APRJ - 699

Applied Project

A Strategic Analysis of

Petroleum Refining Infrastructure in Canada

Wayne Dosman

Coach: Dr. Oliver Mack

Word Count: 19,093

Date Due: March 31, 2013 A Strategic Analysis of Petroleum Refining Infrastructure In Canada

Abstract

Canada continues to be economically dependent on refined petroleum products even as the world moves to constrain their use of fossil fuels. Canada has a long history of producing more crude oil than we consume however little attention is given to the strategic importance of the integrated supply network that gathers, transports, refines and distributes the finished goods. The refining industry in Canada has gone through a 30 year reduction in the number refineries in production and recently various market anomies have become more pronounced.

This study considers the research question whether this consolidated infrastructure will be able to meet the future needs of Canadians? I use a qualitative case study format and publicly available secondary data. The data is analyzed applying three approaches to strategic management, an industry analysis to captured the industry’s structural components, a competitive forces analysis that identifies the industry’s dominate forces and a system dynamics analysis to explore how the system responds to two situations that occur in the industry.

The industry analysis identifies major elements of the petroleum industry’s structure and relates these elements to a review of the Canadian industry’s current structure. We identify four major elements, crude oil slate, mid-stream infrastructure, refinery configuration and capacity, and product slate demand as elements that structurally shape the industry. We then review the composition of these elements in Canada’s refining infrastructure. This review revealed Canada’s refining infrastructure is organized into four regional supply orbits, each having defining features. These features create substantially different constraints and requirements for each orbit. Production capacity shortfalls, product production/demand gaps and significant mid-stream constraints were identified in two supply orbits.

The competitive forces analysis reviewed the competitive forces surrounding the downstream refineries which captured crude slate producers as suppliers and refined product users as buyers. This analysis revealed that the industry’s competitive structure consists of low buyer and supplier power while refiners possess some bargaining power under specific mid-stream constraint circumstances. Competitor rivalry is moderate as although an oligopoly structure exists that is conducive for intense price competition, the lack of excess capacity and threat of imports limit refiners pricing power. The threat of new entrants is high as although incumbents enjoy various barriers to entry, these barriers are mitigated by existing capacity and product shortfalls, and the diseconomies of scale that exist in certain markets. The threat of substitutes was

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada considered moderate as although some substitutes have successfully displaced refined products in the electricity generation market and to certain extent the home heating market, access to infrastructure and price performance trade-offs currently leave them less attractive in the transportation industry. Substitutes are a long run threat however and could motivate companies to hedge their long run exposure by limiting capacity acquisitions to meet current needs.

Systems dynamics principals were used to schematically represent the stocks and flows we identified in the industry and competitive analyses. The industry schematic was then used to quantitatively examine how the system would response to two situations that the industry confronts, an unanticipated refinery shut down and whether to acquire additional capacity. In the refinery shut down situation we found that in supply orbit with mid-stream constraints, adequate inventory levels were critical to maintaining the reliability of supply. In orbits with access to deep water ports or waterways, inventory levels were not as critical as imports could replace production given adequate transportation time horizons. In the capacity addition decision we found that confidence in the long run expected return on capital is the crucial determinant in deciding to acquire capacity. Demand can change much faster than the extended process of adding capacity and as such industry often overprovides capacity. Adding excessive capacity in periods of reduced demand can trigger price wars, reducing industry profitability and possibly leading to periods of closing marginally profitable refineries. As minor capacity demand shortfalls can be covered by imports, over capacity situations can be more harmful to industry profitability than under capacity situations.

The study concludes that the Canadian Refining Infrastructure can meet Canada’s future needs however consideration should be given to three recommendations. Midstream options should be added to the Western and Ontario supply orbits to reduce dependence on existing midstream pipelines. A strategic petroleum reserve of refined petroleum products should be maintained in supply orbits with constrained midstream options. Capacity should be added in the Ontario, Western and possibly Quebec orbits to meet demand expectations however consideration should be given to strategically located small scale refineries.

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada

Table of Contents

ABSTRACT ...... 1 TABLE OF FIGURES ...... 4 1.0 INTRODUCTION ...... 5

1.1 SIGNIFICANCE OF THE CANADIAN REFINING INDUSTRY ...... 5 1.2 RESEARCH QUESTIONS ...... 7 1.3 RESEARCH DESIGN AND APPROACH ...... 7 1.4 SCOPE AND ASSUMPTIONS ...... 8 2.0 REVIEW OF RELATED THEORY ...... 9

2.1 INDUSTRY AND COMPETITIVE ANALYSIS ...... 10 2.2 SYSTEM DYNAMICS ...... 12 3.0 ANALYSIS ...... 14

3.1 - INDUSTRY ANALYSIS ...... 14 3.2 - COMPETITIVE FORCES ANALYSIS ...... 53 3.3 - SYSTEM DYNAMICS ANALYSIS ...... 61 4.0 RECOMMENDATIONS AND CONCLUSIONS ...... 72 REFERENCES ...... 77 APPENDIX 1 – ACRONYMS, UNITS AND CONVERSION FACTORS ...... 84

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada

Table of Figures FIGURE 1 - 2009 TOTAL FINAL CONSUMPTION FOR CANADA ...... 5 FIGURE 2 - REFINING INFRASTRUCTURE SUPPLY NETWORK ...... 8 FIGURE 3 - DETERMINANTS OF COMPETITIVE FORCES ...... 11 FIGURE 4 - PROJECTION OF CANADIAN CRUDE OIL PRODUCTION ...... 16 FIGURE 5 - PRODUCT YIELDS OF REFINERY CONFIGURATIONS USING HEAVY OIL FEEDSTOCK ...... 19 FIGURE 6 - EXPECTED YIELD OF A CRACKING REFINERY ...... 20 FIGURE 7 - CANADIAN DOMESTIC REFINED PRODUCT SALES (2011) ...... 20 FIGURE 8 - CANADIAN DOMESTIC SALES OF RPP 2002 - 2011 ...... 21 FIGURE 9 - CANADIAN PRODUCT DEMAND ...... 22 FIGURE 10 - MAJOR ELEMENTS OF REFINING SUPPLY NETWORK ...... 22 FIGURE 11 - REFINERY CAPACITY VERSES NUMBER OF REFINERIES ...... 23 FIGURE 12 - OWNERSHIP OF CANADIAN REFINERY CAPACITY ...... 24 FIGURE 13 - THROUGHPUT CAPACITY OF CANADIAN REFINERIES ...... 25 FIGURE 14 - SUMMARY OF CANADIAN REFINED PRODUCTS PRODUCTION IN 2011 ...... 26 FIGURE 15 - CANADIAN REFINERY UTILIZATION ...... 27 FIGURE 16 - 2011 REGIONAL CAPACITY VERSES DEMAND ...... 28 FIGURE 17 - CANADIAN SUPPLY ORBITS ...... 29 FIGURE 18 - SUMMARY OF MARITIME REFINED PRODUCTS PRODUCTION IN 2011 (BPD)...... 30 FIGURE 19- MARITIME REFINERY CONFIGURATIONS CAPACITY ...... 32 FIGURE 20 - PRODUCT DEMAND MIX CANADA VERSE MARITIME ...... 33 FIGURE 21 - MARITIME PRODUCT DEMAND ...... 33 FIGURE 22 - SUMMARY OF QUEBEC ORBITS REFINED PRODUCTS PRODUCTION IN 2011 (BPD) ...... 35 FIGURE 23 – QUEBEC ORBITS CAPACITY ...... 37 FIGURE 24 - CANADA VERSES QUEBEC'S PRODUCT DEMAND MIX ...... 37 FIGURE 25 - QUEBEC PRODUCT DEMAND GROWTH ...... 38 FIGURE 26 - QUEBEC'S PRODUCT BALANCE...... 39 FIGURE 27 – SUMMARY OF ONTARIO'S REFINED PRODUCT PRODUCTION IN 2011 (BPD) ...... 40 FIGURE 28 - ONTARIO ORBIT'S CAPACITY ...... 42 FIGURE 29 - CANADA VERSES ONTARIO'S PRODUCT DEMAND MIX ...... 42 FIGURE 30 - ONTARIO'S PRODUCT SUPPLY AND DEMAND BALANCE ...... 43 FIGURE 31 - ONTARIO'S PRODUCT DEMAND GROWTH ...... 44 FIGURE 32 - WESTERN ORBIT'S REFINED PRODUCT PRODUCTION IN 2011 (BPD) ...... 45 FIGURE 33 - WESTERN ORBIT CAPACITY ...... 47 FIGURE 34 - CRUDE UPGRADERS CAPACITY ...... 48 FIGURE 35 - CANADA VERSES WESTERN'S PRODUCT DEMAND MIX ...... 49 FIGURE 36 - WESTERN'S PRODUCT DEMAND GROWTH ...... 50 FIGURE 37 - WESTERN'S PRODUCT BALANCE ...... 50 FIGURE 38 - SALIENT FEATURES OF SUPPLY ORBITS ...... 51 FIGURE 39 - COMPETITIVE FORCES IN THE REFINING INDUSTRY ...... 60 FIGURE 40 - STOCKS AND FLOW SCHEMATIC ...... 61 FIGURE 41 - REFINERY SHUTDOWN CAUSAL MAP ...... 63 FIGURE 42 - ONTARIO'S ORBIT SHUTDOWN RESPONSE ...... 65 FIGURE 43 - INVENTORY RESPONSE TO SHUTDOWN ...... 65 FIGURE 44 - CAPACITY ACQUISITION CAUSAL MAP ...... 67 FIGURE 45 - IMPERIAL OILS DIVISIONAL RETURN ON CAPITAL EMPLOYED ...... 68

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada

1.0 Introduction

1.1 Significance of the Canadian Refining Industry

In spite of the growing negative sentiment towards products from crude oil being a major source of greenhouse gas emissions, global energy demand continues to grow each year and refined petroleum products continues to be the dominate source that supplies the growing demand for energy.

British Petroleum’s’ (BP) Statistical Review of World Energy estimates global energy demand grew 2.5% in 2011 which is also approximately equal to the 10 year average growth in global energy demand (BP, 2012, p. 2). Within the mix of energy sources that fuel this demand, oil continues to be the dominate source of energy. Even though oil’s 2011 global growth of 600 thousand barrels per day (0.7% growth) was less than the growth in total energy demand, oil is still the largest energy source in the mix providing 41.3% of the global total final consumption of energy in 2009 (IEA, 2012, p. 28).

Canada likewise relies heavily on oil products to provide our energy needs; in 2009 the International Energy Agency (IEA) estimated that 44% of Canada’s total final energy consumption was derived from oil products (IEA, 2009).

Figure 1 - 2009 Total Final Consumption for Canada

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada

Canada’s dependence oil products’ is actually growing at a faster rate than our demand for energy. Over the past ten years, our primary energy consumption increased 8.9% (Statistics Canada, 2012b) at the same time when oil consumption increased 12.1% (Statistics Canada, 2012, 2003).

Barring a dramatic increase to the cost of GHG emissions, the worlds’ heavy reliance on refined petroleum products (RPP) is expected to continue well into the future. Changes in the global energy mix are slow to change due to the magnitude of the infrastructure investments currently in place and the higher costs of substitute energy sources.

Canada has a long history of producing more crude oil than it needs’, BP estimated that in 2011 Canada produced more than 1.2 million barrels of oil per day (bpd) more than it consumed (BP, 2012a). However, crude oil is of little value itself as it is only after refining that crude oil in vast quantities that it has an economic use. The use of RPP permeates every market of the Canadian economy so much that any small disruption has an immediate and negative cascading effect throughout the economy.

Notwithstanding the economic dependence that the Canadian economy has on RPP, the industry itself makes a significant value added contribution to domestic production while providing high paying jobs for the Canadian economy. A 2011 Conference Board of Canada report estimated that a 10% loss in domestic refining capacity would reduce GDP by four billion dollars and 38,300 person-years of employment over a five year period (Conference Board of Canada, 2011, p.31). Given Canada’s economic dependence on RPP, the production of a secure reliable supply of RPP into the Canadian marketplace should be managed as a critical strategic resource.

The refining industry in Canada has gone through a 30 year period of reducing the number of producing refineries even though demand constantly grew. Demand has been balanced by building larger refineries in fewer locations and increasing throughput utilization rates. This strategy has resulted in an industry which has historically been reliable but is highly concentrated in specific locations across Canada. Over the past ten years, various fundamental changes have emerged in the Petroleum Industry which has changed the supply and demand dynamics of the North American market. These changes seem to be manifesting in various market anomalies not previously experienced:

- Gasoline shortages are becoming more regular occurrences even in oil rich Western Canada (CBC News, July 28, 2010).

- Despite crude oil being structured as a financial traded global commodity, large price differentials are developing between

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada

benchmark oil prices such as West Texas Intermediate (WTI) and Brent Oil (Sharples, 2012).

- Although Canada produces 1.2 million barrels per day more than they consume, 40% of the crude oil refined in Canada is imported. Moreover, imported crude oil is purchased at Brent Oil prices while the crude that Canada exports is sold at the discounted WTI price or at the further discounted heavy oil prices like Western Canadian Select (CAPP, 2012a).

At this point in time, it is unclear whether these events are isolated occurrences or harbingers of greater events yet to come.

1.2 Research Questions

Bearing in mind economic significance of RPP relative to the changes in concentration of production infrastructure and the recent appearance of market anomalies this research paper will explore the following primary question:

Will Canada’s existing Petroleum Refinery Infrastructure meet the future needs of Canadians?

In pursuing this question, several sub questions and hypotheses arise:

Sub- Question 1) Does Canada’s existing refining infrastructures provide secure, reliable and efficient production or do these legacy assets present an economic risk?

Hypothesis 1) Refining infrastructure in Canada is a Legacy Cost.

Sub- Question 2) Do large economies of scale refineries provide a more appropriate fit to Canada’s energy needs than strategically placed smaller scale refineries?

Hypothesis 2) Smaller scale modern refineries located close to major centers can provide efficient economies to the existing network with less concentration risk.

1.3 Research Design and Approach

The research design will be a qualitative research case study format using reliable publicly available secondary data (Leedy, 2008, p. 135). The purpose of the research process will be to resolve the research questions by identifying emergent patterns from the data being analyzed using three different approaches to strategic management, those being:

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada

1) An Industry Analysis Approach.

2) A Competitive Forces Approach.

3) A System Dynamics Approach.

In the Industry Analysis, the existing industry structure will be explored using data collected from secondary sources for supply, demand, refinery capacity, ownership and throughput data on the Canadian petroleum refinery industry. This data is available through various governmental, national and international petroleum agencies segregated at the national and provincial levels. All sources used will be accessed through their respective sources websites. The data will be used to identify current supply and demand balances, identify potential constraints and excesses, and identify emergent patterns.

We will then use the information and data from the industry analysis section to analyse the competitive forces that exist in this market and to establish causal relationships that can be used to build a qualitative causal map model of refinery infrastructure.

1.4 Scope and Assumptions

In considering the scope of the Petroleum Refining Infrastructure, we will establish the boundaries of the infrastructure to include the availability of the feedstocks, the delivery systems used to move feedstocks to refineries, refineries, the distribution and marketing networks of RPP, and the quantities demanded of RPP (Briggs, Tolliver and Szmerekovsky, 2012, p.2). Throughout this study we will define this chain as the Petroleum Refining Infrastructure Supply Network (Slack, Chambers & Johnson, 2010, p. 375).

Figure 2 - Refining Infrastructure Supply Network

In establishing the scope boundaries we will make the following assumptions throughout this report:

 Demand for RPP will not be severely disrupted by innovation technologies, public policy or changing societal norms other than trends which currently exist. Page 8

A Strategic Analysis of Petroleum Refining Infrastructure In Canada

 International imports of RPP will not flood global markets with below cost production from overcapacity and Canadian refineries can profitability competitive with imports.

 Crude slates will continue to be available internationally and domestically without any unanticipated long run disruptions.

 Taxation and government policy changes are material to the refining industry but have not been considered within this scope.

In setting this scope and making these assumptions, there are material limitations which could change the current supply and demand determinants:

 Factors external to Canada are important and will impact the supply demand determinants of this industry such as international capacity additions, crude oil macro-political events, disruptive technologies, or application of existing technologies in regions not currently employing them.

 Taxing of externalities may dampen demand or reduce energy intensity resulting in long run demand destruction.

 Innovation could make the price/performance trade-off of substitutes more attractive.

 Crude oil slate changes rapidly altering cost curve and mix of light oil/heavy oil. Upstream activities can alter downstream operations significantly by pushing volumes of newly discovered oil through the supply network.

It is the intention of this study to provide a baseline framework based on current trends and emergent patterns from which such risks and variables external to this study can be explored.

2.0 Review of Related Theory

Strategy is a far reaching topic and the breath of its academic literature is broad. Mintzberg, Ahlstrand, and Lampel identify ten schools of strategy that have evolved. This study will focus on the more traditional school of positioning. The positioning school relies on a more systematic, analytical approach to problem solving (Mintzberg, Ahlstrand, and Lampel, 1998). In that regard, the Industry Analysis will detail the refining

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada industry’s physical structure and supply/demand balances, Porter’s Five Competitive Forces will be used to establish the intensity of the industry’s forces and finally we will use these findings to build a system dynamics model that can be used to qualitatively examine market situations within the industry.

2.1 Industry and Competitive Analysis

The positioning school argues that industry structure should drive strategy as there exists’ certain generic strategic positions in each industry which provide a sustainable competitive advantage. Taking an industry top down perspective, this school developed sets of analytical tools to match the right strategy to context of the industry and its competitors. Included in this school is Porters’ theory on competitive analysis, competitive advantage and the value chain (Mintzberg, Ahlstrand, and Lampel, 1998. pp. - 94–106) which forms the foundation for much of this school.

The concept that industry structure impacts differences in levels of industry profitability is rooted in Industrial Organization Economics and the Theories of Monopoly and Perfect Competition. It has long been observed that industries with a single dominating firm often generate above average profits and profitability between industries vary dramatically. Although the macro-environment that businesses operate in have many important external factors that influence profitability all industries operate in the same macro environment hence understanding what influences profitability in the industry environment is an important first step in strategy formation. The balance between meeting customer demand through the intensity of competition and supplier bargaining power results a particular level of industry profitability. It is the examination of the structure of these relationships that gave rise to the positioning school and Porters theory of competitive forces (Grant, 2008, pp. 66 -71).

It has been argued that an industry’s environment is a minor determinant of a firm profitability and that inter-firm differences are much greater influence than industry profitability. Notwithstanding that effect on profitability by industry may be more diminished than originally thought, industry analysis is still regarded as primary step in understanding competition and in predicting the effect that changes in an industry will have on profitability (Grant, 2008, p. 98).

Porter proposes that it is the interactions of five competitive forces that shape the structure and profitability of any industry. The five forces of competition are Internal Industry Rivalry, Threat of New Entrants, Treat of Substitutes, Bargaining Power of Suppliers and the Bargaining Power of Buyers. Competitive forces arise from the industry’s distinctive economic and technical characteristics and each force has specific

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada determinants which govern that forces influence or power on the industry. We have summarized some of these determinants in the following charts.

Figure 3 - Determinants of Competitive Forces

(Porter, 2008, pp. 80-86).

Porter stresses that it is the interaction of the relative strengths of these forces that shapes industry profitability. Consequently, it is the strongest competitive forces that are most important to strategy formation however these prominent influencers are not always obvious (Porter, 2008, p. 80).

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In understanding the interaction of these forces in an industry, a strategist can identify opportunities or weaknesses in the industry structure to reposition their competitive strategies, distinguish short term aberrations from structural market changes or identify industry-transforming potential (Porter, 2008, pp.88-90).

Porter also cautions that it is important not to mistake industry attributes for competitive forces. He explains that each industry has specific elements which influence the forces but in themselves are not forces. Examples of such industry factors are technology, complementary products, government and growth rate (Porter, 2008, p.86).

It has been argued that Porter’s five force frameworks is too narrow a view of industry grouping (Grant, 2008, p 98). It has also been argued that where substitutes limit profitability complements increase industry profitability and often expands an industries market. Complements are often considered to be a sixth competitive force (Grant, 2008, p 98).

2.2 System Dynamics

System Dynamics (SD) originated in the 1950’s by Jay Forrester in his seminal paper “Industrial Dynamics” (Forrester, 1958). As did Michael Porter, Jay Forrester drew on industrial organization economics and engineering disciplines along with the then recent computing advances to proposed that industrial stock-flow-feedback designs can be used to model business management decisions in complex systems using computer based simulations. He found that such system models explained the unexpected results often seen in complex systems better than the causal linear explanations in use at that time.

System dynamics (SD) is a framework to examine the interaction of decisions with a system structure as it changes over time. SD models look endogenously at a system to establish causal relationships which can be used to understand how the system operates and responds to various changes. Systems can be as large as an industry or an economy or a much smaller grouping such as a firm. Systems are viewed as bounded causally closed systems with continuous quantities flowing in and out (rates), supported by various stocks (inventory or levels) that have feedback loops and circular causal relationships. Exogenous changes are viewed as either causal loops that should be added to the system or as triggers which modify conditions within the system resulting in system adaptation. Models can be computer simulations expressing relationships within the system using coupled, nonlinear, first-order differential

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada equations however they can also be expressed schematically using causal maps to qualitatively capture the interactions between the stocks, flow and causal feedback structure of the system (Richardson, 2009, pp. 856 -860).

SD is particularly useful in identifying elements within a system that will react to a change or in identifying a problem and isolating the interaction of physical and behavioral elements causing the problem. Wolstenholme suggests that successful system thinking is predicated on being able to see the whole system in context of its interconnections to the environment. In that regard, he suggests that the establishment and understanding the boundaries of systems and their linkages to the physical environment is a critical component to understanding complex systems (Wolstenholme, 2003).

John Sterman indicates that in systems time delayed responses often create oscillations in matching production with demand. The resulting overshooting or undershooting of demand can result in instability which explains the cyclical long term expansions and contractions of certain industries (Sterman, 2000, pp. 791 – 800). In his 1999 MIT doctoral thesis, Taylor found that long run capacity cycles in the pulp and paper industry can be explained by capacity acquisition delays that create oscillations in capacity. The pulp and paper industry shares many similar characteristics with the petroleum industry, commodity price variations with growth, long supply chains with physical constraints and capacity is added in large quantities with long capacity acquisition delays. Taylor found that a four year acquisition delay in capacity lead to short run price and utilization oscillations within a 14 year long capacity cycle (Sterman, 2000, pp. 824 -828).

SD has a long history of being applied to the dynamic systems of energy markets dating back to the early 1970’s in the designing of various energy models used by the United States Department of Energy such as COAL1 & 2, FOSSIL 1 & 2, the IDEAS (Integrated Dynamic Energy Analysis Simulation) and the DOE’s current model, the National Energy Model System or NEMS (EIA, 2009; DOE, 1997). All these models were developed based on academic work by scholars such as Roger Naill, John Sterman, George Richardson and Eric Wolstenholme, among others, each of which have a long list of published contributions to SD.

We will use a SD qualitative model to explore the physical structure of the industry and that systems feedback response to specific changes.

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3.0 Analysis

3.1 - Industry Analysis

An understanding of the factors that influences profitability in any industry starts with examining the relationship between what customers demand and the competing interests of industry incumbents, the industry’s suppliers and producers of substitute goods (Grant, 2008, p. 80). The structure of these relationships can be established by examining the industry’s supply and demand trends, by identifying trends that are changing in the industry structure and by reviewing the industry’s existing competitors (Grant, 2008, p. 81). Analyzing these relevant structural components of supply, demand and competition in an industry is typically completed concurrent with a competitive forces analysis however we have separated the industry analysis to capture the physical SD elements of stocks, flows, capacity and delays that exist in the industry.

To bring forward the information necessary for the competitive forces and SD analysis we will first review the major elements of the petroleum industry as they relate to Canadian refining infrastructure and then review the relevant structure of Canadian Industry.

3.1.1 Major Elements of the Petroleum Industry Structure

The petroleum industry activities have traditionally been segregated into three segments, the “upstream” exploration and production (E&P) of crude oil, the “midstream” segment that transports crude oil and RPP, and the “downstream” refining and marketing segments (Briggs, Tolliver and Szmerekovsky, 2012, p.2).

There are four key elements of this supply network that combine to determine refining infrastructure efficiency, crude oil slates, midstream transportation options, refinery configuration and product demand (Natural Resources Canada, 2008, pp. 20-33). We will discuss the significance of each of these elements separately.

Crude Oil Slate

The slate of available crude oil (crude) provides the feedstock for refineries. Not all crude is equal in the process of refining oil. Crude is found in varying viscosities and can have numerous heavy metals and chemicals suspended in the emulsion. The industry convention it to characterise crude by its viscosity, also referred to as specific

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada density or weight, and its sulfur content. Only specific refinery designs (configurations) can process heavy or light, sweet or sour crude efficiently. Consequently, crude supplies are segregated by weight and sulfur content and streamed to refineries that are best suited to their characteristics based on the configuration of the refinery and the desired yield of products (Natural Resources Canada, 2008, pp. 21-24).

The convention used by the industry to categorize crude oil viscosity is the American Petroleum Institute’s specific gravity scale measured in degrees API. The industry refers to light oil as being greater than 30o API, medium oil is between 27o to 30o API and heavy oil is less than 27o API (CAPP, 2012a, p. 2). In 2011, 29% of the 3 million barrels of Canadian crude oil production was light or medium weight and 71% was considered heavy (CAPP, 2012a, p. 37)

Crude oil containing high sulfur content is referred to as “sour” while “sweet” crude has low sulfur content. Sulfur content is measured as a percentage of the total volume with sweet oil having a sulfur content of less than or equal to 0.5% and sour being above 0.5% (CAPP, 2012a, p. 2) . Sulfur is undesirable in crude oil as most refined products are combusted resulting in the sulfur reformulating into the pollutant sulfur dioxide. Governments continue to increase standards on polluting externalities such as sulfur. Crude oil containing higher sulfur levels is priced at a discount to offset the additional processing costs of removing the sulfur. Consequently, refineries are willing to pay more for light, sweet crude than for sour heavy crude.

There are two major global standards for crude against which other crude oils are graded and priced. West Texas Intermediate (WTI) is the primary benchmark for US crude while North Sea Brent Oil (Brent) has become the standard for foreign oil. The standard characteristics for WTI is an API of 40o and sulfur content of 0.5% or less while Brent has an API of 37o and a sulfur content of 1.0%. From a refiners cost point of view Brent should be priced less than WTI as a barrel of Brent requires more desulfurization and refining to produce the same products as WTI however due to supply spikes from the US Midwest and increases in Western Canadian production, WTI has traded at a substantial discount to Brent for the past couple of years. Prior to 2005 Brent traded at a slight discount to WTI (EIA, 2012a).

In Canada crude oil production is trending towards more heavy oil. Regionally, Western Canada contributes 91% of all crude oil produced in Canada with the remaining majority of Eastern Canada’s production found offshore of Atlantic Canada. Western Canadian production totaled 2,743,000 barrels of crude oil per day in 2011 consisting of 80% heavy and 20% light oil. Although, much of Western Canada’s production is heavy oil, approximately 30% of it (705,000 b/d) is upgraded within Western Canada into light synthetic oil which has refining characteristics similar to light sweet conventional, i.e.

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada greater than 30o API and less than 0.5% sulfur. The Canadian Association of Petroleum Producers 2012 Market Forecast (CAPP, 2012a, p.37) projects growth in both heavy and light oil production to result in total production of 3,942,000 bpd (61%) by 2017. The majority of this growth is projected to be in heavy oil production which CAPP has projected to grow 1,270,000 bpd (69%) over the five years ending in 2017.

Atlantic Canada oil production is light and medium oil and primarily produced offshore. Production from existing East Coast producing fields is expected to decline by 25% over the next five years, at which time the offshore heavy oil Hebron field is expected to go into production to partially offset the light oil declining production (CAPP, 2012a, p. 37).

Figure 4 - Projection of Canadian Crude Oil Production

(CAPP, 2012a, p. 37)

The trend towards more heavy oil production and the asymmetrical distribution of production across Canada creates significant logistic challenges. A substantial portion of the oil product demand in Canada comes from Central Canada (Quebec and Ontario) while almost all production is in the West. Existing refineries in the east are configured for light oil refining which is the most expensive feedstock. Despite Canada producing more than a million barrels of crude per day than it consumes, the location of the production does not align with the location of demand. Consequently, vast quantities of crude production or RPP need to be physically moved to meet Canada’s daily demand.

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Mid-stream Infrastructure

Crude oil can be transported on land by pipelines, railway cars and trucks or by water using barges or tanker ships. Inland production of crude oil is collected from the wellhead and transported by pipeline through a field gathering system or trucked to centralized storage tanks where it is treated, measured and stored for shipping. Once the crude oil characteristics are determined, it is shipped through a trunk or transmission pipeline system to a refinery or coastal port willing to purchase it. There are more than 250,000 kilometers of field gathering pipelines and over 100,000 kilometers of transmission lines in Canada (CEPA, 2012a).

Refineries that are located close to water can receive crude by barge or large tanker ships. Refineries with coastal water access compete with all other coastal refineries for crude which making them a price taker of world oil prices. Inland refiners are also typically price takers of world prices however in instances when supply dramatically increases and outpaces the pipeline infrastructure in place to transport it, they can have more leverage to reduce prices. Refineries with access to deep water ports compete internationally in purchasing their crude feedstock or selling RPP’s making large complex refineries more feasible than in inland areas as they have more options to buy and sell.

Trucking and the use of rails cars provides flexibility to the delivery and distribution networks. Although they are the most expensive options, they are just as critical to the other cheaper systems as it is the combination of all three methods that makes the global network reliable in delivering 90 million barrels of oil based products to end users each day.

Depending on the distance and location, the transportation costs of moving a barrel of crude or RPP over comparable distances is lowest by pipeline, then open water shipping, followed by shipping by inland waterways, rail then trucking. Generally speaking, open water is slightly higher than pipelines, inland waterways are moderately higher that open water, rail is 3 to 5 times higher than pipelines with truck transportation costs being the most expensive but over shorter distances trucking provides a reasonable solution. The toll rate for transporting a barrel of light crude from Edmonton, Alberta to Sarnia, Ontario in the Enbridge Mainline pipeline is $3.95 while the toll rate from Portland, Maine to Sarnia is $4.40 (CAPP, 2012a, p.40). Rail costs from Alberta to the East Coast can be from $12.00 to $15.00 per barrel (EIA, 2012c).

Once refined, products are shipped by pipeline, ship, rail or truck to local distribution terminals. In the east coast Maritime region, almost all RPP are delivered by ships and barges however in the rest of Canada it is efficient for pipelines, rail and trucks to combine in product distribution. Due to the refinery consolidation in the Canadian Page 17

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Industry, in many markets only one terminal is available for all marketers for loading. In these areas, products exchange agreements are common where a refiner in one area agrees to provide product to a competitor in that area where they do not have a refinery. Most of the product distribution network is owned by the larger refiners, Shell, Imperial Oil, Suncor, Ultramar, Federated Co-op, Husky and Chevron (Natural Resources Canada, 2008, pp. 28-30).

Inventory of RPP is stored at local distribution terminals or at strategically located storage terminals. Refiners build up inventory of crude and RPP to absorb unanticipated supply disruptions, refinery shutdowns, regular refinery maintenance (turnarounds) and seasonal variations in product demand. Inventory hold levels are quite different from region to region in Canada (Natural Resources Canada, 2008, pp. 33-34).

The marketing and retailing of RPP is carried out by numerous companies and intermediaries however they can be segregated into integrated refiner marketers or independent marketers, companies which do not won a refinery. Of the existing eleven companies that own refineries, nine are refiner-marketers. Refiner-marketers controlled 26% of the gasoline service stations in 2010 and 16% is under the control of the top three, Shell, Suncor and Imperial Oil. Independent operators own the remaining 74% of which between 15- 25% of the market is owned by a half dozen larger independent retailers (M.J. Ervin & Associates, 2011, pp. 8-10).

Refineries

Refineries are designed with different processing configurations to efficiently refine different weights of crude into products. Heavier crudes require more elaborate chemical and thermal refining to optimize product yield. Refineries are categorized into three general configurations (Natural Resources Canada, 2008, pp. 23-24);

1) Topping plants consists of crude distillation unit (CDU) and normally has a catalytic reformer. These plants are designed to efficiently handle light sweet crudes and condensates. Although they can process heavier crudes into asphalt and heavy fuel oil, they are not efficient in processing heavy fuels into lighter refined products such as gasoline.

2) Cracking refineries take the heavier middle streams of gas oils from a CDU and “cracks” the complex gas compounds into simpler, lighter gasoline and distillates compounds using a combination of chemical catalysts, high temperatures and pressure.

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3) Coking refineries processes the heaviest streams of oil and thermally cracks the carbon bonds in heavy oils into lighter compounds using a coker or a coker plus hydrocracker (fluid catalytic cracking unit - FCCU). Coker’s and hydrocrackers allow the refinery to process heavier crude slates while still yielding a high amount of lighter products. Coker’s and hydrocrackers can operate independent of CDU complexes to upgrade heavy oil before shipping the crude for further refining. Heavy oil upgraders create a lighter, sweeter feedstock known as synthetic oil which has refining characteristics similar to WTI and therefore command a higher price when sold to refineries.

In addition to these three basic configurations, each process may be paired with a “hydrotreating” unit to reduce the sulfur and nitrogen content in crude. With the lower sulfur content standards required by regulations more hydrotreating units are being added to refineries as they are capable of removing up to 95% of the sulfur contained in crude (Natural Resources Canada, 2008, p. 23-24).

These different refining configurations yield different products percentages dependant on the weight of the crude inputted. For example, using heavy oil as a feedstock would yield different percentage yields in each configuration.

Figure 5 - Product Yields of Refinery Configurations Using Heavy Oil Feedstock

(National Resources Canada, 2012)

Although there is some flexibility in designing the configuration to yield a higher ratio of gasoline to distillates, or visa versa, this flexibility is limited and after a certain point production must be increased to produce the amount of product required. Typically, a cracking refinery will yield the following product percentages;

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Figure 6 - Expected Yield of a Cracking Refinery

(CEPA, 2012b)

Product Slate Demand

Refining crude produces a wide array of products however it is also necessary to match the production of products to the demand for the products.

Figure 7 - Canadian Domestic Refined Product Sales (2011) Motor gasoline 42.00% Diesel fuel oil 28.45% Aviation turbo fuel, kerosene type 5.62%

Heavy fuel oil 4.59% Petro-chemical feedstock 4.16% Asphalt 3.84% Light fuel oil 3.19% Other petroleum products 2.87% Petroleum coke 1.67% Lubricating oils and greases 1.03% Propane and propane mixes 1.00% Butane and butane mixes 0.89% Stove oil, kerosene 0.56% Naphtha specialties 0.06% Aviation gasoline 0.06%

Aviation turbo fuel, naphtha type 0.01% Total RPP 100.00% (Statistics Canada, 2012, p 11)

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Balancing refinery configurations with the availability of crude feedstock to yield the appropriate amounts RPP demanded requires careful planning. More often the process yield excess which cannot be fully utilized within a supply region, the most prudent method to clear the market of a product surplus is to sell and transport it out of the region.

Over the past ten years, domestic sales of RPP have grown in aggregate 195,949 bpd from 1,622,227 bpd in 2002 to 1,818,175 bpd in 2011. Although this represents a 12.1% growth (Statistics Canada, 2012, 2003) or 1.15% Compounded Average Annual Growth Rate (CAGR) over a ten year period (Gitman and Hennessey, 2008, p. 318), domestic demand exhibits substantial annual variation.

Figure 8 - Canadian Domestic Sales of RPP 2002 - 2011

Although the demand for RPP is obviously being influenced by economic growth, other issues such as societal initiatives directed towards reducing energy intensity and the growing awareness of the environmental damage caused by Green House Gases dampen the growth expectations of the RPP.

The rate of growth in the use of individual products has been uneven. Over the past ten years, national gasoline sales have increased 11.7% while diesel sales have increased

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33%. The use of heavy fuel oil is down 33%, light fuel oil is down 27% but asphalt is up 26.7%.

Figure 9 - Canadian Product Demand

Summary

The relative volume of different products that the process of refining crude yields is a function of the crude slate inputted into the refinery and the configuration of the refinery. Different crude slates used as feedstock will produce different product yields in different configurations.

Figure 10 - Major Elements of Refining Supply Network

Refinery Product Crude Oil Mid-stream Configuration Refined Slate Slate Options and Capacity Product Yield Demand

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Matching a source of crude to a particular refinery’s product yield to satisfy product demand is challenging especially given the long lead times involved in adjusting the physical components of this chain to demand which can respond to environmental changes much quicker.

3.2.1 Industry Structure in Canada

Refining infrastructure in Canada has undergone constant restructuring over the past 40 years. Since 1970, the number of operating refineries has dropped from 49 to just 18 producing refineries today (CAPP, 2012b). This reduction of the number of refineries in Canada was not a function of reduced demand for refined products but was undertaken to take advantage of economies of scale in the production of refined products. In spite of this 61% drop in the number of refineries, the refining capacity in Canada has increased 47% during this same time period (BP, 2012a).

Figure 11 - Refinery Capacity Verses Number of Refineries

This reduction in the number of operating refineries has concentrated the ownership control of these refineries. The remaining 18 operating refineries are owned by 11 companies; two companies control 43% of Canada’s refining capacity while largest five refinery owners control 80% (CAPP, 2012a).

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Figure 12 - Ownership of Canadian Refinery Capacity

Capacity % Total Company (bpd) Capacity Imperial Oil 516,000 25.67% Suncor 350,000 17.41% Irving Oil 300,000 14.93% Ultramar 265,000 13.18% Shell Canada 175,000 8.71% Five Largest Refiners 1,606,000 79.90% Next six owners 404,000 20.10% Total Canadian Capacity 2,010,000 100.00% (CAPP, 2012a, pp. 39-40)

Vertically integrated oil companies own 57% of the refining capacity, 18.7% are State Owned Enterprises (SOE) while the remaining are independent of upstream production although some have downstream retail marketing outlets .

Further complicating this oligopoly structure is the regional concentration of these large refineries:

- 67% of Western Canada’s refinery capacity is owned by three companies,

- 84% of Ontario’s capacity is owned by three companies,

- 100% of Quebec’s capacity is owned by two companies while,

- 83% of the Maritime Provinces capacity is owned by two companies.

In addition to the concentration of ownership, in certain regions of Canada, individual large refineries produce a disproportionate share of the regions RPP. The Ultramar 265,000 bpd refinery in Levy, Quebec represents 67% of Quebec’s throughput capacity and without it operating Quebec would require 225,000 bpd of petroleum products from outside Quebec and Ontario would require an additional 40,000 bpd that Quebec refineries currently provide.

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Figure 13 - Throughput Capacity of Canadian Refineries

Capacity Percent of Western Capacity (bpd) Total

Husky Prince George 12,000 0.59% Chevron Burnaby 55,000 2.72% BC Capacity 67,000 3.31% Imperial Oil Edmonton 187,000 9.23% Shell Scotford 100,000 4.94%

Suncor Edmonton 135,000 6.66% Husky Lloydminister 29,000 1.43% Alberta Capacity 451,000 22.27% Regina Consumers Co-Op 100,000 4.94% Moose Jaw Refinery 15,000 0.74% Saskatchewan Capacity 115,000 5.68% Western Capacity 633,000 31.25% Ontario Capacity Nova Sarnia 78,000 3.85% Suncor Sarnia 85,000 4.20% Shell Sarnia 75,000 3.70% Imperial Oil Sarnia 120,000 5.92% Imperial Oil Nanicoke 120,000 5.92% Ontario Capacity 478,000 24.37% Quebec Capacity Ultramar Levis 265,000 13.08% Suncor Montreal 130,000 6.42% Total Quebec Capacity 395,000 19.50% Maritime Capacity North Atlantic Newfoundland 115,000 5.68% Imperial Oil Dartmouth 89,000 4.39% Irving Oil Saint John 300,000 14.81% Total Maritime Capacity 504,000 24.88% Total Canadian Capacity 2,010,000 100.00% (CAPP, 2012a, pp. 39-40)

Industry defines throughput capacity as the volume of crude oil and feedstock that can fed into the distillation unit which is sometimes referred to as the charge capacity of the refinery (EIA, 2012b). Refineries can operate continuously 24/7 however about 5% of operating time is consider necessary for annual maintenance. Consequently, refineries that operate at 95% utilization are considered as being at full capacity. Refined product outputs can confuse the issue as refining increases the volume of output by as great as Page 25

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7% (volumetric gain) resulting in some refineries operating for short periods of time at over 100% of capacity if output volumes of refined products are being compared to capacity. Although refineries are routinely maintained and debottlenecked, no new refineries have been built in Canada since 1984 (Natural Resources Canada, 2008, p.25)

In 2011, Canada extracted over 3 million bpd of crude production of which approximately 1.8 million bpd was used to meet the countries total demand for RPP.

Figure 14 - Summary of Canadian Refined Products Production in 2011

Canada Crude Slates Light/Medium Conventional 689,544

Upgraded Synthetic 705,000 Heavy Oil 1,610,712 Total Orbit Domestic Supply 3,005,256 Crude Imports (Domestic) 326,140 Crude Imports (International) 679,581

Crude Exports - 2,342,427 Inventory Build (draw) 9,617 Other Feedstock 144,251 Refinery Charge Production 1,822,418 Volumetric Gains 87,863 Refinery output Production 1,910,281

Refined Imports 262,237 Refined Exports 387,870 Adjustments/Interprovincial 33,526 Net Refined Products 1,818,174 Demand

Gasoline 762,485 Diesel 517,289 Heavy Fuel 86,730 Other Fuels 451,670 Total Demand 1,818,174

(Statistics Canada, 2012, p. 28-29)

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On the surface the market appears to be a well-balanced market operating at 91% of capacity (1,822,418/ 2,010,000 bpd) with the excess crude being exported. At a 91% utilization rate refineries should be able to maintain a regular maintenance schedule and operate at profitable levels. Over the past ten years the industry has maintained utilization at 88% to 95% of available capacity.

Figure 15 - Canadian Refinery Utilization

Canada is a large country and the physical movements of large quantities of volatile fluids create natural constraints which must be considered. It is expensive and dangerous to move large quantities by rail or truck. Consequently, the lack of natural deep water seaways or pipelines has created partially isolated regional zones of supply and demand in Canada. When regional differences between capacities demand for products are considered, specific regional imbalances begin to emerge.

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Figure 16 - 2011 Regional Capacity Verses Demand

It is evident from this demand and supply chart that in determining the efficiency of this market it is important to understand how regional production and demand combine to balance Canada’s overall demand in a market that is bound by midstream flow restrictions.

The regional concentration of refining assets along with the linear delivery system that supports these refineries combine to create four regional zones or as National Resources Canada refers to them, “supply orbits”. The four supply orbits in Canada are;

1. Maritime Orbit - consisting of Newfoundland, Nova Scotia, Prince Edward Island, and New Brunswick. Maritime refineries also export along the Eastern Seaboard.

2. Quebec Orbit – consists of the Province of Quebec and exports into Ontario.

3. Ontario Orbit - primarily services Central Ontario’s Great Lakes Area and into Northern Ontario.

4. Western Orbit – consists of Manitoba, Saskatchewan, Alberta, British Columbia, Nunavut, NWT and Yukon.

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Figure 17 - Canadian Supply Orbits

(Natural Resources Canada, 2012).

Each orbit has different sources of crude feedstock and each have developed unique resources to refine petroleum products. Although nationally the demand for petroleum products is balanced relative to production, regionally each orbit has significantly different characteristics along the supply network. For example:

- The Maritime’s refine much more finished products than they consume and as their refineries has access to ocean ports, the excess refined products are exported to the US seaboard and into the Arctic.

- Ontario’s demand is greater than their production while Quebec’s production is greater than demand. Consequently, Quebec’s overproduction balances some of Ontario’s shortfall.

- Alberta extracts more crude than all of Canada can use however as limited pipeline capacity is available flowing east and west, most of the excess crude is exported to the US. Alberta also refines more RPP than they consume and although their surplus is transported and consumed in the supply orbit it is not sufficient to meet the orbits total demand.

In order to provide a more transparent understanding of interrelationships of these orbits we will examine the supply network in each orbit.

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Maritime Supply Orbit

The Maritime supply orbit includes the provinces of Newfoundland, Nova Scotia, Prince Edward Island, and New Brunswick. The three refineries in this orbit provides enough refined products to meet all of the orbits domestic demand and export the surplus to the Eastern Seaboard of the United States and into the Arctic.

The defining feature of this market is that their access to deep water ports provides a flexible cost effective gateway to foreign markets not only for importing crude but also for exporting finished products. The following production summary chart reflects the orbits supply, production and demand structure whereas domestic crude which originates from within the orbit accounts for 20% of the total crude input into refineries.

Figure 18 - Summary of Maritime Refined Products Production in 2011 (bpd)

Maritime Orbit Crude Slates Light/Medium Conventional 83,543 Upgraded Synthetic 0 Heavy Oil 2,712 Total Orbit Supply 86,255 Crude Imports (Domestic) - Crude Imports (International) 325,035 Crude Exports - Inventory Build (draw) 5,222 Other Feedstock 10,648 Refinery Charge Production 427,160 Volumetric Gains 20,617 Refinery Production 447,777 Refined Imports 39,427 Refined Exports 238,768 Adjustments/Interprovincial - 46,376 Net Refined Products 202,060 Demand Gasoline 61,956 Diesel 48,542 Heavy Fuel 32,848 Other Fuels 58,714 Total Demand 202,060 (Statistics Canada, 2012a, p. 28-29)

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Exports excluded, domestic crude could provide 45% of domestic consumption, with volumetric gains taken into consideration. The surplus production from the refineries allowed for 53% of the refined products to be exported out of the country and a net 16,000 bpd to be transferred to Ontario and Quebec’s orbits.

Crude Slates

The supply of crude in the Atlantic orbit is a mix of domestic production and imported crude. During 2011, 83,500 bpd of light and medium crude and 2,700 bpd of heavy crude were provided domestically, primarily from offshore production. Domestic crude production provided about 45% of the orbits domestic demand. An additional 325,000 bpd was imported to meet the remaining 115,000 bpd domestic demand and provide the feedstock for the 238,768 bpd of refined products exported out of the orbit. In 2011, 60% of the imported oil came from OPEC nations, primarily Saudi Arabia, Nigeria and Angola, 15% came from the North Sea and the remaining came from numerous smaller sources.

Of the 427,000 bpd of crude processed, 99% was a light or medium blend with the remaining being a conventional heavy oil. The orbits typically maintains a crude inventory of between 4 to 6 million barrels providing a 10 to 15 day supply of feedstock or enough to meet domestic demand for 20 to 30 days (Statistics Canada, 2012, p 28).

This orbits access to deep water ports provides the Atlantic refineries with the ability to purchase crude from multiple global sources. This optionality allows them to tailor the purchases of their crude slate to an ideal mix that optimizes the yield of their refining configuration and satisfy this orbits atypical demand for medium weight finished products. This ability to pick and choose whatever supply source can provide the best weight of crude for the refinery configuration historically was considered an advantage as they were able to but product to best utilize their fixed cost design, rather than having to design more complex refineries to produce the middle and heavier product slate that the orbit demanded. However over the past number of years, this flexibility in crude slate comes at a price as it must purchase crude based on Brent Petroleum prices which has been trading at a 15 to 20 dollar premium to WTI prices.

Midstream delivery and distribution

Imported crude is delivered through sea faring vessels which dock at seaports and then piped short distances to the orbits three refineries. No crude is transported in or out of the orbit through pipelines. Waterways provide world access through the Atlantic Ocean and the St Lawrence Seaway provides waterway access to Quebec and Ontario supply orbits.

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Refined products are primarily distributed through ships and barges to terminals and storage facilities, from which products are typically trucked to end users. The inventory of refined products held in storage terminals, range from 6 to 7 million barrels which is sufficient to meet domestic and import demand for 15 to 18 days or domestic demand for 32 to 38 days.

Refineries

The Atlantic supply orbit has three refineries, two larger complexes which provide over 80% of the orbits refined products and a smaller plant which also processes heavy oils and produces the orbits asphalt supply.

Figure 19- Maritime Refinery Configurations Capacity

Capacity (bpd) % Total Configuration North Atlantic – Newfoundland 115,000 22.82% CDU+Reformer/Cracker/Hydrotreating Imperial Oil Dartmouth 89,000 17.66% CDU+Reformer/Cracking/hydrotreating/Asphalt Irving Oil Saint John 300,000 59.52% CDU+ Reformer/Cracking/Hydrotreating Maritime Orbit Capacity 504,000 100.00% (CAPP, 2012a, p. 39- 40)

Utilization in 2011 was 85% of capacity however over the past 10 years has averaged 90% of capacity. Domestic demand was 202,060 bpd in 2011 which represents 40% of orbits capacity, so even if one refinery went out of production domestic demand could still be satisfied from the remaining refineries without depleting inventories. The surplus output is exported primarily to the US however some surplus is transported to the Quebec and Ontario orbits and supplies the east coast of the Canadian Arctic.

Product Demand

Atlantic Canada has historically had a somewhat atypical demand profile as their large refining capacity has developed a reliance on heavy fuels for electricity generating plants and middle distillates for home heating. The orbits reliance on heavier fuel products can be easily recognized in a comparison with Canada’s aggregate domestic product consumption mix.

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Figure 20 - Product Demand Mix Canada Verse Maritime

In the past it was cost effective to use heavier oil based sources for electricity and home heating however recently these uses are being displaced by lower cost natural gas. This shift to substitute products is reflected the in the negative demand trends in heavy fuel oil and stove kerosene (included in “Others”) over the past 10 years.

Figure 21 - Maritime Product Demand

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The orbit is self-sufficient in its ability to produce all the different RPP that it uses except for lubricating oil and greases of which it must import about 1000 bpd. The Maritime’s orbits excess capacity and ability to sell off unused surplus can efficiently manage any changes to its domestic demand structure or short term disruption in production.

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Quebec Supply Orbit

The Quebec supply orbit consists of the province of Quebec. There are two refineries in this orbit which provides sufficient production capacity to satisfy the orbits demand. Quebec does not produce any crude consequently 92% of its required feedstock is imported from outside of Canada, 7% is from the Maritime orbit and a small amount has recently found its way from Western Canada.

Figure 22 - Summary of Quebec Orbits Refined Products Production in 2011 (bpd)

Quebec Crude Slates Light/Medium Conventional 0 Upgraded Synthetic 0 Heavy Oil 0 Total Orbit Supply 0

Crude Imports (Domestic) 26,429 Crude Imports (International) 302,528 Crude Exports 0 Inventory Build (draw) 4,810 Other Feedstock 15,634 Refinery Charge Production 349,401 Volumetric Gains 4,581 Refinery Gross Production 353,982 Refined Imports 85,407 Refined Exports 56,804 Adjustments/Interprovincial - 28,084 Net Refined Products 354,501 Demand Gasoline 154,728 Diesel 90,799 Heavy Fuel 22,360 Other Fuels 86,614 Total Demand 354,501 (Statistics Canada, 2012a, p. 38-39)

Crude Slates

As previously mentioned, Quebec’s supply of crude is 92% imported crude and 8% from domestic supply. The domestic supply is primarily from offshore Atlantic production Page 35

A Strategic Analysis of Petroleum Refining Infrastructure In Canada however about 3,000 bpd is from the Western Orbit bring brought through Ontario. Approximately 302,000 bpd was imported from outside of Canada to meet domestic demand. OPEC nations, primarily Algeria and Angola, accounted for 53% of the imported supply, the North Sea provided 16%, and the remaining came from numerous smaller sources.

Of the 349,000 bpd of crude used, 86% was a light sweet blend, 13% was conventional heavy oil and a small amount of synthetic crude was processed. Crude inventory levels are maintained between 7 to 9 million barrels which is sufficient to provide 15 to 20 day’s supply of feedstock for the refineries.

Midstream delivery and distribution

Quebec has good waterway access to global markets through the St. Lawrence Seaway and also has good pipeline access to feedstock from Northeast US and from Montreal into Ontario. As the size of vessels that can access the Seaway is limited, it is often cost effective for crude to be transported by pipeline or unit train. The Seaway is impassable at time during the winter months which necessitates a higher level of inventory during winter. In 2011 almost half of the crude used in refining was transported to the refineries by pipeline.

A 240,000 bpd pipeline moves crude from Montreal, Quebec to Sarnia, Ontario (Enbridge’s Line 9). Originally, the line was designed to transport Western crude to Montreal however it was reversed in 1999 to help balance feedstock demands in Ontario. Enbridge has applied to once again reverse this line in 2014 and increase its flow capacity to 300,000 bpd to accommodate the transportation of Western crude to Montreal (Enbridge, 2012). Supplying 200,000 plus bpd of WTI priced western crude to Montreal would be expected to immediately displace the higher Brent Oil priced imported oil and dramatically reduce this orbits dependence on the 300,000 bpd of imported oil.

Refined products are distributed through barges, local area pipelines and trucks to terminals and storage facilities, from which products are typically trucked to end users. The Trans Northern Pipeline (TNPL) is a 132,600 bpd refined product transmission line from Montreal to the Toronto area and Ottawa. This line allows RPP from Montreal refineries and global imports arriving at Montreal via the Seaway access to the southern Ontario market.

Inventory of refined products held in storage and terminals ranges from 11 to 12.5 million barrels which is sufficient to meet demand for 30 to 36 days.

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Refineries

Quebec only has two refineries and both are required to meet the orbits demand for RPP. Both refineries have cracking units while the Suncor plant also has an asphalt plant.

Figure 23 – Quebec Orbits Capacity

Capacity (bpd) % Total Configuration Ultramar Levis 265,000 67.09% CDU/Cracking/Reformer/Hydrotreating Suncor Montreal 130,000 32.91% CDU/ Reformer/Cracking/hydrotreating/Asphalt Quebec Orbit Capacity 395,000 100.00% ( CAPP, 2012a, pp.39-40)

Utilization in 2011 was 89% of capacity however over the past 10 years has averaged 93% of capacity. Domestic demand was 354,501 bpd in 2011 which is more than any one refinery can provide.

Product Demand

The mix of products demanded in Quebec emulates the aggregated Canadian Product Mix with some minor variations. Figure 24 - Canada Verses Quebec's Product Demand Mix

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The use of gasoline and heavy oil is slightly higher while diesel fuel is slightly lower than the Canadian profile. Even though diesel use is lightly below the national average in 2011, it is the fastest growing segment of this market, growing 48% over the past 10 years from its increased use in on-road transportation. Fuel oil use for home heating is slowing being displaced by natural gas.

Figure 25 - Quebec Product Demand Growth

Although Quebec can produce enough RPP to satisfy the orbits demand, the two refineries need to run at almost full capacity to build inventory levels for turnaround maintenance period and to provide a buffer for an unscheduled shutdown or supply disruptions. When comparing volumes of RPP to demand, some minor product shortfalls and excesses exist however these are easily balanced against the large volumes moving into the province bound for Ontario.

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Figure 26 - Quebec's Product Balance

Even though the orbit is close to being self-sufficient in its ability to produce enough RPP to meet demand, over 142,000 bpd of RPP was brought into the province and over 189,000 bpd was shipped out. This large volume of product movement is required for various reasons:

- About 150,000 bpd of RPP is received and transferred into the Ontario’s market to balance Ontario’s demand.

- RPP movement is needed to balance out the daily, weekly and seasonal timing of the demand for certain types of products and building inventories to meet these requirements in Quebec and Ontario orbits.

- As Quebec refineries approach their operating capacity, there is a lack of flexibility in the product yields. This lack of slack creates some production excesses and shortfalls of products that need to be traded off through exports or interprovincial transfers.

Moving products increase the costs of the system and can add $2 to $10 per barrel depending on how it is transported and where it sold. Page 39

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Ontario Supply Orbit

The capacity of the refineries in the Ontario Supply Orbit can only provide 86% of the orbits demand. This leaves it dependent on RPP transported from outside the supply orbit. Additionally, Ontario produces almost no crude itself which leaves it dependent on outside sources for almost all of its feedstock. Ontario requires about 100,000 bpd of Interprovincial transferred RPP and 52,000 bpd of imports to balance their demand.

Figure 27 – Summary of Ontario's Refined Product Production in 2011 (bpd)

Ontario Crude Slates Light/Medium Conventional 1 Upgraded Synthetic 0 Heavy Oil 0 Total Orbit Domestic Supply 1 Crude Imports (Domestic) 299,711 Crude Imports (International) 52,018 Crude Exports Inventory Build (draw) 319 Other Feedstock 77,521 Refinery Charge Production 429,570 Volumetric Gains 30,400 Refinery Gross Production 459,970 Refined Imports 56,015 Refined Exports 45,623 Adjustments/Interprovincial 103,566 Net Refined Products 573,928 Demand Gasoline 288,074 Diesel 123,159 Heavy Fuel 8,861 Other Fuels 153,834 Total Demand 573,928 (Statistics Canada, 2012a, p. 48-49)

Crude slates

Ontario’s supply of crude supply is practically all from outside the orbit, 85% is supplied from the Western Orbit, less than 1% is from the east coast and 15% is imported from

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada outside the country. Approximately 52,000 bpd was imported primarily from the North Sea (18,000 bpd), US (7,810 bpd), and Mexico (6,155 bpd).

Of the crude charged in production, 61% was light conventional crude, 19% was synthetic crude, 15% was conventional heavy oil, and 4% was a heavy bitumen blend. Crude inventory levels are quite limited typically maintained between 2 to 3 million barrels which is only sufficient to provide 5 to 7 day’s supply of feedstock for the refineries. The refineries close proximity to US feedstock offsets some of the risks of this tight inventory hold however for an orbit with no internal supply of crude it is an economic risk to be committed to such a lean chain.

Midstream delivery and distribution

Most of the Crude and RPP movement in Ontario is through pipelines. Ontario has access to feedstock from Montreal, Northern US and from Western Canada. In 2011 99% of the crude used in refining was transported to the refineries by pipeline. Western crude is transported into Ontario via the Enbridge Mainline from Hardisty, Alberta to Superior then Sarnia which can currently move over 700,000 bpd into Sarnia through lines 5 and 6b. Imported and Eastern Canadian crude is piped via Enbridge’s Line 9 from Montreal. A proposed reversal of line 9 in 2014 would substantially reduce the ability to move imported oil to Ontario refineries unless it came through Enbridge’s mainline.

Trans Canada Pipelines is considering converting an existing natural gas pipeline to a crude line which could transport an additional 625,000 bpd to Ontario and on to Montreal from Western Canada. An extension to the existing line could take this line to Quebec City at which point crude could be shipped to the Atlantic orbit or sold on the global market.

Refined products are distributed through pipelines, barges, rail and trucks to terminals and storage facilities, from which products are typically trucked to end users. Most RPP are piped into the Southern Ontario market via the 132,600 bpd Trans Northern Pipeline (TNPL) from Montreal. Marine transport by smaller ships and barges into Sault Ste.- Marie and Thunder Bay from Sarnia moves a small amount of RPP into the northern markets. The inventory of refined products held in storage and terminals ranges from 16 to 18 million barrels which is sufficient to meet demand for 27 to 30 days.

Refineries

Ontario has four refineries and a petrochemical plant that produces distillates as part of its petrochemical formation process. Three refineries are configured to refine light sweet or light sour crude but the 120,000 bpd Imperial Oil Sarnia plant also has a Coker unit which can process heavy oil from Western Canada. Page 41

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Figure 28 - Ontario Orbit's Capacity

Capacity (bpd) % Total Configuration Nova Sarnia 78,000 15.80% Petrochemical Plant Suncor Sarnia 85,000 17.22% CDU/ Reformer/Cracking/Hydrotreating Shell Sarnia 75,000 15.19% CDU/Cracking/Reformer/Hydrotreating Imperial Oil Sarnia 120,000 24.31% CDU/Cracking/Hydrotreating/Coker Imperial Oil Nanicoke 120,000 24.31% CDU/ Reformer/Cracking/hydrotreating/Asphalt Ontario Orbit Capacity 478,000 100.00% (CAPP, 2012a, pp. 39-40)

Utilization in 2011 was 90% of capacity however these refineries are older and low 90% utilization is probably their maximum capacity. Domestic demand was 574,000 bpd in 2011 which was 145,000 bpd more than what was produced.

Product Demand

The mix of products demanded in Ontario is substantially different than Canada overall Product Mix, especially in the gasoline, diesel and heavy fuel product offering.

Figure 29 - Canada verses Ontario's Product Demand Mix

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Ontario supports the largest population in Canada and as such the retail demand for on- road gasoline products is disproportionate to the other economies in Canada. When demand is matched against the orbits actual production, dramatic product imbalances become apparent.

Figure 30 - Ontario's Product Supply and Demand Balance

Although a large portion of the shortfalls can be attributed to the lack of capacity in the orbit, the orbit also has an unusually high weighting of gasoline usage (50%) and low diesel usage (21%) which is out of the normal yield profile of typical refinery (42%/ 28%).

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Figure 31 - Ontario's Product Demand Growth

Gasoline, diesel and aviation fuel use has grown along with economic and population growth. Over the past ten years as the volume of gasoline use has grown 10.38%, diesel has grown 11.6% and aviation fuel has grown 23%.

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Western Supply Orbit

The Western Orbit consists of the provinces of Manitoba, Saskatchewan, Alberta, British Columbia, and the three northern territories of Nunavut, NWT and Yukon. There are eight refineries in this orbit however two are asphalt plants. In addition to the eight refineries there are also six heavy oil upgraders capable of upgrading up to 1,400,000 bpd of heavy oil to lighter synthetic oil.

Figure 32 - Western Orbit's Refined Product Production in 2011 (bpd)

Western Crude Slates Light/Medium Conventional 606,000 Upgraded Synthetic 705,000 Heavy Oil 1,432,000

Total Orbit Domestic Supply 2,743,000 Crude Imports (Domestic) 0 Transfers to Ontario and Quebec Orbits - 300,917 Crude Exports - 1,865,510 Inventory Build (draw) - 734 Other Feedstock 40,448

Refined Charge Production 616,287 Volumetric Gains 32,265 Refinery Production 648,552 Refined Imports 81,388 Refined Exports 46,675

Adjustments/Interprovincial 4,420 Net Refined Products 687,685 Demand Gasoline 230,350 Diesel 254,439

Heavy Fuel 19,320 Other Fuels 183,576 Total Demand 687,685 (Statistics Canada, 2012a, p. 28-29)

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The supply and demand in Alberta and Saskatchewan are balanced as they have 90% of the orbits refining capacity. The remaining provinces and territories rely on product transfers from Alberta or Saskatchewan or imports to balance demand.

Crude slates

Western Canada contributes 91% of all crude oil produced in Canada with production totaled 2,743,000 barrels of crude oil per day in 2011 consisting of 80% heavy and 20% light oil. Although, much of Western Canada’s production is heavy oil, approximately 30% of it (705,000 b/d) is upgraded within Western Canada into light synthetic oil which has refining characteristics similar to light sweet conventional. Excess crude is produced in Alberta and Saskatchewan of which 300,000 bpd was transferred to Ontario and Quebec orbits and 1,865,000 was exported to the US in 2011.

Refineries inventories of crude are maintained a very low level due the availability of supply held in the transmission lines. Reported inventories by refineries were only two to three million barrels which is only four to five days’ supply.

Midstream delivery and distribution

The producing provinces of Western Canada are landlocked although well-established gathering and transmission pipeline systems are in place as their fields have been producing for many years. Consequently all crude movement to refineries is by pipelines.

Numerous gathering lines run from Fort McMurray, Cold Lake and Northern BC into Edmonton and onto Hardisty, Alberta. Larger transmission lines move crude through;

- Kinder Morgan’s Trans Mountain Pipeline (300,000 bpd) from Edmonton to Vancouver and Washington,

- Enbridge Mainline (2,327,000 bpd) from Edmonton and Hardisty East through Saskatchewan then into Minnesota and the Great Lakes area eventually connecting into Sarnia from northern US,

- Trans Mountain Keystone (591,000 bpd) from Edmonton and Hardisty East through Southern Saskatchewan and onto Wood River, Illinois.

- Kinder Morgan Express line (280,000 bpd), south from Hardisty to Montana and Wood River, Illinois.

In all, there currently exists capacity to transmit 3,498,000 bpd of which 1,566,750 is designed for light crude and 1,931,250 for heavy crude. Enbridge’s mainline has

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada capacity to transmit 491,200 of light crude through line 5 and 231,400 bpd of heavy crude through line 6b to Sarnia (Capp, 2012a, p.20).

It should be pointed out that the midstream infrastructure is designed to take crude and RPP out of the Orbit, limited capacity is available to flow back into this orbit except around the fringes that borders the US. Should an unforeseen event occur that disrupts a significant portion of production, it would be expensive to import product to balance demand given the large size of this orbit.

As had previously mentioned in Ontario midstream review, Trans Mountain is considering converting their underutilized natural gas Canadian Mainline to transport up to 625,000 bpd of crude into southern Ontario and possibly as far as Quebec City where it can connect onto the St. Lawrence Seaway.

There are currently three contentious applications for new or expansions of existing pipelines being considered, Keystone XL, the Northern Gateway, and the Trans Mountain expansion. These proposals are for the transmission of crude for export and fall outside the boundaries of our study, other than they add flexibility to the existing system which could reduce the discount for heavy crude and possibly allow Western crude to be priced off Brent Oil.

Refineries

The Western Orbits six refineries and two asphalt plants have capacity to produce 633,000 bpd.

Figure 33 - Western Orbit Capacity

Capacity (bpd) % Total Configuration Husky Prince George 12,000 1.90% CDU/ Reformer/Cracking Chevron Burnaby 55,000 8.69% CDU/ Reformer/Cracking BC Capacity 67,000 10.58% Imperial Oil Edmonton 187,000 29.54% CDU/ Reformer/Cracking/hydrotreating/Asphalt Shell Scotford 100,000 15.80% CDU/ Reformer/Cracking/Hydro refining Suncor Edmonton 135,000 21.33% CDU/Cracking/Hydrotreating/Coker Husky Lloydminister 29,000 4.58% CDU / Asphalt Plant Alberta Capacity 451,000 71.25% Regina Consumers Co-Op 100,000 15.80% CDU/Cracking/Hydrotreating/Coker Moose Jaw Refinery 15,000 2.37% CDU / Asphalt Plant Saskatchewan Capacity 115,000 18.17% Western Orbit Capacity 633,000 100.00% (CAPP, 2012a, pp. 39-40)

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Sixty-five percent of the capacity is concentrated in the Edmonton area which produces surpluses to balance out most of the orbits demand. British Columbia produces less than a third of their demand and as such is dependent on Edmonton refineries via the Trans Mountain Pipeline and imports to balance its demand. Saskatchewan is balanced with RPP demand of about 105,000 bpd in 2011 verses its capacity of 115,000.

The Shell Scotford, Suncor Edmonton and the Regina Saskatchewan refineries all have Coker or hydro treating units which are capable of processing heavy crude and bitumen. Throughput capacity was 97% in 2011and for the past ten years utilization has edging up from the low 90% utilization to the current rates as economic activity and demand increases in the orbit.

In addition to these refineries, Alberta has six heavy crude upgraders which are integrated into Oil Sands mining projects, integrated with in-situ SAGD fields, or are off site operations independent of refineries. These upgraders are designed to take either conventional heavy crude or unconventional oil sands crude and upgrade it to light sweet synthetic crude which can be refined by less complex refineries. The upgrading capacity of these upgraders is close to 1,400,000 bpd however they do require much longer turnaround times and suffer from numerous unscheduled shutdowns due to the nature of the oil sands upgrading process. CAPP indicates that in 2011 only 705,000 bpd were upgraded into synthetic crude (CAPP,2012a, p. 39).

Figure 34 - Crude Upgraders Capacity Upgrader Capacity Athabasca Oil Sands Project (AOSP) 255,000 Suncor Base and Millennium 440,000 Syncrude Mildred Lake 407,000 Nexen Long Lake 72,000 Canadian Natural Resources Ltd (CNRL) Horizon 135,000 Husky Lloydminister Upgrader 82,000 Total Upgrading Capacity 1,391,000 (CAPP, 2012a, p. 39) I

Inventory of RPP is maintained in the 17 to 20 million barrels range which is about 27 to 30 days’ supply. Considering that some of the northern markets need to store month’s

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada supplies of RPP due to their distance from the refineries and the poor access into some communities at times of the year, this level of inventory is actually quite lean.

Product Demand

The mix of products demanded in Western does not mirror Canada’s overall Product Mix, especially in the gasoline, diesel and heavy and light fuel product offerings.

Figure 35 - Canada verses Western's Product Demand Mix

The large agricultural and industrial economies in Western Canada are the major users of diesel. Natural gas and coal has always been abundent and cheap in Western Canada where fuel oil has never been an energy sources for electricity generation and home heating. In the past ten years, gasoline volume demand has increased 14% and diesel volume demand has increased 45% resulting in the volume demanded for both products being almost equal. Asphalt and petrochemical demand also increase over 40% during this period due to strong economic growth.

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Figure 36 - Western's Product Demand Growth

A supply and demand comparison for 2011 reveals that even though the refineries in the orbit were at full capacity, production was 41,687 bpd short of gasoline demand and 44,741 bpd short of diesel demand.

Figure 37 - Western's Product Balance

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The need for the orbit to import 80,000 bpd is quite apparent once these shortfalls are taken into consideration.

Industry Analysis Summary

Although on a national basis the industry does move massive amounts of crude and RPP while the production of RPP appears to be well balanced with demand in 2011, a closer look at supply and demand at the regional supply orbit levels reveal specific imbalances. We have summarized the salient features of each supply orbit in the following chart.

Figure 38 - Salient Features of Supply Orbits

Maritimes Quebec Ontario Western Crude Slate Domestic crude Supply is 92% Supply is Domestic supply can supply 45% imported, 8% provided from exceeds demand of domestic provided from Western Orbit or by over a million demand. outside orbit. imported. bpd.

Primarily Supply is 86% Supply is 80% Production is light/medium light sweet, 13% light or synthetic, 80% heavy and crude. heavy 20% heavy or 20% light oil conventional. bitumen blend.

Midstream Access to deep Access to Supply is brought Various pipelines water ports waterways into orbit can transport 3.5 connects Orbit to connects orbit to primarily through million bpd out of global oils global markets. one pipeline orbit. markets. source. Pipelines moves Large area with RPP from RPP is also limited capacity Quebec into shipped from to move RPP Ontario. Quebec to into orbit. Ontario through a single pipeline. Refineries Three refineries Two refineries Orbit is Eight refineries have capacity to can meet dependent on still required refine over demand if they imports as the 80,000 bpd of 300,000 bpd operate at 93% five refineries imports to more than capacity. capacity only balance 2011 demand. supports 86% of demand. Capacity is demand. Capacity is 395,000 bpd. Capacity is 504,000 bpd. Capacity is 633,000 bpd. 2011 utilization 478,000 bpd. 2011 utilization was 89%; 2011 utilization was 85%. average over the 2011 utilization was 97%. last ten years was 90% of was 93%. capacity. Product Orbit demand Orbit demand Orbit demand Orbit demand Demand was 202,000 bpd was 355,000 bpd was 574,000 bpd was 688,000 bpd in 2011 in 2011 in 2011 in 2011. Page 51

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Capacity Small gasoline Production Production was exceeds product and aviation fuel shortfalls of short 42,000 bpd demand. deficits exist but 133,000 bpd of of gasoline and are easily gasoline and 45,000 bpd of Exported covered off by 42,000 bpd of diesel in 2011. 238,000 bpd in product diesel exist. 2011. movements into Demand growth Ontario. Demand is is strong balanced through especially for imports. diesel.

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3.2 - Competitive Forces Analysis

Porter’s Five Competitive Forces of Strategy is a traditional approach to evaluating industry strategy that provides a useful framework to evaluate the structure surrounding the dynamics of the Canadian refining industry. Porter postulates that the Competitive Forces’ of Internal Industry Rivalry, Threat of New Entrants, Treat of Substitutes, Bargaining Power of Suppliers and the Bargaining Power of Buyers shape the structure of industry. The composition of these forces arises from that industry’s distinctive economic and technical characteristics. The strongest of these forces determine the profitability of an industry making the appreciation of their interactions critical to strategy formation (Porter, 2008, pp. – 80-88).

In the analysis of the competitive forces that affect the refining infrastructures supply network we will review effect of competitive forces on downstream refineries. In applying this framework at this point in the network we will capture the crude slate producers as suppliers, the product users as buyers and still maintaining the scope of our focus.

3.2.1 - Threat of New Entrants

Porter argues that every industry has obstacles that create barriers for new entrants to gain access into that market. These barriers are advantages that incumbents have over new entrants and it the magnitude of these advantages that shapes the profitability of the industry. The threat of entry by a new competitor limits the incumbents’ profitability in that industry as when the barriers to entry are high, new entrants are less likely to be attracted to enter the market. The strongest incumbent advantages within the refining industry are supply side economies of scale, restrictive government policy, large capital requirements, and incumbency advantage of location (Porter, 2008, p. 80-82).

Supply side economies of scale provide a large incumbent advantage when they possess a supply advantage or when incumbents provide large scale, low cost operating capacity sufficient to satisfy demand. Although some Canadian refiners have integrated operations into the upstream market, the open competitive market of the numerous E &P companies negate any advantaged gained from upstream integrations. Many independent E&P companies enjoy the low cost crude economies that the integrated refiners have and are not necessarily contracted to one downstream source. Although the industry consolidation that occurred over the past thirty years has created large economies of scale barriers, the capacity shortfalls and product gaps that exist in the Ontario and Western orbits create opportunities for new entrants to enter or rival incumbents to fill.

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Economies of scale can provide a powerful advantage however under certain conditions the scalability of these economics creates inefficiencies under which diseconomies of scale take over. As volume increases, at some point per unit advantages of scale are offset by complexity and co-ordination issues such as transportation costs, more complex production processes or management inefficiency (Thomas and Maurice, 2008, p. 342 – 348). With the trend towards heavier crude slates, the complexity of refineries must increase in order to efficiently refine this feedstock. In large scale complex refineries, a problem in one segment of the process, such as fire in a coker, could shut down the whole process until that segment is repaired. We have seen in the Northern Canadian and more remote points in the Western markets that the midstream options increase costs or shifts the efficient cost curve of production such that in small limited markets with sources of crude production nearby small scale production should be considered as an option. New technologies or economies of scope can also negate the cost advantage of scale economics (Thomas and Maurice, 2008, p. 342 – 348).

The time lag and bureaucratic costs of the restrictive governmental policies in constructing and starting up a refinery is a significant barrier to entry. Government policy approving a refinery includes federal, provincial and municipal regulations which typically must be handled separately with numerous stakeholder feedback and consent being an important part of the approval process. In the case of pipelines, applications and approvals must be obtained from each province and municipality that the right of way passes through. In many cases the application is not approved after a lengthy expensive process.

Refineries require large long run capital commitments and as the existing refining companies are large enough to attract capital at efficient costs, any new entrant need to have access to low cost, long term capital in large amounts. Many of the international oil companies (IOC) and state owned enterprises (SOE) fall into this category. IOC’s such as Chevron, Shell, Valero (Ultramar) and Exxon (Imperial Oil) are currently involved in the Canadian refining industry. While South Koreas SOC, Korean National Oil Corporate (KNOC), purchased Harvest Oil and Newfoundland’s North Atlantic Refinery in 2009 and the Emirate of Abu Dhabi SOC owns the Nova Chemicals petrochemical plant in Sarnia. This barrier is not seen as restricting expanding capacity as there are many companies with the expertise and capital to expand Canadian capacity providing the return on investment and opportunities are attractive.

Finally, incumbents own many old refinery sites which have been turned into storage terminals facilities that have excellent pipeline access. These sites provide a location advantage for new refineries as the regulatory approval process would be much shorter and the cost of building pipelines supplying the refinery is already a sunk cost.

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Notwithstanding the incumbent advantages in this market, there are many publicly traded companies with access to low cost capital capable of taking advantage of the capacity gaps that exist in the Western and Ontario Orbits and as such the threat of a new entrant is high.

3.2.2- Suppliers Bargaining Power

Suppliers with strong bargaining power will capture more of the industry’s profit for themselves. Supplier groups are powerful if:

- They are more concentrated than the industry it sells to,

- They serve many industries and do not depend heavily on one industry for all it revenues,

- Industry faces large switching costs in changing suppliers.

- Suppliers offer products that are differentiated, or no substitutes for the suppliers’ products,

- They can threaten to integrate forward into the industry (Porter, 2008, pp. 82-83).

The suppliers of crude are numerous and sell into a market dominated by five large companies. Suppliers serve only one industry, growth in supply is greater than growth in demand and industry can quickly switch suppliers. Although crude is differentiated by API weight and suppliers can threaten to integrate forward, few actually integrate forward as most of these producers have smaller capital bases to work from relative to the large capital pools required to build a large scale refinery.

This structure of many suppliers pushing increasing crude production into the supply network can exceed the infrastructure capacity of the local networks creating localized areas of oversupply. This localized oversupply cannot be cheaply moved onto world markets ultimately driving down supply prices within these markets. The supplier group industry is a price taker that has limited power over the refining industry resulting in suppliers having weak bargaining power.

3.2.3 - Buyers Bargaining Power

Powerful buyer groups can drive down prices and capture more value from the industry. Buyer groups are powerful when:

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- There are few buyers purchasing large volumes relative to the size of the vendor,

- The industry’s products are undifferentiated,

- There are few switching costs.

- They can integrate backwards (Porter, 2008, pp. 83-84).

The largest buyers in this group are the marketing divisions of refiners who have vertically integrated into the retailing of fuel products and control 33% of the market. Although the products are undifferentiated with low switching costs, in most of the markets the buyers are diverse and small relative to the refiners selling fuel and other RPP. The aviation market has some large buyers, large airlines and the petrochemical market also has large petrochemical companies as buyers who have some limited buying power. Notwithstanding these wholesale markets, in the high volume, high value gas and diesel market buyers have low bargaining power.

3.2.4 - Substitutes

The presence of substitutes limits an industry’s profitability by placing a ceiling on prices. The threat of substitute is high if:

- The substitute can offer an attractive price-performance trade-off to the industry’s product,

- Buyers cost of switching is low (Porter, 2008, pp. 84-85).

The threat of substitutes exists in the form of renewable energy sources and other forms of fossil fuels. These substitutes threaten different markets at varying intensities. The low price of natural gas and its increased availability has improved its penetration into the home heating and electrical generation markets, displacing some heavier oil products. Over the past five years, 2008 to 2012, electricity generated from heavy fuel oil is down over 50% or 5,702 gigawatt hours (gwh) while electricity generated from natural gas has increased by 13,900 gwh or 33% (Statistics Canada, 2012c). During this same period the amount of electricity generated by renewable energy sources increased by 7,329 gwh which was a fourfold increase (Statistics Canada, 2012d). The dramatic increase in renewable energy sources has been driven by government subsidy programs in response to societies growing concern over GHG emissions however its growth along with natural gas growing market share has resulted in heavy fuel oils and diesel currently generating less than 1% of the electricity generated in Canada.

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With respect to the use of RPP in transportation, substitute’s lack of distribution infrastructure and energy density reduce their performance relative to RPP. As a result, demand is inelastic relative to price indicating that close substitutes are not readily available to consumers (Grant, 2008, p 73). If low natural gas prices are sustained or if technology reduces the performance shortfalls of electric cars (EIA, 2012d), substitutes could displace demand for RPP in this market much like they have in the electrical market. The threat of substitutes in this market is considered moderate over the long run.

3.2.5 - Competitive Rivalry

The extent that competitive rivals limit profitability in an industry is determined by the intensity of their competition and the dimensions on which they compete. Intensity of internal rivalry increases when:

- Competitors are numerous or are peers in size and power.

- Industry growth is slow.

- Exit barriers are high.

- Rivals are all committed to the business (Porter, 2008, pp. 85-86).

The dimensions that rivals compete can be price, differentiation of product or service, or focus. Porter warns that competitors that compete on price can be destructive to industry profitability. Price competition is most likely to occur when;

- Products are undifferentiated with low buyer switching costs,

- Fixed costs are high and marginal costs are low,

- Capacity must be expanded in large increments to be efficient,

- Products are perishable (Porter, 2008, pp. 85-86).

The refining industry fits into each one of these qualifications with the exception of their products are not perishable. To be more precise:

- Industry leaders are of comparable size and power,

- Industry growth of RPP is slow at 1.15% CAGR per year (Statistics Canada, 2012b),

- Exit barriers are high,

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- Rivals are committed to the business,

- Fixed costs are high while marginal costs are low,

- Capacity is added in large increments.

Notwithstanding that this industry should be prone to intense competitive pricing behavior, the oligopoly ownership structure that has survived the consolidation period of this market and lack of excess capacity has dampened the industry’s capability to gain more market share. With many of the participants operating at near full capacity, there is little room to gain more market share unless they expand capacity. The years of consolidating costs and pursing operational effectiveness techniques has lead the industry to pursue what Porter would call a conservative homogenous productivity frontier rather than firms pursuing a truly competitive advantage (Porter, 1996, p.63).

This is a dangerous strategy for these companies as it leaves room in the market for new entrants to add the capacity that incumbents have not filled. Such new entrants may not be so reluctant to enter into price competition or add excessive capacity in specific orbits that could dramatically change the competitive dynamics of the existing rivalry.

A significant cap on the profitability of Canadian competitors exists in the ability of competitors from outside of Canada to import RPP into Canada. If Canadian refiners price their products higher than the global market price plus transport external competitors will import will undercut their excessive prices. This limits the pricing power of the group and makes them price takers of the global market price.

3.2.6 - Factors Influencing Competitive Forces

Porter explains that it is the interaction of the five forces that determine industry structure and its long run potential value however he cautions that it is important not to mistake industry attributes for competitive forces. He explains that each industry has specific elements which influence structure but in themselves are not forces. Examples of such industry elements are technology, complementary products, government and growth rate (Porter, 2008, p.86).

The factors that influence competitive forces are complementary products, technology, and social interests represented through governments.

In response to the growing concern over GHG emissions the Federal Renewable Fuel Regulation required that an average of five percent renewable fuel content in Canadian Page 58

A Strategic Analysis of Petroleum Refining Infrastructure In Canada sold gasoline and a two percent renewable fuel content in diesel and heating distillate fuels (Government of Canada, 2010). These fuel supplements improve the quality of fuel by reducing the carbon footprint of fuel and should be considered as complementary products. Such renewables would include biodiesel and ethanol. Should a technical breakthrough occur that allows large quantities of renewable fuels to be produced at economical prices these products could be a competitive substitute for RPP.

Refinery technology exists to efficiently use natural gas as a feedstock for the production of diesel or to use Oilsands bitumen as a feedstock for the production of diesel. Refineries that produce diesel using such feedstocks’ would alter the midstream constraints currently exhibited and change the yield profiles of this industry. Refineries that capitalize on economies of scope can also alter this industry’s yield profile. Nova’s petrochemical plant in Sarnia produces 78,000 bpd of diesel fuel but is primarily a petrochemical plant.

Social interests and smaller groups representing stakeholder interests are often represented through petitioning governments into strengthening or easing regulatory constraints on industry. The Canadian Government passed numerous regulatory reform changes which also streamlined the environmental assessment process for pipeline applications. These changes sparked the “Idea no more” movement by native Canadians and numerous environmental stakeholders. The balancing of societal, industry and stakeholder interests can yield powerful, unpredictable influences on industry.

Competitive Forces Summary

The intensities of competitive forces combine to create an industry structure that provides refiners with some pricing power over upstream suppliers of crude which can be exploited when supply growth outpaces demand, however downstream pricing power is restricted by global imports. This pricing power is accentuated within the Alberta and Ontario orbits as midstream constraints increase the refiners pricing power. Orbits that access waterways are open to global competition and are price takers to both upstream and downstream global competitive pressures. The salient forces at work in this industry are summarized in the following chart:

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Figure 39 - Competitive Forces in the Refining Industry

The pricing power that refiners have gained over suppliers is expected to continue as long as supply increases faster than suppliers can find access to markets that can obsorb the increase. Refiner profits should increase with this increased power and motivate new entrants and incumbrants to consider capacity expansion. The threat from substitutes in the transportation market is a long run deterant to capacity expansion however technical breakthroughs are required to reduce costs and improve performance to be competitive with RPP. This threat could motivate company’s to hedge or reduce their long run risk by reducing the size of the expansion thereby reducing their exposure to a paradigm shift in demand away from RPP.

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3.3 - System Dynamics Analysis

In contrast to the top down competitive forces analysis, system dynamics (SD) assumes that system responses and problems have endogenous causes. SD posits that it is the interaction of the systems stocks and flows with the feedback nature of behavioral decision making elements that not only define the response limitations of systems to change but can also create the unintended consequences so often seen in complex systems (Richardson, 2009, pp. 856 – 860).

In the refining supply network we are considering, the limitations of stocks and flows are predicated on the physical nature of the commodity and the ability of the system to move it. The inflows, transportation and transformation of crude into RPP have been previously documented in the analyses of the industry and competitive forces. Based on these previous reviews of the structure of the Canadian Refining Industry, the physical stocks and flows of the system can be schematically represented as follows;

Figure 40 - Stocks and Flow Schematic

Substitutes RPP Demand Compliments Midstream/Distribution Constraint

Exports RPP Inventory Imports Midstream Constraints Product Yield

Refining Capacity

Midstream Capacity Midstream Options

Feedstock SupplyRate

Crude Slates

Domestic Crude Imported Crude Supply Supply Midstream Constraint Page 61

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The squares represent the systems stocks, the values and pipes represent the flows while the systems flow constraints are in blue. This schematic represents the refining infrastructure within each orbit as each orbit is characterised by substantially different elements. For simplicity, the schema included interprovincial transfers as imports or exports.

SD is particularly useful in identifying how elements within a system will react to a change or in identifying a problem and isolating the interaction of physical and behavioral elements causing the problem. We will rely on this schematic to explore who this system responds to two problematic situations that this industry faces, the effect of an unanticipated refinery shut down and the effect of adding capacity.

3.3.1 Unanticipated Refinery Shutdown

Refineries handle volatile materials under thermal, pressurized conditions. Consequently they often have system failures, fires, or explosions which shut down operations for periods of time. For example, the Federated Co-op refinery in Regina has experienced three unanticipated shutdowns over the past 18 months (Pacholik, 2013).

We have established that the four supply orbits have differing characteristics which should make each systems response to a shutdown unique. The Maritimes have a large surplus capacity, relatively smaller demand and access to deep water ports. Even if all three were shutdown, the orbits access to deep water ports allows them to arrange global imports to meet their total domestic demand. Quebec likewise has access to waterways which can be used and although a refinery shutdown may increase transportation costs, there are no crude slate or RPP midstream constraints that would restrict imports from covering the production shortfall from a shutdown. The Ontario and Western orbits however are more isolated and physically bound by systemic midstream constraints. Accordingly, we will use the Ontario orbit to probe a shutdown situation.

We will evaluate the Ontario’s Orbit response to a three week shutdown at Shell’s 75,000 bpd Sarnia refinery. This orbits refining capacity is 478,000 bpd however their demand in 2011 was 573,688 bpd making it depended on imports even when refineries are operating at full capacity. Imports are primarily transported into Ontario through the TNPL pipeline which has a capacity of 132,600 bpd. The shutdown would remove 75,000 bpd capacity leaving the remaining capacity at 403,000 bpd.

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Figure 41 - Refinery Shutdown Causal Map

Demand Expectation Substitutes RPP Demand Compliments Import decision Midstream/Distribution Pricing decision Constraint Refine or Import Decision Exports RPP Inventory Imports Midstream Constraints Product Yield

Refining Utilization decision Capacity

Midstream Capacity Midstream Options Feedstock SupplyRate

Crude Slates

Domestic Crude Imported Crude Supply Supply Midstream Constraint We have added the causal loop map in green to highlight the industry’s response to the immediate reduction in capacity. We will outline the key decisions and response industry would make to mitigate the reduction in capacity. We will rely on this schematic to qualitatively understand the potential feedback responses and anticipate delays to the system change. We will demonstrate the stocks and flows quantitative response and limitations as these are easily seen linear constrained conditions.

1. Industry would anticipate that demand would not be immediately dampened by the shutdown and would seek out alternatives to replace the lost production.

2. The industry options are to increase remaining production or import. Economic theory suggests that a firm should produce up the point where price equals the short run marginal cost when price is greater than or equal to the average variable cost of production (Thomas & Maurice, 2008, p. 404). If we assume that Page 63

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each unit produced could be sold at a price greater than the marginal cost and price is greater than the variable cost of production, we would then expect firms to independently decide to defer any planned maintenance turnarounds and over the short term produce at 100% of their capacity.

3. Midstream crude options should be unaffected by the shutdown.

4. Inventory and production will meet current demand however as inventory levels reduce additional imports will be sought out. As the TNPL is near capacity alternative midstream options will be explored. The procurement and transportation of import RPP by rail or truck would cause a response delay.

5. The additional costs of purchasing large amounts of RPP from outside of the orbit would increase costs which would over the long run adversely affect the quantity demanded. However, as the time frame is short and as petroleum products are inelastic to short run changes in price (Grant, 2008, p 73) demand would not be immediately dampened

6. Inventory holds would be used to offset any deficit in production and imports.

7. Any change in quantity would also impact compliments however the short run impact on quantity demand would be neutral.

8. The price increase may affect the price performance trade-off between RPP and substitutes however their lack of infrastructure and short run availability would delay substitutes gaining market share.

If we modeled these responses assuming that:

- Refineries immediately run at 100% of remaining capacity,

- Refining yields in the orbit are not materially affected by the Shell shutdown,

- 80% of the RPP imported is gasoline while 20% is diesel and that the industry was able to import an additional 100,000 barrels at the end of week two and 200,000 barrels by the end of week three and beyond.

Given these parameters we find the systems flows are predictable and linear as the feedback mechanisms are delayed from responding. Over the three week period, inventories readily absorb production and import shortfalls with gasoline inventories falling 1,593,000 barrels (34%) and diesel inventories falling 973,000 barrels (30%).

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Figure 42 - Ontario's Orbit Shutdown Response (barrels per week) Week 1 Week 2 Week 3 Gasoline Inventory 4,625,720 4,298,011 4,070,301 Diesel Inventory 3,266,239 3,034,279 2,802,318 Total Inflows 3,434,200 3,434,200 3,434,200 Total outflows 3,974,814 3,941,122 3,941,122 Net RPP Flows - 540,614 - 506,922 - 506,922

Over the three week shutdown, the system is quite robust and capable of buffering any supply side issues with current inventory levels. However if the shutdown continued for four months as the result of a more damaging explosion, and the variables were maintained at the same amount, inventories would be reduced to a net 900,000 barrels and by week eighteen they would be totally exhausted.

Figure 43 - Inventory Response to Shutdown

This situation assumed that the orbits other refineries are able to increase capacity utilization to 100% without straining their refineries. If a shutdown period was extended, Page 65

A Strategic Analysis of Petroleum Refining Infrastructure In Canada pushing these refineries at 100% capacity for extended periods would create additional failures which would exacerbate the production shortfalls.

Responses to an extended shutdown would have to entail structural changes to the system however many regulatory and safety delays would be incurred. Additional pipelines could be added from areas with access to waterways such as Montreal which would increase the flow of imports into the orbit. However, new pipeline projects take many years to plan and build and regulatory approvals are becoming exceedingly controversial. Regulatory approvals are drawn out and difficult to obtain as has been recently experienced with the Keystone XL (The Canadian Press, 2013) and the Northern Gateway (Fong, 2013) pipeline proposals.

In orbits with midstream constraints, inventory levels are critical to maintaining the reliability of supply. The USA has long recognized the importance of maintaining crude oil inventory’s to buffer crude supply disruptions. In response to the 1973 energy crisis, the US Department of Energy maintains a strategic petroleum reserve (SPR) of crude oil which can be released during supply interruptions. Over the past ten years SPR inventory levels have been maintained at between 55 – 82 days which when combined with industry inventory levels would provide about 120 days’ supply of crude (EIA, 2013). The US supply orbits are referred to Petroleum Administration for Defence Districts or PADD’s which have more refineries in more locations than in Canada’s orbits. Consequently, their risk is more in getting crude into their PADD’s than in providing RPP. The risk in the Ontario and Western orbits continues along the supply network to the finished product, that is, these orbits having no slack capacity to absorb a prolonged refinery shutdown. The risk in these orbits would be better contained by a strategic reserve of RPP than crude.

3.3.2 Capacity Addition Criteria

In deciding whether to add new capacity, John Sterman suggests that individual producers will expand or contract their production capacity to a desired capacity level based on their expectation of long run profitability. He argues that individual firms acting independently cannot solve for equilibrium capacity of productive capital given the uncertainty surrounding the future values of economic growth, changes in elasticity of demand, costs and developments of substitutes and changing social norms. As such, decisions to add capacity are independently made based on long run expectation of the profitability of the new investment. The degree of confidence in the long run expectation of profitability of the investment directly impacts the responsiveness of firms to invest in capacity (Sterman, 2000, pp. 802 – 810).

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The refining industry trends numerous metrics that signal the strength of the market for RPP, capacity utilization, refining margins, crack spreads and production/ product sales are but a few. These indicators help refiners respond to short term production opportunities in the market however as Sterman contents, in making a long run capacity investments the crucial determinant is the long run expectation of profitability.

In modelling the capacity investment decision, we propose that demand expectations are signaled to the market through indicators such as growth rates, capacity utilization, and product shortages signaling to the market that opportunities exist to expand capacity. Although these metrics are used by industry to identify opportunities in the market the crucial determinant employed in long run decisions is the expected return on investment. An additional consideration in the refining industry, planning, regulatory approval process and construction can delay the capacity addition for five to ten years, the effects of this delay should be considered. Linking these determinants suggests the following causal map.

Figure 44 - Capacity Acquisition Causal Map

Substitutes Demand Expectation RPP Demand Compliments Market Opportunity Price decision Midstream/Distribution Constraint Long Run Return on Exports RPP Inventory Imports Midstream Capital Employed Constraints Expectation Product Yield Regulatory & Refining Capacity Construction Delay Capacity Addition

Midstream Capacity Midstream Options

Feedstock SupplyRate

Crude Slates

Domestic Crude Imported Crude Supply Midstream Supply Constraint

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We know from the industry analysis that in the past ten years RPP demand has increased on average 1.15% per year and that capacity utilization has been consistently above 90%. We have also seen that substantial gasoline and diesel production shortfalls existing in the Ontario and Alberta supply orbits. These indicators signal to producers and new entrants that market opportunities exist that may be profitable.

In Canada publicly traded companies operate 75% of the refining capacity. Investments in these companies are made to maximize returns to shareholders (Thomas & Maurice, 2008, pp. 10-15). Consequently, investment decisions are typically made on a portfolio management basis with most companies operating in the Canadian refining industry measuring performance on a return on capital employed (ROCE) bases (Imperial Oil, 2012, p. 30). Corporations review numerous investments opportunities and based on their assessment of expected return on capital, rank and compare expected returns to corporate ROCE. Based on their ranking, they invest in those projects which are most accretive to shareholder earnings. Imperial Oil is the largest refiner in Canada with over 500,000 bpd of capacity and provides a good example of the results of this process.

The ROCE is key performance metric for Imperial Oil and a review of their division’s performance over the past ten years provides some insight into corporations’ internal competition for capital.

Figure 45 - Imperial Oils Divisional Return on Capital Employed

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This graph illustrates that over the past ten years the ROCE for upstream and the chemical operations provided a much larger and more variable ROCE than their downstream operations. We note that the chemical operations are an order of magnitude smaller than the other two divisions. Prior to 2012, upstream operations provided a superior yield even given the viability in their results.

Expected Standard Coefficient Value (E) Deviation of Variation

Upstream 42.41% 16.66% 39.29% Downstream 23.76% 12.41% 52.23% Chemical 45.43% 18.61% 40.97%

The effect that return has on capital allocation decisions is quite apparent; from 2002 to 2011 Imperial Oils’ capital expenditures were 19.98 million dollars of which 83% was allocated to upstream investments, 16% to downstream operations and 1% to chemical division investments. As can be seen in the ROCE graph, downstream operations ROCE improved dramatically in 2012 just as returns from upstream operations turned down as result of lower crude prices to refiners. This change in ROCE sends a strong signal to the market that profitability levels are such that capacity could be profitability added to the industry to at least displace the imports. Capacity addition is a long run decision and confidence in the long run profitability of the industry is the determining motive to invest in expansion. As confidence in improved refining returns grows addition investment in this sector can be expected.

Although the long run expectation for profit is improving, the question arises as to how much capacity should be added and how would the system respond to the increased capacity? In his 1999 MIT doctoral thesis, Taylor found that long run capacity cycles in the pulp and paper industry can be explained by capacity acquisition delays which can create oscillations in capacity. The pulp and paper industry share many similar characteristics with the petroleum industry, commodity price variations with growth, long supply chains and networks with physical constraints, capacity is added in large quantities at one time and long capacity acquisition delays. Taylor found that a four year acquisition delay in capacity lead to short run price and utilization oscillations within a 14 year long capacity cycle (Sterman, 2000, pp. 824 -828).

This effect can be illustrated in the causal map where;

1. Market indicators such as refinery margins, product gaps and inventory shortfall signal to the market that demand is increasing.

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2. Import fill the product gaps in the market however transportation costs increase the price of RPP being sold thereby increasing refiners ROCE.

3. The long run ROCE expected increases motivating companies to acquire capacity.

4. Regulatory approvals and construction delays’ could be as long as five years or more, as such fundamental changes in future demand and competitor responses need to be considered prior to proceeding with plans to acquire additional capacity.

5. Adding new capacity increases production of RPP based on the crude slate used and yield profile of the capacity being added.

6. New production first displaces imports and then builds in inventory until it is demanded.

7. Demand would draw down inventories and a new equilibrium between prices, utilization, imports is reached. If demand is not what was originally anticipated and is not sufficient to draw down inventories and balance the market, as inventory builds refiners would be motivated to reduce utilization and then reduce the price to clear excess inventory levels.

8. The reduced price should stimulate demand, decrease inventory and increase utilization. However if the demand recovery is slow or if the reduced demand is from lower energy intensity such as better fuel efficient cars or changing behavioral pattern, the demand recovery could be prolonged or never.

9. In prolonged demand recoveries, demand expectations are negative, profit expectations are low and the least efficient capacity will eventually be removed from the system if the recovery is long enough.

It can be seen in this illustration that adding capacity beyond actual domestic demand can erode profits and result in more consolidation in the market. Companies adding excess capacity to export RPP into global markets face intense global competition both in purchasing feedstock and selling RPP. They would also face higher transportation costs than many other competitors as Canada is not located close to any major markets other than the US which is already well served within its domestic industry.

Within the context of Canada’s current refining environment, we would expect the increased profitability of downstream operations and the demand product gaps that exist in Alberta and Ontario to attract interest from industry participants and new

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada entrants. However, as excessive capacity could lead to reduced profitability and further consolidation the size of the refinery being added needs to be considered.

In Ontario, the production gaps are quite large as the orbit was short 133,000 bpd of gasoline and 42,000 bpd of diesel in 2011. In Ontario’s situation, acquiring one or two large cracking refineries would take advantage of the unit cost efficiencies provided by economies of scale of production however 350,000 bpd of capacity is required to yield enough gasoline at the 42% yield expected from such a configuration. Although the existing midstream pipelines can deliver this additional feedstock from Western orbit, an additional 350,000 bpd would approach the 700,000 bpd capacity limits of the Enbridge mainline. It would be prudent to consider other sources and delivery systems that could diversify the supply risk.

The Western Orbit is somewhat of a different story as their production gaps are smaller and the demand for diesel has been growing at three times the rate of gasoline growth. This disproportionate growth is expected to continue as long as growth in the industrial sector continues. Additionally, RPP are transported great distances from Alberta into Manitoba, Northern Ontario, and North West Territories. In matching the anticipated demand growth and reduce the amount of RPP transported it would be more efficient these demand gaps could be filled by a combination of smaller scale refineries located closer to demand than in building a large centrally located refinery.

Small scale refining options in this market could include;

- Smaller scale bitumen to diesel, or natural gas to diesel refineries in Northern Alberta or Northern BC which would be closer to demand and feedstock sources. Petrochemical/diesel refineries could also help fill the growing demand for diesel.

- Manitoba has a daily demand of about 60,000 barrels consisting primarily of 28,000 bpd of gasoline and 22,000 of diesel. Feedstock could be provided via The Spectra Express-Platte pipeline runs from Hardisty, Alberta into Manitoba as does the existing Keystone pipeline.

- The North West Territories and the Yukon have producing crude fields which could supply a small scale refinery to meet local demand. Currently, large inventory holds need to be maintained in Northern Canadian communities as fuel must be trucked in during winter months on ice roads. Current demand is only 8,000 bpd but the refinery could also service Northern BC communities which are only partially served from Prince George’s 12,000 bpd refinery.

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System Dynamics Summary

The stock and flows of each orbit creates specific dynamics in how the individual orbits response to change. In orbits without midstream constraints inventories serve as a reserve for seasonal demand and turnarounds however in orbits that are midstream constrained inventories provide the buffer that can absorb system disruptions. Current levels of inventories seem adequate to handle routine short term disruptions in productions however they would not be able to handle low probability events such an extended closure of the Enbridge pipeline into Ontario which provides 85% of the orbits feedstock. Although such events rarely occur they would have a major impact on the economy of Canada. A strategic reserve of RPP held in the orbits that are subject to midstream constraints would reduce consequences of these events.

Confidence in the expected long run return on investment is the crucial determinate in deciding whether to acquire capacity. However, demand and the expectation for demand can change much more rapidly than the industry’s ability to respond to the changes. Rapid changes in demand results in the industry often overproviding or underproviding capacity which coupled with capacity delays can generate into a negative feedback cycles that reduces or adds capacity at inappropriate times thereby reducing industry profitability. As capacity demand shortfalls can be covered with imports, over capacity situations are the more harmful to industry profitability.

4.0 Recommendations and Conclusions

The three analytical approaches utilized in this study each provided valuable insights to answering the research questions we originally raised. The industry analysis identified major elements of the petroleum industry’s structure and related these elements to a review of the industry’s current structure. Information from the industry analysis identified certain emerging patterns and formed the foundation for the Competitive and SD Analyses. The competitive analysis provided the framework to view the interaction of the competitive forces at work in this industry, to determine which forces currently dominate and which forces could influence the competitive environment in the future. SD provided an understanding of how the physical limitations of the industry interact with the industry’s behavioral decision making to respond to changing conditions. Collectively they provide a more complete framework from which to based strategic decisions than any one approach independently.

The research question inquired if Canada’s refining infrastructure will meet the future needs of Canadians. I also posed two sub questions which queried whether its current structure was secure, reliable, and efficient then if additional capacity is needed would it Page 72

A Strategic Analysis of Petroleum Refining Infrastructure In Canada be more efficient to add capacity in large economies of scale refineries or in smaller scale refineries domiciled closer to the sources of demand.

The industry analysis revealed that refining capacity in the Western and Ontario supply orbits do not meet current RPP demand much less future demand, Quebec’s orbit can meet its current domestic demand if it produces at virtually full capacity and the Maritime Orbit operates at a surplus. The Maritime surplus can be moved into Quebec or Ontario to offset any future RPP shortfalls. However the Maritime refineries purchase crude on global markets at a premium Brent Crude price while the Western orbit sells its crude at a discounted WTI or heavy oil price. This inefficient use of national resources could cost Canada billions if the price gap between North American crude and Brent persists. Additionally, Quebec’s production is concentrated in two refineries one of which provides 67% of the orbits capacity, should it fail 250,000 bpd of imports would be required to balance demand.

The lack of midstream options available to Ontario and Western limit their ability to bring RPP and in Ontario’s case crude into the orbit. This raises concern over the reliability of supply in the case of a prolonged disruption at a major refinery. As both orbits also under produce their demand requirements, a production disruption could have major cascading effects on their economies. Inventory levels are sufficient to absorb a short run unanticipated shutdown however a prolonged shutdown would stress inventory levels and could create price shocks.

Additional refining capacity should be added in the Ontario and Western orbits to meet product shortfalls. The Western orbits refineries undersupplied 42,000 bpd of gasoline and 45,000 bpd of diesel during 2011. Alberta is the center of capacity in the orbit as it overproduces and transports finished product long distances to Manitoba and Northern Canada who have no refining capacity. Adding a large cracking refinery would provide economies of scale and fill the current product gap however with their growing demand for diesel and the need to transport RPP to far off corners of the orbit; small scale refineries or more innovative gas to diesel, bitumen to diesel refineries or petrochemical/diesel refinery may provide a more flexible solution. Regions without refineries such as NWT, Yukon and Manitoba should be considered as candidates for smaller scale refineries. NWT has crude production and Manitoba and BC have access to crude pipelines. Areas of high demand such as Fort McMurray should also be considered for a smaller scale refinery to fill local market product gaps but not so large as to create excess capacity.

Ontario’s refineries undersupplied their market by 133,000 bpd of gasoline and 41,000 bpd during 2011. Adding one or two large cracking refineries in this orbit would take advantage of the unit cost efficiencies provided by scale of production however 350,000 bpd of capacity is required to yield enough gasoline at the 42% yield expected from Page 73

A Strategic Analysis of Petroleum Refining Infrastructure In Canada such a configuration. Although Quebec is relatively well balanced, adding specific product capacity in an orbit that has good access to waterways and an expandable pipeline system into Ontario would diversify their dependence on two large refineries and assist in offsetting Ontario’s shortfall and add some slack into their production capabilities. Small scale refinery options in Quebec would diversify their reliance on their two major refineries, provide some slack for inventory builds and turnarounds, and reduce Ontario’s reliance on international imports. Midstream solutions to allow more efficient movement of RPP between the Maritimes and Ontario should also be considered, whether that is expanding the pipeline between Quebec and Ontario or considering a new line from the Maritimes to Quebec or Ontario.

The analysis of competitive forces indicate that even though incumbents enjoy economies of scale, location advantages and regulatory delay barriers, the threat from new entrants is high as capacity utilization is high, capital and new candidates for entry are available, production/demand gaps exist and industry profitability is rising. Although this threat from new entrants is partially moderated by the threat from potential substitutes the threat of new entrants is more dominant due to the unfavourable performance/price trade-off of substitutes in markets lacking stringent carbon constraints. Both supplier and buyer groups bargaining powers are low relative to refiners however refiners are limited in pricing power with the buyer groups by imports that could displace their products if pricing is excessive. The suppliers do not enjoy such a power limitation as the increased profitability of the refiners is a result of lower input costs and is a reflection of the refiners pricing power over these suppliers. Competitor rivalry is currently subdued as little excess capacity exists in three of the four orbits however all the necessary elements for an intense price war exists. It would be expected that incumbents faced with the threat of a new entrant that would disrupt their oligopoly power structure and who still control various terminal locations would reduce that threat by adding to the current capacity to fill the product gaps that exist in certain orbits.

The economy of scale advantage that large refinery enjoy could be reaching a point of diminishing returns due to the complexity requirements of modern refineries and the transportation costs of moving large quantities to far off points by expensive mode of transport. In locations where access to crude feedstocks is available it may be more efficient for local demand to be served by local smaller scale, modern and more efficient refineries.

The current equilibrium between internal rivals and the other four forces can easily be subverted if additional capacity is added that exceeds domestic demand. The industry has gone through a 40 year period of consolidation in the number of refineries and capacity is not yet back to the capacity levels of 1980. It has only been recently that

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A Strategic Analysis of Petroleum Refining Infrastructure In Canada margins have recovered and production/demand gaps are sufficient to add capacity. If a large economy of scale refinery was added in any one orbit, the excessive capacity could dramatically shift the balance of power between rivals and trigger a price war as rivals attempt to drive down their per unit costs by maximizing their production. This could lead to another extended round of consolidation of the older marginally productive refineries if capacity increases are excessive.

The extended time delays in gaining regulatory approvals and the possibility of reduced product demand due to lower energy intensity or changing values creates uncertainty in projecting demand for the future. The delay in adding capacity coupled with the uncertainty of what future demand will be when the capacity comes on line could motivate company’s to hedge or reduce their long run risk by reducing the size of the expansion thereby reducing their exposure to a shift in demand away from RPP in the future.

The system dynamics analysis illustrated that the industry uses inventories to manage the systems inefficiencies and that capacity acquisitions can overshoot demand thereby creating overcapacity situations that result in reduced profits and the closing of marginally profitable refineries.

Existing levels of inventories are maintained at levels that can absorb routine system disruptions. Current inventory levels would not be able to handle low probability, high impact events such an extended closure of the Enbridge pipeline into Ontario which provides 85% of the orbits feedstock. Although such events may occur rarely they would have a major impact on the economy of Canada. A strategic petroleum reserve of RPP held in the orbits that are subject to these midstream constraints would reduce the consequences of these events. The holding costs of such a reserve would increase the cost of RPP in Canada however the impact of disruption could be massive.

Demand and the expectation for demand can change much more rapidly than the industry’s ability to respond to them. Consequently, the industry often overprovides or underprovides capacity which coupled with delays in adding capacity can generate into a negative feedback cycles that reduces or adds capacity at inappropriate times and reduces industry profitability. As capacity demand shortfalls can be covered with imports, over capacity situations are the more harmful to industry profitability.

Finally, to response to our research questions, the Canadian Refining Infrastructure should be able to meet Canada’s future needs however it has developed specific system rigidities and production shortfalls which need to be addressed. The industry moves and transforms a remarkable volume of crude into RPP each day however demand can quickly change while the industry’s ability to respond to these changes is systemically delayed. The industry should be careful in responding to these changes so Page 75

A Strategic Analysis of Petroleum Refining Infrastructure In Canada as not to create capacity issues which reduce profitability. Accordingly, consideration should be given to the following recommendations:

 More flexibility is required in midstream options in the Ontario and Western orbits. Ontario should add additional pipeline options to transport crude and RPP into the orbit while the Western Orbit should expand its ability to move RPP into the orbit and crude out of the orbit.

 A Strategic Petroleum Reserve of RPP should be considered in the Ontario and Western orbits to reduce the potential damage from a low probability, high impact event.

 Capacity should be added in the Western, Ontario and possibly the Quebec orbits to meet current demand and future growth expectations. Small scale refinery options located in localized pockets of demand should be considered such as a bitumen- to-diesel plant in Fort McMurray or a small cracking plant in the North West Territories rather than a centralized large scale refinery.

The enactment of these recommendations should provide Canadian refining infrastructure the flexibility and capacity to continue meeting the needs of Canadians.

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Appendix 1 – Acronyms, Units and Conversion Factors

Acronyms and Units

API - American Petroleum Institute’s specific gravity scale measuring the density or viscosity of petroleum liquids in degrees API

BP – British Petroleum bpd – barrels per day

CAGR - Compounded Average Annual Growth Rate

CEPA – Canadian Energy Pipeline Association

CERI – Canadian Energy Research Institute

CAPP – Canadian Association of Petroleum Producers

CDU - Crude distillation unit

DOE – US Department of Energy

EIA – Energy Information Administration of the US Department of Energy

FCCU - Fluid catalytic cracking unit gwh – gigawatt hours of electricity

IEA – International Energy Agency

NEB – National Energy Board of Canada

NRC - Natural Resources Canada

PADD – Petroleum Administration for Defence District

ROCE – Return on Capital Employed

RPP – Refined petroleum Products

SD – Systems Dynamics

TNPL – Trans Northern Pipeline; transports RPP from Montreal Quebec into the Ontario supply orbit

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WTI – West Texas Intermediate oil blend

Conversion Factors

One cubic meter = 6.2893 barrels of oil

One cubic meter = 1000 litres

One Barrel of oil = 159 litres

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