners may have capable marketing departments able to match buyers and sellers, they may find better value to produce at the source of demand due to response times, knowledge of market, or other reasons.

With an abundance of crude oil production in Alberta and constrained takeaway capacity, congestion has created steep discounts for upstream producers’ revenues and low-cost feedstock for downstream refiners. Compounded by constrained transportation systems and refinery outages in key markets for Alberta’s bitumen, prices for the province’s WCS benchmark averaged almost US$5/bbl in December 2018, down from about US$50/bbl just months before.

In addition to the lower price for WCS, the differential to the West Texas Intermediate (WTI) benchmark substantially increased to over US$45/bbl, which is usually closer to US$15/bbl under ordinary market conditions (Figure 14). In response to the low prices, which its royalties are a function of, the Alberta Government announced Curtailment Orders in December 2018 to limit output and restore prices. The restrictions affected about 25 producers capable of producing over 10,000 bbl/d and were received with mixed sentiments, depending on whether the company had integrated refining operations or sufficient takeaway capacity.

Figure 14: WTI & WCS Prices & Differentials (US$ per barrel), 2005-2019

160 50

140 45

40 120 35 100 30 80 25

60 20 15 40 Price (US$ (US$ Price Barrel)per 10

20 5 Differential (US$ perBarrel) 0 0 1/1/2005 7/1/2005 1/1/2006 7/1/2006 1/1/2007 7/1/2007 1/1/2008 7/1/2008 1/1/2009 7/1/2009 1/1/2010 7/1/2010 1/1/2011 7/1/2011 1/1/2012 7/1/2012 1/1/2013 7/1/2013 1/1/2014 7/1/2014 1/1/2015 7/1/2015 1/1/2016 7/1/2016 1/1/2017 7/1/2017 1/1/2018 7/1/2018 1/1/2019

WTI-WCS Differential WCS WTI

Data Source: (Alberta, 2019c)

Further to the transportation issue, Alberta also attempted to address a hold-up problem for rail service. While most producers are waiting for lower-cost pipeline capacity to be built, they are also unwilling to subscribe to long-term contracts with rail companies. Without commitments to rail, service providers are unable to afford investments in locomotives, transloading terminals, and other infrastructure. An executive at Canadian National Railway

(CNR) was quoted as saying oil producers “would get married with pipelines, but they only date the railroad” to summarize the problem (Tuttle, 2018). Initially, Alberta planned to contract up to 120,000 bbl/d in rail capacity worth almost Cdn$4 billion. The current government is now facilitating the transfer of these confidential agreements to the private sector, suggesting the right price and duration might be reached by market participants instead of the government.

3.1.3 Price Regulation In times where there is a perceived lack of competition, consumers may call on governments to regulate prices to be protected from a perceived market power – where a firm is able to profitably raise prices above competitive levels. While it is beyond the constitutional authority for the federal government to regulate fuel prices, except in times of national emergency, it is up to provinces to decide whether or not to regulate fuel prices. Although Western Canada does not currently have any price regulations for refined products or margins, several provinces in Eastern Canada do have some form of regulation: New Brunswick, Newfoundland, Nova

Scotia, Prince Edward Island, and Quebec. Despite the regulations in the East Coast intended to mitigate volatility, there is a lack of evidence to suggest that regulated rates actually lowers fuel prices for consumers (NRCAN, 2013). Further, a new regulatory board for fuels in Western

Canada would create bureaucratic and market inefficiencies for the larger market, especially if retailers would be required to justify price changes as frequently as weekly.

The provinces that have fuel price regulations also have differing approaches and reasoning for their regulations (Table 4). Quebec sets a minimum floor price to allow for retailers to cover their operating costs and prevent larger chains from predatory pricing by undercutting costs.

New Brunswick and Newfoundland have legislation and utilities boards to set maximums on wholesale and retail prices, subject to distribution costs and taxes. Nova Scotia and Prince

Edward Island each have regulatory agencies to supervise prices, but have a hybrid approach where there is a minimum and maximum price band; there is also zone-based pricing and an opportunity for retailers to apply for “fair and reasonable” changes. From an economic perspective, provinces with price ceilings are more prone to shortages, resulting in drivers either being rationed liters or going without fuel for extended periods of time.

Table 4: Comparison of Gasoline Price Regulation in Atlantic Provinces

Source: (National Energy Board, 2017)

3.2 Translation – Communicating Value & Compliance A private firm that sees an opportunity to make an economic return may pursue that feat if it sees value and knows what the steps are to get there. Before a project can become operational, let alone reach a final investment decision, certain regulatory requirements, both federally and provincially, need to be met before approval is granted. This subsection explores the main regulatory requirements for a refining project in Western Canada and outlines the methods proponents would use to show whether or not it would be in the public interest, especially from an economic standpoint.

3.2.1 Assessing Economic Viability A private firm will not move forward with a project to lose money, especially if it finds its own internal analysis delivers a negative financial outlook before making a formal proposal. While a firm may have different objectives and values than the general public, with different cost tolerances and benefit allocations, there are differing ways to assess the project’s value and impacts to society. As this report proposes a framework for an economic valuation of potential refining projects, it helps to understand current requirements and accepted evaluation approaches. Two of the leading techniques to review a project’s economics are: Economic

Impact Assessment (EconIA) and Cost-Benefit Analysis (CBA). This subsection discusses the tradeoffs between each of these economic modelling efforts and details why a CBA framework can be a better approach to appreciate the net effects of a refining project in Alberta. These economic tools are also applied in practice in the Project Economics section.

While each of these methods can use similar input information, their outputs can tell very different stories. EconIAs traditionally only use an investment or an expenditure to determine

54 gross effects to an economy with the use of a third-party input-output model. Commonly referred output figures include jobs, gross domestic product (GDP), and taxes. Although EconIA input-output models are typically independently maintained, through agencies like Statistics

Canada or Alberta Treasury Board and Finance, resulting estimated effects can have a number of flaws: uses of dated data (often lagged by five years), only provides a snapshot in time, and assumes benefits increases linearly with costs. Further, the shortfalls of an EconIA approach mean that there is no consideration of what incremental changes may occur, how effects are allocated across society, or even the viability of a proposed project to begin with. The reason

EconIAs have been commonplace in regulatory decisions include a sense of objectivity using independent models, ease and simplicity for proponents to derive estimated benefits, and often broadly defined criteria in regulations to assess the economic effects of a project.

A CBA can provide a clearer determination in weighing a proposed project, especially for the evaluation of projects involving government support. A CBA model can also provide value to identify and test sensitivities for cost and revenue centers, which can show the strengths and weaknesses of a proposal with adequate data. Unlike an EconIA, a CBA attempts to monetize all costs and benefits associated with a project to determine a net outcome. However, a CBA is not without its own shortfalls; these risks include: subjective inclusion or exclusion of items, varying preferences (e.g., discount rates), and fluctuating assumptions (e.g., prices and costs) that can greatly affect the results. With current regulations related to refineries in Western Canada, there is no common or prescribed list for factors to be considered in a CBA.

If a project is seeking government support or is preparing a CBA for a public hearing, the CBA should be consistent with the recommendations of the Treasury Board of Canada’s Canadian

Cost-Benefit Analysis Guide. The Treasury Board suggests the prime considerations for a CBA framework that could be reviewed by decision-makers to assess economic evidence. Although the guide focuses on creating a CBA for the purposes of evaluating proposed regulatory changes, the process could translate to a consistent process to evaluate projects. The guide also addresses risks and biases that could influence how results are produced, especially on contentious items like selected discount rates and less conventional approaches that attempt to apply different rates on costs and benefits (Canada, 2007).

3.2.2 Federal Requirements Under the current Canadian Environmental Assessment Act, 2012 (CEAA 2012), the Canadian

Environmental Assessment Agency (CEA Agency) has designated a number of physical activities that would trigger an environmental assessment. The purpose of an environmental assessment is to understand and mitigate adverse effects resulting from certain project. This assessment is used in the public interest decision-making process that weighs the environmental, social, and economic trade-offs. Included on the Regulations Designating Physical Activities are new and expanded oil refineries, as well as heavy oil upgraders, which have an input capacity of 10,000 cubic meters per day (m3/d) or more – this equates to more than 60,000 barrels per day (bbl/d).

Although the NEB has the authority to assess certain energy projects, such as pipelines, in conjunction with the CEA Agency, refineries do not fall under the NEB’s jurisdiction and can instead be assessed by a review panel appointed by the Minister of the Environment (Canada,

2012).

While CEAA 2012 is the current federal legislation (at the time of writing this report), the

Senate-approved Bill C-69 will soon update and replace the existing environmental assessment process once it receives formal assent to become law. One of Bill C-69’s elements, replaces

CEAA 2012 with the Impact Assessment Act and would create the Impact Assessment Agency

(IAA Agency); other tenets of Bill C-69 include repealing the National Energy Board Act to create the Canadian Energy Regulator Act, as well as amending the Canadian Navigable Waters Act.

The Canadian energy sector, in particular, has vehemently protested many of the changes put forward by the House of Commons, including increased assessments, Indigenous engagement, and public participation (Canada, 2019).

There is a sentiment of greater uncertainty in the energy industry for favorable outcomes with the inclusion of loosely defined assessments and unfamiliar processes, such as with gender- based analysis plus (GBA+) that seek to understand impacts to various groups within a society affected by a designated project (Canada, 2016). However, much of the content to be provided in a proponent’s impact assessments are similar in nature to existing requirements, including economic, social, and environmental effects. This would suggest an experienced proponent would already be equipped to fulfill these assessment requirements. Under the proposed legislation, there are concerns that proponents of projects subject to review will take longer and that the new agency will lack sufficient expertise.

Pessimism persists despite the legislated timeline reducing the amount of time the IAA Agency has to review from 365 days to 300; subsequently, panel reviews are also reduced from 720 days to a maximum of 600. As a result, project proponents will likely receive a decision sooner,

57 whether an approval or rejection. However, concerns have been raised on the potential for cabinet to provide indefinite extensions and several other factors involving ambiguity (Bishop,

2018). While there are a number of factors that are to be considered in the evaluation of a project, it is unclear how each one will be weighed in the decision-making process, as well as how climate change obligations will be considered. With the potential for regulatory delays to extend timelines, this risk can add to the proponents’ costs and foregone revenue streams.

3.2.3 Provincial Requirements On a provincial level, Alberta and BC have differing regulatory bodies that are responsible for adjudicating interested parties in building new or expanding existing refining capacity. Alberta has two key responsible authorities that would oversee refining and upgrading operations:

Alberta Environment and Parks (AEP) and the Alberta Energy Regulator (AER). The British

Columbia Oil and Gas Commission (BCOGC) only recently assumed responsibility for refineries in 2017. This subsection describes the differences between Alberta and BC for the respective procedures that proponents would need to interpret and comply with.

As part of Alberta’s Environmental Protection and Enhancement Act, several types of projects are required to undergo an environmental assessment, including oil refineries and upgrading facilities (Alberta, 2017). Refineries fall under the purview of AEP as they are classified as a downstream petrochemical facility. This means that refineries fall into a similar category as propane dehydrogenation facilities, ethane crackers, and methanol and gas-to-liquids plants.

Alberta provides a regulatory roadmap for refinery operators regarding each of the required steps, including addressing relevant legislation (Water Act, Public Lands Act, and Historical

Resources Act) and expected timelines to work towards an approval (Figure 15). As refineries

58 are also expected to conduct a federal environmental impact assessment, projects have the opportunity to conduct a joint review between both federal and provincial authorities simultaneously. Depending on how well prepared the proposal is and if legislative requirements are filed concurrently under the “single window” approach, a successful application for a complex project like a refinery can take between about 2.5 to 4 years to prepare, file, review, and issue a decision (Alberta, 2003). This review time is in addition to the more than five years it takes to plan and construct a refinery.

Figure 15: Alberta Petrochemical Facility Regulatory Roadmap

Source: (Alberta, 2018c)

Although bitumen upgraders are unique to the oil sands and other heavy oil jurisdictions, their regulatory requirements are worth discussing due to a number of refining propositions in

Alberta. Interestingly, many of these new proposals will operate as refineries to directly produce refined products, yet are technically classified as upgraders because they rely on raw bitumen as feedstock. Similar to how AEP reviews refining projects, the AER is responsible for reviewing upstream oil and gas projects, including upgraders that are considered an oil sands processing plant under the Oil Sands Conservation Act. Designed to apply to all oil sands projects and facilities in Alberta, the AER’s Directive 023: Oil Sands Project Applications provides a concise outline for the project application process and general requirements, including socioeconomic and environmental assessments (Figure 16). Applications made to the AER for upgraders are required to discuss several aspects of the project, processing technology selected, plant location and resource sterilization, throughput capacities for major equipment, utilities and infrastructure, water usage, as well as waste and byproduct handling and disposal.

However, the exact requirements for demonstrating economic viability of a project are sparse and proponents typically avoid providing proprietary information to maintain a competitive advantage, especially if a proposal goes before a public hearing.

Figure 16: A Simplified Application Review Process for Oil Sands Projects

Source: (Alberta Energy Regulator, 2013)

In BC, refineries are in a sort of regulatory limbo, where they are regulated under the Oil and

Gas Activities Act, having only been a recent addition to the legislation and currently undergoing development of regulations. Following legislative amendments made in 2015, the

61 two existing refineries in BC, in Burnaby and Prince George, are not considered oil and gas activities. Interestingly, any new refineries yet to be constructed will be classified as oil and gas facilities, but will be subject to yet-to-be delivered regulations (British Columbia, 2015). The

BCOGC only started to regulate oil refineries in 2017 and now takes on a similar role as AEP.

Not unlike Alberta, the BCOGC requires new oil refineries in its province to fulfill sections of its

Environmental Management Act, Environmental Assessment Act, Greenhouse Gas Industrial

Reporting and Control Act, and Safety Standards Act (British Columbia, 2017). Without transparent regulations or a clear path forward for potential entrants, an expansion of refining capacity in BC currently appears to be limited to its two existing refineries. Any new refining activity in BC could be deferred until regulations are determined, as regulatory uncertainties may be a deterrent to such a complex and costly type of project; however, it is more likely that regulations would be formalized by the time any new refineries become operational, which would be in the early-2020s at the soonest.

3.3 Transformation – Anatomy of a Barrel To understand what comes out of refineries, one must know what goes into them first. Before refined petroleum products (RPPs), such as gasoline and diesel, can be pumped into cars and trucks, crude oil feedstocks must be sourced and processed. This section discusses the upstream and downstream aspects of the crude oil supply chain in Western Canada, from where crude oil comes and where it goes. As much of Alberta’s production is ultra-heavy bitumen, upgrading options are also discussed as the processing is used to create a synthetic light oil and limited volumes of diesel.

Once crude oil is received at a refinery, the feedstock is blended with other types of oil and processed into a multitude of products, referred to as a product slate. Finished products have many different purposes and specific standards to meet local preferences. Although the exact output of refined products can vary from refinery to refinery, a common approximation for production and pricing in North America is called the “3:2:1 crack spread”, where three barrels of crude oil can make two barrels of gasoline and one barrel of diesel (Canadian Fuels

Association, 2013). Not all refineries follow this production function, as every refinery can be designed to run on different feedstocks that produce a varying range of products and are suited to regional demand preferences, such as industrial uses, climate and seasons, and prevalence of vehicles (e.g., diesel trucks versus gasoline cars). It is also possible for crack pricing spreads to be in the negative, especially when there is a buildup of refined product inventories and high crude oil prices – as what happened in early 2019 at the USGC (Figure 17). A negative spread can signal that there is a surplus of products, while a strong positive spread can indicate a shortage and arbitrage opportunity to supply that market.

Figure 17: USGC Gasoline & Distillate Crack Spreads (US$ per barrel)

Source: (Energy Information Administration, 2019)

3.3.1 Upstream Production

As the largest supplier of Canadian crude oil, Alberta produced about three mmbbl/d in upgraded and nonupgraded bitumen in 2018, as well as about 0.5 mmbbl/d in conventional oil

(Figure 18). Although conventional crude oil represents a significant amount of production, the focus of this report is on the challenges of abundance and refining requirements for bitumen.

Raw bitumen production in Alberta is derived from two main methods: mining and in situ projects. Mining operations excavate overburden to reach bitumen mixed with sand and other debris, usually less than 200 meters deep. Once excavated, the sand and bitumen are blended with hot water and stirred to separate the oil. Newer processes, such as paraffinic froth treatment, create blends of oil that can be transported easier without requiring upgrading capacity to match raw production volumes. Each mining project typically represents several billion dollars of investment, thousands of workers during construction and operation, and hundreds of thousands of barrels of production each day.

Figure 18: Alberta Total Primary Energy Production, 2008-2028

Source: (Alberta Energy Regulator, 2019)

Conversely, smaller-scale in situ schemes use steam injection to reduce the viscosity of oil underground. In situ projects can reach deposits much deeper, usually several hundred meters below the surface. Recent developments with the use of solvents show potential to increase ultimate recoveries while lowering operating costs by reducing the amount of steam needed

(Cenovus, 2019). Improvements in capacities, design-replicability, and lower capital costs would suggest that some producers will have the ability to increase production incrementally into the future with in situ schemes being favored over mining operations, which could affect the average density and quality of oil for Alberta crude reflected in benchmark prices. If partial upgrading becomes more commonplace on in situ schemes, Western Canadian refineries could see an improvement in the typical density and quality of feedstocks. Any marginal improvement in oil qualities are likely a factor refiners are cognizant of, especially with the sunk investment required to process heavier oil. Even with the potential for partial upgrading technologies, bitumen will continue to have a role in North American refinery feedstocks for years to come.

3.3.2 Upgrading in Between Several mining operations in Alberta have upgraders to improve the quality of their production before it gets sent to market, which transforms raw production into less-contaminated and lighter oil worth a premium price to nonupgraded bitumen. Upgraded production also has the benefits of freeing up pipeline capacity, as it reduces diluent needed for pipelines and allows producers to access more markets. Upgrading involves high capital cost equipment to produce synthetic crude oil (SCO) that resembles lighter blends of oil. While there are also higher processing costs associated with upgrading, the resulting product means that simpler refineries can be fed light oil and receive a higher price relative to heavier and higher sulphur crude oils.

However, many oil sands projects prefer to produce heavier blends of oil over full upgrading due to competing with lower cost, lighter oil supplies that have become abundant in the US due to shale oil production. Recently, global heavy oil supplies, particularly for North American refiners, have been challenged by geopolitics in Venezuela and Mexico decreasing supplies and putting an upwards pressure on heavy oil prices. Although upgraded bitumen can typically be priced relative to the main North American benchmark for light-sweet crude, referred to as

West Texas Intermediate (WTI), the additional capital and processing costs can make the initial economics of an upgrader unattractive. IHS Markit estimated in 2017 that the capital costs of an upgrader can exceed US$60,000 per flowing barrel and add an additional US$8-$10/bbl to base operating costs (Oil Sands Magazine, 2018). Further, output can be exacerbated by the same transportation challenges that all other liquids leaving Alberta face, meaning that the higher quality products can still be subjected to transportation discounts that challenge economics even further. With the costs to upgrade raw production and competition with other light crude oils, there is value to focus on refineries capable of handling raw bitumen versus upgraders that only convert the heavy oil to lighter blends.

Without differentials, in addition to the added processing costs, sufficiently and consistently exceeding the discount between WTI and the leading Western Canadian Select (WCS) heavy oil benchmark, it becomes uneconomic for producers to want to upgrade bitumen for the sole sake of making lighter oil. Due to the significant costs and technical complexities involved, there are only four operational upgraders in Alberta: Suncor, Syncrude, Canadian Natural Resources

Limited’s (CNRL) Horizon, and Shell Scotford; the Nexen (a subsidiary of the China National

Offshore Oil Company [CNOOC]) Long Lake in situ upgrader was also previously operational, but

66 was persistently challenged by economic conditions that led to an indefinite shut-in following the 2016 wildfires. However, new hybrid upgrader projects have started to emerge that are designed to directly produce refined products from nonupgraded bitumen feedstock, skipping the need for premium-priced lighter oil. As part of its “Made-in-Alberta” strategy, the former

Alberta government offered up to Cdn$3 billion in financial support for research and development of new technologies related to upgrading and petrochemical feedstocks. Out of this total, the Government of Alberta provided up to Cdn$1 billion in financial incentives under its Partial Upgrading Program (PUP) in 2018 to spur innovation and encourage more smaller- scale upgrading processes within the province (Alberta, 2018d).

In addition to making lighter oil, upgraders are also capable of producing distillate products, like diesel. Suncor produced nearly 29,000 bbl/d of diesel from its oil sands operations in 2018, representing about 10 per cent of its total upgraded products (Suncor, 2018). Hybrid upgrading refinery projects such as the North West Redwater Sturgeon refinery, which was initially applied for under the name North West Upgrading, are designed and equipped to handle raw bitumen to specifically produce diesel and limited volumes of other by-products, such as naphtha. The Sturgeon refinery, which is the first new refinery in Canada in over 30 years, has been slow to reach full operation to process 50,000 bbl/d of bitumen due to a number of technical issues. As a result of an issue with the facility’s gasifier unit (Unit 40), the facility has been unable to process heavy feedstock and has instead relied on lighter, costlier synthetic feedstock to produce diesel (Figure 19). Further, there has been skepticism about advancing the project’s second and third phases due to awaiting performance results from the first stage of the project; regulatory approvals have been granted to both phases, which would each process

67 an additional 50,000 bbl/d. The additional capacity of both phases would contribute 80,000 bbl/d of diesel to the existing surplus production of refined products in Alberta, all of which would need to clear in markets beyond the province.

Figure 19: Sturgeon Refinery Process Flow Schematic

Source: (North West Refining, 2019)

Despite being planned to address a growing demand for diesel leading up to 2010, the Sturgeon refinery has since been criticized for being a government “boondoggle” by Ted Morton, who previously held roles as Alberta’s Minister of Finance and Energy (Morgan, 2017). These claims came from how the project was financed with processing fees that were subject to cost overruns and questioned whether the province was better off marketing the raw product instead. The Cdn$26 billion cost of service agreement between the province and the refinery has Alberta paying processing tolls to cover the refinery’s capital costs and incurred debt, which rose from Cdn$4 billion when it was first proposed in 2008 to almost Cdn$10 billion today. The value of the project is still reportedly profitable as it relies on Alberta’s Bitumen Royalty in Kind

(BRIK) program and a commitment from the government to supply 75 per cent of the facility’s throughput for 30 years that enabled a lower cost of capital – CNRL provides the remaining 25 per cent of feedstock.

Low bitumen prices and upcoming fuel standards also have the potential to strengthen the fundamentals of a refining project over upstream activities. Although Alberta has the option to take its royalties as a share of either gross revenues or profits, depending on an oil sand project’s payout phase, it can also take its royalty in the form of physical volumes and have the

Alberta Petroleum Marketing Commission (APMC) sell it on behalf of the province. With a BRIK supply contract, the question of whether a refinery can provide value considers what price the

APMC could get on the market versus for raw products versus what it could get for a higher- value product, like diesel, less the additional processing and transportation costs (Figure 20).

Without this information being openly available, it has added to the public scrutiny of the

Sturgeon refinery.

Figure 20: Benefits & Risks of Sturgeon Toll Payment

Source: (Auditor General of Alberta, 2018)

In 2018, Alberta’s Auditor General concluded that that the APMC does not have “well-designed systems to manage and communicate the risks of its business arrangements and the agency does not have sufficient evidence to demonstrate that its risk management systems are operating effectively” (Auditor General of Alberta, 2018). Although the Sturgeon refinery may have an advantage to replicate additional phases at lower costs on its now-brownfield site near the Alberta Industrial Heartland region, future governments will look to take on less risk and reduce costs through innovative financial instruments at their disposal.

A number of other upgrading refinery projects have been proposed in Alberta beyond

Sturgeon’s expansions, including the 167,000 bbl/d refinery planned by Sinopec, and Value

Creation Incorporated’s (VCI) 260,000 bb/d Heartland Complex. If Alberta increases its own refining capacity, it will likely try to develop one of these planned projects to rely on more nonupgraded bitumen as a feedstock and promote economic benefits for political purposes.

The new Sinopec refinery is a reincarnation of the Alberta First Nations Energy Centre (AFNEC).

The original AFNEC refinery was a Cdn$6.6 billion project that had similar terms with the government as Sturgeon, with the province also supplying 75 per cent of the project’s initial

125,000 bbl/d capacity through the BRIK program for 30 years. However, the province cited front-end planning risks in its decision to pull its support from the original project in 2012

(Clancy, 2018).

The Sinopec project is open to the possibility of a revitalized joint venture with First Nations, which could unlock further tax benefits and provincial financial support programs. The upcoming Alberta Indigenous Opportunities Corporation will offer up to Cdn$1 billion in loan

70 guarantees for First Nations interested in investing in energy projects, but it appears to have coincided with the Trans Mountain pipeline announcement (Stewart, 2019). There were a number of Indigenous-backed consortiums that were interested in the pipeline, including the

Project Reconciliation and Iron Coalition groups. However, capital designated for the pipeline means that it is undetermined how much funding will remain for a refinery to be financed by

First Nations.

The current Cdn$8.5 billion Sinopec project description sounds like it will use nonupgraded bitumen as feedstock, which would suggest it will also apply for regulatory approvals as an upgrader. In January 2019, VCI was the recipient of a Cdn$440 million loan guarantee from the

Alberta government to put towards its Cdn$2 billion Heartland project, with the first phase processing 77,500 bbl/d of diluted bitumen by 2022. The Heartland project promises more than

2,000 construction jobs, 200 full-time positions during operations, and Cdn$2.5 billion in revenues to the province over 30 years. These metrics, along with the other project benefits discussed below, appear to be derived using the EconIA method mentioned previously.

However, it is currently unclear how the loan guarantee for VCI will be used and what the structure of the agreement entails – representing yet another lack of communication.

While it is tempting for Alberta to develop another refinery, there are also competitive propositions in BC that have geographical, transportation, and scale advantages. In BC, Kitimat

Clean Limited (Kitimat Clean) has proposed to build a greenfield 400,000 bbl/d heavy oil refinery near Kitimat. At a projected cost of Cdn$22 billion, the project plans to use railcars to move undiluted bitumen from Alberta to its refinery to produce gasoline, jet fuel, and diesel for

71 international export – and skirting the crude oil tanker moratorium made law by the assent of

Bill C-48. It is uncertain how much of the products produced in Kitimat will supply the rest of

BC. The first phase is estimated to cost Cdn$8.5 billion and process up to 125,000 bbl/d.

Although the company submitted an environmental project description to the BC and federal governments in March 2016, the company planned to take two years to do further environmental analysis, permitting, and engineering designs.

While its status is still unapproved, the project is expected to take more than five years to construct and employ 6,000 workers during that phase. An estimated 5,000 permanent jobs would be created within the refinery and petrochemical sectors in BC and across Canada, with thousands more jobs purported to be indirectly created beyond. However, one should take caution in how this project would align with other large-scale industrial projects also planned for Kitimat through the 2020s, such as the recently approved Cdn$40 billion LNG Canada project and the Pacific Future Energy (Pacific Future) refinery. Competing labor pools and other resources could rapidly lead to cost inflations, similar to the fate of the Sturgeon refinery during the bitumen boom during the mid-2000s to early 2010s in northern Alberta. The Kitimat Clean project appears to also look for a Cdn$10 billion loan guarantee from the federal government

(Kitimat Clean, 2019). As the project focuses on being an international exporter of refined products, Kitimat Clean believes it will offer a competitive cost advantage relative to other refiners with access to Pacific Rim markets. It is unclear how much Kitimat Clean would be willing to supply the BC market and how much it could lower consumer prices.

Similar to Kitimat Clean, the Pacific Future project also intends to process bitumen and has an ambitious proposed start-date of 2023. The Pacific Future refinery is expected to cost between

Cdn$12 billion and Cdn$14 billion to handle 200,000 bbl/d of undiluted bitumen that would be moved along CNR’s Mainline railway from Edmonton. Undiluted bitumen does not require blending agents to reduce viscosity for transport, which lowers freight costs and also makes the cargo exempt from Transport Canada’s Transportation of Dangerous Goods Regulations. The project expects to create 3,500 jobs during construction and over 1,000 full-time positions – macroeconomic contributions have not yet been published (Pacific Energy Future, 2016).

Previous major projects in BC set precedence for seeking government-induced cost savings through preferential exemptions and revised regulations. LNG Canada received several supports from both the BC and federal governments, which included “cost competitiveness” measures for sales tax exemptions on construction costs, industrial rates for electricity supplies, and repealing the LNG Income Tax Act (British Columbia, 2018). To allow the import of specialized materials, LNG Canada received special exemptions from the federal government for tariff exemptions on steel modules (Argitis, 2018). With duties waived on the steel modules from Korea worth Cdn$1 billion, LNG Canada proponents were able to strengthen the economics of the project.

One of the cost advantages for the Pacific Energy project involves keeping capital costs low by importing 100-150 prebuilt modules shipped in from Asia. The project’s proponent argues that this would be cost prohibitive for refineries in Alberta to attempt (Fletcher, 2018). Ironically, by reducing the capital costs and relying on an EconIA method, the economic impact modelling

73 would have reflected reduced benefits generated in Canada – such as the jobs that were needed to create the modules. Although the imported components and economies of scale support the viability of the project in BC, some outstanding constraints could potentially delay the commencement of the refinery. With the number of major industrial projects planned in near proximity to Kitimat, which has deep ports and relatively short distances to Asian market, the region runs the risk of facing labor constraints and other cost pressures. With a collective of the major energy projects listed above in the area, the coinciding timelines and other socioeconomic factors carry significant risk for those BC projects moving forward.

3.3.3 Downstream Marketing

Bitumen is abundantly available in Alberta (Table 5), yet costly to process and move due to its density and sulphur content. This means that bitumen usually needs to either be blended with diluent or sent for upgrading to be able to flow more easily on pipelines; all of which adds to transportation costs relative to lighter conventional oil. Beyond transportation costs, marketing opportunities are limited because not all refineries can process heavier oil. Existing refineries in

Alberta and BC also prefer to rely mostly on lighter oil feedstocks with heavier flows destined for outside of Western Canada (Figure 21).

Table 5: In-Place Volumes & Established Reserves of Crude Bitumen (109 m3), 2018

Source: (Alberta Energy Regulator, 2019a)

Figure 21: Input to Refineries by Crude Type – Alberta and British Columbia, 2017

Source: (National Energy Board, 2018)

With exports of bitumen heavily dependent on a few key downstream markets, planned maintenance and unexpected outages in these regions can drastically increase the discount for

Alberta’s oil. When coupled with a rapid onset of new production, the WCS benchmark will decrease and the differential to WTI will widen. This is what happened towards the end of 2018 with the addition of Suncor’s 180,000 bbl/d Fort Hills mining project and the outage of the

400,000 bbl/d BP Whiting refinery in Indiana suited to processing bitumen. As a result of the historically wide differential, Alberta initiated its Curtailment Orders to stem the buildup of production and recover rent on its resources through higher royalties tied to prices. Production was initially reduced by 325,000 bbl/d in January 2019 and was relaxed monthly going forward as market conditions and transportation options were restored; the limit for September 2019 is

3.76 mmbbl/d, compared to the 3.56 mmbbl/d in January (Alberta, 2019).

Besides Sturgeon, there are four other operating refineries within Alberta: Imperial’s 191,000 bbl/d Strathcona, Shell’s 92,000 bbl/d Scotford, Suncor’s 142,000 bbl/d Edmonton, and Husky’s

29,000 bbl/d Lloydminster (which produces asphalt). These five refineries represent a total

75 capacity of 533,000 bbl/d and are capable of processing a range of feedstocks that are often integrated with upstream production, including the oil sands (Table 6). It is worth noting

Saskatchewan has two refineries capable of running on heavy feedstocks: the 135,000 bbl/d

Federated Co-operatives Limited integrated upgrader and refinery and the 19,000 bbl/d Gibson

Moose Jaw facility. Gibson is currently advancing its small-scale Moose Jaw Expansion project, which intends to grow throughput capacity to about 22,000 bbl/d at a capital cost of up to

Cdn$25 million (Globe News Wire, 2019).

Table 6: Refineries in Western Canada by Province

Source: (CAPP, 2019)

In BC, there are currently only two refineries in operation, which both rely on lighter feedstocks: the 55,000 bbl/d Parkland Fuel Corporation (Parkland) Burnaby and 12,000 bbl/d

Husky Prince George. Connected by Canada’s existing Trans Mountain pipeline, Alberta currently supplies BC with as much as 25 per cent of its gasoline and diesel needs. Parkland has shown interest in expanding its output to feed more of the BC market. Parkland announced its

Cdn$300 million facility modernization strategy between 2019 and 2023 to add new processing and hydrotreatment for feedstocks, which is intended to allow the refinery to handle more renewable feedstocks (Parkland Fuel Corporation, 2019). Parkland also has the advantage of owning retailers that can distribute fuels in BC, which is something a new entrant would also need to address and make investments.

Beyond Western Canada, the two largest markets and most complex refining hubs in North

America that are regularly able to draw on heavy feedstocks are in the US Midwest and USGC, which are respectively referred to as the Petroleum Administration for Defense Districts (PADD)

II and III. According to the Canadian Association for Petroleum Producers (CAPP), Western

Canada supplied 2.5 mmbbl/d in oil out of the total 3.8 mmbbl/d in refining capacity in PADD II over 2018 (Figure 22). Despite PADD III having 49 refineries with a total 9.8 mmbbl/d in capacity, only about 2 mmbbl/d is suitable for heavy refining. While Western Canada supplied about 480,000 bbl/d to PADD III in 2018, progressive geopolitical challenges in Venezuela and

Mexican energy policy reforms are creating a shortage of heavy oil supplies to the USGC (Figure

22). The heavy supply shortage has increased the price of heavy oil, but market access constraints and other policy questions have limited how much more Alberta producers can supply to the region (CAPP, 2019).

Figure 22: PADD II Refining Capacity, 2018

Source: (CAPP, 2019)

Figure 23: PADD III Refining Capacity, 2018

Source: (CAPP, 2019)

Without an upgrader, which most in situ operators lack access to, nonupgraded production is forced to find its way to select refineries capable of handling ultra-heavy oil. Some in situ producers have contracted access to or co-own refineries, such as Cenovus with its joint ownership in refineries in Illinois and Texas (Cenovus, 2017). Other Alberta integrated producers with refineries outside of the province include Suncor with refineries in Ontario,

Quebec, and Colorado; beyond Alberta and BC, Husky has refineries in Ohio and Wisconsin.

Destinations for Alberta’s bitumen are linked to the complexity of refineries capable of processing the heavier feedstock. The sophistication of a refinery is based on the Nelson complexity index (Equation 3). A higher Nelson rating reflects an operation’s ability to recover more products from lower quality feedstocks with more complex equipment.

Equation 3: Nelson Complexity Index

� �� = ∑ �� =1

��: Complexity factor

��: Unit Capacity

��: Distillation unit capacity

Beyond a basic distillation column, refineries that are more complex have special equipment that use chemical processes to either make or break hydrocarbon chains. Each additional piece of equipment can produce unique benefits, such as improving separation, removing sulphur and other contaminants, or upgrading low-value products to higher-value ones (Figure 24).

Although additional pieces of equipment can have individual complexity ratings that range from

1.0 to 60.0, the Phillips 66 Ferndale refinery in Washington has a higher total complexity of 7.0

79 and is capable of handling heavier crudes sourced from Alberta. Some of the world’s most complex refineries are found in the USGC and are closer to 15.0 on the Nelson index, which is why they are able to thrive on high density, low cost feedstocks like bitumen (Energy

Information Administration, 2012).

Figure 24: Simplified Illustration of a Petroleum Refinery

Source: (National Energy Board, 2018)

Deep conversion equipment are much more costly than those on simpler refineries. Installed fluid catalytic cracker (FCC) and hydrocracker units were estimated to respectively cost US$150 million and US$350 million for 50,000 bbl/d in 2005 (Colorado School of Mines, 2018). Heavy- residue hydrocracking and hydrotreatment processes are designed to produce no petroleum coke, which results in less carbon-intensive finished products. Other equipment capable of processing heavier oils include equipment include cokers designed to remove carbon out of the residual to capture the last value out of byproducts. These coker projects can cost in excess of

Cdn$1 billion, which was the value previously reported by Suncor for plans at its Montreal refinery in 2014 (McCarthy, 2015).

These costs can be prohibitive for most refiners to install, which explains why these processes account for much less than the more basic vacuum distillation process (Energy Information

Administration, 2019). More complex refineries, especially those in the USGC, that previously made substantial investments in processing equipment capable of handling heavier crude oil, have recently enjoyed the advantages and economic benefits of being able to source lower cost feedstocks, which run at a discount to lighter, sweeter blends.

3.4 Transportation – From Here to There Even with growth in demand across Western Canada, Alberta continues to have a substantial surplus of refined product supplies. After stockpiling reserves and distributing finished products throughout Alberta, refiners need to export excess volumes to other markets. While Alberta and Saskatchewan are net exporters of refined products, BC relies on imports from a number of sources to make up for its fewer and smaller refineries’ output. This section discusses the supply and demand balances for refined fuels to explain how refined products can get to markets and why most incremental finished products will need to move beyond Western

Canada.

3.4.1 Balancing Supply & Demand As discussed in the previous section, Alberta has over 530,000 bbl/d in refining capacity available, while BC only has under 70,000 bbl/d; it should be noted that the Prince George refinery supplies most of BC north of Kamloops and also the Northern Territories by rail (Figure

25). According to the NEB, Alberta’s total refined product demand in 2017 was 323,000 bbl/d, which included 117,000 bbl/d in gasoline and 122,000 bbl/d in diesel. Similarly, BC consumed

214,000 bbl/d in 2017, including 96,000 bbl/d in gasoline and 79,000 bbl/d in diesel (National

Energy Board, 2019). As a result, additional production of finished products made in Alberta will need to reach markets outside of its provincial boundaries and more likely international opportunities.

Figure 25: Alberta & BC Refining Capacity & Product Demand, 2017

Data Source: (National Energy Board, 2019)

The excess supply in Alberta and shortage in BC means that there are trade opportunities between the two provinces, but any major increases in supply could crowd out existing suppliers. Since the 1980s, three out of the four refineries operating in the Burrard Inlet in BC have shut down. Increasing population demand and the resulting shortfall in BC supplies has since needed to be filled by imports, which has led to BC importing 2/3 of its refined products from Alberta and about 10 per cent from the US Pacific Northwest (Parkland Fuel Corporation,

2019). The 300,000 bbl/d Trans Mountain system is estimated to supply 30,000 bbl/d of refined products from Alberta, with the remainder supplied by rail (CAPP, 2019). Existing supply chains will be disrupted with a new refinery, either in Alberta or BC, and especially if the costs of

Western Canadian supplies can undercut and displace imports from Washington State through reduced transportation costs.

To avoid a similar situation with refined products as the crude oil backlog that resulted in the

Curtailment Orders, an increase of refined products should demonstrate it can reach distant markets to avoid deleterious prices and margins at home. As the Kitimat projects intend to do, any expansion of refining capacity will likely need to leave the Western Canadian market. While the Kitimat refineries have explicitly stated their intentions to focus on satisfying expanding

Asian markets, it will be necessary for any other projects to find opportunities to supply foreign markets with their products.

With existing transportation options available, such as trucks and barges, Alberta or BC refiners could potentially expand access to California, Oregon, and Washington – collectively referred to as PADD V (US West Coast). As there is a lack of crude oil pipelines, PADD V could present a nearby market opportunity as it is fairly isolated on land and relies on seaborne imports from

Alaska to backstop production in California. Further, the region has limited capacity to export refined products into BC, as it already has high refinery utilization rates for the five refineries in the Puget Sound area in Washington, and has relatively similar fuel standard requirements in certain states to those in Canada, such as those from the California Air Resources Board (Energy

Information Administration, 2015). This would suggest that harmonized environmental standards with supply-constrained jurisdictions in the US could create marketing opportunities for refined products sourced from Western Canada.

3.4.2 Pipelines The most efficient way to move petroleum products across land, either raw or refined, to market involves a pipeline. Alberta’s Industrial Heartland and the refining hub that it encompasses near Edmonton and Fort Saskatchewan have three main pipelines that leave the area and can move refined products (Figure 26): Trans-Northern’s Alberta Product Pipe Line

(APPL), Enbridge’s Mainline, and the Trans Mountain system, including the re-approved Trans

Mountain Expansion (TMX). From this main staging point in Central Alberta, 48,000 bbl/d in refined products can flow 320 kilometers south along the APPL to Calgary. After the APPL completes a replacement project later in 2019, more refined products, like jet fuel and diesel, will be able to reach the recently-expanded Calgary International Airport and the Shepard industrial area in southeast part of the city (Trans-Northern, 2018).

Figure 26: Major Existing & Proposed Canadian & U.S. Crude Oil Pipelines

Source: (CAPP, 2019)

Outside of Alberta, the Enbridge Mainline runs east and ultimately reaches Sarnia, Ontario. The

Mainline also allows Saskatchewan to contribute crude oil and refined products as the volumes head east. Enbridge is currently advancing its Cdn$9 billion Line 3 Replacement project, which will replace old infrastructure and restore up to 370,000 bbl/d in volumes previously reduced by imposed pressure restrictions (Enbridge, 2019). The project will replace dated infrastructure in both Canada and the US that dates back to the 1960s. Much of the regained volumes on the

Line 3 system, however, are expected to feed refineries in US Midwest with heavier oil.

Depending on the ability of US refineries to contract space for crude oil flows under Enbridge’s planned tolling agreement for its Mainline, there may be limited room for Alberta refiners to export refined products if heavy oil dominates the available spare capacity.

The Government of Canada-owned TMX formally re-received approvals in June 2019 after it addressed the Federal Court of Approval’s (FCA) August 2018 decision. In its ruling, the FCA quashed the original federal cabinet approval for the project that was granted in November

2016. Although cost estimates for the TMX have recently approached Cdn$10 billion, there continues to be interest and a business case for the pipeline with the existing system regularly oversubscribed. With excess production and disproportionate pipeline capacity available, common carrier pipelines use apportionment to ration available capacity on the system.

Volumes not fulfilled under apportionment are then either stored or moved with costlier rail services, which can lead to a buildup of supply and result in lower prices for oil in the areas constrained by takeaway capacity.

Tolls for Trans Mountain shipments from Edmonton to BC are also based on the density of oil shipped, which is reflective of the blending agents required to reduce the viscosity of the oil being moved and occupy space in the pipeline (Figure 27). The current tolls from Edmonton to

Burnaby are about Cdn$3.25/bbl for light products, but are expected to rise to account for the

TMX construction costs (Trans Mountain Pipeline, 2019). For products bound for exports beyond BC, heavier oils are shipped to either the Westridge Marine Terminal (Westridge) or

Sumas Terminal, with the latter being used as a staging area to supply Washington refineries along the Puget Sound pipeline (Figure 28).

Figure 27: Trans Mountain Tolls Edmonton-Westridge (Cdn$ per barrel), 2009-2019

Source: (National Energy Board, 2019a)

Figure 28: Trans Mountain Pipeline System

Source: (Trans Mountain, 2019)

The TMX pipeline presents an opportunity to relieve some of the pressures for bitumen producers in Alberta, but does not offer as much for BC in terms of refined products. With the expansion, the existing pipeline and two reactivated segments would become Line 1; the new pipeline and parts of the existing system would become Line 2. The new Line 2 will be used exclusively for heavy oil and bitumen, while Line 1 will still be able to carry lighter oil and refined products in batches. Although 20 per cent of the Trans Mountain system was planned to move heavy oil in 2014, it has regularly moved much less heavy products and instead favored light oil and refined products (Figure 29).

Figure 29: Trans Mountain Pipeline Throughput & Capacity (Thousand barrels per day at Burnaby, Sumas, & Westridge), 2009-2019

Source: (National Energy Board, 2019a)

While much of the TMX capacity is already contracted for bitumen, additional room for more refined products on the existing Trans Mountain system will be limited; this would mean that any surplus capacity in Alberta would likely need to be contracted on costlier railcars. In consideration of the light product constraints on the Trans Mountain system, the threats made by the Alberta Government under the Preserving Canada’s Economic Prosperity Act, colloquially dubbed the ‘Turn-Off-The-Taps’ legislation, are largely political theater. Instead of shutting off oil exports, Alberta could legally squeeze fuel supplies for BC by encouraging shipments of heavy oil instead, which the current BC refineries cannot process.

3.4.3 Alternative Modes Without pipelines, the next best alternative for transporting products depends on proximity between upstream production, refineries, and final consumption. Although figures include deliveries to the US, Canadian oil exports via rail rapidly increased with pipeline constraints and additional upstream production in 2018, rising from about 150,000 bbl/d in January and up to

350,000 bbl/d by December (Figure 30). Longer distances can also be served by rail, which offers a faster pace than pipelines and can connect easier to higher-priced markets with rail serving more markets compared to pipelines. The frequency and size of hauls also depends on the availability of railcars, which can be further affected by a number of reasons: like adverse winter conditions, obligations for grain movements, and lack of engineers. The Government of

Alberta previously planned to spend up to Cdn$3.7 billion to lease 4,400 railcars capable of carrying up to 120,000 bbl/d, but has since sought to offload the agreements to the private sector.

Figure 30: Canadian Crude Oil Exports by Rail, 2012-2019

400 350

300 250 200 150

Thousandbbl/d 100 50 - Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Sep-12 Sep-13 Sep-14 Sep-15 Sep-16 Sep-17 Sep-18 May-12 May-13 May-14 May-15 May-16 May-17 May-18 May-19 Data Source: (National Energy Board, 2019)

For shorter routes, trucks can deliver up to a few hundred barrels of refined products from refineries and other terminals. Longer distances and limited volumes make trucking less economic compared to other options and, therefore, this mode does not have a significant role in this analysis. Movements by sea can be quite cost efficient for longer distances, whether importing or exporting (Figure 31). Smaller barges occasionally act as conduits to buffer BC

89 shortages by importing refined products supplied by Washington’s refineries, but imports into

BC need to be blended with renewable fuels to meet provincial requirements. Therefore, international imports beyond Washington are limited in volumes and frequency. With a potential surplus of refined products from leaving BC in the future, exporters may find it viable to use barges to reach other markets along the West Coast, including California. However, this would only be a viable option if the boats are available for contract and fuels can meet the destinations’ environmental fuel standards.

Figure 31: Crude Oil Transportation Costs (Approximations), 2011

Source: (Inkpen & Moffett, 2011)

Although there have been significant volumes of imports of gasoline and diesel into BC, the Port of Vancouver reported net exports for all of these petroleum products between 2016 and 2018

(Port of Vancouver, 2018). This would suggest exporters are finding economic opportunities to ship products abroad, especially considering larger ships can be contracted on a daily rate-basis and can realize tremendous scales of economies once filled. The largest tankers cleared for the

Port of Vancouver are the Aframax class, which can haul up to 850,000 barrels (Clear Seas,

2019). Studies have also found that shipping crude oil long distances by sea can be more cost

90 competitive than pipelines on a per barrel basis, with European and African imports to Eastern

Canada costing well under Cdn$2/bbl to transport (CERI, 2018). It is likely transportation costs and travel times to move products from Canada’s West Coast to distant Asian markets would resemble similar shipping rates, adding credibility that either Alberta or BC could compete in the global market with supplies of refined products.

3.5 Termination – End Use & End Date Petroleum products will undoubtedly have a role in our daily lives for decades to come, especially as global populations continue to grow and move. Over the longer term, government policies can nudge individuals’ preferences or make substitutes appear more attractive on the margin, whether for fuels or modes of transportation. Despite environmental impact reduction policies in developed economies, demand for refined products is projected to continue to increase worldwide as developing economies become accustomed to modern luxuries, such as heating, lighting, and transportation. However, even with this growth, it is important to consider how the composition of energy use and carbon policies can affect the future need for refineries.

3.5.1 Energy Transition As the globe continues to advance technologically and use greater volumes of hydrocarbons, developed economies have increasingly become able to afford more carbon-conscious alternatives. While natural gas burns cleaner, it has traditionally found its purpose in heating and power generation over direct use in transportation. As electric cars and other power needs evolve, so too will the role of developing natural gas, battery storage, and supporting infrastructure. For now, and for expected decades to come, crude oil fulfills the need for a fuel

91 that is balanced between energy content and volume (Figure 32). The transportation sector, including long-distance hauling and travel on land, sea, and air, continue to represent a substantial share of demand for refined products. While these sectors and other petroleum byproducts are beyond the scope of this research, the International Energy Agency (IEA) provides a global outlook for oil demand that considers some of these broader factors.

Figure 32: Energy Density Comparison of Transportation Fuels (Indexed to Gasoline = 1), Energy Content per Unit Weight

Source: (Energy Information Administration, 2013)

According to the IEA’s New Policy Scenario, their global crude oil demand forecast

“incorporates existing energy policies as well as an assessment of the results likely to stem from the implementation of announced policy intentions.” Under this outlook, oil demand in the transportation sector is still expected to rise from 51.6 mmbbl/d in 2017 to 59.5 mmbbl/d in

2040 – representing a 15.5 per cent growth between the two periods (Figure 33).1 This would suggest that with more rapid hydrocarbon fuel demand growth beyond Western Canada, there

1 A conversion of 7.35 barrels of oil to one tonne of oil equivalent is use to determine a bbl/d basis.

92 will be export opportunities for refiners to meet the needs of other growing economies, especially within Asia. Even with carbon pricing and other emission reduction strategies, newer refineries can be designed to produce certain specifications of fuel that meet regional emissions standards domestically and abroad. These specialized refined products can carry benefits to distant markets, which include higher octanes and lower sulphur contents.

Figure 33: IEA World Oil Demand under New Policies Scenario, 2000-2040

Source: (International Energy Agency, 2019)

3.5.2 Industrial Emitters In Alberta, the current government’s iteration of the industrial emitters’ policy will become the

Technology Innovation and Emission Reduction (TIER) fund. Starting in January 2020, facilities that produce over 100,000 tonnes of carbon dioxide equivalent (CO2e) other than electricity generators, will need to improve their emissions intensities by 10 per cent compared to their average performance between 2016 and 2018. To achieve the requirements, operators can

93 reduce facility emissions, purchase credits or offsets, or pay a compliance price of

Cdn$20/tonne (United Conservative Party, 2019). Alberta has had similar systems in place since the Specified Gas Emitters Regulation was first introduced in 2007 and the current Carbon

Competitiveness Incentive Regulation was enacted in 2018; this would suggest that even with the new TIER system, existing refineries have already considered these carbon costs in their margins and passed those along to consumers. It is worth noting that Alberta formally repealed its consumer carbon tax in June 2019, which translated to 6.73 cents per liter on gasoline and

8.03 cents per liter for diesel based on the carbon price of Cdn$30/tonne. However, it remains to be seen if the federally imposed carbon price will be introduced in 2020 or will be extinguished in court on a constitutional challenge before then.

BC has a number of carbon policies under its Climate Action Legislation, including carbon taxes, industrial reporting, and greenhouse gas reduction. Industrial operations, including refineries, which emit over 10,000 tonnes of CO2e per year are required to report their emissions under the Greenhouse Gas Emission Reporting Regulation. Further, the carbon tax in BC, including the rate paid under the CleanBC Industrial Incentive Program, rose from Cdn$35 to Cdn$40/tonne in April 2019, and will rise up to Cdn$50/tonne by 2021 (Figure 34). At the current rate of

Cdn$40/tonne, consumers pay 8.89 cents per liter on gasoline and 10.23 cents per liter at the pump (British Columbia, 2019). This comparison would suggest Alberta possesses a marginal carbon tax advantage for both industrial emitters and consumers compared to BC, even if the federal carbon levy backstop is imposed with its carbon price reaching Cdn$50/tonne by 2022

(Canada, 2018).

Figure 34: Current2 Canadian Carbon Pricing Policies, 2015-2025

Source: (Dobson, Winter, & Boyd, 2019 )

3.5.3 Blending Requirements Other factors with the potential to influence the viability of refineries include government mandated fuel blending standards. Since 2010, Alberta has had its Renewable Fuel Standards

(RFS). The RFS requires a minimum annual average of 5 per cent renewable alcohol in gasoline and 2 per cent in diesel sold in Alberta, which is intended to produce an emissions intensity 25 per cent lower than the fuels’ respective benchmark (Alberta, 2010). In addition to lowering emissions, the RFS also facilitates a market for renewable fuels and encourages the development of other technologies. Beyond grains, other biological sources of fuels include corn, canola, cellulose, and even livestock waste.

BC implemented its Renewable Fuel Regulations (RFR) in 2008. As part of the RFR, the BC Low

Carbon Fuel Standards (LCFS) also intends to reduce emissions from fuels used, diversify supplies, and provide incentives for low carbon fuels. While BC sets a 5 per cent average blend

2 Alberta will lower its industrial emitter carbon price to Cdn$20/tonne with its new TIER program that will replace the existing CCIR, which had a carbon price of Cdn$30/tonne.

95 rate for gasoline, diesel has a 4 per cent blend rate. BC anticipates ethanol demand to increase with more E15 compatible vehicles (capable of running off of up to 15 per cent ethanol blended into fuel) on the road, which are needed to meet provincial fleet fuel economy standards by

2025 (British Columbia, 2018). Other fuel alternatives expected to create opportunities in BC include biodiesel and hydrogenation-derived renewable diesel produced from refined fats and vegetable oil. However, limited sources of ethanol in Western Canada means this can add to the cost of blended fuel with a need for a backstop of imports from the US. Imports would be required to mitigate effects from potential shortages resulting from poor crop yields and processing facility outages. From BC to Manitoba, there is a maximum capacity of about 810 million liters per year of biofuels, which translates to just under 14,000 bbl/d (Figure 35). This would suggest that any significant increases in oil refineries will require comparable increases in ethanol and biodiesel facilities.

Figure 35: Western Canadian Biofuel Industry Map

Source: (Renewable Industries Canada, 2019)

The Government of Canada is continuing to develop its own Clean Fuel Standard (CFS) that intends to reduce 30 million tonnes in greenhouse gas emissions by 2030 relative to 2005. The

CFS will also be designed to incent the innovation and adoption of clean technologies in the oil and gas sector, and development and use of low-carbon fuels throughout the economy

(Canada, 2019a). Across Canada, the CFS will require a minimum 5 per cent of renewable fuel content for gasoline and 2 per cent. Interestingly, BC and Alberta, as well as Saskatchewan,

Manitoba, and Ontario already either meet or exceed these conditions; this is worth noting in the event the CFS plan is scrapped following the 2019 federal election, suggesting western provinces should not expect to see a decrease in fuel prices – despite political grandstanding.

Although refineries are able to decrease some of the sulphur content from feedstock, the WCS benchmark typically has higher sulphur ratios of about 3.5 per cent, which is higher than many other blends (Crude Monitor, 2019). Internationally, one of the greatest potential disruptors to the global market for high sulphur diesel and oils, such as bitumen, is the International

Maritime Organization’s (IMO) 2019 Guidelines on Consistent Implementation of 0.50% Sulphur

Limit Under MARPOL Annex VI. The guidelines are more commonly referred to as the IMO sulphur standards that will become effective January 1, 2020. Although the IMO sulphur standards target bunker fuels for shipping, there are probable repercussions for both Western

Canada’s upstream and downstream sectors. The standards limit the sulphur allowed in fuel oil for ships to 0.5 per cent, down from 3.5 per cent previously; as result of the standards, IMO forecasts a 77 per cent reduction of sulphur oxide emissions from ships between 2020 and 2025

(International Maritime Organization, 2019). While it is possible for certain refineries to process

97 impurities such as sulphur, there is a challenge of how much existing complex refining capacity is available to handle heavy oils and produce sufficient diesel for shipping.

There are a number of possible outcomes for shipping companies with the standard’s rapidly approaching start date, but common strategies include: ships do not comply and face penalties if caught, make expensive conversions to use liquefied natural gas, attach emission scrubbers that cost about US$1 million to use higher sulphur fuels, or blend higher quality products like diesel with the low quality bunker fuel (Al-Sadoun, 2019). Because of the IMO standards, there is an expectation that high-sulphur feedstocks, like WCS, will face steeper discounts without sufficient heavy oil refining capacity to remove impurities. Although bunker fuels only account for about 4 per cent of global oil demand, CERI estimates that lost refinery margins could translate to discounts for WTI-WCS of between US$16/bbl to US$20/bbl. Adding to the base

WTI-WCS differential, IMO regulations could potentially increase the total differential up to

US$40/bbl. The magnitude of the discount will also depend on the degree of shipping compliance with lower sulphur fuels (Figure 36). Additionally, diesel prices are expected to rise with increased demand from the shipping sector. Refineries with heavier processing capabilities are expected to benefit due to lower cost feedstock, such as those with fluid catalytic crackers and delayed coking capacity.

Figure 36: Changes to WTI & WCS Prices Due to the IMO Regulation (2017 US$)

Source: (CERI, 2018a) 4.0 Project Economics

The objective of Alberta’s resource-owners is to maximize the value of the products it sells and rent it collects. In terms of refining in Alberta, it is worth considering whether the province would be better off exporting raw products to refine in other markets or to encourage processing within the province to capture additional value. Governments may provide subsidies to generate indirect benefits for some citizens at the cost of others in an attempt to increase the size of the proverbial pie. In the case of efficient interventions, making society is made better off if the total gains to the “winners” can exceed the losses to everyone else.

In reality, other factors can play into where refineries are built that override economic rationale, such as governments competing against other jurisdictions to secure tax dollars and generate jobs via construction and operational activities. These supports have typically taken the form of feedstock supplies, cost of service agreements, and loan guarantees. Ideally, such subsidies are provided if they are perceived to outweigh the initial costs of intervention, though this is not always the case and certain projects stand to benefit differently than others.

This section of the report provides three modelling exercises to assess the attractiveness of a project to both private and public sectors. A cost-benefit analysis (CBA) is first established to determine a net value of a hypothetical project. Second, a Monte Carlo simulation is explored on top of the CBA to evaluate risks and uncertainties that affect simultaneous input assumptions. Relying on expenditures calculated within the CBA, a third model is created for an economic impact assessment to estimate the gross direct and indirect macroeconomic effects on Alberta. Further information on project details, processes, and limitations are subsequently discussed throughout this section.

Relying on the information collected and summarized in the preceding sections, this part of the report assesses the economics of various types of refineries to understand the characteristics of projects that Alberta could made be the most viable with the least cost to government. The hypothetical refineries are assessed for commercial viability and economic impacts. Metrics from these assessments can be used to understand the credibility of projects advancing, where government supports can have the most effective impacts, and what kind of benefits could be expected for the general public. The projects of interest involve three hypothetical refineries that are used to test the economic viability and resource opportunity cost of each option:

 New Refinery – a larger 100,000 bbl/d greenfield refinery that would need to be constructed without any prior existing infrastructure;  Expansion – represents an incremental addition of 50,000 bbl/d heavy oil processing equipment to an existing facility to increase throughput capacity of bitumen; and,  Acquisition – an existing 50,000 bbl/d refinery that exists in a market outside of Alberta that could be purchased without further equipment additions or facility expansions.

100

4.1 Cost-Benefit Analysis A CBA framework is developed to assess the options for refineries capable of processing bitumen as a feedstock. Using a discounted cash flow model, the CBAs deliver a net present value that would suggest the project delivers either a positive economic value or a net loss. A positive value would suggest that the project may be viable on its own and would not necessarily require government intervention. A negative or even marginally economic project would require some form of subsidy to become viable, which could be used for further discussion and policymaking decisions. Assumptions for the base case CBA models are outlined below (Table 7) and are expanded in the following subsections.

Table 7: Base Scenario Assumptions

Category Assumed Rate

TIER Compliance Cost Cdn$20/tonne CO2e in excess of 100,000 tonnes/year

Refinery Emission Intensity 0.03 tonne CO2e/barrel of oil Alberta Corporate Income Tax Rate 8% (Post 2022) Federal Corporate Income Tax Rate 15% Project Life 30 Years

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4.1.1 Costs Costs for refineries are separated into two main categories: capital and operating. Capital costs reflect those that are used to finance and build a refinery. In addition to engineering designs, regulatory costs, and installed equipment, capital costs can be sensitive to labor productivity, regional inflation, and startup delays. To provide capital costs for the different hypothetical refineries, research from earlier sections provides a range of values for costs and throughput scale for the hypothetical projects. Capital costs divided by the nameplate throughput capacity derives a “per flowing barrel” dollar value. This flowing barrel basis is used to create a boundary range of total costs for a project, which tests for soundness of assumptions and can later be subjected to other scenarios (Table 8).

Table 8: Reference Refinery Capital Costs & Capacities

Nameplate Approximate Cost Refinery Capital Cost Refinery Name Capacity per Flowing Type (Cdn$ billion) (bbl/d) Barrel Northwest Redwater $4/$10 50,000 $80,000/$200,000 Sturgeon (Proposed/Actual) New Sinopec $8.5 167,000 $50,000 Refinery VCI Heartland $2 77,500 $25,000 Kitimat Clean $22/$8.5 400,000/125,000 $55,000/$70,000 (Total/Phase 1) Pacific Future $14 200,000 $70,000 Energy Expansion Fluid Catalytic $0.25 50,000 $5,000 (Addition of Cracker Equipment Hydrocracker $0.6 50,000 $12,000 Only) Acquisition (Dedicated Husky Superior $0.575 50,000 $11,500 to Oil Sands)

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Operating costs can take the form of both fixed and variable rates, where fixed costs do not change and variable costs adjust with throughput. Fixed costs for refineries are generally in the form of routine maintenance, major turnarounds, labor and management of assets, and other costs to keep the refinery safely and efficiently operational. Variable costs can fluctuate alongside utilization rates and the complexity of a refinery for a number of reasons, including fuel and electricity consumption, as well as catalysts and chemicals used to process oil

(McKinsey & Company).

The IEA reported North American operating costs for refineries were about US$8/bbl in 2014, which converts to about Cdn$11/bbl in today’s dollars (International Energy Agency, 2014).

Additional operating cost information was sourced from the Livingston paper on the Sturgeon refinery, which cited Husky’s operating costs of US$10/bbl for the model developed in that study; further, the report included annual maintenance costs of US$20 million and major turnarounds worth US$80 million every four years (Livingston, 2018). While the model for this report follows a similar pattern for recurring operating expenses, there is also an ability to apply sensitivities to these input costs.

A fundamental input cost for refineries involves the feedstock that it uses. With the hypothetical refineries designed to draw on nonupgraded bitumen supplies, the Western

Canadian Select (WCS) benchmark was chosen for pricing. To develop a price forecast, the historical pricing was assessed for a baseline discount to the leading North American West

Texas Intermediate (WTI) benchmark. Since the WCS benchmark was first established in 2005, the differential between WTI and WCS has averaged about US$18/bbl. The differential is a

103 permanent characteristic for WCS, which is a result of physical qualities and transportation costs that can also fluctuate with supply and demand fundamentals. In alternative scenarios, the differential can also be affected by policy decisions.

To forecast oil prices for the model in this report, WTI futures prices up to 2023 are sourced from the Chicago Mercantile Exchange (CME) with July 2019 data. Beyond 2023, prices are forecast to increase annually by an assumed rate of inflation. Price discounts are then applied to determine an implied WCS, which can change depending on policies selected and supporting assumptions. Any US dollar values have been converted to Canadian dollars for final results. It is possible for the WCS discount to vary with benchmarks in other jurisdictions, such as Asia; however, this analysis was not conducted in this report due to insufficient marketing information.

Although the effects of renewable fuel blending standards and consumer carbon prices on fuel are beyond the scope of this modelling exercise, it is important to consider the carbon emissions subject to industrial regulations. Relying on Environment and Climate Change

Canada’s National Inventory Report for greenhouse gas emissions, refining operations in

Alberta produced a total of 5.4 million tonnes of carbon dioxide equivalent (CO2e) in 2017, which was the most recent year data was available (Canada, 2019b). Converting this output to a daily rate suggests that about 14,800 tonnes of CO2e is produced each day. Relative to the

533,000 bbl/d in refining capacity, this would equate to a ratio of about 0.03 tonnes of CO2e per barrel of capacity.

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A hypothetical refinery with 100,000 bbl/d in capacity would therefore produce about 1.1 million tonnes of CO2e per year. Relying on Alberta’s proposed Technology Innovation and

Emissions Reduction (TIER) system, facilities that exceed the 100,000 tonnes per year emissions threshold can pay Cdn$20/tonne as one of the compliance options (Alberta, 2019a). Combining these emissions and costs, a 100,000 bbl/d refinery could pay Cdn$20 million per year in carbon costs, or about 50 cents per barrel processed. This number could potentially be higher due to the energy intensity for heavy oil processing relative to conventional refining.

The simple tax structure applied in the refinery modelling only considers provincial and federal corporate income tax rates applied to positive net earnings. Under the Job Creation Tax Cut Act,

Alberta’s corporate income tax rate will decrease from the current rate of 11 per cent to 8 per cent in January 2022. The tax rate was reduced from 12 per cent in July 2019 and will incrementally decrease by 1 per cent each year until it reaches its target of 8 per cent (Alberta,

2019b). By the time any refinery projects are planned to be operational in Alberta, it is expected they will start past 2022 and will therefore be subject to the 8 per cent rate. Similarly, the federal tax rate is expected to remain at the current 15 per cent over the life of the project.

4.1.2 Benefits Private benefits for a refinery take the form of revenues and profits, which are typically derived from the finished products they produced. The refineries in this model are assumed to produce only gasoline and diesel, with other fuel products excluded to simplify the analysis (e.g., jet fuel, gas oil, bunker fuel, petroleum coke, asphalt, etc.). Under the base scenario, the refinery is assumed to produce a ratio of 60:40 for gasoline to diesel to approximate the 3:2:1 crack spread. To remain consistent with the oil price forecast methodology above, prices for refined

105 products are also based on CME futures strips and converted to Canadian dollars. Due to limited publicly available prices, Reformulated Blendstock for Oxygenate Blending (RBOB) futures are used to represent gasoline wholesale prices, with Ultra Low Sulphur Diesel (ULSD) futures used for diesel. Recent projects, including the Sturgeon refinery, have realized additional revenue streams from carbon capture technologies to market CO2 for other purposes, such as enhanced oil recovery. Due to the limited availability of information for this process and the corresponding infrastructure requirements, the refineries in this analysis exclude carbon capture equipment.

Although provincial and federal taxes are a cost to the refinery owner, tax revenues are also a benefit to the jurisdiction collecting them. Corporate income tax revenues can be applied towards social programs, including health, education, and infrastructure. Since the acquisition scenario is assumed to occur outside of Alberta, the tax and economic impacts are excluded from this analysis. The CBA model provides a private cost calculation for the net present value of each tax stream, including the carbon tax from the industrial emitter. While the TIER fund is intended to recycle revenues into innovation and emissions reduction efforts, this is still viewed as a revenue generator worth tracking. A summary of the net present value of the tax revenues collected over the life of the projects can be found below (Table 9).

Table 9: Net Present Values of Tax Revenues

Refinery Provincial Tax Federal Tax Carbon Cost Under TIER Type (Cdn$ billions) (Cdn$ billions) (Cdn$ billions) New $0.82 $1.54 $0.20 Refinery Expansion $0.39 $0.73 $0.01

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4.1.3 Scenarios Under the base case scenario, the CBA model tests the private viability of each type of refining

project with the information available from proposals taken at face value (Table 8). This

assumes that all projects receive all necessary regulatory approvals and will complete

construction within five years to commence operations by 2025. This scenario would suggest

that there are no cost overruns and will have stable operating costs and a regular maintenance

schedule. Under these optimistic conditions, the hypothetical new refinery delivers a net loss of

Cdn$2.12 billion, while the expansion and acquisition refineries deliver positive net present

values (NPV) of Cdn$1.75 billion and Cdn$2.75 billion, respectively (Table 10).

Table 10: Base & Alternative Scenario Net Present Values

Scenario Changes New Refinery Expansion Acquisition (Billion Cdn$) (Billion Cdn$) (Billion Cdn$) Base N/A -$2.12 $1.75 $2.75 Capital Low +50% -$7.12 $0.75 $2.25 Cost High +100% -$12.12 -$0.25 $1.75 Inflation IMO WTI-WCS Differential +US$16/bbl Standards $5.09 $5.35 $6.35 Diesel Wholesale Uplift +10% Refining New Refinery Titan Capital Cost - Cdn$21 billion $5.80 N/A N/A Capacity - 300,000 bbl/d Discount Low 3% $2.90 $4.10 $5.10 Rate High 10% -$3.30 $1.19 $2.19

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The CBA portion of the model was also designed to test selected scenarios, which combine varying changes to input factors to estimate effects on the viability of the project. A select number of factors were adjusted to identify the effects of certain assumptions under different scenarios compared to the base case. Four alternative scenarios tested include:

 Capital Cost Inflation – in contrast to the cost information considered in the base case, capital costs will likely overrun in reality. Relative to the status quo of no cost inflation, project economics are reevaluated with 50 per cent and 100 per cent cost inflations.  IMO Standards – the IMO standards have a likelihood of depressing high sulphur oils for feedstocks and putting upwards pressure on diesel prices, reflecting demand for low sulphur shipping fuels. The key effects of this scenario are an increased discount for WCS as a feedstock and a 10 per cent uplift in diesel prices.  Refining Titan – a new refinery similar in cost and scale to the ones proposed for Kitimat are tested, which has a capacity of 300,000 bbl/d and a capital cost of Cdn$21 billion.  Discount Rate – the discount rate reflects the time-preference of money, which means that a higher rate would suggest that a dollar today is worth more than one tomorrow. As discussed in the Treasury Board Secretariat’s Cost-Benefit Analysis Guide, the differences in discount rates selected are rationalized as follows (Canada, 2007): o Consistent with the recommendations of Canada’s Treasury Board, the base case uses an 8 per cent discount rate; o The higher discount rate of 10 per cent reflects a private-sector’s weighted average cost of capital (WACC), which entails the opportunity cost of capital for a foregone investment, including equity and debt; and, o The Treasury Board also notes that there are other factors than the economic opportunity cost of funds when considering the discount rate, where consumer consumption is involved and there are no or minimal resources involving opportunity costs – this has led to a social discount rate of 3 per cent, which can also represent the lower cost of capital achieved by a government partnership.

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From results modelled from the alternative scenarios that use nominal figures and discount rates, new refineries are especially challenged by cost overruns due to inflation; expansion and acquisition projects would appear to still be mostly viable across all scenarios. Widened price differentials between WTI and WCS under the scenario where the IMO standards depress bitumen benchmarks and elevate diesel prices would make all refineries more attractive, essentially lowering feedstock costs and increasing revenues. Despite a higher capital cost, the

Refining Titan scenario produces a net positive value by capturing the high capacity efficiencies.

Compared to a higher cost of capital for a private company, a lower discount rate can make an unviable project positive and can occur when receiving support from a government.

Opportunity costs reflect the difference between a foregone and chosen option. In the case of this report, the opportunity cost of interest is the value of raw resources shipped to market against domestic refining options. As shown in Figure 37, the net values of new and expanded refineries in Alberta are compared from the base case scenario assumptions. For each refinery type, raw resource netback reflects the discounted value of bitumen marketed in its raw form, less transportation costs. The net present values of the refineries, which were calculated in the preceding sections, are then deducted from the raw resource netback to derive the net opportunity cost. The results from this analysis show that there was a net opportunity cost of

Cdn$2.12 billion dollars for a new refinery and Cdn$1.75 billion net benefit for an expansion project. Based on total throughput capacities of 985.5 million barrels for new refineries and

492.8 million for an expansion over 30 years, this translates to a net cost of Cdn$2.15 and net benefit of Cdn$3.50 per barrel, respectively. These values would change under the different scenarios, including feedstock valuations and transportation cost assumptions.

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Figure 37: Opportunity Cost of Raw Production & Refinery Options in Alberta

4.1.4 Monte Carlo Simulation While the CBA approach provides a deterministic evaluation of project economics, this can be further enhanced by a Monte Carlo simulation. The Monte Carlo method enables a probabilistic approach to account for risks and uncertainties. The process involves applying probability distributions around input factors, such as the costs and revenues listed above. Using @RISK software, the model runs several thousand iterations (10,000 runs for this research), which each have different combinations of all the input variables. For the purposes of this report, the

Monte Carlo simulation was used to evaluate the simultaneous effects of all dynamic inputs and to identify the likelihood of a project generating a net positive economic value. Similar to the basic CBA, the end result reports a net present value and a distribution of all outputs determined from the simulations. From these simulations, the Monte Carlo analysis produces a sensitivity analysis based on the input factors that were most receptive to changes.

Monte Carlo simulations reported for the NPV and sensitivity analyses can be found in

Appendix A. The simulations apply a range of values for input assumptions, which are held constant throughout the life of the projects. Regardless of which project is proposed, all refinery projects are most sensitive to the WTI-WCS price differential, where a wider

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differential makes a refining project more attractive. Capital costs and corresponding inflation

have the second highest effects on the NPVs for new refinery proposals, followed by the

discount rate, which are both positively correlated with the cost of capital. Both expansions and

acquisitions are also sensitive to discount rates as well as processing costs that could adversely

impact profitability with increases.

Based on the sensitivity analyses, policymakers can optimize incentives if they are warranted.

Supports can be tailored for certain types of projects able to deliver a positive NPV and at a

lower risk. Regardless of which scenario was chosen, a new refinery has a very low chance (less

than 5 per cent) of being successful (non-negative net present value) in Alberta and would

require significant resources and supports to become viable. Expansions could reasonably

benefit from government intervention with less risk, while acquisitions would be most

rewarding to the private sector and would therefore not warrant direct government assistance

(Table 11). Based on the Monte Carlo simulations for commercial viability, expansion projects

have about a 65 per cent chance of success, while acquisitions are nearly 95 per cent.

Table 11: Net Present Values & Top Sensitivities of Monte Carlo Simulations

Metric New Refinery Expansion Acquisition

Maximum NPV $16.47 $1.69 $13.50 (Cdn$ billion) Mean NPV -$7.63 $0.72 $2.31 (Cdn$ billion) Minimum NPV -$21.19 -$6.89 -$3.80 (Cdn$ billion) Probability of 4.1% 64.4% 94.7% Non-Negative NPV WTI/WCS Differential WTI/WCS Differential WTI/WCS Differential Most Sensitive Inputs Capital Cost Inflation Discount Rate Discount Rate Discount Rate Processing Cost Processing Cost

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4.2 Economic Impact Assessment An economic impact assessment (EconIA) was derived using the publicly available provincial economic multipliers maintained by Alberta Treasury Board and Finance. The most recent year available is for 2013, which is one of the inherent flaws of EconIAs. Economic multipliers are derived by an input-output model that captures the interdependence of industries and reflects the flow of goods and services through the economy (Alberta, 2017). The EconIA model is used to show how changes in an industry can impact the economy in terms of GDP, labor income, and employment. There is the option to select multipliers for either an open or a closed model.

An open model captures direct and indirect impacts, while the closed model also captures induced effects which leads to a higher multiplier value. For this model, only an open model was considered.

The economic multipliers are combined with the capital and operating expenses of the projects to derive economic benefits generated from the respective construction and operation phases

(Table 12). Capital costs are multiplied by the corresponding multipliers for “oil and gas engineering construction.” Similarly, processing and maintenance costs are multiplied by

“petroleum and coal product manufacturing.” The outputs of the EconIAs for the base case refineries are presented below (Table 13). Although an acquisition would likely have some positive effects on Alberta’s upstream and midstream energy sectors, the refinery was already constructed and incremental economic benefits would largely go towards whichever jurisdiction it was in; similar to the issue of taxation, the acquisition simulation was exempt from this part of the analysis.

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Table 12: Alberta Economic Multipliers by Industrial Sector, 2013

Industry Code Industry Title GDP Labor Income Employment BS23C20 Oil and gas engineering construction 0.671 0.427 0.049 BS32400 Petroleum and coal product manufacturing 0.781 0.106 0.012 Source: (Alberta, 2017)

Table 13: Estimated Economic Impacts for Alberta

Gross Domestic Labor Income Jobs Refinery Project Product Type Phase (Cdn$ billion 2013 (Cdn$ billion 2013 (Fulltime Prices) Prices) Equivalent) New Construction $6.71 $4.27 4,900 Refinery Operation $7.92 $1.07 1,200 Construction $1.34 $0.85 980 Expansion Operation $4.48 $0.61 700

4.3 Limitations Working with the information available, the economic modelling for this report attempted to

identify how changes for inputs could impact different types of refineries. While many

considerations were made to capture how the economics of projects can be shaped, there are

several factors that could benefit from additional resources beyond the scope of this research.

These topics primarily include tax reforms, labor allocation, and liability management.

In contrast to lower corporate income taxes, capital cost allowances and other exemptions

could potentially be applied to these projects. However, there was insufficient information to

adequately factor these considerations into the model. A capital cost allowance grants an

annual deduction for depreciable property allocated to a particular class of assets, which

enables companies to recover their investments faster. Interestingly, the federal government

introduced an accelerated capital cost allowance in the 1990s to encourage major energy

projects and refining during a period of low energy prices; this program existed until 2008. The

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Alberta Industrial Heartland Association has advocated to permanently extend the accelerated capital cost allowance, which would introduce a 100 per cent cost allowance for the entire cost of a petrochemical facility over a minimum of 10 years (Alberta Industrial Heartland

Association, 2019).

The capital costs of a project were assumed to be spent in one lump before the startup of the project. Understanding the outlay of capital and construction plans would be useful, especially if there are multiple ongoing projects that are competing for labor. This could have inflationary effects on capital costs, as is what happened with the Sturgeon refinery. Similarly, the exact spread of labor by trades could better inform the expected economic impacts, which are modelled by industrial sectors. Although the Alberta economic multipliers provided insight into how effects could be realized within the province, Statistics Canada maintains a higher-quality input-output model that is capable of depicting local, regional, and national effects from a project. However, results from Statistics Canada were not available without a significant fee for each modelling exercise.

The refineries in this report were assumed to have useful lives between 20 and 40 years. The value of these assets at the end of their lives were not considered, as owners would have different options of what to do with the refineries at that time. While the refineries could extend their lives or be sold off at some undeterminable price, this research does not speculate whether the asset would be retired or a new owner would take possession. Although there are abandonment and reclamation obligations associated for a refinery, it is assumed in this report that any salvage value would ultimately offset such costs.

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5.0 Conclusions

Refining opportunities come at a significant cost and have complex operations. To understand the opportunities and risks of such ventures, revenues and costs were examined to identify whether economic opportunities even exist in Alberta for additional refining capacity. By decomposing fuel prices in Western Canada, it was beneficial to identify the common elements of fuel prices: crude oil, taxes, retail margins, and especially refinery margins. Focusing on refinery margins found that escalations over recent years corresponded to operating and compliance cost increases, rather than perceived market power and other market failures. By investigating policy considerations and integrating project economics, new refining projects were found to face the lowest likelihood of being economically successful without intervention.

Information sourced and modelled from real world proposals suggests expansions of existing refineries would be the most reasonable to advance. Further, the model also identified sensitivities that could make marginal expansion projects viable with tailored supports.

Although it may be tempting for governments to intervene in refining projects, it is important to consider the tradeoffs and policy implications as a result of supporting such projects.

Subsidization of any new project can create economic benefits that provide jobs and funding for social programs, such as education and health care. On an economic basis, caution should be taken with supporting projects with public resources and applying uniform subsidies, as each business case would need to be evaluated and can vary from project to project. If a private project is unable to secure funding on its own, the market would suggest that the project may be too high risk. Although some of these risks can be mitigated with government involvement,

115 including feedstock supplies and cost of service agreements that can lower the cost of capital, these interventions carry an opportunity cost and face inherent risks.

There are several areas across the Western Canadian petroleum supply chain that can benefit from regulatory efficiencies and encouraging private sector investment. Governments should first consider several factors before making policy changes to promote refinery projects. These considerations include justifying intervention, clarifying existing rules, understanding sources of supply, optimizing existing transportation infrastructure, and appreciating how demand and policies extraneous to refining can shape the market. In the sections below, key research findings and modelling results are summarized, recommendations provided, and items for further investigation considered.

5.1 Findings Beyond directing public resources to promote a project, a backing by the government can deliver dividends in many different forms. A partnership with a high-credit rating, such as the

Alberta government, can create competitive advantages that lower the private cost of capital and contribute to making projects more likely to be successful. These benefits can be in the form of favorable interest rates, long-term supply of feedstocks, or developing international trade partnerships. However, the government needs to consider potential risks and implications to its own reputation and credit rating if companies are unable to generate profits or default on their obligations. While it is a challenge for competitive projects to disclose all details on public record, governments need to weigh the costs and benefits before getting involved in such a partnership, especially if it is difficult to walk away from a multibillion dollar sunk cost.

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From the economic analysis provided in this report, new refineries appear to face the greatest challenges and are especially sensitive to discounts for Alberta bitumen and capital cost overruns. Programs related to lowering feedstock and capital costs could support new refineries most effectively, which was the intent with incentives provided to the Sturgeon refinery. For that project, the government signed long-term contracts to provide bitumen supplies and associated processing fees, which enabled to operator to lower its cost of capital used to finance the project. Unlike the projects modelled in this report, the Sturgeon refinery also has additional and unconventional revenue streams that bolster its economic viability, including carbon captured, stored, and marketed for enhanced oil recovery. Some projects in

BC purport to have natural cost advantages, especially when it comes to sourcing construction materials from international suppliers at lower costs. However, whether in the Kitimat region or a boom in Alberta’s oil sands, there is a significant risk for multiple competing projects to inflate labor costs, which ultimately translate to higher capital costs.

Expansions of existing facilities have a lower risk of capital cost overruns, but are still subjected to price differentials, costs of capital, and managing operating costs to ensure projects remain viable. These projects can also incrementally meet market conditions in Western Canada over new refineries due to their modest capacities. An excess of refined production that cannot be absorbed by the Western Canadian market will either need to be exported abroad or will adversely affect the supply and demand balance. Similar to the buildup of raw bitumen waiting to leave Alberta lacking sufficient takeaway capacity, an abundance of refined products with nowhere to go will depreciate wholesale fuel prices.

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While there is a significant economic upside potential to purchase an existing refinery for bitumen processing, complex refinery acquisitions are rare for Alberta producers looking to integrate downstream operations. Although acquisition projects share similarities with expansion projects, government intervention is unlikely to be warranted for these types of projects. One of the key arguments for supporting expanded refining capacity involves creating economic benefits for Albertans. If an upstream producer invests in another jurisdiction, benefits are not directly realized by Alberta, other than finding another source of demand for bitumen. Further, unless a major firm absorbs other refineries in Alberta to consolidate market shares (e.g., Suncor absorbing Shell or Husky), there is unlikely to be any competition issues that would need to be resolved through economic regulation. If a company exporting from

Alberta is able to partially or fully upgrade its oil in advance, both the province and company could benefit by utilizing pipeline capacities more efficiently. Therefore, a royalty credit could be investigated to help offset the additional costs of processing and exporting, which reflects the benefits of reduced diluent demand and pipeline capacity occupied with denser oil.

5.2 Recommendations Alberta should first explore solutions to regulatory challenges that have limited takeaway capacity for the province’s bitumen resources. Improved market access would alleviate low oil prices that have resulted from a transportation-constrained environment, where production exceeds takeaway capacity. Despite having an abundance of oil in Alberta, the province needs to balance the creation of near-term economic benefits against maximizing the value of its resources over the long run. Expanded refining capacity in Alberta can alleviate current challenges, but policy solutions also need to address lasting fundamental problems. With an

118 abundance of dense bitumen in Alberta, refining allows for more of the province’s resources to be exported using existing infrastructure, but comes at a significant cost. By making a lighter product in Alberta, producers will also be able to ship more volumes on existing systems.

Although it is likely more pipeline infrastructure will one day be developed, persistent legal and regulatory delays in Canada and the US have increased costs and made a number of transportation projects unattractive in the present.

Alberta should require the use of a consistent cost-benefit analysis framework for projects seeking government support and demonstrate a net value of the investment. Broadly defined regulatory requirements result in the submission of gross economic impacts, which are derived from input-output models and economic impact assessments. A standardized cost-benefit framework would be better suited to demonstrate the net benefits of a project seeking public support. Proponents applying for projects should demonstrate a multitude of risks and sensitivities to their proposals, such as labor constraints, project operating lives, capital and operating costs, feedstock costs, output revenues, market access, and closure liabilities. It would be worthwhile for proponents to provide robust scenario planning on how policies can affect their operations over the long-term for markets they plan to supply, including considering fuel standards, carbon policies, and energy transitions.

Alberta should maximize the value of its resources and limit its risk exposure by understanding the tradeoffs and consequences of intervention. With the nature of long-lasting assets in response to short-term phenomena, projects will respond differently to various supports. This makes it critical to understanding and communicating the costs, benefits, and challenges of

119 each project. By understanding the limitations and sensitivities of proposals, governments can better coordinate resources to support proposals from the private sector. Before offering financial instruments such as loan guarantees, government agencies can instead offer efficient solutions for unique problems for proposals. These tailored solutions can include streamlining regulatory applications, optimizing the use of existing transportation infrastructure, offering royalty credits and feedstock supplies, and managing regional development to attract capital and pace activities.

Alberta should require full transparency for publicly supported projects. Previous projects supported by the government have had a number of issues in determining their net value to

Albertans due to a lack of requirements for operational reporting. Although certain details and proprietary information can remain in confidence with the government, regular reporting should demonstrate the performance of projects, much like a publicly traded company is required to do for investors. A higher degree of transparency can more clearly show what kind of return the province is getting on its investment and assure the province that it is making the most of its resources. Conversely, this would also force operators to explain challenges and successes, which the government could respond to and hold the proponent accountable.

5.3 Further Considerations While the primary focus of this report was on whether or not the Alberta government should support expanded refining, several other energy-related issues could be further explored. The research gathered for this report covered a wide spectrum of content related to refining in

Western Canada and found factors that both encouraged and deterred projects. There were many fascinating topics discovered beyond the scope of this research, which this report offers a

120 starting point for further investigations into these other energy-related challenges. Topics that may be worth further consideration include BC’s ongoing fuel inquiry and competition issues, optimal resource extraction and royalty recovery under transportation constraints in Alberta, and regulatory delay costs as a result of new legislation for environmental assessments.

6.0 Appendix A – Monte Carlo Simulation Results This section provides Monte Carlo simulation results for the different types of projects tested in the Project Economics section. Figures provide information on the spectrum of the net present values (NPVs) of projects and the sensitivities of inputs. The first figures for each type of refinery scenario show a distribution of outputs representing the range of NPVs based on a

10,000 iteration simulation, which tested varying input assumptions. Descriptive statistics about the distributions are provided on the side, which include minimum, mean, and maximum

NPVs. The second set of figures reflect the sensitivity analyses and show the top six factors that have the greatest effects on NPVs. These summaries were used to guide which projects would potentially be most viable and understand where policies can have the most efficient effect.

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6.1 New Refinery Figure 38: New Refinery NPV Monte Carlo Simulation Results

Figure 39: New Refinery NPV Sensitivity Analysis

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6.2 Expansion Figure 40: Expansion NPV Monte Carlo Simulation Results

Figure 41: Existing NPV Sensitivity Analysis

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6.3 Acquisition Figure 42: Acquisition NPV Monte Carlo Simulation Results

Figure 43: Acquisition NPV Sensitivity Analysis

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