Group 7 Ice-Fili Analysis

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

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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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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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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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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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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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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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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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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.


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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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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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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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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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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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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.


Page 17

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 18

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.


Page 19

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;


Page 20

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)

http://www.cepa.com/wp-content/uploads/2011/06/barrel-grey1.gif


Page 21

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


Page 22

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

Crude Oil

Slate

Mid-stream

Options

Refinery

Configuration

and Capacity

Product

Slate

Yield

Refined

Product

Demand


Page 23

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).


Page 24

Figure 12 - Ownership of Canadian Refinery Capacity

Company Capacity

(bpd) % Total

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.


Page 25

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

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)


Page 26

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)


Page 27

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.


Page 28

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.


Page 29

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.


Page 30

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


Upgraded Synthetic 0

Heavy Oil 2,712

Total Orbit Supply 86,255

Crude Imports (Domestic) -


Crude Exports -



Refinery Charge Production 427,160


Refinery Production 447,777



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.


Page 32

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.


Page 33

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


Page 34

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.


Page 35

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


Heavy Oil 0

Total Orbit Supply 0

Crude Imports (Domestic)

26,429


Crude Exports 0





Refinery Gross Production 353,982



Adjustments/Interprovincial - 28,084


Demand

Gasoline 154,728

Diesel 90,799

Heavy Fuel 22,360

Other Fuels 86,614



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 36

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.


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.


Page 37

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


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


Page 38

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.


Page 39

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 40

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


Heavy Oil 0

Total Orbit Domestic Supply 1

Crude Imports (Domestic) 299,711


Crude Exports

Inventory Build (draw) 319




Refinery Gross Production 459,970





Demand

Gasoline 288,074

Diesel 123,159

Heavy Fuel 8,861

Other Fuels 153,834



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


Page 41

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.


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.


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Figure 28 - Ontario Orbit's Capacity


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


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


Refined Charge Production 616,287


Refinery Production 648,552





Demand

Gasoline 230,350

Diesel 254,439

Heavy Fuel 19,320

Other Fuels 183,576




Page 46

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.


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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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


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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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

can supply 45% of domestic demand. Primarily light/medium crude.

Supply is 92% imported, 8% provided from outside orbit. Supply is 86% light sweet, 13% heavy conventional.

Supply is provided from Western Orbit or imported. Supply is 80% light or synthetic, 20% heavy or bitumen blend.

Domestic supply exceeds demand by over a million bpd. Production is 80% heavy and 20% light oil

Midstream Access to deep water ports connects Orbit to global oils markets.

Access to waterways connects orbit to global markets. Pipelines moves RPP from Quebec into Ontario.

Supply is brought into orbit primarily through one pipeline source. RPP is also shipped from Quebec to Ontario through a single pipeline.

Various pipelines can transport 3.5 million bpd out of orbit. Large area with limited capacity to move RPP into orbit.

Refineries Three refineries have capacity to refine over 300,000 bpd more than demand. Capacity is 504,000 bpd. 2011 utilization was 85%.

Two refineries can meet demand if they operate at 93% capacity. Capacity is 395,000 bpd. 2011 utilization was 89%; average over the last ten years was 93%.

Orbit is dependent on imports as the five refineries capacity only supports 86% of demand. Capacity is 478,000 bpd. 2011 utilization was 90% of capacity.

Eight refineries still required 80,000 bpd of imports to balance 2011 demand. Capacity is 633,000 bpd. 2011 utilization was 97%.

Product Demand

Orbit demand was 202,000 bpd in 2011



Orbit demand was 688,000 bpd in 2011.


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Capacity exceeds product demand. Exported 238,000 bpd in 2011.

Small gasoline and aviation fuel deficits exist but are easily covered off by product movements into Ontario.

Production shortfalls of 133,000 bpd of gasoline and 42,000 bpd of diesel exist. Demand is balanced through imports.

Production was short 42,000 bpd of gasoline and 45,000 bpd of diesel in 2011. Demand growth is strong especially for 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.


Page 55

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


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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

Crude Slates

Midstream

Options

Refining

Cap acity

RPP Inventory

RPP Demand

Domestic Crude

Supp ly

Imp orted Crude

Supp ly

Feedstock

Supp lyRate

Product Yield

Midstream/Distribution

Constraint

Midstream

Cap acity

Midstream

Constraint

Imp orts

Substitutes

MidstreamConstraints

Compliments

Exports


Page 62

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

Crude Slates

Midstream

Options

Refining

Capacity

RPP Inventory

RPP Demand

Domestic Crude

Supp ly

Imported Crude

Supp ly

Feedstock

Supp lyRate

Product Yield


Constraint

Midstream

Capacity

Midstream

Constraint

ImportsMidstreamConstraints

Demand

Expectation

Utilization decision

Import decision

Refine or Import

Decision

Exports

Substitutes

Compliments

Pricing decision

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 64

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%).


Page 65

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 66

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

Crude Slates

Midstream

Options

Refining

Cap acity

RPP Inventory

RPP Demand

Domestic Crude

Supp ly

Imp orted Crude

Supp ly

Feedstock

Supp lyRate

Product Yield


Constraint

Midstream

Cap acity

Midstream

Constraint

Imp ortsMidstreamConstraints

Long Run Return onCap ital Employ ed

Expectation

Demand

Expectation

Market

Opp ortunity

Cap acity

Addition

Regulatory &

Construction Delay

Exports

Price decision

Substitutes

Compliments


Page 68

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


Page 69

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.

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.

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%


Page 70

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


Page 71

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 73

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 74

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


Page 75

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 76

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.


Page 77

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Page 84

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


Page 85

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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