Energy Sector: Energy Sources: Petroleum Products Market: Developing a Strategy for Canadian Refining and Oil Security

 

Energy Sources

Canadian Refining and Oil Security
November 2008

PDF Version (1016 KB)

Table of Contents

1. Introduction

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

There are a few market fundamentals that will not change:

  • the marginal cost of producing a barrel of oil is slightly higher today than it was 10 years ago;
  • oil prices are not likely to return to the $20/bbl range;
  • the era of "cheap" oil is over;
  • the world will continue to be reliant on oil for the foreseeable future, particularly in the transportation sector;
  • demand in emerging economies like China and India will continue to grow, perhaps at a slower rate;
  • there is sufficient supply to meet demand in the medium term.

The changing economic conditions do not reduce the vulnerabilities of the Canadian petroleum product supply or make a discussion of security of supply any less relevant.


Return to Top of Page

2. Executive Summary

The events of the last few years have created a market that is significantly different from any in the past. It is, therefore, timely to re-examine oil security of supply issues in the context of today's market realities.

2.1 The World

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 1998-2007, 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 2003, and the continued development and application of new drilling technology and enhanced recovery methods.


Return to Top of Page

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 1997, to 2.8 million barrels in 2007. 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 2007 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.

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.


Return to Top of Page

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.


Return to Top of Page

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.
  • 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.

Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.

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.


Return to Top of Page

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 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.

Figure 1: Crude Oil Prices January 1998 to July 2008

Figure 1: Crude Oil Prices January 1998 to July 2008

Source: NRCan and Energy Information Administration.

The price of oil closed above $100/bbl for the first time on February 19, 2008, 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 2008 and averaging $134/bbl for the month, prices declined, and by October were trading in the $60/bbl range.

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


Return to Top of Page

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 1998-2007, 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 1998, 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 1998-2007 (million barrels per day)
  1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
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

The source of the world's oil supply is also shifting. Production in OECD countries has declined by about 10% since 1998, 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 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%.

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 Spare Capacity (3Q 1998 - 2Q 2008)

Figure 2: OPEC Spare Capacity (3Q 1998 - 2Q 2008)

Source: Natural Resources Canada.

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.


Return to Top of Page

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)

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, 1980 to 1,332 billion barrels on January 1, 2008).


Return to Top of Page

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.

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

Figure 4: World Oil Supply Disruptions

Source: International Energy Agency.

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.


Return to Top of Page

5. Canadian Oil Markets - A Ten Year Perspective

5.1 Political Framework

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.


Return to Top of Page

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.


Return to Top of Page

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 1997 and reached 2.8 million barrels per day in 2007. 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 1990, Canada's annual oil sands production has more than tripled, reaching 1.2 million barrels per day in 2007.

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 2007, 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 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 1998-2007 (MB/D)

Figure 5: Canadian Crude Oil Production 1998-2007 (MB/D)

Source: Statistics Canada.

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 1998.

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 2005 as production of conventional oil off Canada's east coast has increased. In 1998, the North Sea accounted for 42% of imports. By 2007, 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.

Figure 6: Crude Oil Exports and Imports 1998-2007 (thousands of barrels per day)

Figure 6: Crude Oil Exports and Imports 1998-2007 (thousands of barrels per day)

Source: Statistics Canada.
MB/D = Thousand Barrels Per Day.

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.

Figure 7: Canadian Sources of Oil Imports (Percent)

Figure 7: Canadian Sources of Oil Imports (Percent)

Source: Statistics Canada, Catalogue number 45-004.
MB/D = Thousand Barrels Per Day.


Return to Top of Page

5.4 Oil Pipelines

Canadian crude oil is transported across North America via a complex network of pipelines (See Annex A for a pipeline map). According to the National Energy Board, many oil pipeline systems were at or near capacity in 2007 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.


Return to Top of Page

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.

Figure 8: Refineries in Canada 2008 (thousands of cubic metres per day)

Figure 8: Refineries in Canada 2008 (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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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 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.


Return to Top of Page

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.

Figure 9: Canadian Refinery Capacity and Utilization Rates

Figure 9: Canadian Refinery Capacity and Utilization Rates

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.


Return to Top of Page

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 - 2007
Total All Products (Millions of Cubic Metres)
  1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 1998 vs 2007
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 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.

Figure 10: Annual Canadian Demand for Refined Petroleum Products
(Millions of cubic metres)

Figure 10: Annual Canadian Demand for Refined Petroleum Products (Millions of cubic metres)

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 1998 vs 2006

Figure 11: All Petroleum Products 1998 vs 2006


Return to Top of Page

5.11 Product Distribution

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 - 2007

Figure 12: Refined Petroleum Products Production and Sales - 2007

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.

Figure 13: Refinery Supply Orbits

Figure 13: Refinery Supply Orbits


Return to Top of Page

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.

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.


Return to Top of Page

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.

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 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 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.


Return to Top of Page

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.

Figure 14: Canadian Petroleum Product Inventories (Thousand of cubic metres)

Figure 14: Canadian Petroleum Product Inventories (Thousand of cubic metres)


Return to Top of Page

5.15 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.

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.

When the factors that can influence prices - supply/demand, crude oil costs, distribution costs, federal and provincial taxes and local market conditions - all come together, retail prices, and to a lesser degree wholesale prices, can vary significantly between markets.

For a more complete analysis of crude oil and petroleum product prices, readers are encouraged to consult Natural Resources Canada's Fuel Focus website at: www.fuelfocus.nrcan.gc.ca


Return to Top of Page

6. Regional Analysis

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 2008 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.

Table 4: Western Canadian Petroleum Product Supply and Demand - 2007 (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

Source: Statistics Canada 45-004

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 - 2007 (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

Source: Statistics Canada 57-003

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, 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

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.


Return to Top of Page

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 2008 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 - 2007 (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

Source: Statistics Canada 45-004

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.

Figure 16: Quebec/Ontario Clean Products Pipeline

Figure 16: Quebec/Ontario Clean Products Pipeline

Table 8: Ontario Petroleum Product Demand by Sector - 2007 (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

Source: Statistics Canada 57-003

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.


Return to Top of Page

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 2008 Capacity
Company Location Capacity MBD Capacity '000 m3
Irving Oil Saint-John 250 39.7
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 - 2007 (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 - 2007 (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.


Return to Top of Page

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:

  • 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.

Return to Top of Page

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.


Return to Top of Page

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.

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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 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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

8.9 Geopolitics

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

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.


Return to Top of Page

9.2 Ontario

In Ontario, access to alternate sources of product in times of supply shortfalls is a particular challenge. This is more acute in the winter months, when the St. Lawrence Seaway is closed. Trucking in from other jurisdictions small quantities of products that meet Canadian specifications is not always easy.

Ontario is also vulnerable to crude oil supply disruptions in that their supplies are delivered by a single pipeline from the west and one from Montreal. Right now, Ontario refiners have the choice of running Canadian or imported crude oil. If the Sarnia-Montreal leg of the Enbridge pipeline is reversed, Ontario will no longer have access to imported crude. While this would reduce Ontario's exposure to a disruption in imported oil supplies, it would become completely dependent on the Enbridge pipeline from Alberta for its crude supply.

Some of Canada's oldest refineries are located in Ontario. These refineries have been operating at close to full capacity since the Petro-Canada refinery in Oakville was closed. Like western Canada, with very little slack in the system, a relatively minor disruption can have immediate impacts on the market.


Return to Top of Page

9.3 Quebec

Quebec's most significant vulnerability is its dependence on imported crude oil. With supplies of light sweet crude diminishing, Quebec refiners will need to make additional investments to equip their refineries to handle a heavier crude slate. However, if the proposed reversal of the Enbridge pipeline between Sarnia and Montreal goes ahead, Montreal refiners will once again have access to Canadian crude oil, while retaining the option to import crude oil as well. This would add a degree of flexibility to the market and significantly reduce the region's dependence on foreign oil.

Greater use of heavier Canadian crude oil would also bring environmental challenges with it. These feedstocks require more processing, more energy use and more investments in emission reduction technology.


Return to Top of Page

9.4 Atlantic

In Atlantic Canada, the dependence on imported crude oil is the region's greatest risk. With supplies of light crude from the North Sea on the decline, refiners in this region are becoming increasingly dependent on oil imports from OPEC countries. Like Quebec, refiners in this region will need to invest in more intensive processing capacity in order to handle heavier crude slates and address the accompanying environmental challenges.

The implementation of the National Renewable Fuels Standard will present unique challenges for this region. Access to local production of biofuels will be limited. With mostly rural markets and smaller populations, there will be less opportunity to blend higher concentrations in urban markets in order to achieve the averages in the mandate. The higher distribution costs associated with dedicated trucks and barges to move the biofuels will be recovered over much smaller volumes of sales in this region, increasing the per unit cost.


Return to Top of Page

9.5 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.

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.


Return to Top of Page

ANNEX A

Canadian and U.S. Crude Oil Pipelines

Canadian and U.S. Crude Oil Pipelines


Return to Top of Page

ANNEX B

2008 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
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 Lloyminster (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  
1In addition to the possibility of new construction, Petro-Canada, Ultramar and Co-op are assessing the feasibility of expanding production capacity at their existing facilities.
2It is important to note that these are only proposals - on numerous occasions, industry has stressed that these proposals will only be followed through if the economics warrant construction.
3In their proposal, NLRC has indicated that the refinery could be expanded to 600 000 bbl/day in the future.

Return to Top of Page

ANNEX C

Proposed Refinery Projects

Irving Oil

In 2006, Irving Oil announced they were exploring the possibility of building a second refinery in Saint John, New Brunswick. The proposed refinery could process up to 47,700 cubic metres of crude oil a day. Output from the proposed refinery would largely be exported to the U.S. northeast where 1.7 million barrels (270,300 cubic metres) per day of transportation fuels are consumed, with more than one million barrels brought in from outside the region.

In March 2008, Irving Oil and BP PLC announced a Memorandum of Understanding to work together on developing the proposed Eider Rock Refinery. According to Irving, a final construction decision is not expected until 2009. The total cost of the refinery is expected to exceed US $7 billion, and start-up is anticipated for 2015.

Newfoundland and Labrador Refining Corporation (NLRC)

NLRC, a privately held company, announced in 2006 it had initiated a feasibility study to build a new refinery located at the Southern Head of Placentia Bay in Newfoundland. The proposed refinery would have an initial capacity of 47,700 cubic metres per day, with the option to expand to 95,400 cubic metres a day if future market conditions allow for such expansion. Output from the proposed refinery would be exported to the northeastern U.S. and potentially Europe (diesel and jet fuel). The project received federal environmental approval in late April 2008. NLRC is continuing its ongoing efforts to attract financing and/or partners for the project.

Federated Co-operatives

In January 2008, Federated Co-operatives Limited announced an approximately $2 billion expansion to its refinery in Regina. The planned expansion is expected to increase crude processing capacity from its current level of 15,900 cubic metres a day to 20,670 cubic metres a day by 2012. According to Federated, the additional capacity will serve the growing needs of their network of 283 retail gasoline stations.

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.



Return to Top of Page

ANNEXE 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