CREEnergy P r o s p e c t u s

CREEnergy Oil & Gas

(CROG)

PO Box 595 Frog Lake, Alberta T0A 1M0

C/O 16301-107a Ave NW Edmonton. Alberta T5P 0Z4

Office 780 484 5506 Cell (780) 999-6110

Email: creenergyinc@gmail.com

CREEnergy P r o s p e c t u s

CREEnergy Refining and Oil Security

July 2016

Table of Contents

1. Introduction

2. Executive summary

o 2.1 The World

o 2.2 Canada

o 2.3 The Future

o 2.4 The Challenges

o 2.5 The Task

3. Background

4.World oil Market context

o 4.1 How Oil Markets Work

o 4.2 Crude Oil Prices

o 4.3 World Oil Supply and Demand

o 4.4 World Oil Reserves

o 4.5 Past Disruptions

5. Canadian Oil Markets- a 10 year perspective

o 5.1 Political Framework

o 5.2 Reserves

o 5.3 Oil Production

o 5.4 Oil Pipelines

o 5.5 Refining Infrastructure

o 5.6 Refinery Economics

o 5.7 Crude Slate

o 5.8 Refinery Configuration

o 5.9 Refinery Utilization

o 5.10 Petroleum Product Supply and Demand

o 5.11 Product Distribution

o 5.12 Distribution Infrastructure

o 5.13 Regional Product Movements

o 5.14 Inventories

o 5.15 Product Prices

6. Regional Analysis

o 6.1 Western Canada

o 6.2 Ontario

o 6.3 Quebec-Atlantic Canada

o 6.4 Northern Communities

7.Where are we headed by 2018

o 7.1 Renewable Fuel Standards

o 7.2 Clean Air Agenda

o 7.3 New Refinery Capacity

o 7.4 Pipeline Capacity

o 7.5 Heavier Crude Slate

o 7.6 Prospects for East Coast Offshore Development

o 7.7 Dieselization of the Vehicle Fleet

8. Market Vulnerabilities and Risk Factors

o 8.1 Environmental Regulations

o 8.2 Renewable Fuel Standard

o 8.3 Tighter Fuel Specifications

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o 8.4 Consistency of Fuel Specifications

o 8.5 Sources for Alternate Supplies

o 8.6 Distribution Network

o 8.7 Pipeline Capacity

o 8.8 Aging Refining Infrastructure

o 8.9 Geopolitics

o 8.10 Terrorism

o 8.11 Weather-related Issues

9. Regional Perspective

o 9.1 Western Canada

o 9.2 The North

Annexes

o Annex A - Canadian and U.S. Crude Oil Pipelines

o Annex B - 2014 Canadian Refining Capacities

o Annex C - Proposed Refinery Projects

o Annex D - List of Acronyms

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1. Introduction

Oil markets are volatile and trying to conduct a static analysis is always a challenge. When work was begun on

this project oil prices were at an all-time high and were breaking new records every day.The events of the last

few months indicate how quickly markets can change. The recent economic downturn has resulted in significant

declines in oil prices and a weakening of the Canadian dollar.

Clearly these events will have some influence on where oil markets go in the coming decade. The paper tries to

identify the areas that may be affected by this shift in market conditions. However, at this time, it is difficult to

know where oil prices will settle and how these prices will affect industry plans. We have therfore tried to

minimize our cashflow projections to show profitabilty regardless of the price of oil, based on a fluctuating

gasoline and diesel demand

There are a few market fundamentals that will not change:

the marginal cost of producing a barrel of oil is slightly lower today than it was 2 years ago;

oil prices are not likely to return to the $160/bbl range in 2017;

the era of "WTI" oil is over due to the Global production;

the world will continue to be reliant on oil for the foreseeable future, particularly in the transportation

sector;

demand in emerging transportation giants like CNR and BC Ferries will continue to order

there will be a constant supply to meet demand for First Nation Gas Outlets.

The changing economic conditions will not reduce our First Nation petroleum product but will be in demand.

2. Executive Summary

CREEnergy Oil and Gas Inc. (“CREEnergy”) is an Alberta corporation formed in 2007 as the first Aboriginal

Company dedicated to oil and gas development on First Nation reserves and build min-refineries in Canada

and the USA. After a lengthy study and consultation with Chiefs and Council Members, CREEnergy has

selected a USA partner with investment money and ready to proceed.

We have found that many First Nation Reserves have probable or proven oil and gas reserves and are located

within or near producing oil fields. CREEnergy with the credibility to work closely with the Elders, Chiefs and

First Nations Councils to ensure an orderly development of their natural resources. Through these positive

relationships CREEnergy has the ability to interact and secure land assets on First Nation reserves with high

potential for oil and gas development. The ability to diversify leases across ten different First Nations reserves

and approximately 200 square miles of land in Manitoba and Alberta, and to select the best land based on

exploration results, is unique to CREEnergy and has been accomplished.

CREEnergy will comply fully with all applicable Government Acts and Regulations. This provides the

accountability to meet technical, social, environmental and other regulatory standards. CREEnergy must

ensure a solid partnership is in the best interests of the members of each partnering First Nation. In this

way, CREEnergy can assure our investing joint venture partners a stable and profitable working relationship

has achieved and we are ready to build a mini-refinery and to develop oil and gas reserves on our other First

Nations partners leased lands.

Joint Venture Opportunity

CREEnergy P r o s p e c t u s

CREEnergy’s USA JV partner with a positive working relationship and well funded joint venture agreement is

enthusiastic in a high volume hydrocarbon extraction and manufacturing. Working as a team in partnership we

will develop oil and gas into production on leased lands owned and controlled by CREEnergy’s First Nation

Partner for our mini-refinery. Our intent is to secure up to 20 acres under lease (twenty acres) for storage, future

development purposes and building of a tank farm and the mini-refinery.. This production utilizing new wells

and shut-­in wells is targeted only by CREEnergy to achieve a potential of more than 100,000 bbl/day. In order

to further maximize profitability, development of two mini-­refineries have been assessed and one chosen for

southern Alberta and the other First Nation in Northern Alberta.

In consultation with a Band Council and approval is granted ,the land is explored and decisions made on which

areas to secure under a lease, then the funding from a USA JV partner, through a Trust Account, will be used to

secure the appropriate leases on the targeted First Nations lands and development will proceed.

The process and legal structures to secure these leases may vary between First Nations. It is most likely that a

Limited Partnership (“LP”) between each First Nation and CREEnergy will be used. Lease agreements would

then be made between the Limited Partnership and CREEnergy.

Canada is currently the third

‐ largest producer of natural gas and the ninth

‐ largest producer of crude oil in the world

First Nation has .5% of oil reserves and .1% of natural gas reserves in North America. The majority of the

opportunities exist in Western Canada, home to 1,000’s of First Nations traditional and reserve lands.

Clearly, oil and gas development must take into account Aboriginal treaty, title and rights. Aboriginal

involvement or consultation is the primary vehicle for understanding and reflecting Aboriginal rights in

development projects. The legal and regulatory requirements governing consultation are continuously evolving

based on new legal decisions and are considered the minimum requirements for meaningful engagement of

Aboriginal peoples. In lieu of finalized legal procedures, it is advisable for industry to meet or exceed the

currently accepted practices, in order to ensure timely development of their mineral rights holdings.

Successful development of Canadian petroleum reserves largely depends on reasonable and timely access to

resources and perceived investment security. Understanding Aboriginal issues, such as land claim issues and

requirements for consultation, represent a key aspect of achieving timely access to oil and gas resources.

More recently, an unprecedented number of First Nations group are creating their own future in corporate

Canada. This proposal offers a unique proposition to partner with First Nations oil and gas company, that in

turn presents multiple opportunities to partner with many different First Nations.

The goals of this business plan are

to:

1) Link CREEnergy with First Nation with operating and financing opportunities in order for the oil and

gas resources located on Indian Reserve lands will be developed in a sustainable manner;

2) For the economic benefits derived from these resources-­operator/owned based business opportunities

to flow back to the First Nation communities and individual band members, and in turn stimulate increased

educational, occupational and small business opportunities; and,

3) To build oil refineries from the ground up for the first time in 20 years, by way of joint venture

agreements between CREEnergy and First Nations Chief and Council .

We propose that with a partnership policy in which the First Nation retain the federal and provincial excise tax,

as well as the GST/HST, it would be economically viable not only to build and operate a refinery, but also create

a substantial First Nations “social and economic development fund.” This fund will be dedicated to creating and

stimulating economic growth for all First Nations in Western Canada. We view this as an excellent opportunity

CREEnergy P r o s p e c t u s

to move forward with a substantive project between your Nation that will inject millions of dollars into your

community as well the Federal and Provincial Governments grants available. There will be political and social

benefits realized in each of the three governments as well as benefits for our people.

The Federal Government endorses this concept in their 2009-2010 Indian and Northern Affairs

Canada and Canadian Polar Commission Report on Plans and Priorities:

“The proposed strategies for First Nations governance over land, resources and the

environment seek to ensure that optimal conditions exist to attract investment; to

maximize the socio-­economic benefits flowing from lands and resources under the

control and management of First Nations and Inuit communities; and to foster strategic

partnerships and joint ventures to seize opportunities associated with development of land

and resources.”… “Some of our key partners are First Nations governments interested in

assuming jurisdiction and developing the necessary legislative instruments, through such

means as the First Nations oil and gas pilot projects.”

It is the Government of Canada’s position to assist First Nations with sustainable resource projects well into the

future. We believe as a Treaty First Nation that matters such as excise tax on oil and gas may be negotiated by

policy on a government-­to-­government basis regarding the Host Nation retaining the excise taxes as well as

the GST. This policy will be in the form of an agreement between the First Nations, and Provincial Government

and the Federal Government of Canada.

Also from the Northern Affairs Canada and Canadian Polar Commission Report – “On the positive side,

provincial governments increasingly view Aboriginal economic development as a priority, particularly in the

western provinces, where there is great potential for partnerships with the co-­op movement; other investors and

public-­private partnerships also show potential to build on success models and develop First Nations financial

institutions where they have total control or 70%.”

Estimated Capital Requirements

The Partnership agreement will confirm the following:

• An exclusive contract based on specific terms for which the joint venture will exist,

• A 50 percent partnership with CREEnergy for the sharing of all earnings

• An initial non-­refundable down payment to CREEnergy if extension negotiated

• A deposit of $60 million USD will be made by the Host First Nation partner at the start of the contract

held in trust for securing leases and setting up Limited Partnerships

• An estimated total of about $120 million USD (CREEnergy’s balance of $60 million USD)

will be required to build one (1) refinery additives plant and one (1) 20,000 bbl/day refinery

The following table is a summary of estimated capital requirements:

Description Amount (USD $)

Oil refinery (20,000 bbls/day capacity) 41,000,000 $

Refinery additives plant 1.

34,000,000

Lease acquisition and lease infrastructure 2.

4,400,000

Exploration/ Engineering testing 3.

3,000,000

Shut-in well work overs 4.

3,000,000

oil purchase/old wells 5.

33,000,000

Working capital 1,600,000

TOTAL 120,000,000 $

Capital Requirements & Use of Proceeds

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2.1 The World

Oil $ year One Two Three Four Five

Oil prod (bopd) 2875 9731 18508 27156 34344 Refinery (bopd) 20000 20000 20000 20000

Revenue $ %

Oil /YY 43.908333 45445124.7 1 153817915.8 0.73 292555953.8 0.69 429254888.7 0.59 542875603.9 0.79

Adpak 0 0 18188877.02 0.46 43653906.91 0.46 44802618.55 0.46 45950846.23 0.46

Refinery 0 0 39148983.77 0.25 93960195.68 0.32 96430127.6 0.22 98902695.83 0.18

net of crude cost 45445124.7 1 211155776.6 98.5 430170056.4 101 570487634.9 81.4 687729145.9 97.2

Expenses

Oil production 15548594.9 0.3421 52521189.76 0.25 100183560.1 0.23 146480173.6 0.26 185476026.8 0.27

Adpak 0 0 11957279.91 0.06 27914814.68 0.06 27444531.37 0.05 27461694.65 0.04

Refinery 0 0 21546446.3 0.1 51711473.76 0.12 53072299.23 0.09 54433127.81 0.08

15548594.9 0.3421 86024915.97 40.7 179809848.5 41.8 226997004.3 39.8 267370849.2 38.9

EBITDA 29896529.7 65.786 125130860.7 57.7 250360207.8 58.9 343490630.6 41.6 420358296.7 58.3

Refinery gals/bbl $/gal

Gasoline 19.5 2.18 42.51

Diesel 9.2 2.7 24.84

Jet Fuel 4.1 2.28 9.348 CREEnergy

Kerosene 4.2 3.82 16.044

Naphtha 3.7 2.44 9.028 0.232892919

Isopentaine 0.2 3.2 0.64 0.06489251

Feed Stock 1.5 2.1 3.15 0.1202117

Lubricants 0.5 2 1

Asphalt & rd o 1.3 1.85 2.405 80.908333

Total 44.2 108.965

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The last ten years have seen significant price fluctuations in world oil markets and periods of increased volatility

and record-setting prices. During the period January 1998 to December 2007, nominal monthly prices for WTI,

the North American marker, ranged from about $11/bbl to $95/bbl, averaging just over $38/bbl. By July 2008,

the monthly average had reached $134/bbl.

The effect of higher nominal prices on economic growth has been muted by continued progress in lowering

energy intensity.

In spite of record-setting oil prices in recent years, world oil demand continues to grow. Over the 10-year period

of 2005-2015, world demand for oil grew at a rate of about 1.6% per year. However, there was a shift toward the

non-OECD countries, particularly China and India, who have been accounting for much of the growth in

demand.

The source of the world's oil supply is also shifting. Production in OECD countries has declined by about 10%

since 1998. Helping to offset this decrease, production in countries such as Russia, China and other non-OPEC

nations rose by 31% over the 10-year period, increasing their share of total supply from 30% in 1998 to 35% by

2007. However, more than a third of world oil supply continues to come from OPEC. While OPEC's production

increased by 15% over the ten-year period, its share of total world supply held relatively constant at 41%.

OPEC's spare capacity had remained relatively stable, in the range of 3-4 MMBD, for most of the last decade.

In spite of all of the price volatility and political unrest in the last 10 years, there has never been a physical

shortage of crude oil that the world market could not satisfy. There have, however, been local supply disruptions

resulting from problems with refinery operations that have created temporary shortages or severe supply

constraints in certain markets, both in Canada and elsewhere in the world.

The world's proven oil reserves have increased in all but one of the last 17 years. This growth has been the result

of new finds, the inclusion of oil sands reserves in 2010, and the continued development and application of new

drilling technology and enhanced recovery methods.

2.2 Canada

Canada's proven oil reserves, at 179 billion barrels, are second only to Saudi Arabia's. More than 95 per cent of

Canada's established oil reserves are in the form of oil sands.

Canada is currently the 7th largest oil producer in the world. Canada's crude oil production has risen fairly

steadily over the past decade from 2.1 million barrels in 2004, to 2.8 million barrels in 2013. While conventional

sources continue to provide more than half of crude oil production, the oil sands have been responsible for most

of the growth in recent years.

Canada produces more crude oil than it consumes and is a large and growing net exporter of crude oil. However,

crude oil imports satisfy more than half of domestic refinery demand. The transportation costs associated with

moving crude oil from the oil fields in Western Canada to the consuming regions in the east and the greater

choice of crude qualities make it more economic for some refineries to use imported crude oil.

Over the last decade, Canada's crude oil imports grew from 770 MBD to 859 MBD. Canada has become

increasingly reliant on oil from OPEC countries, which now account for 49% of all imports of crude oil into

Canada.

Oil pipeline systems were at or near capacity in 2012 and a number of proposals have emerged to provide

additional pipeline capacity to transport crude oil and to provide additional supplies of diluent required to support

growing oil sands operations. This additional pipeline capacity, if approved, will enhance access to markets and

increase market penetration of Canadian crude oil.

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In the 1970s and early 1980s the Canadian refining sector closed down small inefficient facilities, which could

not be economically retrofitted to accommodate Canada's cleaner fuel standards, and replaced them with new

larger installations. Today, Canada has more than double the refining capacity at its 16 refineries that

manufacture the full range of petroleum products than it had when there were 44 refineries in the 1960s.

In recent years, growth in the demand for petroleum products has led to an improvement in capacity utilization,

increasing operating efficiency and reducing costs per unit of output. As a result, refinery utilization rates have

been above 90% nationally for six of the last ten years.

There have been no new refineries built in Canada since 1984. Historically, refining margins have been poor,

discouraging investments of this magnitude. The significant capital investments required in existing refineries to

meet evolving product specifications and environmental regulations have made it more difficult to attract the

capital for capacity expansions or new builds.

Since 1998 demand for petroleum products has been growing steadily at a rate of about 1 percent per year.

Gasoline demand has increased slightly in most of the last 10 years. The distillate demand (diesel oil, furnace oil

and kerosene), driven primarily by on-road diesel requirements, has been the fastest growing component since

1993.

Distribution challenges arise from the fact that petroleum products are refined in only a few geographic regions

but they are consumed all across Canada.

Western refineries supply all product demand from Vancouver to Thunder Bay, including the northern territories.

Refiners in southern Ontario move product to Sault Ste-Marie and northern Ontario. Montreal and Quebec City

facilities supply the St Lawrence River corridor from Toronto to the Gaspé Peninsula, as well as the more remote

areas of northern Quebec and occasionally parts of the Arctic. Petroleum products from the three Atlantic

refineries find their way to the Arctic and Hudson Bay regions as well as the U.S. eastern seaboard.

The logistics network required to supply petroleum products from the refineries to the end-users is a complex

system of pipelines, ships, railways and trucks. Often several methods of transportation are utilized to move

petroleum products from the refineries, ports and large terminals to tremendously disperse markets all across the

country.

The Canadian downstream petroleum industry can be broken into three distinct regions: Western Canada,

Ontario and Quebec/Atlantic Canada. Some regions are better suited than others to import products. Because of

their connection via major waterways, Atlantic Canada and Quebec have good access to supplies from the

northeastern United States and Europe.

Ontario also has access to supplies from large U.S. markets and can also bring in products via Quebec. In 2005

Ontario shifted to a net import position with the closure of the Oakville refinery and increased product

movements from Quebec refineries. However, logistical constraints, such as the size of ships that can navigate

the St. Lawrence Seaway and the seaway shipping season, increase the cost of these supplies. Other modes of

transportation, such as pipeline, unit train and trucking, are necessary to bring products from other regions.

Most of Western Canada is landlocked, and as such, has very limited access to supplies from other regions. The

current infrastructure was not designed to transport supplies to the prairies from other regions. However, the

prairies supply a substantial volume of gasoline into the Vancouver market. In the event of a supply shortage in

the prairies, refiners have the ability to balance supply and demand by importing gasoline into Vancouver to free

up additional product from Edmonton refiners for the prairie markets.

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2.3 The Future

Integrating bio-fuels into the Canadian petroleum product distribution system will affect all refiners, distributors

and marketers of petroleum products. The different properties between regular gasoline and ethanol-blended

gasoline will affect not only production, but distribution and storage of gasoline as well.

Rates of return on capital employed have improved to levels where the refining industry is now considering

significant new investment in capacity expansion.

These projects will face a number of hurdles, including the current economic slowdown. Margins must be

sustainable for several years. The regulatory approval process for a new refinery can be very onerous and time

consuming. In spite of the public call for more capacity to ease pressures on prices, few communities want a

refinery in their backyard.

Oil sands development continues to fuel expansion and construction of new pipelines to deliver crude oil to both

traditional and new markets. Crude oil pipeline capacity out of western Canada continues to be tight and at this

time there is an inherent lack of flexibility in the system. Current proposals before the NEB indicate that the

market expects pipeline capacity to increase gradually to meet expected growth in supply. It is still unclear how

recent economic events will affect these decisions.

As Canadian producers look to diversify their customer base, market conditions could make it more economical

for more Canadian oil to move to Ontario and other eastern Canadian markets. A proposal is being considered to

re-reverse Enbridge's Line 9, which currently transports crude oil from Montreal to Sarnia. In addition, refineries

in Atlantic Canada could also access western Canadian crude if Line 9 is reversed along with a portion of the

Portland to Montreal Pipeline which currently operates only in northbound service. This could significantly

reduce eastern Canada's reliance on imported crude oil.

2.4 The Challenges

Once ethanol is fully integrated into the Canadian gasoline distribution system, there will be an added

element of vulnerability in the supply network. The gasoline blending component cannot be used

without the ethanol component added to it. If the ethanol supply were to be disrupted, not just the 5% or

10% that is ethanol, but the entire gasoline pool, would be lost.

The on-going move toward increasingly cleaner products can reduce the flexibility of the product

supply and distribution network. In some cases, refiners will need to sacrifice volume in order to

achieve a cleaner output.

Maintaining the integrity of products that have very strict specifications also presents distribution

challenges. Pipelines that move a variety of products need to carefully plan their batches to minimize

product contamination and volume losses.

Differing fuel specifications between jurisdictions (across both provincial and international borders)

make it more difficult to import petroleum products into regions when there are supply problems. If

product must be blended specifically to meet unique provincial or Canadian requirements, it will be

virtually impossible to import small volumes or to find supply on short notice.

It is becoming harder to secure trucks and/or truck drivers to transport product on an ad-hoc basis. Rail

availability is also becoming tight. Longer lead times required to transport goods have made rail less of

a viable option in situations where product needs to be moved quickly. This situation is expected to

worsen in coming years.

With existing capacity nearly fully utilized, equipment aging and refinery operations becoming more

complex, petroleum product markets are increasingly vulnerable to unplanned refinery shutdowns. The

number of incidents that disrupt demand can be expected to increase as new fuel quality and

environmental standards continue to apply pressure on both refineries and the distribution system.

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With five of the six largest oil reserve holders located in the Middle East (Canada is number 2),

political tensions in this region will continue to influence oil markets for the foreseeable future. Even

when political activities occur in Middle East countries that do not produce oil, the fear that the action

could spill over into oil producing nations, triggers a reaction in oil prices.

Closely linked to the geopolitics of the Middle East is the increased threat of terrorist activities that

could disrupt oil supplies. Since the terrorist attacks on September 11, 2001, security of energy

infrastructure has drawn significantly more attention both in Canada and around the world. The ever-

present threat of further terrorist events adds a new level of uncertainty to the security of oil supplies

and has added a fear premium to the price of oil on the futures market. Domestic terrorism is also on the

rise.

Severe weather events have also been on the increase in recent years. Hurricanes, tornados, ice storms,

floods and tsunamis have all disrupted either oil production or refined product supplies over the last

decade. Scientists are predicting an increase in such extreme weather conditions that often provide very

little lead time and offer few defence options.

2.5 The Task

In light of these changing market dynamics, governments and industry need to evaluate the vulnerabilities, assess

the risks associated with them and re-examine the tools available to address those risks.

3. Background

In recent years the Canadian petroleum product market has become increasingly vulnerable to supply disruptions.

Canadian refineries are operating consistently at or near capacity. Demand for petroleum products is growing,

despite escalating consumer prices. More stringent environmental regulations with respect to fuel quality and

facility emissions are diverting investment dollars away from capacity expansions. Aging refineries are being

pushed to maximize output and, as a result, there has been an increase in the number of incidents that required

unplanned shutdowns.

Tighter markets lead to more uncertainty about the supply of oil and petroleum products and add further upward

pressure on already record-high consumer prices. Consumers turn to governments for assurances that there will

be an adequate supply of fuels, such as gasoline, diesel fuel and home heating oil, at reasonable prices. However,

they also want strong leadership on the environmental front and expect cleaner fuels and fewer emissions.

In developing a strategy for managing these complex issues, the industry and governments are faced with

challenges that often have mutually exclusive solutions. Addressing security of supply concerns in the context of

the environmental agenda will require careful consideration of a number of issues.

The events of the last few years have created a market that is significantly different from any in the past.

Solutions such as the creation of a strategic petroleum reserve are being proposed in a number of public fora. It

is, therefore, timely to re-examine some of these security of supply issues, in the context of today's market

realities.

This paper will discuss some of the changes in Canadian and world oil markets over the last decade, examine

some of the anticipated market pressures in the coming years, and provide a framework for a discussion of the

market vulnerabilities and risk factors associated with petroleum product supply in Canada. Possible actions by

industry and the provincial and federal governments will be identified.

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4. World Oil Market Context

4.1 How Oil Markets Work

Since the deregulation of Canadian oil markets in 1985, the price of Canadian crude oil has been determined by

international oil markets. Oil is traded widely all around the world and can move from one market to another

easily by ship, pipeline or barge. Therefore, the market is worldwide and the supply/demand balance determines

the price for crude oil all around the world. If there is a shortage of oil in one part of the world, prices will rise in

that market to attract supplies from other markets until supply and demand are in balance. If there is a surplus in

a region and the price drops, buyers will soon be drawn to that market. Prices vary only to reflect the cost of

transporting crude oil to that market and the quality differences between the various types of oil. The global

nature of the market also explains why events anywhere in the world will affect oil prices in every market.

In addition to all of the actual barrels of oil that are physically traded, there is a second market that trades in

"paper" barrels. This simply indicates that oil is traded on paper based on a perceived monetary value of oil and

there is not usually a physical exchange of the product. In these futures markets, paper contracts for oil are

bought and sold based on the expected market conditions in the coming months, or even years.

There are two types of buyers and sellers in the futures market: those that are actual producers or users of crude

oil and those who buy futures contracts as an investment, without any intention of ever taking possession of the

actual crude oil. The first group uses the futures market to protect themselves from price volatility by locking in

either their costs or their revenue. The second group is made up of investors who can make money by correctly

guessing whether prices will increase or decrease in the future.

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In the spot market, oil is bought and sold for cash and delivered immediately. The current spot price for oil is

influenced by the futures market price because the futures price represents the market's collective view, at a

given point in time, of where prices may be headed.

4.2 Crude Oil Prices1

The last ten years have seen significant price fluctuations in world oil markets and periods of increased volatility

and record-setting prices.

There are three major world crude oil price markers (West Texas Intermediate (WTI), Brent and the OPEC

Basket), all measured in nominal US dollars. During the period January 2007 to December 2010, nominal

monthly prices for WTI, the North American marker, ranged from about $11/bbl to $130/bbl, in 2015 it is now

averaging just over $38 /bbl.

Figure 1: Crude Oil Prices January 2010 to July 2014

The price of oil closed above $100/bbl for the first time on February 19, 2011, with concerns about new OPEC

production cuts, a weakening US dollar and geopolitical uncertainty involving Nigeria and Venezuela. After

peaking at $147 in mid-July 2011 and averaging $134/bbl for the month, prices declined, and by October 2014

were trading in the $60/bbl range.

1 All crude oil prices are in US dollars per barrel unless otherwise noted.

4.3 World Oil Supply/Demand

In spite of record-setting oil prices in recent years, world oil demand continues to grow. Over the 10-year period

of 2004-2015, world demand for oil grew at a rate of about 1.6% per year. However, there was a shift toward the

non-OECD countries, particularly China and India, who have been accounting for much of the growth in

demand. While OECD countries saw their demand grow by only 5% in the 10 year period, non-OECD demand

increased by 35%. In 2004, non-OECD countries accounted for 37% of world demand, compared to the OECD's

share of 63%. By 2007, non-OECD's share of total demand was 43%. Although Chinese oil demand is still only

one-third of the U.S. demand, on a percentage basis, China's demand grew at nine times the U.S. rate between

2003 and 2007.

Table 1: World Oil Supply and Demand 2005-2014 (million barrels per day)

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Demand

OECD 47.0 47.9 47.9 48.0 48.0 48.6 49.4 49.8 49.6 49.2

non-OECD 27.3 28.1 28.7 29.3 30.0 31,0 33.1 34.2 35.5 36.9

TOTAL 74.3 76.0 76.6 77.3 78.0 79.6 82.5 84.0 85.1 86.1

Supply

OECD 21.9 21.5 21.9 21.8 21.9 21.6 21.2 20.3 20.0 19.8

OPEC 31.0 29.6 31.0 30.5 28.9 30.8 33.1 34.2 34.3 35.5

Other non-OECD 23.1 23.5 24.3 25.1 26.3 27.6 29.1 30.2 31.2 30.3

TOTAL 76.0 74.6 77.2 77.4 77.1 80.0 83.4 84.7 85.5 85.6

Stock change 1.7 -1.4 0.6 0.1 -0.9 0.4 0.9 0.7 0.4 -0.5

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The source of the world's oil supply is also shifting. Production in OECD countries has declined by about 10%

since 2007, as the more mature fields of the North Sea begin to decline. Helping to offset this decrease,

production in countries such as Russia, China and other non-OPEC nations rose by 31% over the 10-year period,

increasing their share of total supply from 30% in 2007 to 35% by 2012. However, more than a third of world oil

supply continues to come from OPEC. While OPEC's production increased by 15% over the ten-year period, its

share of total world supply held relatively constant at 41%.

World oil markets have remained well supplied throughout that last decade. In fact, in seven of the last ten years,

supply exceeded demand and there was a slight stock build. However, with OPEC accounting for 40% of world

supply and most of the spare production capacity also in OPEC countries, any indication of a potential supply

disruption in the Middle East or producing nations such as Nigeria or Venezuela will lead to upward pressure on

prices.

Figure 2:

OPEC's spare capacity had remained relatively stable, in the range of 3-4 MMBD, for most of the last decade.

The only exception was in 2001-2 when a sharp decline in oil demand following the September 2001 terrorist

attacks forced large cutbacks in production and pushed spare capacity up to 6-7MMBD. In spite of all of the

price volatility and political unrest in the last 10 years, there has never been a physical shortage of crude oil that

the world market could not satisfy.

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4.4 World Oil Reserves

One of the benefits of higher prices has been that some of the more expensive oil sources in more remote

locations have become economic to develop. The world's proven oil reserves have more than doubled in the last

27 years. Reserves have increased in all but one of the last 17 years. This growth has been the result of new finds,

the inclusion of oil sands reserves in 2003 and the continued development and application of new drilling

technology and enhanced recovery methods. Historically, only 20-30% of the oil in a well was recoverable. With

today's technology, many wells now recover 40%, 50% or higher of the oil initially in place, and that incremental

oil continues to add to proven reserves.

Figure 3: Global Growth in Proven Oil Reserves (Billion Barrels)

Source Oil and Gas Journal.

World proven oil reserves have more than doubled in the last 28 years (from 642 billion barrels on January 1,

1987 to 1,332 billion barrels on January 1, 2015).

4.5 Past Disruptions

In the last 50 years there have been nine significant oil supply disruptions, the largest occurring during the

1978/79 Iranian revolution. This resulted in a supply shortfall of approximately 5.6 MMBD (million barrels per

day) for a period of 6 months.

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The events in the 1970s triggered the establishment of the International Energy Agency (IEA), a group of

consuming countries that have developed contingency plans to deal with future oil supply disruptions.

IEA net oil importing countries have a legal obligation to hold emergency oil reserves equivalent to at least 90

days of net oil imports of the previous year. IEA Member countries currently hold some 4.1 billion barrels of

public and industry oil stocks, of which, roughly 1.5 billion barrels are government controlled for emergency

purposes.

Figure 4: World Oil Supply Disruptions

In the event of an emergency, the maximum draw down rate of IEA public oil stocks in the first month is 12.9

MMBD, 9.6 MMBD of crude oil and 3.3 MMBD of oil product stock draw. Thus, the IEA stock draw potential

for both public and compulsory industry stocks is of sufficient magnitude and sustainability to cope with even the

largest cited historical supply disruption. This safety net provides a further supplement to spare production

capacity in the system.

5. Canadian Oil Markets - A Ten Year Perspective

5.1 Political Framework

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Under the terms of Canada's Constitution, the provinces have ownership over the natural resources that lie within

their provincial boundaries. In 1985, an agreement (the Western Accord) was reached between the federal

government and the Provinces of Alberta, Saskatchewan and British Columbia to move away from a highly

centralized and regulated oil and gas industry to a deregulated and open market. Canada's market oriented energy

policy has proven to be attractive in terms of stimulating investment, growth in resources and in assuring

Canadian consumers of a large and diverse energy supply.

Prices set in free and competitive markets provide the best signals to producers and consumers with respect to

investment and consumption decisions. Rising prices send signals to producers to invest more in supply

development and to consumers to use oil more efficiently and, where possible, to switch to other fuels. This helps

ensure that sufficient supplies are available and prevents energy shortages. Even within the context of free

markets, government actions are sometimes required to advance environmental policies or respond to market

failures.

5.2 Reserves

Canada's established reserves (proven oil reserves) are second only to Saudi Arabia's. At the start of 2007,

Canada's total remaining established oil reserves amounted to 179 billion barrels. This number represents the

amount of crude oil that can be recovered under current technology and present economic conditions from

known reservoirs, specifically proven by drilling, testing or production.Canada's established reserves include 5.4

billion barrels of conventional oil reserves. Conventional oil, trapped in underground geological formations, is

extracted through drilling and pumping. The bulk of these reserves are found in Alberta, Saskatchewan and the

east coast offshore.

The large majority of Canada's established oil reserves - more than 95 per cent are in the form of oil sands. The

oil sands are a mixture of crude bitumen (a semi-solid form of crude oil), silica sand, clay minerals, and water.

Several processes have been developed for separating the bitumen from the other elements, which can then be

upgraded to synthetic crude oil. In Canada, the oil sands reserves are found primarily the Athabasca, Cold Lake

and Peace River areas of Alberta.

Canada's established reserves are sufficient to meet Canadian demand for the next 200 years at current rates of

production. Indeed, the actual oil resource is believed to be much larger than the current established reserves. A

recent report by Alberta's Energy Resources Conservation Board estimated the ultimate potential of Alberta oil

sands at 315 billion barrels. This is much larger than the current established reserves for oil sands of 173 billion

barrels.

5.3 Oil Production

Canada is currently the 7th largest oil producer in the world. Canada's crude oil production has risen fairly

steadily over the past decade. Crude oil production amounted to 2.1 million barrels per day in 2005 and reached

2.8 million barrels per day in 2009. While conventional sources continue to provide more than half of crude oil

production, the oil sands have been responsible for most of the growth in oil production in Canada in recent

years. Since 2009, Canada's annual oil sands production has more than tripled, reaching 1.2 million barrels per

day in 2011.

The Western Canada sedimentary basin is an important source of crude oil for Canada and the northern U.S.

Canadian east coast offshore production flows to eastern Canadian refineries and the U.S. northeast. Production

from the offshore east coast has increased in recent years. In 2011, it accounted 24% of Canadian conventional

oil production and 14 per cent of total Canadian production.

Canada produces more crude oil than it consumes and is a large and growing net exporter of crude oil. However,

crude oil imports satisfy more than half of domestic refinery demand. The transportation costs associated with

moving crude oil from the oil fields in Western Canada to the consuming regions in the east and the greater

choice of crude qualities make it more economic for some refineries to use imported crude oil. Therefore,

Canada's oil economy is now a dual market. Refineries in Western Canada run domestically produced crude oil,

refineries in Quebec and the eastern provinces run primarily imported crude oil, while refineries in Ontario run a

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mix of both imported and domestically produced (mainly western Canada) crude oil. In more recent years,

eastern refineries have begun running Canadian crude from east coast offshore production.

Figure 5: Canadian Crude Oil Production 2007-2014 (MB/D

Imported crude oil flows by tanker into Newfoundland and Labrador, Nova Scotia, New Brunswick and part of

Quebec, and by pipeline through Portland, Maine, to Montreal and Ontario. While imports into Canada have

been growing in the last few years, exports of Canadian oil to the U.S. have been increasing more rapidly.

Canada's net exports of crude oil have increased by 70 % since 2011.

The east coast Canadian refineries, which rely on imported crude oil, export their surplus production to the

United States. This ensures that Canada derives the maximum benefit from the development of its resources in

terms of investment, employment and economic growth.

Over the last decade, Canada's crude oil imports grew from 770 MBD to 859 MBD. However, imports have been

declining since 2010 as production of conventional oil off Canada's east coast has increased. In 2013, the North

Sea accounted for 42% of imports. By 2013, that share had declined to 38% as production for that area began to

wane. As a result, Canada has become increasingly reliant on oil from OPEC countries, which now account for

49% of all imports of crude oil into Canada.

Algeria's share of Canadian imports has more than doubled over the past decade, now contributing 21% of

imports and accounting for 85% of the growth in Canada's crude oil imports from OPEC.

Regardless of the source of crude oil, the price paid by Canadian refineries is determined by the world oil market

and is similar to that paid by US refiners for Canadian crude oil.

5.4 Oil Pipelines

Canadian crude oil is transported across North America via a complex network of pipelines (See figure 8 for

pipeline map). According to the National Energy Board, many oil pipeline systems were at or near capacity in

2010 and, at times, were under apportionment. As a result of these circumstances, a number of proposals

emerged to provide additional pipeline capacity to transport crude oil and to provide additional supplies of

diluent required to support growing oil sands operations. This additional pipeline capacity, if approved, will

enhance access to markets and increase market penetration of Canadian crude oil. In the short term, however,

weak refinery margins, reflecting slowing demand for refined petroleum products in the U.S., could affect

refinery investments.

5.5 Refining Infrastructure

There are currently 12 companies operating refineries in Canada. Only Imperial Oil, Shell and Petro-Canada

operate more than one refinery and market products nationwide. Other refiners generally operate a single refinery

and market product in a particular region. These regional refiners include North Atlantic Refining, Irving Oil and

Ultramar in the east, Suncor in Ontario and Federated Co-op, Husky and Chevron in the west. Of the 19

refineries in Canada, there are 16 that manufacture the full range of petroleum products. Husky's facility in

Lloydminster, Alberta, and the Moose Jaw Asphalt plant in Moose Jaw, Saskatchewan, are primarily asphalt

plants with limited production of other products. The Nova Chemicals facility in Sarnia, Ontario, is a

petrochemical plant that also produces some distillate products.

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Figure 8: Refineries in Canada 2013 (thousands of cubic metres per day)

There are three main refining centres in Canada (Edmonton, Sarnia and Montreal), but most provinces have at

least one refinery. Manitoba and Prince Edward Island are the only provinces with no refining capacity and there

are no refineries in the territories.

5.6 Refinery Economics

The overall economics or viability of a refinery depends on the interaction of three key elements: the choice of

crude oil used (crude slates), the complexity of the refining equipment (refinery configuration) and the desired

type and quality of products produced (product slate). Refinery utilization rates and environmental considerations

also influence refinery economics.

Using more expensive crude oil (lighter, sweeter) requires less refinery upgrading but supplies of light, sweet

crude oil are decreasing and the differential between light sweet crude oil and the heavier sour crudes is

increasing. Using cheaper heavier crude oil means more investment in upgrading processes. Costs and payback

periods for refinery processing units must be weighed against anticipated crude oil costs and the projected

differential between light and heavy crude oil prices.

Crude slates and refinery configurations must take into account the type of products that will ultimately be

needed in the marketplace. The quality specifications of the final products are also increasingly important as

environmental requirements become more stringent.

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5.7 Crude Slate

Most refineries in Western Canada and Ontario were designed to process the light sweet crude oil that is

produced in Western Canada. Unlike leading refineries in the U.S., Canadian refineries in these regions have

been slower to reconfigure their operations to process lower cost, less desirable crude oils; instead, choosing to

rely extensively on the abundant, domestically produced, light, sweet crude. As long as these lighter crude oils

were available, refining economics were insufficient to warrant new investment in heavy oil conversion capacity.

Much of this investment by the large integrated oil companies (companies that are involved in both the

production of crude oil and the manufacturing and distribution of petroleum products) is associated with ensuring

a market for their growing oil sands production.

In Western Canada and Ontario, more than 60% of the crude oil processed by refiners is either conventional

light, sweet crude oil or high quality synthetic crude oil. Synthetic crude is a light crude oil that is derived by

upgrading oil sands. Most of the remaining crude oil processed by these refineries is heavy, sour crude. The

crude slate is expected to change significantly in the years ahead as refiners increase their capacity to process

heavy crude oil and lower quality synthetic crude.

Refineries in Atlantic Canada and Quebec use imported crude oil and tend to process a more diverse crude slate

than their counterparts in Western Canada and Ontario. These refiners have the capacity to purchase crude oil

produced almost anywhere in the world and therefore have incredible flexibility in their crude buying decisions.

Approximately 1/3 of crude processed in Eastern Canada and Quebec is conventional, light sweet crude and

another 1/3 is medium sulphur, heavy crude oil. The remaining 1/3 is a combination of sour light, sour heavy and

very heavy crude oil. The crude slate in Eastern Canada is expected to remain much more static than that in

Western Canada and Ontario, as these refiners are not constrained by the quality or volume of domestic crude

production.

5.8 Refinery Configuration

A refiner's choice of crude oil will be influenced by the type of processing units at the refinery. Refineries fall

into three broad categories. The simplest is a topping plant, which consists only of a distillation unit and probably

a catalytic reformer to provide octane. Yields from this plant would most closely reflect the natural yields from

the crude processed. Typically only condensates or light sweet crude would be processed at this type of facility

unless markets for heavy fuel oil (HFO) are readily and economically available. Asphalt plants are topping

refineries that run heavy crude oil because they are only interested in producing asphalt.

The next level of refining is called a cracking refinery. This refinery takes the gas oil portion from the crude

distillation unit (a stream heavier than diesel fuel, but lighter than HFO) and breaks it down further into gasoline

and distillate components using catalysts, high temperature and/or pressure.

The last level of refining is the coking refinery. This refinery processes residual fuel, the heaviest material from

the crude unit and thermally cracks it into lighter product in a coker or a hydrocraker. The addition of a fluid

catalytic cracking unit (FCCU) or a hydro cracker significantly increases the yield of higher-valued products like

gasoline and diesel oil from a barrel of crude, allowing a refinery to process cheaper, heavier crude while

producing an equivalent or greater volume of high-valued products.

Hydrotreating is a process used to remove sulphur from finished products. As the requirement to produce ultra

low sulphur products increases, additional hydrotreating capability is being added to refineries. Refineries that

currently have large hydrotreating capability can process crude oil with higher sulphur content.

Canada has primarily cracking refineries. These refineries run a mix of light and heavy crude oils to meet the

product slate required by Canadian consumers. Historically, the abundance of domestically produced light sweet

crude oil and a higher demand for distillate products, such as heating oil, than in some jurisdictions reduced the

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need for upgrading capacity in Canada. However, in more recent years, the supply of light sweet crude has

declined and newer sources of crude oil tend to be heavier. Many of the Canadian refineries are now being

equipped with upgraders to handle the heavier grades of crude oil currently being produced.

Annex B provides a list of all Canadian refineries and their capacities.

5.9 Refinery Utilization

In the 1970s and early 1980s the refining industry in Canada made the market more cost effective by closing

down small inefficient facilities, which could not be economically retrofitted to accommodate Canada's cleaner

fuel standards, and replaced them with new larger installations. Today, Canada has more than double the refining

capacity at its 19 refineries than it had when there were 44 refineries in the 1960s.

In recent years, growth in the demand for petroleum products has led to an improvement in capacity utilization,

increasing operating efficiency and reducing costs per unit of output. As a result, refinery utilization rates have

been above 90% nationally for six of the last ten years. A utilization rate of about 95% is considered optimum as

it allows for normal shut downs required for maintenance and seasonal adjustments.

However, with increased refinery utilization rates comes increased vulnerability to unplanned refinery outages.

With little or no spare refining capacity, even a small supply disruption can create problems.

There have been no new refineries built in Canada since 1984. The cost of a grassroots refinery today is likely

more than $5 billion. Historically, refining margins have been poor, discouraging investments of this magnitude.

In addition, refiners have been required to make significant capital investments in existing refineries in order to

meet evolving product specifications and environmental regulations. This has made it more difficult to attract the

capital required to capacity expansions or new builds.

Over the past several years, with greater refinery utilization rates, refining margins have increased and the

economic incentives to build new capacity have improved. However, industry decisions to construct a new

refinery will be based on the perceived long term economic returns. The industry will need to feel relatively

certain that more recent margin improvements are sustainable before investments with 20-year payback periods

are seriously considered. For example, returns for the first half of 2008 have been significantly lower than those

experienced in the last few years. With the recent erosion in oil prices, these returns are not expected to rebound

for the balance of this year. If new projects do go forward, these investments will take several years to be

realized. It can take six to ten years for a grassroots refinery to be built.

5.10 Petroleum Product Supply and Demand

Since 1998 demand for petroleum products has been growing steadily at a rate of about 1 percent per year.

However, product demand is a moving target and the demand for each product does not always grow at the same

pace.

Table 2: Canadian Petroleum Product Supply and Demand - 2013

Total All Products (Millions of Cubic Metres)

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2004 vs 2014

Production 108.5 109.7 112.3 115.4 119.0 123.4 125.3 121.6 119.8 121.7 12%

Imports 10.4 9.8 9.2 11.5 10.0 12.9 14.2 16.2 16.8 15.8 51%

Exports 16.8 17.4 17.6 22.9 24.6 25.1 25.9 25.7 24.5 24.9 48%

Domestic Sales 92.4 93.3 94.8 93.8 94.1 98.6 102.5 101.5 100.0 103.4 12%

Gasoline demand has increased slightly in most of the last 10 years. The distillate demand (diesel oil, furnace oil

and kerosene), driven primarily by on-road diesel requirements, has been the fastest growing component since

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1993. Because of the significant proportion of distillate demand that comes from the trucking industry, this

component is the most closely linked with economic activity.

The relationship between gasoline and distillate sales can also create challenges for refiners. A refinery has a

limited range of flexibility in setting the gasoline to distillate production ratio. Beyond a certain point, distillate

production can only be increased by also increasing gasoline production.

Domestic sales of diesel have been increasing since 2003, reflecting the strong growth in the Canadian economy

and a growing proportion of diesel-powered vehicles in the fleet. Most of this growth can be attributed to

increased diesel use in the agricultural, mining and energy sectors of western Canada. However, with increasing

fuel efficiency standards being imposed on vehicle manufacturers by governments, automobile companies have

indicated that they will be introducing more diesel-powered vehicles in order to adhere to the regulations.

Demand for diesel fuel is expected to continue to grow as retail consumers (non-commercial) start to take notice

of the efficiency and durability of diesel engines.

This disproportionate growth in diesel demand has also led to significant supply challenges in recent years,

particularly in western Canada. With refinery capacity fully utilized and demand continuing to grow, the supply

of diesel has been strained for a number of years. This has created a particular issue for the trucking industry and

agricultural users. Even a small interruption in refinery production can create supply challenges and require

imports to satisfy demand. There have been a number of occasions in the last year when western suppliers were

required to put their customers on allocation, restricting deliveries to a percentage of historical sales, in order to

ensure adequate supplies for priority customers (emergency vehicles, hospitals etc.) in the short to medium term.

Figure 11 illustrates the important role that on-road use plays in the consumption of petroleum products.

Trucking remains the transportation mode of choice for many consumer goods in Canada and any disruption to

the diesel fuel supply can have widespread implications for the Canadian economy.

Figure 11: All Petroleum Products 2008 vs 2012

5.11 Product Distribution

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Some of the distribution challenges arise from the fact that petroleum products are refined in only a few

geographic regions but they are consumed all across Canada.

Figure 12: Refined Petroleum Products

Production and Sales – 2013

Of the western provinces, only Alberta and Saskatchewan produce more products than they consume. Manitoba

and parts of British Columbia and most of the territories are supplied primarily from the three refineries in

Edmonton.

Quebec and Ontario together are close to being in balance with significant volumes moving from Quebec to

Ontario since the closure of the Oakville refinery. Atlantic Canada is a major exporter of petroleum products.

However, even the provinces that are self-sufficient must still move petroleum products over long distances to

supply all of their customers.

Figure 13 illustrates how far product is moved in Canada. Western refineries supply all product demand from

Vancouver to Thunder Bay, including the northern territories. Refiners in southern Ontario move product to Sault

Ste-Marie, northern Ontario and as far to the east as Ottawa. Montreal and Quebec City facilities supply the St

Lawrence River corridor from Toronto to the Gaspé Peninsula, as well as the more remote areas of northern

Quebec and occasionally parts of the Arctic. Petroleum products from the three Atlantic refineries find their way

to the Arctic and Hudson Bay regions as well as the U.S. eastern seaboard.

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Figure 13: Refinery Supply Orbits

5.12 Distribution infrastructure

The logistics network required to supply petroleum products from the refineries to the end-users is a complex

system of pipelines, ships, railways and trucks. Often several methods of transportation are utilized to move

petroleum products from the refineries, ports and large terminals to tremendously disperse markets all across the

country.

Refineries to Terminals

Generally, petroleum products are blended at the refinery and shipped by rail, ship or pipeline to local terminals.

From the local terminals, products are trucked to retail sites.

Product exchanges are now very common in the Canadian refining industry. In order to reduce transportation

costs and to capitalize on increasing economies of scale, refiners have entered into a large number of product

exchange agreements with one another. Product exchanges occur when one refiner provides another refiner with

specific products in a certain location in exchange for a similar quality and volume of products in another

location.

Product exchanges significantly reduce the volumes and distances over which products are moved, thereby

considerably reducing transportation costs. These agreements have not only allowed the industry to consolidate

their operations at the refinery level but have also led to a consolidation of local product terminals. It is no longer

unusual to purchase gasoline from a branded outlet that was produced by one of its main competitors.

In cases where product exchanges are not available, companies need to make other arrangements to supply their

terminals and retail networks. The method of transportation they select to move their products will be influenced

by several factors. Geographic barriers are a major concern as well as the volume of products demanded in each

of these markets and the relative costs of transportation. Each mode of transportation has its own inherent

strengths and weaknesses.

Pipelines are the safest, most reliable and cost-effective way of transporting the large volume of petroleum

products that must be moved throughout Canada each day. However, the enormous capital cost associated with

constructing pipelines limits their use to locations where very large volumes of product are to be moved for an

extended period of time. The payback period for these projects is often 15-20 years or greater.

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Method of Transportation Comparative Costs

Pipeline Low

Ship or barge Moderate

Rail Moderate

Truck High

Where the volume of petroleum products cannot justify the construction of a pipeline, petroleum products are

transported to terminals across land by truck and rail and over water by marine tanker. In Atlantic Canada,

almost all petroleum product terminals are serviced by marine tanker. In other areas of Canada, railways and

trucks are much more important. Although transportation by truck is the most expensive transportation method, it

is also the most flexible. Highway truck tankers transport all gasoline from the terminals or refinery truck loading

facility (commonly referred to as the loading rack) to underground storage tanks at each retail outlet.

Most of Canada's refined petroleum product distribution network is operated by three national oil companies

(Shell, Petro-Canada, and Imperial Oil) and a handful of regional refiners (Irving Oil, Ultramar, Suncor Energy,

Federated Co-op, Husky and Chevron). With only a few exceptions, all product terminals are owned and

operated by one of these companies.

Terminals

As a result of the significant rationalization of terminals over the last 20 years, in some markets, only one

terminal exists and all marketers load at that terminal. From these local terminals, petroleum products are trucked

to retail / customer sites. Each product has a different delivery system from the terminal depending on the

customer base. For example, jet fuel is often moved by pipeline directly to the airport. Diesel fuel is distributed

through retail outlets, large commercial card lock facilities where trucking companies can fill up at unattended

distribution sites, or by truck delivered directly to customer storage tanks. Furnace oil is distributed from the

terminal directly to home heating customers.

Gasoline, the most visible and widely used of all the products, has the most dispersed distribution network.

Before the gasoline leaves the terminal, some gasoline retailers will add performance and detergent additives to

distinguish their brand from those of their competitors. The formula for each additive package is unique to that

specific brand. As many companies pick up product from the same terminal, the proprietary additives are

generally added at the terminal and are the only way to differentiate gasoline at retail outlets.

Ethanol, and ethanol-blended gasoline, because of its ability to pick up water, cannot be transported by pipeline.

Ethanol can be shipped by railcar or truck but must be blended at the terminal for those locations supplied by

marine or pipeline. Dedicated tanks are required to store the ethanol and the gasoline-blending component with

which it will be mixed. The handling of ethanol-blended fuels also requires modifications to other aspects of the

fuel distribution system, including trucks, retail storage tanks and service station pumps.

5.13 Regional Product Movements

The Canadian downstream petroleum industry can be broken into three distinct regions: Western Canada,

Ontario and Quebec/Atlantic Canada. The industry is often divided this way because of the differences in the

feedstock available to the refiners in each of these areas. In Atlantic Canada and Quebec, refiners rely almost

exclusively on foreign crude to meet their requirements. On the other hand, Western Canada is dependant on

domestic production to satisfy its crude requirements. Ontario refiners have access to both foreign and

domestically produced crude oils. Many of the same factors that influence the availability of different crude oil

supplies in each of these regions have also shaped the development of the petroleum product distribution

network.

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The availability of both crude oil and petroleum product imports in every region hinges on geographic

constraints. Some regions are better suited than others to import products. Because of their connection via major

waterways, Atlantic Canada and Quebec have good access to supplies from the northeastern United States and

Europe.

Ontario also has access to supplies from large U.S. markets and can also bring in products via Quebec. In 2010

Ontario shifted to a net import position with the closure of the Oakville refinery and increased product

movements from Quebec refineries. However, logistical constraints, such as the size of ships that can navigate

the St. Lawrence Seaway and the seaway shipping season, increase the cost of these supplies. Other modes of

transportation, such as pipeline, unit train and trucking, are necessary to bring products from other regions.

Most of western Canada is landlocked, and as such, has very limited access to supplies from other regions. The

current infrastructure was not designed to transport supplies to the prairies from other regions. However, the

prairies supply a substantial volume of gasoline into the Vancouver market. In the event of a supply shortage in

the prairies, refiners have the ability to balance supply and demand by importing gasoline into Vancouver from

Washington State. This frees up additional product from Edmonton area refiners to be distributed to prairie

markets.

A more detailed analysis of the distribution network in each region is provided in section 4

5.14 Inventory Levels

To provide added flexibility to the distribution of petroleum products, refiners and marketers maintain

inventories of the various products in strategic locations throughout the distribution chain. If supplies of imported

or domestic crude oil were interrupted for any reason, or if the product distribution system failed, companies

would rely on commercial inventories to meet short-term needs while alternate arrangements were being made.

Canadian crude oil and petroleum product inventories have been relatively stable for the last 10 years. Inventory

levels for some products, such as gasoline and furnace oil, fluctuate significantly over the year. Demand for these

products is very seasonal and at its peak can exceed the production capacity of refineries. Therefore, refiners

need to anticipate the peak consumption periods by building inventories in advance. Gasoline inventories

increase during the first quarter of the year and are used during the summer months to supplement refinery

production. Furnace oil stocks grow during the fall and are drawn during the coldest months of winter when

demand is at its highest level.

Refiners also build up inventories of all products in advance of scheduled refinery maintenance (called

turnarounds). Turnarounds can vary in frequency from annually to once every few years and sometimes require

the refinery to be completely shut down for a period of several weeks. Refiners anticipate this by building up

product stocks that can be used during the turnaround.

Refiners' crude oil inventories fluctuate over a very narrow band and are less seasonal than product stocks. There

are significant regional variations in crude oil stocks, with refiners in the West, who run domestic crude oil

maintaining about 5-7 days of oil, and refiners in eastern Canada who run imported crude oil averaging 15-20

days.

.15 Product Pricing

The last piece in the supply/demand chain is price. Prices play an important role in maintaining supply and

demand balance and refinery economics. They are also an important consideration for consumers of petroleum

products and can often determine the viability of a business that has a petroleum product as one of its major

inputs.

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Petroleum product prices generally track the price of crude oil, the raw material from which they are made.

However, it is the supply and demand dynamics of each individual product in specific markets that determines

the final consumer prices. In recent years product prices have tracked the changes in crude oil prices very

closely, both the increases and the decreases. When it appears that product and crude oil prices are not tracking,

the real cause can generally be traced to underlying market supply issues. For example, it has been supply issues

that have resulted in diesel prices rising above gasoline prices during the recent year, retail price spikes unrelated

to crude oil price changes in the summer of 2008 and a widening in the retail and wholesale price differentials

between eastern and western markets in Canada in 2008.

Price is the equalizer that ensures supply always meets demand. If demand exceeds supply, prices will rise until

either new supplies are attracted to the market or demand is dampened so that equilibrium is achieved. If supply

exceeds demand, prices will drop until the market is in balance. When demand is non-discretionary and cannot

react to the higher price signals, consumers can face significant challenges in coping with the higher prices.

From a refiner's perspective, the price of petroleum products is measured at the refinery gate. The price at which

a refiner can sell product at the loading rack is called the rack price. It is rack prices that determine refinery

viability in terms of revenue generated from the refining process.

Because of the ability to move product to the market where the highest price is found, most petroleum product

prices are similar from market to market. For example, if the rack price for gasoline was lower in Toronto than it

was in Buffalo, refiners in Toronto would choose to ship their product to Buffalo to sell at the higher price, as

long as the cost of transporting it to Buffalo was less than the price difference. This would increase the supply in

Buffalo and lead to a price decrease until the two markets were in balance. The same would apply in reverse if

the Toronto price were higher. Generally, the difference in wholesale prices between two markets can be

attributed to the cost of transportation between those two markets.

As a result of the integrated nature of North American petroleum product markets, Canadian refiners are price

takers and must price their products to compete with the price of imported product delivered to Canada. Even if

no products are in fact actually imported, the existence of the import option imposes a certain pricing discipline

on local refiners.

The price that the consumer pays for a petroleum product depends on the product and how the product will be

used. With the exception of automotive fuels, most petroleum products are sold at the wholesale level directly to

the consumer of the fuel, usually under contract. The terms of the contracts are considered commercially

sensitive and not generally made public. As a result, the prices of these products are less transparent and more

difficult to track.

Wholesale prices for petroleum products react to a broad range of factors unique to their individual markets.

Product prices are influenced by the supply and demand balances as well as the prices of alternative products

with which they compete. For example, propane can be used for heating, as an automotive fuel or for agricultural

uses like crop drying. A late, wet harvesting season in the prairies can overlap with an early cold winter that both

result in a surge in demand and short-term price spikes.

The demand for diesel fuel is directly related to economic activity, which is manifested in increased truck traffic

to move goods and services in a robust economy. Diesel oil is also an automotive fuel and can be easily

converted to furnace oil for home heating. When all of these uses compete for supply, prices will rise. Diesel

users have faced significant increases in their costs in recent years, particularly in western Canada, as demand

growth has outpaced supply increases.

Automotive fuels are distributed to consumers through retail outlets. The retail price, therefore,

includes distribution costs as well as a number of federal and provincial consumption taxes. Retail

price can also be used as a tool to attract market share. This kind of competition in the market can lead

to significant price wars resulting in low and volatile consumer prices.

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and provincial taxes and local market conditions - all come together, retail prices, and to a lesser

When the factors that can influence prices - supply/demand, crude oil costs, distribution costs, federal

degree wholesale prices, can vary significantly between markets.

6. Regional Analysis

According to the Oil & Gas Journal, Canada had roughly 173 billion barrels of proved oil reserves at

the beginning of 2015, ranking it third in the world. Only Saudi Arabia and Venezuela hold higher

reserves. In addition, Canada is one of only two countries among the top 10 proved reserves holders

that is not a member of the Organization of the Petroleum Exporting Countries (OPEC).

Canada's proved oil reserves from 2006 to 2012 were well below 10 billion barrels. In 2013, they rose

to 180 billion barrels after oil sands resources were deemed to be technically and economically

recoverable. Oil sands now account for approximately 166 billion barrels of proved reserves, nearly

all of Canada's current proved oil reserves. Oil sands proved reserves saw a slight year-on-year decline

in 2014. Nevertheless, oil sands production during the year continued to be robust, despite the decline

in crude oil prices.

6.1 Western Canada

There are currently six refineries operating in Western Canada that produce a wide range of petroleum products.

The three largest are located near Edmonton. The remaining refineries, located in Prince George, Vancouver and

Regina, primarily supply local markets.

Table 3: Western Refineries 2013 Capacity

Company Location Capacity MBD Capacity 1000 m3

Imperial Oil Edmonton 187 29.7

Petro-Canada Edmonton 125 19.9

Shell Scotford 100 15.9

Consumer's Coop Regina 100 15.9

Chevron Burnaby 55 8.7

Husky Prince George 12 1.9

Overall, supply and demand for petroleum products in the western provinces is well balanced. This is because,

for the most part, western Canada is landlocked, and as such, has very limited access to supplies from other

regions. The current infrastructure was designed to transport supplies from the Edmonton refineries to the

prairies markets and the BC coast. It does not include the capacity to bring petroleum products to the prairies

from other regions. This can present supply challenges when a refinery has to temporarily curtail production. The

markets closest to the refinery are hardest to re-supply form other markets.

Although the volumes of petroleum product imports and exports are not very large, they play a significant role in

balancing supply and demand in this region. The Edmonton refiners supply a substantial volume of petroleum

products into the Vancouver market. In the event of a supply shortage in the prairies, refiners have the ability to

balance supply and demand by importing supplies into Vancouver from Washington State, freeing up additional

volumes for the prairie markets. Also, at times, there is some surplus product available for export by truck from

Regina and Winnipeg/Gretna or by barge from Vancouver.

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Table 4: Western Canadian Petroleum Product Supply and Demand - 2013 (Thousands of Cubic Metres)

Gasoline Diesel Fuel Furnace Oil All Products

Production 12 495 11 846 460 39 788

Imports 316 824 3 578

Exports 195 650 8 2 249

Net Inter-regional Transfers -233 -313 -3 -330

Domestic Sales 14 157 13 996 246 38 065

As western Canada is a significant producer of agricultural products, this region consumes a larger volume of

diesel fuel compared to the rest of the country. Additional diesel is consumed by the oil and gas industry in their

oil extraction operations. Due to the readily available supply of natural gas in this region, heating oil is used in

very few industrial or residential applications.

Perhaps the most unique feature about product distribution in western Canada is the distance between product

terminals. Terminals are generally located on old refinery sites; and although most of the product demand is

located within a 150 kilometre radius of the terminals, the average distance between terminals is about 500-600

kilometres. As a result, trucking distances from the terminal to the customer are much greater in western Canada

than in most other areas of the country.

Without doubt, the heart of the western Canadian petroleum product distribution system is located in Edmonton.

The Edmonton area refineries account for most of the refining capacity in western Canada but the Edmonton

market accounts for less than a third of western Canada's product demand.

Surplus refined products are shipped to several other terminals throughout western Canada via three pipeline

systems and also by rail. The Trans Mountain Pipeline (TMPL) transports refined product from the Edmonton

area refiners to terminals in Kamloops and Vancouver. The Alberta Products Pipeline (APPL) moves refined

product from Edmonton to Calgary. Enbridge's Line 1 ships refined product from Edmonton to Milden, Regina,

and Gretna. Product deliveries to Milden and Gretna are shipped via secondary pipelines to Saskatoon and

Winnipeg respectively.

Table 5: Western Canadian Petroleum Product Demand by Sector - 2013 (Thousands of Cubic Metres)

Gasoline Diesel Fuel Furnace Oil All Products

Industrial - 1 770 49 2 062

On-Road 11 897 4 455 - 16 352

Off-Road - 1 642 - 2 464

Agriculture 902 1 717 10 2 633

Residential - 20 51 76

Other 830 3 146 158 7 287

Total Demand 13 629 12 709 268 30 874

There are two refineries operating within British Columbia and together they supply about a third of the refined

product demand in the province. The balance of the local demand is supplied from Edmonton via TMPL

shipments to Kamloops and Vancouver and through rail shipments to Prince George, Terrace and smaller

locations within the B.C. interior. From Vancouver, product is barged to terminals on Vancouver Island and

along the coast. Any shortfall is met through imports into Vancouver from the U.S. west coast.

The TMPL was designed to carry crude oil from Edmonton to refineries in Vancouver and Washington State.

During the rationalization in the Canadian refining sector, three Vancouver refineries ceased operations (Shell,

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Petro-Canada and Imperial Oil) and were converted to terminal facilities. Today, refined products are delivered

to these terminals from a combination of pipeline and barge movements from the Chevron refinery and deliveries

from TMPL.

Three Edmonton refineries and two product terminals in Calgary supply petroleum products in Alberta. The

Calgary terminals are generally supplied via the Alberta Products Pipeline (APPL) from Edmonton. During high

demand months, the APPL is utilized at full capacity. For this reason, the trucking of product from Edmonton to

southern Alberta sites is sometimes necessary to supplement pipeline movements. The Edmonton refineries also

distribute product to terminals in Saskatoon and Regina via Enbridge's Line 1. Almost half of Saskatchewan's

product supply is shipped into the province from Edmonton. Consumers' Co-operative Refinery located in

Regina supplies the remainder of Saskatchewan's petroleum product demand.

Figure 15: Western Canadian Clean Products Pipeline

Two terminals located in Winnipeg supply the entire province of Manitoba. Products are shipped from the

Edmonton and Co-op refineries down Enbridge's Line 1 to Gretna. The terminal at Gretna contains breakout

tanks, which allow product to be injected into the Winnipeg Products Pipeline (WPPL). A small truck loading

rack also provides the capability to export products to nearby American communities.

The Winnipeg terminals are equipped with rail loading facilities that are used to ship product into northern

Ontario. In the summer months, the Winnipeg terminals supply the majority of the product demand in markets

between Winnipeg and Thunder Bay. During the winter months, when barge traffic on the Great Lakes is

curtailed, all products in this area are supplied out of Winnipeg.

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6.2 Ontario

There are four refineries in Ontario, three of which are located in Sarnia and one in Nanticoke. Product is shipped

from each of these refineries primarily by pipeline.

The Sun Canadian pipeline system carries product from the Shell and Sunoco refineries in Sarnia to London,

Hamilton and Toronto. The Sarnia Products Pipeline (SPPL) carries product from the Imperial Oil refinery in

Sarnia to St George (near Brantford) and Toronto. The Trans Northern Pipeline (TNPL) system is the largest

products pipeline within the province.

Table 6: Ontario Refineries 2013 Capacity

Company Location Capacity MBD Capacity '000 m3

Imperial Oil Sarnia 119 18.9

Imperial Oil Nanticoke 118 18.8

Suncor Sarnia 70 11.1

Shell Sarnia 72 11.4

Historically, product was injected into the system from the Nanticoke and Oakville (now closed) refineries, and

through tie-ins from the Sarnia pipeline systems. Delivery points included Toronto, Belleville, Kingston,

Cornwall and Ottawa. Between Montreal and Farran's Point, Ontario, the line ran east to west, delivering product

from Montreal refineries into eastern Ontario. A spur line from Farran's Point to Ottawa meant that the Ottawa

market could be supplied from either Toronto or Montreal. In 2005, the Farran's Point to Toronto portion of the

line was reversed to allow products to flow by pipeline from Montreal refineries into southern Ontario.

There were many driving forces behind the reversal of the TNPL eastern line. First, the cost to supply product

into the Ottawa market for most refiners favours Montreal as the supply point. Imperial Oil is the one exception

as they have an abundance of supply in Ontario with two (2) refineries and must trade for supply or purchase

product in Quebec where they no longer have a refinery. Reversing TNPL enabled lower cost product to be

delivered directly into the Toronto market by Quebec refiners (Petro-Canada, Shell, and Ultramar). Currently this

pipeline has little or no spare capacity to transport additional products in the case of a shortage.

Table 7: Ontario Petroleum Product Supply and Demand - 2012 (Thousands of Cubic Metres)

Gasoline Diesel Furnace Oil All Products

Production 10 322 4 402 1 105 27 940

Imports 370 34 1 1 643

Exports 156 535 72 1 877

Inter-regional Transfers Out 4 799 2 619 236 8 560

Domestic Sales 15 972 6 842 1 129 33 226

Environmentally driven legislation (in particular the move to ultra-low suphur diesel) required major investments

by most refiners. Consolidation of refinery supply orbits and the closure of the Petro-Canada refinery in Oakville

eliminated the need to make some investments. Consequently, Ontario has become quite dependent on volumes

of product now transported into southern Ontario from Quebec refineries.

Northern Ontario is supplied from the Sault Ste Marie, Thunder Bay and Sudbury terminals. Only one terminal

exists in Thunder Bay and is operated by Petro-Canada. Other refiners bring their product into the market

through the Petro-Canada facility. Petro-Canada and Shell supply product by rail from Winnipeg year round and

Imperial Oil supplies product in the summer months by marine from Sarnia and in the winter from Winnipeg. At

Sault Ste Marie, there are three (3) terminals (Shell, Imperial Oil, and Sunoco). Shell provides product to the

terminal by rail from Montreal, while Imperial Oil and Sunoco supply product year round by marine movements

from Sarnia. In Sudbury, Imperial Oil operates a terminal which is supplied by rail from their Nanticoke refinery.

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Figure 16: Quebec/Ontario Clean Products Pipeline

Table 8: Ontario Petroleum Product Demand by Sector - 2013 (Thousands of Cubic Metres)

Gasoline Diesel Fuel Furnace Oil All Products

Industrial 806 48 1 845

On-Road 14 659 4 062 18 721

Off-Road 593 724

Agriculture 363 282 33 721

Residential 20 506 526

Other 633 1 145 481 4 898

Total Demand 15 655 6 908 1 068 27 436

As the province with the largest population base in the country, Ontario uses the most gasoline of all the regions.

In addition, due to its high population density, a significant volume of on-road diesel is required to transport

goods. Although some industry and residential consumers rely on furnace oil to heat their homes, natural gas is

the primary energy source for heating in this region.

6.3 Quebec-Atlantic Canada

There are six (6) refineries in Quebec/Atlantic, two (2) are located in Montreal, one (1) at St Romauld (near

Quebec City), one (1) in Saint John NB, one (1) at Dartmouth NS, and one (1) at Come-By-Chance in

Newfoundland and Labrador. In contrast to other regions, product movements are primarily by marine. The

exceptions are the TNPL movements into Ontario and the unit train which moves product from Ultramar's

refinery at St Romauld to Montreal. Marine terminals are located near the major population centres along the St

Lawrence River and in the Atlantic provinces.

Ultramar is currently constructing a product pipeline that will run from their refinery in St-Romuald to Montreal.

This pipeline would have an initial capacity of 100,000 barrels per day with the possibility of expansion with the

addition of further pumping facilities.

Table 9: Quebec/Atlantic Refineries 2013 Capacity

Company Location Capacity MBD Capacity '000 m3

Irving Oil Saint-John 250 39.7

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Ultramar St-Romuald 215 34.2

Shell Montréal 130 20.7

North Atlantic Refining Come-By-Chance 115 18.3

Petro-Canada Montréal 130 20.7

Imperial Oil Dartmouth 89 14.1

The Quebec/Atlantic region has a surplus of product overall. North Atlantic Refining exports the majority of the

product from its refinery and Irving Oil exports about 50 % of its production. Both North Atlantic and Irving

have been very successful in marketing their ultra low sulphur products into the United States, with some cargoes

reaching destinations as far away as California.

In addition to their ability to export products to other markets, this region is unique in that is has the ability to

import petroleum products from overseas via tanker when the need arises. These products can then be transported

by smaller vessels, rail, truck or pipe to locations outside the region.

Table 10: Quebec/Atlantic Petroleum Product Supply and Demand - 2013 (Thousands of Cubic Metres)

Gasoline Diesel Furnace Oil All Products

Production 20 997 11 576 6 712 53 950

Imports 3 921 651 25 10 579

Exports 8 036 2 645 4 014 20 763

Inter-regional Transfers Out -4 565 -2 306 -233 -8 230

Domestic Sales 12 410 6 832 2 981 32 141

Currently Irving Oil as well as Newfoundland and Labrador Refining Corporation are evaluating the possibility

of building new refineries in this region. These refineries would be primarily export oriented and would supply

the north-eastern United States.

Table 11: Quebec/Atlantic Petroleum Product Demand by Sector - 2013 (Thousands of Cubic Metres)

Gasoline Diesel Fuel Furnace Oil All Products

Industrial 825 145 2 314

On-Road 10 782 3 054 13 836

Off-Road 1 001 1 386

Agriculture 234 371 34 646

Residential 1 446 1 523

Other 615 1 365 1 128 5 347

Total Demand 11 630 6 616 2 752 25 051

Due to the rural nature of the population and a lack of natural gas infrastructure, the Atlantic/Quebec region is

highly dependant on heating oil to fulfill its heating needs.

6.4 Northern Communities

Canada is unique in that it has vast undeveloped northern territories with relatively little population base.

Northern Canadian communities are serviced by rail, truck and marine. Due to their remote nature, some of these

communities can only be supplied during the winter months by ice roads that are only open during specific

months of the year. The territories can be broken down into 4 supply orbits:

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Eastern Arctic - supplied by coastal ships from Atlantic Canada or Quebec.

Western Hudson Bay - supplied from Churchill via barge to the local communities. Churchill is

supplied via rail from Winnipeg.

Mackenzie Valley, North Shore - product is railed to Hay River and moved further north by barge on

the Mackenzie River in summer or by ice road in the winter.

Yukon - product is barged to Skagway, Alaska and trucked to Whitehorse. Some product is also trucked

in from Fairbanks.

7. Where Are We Headed by 2018?

The Canadian downstream industry continues to evolve. There a number of measures and policies that will come

into force in the next decade and others that have yet to be confirmed. These will not only have an impact on the

structure of the market, they will also influence industry investment decisions.

7.1 Renewable Fuel Standards

Integrating bio-fuels into the Canadian petroleum product distribution system will affect all refiners, distributors

and marketers of petroleum products, changing the way in which they do business. The different properties

between regular gasoline and ethanol-blended gasoline will affect production, distribution and storage of

gasoline.

Ethanol-blended gasoline cannot be intermingled with other types of gasoline during the summer months, and

ethanol, unlike regular gasoline, must be transported and stored separately from the base gasoline mixture. The

two components can only be combined at the last step in the distribution chain. The petroleum distribution and

storage system contains water. Petroleum remains separate from the water, but ethanol has an affinity for water.

If ethanol-blended gasoline interfaces with water, the ethanol is pulled from the gasoline into the water. As a

result, ethanol is delivered and stored separately until delivery to retail stations. For this reason, ethanol cannot

be pipelined and will need to be delivered to the terminals from the production facilities by other higher costs

modes of transportation, probably rail.

The distribution system in many regions of Canada cannot currently handle renewable fuels without further

investments. In these regions, a large number of changes are required to the logistics system to make the

transition from traditional gasoline ethanol-blended gasoline. While sustained supply problems are not

anticipated, it is important to realize that we will be moving away from a well developed and very efficient

distribution system to a new, less efficient system with an unproven track record.

7.2 Clean Air Agenda

Refineries currently account for about 3% of Canada's Greenhouse Gas (GHG) emissions. However, the

international trend toward lower GHG emissions among developed nations will demand significant new

investment for the refining industry over the next number of years. This, combined with the increased drive to

reduce industrial air pollutants in Canada, may affect the ability of the industry to provide a secure domestic

source of petroleum products.

Refining is a unique sector in that, in addition to reducing pollutants at refinery sites, the main outputs from the

refinery contribute to the vast majority of emissions from the transportation and industrial sectors through fuel

use. An added challenge is the fact that regulations aimed at improving emissions of air pollutants, either at the

refinery or from vehicles, often require higher energy intensity, thereby increasing a refinery's GHG emissions.

Fuel quality regulations to reduce contaminants in transportation fuels have contributed to significant overall

environmental benefits at the point of use. However, these regulations have required refiners to add additional

processing capability that has increased the amount of GHG emissions released at the refinery site. The

implementation of low sulphur gasoline and diesel between 2001 and 2006 resulted in the closure of the Petro-

Canada facility in Oakville and was estimated to have cost the industry over $6 billion. Further requirements are

expected in the future to reduce sulphur in fuel for ships and home heating oil.

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The industry trends continue to move toward improving the quality of fuels by regulating the removal of sulphur

and benzene, conversion of less valuable and heavy fuel oil into low-sulphur diesel, as well as increased

processing of poorer quality crude oil, as the available supply of light sweet crude oil diminishes. All of these

trends will have a direct impact on the GHG emissions profile of refineries, without increasing crude throughput

or product output. Stringent facility emissions standards will be difficult to adhere to given the increased energy

intensity required to produce cleaner fuels.

7.3 New Refinery Capacity

Over the past few years, growth in the demand for North American petroleum products has outpaced new

capacity additions, leading to higher refinery utilization rates and improved refinery margins. Rates of return on

capital employed have improved to levels where the refining industry is now considering new investment in

capacity expansion. However, these margins will need to be sustained for several years if investments with 20-

year paybacks are to go forward. In the first half of 2008, refining margins were substantially lower than they had

been in the previous few years. With the current economic downturn, these margins are not expected to rebound

this year.

Currently, Irving Oil and Newfoundland and Labrador Refining Corporation have put forth proposals to build

new refineries in Canada. In addition, other companies are evaluating the possibility of expanding current

refining capacity. Annex C provides details on current proposals for capacity additions.

These projects will face a number of hurdles. The regulatory approval process for a new refinery can be very

onerous and time consuming. In spite of the public call for more capacity to ease pressures on prices, few

communities want a refinery in their backyard.

Demand for petroleum products in the longer term is also an uncertainty. High prices, increased environmental

awareness and a slowing of economic activity have all been contributing to slower demand growth. Industry will

not want to be left with stranded investments if the need for their products declines. As demand begins to flatten,

planned new refinery developments and capacity expansions could be curtailed or shelved completely. Shell

Canada recently announced that it would not proceed with its proposal for a new refinery in Sarnia.

7.4 Pipeline Capacity

The National Energy Board (NEB) reports that oil sands development continues to fuel expansion and

construction of new pipelines to deliver crude oil to both traditional and new markets. Crude oil pipeline capacity

out of western Canada continues to be tight and at this time there is an inherent lack of flexibility in the system.

The numerous pipeline applications filed with the NEB and approved in 2007 and the possibility of a number of

others yet to be filed, however, indicate that the market expects pipeline capacity to increase gradually to meet

expected growth in supply. However, it is not yet clear how recent economic events will affect these decisions.

In addition, it is likely that crude oil producers will look for opportunities to enter into supply agreements with

downstream refineries to solidify markets for their production. These arrangements secure markets for Canadian

crude oil production and help the industry to decide which pipeline projects to support to connect those markets.

As Canadian producers look to diversify their customer base, market conditions could make it more economical

for refineries located in Ontario that currently take western Canadian crude oil to take more. Refiners in Quebec

that do not currently have access to Canadian feedstock could receive western Canadian crude oil through the re-

reversal of Enbridge's Line 9, which currently transports crude oil from Montreal to Sarnia. In addition, refineries

in PADD I (U.S. Northeast) could also access western Canadian crude if Line 9 is reversed along with a portion

of the Portland to Montreal Pipeline which currently operates only in northbound service.

7.5 Heavier Crude Slate

As the sources of light crude oil diminish worldwide, there has been a significant increase in the volume of heavy

crude refined by North American refineries. In Canada, heavy crude oil accounted for 25 per cent of total crude

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inputs in 2006, up from 19 per cent in 2000. Most forecasters expect that crude slates will continue to get heavier

in the coming decade. Currently, the ability to process increased volumes of heavy crude in Canadian refineries

is limited to certain regions. Significant investments will be required in the coming years to refit refineries to

adapt to changing feedstock. In addition, higher energy use will be required for the further processing necessary

to handle these heavier crude types and meet modern fuel specifications.

7.6 Prospects for East Coast Offshore Development

The three projects currently in production off the coast of Newfoundland and Labrador are expected to have

depleted current reserves by 2020. Estimates of reserve additions will likely take production past 2020, but at

reduced rates. The Hebron project is expected to start production by 2017, but it will be producing a heavy crude

oil. There are a number of offshore exploration programs that may take place over the next few years, but if a

discovery is made, production may not take place before 2020. The Nova Scotia offshore currently only produces

gas, with no large oil discoveries having been made recently.

7.7 Dieselization of the Vehicle Fleet

Several European countries have adopted fiscal measures to encourage the use of diesel engines in order to

achieve their environmental goals for vehicle efficiency. It's possible that Canadian vehicle manufacturers will

also begin to introduce a greater number of diesel-powered cars and trucks in the coming decade.

A refinery has a limited range of flexibility in setting the gasoline to distillate production ratio. Beyond a certain

point, distillate production can only be increased by also increasing gasoline production. For this reason, Europe

is a major gasoline exporter, primarily to the U.S. If Canada moves toward a higher use of diesel-powered

vehicles, Canadian refineries will need to be reconfigured to accommodate the shift in product mix. Diesel

shortages in western Canada are an indication of the challenges this could present.

8. Market Vulnerabilities and Risk Factors

There are a number of vulnerabilities and risk factors in the downstream petroleum industry. Some of these have

been around for many years while others are emerging as factors. There are emerging policy issues that may add

to the complexity of the industry, while others could reduce the flexibility of the production and distribution

systems. Many of the risks associated with security of supply are constantly evolving and, while this list is not

intended to be exhaustive, some of the key factors are briefly described below.

8.1 Environmental Regulations

Since prices for both feedstock and final products are set in international markets, the Canadian petroleum

refining sector is a price taker. Any regulation that does not account for increased energy intensity due to factors

beyond the control of refiners (e.g. increasingly stringent fuel specifications) could place an increased

competitive burden on this sector vis à vis its U.S. counterpart and could affect security of supply in Canada.

Due to the cyclical nature of profits in the industry and the ever-changing regulatory environment, the industry

has become very hesitant to invest in new or existing operations. As much regulatory certainty as possible is

needed to ensure that this much-needed investment takes place.

8.2 Renewable Fuel Standard

Once ethanol is fully integrated into the Canadian gasoline distribution system, there will be an added element of

vulnerability in the supply network. The gasoline component that is blended with ethanol to make the final

product that is used in vehicles is not marketable on its own. It is manufactured to different specifications and

cannot be used without the ethanol component added to it. If the ethanol supply were to be disrupted, the impact

on gasoline supply would not be just the 5% or 10% that is ethanol but the entire gasoline pool would be lost.

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8.3 Tighter Fuel Specifications

The on-going move toward increasingly cleaner products will also reduce the flexibility of the product supply

and distribution network. In some cases, refiners will need to sacrifice volume in order to achieve a cleaner

output. Maintaining the integrity of products that have very strict specifications also presents challenges as they

move through the distribution system. Pipelines that move a variety of products need to carefully plan their

batching to minimize product contamination and volume losses.

8.4 Consistency of Fuel Specifications

Differing fuel specifications between jurisdictions (across both provincial and international borders) make it

more difficult to import petroleum products into regions when there are supply problems. In some cases, fuels are

not able to meet specifications, and therefore cannot be marketed in certain regions. As product must be blended

specifically to meet Canadian or provincial requirements, it is virtually impossible to import small volumes or to

find supply on short notice. The industry has encouraged governments to harmonize fuel specifications.

8.5 Sources for Alternate Supplies

Fuel specifications that are not consistent with those of our major trading partners, primarily the United States

and Europe, make it more difficult, and more costly, to obtain alternate supplies when the Canadian supply is

compromised. Uniquely Canadian fuel requirements can provide barriers to imports if these specifications are not

common in other countries. With enough lead time, arrangements can be made to purchase product that meets

Canadian standards. However, for quick turnaround in an emergency, the more unique the requirement, the fewer

choices there will be for possible suppliers. Purchases of a specialty product will also generally cost more.

8.6 Distribution Network

The economic growth experienced in the Canadian economy in the last decade and the associated increased

demand for trucking capacity has put a strain on this type of transportation. With fewer individuals entering the

trucking profession, it is becoming harder to secure trucks and/or truck drivers to transport product on an ad-hoc

basis. Rail availability is also becoming tight. Longer leads times required to transport goods have made rail less

of a viable option in situations where product needs to be moved quickly. This situation is expected to worsen in

coming years as labour shortages continue.

8.7 Pipeline Capacity

Proposals to reverse Line 9 from Sarnia to Montreal and a portion of the Portland pipeline from Montreal to the

Eastern seaboard could have a major impact on Canadian oil security of supply. Such a move, coupled with the

projected growth in Canadian offshore oil production, could be expected to significantly reduce Canada's

dependence on imported oil. This would make the country much less vulnerable to a supply disruption,

particularly those resulting from geopolitical events.

8.8 Aging Refining Infrastructure

With existing capacity nearly fully utilized, equipment aging and refinery operations becoming more complex,

petroleum product markets are increasingly vulnerable to unplanned refinery shutdowns. Supply interruptions are

becoming more frequent and will become increasingly difficult to manage without substantial investment in new

capacity. The number of incidents that disrupt demand can be expected to increase as new fuel quality and

environmental standards continue to apply pressure on both refineries and the distribution system.

8.9 Geopolitics

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With five of the six largest oil reserve holders located in the Middle East (Canada is number 2), political tensions

in this region will continue to influence oil markets for the foreseeable future. Even when political activities

occur in Middle East countries that do not produce oil, the fear that the action could spill over into oil producing

nations, triggers a reaction in oil prices.

However, partially off-setting these supply pressures is the reality that most Middle East economies are

dependant of oil revenues for the bulk of their national budgets. The oil must keep flowing if local programs are

to be sustained.

Political unrest is not limited to the Middle East. Several other major oil producers, most notably Venezuela,

Nigeria and Russia, have also had production disruptions in recent years because of domestic political events.

8.10 Terrorism

Closely linked to the geopolitics of the Middle East is the increased threat of terrorist activities that could disrupt

oil supplies. Since the terrorist attacks on September 11, 2001, security of energy infrastructure has drawn

significantly more attention both in Canada and around the world. The ever-present threat of further terrorist

events adds a new level of uncertainty to the security of oil supplies and has added a fear premium to the price of

oil on the futures market. Recently, there have also been increased threats from domestic protest groups.

8.11 Weather-related Issues

Severe weather events have also been on the increase in recent years. Hurricanes, tornados, ice storms, floods

and tsunamis have all disrupted either oil production or refined product supplies over the last decade. Scientists

are predicting an increase in such extreme weather conditions that often provide very little lead time and offer

few options for protection.

9. Regional Perspective

Many of the risks and vulnerabilities identified in the previous section will be national issues, affecting most

regions in a similar way. National standards for air quality and greenhouse gas emissions, renewable fuel

standards, world geopolitics and threats from terrorist activity will be national in nature. However, not all regions

will be implicated equally by these factors. In addition, some of the issues, such as aging infrastructure, pipeline

issues and supply options, will have distinct implication in each of the regions.

9.1 Western Canada

For western Canada, the largest vulnerability is reduced access to alternate supplies. With refineries operating at

full capacity most of the time, even the slightest technical problem or temporary disruption to production can

cause significant market impacts. The infrastructure is built to transport products from Alberta to the other

western provinces. Moving product into Alberta, in times of shortage, is much more difficult.

The economic boom in the west in recent years has seen diesel demand, particularly in the oil sands, grow more

quickly than gasoline demand. This is straining the gasoline/distillate ratio at refineries and increasing the need to

import product to balance markets. Being landlocked, with limited access to imported products, it is not always

easy to acquire products on the spot market that meet Canadian specifications.

9.2 The North

Product delivery and fuel quality are the primary concerns for northern regions. Many communities receive

product deliveries only once a year and delivery systems are very weather-dependant. Some markets rely on ice

roads in the winter to transport products by truck, while others depend on air deliveries during the summer. With

shifting weather patterns, some of these windows for delivery are narrowing.

CREEnergy P r o s p e c t u s

With once a year deliver, maintaining fuel quality can become an issue, particularly when fuel standards are

becoming more rigid. The national renewable fuel standard will raise particular concern from a transportation

and storage perspective as well as with respect to fuel performance. The need for dedicated storage tanks for

ethanol will increase the cost of fuel. Ethanol's tendency to absorb water will create performance challenges

particularly in winter.

ANNEX A

Canadian and U.S. Crude Oil Pipelines

ANNEX B

2014 Canadian Refining Capacities

Location Capacity

(b/d)

Capacity ('000

m3/d) Products

Existing Refineries1

North Atlantic Come-By-Chance

(NL) 115 000 18.3 All Products

Imperial Dartmouth (NS) 89 000 14.1 All Products

Irving Oil Saint-John (NB) 250 000 39.7 All Products

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Total Atlantic 408 000 72.2

Petro-Canada Montréal (QC) 130 000 20.7 All Products

Shell Canada Montréal (QC) 130 000 20.7 All Products

Ultramar St-Romuald (QC) 215 000 34.2 All Products

Total Quebec 475 000 75.5

Imperial Nanticoke (ON 118 000 18.8 All Products

Imperial Sarnia (ON) 119 000 18.9 All Products

Nova Sarnia (ON) 80 000 12.7 Petrochemicals

Shell Canada Sarnia (ON) 72 000 11.4 All Products

Suncor Sarnia (ON) 70 000 11.1 All Products

Total Ontario 459 000 73.0

Coop Newgrade Regina (SK) 100 000 15.9 All Products

Moose Jaw Refinery Inc. Moose Jaw (SK) 15 000 2.4 Asphalt

Imperial Strathcona (AB) 187 000 29.7 All Products

Petro-Canada Edmonton (AB) 125 000 19.9 All Products

Husky Lloydminister (AB) 25 000 4.0 Distillate/Asphalt

Shell Canada Scotford (AB) 100 000 15.9 All Products

Total Prairies 552 000 87.8

Chevron Burnaby (BC) 55 000 8.7 All Products

Husky Prince George (BC) 12 000 1.9 All Products

Total British Columbia 67 000 10.7

Total Existing Refineries 2 007 000 319.1

Proposed Refineries2

Newfoundland Refining Company

(NLRC)3 Placentia Bay (NL) 300 000 47.7 All Products

Irving Oil Saint-John (NB) 300 000 47.7 All Products

Total Proposed Refineries 600 000 95.4

ANNEX C

Proposed Refinery Projects for Siksika

Refinery Economics

Oil refineries produce value-added petroleum products from crude oil. Profitability is thus determined

by several different variables:

Feedstock costs (primarily crude oil)

Fuel costs and other operational costs for the refinery itself

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Costs of complying with emissions regulations (particularly NOx)

Market prices for the products produced.

Determining profitability for a specific refinery is very difficult since data on operational and

environmental compliance costs are generally not available. A rough measure could be obtained by

calculating the cost of crude-oil feedstock (though to do this with precision would require knowledge

of the crude blends used in a specific refinery) and comparing that cost with the market value of the

suite of products produced at the refinery. This still requires more information than might be publicly

available for a typical refinery, and is subject to market conditions for the various products produced.

A useful but simplified measure of refinery profitability is the “crack spread.” The crack spread is the

difference in the sales price of the refined product (gasoline and fuel oil distillates) and the price of

crude oil. An average refinery would follow what is known as the 3-2-1 crack spread, meaning for

every three barrels of oil the refinery produces an equivalent two barrels of gasoline and one barrel of

distillate fuels (diesel and heating oil). This ratio of refined product output closely mirrors the

composition in Figure 2.4, but remember that the crack spread is only a first-order approximation of

how profitable a refinery would be at the margin! The higher the crack spread the more money the

refinery will make, so it will be utilizing as much capacity it has available. Inversely, at some lower

crack spread prices, it actually may be in the refinery’s best interest, due to costs for the plant, to scale

back the amount of capacity utilized.

Calculating the 3-2-1 crack spread typically uses published prices for crude oil, gasoline and

distillates. These prices are typically taken from the New York Mercantile Exchange. The NYMEX

has traded contracts for crude oil and gasoline but no contract for diesel fuel (the most-produced of the

distillate fuel oils). In calculating the 3-2-1 crack spread, prices for heating oil futures are typically

used instead. Below is an example of how to calculate the crack spread, using data from 2012.

Oil Price: $84.54/barrel

Gasoline Price: $2.57/gallon

Heating Oil Price: $2.79/gallon

(remember that 42 gallons = 1 barrel)

(2 barrels * 42 gallons/barrel * $2.57/gal of gas) +

(1 barrel * 42 gallons/barrel * $2.79/gal of heating oil) - (3 barrels * $84.54/barrel of oil)

= $79.44 profit / 3 barrels of oil.

The crack spread would thus be $79.44 / 3 = $26.48/barrel of oil

The crack spread, of course, is not a perfect measure of refinery profitability. What it really measures

is whether the refinery will make money at the margin – i.e., whether an additional barrel of crude oil

purchased upstream will yield sufficient revenues from saleable products downstream. In reality,

existing refineries must consider their refining costs in addition to just the cost of crude oil. These

costs include labor (though that is generally a small part of refinery operations); chemical catalysts;

utilities; and any short-term financial costs such as borrowing money to maintain refinery operations.

These variable costs of refining may amount to perhaps $20 per barrel (depending on conditions in

utility pricing and financial markets). In the example above, the true margin on refining would

be $6.58 per barrel of crude oil – much lower than the simple crack spread would suggest.

The crack spread tends to be sensitive to the slate of products produced from the refinery. In the

example above, we used gasoline and distillate fuel oil (heating oil) because those are two typically

high-valued products, and U.S. refineries are generally engineered to maximize production of gasoline

and fuel oil.

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The crack spread is also sensitive to the selection of the oil price used. In the example above, we used

the NYMEX futures price for crude oil, which recall is based on the West Texas Intermediate blend -

a fairly light crude oil. Many U.S. refineries, however, are engineered to accept heavier crude oils as

feedstocks. If there are systematic differences in the prices of heavy crude oils versus West Texas

Intermediate, then the crack spread calculation (while illustrative) may not be sensible for a particular

refinery.

The Energy Information Administration recently published a couple of good articles describing how

the U.S. refinery fleet has been adjusting to changes in U.S. crude oil production. Not only has the

quantity of crude oil produced in the U.S. been increasing rapidly, but the oil coming out of the large

shale plays (like the Bakken in North Dakota) is much lighter than the crude oils typically accepted by

U.S. refineries.

Beginning The Refining Process

First - a word about the refining process. Simply stated, because crude oil is made up of a mixture of

hydrocarbons, the first step in the refining process is to separate the different types of hydrocarbons

from the mix. This is accomplished by heating the crude oil in a process similar to that used in a

“moonshine-still”. During the course of the distillation process different products are boiled off and

extracted at different temperatures. For instance, at the lowest temperatures, less than 360 degrees F.,

the lighter products are recovered such as butane, naphtha, and low octane gasoline. The yield at this

stage is about 20 percent gasoline and about 50 percent residual crude. As the temperature rises to 650

degrees F., distillates such as jet fuel, kerosene, home heating oil and diesel fuel are recovered next.

End Of The Process

Finally, at the more sophisticated refineries, the residual oil that is left, the heaviest and least valued of

the crude is processed even further at temperatures over 1000 degrees F. to extract even more of the

lighter products, principally gasoline. By using these extra steps in the process, gasoline yields of

around 60 percent can be obtained with only about 5 percent residual. Additional processing of the

gasoline from that point can, among other things, remove the sulfur content and for some of the

gasoline, produce a higher octane, which because of this extra processing will cost you more at the

pump.

Seasonal And Regional Production And Markets

Keep in mind that because of many variables, including different taxes levied, seasonal changes and

different blends required in the refining process, the cost of obtaining a gallon of gasoline for the

Calgary market will be less than for a gallon of gasoline sold at the pump in Vancouver. In California,

where much of its oil comes from refineries within the state, special laws call for specific

requirements for lead content and other additives as well as unique gasoline formulations to prevent

smog and other environmental considerations.

These extra requirements relate to higher refining costs that will be passed along in the higher pump

prices. Also, since the quality of all crude oil varies widely, it should be noted that the level or ease

(and cost) of refining depends a great deal on the quality of the crude. For instance, premium crude oil

from Texas, called West Texas Intermediate has the most desirable characteristics for producing the

lighter products like gasoline while premium crude from Nigeria is easier to refine for middle

distillates like home heating oil and jet fuel. In direct contrast, the refining of Saudi Arabian Light will

yield about 50 percent heavy residual crude that must go through the more costly additional processing.

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The Gulf Coast is the leader in oil refinery capacity in the U.S. and has the greatest concentration of

state-of-the-art facilities in the world capable of refining the heavier residual crude. This region

supplies refined products to both the East Coast (more than half of the gasoline, heating oil, diesel,

and jet fuel) and to the Midwest (more than 20 percent). As stated earlier, California operates its own

reformulated gasoline program.

So What Is The Profit-Margin For Refining Crude Oil Into Gasoline?

As of 1999, for every gallon of gasoline refined from crude oil, U.S. oil refiners made an average

profit of 22.8 cents. By 2004, the profits jumped to 40.8 cents per gallon of gasoline refined. In the

specialized California market where the gasoline must conform to the requirements of the California

Air Resources Board, refinery margins were even higher. In fact, this helped Exxon, the largest

company, report a profit (as of February 2008) of $40.6 billion. Nevertheless, one financial tracking

institution reported that the profit-margins have now dropped to about 29.6 cents a gallon or around

60 percent lower than a year ago.

Generally speaking, since there are so many variables to consider, precise cost breakdowns are

difficult to ascertain. According to the Energy Information Administration (EIA), however, which

issues the “Official Energy Statistics from the U.S. Government” the average cost at the pump for a

gallon of gasoline is broken down as follows:

74% - Cost of the crude oil

11% - Taxes

10% - Refining costs

5% - Distribution and marketing

In a simple illustration, let’s assume an oil company is paying $100 for a barrel (42 gallons) of basic

crude oil. Their cost for a gallon will be about $2.38. At a gasoline-pump price of $4.00 per gallon, 44

cents has to pay for taxes and 20 cents for distribution and marketing expenses. This leaves $3.36 for

the oil companies. Out of that total they have to pay for the cost of the gallon of crude oil itself which

was $2.38 and also the 40 cents to refine it into gasoline. This leaves$0.58 profit per gallon of

gasoline. As noted, however, depending on which report one looks at, this profit-margin can range

anywhere between an estimated 30 to 60 cents per gallon.

Oil Companies Caught In A Double Bind?

The oil companies, however, express much grief that they are actually losing their profit-margin

because as crude oil prices continue to rise over $100 per barrel, they are finding it increasingly

difficult to pass any substantial portion of their added costs onto the consumer. Like everyone else,

they claim, the oil industry is going through a traumatic period. On one hand they must strive to

satisfy their shareholders. But, on the other hand, to keep the investors happy a business must grow to

increase profits which, they claim is getting more difficult to do. They are caught in a double bind,

experts say. While the price of oil is increasing, the consumption of gasoline in the U.S. is falling. In

this regard, although crude oil prices more than doubled in the past year, the oil experts say, wholesale

prices for gasoline have risen only 39 percent.

Final Note

Unfortunately, despite the U.S. attempts to reduce oil consumption (3.3 percent in March 2008), that

reduction in consumption will be significantly offset by the increased demand for crude oil from

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developing nations like China and India. And because nearly three-quarters of the cost of gasoline at

the pump is traceable to the cost of the basic crude, despite our lessening demand, the price for

gasoline will keep rising, a factor mostly driven by the increasing global demand for that all too

precious crude oil.

Petro-Canada

Petro-Canada is in the final stages of construction to convert their Edmonton refinery to upgrade and

refine oil sands feedstock exclusively. According to the company, the conversion will displace around

13,515 cubic metres of conventional oil, but will not increase overall capacity of the refinery. The

$2.2 billion conversion project was 79 percent complete at the end of March 2008, and is on track to

start up in the fourth quarter of 2008.

In addition, Petro-Canada is considering the installation of a 3,975 cubic metre per day coker unit at

their refinery in Montreal. The coker unit would allow the refinery to run heavy crude oil. A final

investment decision is expected in the second half of 2008.

REFINERY 6,000

GASLOINE 2.18

DIESEL 2.7

GAS BOIL OFF WILL BE USED FOR

ELECTRIC

JET FUEL 2.28

KEROSENE 3.82

NAPHTHA 2.44

ISOPENTAINE 3.2

FEED STOCK 2.1

LUBRICANTS 2

ASPHALT & ROAD OIL 1.85

THIS IS BASED ON

PRICES WTA

PRODUCT FROM 1/BBL GAL/BBL GAL/20K BBL PER/DAY PER/MONTH

GASOLINE 23.5 141000 $ 307,380.00 $ 9,221,400.00

DIESEL 11 66000 $ 178,200.00 $ 5,346,000.00

JET FUEL 4.5 27000 $ 61,560.00 $ 1,846,800.00

KEROSENE 4.2 25200 $ 96,264.00 $ 2,887,920.00

NAPHTHA 3.7 22200 $ 54,168.00 $ 1,625,040.00

ISOPENTAINE 0.2 1200 $ 3,840.00 $ 115,200.00

PETRO FEEDSTOCK 1.5 9000 $ 18,900.00 $ 567,000.00

LUBRICANTS 0.5 3000 $ 6,000.00 $ 180,000.00

ASPHALT & ROAD OIL 1.3 7800 $ 14,430.00 $ 432,900.00

GAS BOIL OFF 2500CF

TOTALS 50.4 302400 $ 740,742.00 $ 22,222,260.00

CREEnergy P r o s p e c t u s

operational cost $ 89.74 $ 538,440.00 $ 16,153,200.00

NET PROFITS $ 202,302.00 $ 6,069,060.00

One barrel contains 42 gallons of crude oil.

The total volume of products made is 8.4 gallons

greater than the original 42 gallons of crude oil

this represents "processing gain."

ANNEX D

List of acronyms

MBD - thousands of barrels per day

MMBD - millions of barrels per day

M3 - cubic metres

M3/d - cubic metres per day

‘000 M3 - thousands of cubic metres

IEA - International Energy Agency

OECD - for Economic Cooperation and Development

OEE - Office of Energy Efficiency

OPEC - Organization of Petroleum Exporting Countries

Conversion :

1 barrel = 159 litres

1 M3 = 1,000 litres

1 M3 = 6.289811 barrels