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Crude Oil
Forecast, Markets & Pipeline Expansions June 2009 Crude Oil Forecast, Markets & Pipeline Expansions
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Canadian Association of Petroleum Producers
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EXECUTIVE SUMMARY For several years, the forecasted growth in Canadian crude oil supply, primarily due to the development of the Alberta oil sands, led industry to conclude there was an urgent need for additional pipeline capacity to connect to new and expanded markets. Growth in crude oil supply is still being forecast; only at a slower rate than previously anticipated. While access to markets remains an important consideration for producers, the need for additional pipeline capacity has been tempered by a lower outlook for supply growth and significant new pipeline capacity now underway. On average, current oil prices are significantly lower than in recent years. The economic downturn in major market areas has also impacted the industry and the global financial crisis has hindered the ability of companies to acquire investment capital. In line with a lower forecasted growth in crude oil supply, a lower growth in market demand is also anticipated given the economic downturn and the fact that refinery conversions and expansions are proceeding at a slower pace.
Canadian Crude Oil Production and Supply
Canadian Crude Oil Production
CAPP conducted a survey of oil sands producers in early 2009 to determine their plans for production of both bitumen and upgraded crude oil for the period from 2009 to 2025. From this data, CAPP has prepared a “Growth Case” and an “Operating & In Construction Case.” The Growth Case represents the expected outlook, which assumes the current investment climate will improve over time. The Operating & In Construction Case, a more conservative outlook, only includes projects that are currently in operation or are under construction. As such, this latter case represents a minimum potential growth outlook from the oil sands. The forecast for Canadian crude oil production under both cases is shown in the following table.
million b/d
2008
2015
2020
2025
Growth Operating & In Construction
2.72
3.29
4.00
4.17
2.72
3.02
3.03
2.84
In the Operating & In Construction Case, production is forecast at only 2.8 million b/d by 2025 due to the decline in conventional production. Although conventional production as a whole is expected to decline gradually, this rate of decline is offset somewhat by an increase in light crude oil production from the Bakken field in Saskatchewan, which is expected to exhibit strong growth in the next few years. Later in the forecast, the Hebron heavy oil project in Atlantic Canada is expected to come on stream by 2017.
Canadian Oil Sands & Conventional Production thousand barrels per day
5,000
Actual
Forecast Atlantic Canada
4,000
June '08 Moderate Growth Forecast
Oil Sands Growth
3,000
2,000
Oil Sands Operating & In Construction
1,000 Conventional Heavy Conventional Light
Pentanes 0 2005
2007
2009
2011
2013
2015
2017
2019
2021
2023
2025
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Crude Oil Markets
uncertain at this stage, however, given limited pipeline access to this region from western Canada.
CAPP also surveyed refineries in Canada and the U.S. to obtain information on their current capability and plans to process additional volumes of western Canadian crude oil. This information is intended to help industry gain a better understanding of the potential markets for the expected growth in oil sands supply, and in turn, assist the industry in the evaluation of pipeline projects connecting supply to these potential markets. Based on the survey results, the potential demand for Canadian crude oil in most markets is relatively flat. However, the U.S. Midwest is expected to take more western Canadian crude oil, as a result of a number of planned refinery expansions and conversions to process heavier crude oil. The U.S. Gulf Coast is considered a market with significant potential given its large refining capacity and the ability of many of these refiners to process heavy crude. Also, the steep decline in Mexico’s production and Venezuela’s recent shift towards exporting oil to non-U.S. markets such as China, are factors that could make securing supply from Canada more attractive in the future. The full potential of this market remains
Crude Oil Pipelines and Expansions The major pipeline projects that are currently under construction will add over one million b/d in pipeline capacity exiting western Canada by the end of 2010. A corresponding growth in supply of one million b/d is not expected to occur until 2016. Current pipeline capacity underway or in the regulatory process will provide excess capacity for a number of years and sufficient pipeline capacity available exiting Western Canada throughout the forecast period. There are numerous pipeline project proposals presented. However, many of these proposals were developed in response to earlier expectations that additional capacity was required to meet more rapid growth in oil sands production than is currently being forecast. Given the current supply outlook and market conditions, the timing of most of these pipeline proposals has been delayed.
Market Demand for Western Canadian Crude Oil – Actual 2008 vs 2015 Potential
thousand barrels per day
623 Supply 2008 - 2,436 2015 - 3,308
482 [547]
Non-US 8
398
PADD IV PADD V
PADD II
612
2,708 255 [257] 149 [171]
1,796 1,155 [2,005] 68 [74]
2009 Total Refining Capacity
PADD I
8,378
PADD III 89 [380+]
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230 [253]
3,746
Canadian Association of Petroleum Producers
2008 Actual Demand
Additional Demand - 2015 Potential
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Canadian & U.S. Crude Oil Pipelines All Proposals Canadian & U.S. Crude Oil Pipelines All Proposals
Enbridge Gateway Kinder Morgan TMX Northern Leg Kinder Morgan TMX2 Expansion TMX3 Expansion Burnaby
1 2 Edmonton
3
Trans Mountain
Hardisty Altex
Anacortes
Enbridge Alberta Clipper
5
Express TransCanada AB-USGC Keystone XL
Enbridge (North Dakota) Expansion
6
Enbridge Southern Access Expansion Enbridge Southern Access Extension Montreal
9 8
TransCanada AB-California
7
Salt Lake City
Guernsey
Enbridge
4 Flanagan
TransCanada Keystone
12
BP/Enbridge GAP Phase 1
BP
BP/Enbridge GAP Phase 2 Centurion Pipeline
11
BP/Enbridge GAP Phase 3 ExxonMobil/Enbridge Pegasus Expansion
Buffalo
Wood River
13
23
Houston
Enbridge Ohio Access 20
Enbridge Spearhead Expansion (North)
Philadelphia Sunoco to Toledo Mustang Expansion
Capline
14
21
Sunoco Buffalo to Philadelphia
Mid Valley
Cushing
22
16 Chicago 19 Toledo 15 Lima 18 Patoka
Portland
Sarnia
St. Paul
Platte
17
17
10
Enbridge Trailbreaker Portland Pipeline Reversal
TransCanada Louisiana Access Sunoco to USGC
St. James
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TABLE OF CONTENTS Executive Summary
i
List of Figures and Tables
v
1 Introduction
1
2
2
Crude Oil Production and Supply Forecast
2.1 Canadian Crude Oil Production
2
2.2 Western Canadian Crude Oil Production
3
2.2.1 Oil Sands
3
2.2.2 Conventional Crude Oil Production
5
2.3 Western Canadian Crude Oil Supply
6
2.4 Methodology
7
2.5 Production and Supply Summary
8
3
9
Crude Oil Markets
3.1 Canada
10
3.1.1 Western Canada
10
3.1.2 Ontario
10
3.1.3 Québec
10
3.2 United States
11
3.2.1 PADD I (East Coast)
11
3.2.2 PADD II (Midwest)
12
3.2.3 PADD III (Gulf Coast)
14
3.2.4 PADD IV (Rockies)
15
3.2.5 PADD V (West Coast)
15
3.3 Asia
17
3.4 Methodology
17
3.5 Markets Summary
18
4
19
Crude Oil Pipelines
4.1 Major Crude Oil Pipelines
19
19
4.1.1 Existing Major Crude Oil Pipelines
4.2 Crude Oil Transportation Requirements
21
4.3 Crude Oil Pipeline Expansions/Proposals
22
4.3.1 Crude Oil Pipeline Expansions/Proposals to the U.S. Midwest, Ontario, Québec and the East Coast
22
4.3.2 Crude Oil Pipeline Expansions/Proposals to the U.S. Gulf Coast
25
4.3.3 Crude Oil Pipeline Expansions/Proposals to the West Coast
27
4.3.4 Other Proposals
28
4.3.5 Diluent Pipeline Proposals
29
4.4 Pipeline Summary
29
Glossary
30
APPENDIX A: Acronyms, Abbreviations, Units and Conversion Factors
32
APPENDIX B: CAPP Canadian Crude Oil Production and Supply Forecast 2009 – 2025
33
APPENDIX C: Canadian and U.S. Crude Oil Pipeline Expansions/Proposals
37
APPENDIX D: Crude Oil Pipelines and Refineries
39
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List of Figures and Tables Figures Figure 2.1
Canadian Oil Sands & Conventional Production
3
Figure 2.2
Oil Sands Regions
4
Figure 2.3
Growth Case - Western Canada Oil Sands & Conventional Production
4
Figure 2.4
Operating & In Construction - Western Canada Oil Sands & Conventional Production
5
Figure 2.5
Growth Case - Western Canada Oil Sands & Conventional Supply
7
Figure 2.6
Operating & In Construction - Western Canada Oil Sands & Conventional Supply
8
Figure 3.1
Market Demand for Western Canadian Crude Oil – 2008 Actual vs 2015 Potential
9
Figure 3.2
Western Canada: Forecast Western Canadian Crude Oil Receipts
10
Figure 3.3
Ontario: Forecast Western Canadian Crude Oil Receipts
10
Figure 3.4
Petroleum Administration for Defense Districts
11
Figure 3.5
2008 PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil
11
Figure 3.6
2008 PADD II: Foreign Sourced Supply by Type and Domestic Crude Oil
12
Figure 3.7
PADD II (North): Forecast Western Canadian Crude Oil Receipts
12
Figure 3.8
PADD II (East): Forecast Western Canadian Crude Oil Receipts
13
Figure 3.9
PADD II (South): Forecast Western Canadian Crude Oil Receipts
14
Figure 3.10 2008 PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil
14
Figure 3.11 PADD IV: Forecast Western Canadian Crude Oil Receipts
15
Figure 3.12 2008 PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil
16
Figure 3.13 Washington: Forecast Western Canadian Crude Oil Receipts
16
Figure 3.14 2008 PADD V (California): Foreign Sourced Supply by Type and Domestic Crude Oil
17
Figure 4.1
Current Crude Oil Expansions from Western Canada
21
Figure 4.2
Pipeline Proposals to the U.S. Midwest, Ontario and U.S. East Coast
22
Figure 4.3
Pipeline Proposals to the U.S. Gulf Coast
25
Figure 4.4
Pipeline Proposals to U.S. West Coast
27
Figure 4.5
Diluent Pipeline Proposals
28
Tables Table 2.1
Canadian Crude Oil Production
2
Table 2.2
Western Canadian Crude Oil Production
3
Table 2.3
Western Canadian Crude Oil Supply
6
Table 3.1
Summary of Major Announced Refinery Upgrades in Eastern PADD II
13
Table 3.2
Summary of Major Announced Refinery Upgrades in PADD III
15
Table 3.3
Total Oil Product Demand in Major Asian Countries
17
Table 4.1
Approved Oil Pipeline Expansions from Western Canada
21
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1
introduction
Historically, CAPP has prepared an annual Canadian crude oil production and supply forecast to provide industry and the general public with a view of the long-term outlook for Canadian production trends and available supply to markets. Beginning in 2007, CAPP expanded the report to include a synopsis on the potential markets for this crude oil supply in an attempt to capture and summarize the market choices available to industry participants as they evaluate proposed pipeline expansions or new pipeline projects. For several years, the forecasted growth in Canadian crude oil supply, primarily due to the development of the Alberta oil sands, led industry to conclude that there was an urgent need for additional pipeline capacity to connect to new and expanded markets. Growth in crude oil supply is still being forecast; only at a slower rate than previously anticipated. While access to markets remains an important consideration for producers, the need for additional pipeline capacity has been tempered by a lower outlook for supply growth. Over the past 12 months, the industry has witnessed a dramatic change in oil prices. The benchmark WTI crude oil price dropped from a peak in July 2008 of over US$140 per barrel to less than US$40 per barrel by year-end. On average, current prices are significantly lower than in recent years. The economic downturn in major market areas has also impacted the industry and the global financial crisis has hindered the ability of companies to attract investment capital.
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Canadian Association of Petroleum Producers
CAPP’s estimate of industry capital spending for oil sands development was reduced to $10 billion dollars for 2009 compared to $20 billion in 2008. The forecast for market demand growth is also lower than in the previous report, which is in line with the lower forecasted growth in supply. As a result, many pipeline proposals have been deferred but remain as options that could respond to future market needs. The outline of the report is as follows: • Chapter 1 provides an introduction to the report • Chapter 2 discusses the latest crude oil production and supply forecast • Chapter 3 summarizes the major potential crude oil markets • Chapter 4 describes the existing major crude oil pipeline network and proposed expansions
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2
Crude Oil Production and Supply Forecast
According to the Oil and Gas Journal, Canada has total proven oil reserves of over 178 billion barrels. The two major oil producing areas in Canada are the Western Canada Sedimentary Basin (WCSB) and Atlantic Canada. While CAPP has included a forecast of production from Atlantic Canada in this report, the primary focus will be on production from Western Canada since most of the growth in oil production is expected to be derived from the oil sands areas located primarily in the western province of Alberta. CAPP conducted a survey of oil sands producers in early 2009 to determine their planned production of bitumen and upgraded crude oil for the period from 2009 to 2025. These results were subsequently adjusted to reflect: the historical performance trends of oil sands projects following start up, the status of projects, and potential labour and capital constraints. The majority of oil sands projects, particularly in situ, are executed in multiple phases. Historically, in situ projects require some time to ramp up to capacity while new mining projects typically require some fine tuning before full capacity is maintained on a consistent basis. From this data, CAPP has prepared a “Growth Case”, representing the expected outlook which assumes the eventual return of higher oil prices and investment activity. In addition, a lower forecast has also been prepared using the same risk factors but includes only projects currently in operation or under construction. This latter case represents a minimum potential growth from the oil sands.
2.1 Canadian Crude Oil Production Western Canadian crude oil production averaged 2.4 million b/d in 2008 and is projected to grow significantly over the forecast period due to development of the oil sands. On the conventional side, both light and heavy production in the WCSB is declining. Production in Atlantic Canada is expected to grow in 2017 with the expected start of production from the Hebron heavy oil project. In 2008, production in Atlantic Canada was 342,000 b/d, which accounted for about 13 percent of total Canadian crude oil production of 2.7 million b/d.
Table 2.1 Canadian Crude Oil Production million b/d
2008
2015
2020
2025
Growth
2.72
3.29
4.00
4.17
Operating & In Construction
2.72
3.02
3.03
2.84
Table 2.1 shows the forecast for Canadian crude oil production under the Growth Case and the “Operating & In-Construction” Case. In latter case, the production is forecast at only 2.8 million b/d by 2025 due to the decline in conventional production (Figure 2.1).
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Figure 2.1 Canadian Oil Sands & Conventional Production thousand barrels per day
5,000
Actual
Forecast Atlantic Canada
4,000
June '08 Moderate Growth Forecast
Oil Sands Growth
3,000
2,000
Oil Sands Operating & In Construction
1,000 Conventional Heavy Conventional Light
Pentanes 0 2005
2007
2009
2011
2013
2015
2.2 Western Canadian Crude Oil Production
2019
2021
2023
2025
2.2.1 Oil Sands
In 2008, over 87 percent of all Canadian crude oil production came from Western Canada. Western Canadian crude oil production is comprised of conventional oil and oil sands production. In 2006, oil sands production reached over 1.1 million b/d and surpassed conventional crude oil production for the first time. Table 2.2 shows the forecast for total western Canadian crude oil production in both cases.
Table 2.2 Western Canadian Crude Oil Production
3
2017
million b/d
2008
2015
2020
2025
Growth
2.38
3.16
3.78
4.05
Operating & In Construction
2.38
2.89
2.81
2.72
Canadian Association of Petroleum Producers
The three main oil sands deposits are located in the Peace River, Athabasca and Cold Lake areas in the province of Alberta (Figure 2.2). The Alberta Energy Resources and Conservation Board (ERCB) has designated three geological zones for the major oil sands areas and estimated that these areas contain an ultimate recoverable resource of 315 billion barrels, with remaining established reserves of 173 billion barrels at year-end 2007. There are also smaller deposits in northwest Saskatchewan, next to the Athabasca oil sands deposit. The Saskatchewan Ministry of Energy and Resources has estimated 2.7 million hectares of potential land but the resource base has not been officially determined. Bitumen is produced from the oil sands by mining and extraction, in situ thermal recovery and in situ non-thermal recovery. In areas where the oil is located near the surface, open-pit mining is the most efficient method. However, to recover oil that is located further below the surface, in situ techniques are employed. Common in situ thermal extraction techniques include Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). Of the remaining established reserves, 142 billion barrels, or 82 percent, is considered recoverable by in situ methods and 31 billion barrels from surface mining.
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Figure 2.2 Oil Sands Regions
In 2008, 629,000 b/d was mined, which is slightly over half of the total oil sands production. Currently, all mined bitumen is upgraded as part of an overall integrated operation. This trend of upgrading mined bitumen is expected to continue throughout the forecast period for most projects. Production from the upcoming Kearl mining project could be processed at Imperial refineries in Alberta or processed at other upgraders in Alberta.
Athabasca Deposit Fort McMurray
Area of Potential
Peace River
Peace River Deposit
In contrast, the majority of in situ bitumen production is currently not upgraded prior to transporting it to market. Suncor’s Firebag production is the exception. One recent example, however; of an operating in situ project coupled with upgrading is the Long Lake project operated by Nexen Inc. It produced its first upgraded crude oil at the end of January 2009.
Cold Lake Deposit Edmonton
Lloydminster
Calgary
Proponents of many of the oil sands projects that were included in the last report have since announced project delays until a time when they believe that their investment can generate a high enough rate of return. On one side of the equation, low oil prices and more difficulty in attracting investment capital have a negative impact on project economics. On the other hand, supply costs for projects are starting to decrease gradually with lower estimates for labour, materials and equipment.
Oil sands production currently makes up just over half of western Canada’s total crude oil production. It is expected to grow from over 1.2 million b/d in 2008 to approximately 2.2 million b/d in 2015 and to about 3.3 million b/d in 2025 in the Growth Case (Figure 2.3). The Growth Case is based on the assumption that oil sands projects will be developed and brought into service gradually, at a pace similar to historical and current trends. Historically, in situ projects require time to ramp up to capacity while new mining projects typically require some fine tuning before capacity is maintained on a consistent basis.
Figure 2.3 Growth Case - Western Canada Oil Sands & Conventional Production thousand barrels per day
5,000
Actual
4,000
Forecast
June '08 Moderate Growth Forecast
In Situ
3,000
2,000 Mining 1,000
0 2005
Conventional Heavy Conventional Light
Pentanes 2007
2009
2011
2013
2015
2017
2019
2021
2023
2025
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2.2.2 Conventional Crude Oil Production
The integrated mining projects in operation are listed below in chronological order: • The Suncor Steepbank and Millennium Mine;
Conventional crude oil production in western Canada has been declining since the late 1990s as a result of the maturity of the basin. By 2025, total conventional crude oil production is expected to decrease from one million b/d in 2008 to about 589,000 b/d. In 2008, Alberta conventional light crude oil production was flat due to higher oil prices, which led to higher drilling activity. The Government of Alberta also announced new, one-year, incentive programs to stimulate activity in Alberta in March 2009. Overall, conventional production is expected to gradually decline, on average, by 4 percent through the forecast period in Alberta and British Columbia.
• The Syncrude Mildred Lake and Aurora Mine; • The Athabasca Oil Sands Project (AOSP), which is a joint venture between Shell, Chevron and Marathon Oil; and • The CNRL Horizon Project, which produced its first oil in February 2009. The expansions by Shell and Syncrude and the Imperial Kearl Lake project are the three major mining projects currently under construction. In the Operating and In Construction Case, oil sands production is expected to grow from over 1.2 million b/d in 2008 to approximately 1.9 million b/d in 2015 and to about 2.0 million b/d in 2025 (Figure 2.4). Please refer to Appendix B.1 and Appendix B.2 for detailed production forecast data.
Saskatchewan light crude oil production exceeded expectations by increasing almost 13 percent in 2008. This growth can be attributed to the higher drilling activity and production from the Bakken field. The Bakken oil field in south east Saskatchewan is a significant conventional oil play in Canada and continues to generate strong interest as a result of the improved use of existing technology. However, in a lower oil price environment, the growth in the near term is expected to be more modest than
Figure 2.4 Operating & In Construction - Western Canada Oil Sands & Conventional Production thousand barrels per day
5,000
Actual
Forecast
4,000 June '08 Moderate Growth Forecast
3,000 In Situ
2,000
Mining
1,000
Conventional Heavy Conventional Light
Pentanes 0 2005
5
2007
2009
2011
2013
2015
Canadian Association of Petroleum Producers
2017
2019
2021
2023
2025
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in recent experience. The decline in heavy crude oil production in Saskatchewan has been offset somewhat by the production from the Lower Shaunavon field. In Manitoba, production rose 6 percent in 2008. However, it should be noted that the Sinclair field, which was designated in 2005, and was the first major discovery in Manitoba in many years, accounted for 30 percent of the province’s crude oil production. Production is expected to start declining within the next 2 years as the field matures.
2.3 Western Canadian Crude Oil Supply Of particular interest to market participants is the supply of actual crude oil types that will be available from initial production. On a volumetric basis, supply is greater than production because supply includes pentanes/condensate volumes that have been imported to supplement the locally produced volumes of condensate for use as diluent. Diluent is necessary in order to transport the non-upgraded bitumen production to market. The CAPP forecast categorizes the various crude oil types that comprise western Canadian crude oil supply into four major categories: Conventional Light, Conventional Heavy, Upgraded Light and Bitumen Blend. The “Bitumen Blend” category includes upgraded heavy sour crude, bitumen diluted with upgraded light crude oil (also known as “SynBit”) and bitumen diluted with condensate (also known as “Dilbit”). The most common form of Bitumen Blend is bitumen blended with a standard condensate such as pentanes plus, which is mainly recovered from processing natural gas, to create a type of crude oil that meets pipeline specifications for density and viscosity. An example of such a Dilbit would be Cold Lake crude oil, which has a density of about 930 kg/m3 (21° API) and a sulfur content of 3.6 percent. As discussed above, the main source of diluent is natural gas condensates that are produced in western Canada. However, this diluent supply has not been sufficient to meet the needs of growing bitumen production. Companies imported over 60,000 b/d of diluent into Alberta by rail in 2008. To meet growing demand for diluent, Enbridge is building the Southern Lights diluent pipeline from Chicago to Alberta. The pipeline will have an initial capacity of 180,000 b/d and is expected to be in service in July 2010. Demand for condensate imports will exceed the initial capacity of this pipeline by 2015 in the Growth Case.
Subsequently, rail and truck imports could be used to increase the condensate supply available to market in the interim. Potential longer-term solutions include blending more upgraded light crude oil with bitumen or the consideration of additional diluent pipeline options. It should be noted that this latest forecast incorporates the fact that fewer companies reported an intention to use upgraded synthetic crude oil as a source of diluent this year than in the past. Blending with a traditional condensate diluent requires a 70:30 bitumen to condensate ratio. When upgraded light crude is used as the diluent, the blending ratio is approximately 50:50.
Table 2.3 Western Canadian Crude Oil Supply million b/d
2008
2015
2020
2025
Growth
2.44
3.31
3.94
4.24
Operating & In Construction
2.44
3.02
2.95
2.87
Table 2.3 shows the total western Canadian crude oil supply projections for both cases. Please refer to Appendices B.3 and B.4 for detailed supply data. In the Growth Case, upgraded light crude oil supply is projected to grow from about 564,000 b/d in 2008 to 1.0 million b/d in 2015 and 1.3 million b/d by 2025. The upgraded light crude oil supply includes the upgraded light crude oil volumes produced from: • Upgraders that process conventional heavy oil, e.g., the Husky Upgrader at Lloydminister and the CCRL Upgrader in Regina; • Integrated mining and upgrading projects, e.g., Suncor, Syncrude and CNRL operations; • Integrated in situ projects, e.g., the Nexen Long Lake project; • Offsite upgraders, e.g., the Athabasca Oil Sands Project; and • Some Merchant Upgraders Bitumen Blend, which makes up the heavy crude oil supply from the oil sands, is forecasted to increase from 933,000 b/d in 2008 to 1.6 million b/d in 2015 and up to 2.4 million b/d in 2025 (Figure 2.5).
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Figure 2.5 Growth Case - Western Canada Oil Sands & Conventional Supply
thousand barrels per day
5,000
Actual
4,000
Forecast June '08 Moderate Growth Forecast
3,000
Bitumen Blend*
2,000 Upgraded Light
1,000
0 2005
Conventional Heavy Conventional Light 2007
2009
2011
2013
2015
2017
2019
2021
2023
2025
* Bitumen Blend includes some volumes of upgraded heavy sour crude oil and bitumen blended with diluent or ugpraded crude oil.
In the Operating and In Construction Case, the projected growth from the oil sands projects can no longer offset the declines in conventional production by 2015. The supply of upgraded light crude oil is forecasted to grow from 564,000 b/d in 2008 to 911,000 b/d in 2015. Bitumen Blend is forecasted to grow from 933,000 b/d in 2008 to 1.4 million b/d in 2015. From 2015 to the end of the forecast period, supply of both upgraded light crude oil and Bitumen Blend is essentially flat. In this Case, there would be sufficient condensate imports available throughout the forecast period after the construction of the Enbridge Southern Lights diluent pipeline (Figure 2.6).
2.4 Methodology From the survey data, CAPP determined the amount of upgraded crude oil and bitumen that could potentially be available to the market. The following key assumptions have been used to determine available oil sands supply:
a) All bitumen must be blended with either condensate or upgraded light crude oil prior to being transported by pipeline. b) Condensate is the preferred diluent over upgraded light crude oil. c) Prior to the in-service of the Enbridge Southern Lights diluent import pipeline in July 2010, the amount of western Canadian condensate production plus railed imports is not sufficient to blend with expected bitumen production and, therefore, some producers will blend their bitumen with upgraded light crude oil to meet pipeline specifications. d) By 2010, Southern Lights imports will provide additional diluent to western Canadian producers; however, some producers may continue to use some upgraded crude oil to blend with bitumen. CAPP has not surveyed conventional crude oil producers but has instead relied upon historical trends, recent announcements and discussions with provincial government representatives to derive its forecast.
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Canadian Association of Petroleum Producers
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Figure 2.6 Operating & In Construction - Western Canada Oil Sands & Conventional Supply
thousand barrels per day
5,000
Actual
4,000
Forecast June '08 Moderate Growth Forecast
3,000 Bitumen Blend* 2,000 Upgraded Light
1,000
0 2005
Conventional Heavy Conventional Light 2007
2009
2011
2013
2015
2017
2019
2021
2023
2025
* Bitumen Blend includes some volumes of upgraded heavy sour crude oil and bitumen blended with diluent or ugpraded crude oil.
2.5 Production and Supply Summary Much has changed over the last year. A number of oil sands projects have been deferred or cancelled due to factors including lower oil prices and challenges in attracting investment capital. CAPP’s latest forecast reflects the changed business environment and is consequently lower than its June 2008 Moderate Growth Case. The average annual growth rate in oil sands production is 6 percent over the forecast period. Current oil sands production of 1.2 million b/d is forecasted to increase to 2.2 million b/d in 2015 then to 3.3 million b/d by 2025.
Canadian conventional production is expected to decline gradually however; light crude oil production from the Bakken field in Saskatchewan is expected to grow in the next few years. Further out on the horizon, the Hebron heavy oil project in Atlantic Canada is expected to come on stream by 2017 thereby increasing crude oil supply in the region.
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3
Crude Oil Markets
In addition to examining the prospects for crude oil production, it is useful to have an understanding of the potential market demand for the expected growth in oil sands supply. This assessment will, in turn, assist the industry in the evaluation of the various pipeline projects that are being proposed. In this context, CAPP surveyed refineries in Canada and the U.S. to obtain information on their current capability and plans to process additional volumes of western Canadian crude oil and, in particular, oil sands to 2015. (particularly, Illinois, Indiana, Michigan, and Ohio); PADD IV; California and Washington in PADD V. Since the reversal of the Enbridge Spearhead pipeline and the ExxonMobil Pegasus pipeline in early 2006, western Canadian crude oil has flowed to the Cushing, Oklahoma hub and the U.S. Gulf Coast, respectively.
In 2008, total crude oil supply from western Canada was over 2.4 million b/d. Domestic demand for western Canadian crude oil was approximately 712,000 b/d and the remaining supply of over 1.7 million b/d or 70 percent was exported (Figure 3.1). The primary markets for western Canadian crude oil are currently: British Columbia; Alberta; Saskatchewan; Ontario; Minnesota; eastern PADD II
Figure 3.1 Market Demand for Western Canadian Crude Oil – Actual 2008 vs 2015 Potential thousand barrels per day 623 Supply 2008 - 2,436 2015 - 3,308
482 [547]
Non-US 8
398
PADD IV PADD V
PADD II
230 [253]
3,746
612
2,708 255 [257] 149 [171]
1,796 1,155 [2,005] 68 [74]
PADD I
8,378
PADD III 89 [380+]
9
2009 Total Refining Capacity
Canadian Association of Petroleum Producers
2008 Actual Demand
Additional Demand - 2015 Potential
(A47595)
3.1 Canada
3.1.2 Ontario
Canadian refineries that have access to western Canadian crude oil have a total refining capacity of over one million b/d. In 2008, these refineries processed about 712,000 b/d of western Canadian crude oil. This is expected to increase to approximately 788,000 b/d by 2015 with planned refinery expansions.
There are four refineries (excluding the Nova Chemical refinery and petrochemical complex in Sarnia) located in Ontario with a total refining capacity of 398,000 b/d. These refineries process western Canadian crude oil as well as crude oil (foreign imports and Atlantic Canada production) that is received by tankers via the Portlandto-Montréal pipeline and, subsequently, the Enbridge Montréal-to-Sarnia pipeline (Line 9). Ontario refineries have, for a number of years, selected their feedstock sources based on both availability and pricing.
3.1.1 Western Canada There are eight refineries located in western Canada with a total refining capacity of about 622,500 b/d. These refineries process western Canadian crude oil exclusively. The Moose Jaw asphalt plant in Moose Jaw, Saskatchewan produces mostly asphalt while other refineries manufacture a wide range of petroleum products. In 2008, they received 481,800 b/d of crude oil and this is expected to increase to 547,200 b/d in 2015 (Figure 3.2).
Figure 3.2 Western Canada: Forecast Western Canadian Crude Oil Receipts Total refining capacity = 622
thousand barrels per day
600 500
Figure 3.3 Ontario: Forecast Western Canadian Crude Oil Receipts 400
400
thousand barrels per day
Total refining capacity = 398
350 300
300
250
200
200
100 0
According to Statistics Canada, Ontario refineries received 367,400 b/d of crude oil in 2008 from the following sources: Western Canada (230,300 b/d or 63 percent); Eastern Canada (18,700 b/d or 5 percent); the United Kingdom (33,200 b/d or 9 percent); Saudi Arabia (31,200 b/d or 8 percent); United States (23,900 b/d or 6 percent); and other foreign sources (30,100 b/d or 8 percent). Receipts of western Canadian crude oil are projected to remain flat for the forecast period (Figure 3.3.)
150 2008
2009
2010
2011
2012
2013
2014
2015
Light Synthetic Conventional Light Sweet Conventional Medium Sour Heavy
Receipts of conventional light sweet crude oil are expected to fall, in part due to the maturity of the basin as well as refinery conversions. Receipts of light synthetic and heavy crude oil are expected to increase throughout the forecast period. Of note, the Petro-Canada conversion project at its Edmonton refinery has been completed; the refinery began to process 100 percent oil sands feedstock in January 2009. Also, there are plans for the Consumers’ Co-operative refinery located in Regina to expand by 30,000 b/d and to use some light synthetic crude oil as feedstock by 2012.
100 50 0
2008
2009
2010
2011
2012
2013
2014
2015
Light Synthetic Conventional Light Sweet Conventional Medium Sour Heavy
3.1.3 Québec Québec has three refineries. The two refineries located in Montréal have a combined refining capacity of 260,000 b/d, and the refinery in Québec City has a capacity of 215,000 b/d. The Montréal refineries process both crude from Eastern Canada and foreign sources received from the Portlandto-Montréal pipeline. If the Enbridge Montréal-to-Sarnia pipeline (Line 9) is reversed in the future, the Montréal market could be a new outlet for western Canadian crude oil supply. As noted in the 2008 report, Petro-Canada Crude Oil Forecast, Markets & Pipeline Expansions
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3.2.1 PADD I (East Coast)
had previously announced that it was considering adding a 25,000 b/d coker at its refinery in Montréal, which would displace some light crude oil with heavy crude oil. However, a decision on this project had been deferred. The Suncor and Petro-Canada merger was announced in March 2009. At this time, it is uncertain if the merger will have any impact on the timing of this project.
PADD I is located along the east coast of the United States. There are 14 refineries in Delaware, Georgia, New Jersey, Pennsylvania, Virginia and West Virginia with a total capacity of over 1.8 million b/d. In 2008, refinery imports of foreign crude oil totaled 1.4 million b/d and over half of these volumes were light sweet crude oil (Figure 3.5). Over 259,000 b/d (or 2 percent) of the crude oil processed in PADD I refineries was sourced from Canada. Of these volumes, 68,200 b/d came from western Canada. These receipts, with the bulk being heavy crude oil, were delivered by pipeline. Without additional pipeline access to this market, western Canadian crude oil deliveries are expected to remain relatively flat through 2015. PADD I refineries have the potential to process western Canadian crude oil by displacing imports of other foreign sourced crude oil, in particular, light sweet crude oil. There are pipeline proposals being assessed to serve this market with western Canadian crude oil.
3.2 United States The United States, with a total refining capacity of almost 18 million b/d, is Canada’s largest market for crude oil exports. In 2008, Canada was the largest exporter of crude oil to the U.S., ahead of both Mexico and Saudi Arabia. Canada exported over 1.9 million b/d, which was equivalent to almost 19 percent of total U.S. imports from foreign sources. Of this volume, 1.7 million b/d was sourced from Western Canada (Figure 3.1). The U.S. demand for western Canadian oil supply is expected to reach 2.9 million b/d in 2015. The bulk of this growth is expected to be heavy crude oil. The U.S. is a natural market for much of Canada’s rising crude oil supply, in CAPP’s view, because of its geographic proximity to the U.S. and the geopolitical stability in the country.
Figure 3.5 2008 PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil
The U.S. Department of Energy divides the 50 states in the U.S. into five Petroleum Administration for Defense Districts or PADDs (Figure 3.4). The PADDs were originally delineated during World War II for oil allocation purposes and are helpful in this report to facilitate the following discussion on the various markets in the U.S.
Figure 3.4 Petroleum Administration for Defense Districts PADD IV: Rockies
PADD V: West Coast, AK, HI
WA
ND
MT OR
WY NV AK
MI
IA IL
KS
CO
CA
VT
IN OH
MO
OK
PA WV VA
KY
SC GA
NM
AR TX
LA
MS AL
FL
PADD I: East Coast
PADD III: Gulf Coast
11
Heavy Light Sweet*
NH MA RI CT NJ DE MD
NC
TN
AZ
HI
NY
WI
NE
UT
307
ME
MN
Canadian Association of Petroleum Producers
thousand barrels per day
7 Domestic Crude
803
PADD II: Midwest
SD
ID
Total refining capacity = 1,796
* Includes small volumes of Medium Sweet Source: EIA
Light/ Medium Sour
304
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3.2.2 PADD II (Midwest)
Northern PADD II
PADD II is located in the U.S. Midwest and has historically been the largest market for western Canadian crude oil with a refining capacity of 3.7 million b/d. In 2008, PADD II refineries received over 1.5 million b/d of foreign sourced crude oil and over half these volumes were heavy crude oil (Figure 3.6). Crude oil from western Canada totaled over 1.1 million b/d, making Canada by far the largest supplier.
Northern PADD II consists of North Dakota, South Dakota, Minnesota and Wisconsin. There is one refinery in both North Dakota and Wisconsin and two refineries in Minnesota. These four refineries have a total refining capacity of 489,000 b/d. In 2008, imports into northern PADD II were 287,000 b/d and western Canadian crude oil accounted for almost all of it. Imports of western Canadian crude oil are expected to grow to 370,000 b/d by 2011 and remain flat afterwards (Figure 3.7).
Figure 3.6 2008 PADD II: Foreign Sourced Supply by Type and Domestic Crude Oil Total refining capacity = 3,726
thousand barrels per day
318 342
Light Sweet*
Light/ Medium Sour Heavy
Domestic Crude
1,718
In 2007, Flint Hills Resources completed a project to increase the capacity of its refinery in Minnesota by 50,000 b/d. This increased capacity can be more fully utilized with the completion of the pipeline expansion in the third quarter of 2008 (see the MinnCan Project in the Pipeline section of this report). Murphy Oil had previously discussed plans to expand its 35,000 b/d refinery to 235,000 b/d. This expansion would essentially be a tear-down and rebuild of the facility. However, it has been announced that these plans will not proceed until a financial partner is found.
Figure 3.7 PADD II (North): Forecast Western Canadian Crude Oil Receipts
844
* Includes small volumes of Medium Sweet Source: EIA
In recent years, however, growth in heavy oil production in western Canada has saturated this traditional market. As a result, producers are looking for refiners in traditional markets to increase their capacity for refining heavy crude, as well as increased access to new markets such as the U.S. Gulf Coast.
500 450 400 350 300 250 200 150 100 50 0
2008
The U.S. Energy Information Administration further divides PADD II into three refining districts, which is used in the following discussion.
thousand barrels per day
Total refining capacity = 489
2009
2010
2011
2012
2013
2014
2015
Light Synthetic Conventional Light Sweet Conventional Medium Sour Heavy
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Eastern PADD II Eastern PADD II consists of Michigan, Illinois, Indiana, Kentucky, Tennessee and Ohio and has 14 refineries with a total refining capacity of 2.4 million b/d. In 2008, western Canadian crude oil accounted for 802,800 b/d
or 74 percent of the total foreign imports into the region. Proposed expansions and conversions could result in higher runs of western Canadian heavy crude oil in the next several years (Figure 3.8). Table 3.1 summarizes announced projects designed to process additional volumes of Canadian crude oil.
Table 3.1 Summary of Announced Refinery Upgrades in Eastern PADD II Operator
Location
Current Capacity (thousand b/d)
Scheduled In-Service
Description
ExxonMobil
Joliet, IL
239
TBD
Increased ability to process heavy crude oil
WRB Refining
Roxana, IL
306
2011 (originally end 2009)
Add a 65,000 b/d coker; increase total crude oil refining capacity by 50,000 b/d; double heavy oil refining capacity to 240,000 b/d
BP
Whiting, IN
160
2012 (originally 2011)
Construction of new coker and a new crude distillation unit
Marathon
Detroit, MI
100
Mid 2012 (originally Q4 2010)
Increase heavy oil processing capacity by 80,000 b/d and increase total crude oil refining capacity to 115,000 b/d
BP
Toledo, OH
155 (60 heavy)
Dependant on market conditions (originally 2015)
Reconfigured to process 120,000 b/d of bitumen (180,000 b/d total capacity)
Husky
Lima, OH
165
TBD
Conversion to process 105,000 of heavy crude oil (170,000 b/d total)
Valero
Memphis, TN
195
2012 (originally 2009)
Cat-cracking unit upgrade
Figure 3.8 PADD II (East): Forecast Western Canadian Crude Oil Receipts 2000 1800 1600 1400 1200 1000 800 600 400 200 0
Total refining capacity = 2,414
2008
2009
2010
2011
thousand barrels per day
2012
2013
2014
2015
Light Synthetic Conventional Light Sweet Conventional Medium Sour Heavy
13
Canadian Association of Petroleum Producers
Southern PADD II Southern PADD II has eight refineries located in Kansas and Oklahoma with a total refining capacity of 823,500 b/d. With the reversal of the Enbridge Spearhead pipeline in March 2006, western Canadian producers were able to deliver up to 125,000 b/d of crude oil into Cushing, Oklahoma. In April 2009, Enbridge completed the expansion of this pipeline to 190,000 b/d. Access to the Cushing market offers western Canadian crude oil producers some opportunities to penetrate other markets (e.g. PADD III) through existing pipelines. Based on the survey responses, this market is not expected to be a large growth area for western Canadian crude oil. In 2008, refineries in this market received about 64,900 b/d of western Canadian crude oil, and this is projected to rise to 96,600 b/d in 2015 (Figure 3.9).
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Figure 3.9 PADD II (South): Forecast Western Canadian Crude Oil Receipts 200 180 160 140 120 100 80 60 40 20 0
Total refining capacity = 824
Figure 3.10 2008 PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil
thousand barrels per day
Total refining capacity = 8,378
thousand barrels per day
1,623
Domestic Crude
2008
2009
2010
2011
2012
2013
2014
3.2.3 PADD III (Gulf Coast) PADD III is comprised of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas. There are 51 refineries in this market with a total refining capacity of over 8.4 million b/d, of which a significant portion has heavy crude oil processing capabilities. It is the largest and most complex refining district in the United States and is considered to be potentially well suited and capable of processing Canadian heavy crude oil. In 2008, PADD III imported 5.3 million b/d of crude oil from foreign sources, of which 2.2 million b/d was heavy crude oil (Figure 3.10). These imports came from 43 different countries with the top suppliers being Mexico (22 percent), Saudi Arabia (17 percent), Venezuela (17 percent) and Nigeria (11 percent). Deliveries of western Canadian heavy crude oil to this market totaled about 88,800 b/d. The only pipeline access for delivery of western Canadian crude oil to the Gulf Coast is through the ExxonMobil Pegasus pipeline. This pipeline originates at Patoka, Illinois and ends at Corsicana, Texas and has a capacity of 66,000 b/d. This pipeline is currently being expanded by 30,000 b/d, and is expected to be in-service in June 2009. In 2008, approximately 22,800 b/d that were shipped off the Westridge dock in Burnaby, British Columbia arrived via tanker. In addition, about 11,700 b/d of light sweet crude was also imported from Atlantic Canada by tanker.
Heavy
Light Sweet*
2015
Light Synthetic Conventional Light Sweet Conventional Medium Sour Heavy
2,237
1,204
Light/Medium Sour 1,834
* Includes small volumes of Medium Sweet Source: EIA
The steep decline in production from Mexico’s Cantarell field could make securing supply from Canada more attractive in the future. In addition, Canada’s other major competitor, Venezuela, has recently signed agreements to ship oil to other markets such as China. In recent years, PADD III refineries have added several new cokers which will enable them to run heavier and more sour grades of crude oil, which are becoming increasingly predominant in the world’s oil production slate. Table 3.2 summarizes the major refinery upgrades announced for the region. Although these upgrades may not all be specifically designed to process Canadian crude oil, many of these companies have confirmed that their refineries are planning to take more Canadian crude. Thus the main constraint to the growth of supply of western Canadian heavy crude used in this region is not available refining capacity but is in fact the availability of pipeline capacity to the region. There are a number of pipeline proposals to increase pipeline capacity to the U.S. Gulf Coast scheduled for as early as 2012 or 2013. CAPP has estimated that this market could receive at least 380,000 b/d of western Canadian crude oil by 2013 based on announced contractual commitments.
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Table 3.2 Summary of Major Announced Refinery Upgrades in PADD III Scheduled In-Service
Description
256
4Q 2009
Increase capacity to 425,000 b/d
St. Charles, LA
250
2012 (originally 2011)
New 50,000 b/d hydrocracker and 10,000 b/d expansions to the crude and coker units
Holly
Artesia, NM
85
2009
Additional 25,000 b/d capacity and capability to run up to 40,000 b/d of heavy crude oil
Motiva Enterprises
Port Arthur, TX
285
2012 (originally late 2010)
Increase capacity to over 600,000 b/d
Valero
Port Arthur, TX
310
2011 (originally 2010)
New 50,000 b/d hydrocracker. Plans for previously announced 45,000 b/d coker addition is on hold
WRB Refining
Borger, TX
146
2009+
Debottleneck to add 20,000 b/d bitumen capacity
Operator
Location
Marathon Oil
Garyville, LA
Valero
Current Capacity (thousand b/d)
3.2.4 PADD IV (Rockies) PADD IV includes the states of Colorado, Montana, Utah, Wyoming and Idaho. It has 14 refineries located in four of the five states (there are no refineries in Idaho), and has a total refining capacity of 611,500 b/d. Although PADD IV is smaller than the other core markets, it has been a stable market for western Canadian crude oil supply. In 2008, PADD IV processed 255,000 b/d of Canadian crude oil or about 48 percent of its feedstock requirements. Canada is the only source of foreign crude oil to this market. Throughout the forecast period, western Canadian crude oil receipts are forecasted to remain relatively flat (Figure 3.11). Some refiners have indicated, however, that once crude oil production from certain areas of PADD IV declines, there could be opportunities for Canadian crude oil to replace these supplies. In addition, a few refiners have either recently invested in upgrading projects that could enable their refinery to process oil from the oil sands or have plans to do so in the future. As a result, the feedstock slate for this market could become slightly heavier.
15
Canadian Association of Petroleum Producers
Figure 3.11 PADD IV: Forecast Western Canadian Crude Oil Receipts 600
thousand barrels per day
Total refining capacity = 612
500 400 300 200 100 0 2008
2009
2010
Light Sweet* Light/Medium Sour Heavy
2011
2012
2013
2014
2015
*Includes small volumes of Medium Sweet
3.2.5 PADD V (West Coast) PADD V includes the states of Alaska, Washington, Oregon, California, Nevada, Arizona and Hawaii. The majority of PADD V is geographically divided from the rest of the United States by the Rocky Mountains, and has very good access to tankers, and is located in close proximity to production from Alaska and California. Nonetheless, this market still depends on foreign imports for almost half of its requirements (Figure 3.12).
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Figure 3.12 2008 PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil thousand barrels per day
Total refining capacity = 3,238
Domestic Alaska
Other Domestic 698
Total refining capacity = 629
thousand barrels per day
600 416
678
Figure 3.13 Washington: Forecast Western Canadian Crude Oil Receipts
500 400
Heavy
300
Light/ Medium Sour
200 590
100 0
Light Sweet* 187
2008
2009
2010
Light Sweet* Light/Medium Sour Heavy
2011
2012
2013
2014
2015
*Includes small volumes of Medium Sweet
California * Includes small volumes of Medium Sweet Source: EIA
For the purposes of the remainder of this report, the PADD V market region will focus only on Washington and California as these states represent both the current demand and future prospects for western Canadian crude oil.
Washington There are five refineries in Washington that have a combined capacity of 629,000 b/d. Alaska is still the primary source of feedstock for these refineries, however; Alaskan production continues to decline. As a result, these refiners are becoming increasingly dependent on imports from Canada and other countries. In 2008, these refineries received 221,000 b/d of foreign crude oil, sourced primarily from Canada (56 percent), Angola (18 percent) and Saudi Arabia (15 percent). In 2008, receipts of western Canadian crude were 123,000 b/d. These receipts are expected to remain flat throughout the forecast period (Figure 3.13). ConocoPhillips has delayed its proposed addition of a 25,000 b/d coker unit at its refinery located at Ferndale. Construction is now scheduled to start in 2012. The Washington market has the potential to process additional volumes of western Canadian crude oil but given the latest supply forecast and the small size of this niche market, development of this market may be limited.
California has 19 refineries with a total refining capacity of over 2 million b/d. Most of the refineries are located near the coast in the Los Angeles area and in the San Francisco Bay area. These refineries account for almost 95 percent of the refining capacity in the state. These refineries are among the most sophisticated in the world, partly due to California having the strictest environmental requirements in the United States for refined petroleum products. They have the capability to process a wide variety of crude oil types and are designed to yield a higher proportion of light products, such as gasoline. The three refineries in Bakersfield are smaller and process local California crude oil; they would not be expected to receive Canadian crude. In 2008, California refineries received about 38 percent of their supply from California; 13 percent were domestic imports sourced from Alaska with the rest of their supply from foreign sources, delivered by tanker through marine terminals. The top three sources of the 853,000 b/d in foreign crude were Saudi Arabia (27 percent); Iraq (24 percent); and Ecuador (20 percent). Canada only accounted for about 3 percent of foreign imports (Figure 3.14).
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Figure 3.14 2008 PADD V (California): Foreign Sourced Supply by Type and Domestic Crude Oil Total refining capacity = 2,080
thousand barrels per day
240 351
Domestic Alaska
Heavy
Other Domestic
Light/ Medium Sour
468
683
34
Light Sweet*
* Includes small volumes of Medium Sweet Source: EIA
The rate of decline of California production has eased over recent years compared to historical trends but the California Energy Commission still expects production to fall by 2 to 3 percent per year in the future. Alaskan crude production is supplied primarily to Alaska and Washington, with the balance going to California. As production in Alaska continues to decline, the California refineries will need to replace their domestic crude oil sources with increased imports. Given Canada’s proximity to California, this would appear to be a potential market opportunity for western crude oil. The California Air Resources Board has recently introduced a new low-carbon fuel standard to be implemented by 2012. However, greenhouse gas (GHG) reductions in the oil sands along with Canadian GHG policies may qualify oil sands to continue to supply this market. With less optimistic views currently with respect to oil supply growth, pipeline proposals to serve this market have been deferred and are being re-evaluated.
3.3 Asia The Asian market has attracted significant interest over the last few years because of its rising demand for energy. Undoubtedly, Asia has also been affected by the global economic downturn, but this market, particularly China and India, remains a prospect in the longer term. China is the largest consumer of oil after the United States and economic growth rates are expected to be relatively strong compared to other countries. Table 3.3 shows oil demand from 2006 to 2009 in the major Asian countries. The International Energy Agency (IEA) forecasts that oil demand from China will decline slightly in 2009 but growth in the longer term is anticipated. There are a number of pipeline project proposals that could take western Canadian crude oil to these markets.
Table 3.3 Total Oil Product Demand in Major Asian Countries million b/d
2006
2007
2008
2009
China
7.21
7.54
7.86
7.80
India
2.80
2.95
3.08
3.13
Japan
5.20
5.01
4.74
4.05
Korea
2.18
2.21
2.15
2.13
Source: International Energy Agency (IEA), April 2009
3.4 Methodology CAPP did not put any constraints on the data submitted by refiners nor were any alternate cases prepared. Some assumptions were made based on discussions with refiners and publicly available information. The CAPP survey categorizes western Canadian crude oil into four main types as follows: 1. Conventional Light Sweet (greater than 27° API and less than or equal to 0.5% sulphur) including condensates and pentanes plus; 2. Heavy (equal to or less than 27° API) including conventional heavy, synthetic sour and crude oil blends such as DilBit, SynBit and DilSynBit; 3. Conventional Medium Sour (greater than 27° API and greater than 0.5% sulphur); and 4. Light Sweet Synthetic
17
Canadian Association of Petroleum Producers
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For the purposes of the historical data in this section of the report, the following crude types and definitions apply: • Sweet: crude oil with a sulphur content of less than or equal to 0.5% • Sour: crude oil with a sulphur content of greater than 0.5% • Light: crude oil with an API of at least 30° • Medium: crude oil with an API greater than 27° but less than 30° • Heavy: crude oil with an API of 27° API or less No differentiation is made between sweet and sour crude oil that falls in the heavy category because heavy crude oil is generally sour.
3.5 Markets Summary Based on the survey results, the forecasted potential demand for Canadian crude oil in all markets is lower than in the last report. However, in 2015, PADD II is expected to be able to take more western Canadian crude oil due to the planned refinery conversions in the area. PADD III is considered a market with significant potential given its large refining capacity and the ability of many of these refiners to process heavy crude. Also, the steep decline in Mexico’s production and Venezuela’s recent shift towards exporting oil to non-U.S. markets such as China, are factors that could make securing supply from Canada more attractive in the future. The full potential of this market remains uncertain at this stage, however, given limited pipeline access to this region from western Canada.
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4
Crude Oil Pipelines
Pipelines are the main connection between the crude oil supply areas to the end markets since they are generally the most efficient and reliable mode of transporting crude oil. As such, pipeline developments determine the destination of Canadian crude oil. The additional capacity from all currently active (i.e. in construction or in the regulatory process) pipeline projects would result in total available pipeline capacity in excess of forecast supply through to the end of the forecast period. In addition, there remain a number of proposals that have been grouped into three main areas: U.S. Midwest, Ontario, Québec, U.S. East Coast; the U.S. Gulf Coast; and the West Coast. However, the proposed timing for many of these proposals is uncertain.
4.1 Major Crude Oil Pipelines Historically, major Canadian crude oil pipelines such as the Enbridge Pipeline and the Kinder Morgan Trans Mountain pipeline operated as common carriers. The exceptions are the Kinder Morgan Express pipeline and the Enbridge Line 9 (Montreal, Québec to Sarnia, Ontario) that operate as contract carriers (i.e. require long-term take-or-pay commitments). On common carrier pipelines, shippers nominate monthly for space on the pipeline without a contract. The TransCanada Keystone pipeline, which is scheduled to be in-service by the end of 2009, will operate as a contract carrier while the Enbridge Alberta Clipper pipeline will be a common carrier.
4.1.1 Existing Major Crude Oil Pipelines Western Canadian crude oil is delivered to markets or other pipelines by three major Canadian trunklines – Enbridge, Trans Mountain and Express pipelines.
19
Canadian Association of Petroleum Producers
The following table provides the estimated current crude oil capacity on these trunklines.
Pipeline
Enbridge
Crude Type
Estimated Annual Capacity (thousand b/d)
Light
692
Heavy
1,186
Express
Light/heavy (35/65)
280
Trans Mountain
Light/heavy (80/20)
300
TOTAL
2,458
Enbridge Pipelines The Enbridge system which operates in Canada and the U.S. is the world's longest crude oil pipeline. It can deliver more than 2 million b/d of crude oil and other commodities from primarily western Canada to other markets in western Canada, the U.S. upper Midwest and Ontario. In addition, it connects to various pipelines in the U.S. such as Spearhead and Mustang. It also receives crude oil from U.S. pipelines for deliveries to markets in the U.S. Midwest and Ontario.
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In 2007, Enbridge added about 45,000 b/d of capacity downstream of Superior, Wisconsin while no additional capacity was added upstream of Superior. In April 2008, Enbridge completed Stage 1 of the Southern Access program (Line 61) from Superior to Delavan adding about 46,000 b/d of capacity, while the remainder of Line 61 from Delevan to Flanagan began operating in May 2009.
Kinder Morgan Trans Mountain Pipeline The Trans Mountain system originates in Edmonton, Alberta and transports crude oil to the Vancouver area, including its Westridge dock for vessel or barge loadings, and by pipeline to refineries in Washington State. The system also ships refined petroleum products from the Edmonton refineries to Kamloops, British Columbia and Vancouver. It can currently transport about 300,000 b/d assuming 20 percent of the volumes are heavy crude oil. Note that the actual available capacity varies depending on the amount of heavy crude oil transported. Currently, about 25 percent of the volumes shipped are heavy crude oil. In 2008, Trans Mountain completed TMX1, which consisted of a Pump Station Expansion (PSE) and the Anchor Loop Expansion (ALE) project.
Kinder Morgan Express-Platte Pipelines The Express pipeline ships crude oil from Hardisty, Alberta to PADD IV and has a capacity of 280,000 b/d. The pipeline is underpinned by contracts, many of which expire in 2012, totaling 231,000 b/d with the remaining space being available for spot shippers.
Committed shippers have been allocated 30,000 b/d out of this expanded capacity. This portion of the pipeline will continue to operate in southbound service and is referred to as Spearhead South. There are plans to reverse the remaining portion of the pipeline that runs from Flanagan to Hartsdale, Illinois to operate in northbound service. The pipeline originally operated in northbound service but was reversed in March 2006.
Enbridge Light Sour Line As part of its Southern Lights diluent project, Enbridge constructed a 20-inch diameter light sour crude oil line from Cromer, Manitoba to Clearbrook, Minnesota. This line came into service in February 2009 and has a capacity of 185,000 b/d. This expansion was built to provide access to growing crude oil deliveries into the Enbridge Cromer terminal from southeast Saskatchewan.
ExxonMobil Mustang Pipeline The Mustang pipeline is jointly owned by Enbridge Pipelines and ExxonMobil and is connected to the Enbridge Lakehead system at Lockport, Illinois and extends to the Patoka, Illinois terminal. It has a heavy crude oil capacity of about 91,000 b/d of which 88,000 b/d is committed capacity. Nominations on the pipeline have exceeded capacity since December 2005 and this trend is expected to continue until there is new pipeline capacity into the region.
ExxonMobil Pegasus Pipeline
The Platte system connects to Express at Casper, Wyoming and extends to Guernsey, Wyoming then to Wood River, Illinois. Capacity from Guernsey to Wood River is about 145,000 b/d and because of strong demand, pipeline capacity has been constrained since January 2007. Therefore, Express is not operating at capacity due to insufficient capacity on the Platte system.
The Pegasus pipeline was reversed in March 2006 and runs from Patoka, Illinois to Nederland, Texas. It currently provides western Canadian crude oil producers with the only pipeline access to the U.S. Gulf Coast. It has a heavy crude oil capacity of 66,000 b/d, of which 50,000 b/d is committed capacity. Pegasus is scheduled to be expanded to 96,000 b/d by the end of June 2009. Nominations have exceeded capacity since it was reversed.
Enbridge Spearhead (South) Pipeline
MinnCan Project
The Spearhead pipeline is connected to the Enbridge Lakehead system at the Enbridge terminal near Chicago and delivers light and heavy crude oil to Cushing, Oklahoma. As of May 2009, the initiation point has been changed to Flanagan, Illinois and the pipeline capacity was increased by 65,000 b/d to 190,000 b/d.
The Minnesota Pipeline is connected to the Enbridge system at Clearbrook, Minnesota and transports crude oil from Canada to Minnesota refineries owned by Flint Hills in Rosemount and Marathon Oil in St. Paul.
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In 2008, the three major trunklines from western Canada transported over 1.8 million b/d of crude oil. These pipelines operated close to full available capacity for most of the year. The pipeline expansion projects that have already been approved and are in construction will add over one million b/d in pipeline capacity by the end of 2010 (Table 4.1). This capacity will meet and exceed the forecast supply through to 2019 (Figure 4.1).
This line was operating at its capacity of 300,000 b/d. The MinnCan project was designed to bring additional crude oil supply from Canada to these refineries. It is a new 24-inch diameter pipeline that follows most of the original system’s route but ends at the Flint Hills refinery. This endpoint provides a direct interconnection with that facility and a direct interconnection, through existing pipeline facilities, with Marathon’s refinery. The MinnCan project was completed in the third quarter of 2008, providing up to 165,000 b/d additional crude to these refineries. This new pipeline can also be expanded up to 350,000 b/d.
Table 4.1Approved Oil Pipeline Expansions from Western Canada
4.2 Crude Oil Transportation Requirements Given that the growth in western Canadian crude oil supply is expected to be lower than in recent forecasts, the main driver behind the proposals for new pipeline projects has diminished substantially.
Pipeline
Proposed in Service Date
TransCanada Keystone
Dec 2009
435
Enbridge Alberta Clipper
Jul 2010
450
TransCanada Keystone Extension
4Q 2010
155
TOTAL Capacity
1,040
Current Oil Pipeline Expansions from Western Canada Figure 4.1 Current Crude Oil Expansions from Western Canada
Trans Mountain
Edmonton Hardisty
Burnaby Anacortes
Express 6
Enbridge Alberta Clipper Montreal
Salt Lake City
Enbridge
St. Paul
Guernsey
Platte
4 Flanagan
TransCanada Keystone
Chicago
Sarnia
BP Cushing
Wood River
Patoka
Mid Valley
Capline
Houston
21
Canadian Association of Petroleum Producers
St. James
Portland Buffalo
Toledo Lima
Capacity (thousand b/d)
Philadelphia
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4.3 Crude Oil Pipeline Expansions/Proposals The remainder of this section focuses on pipeline expansions and proposals to ship western Canadian crude oil to the various markets and is divided into three areas: U.S. Midwest, Ontario, Québec, East Coast; the U.S. Gulf Coast; and the West Coast. There are currently two major crude oil pipeline expansions in construction from western Canada to the U.S. Midwest: the Enbridge Alberta Clipper and the TransCanada Keystone. In addition, there are many other expansions or proposals that will connect to these two pipelines to deliver western Canadian crude oil to markets outside the U.S. Midwest such as, Ontario, Québec, PADD I and the U.S. Gulf Coast (Figure 4.2). These projects are summarized in Appendix C.1.
4.3.1 Crude Oil Pipeline Expansions/Proposals to the U.S. Midwest, Ontario, Québec and the East Coast TransCanada Keystone and Extension
4
The Keystone pipeline will run from Hardisty, Alberta to terminals in Wood River and Patoka, and is scheduled to be in-service in December 2009 with an initial capacity of 435,000 b/d. The pipeline will include both new construction and the conversion of existing pipe that is currently in natural gas service. All key Canadian and U.S. regulatory approvals are in place and construction commenced in the second quarter of 2008.
Current Oil Pipeline Expansions/Proposals to the U.S. Midwest, Ontario, Québec and U.S. East Coast Figure 4.2 Pipeline Proposals to the U.S. Midwest, Ontario, Québec and U.S. East Coast
Trans Mountain
Edmonton Hardisty
Burnaby Anacortes
Enbridge (North Dakota) Expansion
Express
Enbridge Alberta Clipper 6
9
Enbridge Southern Access Expansion 10
St. Paul Salt Lake City
Guernsey 4 TransCanada Keystone
Platte
BP
Enbridge Ohio Access Sarnia
Enbridge
Montreal 17 Buffalo
17
Enbridge Trailbreaker Portland Pipeline Reversal
Portland Sunoco Buffalo to Philadelphia
16 Sunoco to Toledo 19 20 Chicago Enbridge Spearhead Flanagan 15 Toledo Expansion (North) 18 Lima Philadelphia 10 Mustang Expansion Wood Patoka Enbridge Southern Access Extension River
Cushing
Mid Valley
Capline
Houston
St. James
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TransCanada is also proposing two extensions to the Keystone pipeline. The first one is an extension to Cushing, Oklahoma, which would connect at the Nebraska/ Kansas border. The extension would increase capacity by 155,000 b/d to an ultimate capacity of 590,000 b/d, and is scheduled to be in-service in the fourth quarter 2010. The second one is a Heartland Extension, which is a 600,000 b/d oil pipeline from Fort Saskatchewan to the Keystone connection at Hardisty. It is scheduled to be in service in the 2012 or 2013 timeframe.
Enbridge is also proposing to extend the Southern Access pipeline to the Patoka, Illinois hub from Flanagan with a 36-inch diameter line that would have an initial capacity of 400,000 b/d. The pipeline could be in-service as early as 2012 but the actual timing will depend on the market and regulatory approvals.
Enbridge Spearhead North
15
TransCanada is proposing a 400,000 b/d DilBit line from the oil sands area of Fort McMurray to Hardisty, Alberta with multiple receipt points. Potential timing for this project is sometime between 2012 and 2014.
Since May 2009, the Southern Access pipeline has connected with Spearhead at Flanagan. Currently, Spearhead flows southbound but Enbridge intends to reverse the segment of the pipeline between Flanagan, Illinois to Hartsdale, Indiana (near Chicago) as part of the Southern Access project. This segment, referred to as Spearhead North, has a capacity of 130,000 b/d and is scheduled to be in-service by Q3 2009.
Enbridge Alberta Clipper
Bow River Pipeline
TransCanada DilBit Pipeline
6
The 36-inch diameter Clipper pipeline is an expansion of the Enbridge existing mainline system and will extend from Hardisty, Alberta to Superior, Wisconsin with a connection to the Minnesota pipeline at Clearbrook. The initial capacity is 450,000 b/d of heavy crude oil and could be further expanded to 800,000 b/d. It is scheduled to be in-service in July 2010. In May 2009, Enbridge extended Line 4 from Hardisty to Edmonton by connecting currently deactivated 48-inch diameter segments with a new 36-inch diameter pipeline. This extension was built to ensure sufficient heavy crude oil capacity for Enbridge Alberta Clipper and has a capacity of 450,000 b/d. It can be expanded to an ultimate capacity of 800,000 b/d.
Enbridge Southern Access Expansion/ Extension 10 Enbridge completed construction of its Southern Access expansion program. The first phase, completed in April 2008, was a new 42-inch diameter pipeline from Superior to Delavan, Wisconsin. The second phase build out to Flanagan, Illinois was subsequently completed in May 2009 adding about 400,000 b/d of capacity. Further expansions to 600,000 b/d and 800,000 b/d can be achieved by adding pump stations. The Southern Access pipeline will connect to the Enbridge Spearhead pipeline at Flanagan. See sections on Enbridge Spearhead South and Enbridge Spearhead North. 23
Canadian Association of Petroleum Producers
The Bow River Pipeline system gathers oil production in southern Alberta for delivery north to Hardisty, Alberta and south to interconnecting export pipelines near the Montana border. Inter Pipeline Fund (Inter Pipeline) plans to expand oil delivery capabilities on the Bow River Pipeline system and has received support in terms of 7-year contractual commitments to transport 30,000 b/d. The project includes the construction of 135 kilometres of new pipeline and will enable the shipment of segregated crude oil streams from Hardisty, Alberta to refining markets in Montana. The intent of this project is to allow crude oil types sourced at Hardisty to be shipped south as a distinct, segregated stream and give Montana refineries access to multiple grades of oil available at Hardisty without commingling with the locally gathered Bow River oil stream. The project is scheduled for completion in the first quarter of 2010.
Enbridge Line 5 Expansion Line 5 extends from Superior, Wisconsin to Sarnia, Ontario. The expansion consists of adding Drag Reducing Agent (DRA), and is expected to add 50,000 b/d of new light crude oil capacity. Total capacity will then approximate 540,000 b/d. The timing for this project is undetermined.
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Enbridge Line 6B Debottleneck and Expansion Enbridge is exploring various options to expand Line 6B which extends from Chicago, Illinois to Sarnia. Tank constraints are currently limiting usable capacity from 290,000 b/d to 190,000 b/d. The project scope includes two new tanks and pump stations which could add between 65,000 and 135,000 b/d of capacity. Total new capacity would approximate up to 425,000 b/d and the projected in-service date is in the first quarter of 2010. This new capacity would be required should Enbridge’s Line 9 be reversed.
Enbridge Trailbreaker
17
Enbridge had been in discussions with industry to reverse Line 9 from Sarnia to Montreal in order to access markets in Ontario, Quebéc, the Maritimes and U.S. markets. If reversed, Line 9 could ship up to 215,000 b/d of crude. The project proposal included the reversal of one line on the Portland Pipeline system to ship 200,000 b/d that would be loaded on tankers. Portland Pipeline conducted an open season for the reversal but did not receive the level of firm volume commitments required to proceed. At this time Enbridge is continuing its discussions with industry with respect to appropriate timing and market conditions needed to reconsider this proposal.
Enbridge North Dakota
9
The North Dakota pipeline connects to the Enbridge Lakehead pipeline at Clearbrook, Minnesota and provides producers in Montana and North Dakota with access to markets in PADD II and Ontario. Increased production in these areas has resulted in a need for additional pipeline capacity. Enbridge added 30,000 b/d of capacity to the North Dakota system in January 2007 and is planning another expansion of 52,000 b/d by January 2010, which would increase total system capacity to 162,000 b/d.
ExxonMobil Mustang Expansion
Enbridge Line 6C Enbridge is considering a new 36-inch diameter line from its Griffith/Hartsdale terminal to Stockbridge, Michigan that would parallel Line 6B. The intent is to deliver additional supply to refineries in Michigan and Ohio. The estimated capacity would be 400,000 b/d with an in-service date of 2012. If needed, the line could be extended to Sarnia, Ontario.
Sunoco Pipeline
19 20
Sunoco is proposing a crude oil pipeline to refineries in the Philadelphia area. The market in this area includes Sunoco’s two refineries in Pennsylvania and its New Jersey refinery as well as the ConocoPhillips and Valero refineries in Pennsylvania, New Jersey and Delaware. The project includes an expansion on the Enbridge system to Buffalo and the use of the existing Sunoco right-of-way to build a new 24-inch diameter pipeline from Buffalo to Philadelphia. The capacity of the pipeline would be about 400,000 b/d. Sunoco is also considering expanding its Marysville to Toledo pipeline from 190,000 b/d to 288,000 b/d.
Enbridge Ohio Access
16
Enbridge is proposing a phased approach to increase the ability to transport additional deliveries of western Canadian crude oil. The timing is scheduled to coincide with the timing of expansions and conversions to process more heavy crude oil at refineries in Detroit and Ohio. The first phase would entail a debottlenecking of Line 17 and a new pipeline ex-Griffith which would increase capacity by 20,000 b/d to 120,000 b/d to serve increased demand by Marathon’s Detroit refinery. Phase 2 would increase pipeline capacity from 120,000 b/d to 400,000 b/d to serve the refineries in Toledo and Lima, Ohio. Phase 2 includes a new 36-inch diameter line from Stockbridge to Samaria and then 20-inch diameter laterals to Toledo and Lima.
18
The Mustang expansion proposal would increase throughput by adding new and modifying existing pump stations. The pipeline can transport both light and heavy crude. With the proposed expansion, the capacity could increase by 38,000 b/d to 131,000 b/d.
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Current Oil Pipeline Expansions/Proposals to the U.S. Gulf Coast Figure 4.3 Pipeline Proposals to the U.S. Gulf Coast
Trans Mountain
Edmonton Hardisty
Burnaby Anacortes 5
Express
Enbridge Alberta Clipper
Altex TransCanada Keystone XL
Guernsey Salt Lake City
6
8
Platte
Enbridge Southern Access Expansion Enbridge Southern Access Extension
10
St. Paul
4
BP/Enbridge GAP Phase 2 11
Canadian Association of Petroleum Producers
Toledo
13
Mid Valley
22
14
23
TransCanada Louisiana Access
Capline 21
25
Buffalo
Patoka
Cushing
BP/Enbridge GAP Phase 3 Houston
There are two proposals for bullet lines from Alberta to the U.S. Gulf Coast: the TransCanada Keystone XL and Altex Energy - with total capacity of about 1,565,000 b/d. Four pipeline companies (ExxonMobil/Enbridge, Sunoco,
Portland
Philadelphia
Wood River
ExxonMobil/Enbridge Pegasus Expansion
The U.S. Gulf Coast began receiving western Canadian crude oil by pipeline in April 2006 through the reversed ExxonMobil Pegasus pipeline, which is scheduled to be expanded in June 2009. Prior to this, there were and continue to be spot vessel movements of western Canadian crude oil from the Trans Mountain Westridge dock. Due to the large refining capacity of the PADD III market, Canadian producers have been assessing various pipeline proposals to the Gulf Coast (Figure 4.3).
Sarnia
Lima
12
BP
Centurion Pipeline
4.3.2 Crude Oil Pipeline Expansions/Proposals to the U.S. Gulf Coast
Chicago
Flanagan
TransCanada Keystone BP/Enbridge GAP Phase 1
Enbridge
Montreal
Sunoco to USGC St. James
ExxonMobil and Centurion) are proposing new pipelines, expansions or reversal of existing lines to transport western Canadian crude oil from the U.S. Midwest to the Gulf Coast. The in-service dates for these proposals will depend on market conditions. Proposals for projects targeting the U.S. Gulf Coast are summarized in Appendix C.2.
BP/Enbridge Gulf Access Pipeline
12 13 14
BP and Enbridge are proposing the Gulf Access Pipeline which, in Phase 1, consists of the reversal and expansion of BP #1 pipeline which will interconnect with Southern Access at Flanagan, Indiana to move between 150,000 b/d and 200,000 b/d of crude oil to Cushing, Oklahoma. From Cushing, a new 250,000 b/d crude oil pipeline would be built to the U.S. Gulf Coast with interconnections to the Houston, Texas area refineries. Extensions could also be built to reach either Port Arthur, Texas or Nederland, Texas.
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Phase 2 of this project requires the building of the Enbridge Southern Access Extension and the reversal of the Enbridge Ozark pipeline. The Southern Access extension pipeline would extend from Flanagan to Patoka, Illinois. From Patoka, the crude oil could be transported to Wood River, Illinois then flow on the reversed Ozark pipeline, which has a capacity of about 200,000 b/d, to Cushing. The system capacity to the U.S. Gulf Coast would be approximately 400,000 b/d with an in-service date as early as 2012. With market support, Phase 3 of this project would include another new pipeline that will extend from Patoka to either Port Arthur or Nederland.
Sunoco Pipeline – to U.S. Gulf Coast 21 Sunoco has a proposal to construct a new pipeline line from Cushing, Oklahoma to its Wortham, Texas terminal and then reverse a 26-inch diameter pipeline to Nederland, Texas. The Cushing portion would have an initial capacity of 300,000 b/d.
ExxonMobil Pipeline – Enbridge Pipelines Joint Initiative ExxonMobil and Enbridge are proposing the Texas Access pipeline which consists of a new 30-inch diameter crude oil pipeline from Patoka to Beaumont, Texas with a capacity of 445,000 b/d, and a connecting lateral to Houston. With horsepower additions, the pipeline could expand to more than 550,000 b/d.
TransCanada Keystone XL and Louisiana Access options 8 23 The TransCanada Keystone XL project is a proposal for a 36-inch diameter pipeline from Hardisty, Alberta where it would connect with the proposed Cushing Extension at the Nebraska/Kansas border, and then to Port Arthur and Houston, Texas. The intent is to have a bullet pipeline from Hardisty to the U.S. Gulf Coast by the end of 2012. The initial pipeline capacity would be 700,000 b/d;
380,000 b/d of this capacity has been secured by contracts. The pipeline could be further expanded to 1.5 million b/d. Additional options being proposed include access to Louisiana by either building new or using existing facilities from Patoka to New Orleans or building a new line from Port Arthur, Texas to New Orleans. Proposed project timing is between 2014 and 2016.
Altex Energy
5
In light of the lower crude oil supply forecast, industry has been re-evaluating the timing and need for the Altex proposal. Altex is proposing a 36-inch diameter pipeline employing proprietary technologies that would use less diluent per barrel of bitumen than is required by other pipelines. The pipeline would transport heavy crude oil or bitumen from various locations in Alberta to the Port Arthur/Beaumont, Texas area. The initial capacity is estimated at 425,000 b/d and could expand to one million b/d with additional pumps.
ExxonMobil Pegasus Expansion
22
The Pegasus expansion would increase capacity by 30,000 b/d from Patoka, Illinois to Nederland, Texas with a start up date of June 2009.
Centurion Pipeline
11
Centurion Pipeline, owned by Occidental Petroleum, will reverse an existing 16-inch diameter common carrier pipeline to deliver western Canadian heavy crude oil from Cushing to Slaughter, Texas. In July 2008, Holly Corporation (Holly) agreed to build additional infrastructure from Slaughter to its Navajo refinery in New Mexico. These projects are expected to be complete and in service by the fourth quarter of 2009. Previously, Holly had entered into shipping commitments on both the Keystone and Spearhead pipelines for Canadian crude oil delivered to Cushing, Oklahoma.
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Crude Oil Pipeline Expansion/Proposals Figure 4.4 Pipeline Proposals to the U.S. West Coast
Kitimat
Enbridge Gateway
1 2
Edmonton
Trans Mountain
Burnaby
to the West Coast
3 Anacortes
Hardisty Kinder Morgan TMX2 Expansion TMX3 Expansion
Express 7
TransCanada AB-California
Montreal
Enbridge
St. Paul Guernsey
Portland Sarnia Buffalo
Salt Lake City
Chicago Toledo
Flanagan
Lima
Platte BP
Cushing
Wood River
Philadelphia
Patoka
Mid Valley
Capline
Houston
4.3.3 Crude Oil Pipeline Expansions/Proposals to the West Coast The map in Figure 4.4 illustrates crude oil pipeline expansions from western Canada to the West Coast. Appendix C.3 provides a summary of all proposals.
Kinder Morgan TMX2, TMX3 and Northern Leg Expansion 2 3 The TMX2 expansion could increase capacity by 80,000 b/d by 2012. The scope of TMX2 includes a new line from Edmonton, Alberta to Kamloops, British Columbia. TMX3 includes a new line to the Washington State refineries and a second berth at the Westridge dock. TMX3 could provide an additional 320,000 b/d of new 27
Canadian Association of Petroleum Producers
St. James
capacity by 2013. These expansions would provide additional access to Vancouver, Washington State and other markets served by oil tankers and barges which load at its Westridge dock. TMX Northern Leg is a pipeline with a capacity of 400,000 b/d, extending from its existing system near Rearguard, British Columbia to a deep water port facility at Kitimat, British Columbia that would accommodate Very Large Crude Carriers (VLCC) for delivery to PADD V or the Far East. Depending on industry support, the pipeline could be in service as early as 2014.
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Kinder Morgan Vancouver Port Development
TransCanada AB – California
Kinder Morgan is proposing further development at the Vancouver port area by building a pipeline from the Westridge Dock to the Vancouver Wharves and/or building a line to the Delta Port enabling access to larger tanks thereby increasing export capacity.
Enbridge Northern Gateway
1
The Northern Gateway project includes the construction of a new 36-inch diameter pipeline from Edmonton, Alberta to a deep water port at Kitimat, British Columbia and is being designed to provide 500,000 b/d of crude oil export capacity. Crude oil would be loaded on tankers for delivery to PADD V and the Far East. Enbridge is, depending on industry support, anticipating submitting an application to the National Energy Board in the second quarter of 2009.
7
TransCanada is in discussion with parties to transport 400,000 b/d of western Canadian crude oil by pipeline to California to access over 1.8 million b/d of refining capacity. The estimated in-service date is 2016.
4.3.4 Other Proposals Canadian National (CN) Railways and Altex are jointly explorting a “Pipeline on Rail” strategy. This proposal could transport as little as 10,000 to 20,000 b/d of undiluted or under-diluted bitumen in heated railcars. Through connections to other railroads, CN can access the majority of U.S. Gulf Coast refineries. This rail solution would also be suitable for condensate imports. CN has expressed that if there was interest, there would be no upper limit to the volumes that could be transported via rail.
Diluent Pipeline Proposals Figure 4.5 Diluent Pipeline Proposals
24
Enbridge Gateway Condensate Import
25
Trans Mountain
TransCanada
Edmonton Hardisty
Burnaby Anacortes 26
Express
Enbridge Southern Lights
Montreal
Enbridge
St. Paul
Guernsey
Portland Sarnia
Salt Lake City Toledo
Chicago
Platte
Lima
Philadelphia
Patoka
Wood River
Mid Valley
Cushing 27
Capline/Chicap
Capline Houston
St. James
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4.3.5 Diluent Pipeline Proposals
Enbridge Northern Gateway Diluent
Figure 4.5 shows the current diluent pipeline proposals.
As part of its Northern Gateway crude oil pipeline project, Enbridge is proposing a 20-inch diameter, 175,000 b/d diluent import pipeline that would extend from Kitimat, British Columbia to Edmonton, Alberta. It would supply diluent to western Canadian heavy crude oil producers. An application to the National Energy Board is expected in the second quarter of 2009.
Enbridge Southern Lights
26
The project is in response to demand by western Canadian heavy crude oil producers for additional diluent supply from various sources in the U.S. Midwest. The project includes a new 16-inch diameter diluent line from Flanagan, Illinois (near Chicago) to Clearbrook, Minnesota, and the reversal of Line 13 from Clearbrook to Edmonton, Alberta. The capacity of the diluent import line is 180,000 b/d, of which 77,000 b/d is for committed shippers, and can be expanded to 300,000 b/d. The in-service date of July 2010 will coincide with crude oil expansions on the Enbridge mainline system (i.e. Southern Access and Alberta Clipper/Line 4 extension) in order that eastbound capacity is unaffected.
Joint Capline/Chicap Industry Initiative
27
The owners of both Chicap and Capline are co-operating to enable the movement of a limited amount of diluent from the U.S. Gulf Coast to Chicago by mid 2010. The plan is for the Chicap pipeline to connect to the Enbridge Southern Lights pipeline. Chicap runs from Patoka, Illinois to Manhattan and Mokena, Illinois. Ultimate capacity on the pipeline is estimated to be 320,000 b/d operating in batched diluent and light crude oil service. Initial total capacity of the pipeline in 2010 will be about 50 percent of the ultimate capacity. Capline extends from St. James, Louisiana to Patoka and has a capacity of more than one million b/d. The level of diluent deliveries is not known at this time.
29
Canadian Association of Petroleum Producers
TransCanada Diluent Pipeline
24
25
TransCanada is proposing a diluent line from Fort Saskatchewan, Alberta to Fort McMurray, Alberta with an initial capacity of 120,000 b/d and multiple delivery points. The possible in-service date is between 2012 and 2014.
4.4 Pipeline Summary The major pipeline proposals that are currently under construction will add over one million b/d in pipeline capacity exiting western Canada by the end of 2010. A corresponding growth in supply of one million b/d is not forecasted until 2016. Pipeline projects that are currently underway or in the regulatory process will provide excess capacity for a number of years and sufficient pipeline capacity available exiting Western Canada throughout the forecast period. There are still many pipeline proposals being presented. However, many proposals were developed in response to earlier expectations that additional capacity was required to meet more rapid growth in oil sands production than is currently being forecast. Given the current supply outlook and market conditions, the timing of many of these pipeline proposals has been delayed.
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Glossary API Gravity
A specific gravity scale developed by the American Petroleum Institute (API) for measuring the relative density or viscosity of various petroleum liquids.
Barrel
A standard oil barrel is approximately equal to 35 Imperial gallons (42 U.S. gallons) or approximately 159 litres.
Bitumen
A heavy, viscous oil that must be processed extensively to convert it into a crude oil before it can be used by refineries to produce gasoline and other petroleum products.
Bitumen Blend
In this report, bitumen blend includes upgraded heavy sour crude oil, and bitumen to which light oil fractions (ie diluent or upgraded crude oil) have been added in order to reduce its viscosity and density to meet pipeline specifications.
Coker
The processing unit in which bitumen is cracked into lighter fractions and withdrawn to start the conversion of bitumen into upgraded crude oil.
Condensate
A mixture of mainly pentanes and heavier hydrocarbons. It may be gaseous in its reservoir state but is liquid at the conditions under which its volumes is measured or estimated.
Crude oil (Conventional) A mixture of pentanes and heavier hydrocarbons that is recovered or is recoverable at a well from an underground reservoir. It is liquid at the conditions under which its volumes is measured or estimated and includes all other hydrocarbon mixtures so recovered or recoverable except raw gas, condensate, or bitumen. Crude Oil (heavy)
Crude oil is deemed, in this report, to be heavy crude oil if it has an API of 27º or less. No differentiation is made between sweet and sour crude oil that falls in the heavy category because heavy crude oil is generally sour.
Crude Oil (medium)
Crude oil is deemed, in this report, to be medium crude oil if it has an API greater than 27º but less than 30º. No differentiation is made between sweet and sour crude oil that falls in the medium category because medium crude oil is generally sour.
Crude oil (synthetic)
A mixture of hydrocarbons, similar to crude oil, derived by upgrading bitumen from the oil sands.
Density
The mass of matter per unit volume.
Dilbit
Bitumen that has been reduced in viscosity through addition of a diluent (or solvent) such as condensate or naphtha.
Diluent
Lighter viscosity petroleum products that are used to dilute bitumen for transportation in pipelines.
Extraction
A process unique to the oil sands industry, in which bitumen is separated from their source (oil sands).
Feedstock
In this report, feedstock refers to the raw material supplied to a refinery or oil sands upgrader.
Integrated mining project
A combined mining and upgrading operation where oil sands are mined from open pits. The bitumen is then separated from the sand and upgraded by a refining process.
In Situ recovery
The process of recovering crude bitumen from oil sands other than by surface mining.
Merchant upgrader
Processing facilities that are not linked to any specific extraction project but is designed to accept raw bitumen on a contract basis from producers. Crude Oil Forecast, Markets & Pipeline Expansions
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Oil
Condensate, crude oil, or a constituent of raw gas, condensate, or crude oil that is recovered in processing and is liquid at the conditions under which its volume is measured or estimated.
Oil sands
Refers to a mixture of sand and other rock materials containing crude bitumen or the crude bitumen contained in those sands.
Oil Sands Deposit A natural reservoir containing or appearing to contain an accumulation of oil sands separated or appearing to be separated from any other such accumulation. The ERCB has designated three areas in Alberta as oil sands areas. Pentanes Plus
A mixture mainly of pentanes and heavier hydrocarbons that ordinarily may contain some butanes and is obtained from the processing of raw gas, condensate or crude oil.
PADD
Petroleum Administration for Defense District that defines a market area for crude oil in the U.S.
Refined Petroleum Products
End products in the refining process (e.g. gasoline).
Specification
Defined properties of a crude oil or refined petroleum product.
SynBit
A blend of bitumen and synthetic crude oil that has similar properties to medium sour crude oil.
Upgrading
The process that converts bitumen or heavy crude oil into a product with a lower density and viscosity.
West Texas Intermediate WTI is a light sweet crude oil, produced in the United States, which is the benchmark grade of crude oil for North American price quotations.
31
Canadian Association of Petroleum Producers
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APPENDIX A
Acronyms, Abbreviations, Units and Conversion Factors Acronyms
Canadian Provincial Abbreviations
API
AB
Alberta
CAPP Canadian Association of Petroleum Producers
BC
British Columbia
CSS
Cyclic Steam Stimulation
MB
Manitoba
DRA
Drag Reducing Agent
NWT Northwest Territories
EIA
Energy Information Administration
ON
Ontario
ERCB
(Alberta) Energy & Resources Conservation Board
QC
Québec
IEA
International Energy Agency
PADD
Petroleum Administration for Defense District
Units
S
sulphur
b/d
SAGD
Steam Assisted Gravity Drainage
U.S.
United States
American Petroleum Institute
Conversion Factor 1 cubic metre = 6.293 barrels (oil)
WCSB Western Canada Sedimentary Basin WTI
barrels per day
West Texas Intermediate
U.S. State Abbreviations AL
Alabama
AK
Alaska
AZ
Arizona
AR
Arkansas
CA
California
CO
Colorado
CT
Connecticut
DE
Delaware
GA
Georgia
ID
Idaho
IL
Illinois
IN
Indiana
IA
Iowa
KS
Kansas
KY
Kentucky
LA
Louisiana
ME
Maine
MD
Maryland
MA
Massachusetts
TN
Tennessee
MI
Michigan
TX
Texas
MN
Minnesota
UT
Utah
MS
Mississippi
VT
Vermont
MO
Missouri
VA
Virginia
MT
Montana
WA
Washington
NE
Nebraska
WV
West Virginia
NV
Nevada
WI
Wisconsin
NH
New Hampshire
NJ
New Jersey
NM
New Mexico
NY
New York
ND
North Dakota
OH
Ohio
OK
Oklahoma
OR
Oregon
PA
Pennsylvania
SD
South Dakota Crude Oil Forecast, Markets & Pipeline Expansions
32
33
Canadian Association of Petroleum Producers 304 2,506
TOTAL CANADIAN OIL PRODUCTION
1,065
TOTAL OIL SANDS
456
1,263
494
769
2,618
304
2,314
1,111
494
618
166
1,037
1,320
536
784
2,752
369
2,383
1,201
536
665
165
1,017
442
264
178
575
18
22
162
26
347
1,306
584
723
2,718
342
2,375
1,213
584
629
159
1,004
411
255
156
593
16
23
183
23
347
2008
Actuals 2007
1,520
665
855
2,807
285
2,522
1,391
660
731
152
979
393
247
145
586
16
23
191
21
335
2009
Forecast
1,691
745
946
2,917
265
2,652
1,546
738
808
151
954
375
240
135
579
15
23
198
20
323
2010
1,816
803
1,013
2,995
255
2,740
1,665
793
872
151
925
360
233
127
565
14
23
198
18
312
2011
1,899
850
1,049
3,018
225
2,793
1,743
837
905
150
901
349
228
121
552
14
22
198
17
301
2012
2,029
926
1,102
3,071
180
2,891
1,868
914
955
149
873
338
223
115
535
13
22
194
16
290
2013
2,214
1,007
1,207
3,194
150
3,044
2,049
994
1,055
148
847
328
219
109
519
12
21
190
14
280
2014
2,361
1,082
1,280
3,289
125
3,164
2,196
1,069
1,127
148
821
318
215
103
503
12
21
187
13
270
2015
2,551
1,198
1,354
3,437
110
3,327
2,385
1,185
1,200
147
795
309
210
98
486
11
21
181
13
261
2016
2,691
1,320
1,370
3,560
125
3,435
2,519
1,303
1,216
146
769
299
206
93
470
11
20
176
12
252
2017
2,804
1,419
1,385
3,709
190
3,519
2,628
1,397
1,231
145
745
291
202
89
454
10
20
170
11
243
2018
2,949
1,528
1,421
3,865
230
3,635
2,768
1,503
1,265
145
721
282
198
84
439
10
19
165
11
234
2019
3,118
1,603
1,515
4,000
225
3,775
2,933
1,578
1,354
144
699
274
194
80
425
9
19
160
10
226
2020
3,182
1,633
1,549
4,028
215
3,813
2,995
1,608
1,387
143
675
266
190
76
409
9
19
154
10
218
2021
3,263
1,670
1,593
4,060
190
3,870
3,075
1,645
1,430
143
652
259
186
72
394
8
18
148
9
211
2022
3,388
1,720
1,668
4,136
165
3,971
3,199
1,695
1,504
142
631
251
183
69
379
8
18
142
9
203
2023
Growth
3,468
1,750
1,718
4,170
140
4,030
3,279
1,725
1,554
141
610
244
179
65
365
7
18
136
8
196
2024
3,511
1,781
1,730
4,177
125
4,052
3,322
1,756
1,566
140
589
237
175
62
352
7
17
131
8
189
2025
June 2009
** Raw bitumen numbers are highlighted. The oil sands production numbers (as historically published) are a combination of upgraded crude oil and bitumen and therefore incorporate yield losses from integrated upgrader projects. Production from off-site upgrading projects are included in the production numbers as bitumen.
2. CAPP has revised from the June 2007 report historical light/heavy ratio for Saskatchewan starting in 2005.
1. CAPP allocates Saskatchewan Area III Medium crude as heavy crude. Also 17% of Area IV is > 900 kg/m3.
Notes:
626 439
Oil Sands Mining
Oil Sands In Situ
OIL SANDS RAW BITUMEN**
2,202
ATLANTIC CANADA OIL PRODUCTION
989
TOTAL OIL SANDS
WESTERN CANADA OIL PRODUCTION
551 439
Oil Sands Mining
160
Oil Sands In Situ
OIL SANDS (BITUMEN & Upgraded Crude Oil)
PENTANES/CONDENSATE
468 1,053
TOTAL CONVENTIONAL
273
271
Total Conventional Heavy
183
197
581
Alberta Conv. Heavy
585
19 19
Saskatchewan Conv. Heavy 1,2
Heavy
Total Conv. Light and Medium
14 19
155
148
Manitoba
29
360
2006
30
374
2005
N.W.T.
Saskatchewan 1,2
B.C.
Alberta
Light & Medium
CONVENTIONAL
thousand barrels per day
CAPP Canadian Crude Oil Production Forecast 2009 – 2025
APPENDIX B.1
(A47595)
304 2,506
TOTAL CANADIAN OIL PRODUCTION
439 1,065
Oil Sands In Situ
TOTAL OIL SANDS
456
1,263
494
769
2,618
304
2,314
1,111
494
618
166
1,037
1,320
536
784
2,752
369
2,383
1,201
536
665
165
1,017
442
264
178
575
18
22
162
26
1,306
584
723
2,718
342
2,375
1,213
584
629
159
1,004
411
255
156
593
16
23
183
23
347
2008
Actuals
347
2007
1,520
665
855
2,807
285
2,522
1,391
660
731
152
979
393
247
145
586
16
23
191
21
335
2009
1,689
743
946
2,915
265
2,650
1,545
736
808
151
954
375
240
135
579
15
23
198
20
323
2010
Forecast
1,810
798
1,013
2,990
255
2,735
1,659
788
872
151
925
360
233
127
565
14
23
198
18
312
2011
1,882
835
1,047
3,002
225
2,777
1,727
822
904
150
901
349
228
121
552
14
22
198
17
301
2012
1,962
876
1,086
3,006
180
2,826
1,804
863
941
149
873
338
223
115
535
13
22
194
16
290
2013
2,051
893
1,158
3,037
150
2,887
1,892
881
1,012
148
847
328
219
109
519
12
21
190
14
280
2014
2,080
912
1,168
3,015
125
2,890
1,922
900
1,022
148
821
318
215
103
503
12
21
187
13
270
2015
2,098
924
1,175
2,991
110
2,881
1,939
911
1,028
147
795
309
210
98
486
11
21
181
13
261
2016
2,108
928
1,180
2,989
125
2,864
1,949
915
1,034
146
769
299
206
93
470
11
20
176
12
252
2017
2,116
932
1,184
3,038
190
2,848
1,957
919
1,038
145
745
291
202
89
454
10
20
170
11
243
2018
2,120
936
1,184
3,057
230
2,827
1,961
923
1,038
145
721
282
198
84
439
10
19
165
11
234
2019
2,125
941
1,184
3,034
225
2,809
1,966
928
1,038
144
699
274
194
80
425
9
19
160
10
226
2020
2,132
947
1,184
3,006
215
2,791
1,973
935
1,038
143
675
266
190
76
409
9
19
154
10
218
2021
2,137
953
1,184
2,963
190
2,773
1,978
940
1,038
143
652
259
186
72
394
8
18
148
9
211
2022
2,140
956
1,184
2,919
165
2,754
1,981
943
1,038
142
631
251
183
69
379
8
18
142
9
203
2023
2,144
959
1,184
2,876
140
2,736
1,985
947
1,038
141
610
244
179
65
365
integrated upgrader projects. Production from off-site upgrading projects are included in the production numbers as bitumen.
7
18
136
8
196
2024
2,145
961
1,184
2,841
125
2,716
1,987
949
1,038
140
589
237
175
62
352
7
17
131
8
189
2025
June 2009
Operating & In Construction
** Raw bitumen numbers are highlighted. The oil sands production numbers (as historically published) are a combination of upgraded crude oil and bitumen and therefore incorporate yield losses from
2. CAPP has revised fromthe June 2007 report historical light/heavy ratio for Saskatchewan starting in 2005.
1. CAPP allocates Saskatchewan Area III Medium crude as heavy crude. Also 17% of Area IV is > 900 kg/m3.
Notes:
626
Oil Sands Mining
OIL SANDS RAW BITUMEN**
2,202
989
TOTAL OIL SANDS
ATLANTIC CANADA OIL PRODUCTION
439
WESTERN CANADA OIL PRODUCTION
551
Oil Sands In Situ
160
Oil Sands Mining
OIL SANDS (BITUMEN & Upgraded Crude Oil)
PENTANES/CONDENSATE
468 1,053
Total Conventional Heavy
TOTAL CONVENTIONAL
183 273
197 271
Saskatchewan Conv. Heavy 1,2
581
19
19
Alberta Conv. Heavy
Heavy
585
19
Total Conv. Light and Medium
14
155
148
N.W.T.
29
360
2006
30
374
2005
Manitoba
Saskatchewan 1,2
B.C.
Alberta
Light & Medium
CONVENTIONAL
thousand barrels per day
CAPP Canadian Crude Oil Production Forecast 2009 – 2025
APPENDIX B.2
(A47595)
Crude Oil Forecast, Markets & Pipeline Expansions
34
35
405
985
Net Conventional Heavy to Market
TOTAL CONVENTIONAL
Canadian Association of Petroleum Producers 2,317
2,411
1,217
1,194
1,458
835
623
954
382
571
2007
2,436
1,283
1,153
1,497
933
564
939
350
589
2008
Actuals
2,578
1,295
1,283
1,673
972
701
905
323
582
2009
788
878
303
575
2010
2,717
1,354
1,363
1,839
1,051
Forecast
2,808
1,392
1,415
1,960
1,106
854
847
286
561
2011
2,870
1,434
1,437
2,049
1,160
889
822
274
548
2012
3,001
1,556
1,445
2,208
1,294
914
793
262
531
2013
3,192
1,722
1,470
2,427
1,471
955
765
251
515
2014
3,308
1,807
1,501
2,570
1,567
1,002
739
240
499
2015
3,492
1,962
1,529
2,780
1,733
1,047
711
229
482
2016
2. Includes: a) imported condensate b) manufactured diluent from upgraders and c) upgraded heavy volumes coming from upgraders.
1. Includes upgraded conventional.
Notes:
2,190
WESTERN CANADA OIL SUPPLY
1,169
1,148
1,092
1,098
Total Light Supply
Total Heavy Supply
1,354
782
571
963
386
577
2006
1,204
693
Bitumen Blend 2
TOTAL OIL SANDS AND UPGRADERS
511
Upgraded Light (Synthetic)1
OIL SANDS
581
2005
Total Light and Medium
CONVENTIONAL
thousand barrels per day
Blended Supply to Trunk Pipelines and Markets
3,600
2,058
1,542
2,915
1,839
1,076
685
219
466
2017
CAPP Western Canadian Crude Oil Supply Forecast 2009 – 2025
APPENDIX B.3
3,680
2,095
1,584
3,020
1,886
1,134
660
209
450
2018
3,820
2,194
1,626
3,185
1,994
1,191
635
200
435
2019
3,939
2,271
1,667
3,327
2,080
1,247
611
191
421
2020
3,975
2,291
1,684
3,388
2,109
1,279
587
182
405
2021
4,021
2,299
1,722
3,458
2,125
1,332
563
173
390
2022
4,138
2,425
1,713
3,597
2,260
1,338
541
165
375
2023
4,213
2,512
1,702
3,694
2,354
1,340
519
157
361
2024
4,240
2,553
1,687
3,742
2,403
1,339
498
150
348
2025
June 2009
Moderate Growth
(A47595)
405
985
Net Conventional Heavy to Market
TOTAL CONVENTIONAL
2,411
1,217
1,194
1,458
835
623
954
382
571
2007
2,436
1,283
1,153
1,497
933
564
939
350
589
2008
Actuals
2,578
1,295
1,283
1,673
972
701
905
323
582
2009
Forecast
2,715
1,353
1,362
1,837
1,050
787
878
303
575
2010
2,800
1,385
1,415
1,953
1,099
853
847
286
561
2011
2,849
1,412
1,438
2,028
1,138
890
822
274
548
2012
2,920
1,486
1,433
2,127
1,224
902
793
262
531
2013
3,010
1,587
1,423
2,244
1,336
908
765
251
515
2014
3,021
1,611
1,410
2,282
1,371
911
739
240
499
2015
3,017
1,624
1,393
2,306
1,395
911
711
229
482
2016
2. Includes: a) imported condensate b) manufactured diluent from upgraders and c) upgraded heavy volumes coming from upgraders.
1. Includes upgraded conventional.
Notes:
1,169
1,098
2,190
Total Heavy Supply
WESTERN CANADA OIL SUPPLY
2,317
1,148
1,092
Total Light Supply
1,354
1,204
782
693
TOTAL OIL SANDS AND UPGRADERS
571
511
Bitumen Blend 2
963
386
577
2006
Upgraded Light (Synthetic)1
OIL SANDS
581
2005
Total Light and Medium
CONVENTIONAL
thousand barrels per day
Blended Supply to Trunk Pipelines and Markets
3,004
1,626
1,378
2,319
1,407
912
685
219
466
2017
CAPP Western Canadian Crude Oil Supply Forecast 2009 – 2025
APPENDIX B.4
2,990
1,627
1,363
2,330
1,418
912
660
209
450
2018
2,970
1,624
1,347
2,335
1,424
911
635
200
435
2019
2,954
1,621
1,332
2,342
1,431
912
611
191
421
2020
2,938
1,622
1,316
2,351
1,440
911
587
182
405
2021
2,921
1,621
1,301
2,358
1,447
911
563
173
390
2022
2,903
1,617
1,286
2,362
1,451
911
541
165
375
2023
2,886
1,613
1,273
2,367
1,456
912
519
157
361
2024
2,868
1,608
1,260
2,370
1,458
912
498
150
348
2025
June 2009
Operating & In Construction
(A47595)
Crude Oil Forecast, Markets & Pipeline Expansions
36
(A47595)
APPENDIX C.1 Crude Oil Pipeline Expansions and Proposals to U.S. Midwest, Ontario, Québec and the U.S. East Coast Pipeline
Proposed In-service Date
Capacity (thousand b/d)
Cushing, OK
3Q 2009
130
Patoka, IL
December 2009
435
North Dakota
Clearbrook, MN
January 2010
52
Hardisty, AB
Superior, WI
July 2010
450
KS/NE border
Cushing, OK
4Q 2010
155
Flanagan, IL
Hartsdale
2012/2013
400
Chicago, IL
Sarnia, ON
2012/2013
65 to 135 200
Originating Point
End Point
Enbridge Spearhead - North
Flanagan, IL
TransCanada Keystone
Hardisty, AB
Enbridge North Dakota Enbridge Alberta Clipper TransCanada Keystone Cushing Extension Enbridge Chicago Connectivity Enbridge Line 6B Expansion Enbridge Line 6C TransCanada Heartland Extension Enbridge Southern Access Extension (also referred to as part of BP/Enbridge Gulf Access) Enbridge Line 5 Expansion
Griffith, Hartsdale, IN
Stockbridge, MI
2012/2013
Fort Saskatchewan, AB
Hardisty, AB
2012/2013
600
Flanagan, IL
Patoka, IL
2012+
400 to 800 50
Superior, WI
Sarnia, ON
TBD
Enbridge Ohio Access Phase 1
Stockbridge, MI
Toledo, OH
TBD
20
Enbridge Ohio Access Phase 2
Stockbridge, MI
Toledo, OH
TBD
180
Enbridge Southern Access Expansion
Superior, WI
Flanagan, IL
TBD
800
ExxonMobil Mustang Expansion
Lockport, IL
Patoka, IL
TBD
38
Marysville, MI
Toledo, OH
TBD
190 to 288 (light crude)
Buffalo, NY
Philadelphia, PA
TBD
400
Sarnia, ON
Montréal, QC
2012/2013
215
Montréal, QC
Portland, ME
2012/2013
200
Sunoco Pipeline - to Toledo Sunoco Pipeline - to Philadelphia Redeployment of Existing Infrastructure Enbridge Trailbreaker (Line 9 re-reversal) Portland reversal
37
Canadian Association of Petroleum Producers
(A47595)
APPENDIX C.2 Crude Oil Pipeline Proposals to the U.S. Gulf Coast Pipeline ExxonMobil Pegasus Expansion
Originating Point
End Point
Proposed In-service Date
Capacity (thousand b/d)
Patoka, IL
U.S. Gulf Coast
June 2009
30
TransCanada Keystone XL
Hardisty, AB
U.S. Gulf Coast
2012/2013
700
BP/Enbridge Gulf Access Phase 1 (new build portion)
Cushing, OK
Houston, TX (and potential Nederland/ Port Arthur, TX extension)
2012+
150 to 200
BP/Enbridge Gulf Access Phase 2 (Southern Access Extension portion)
Flanagan, IL
Patoka, IL
2012+
400 to 800
BP/Enbridge Gulf Access Phase 3
Patoka, IL
Nederland/Port Arthur, TX
2012+
500+
TransCanada Louisiana Access Option 1
Patoka, IL
New Orleans, LA
2014/2016
400
TransCanada Louisiana Access Option 2
Port Arthur, TX
New Orleans, LA
2014/2016
400
Fort McMUrray, Hardisty, AB
Beaumont/Port Arthur, TX
TBD
425
Patoka, IL
Beaumont, TX
TBD
445
Cushing, OK
U.S. Gulf Coast
TBD
300
Centurion Pipeline - reversal
Cushing, OK
Slaughter, TX
4Q 2009
60
BP Pipelines #1 reversal and expansion (part of BP/Enbridge Gulf Access Phase 1)
Flanagan, IL
Cushing, OK
2012+
150 to 200
Wood River, IL
Cushing, OK
2012+
200+
Altex Energy ExxonMobil /Enbridge Texas Access Sunoco Pipelines to US Gulf Coast Redeployment of Existing Infrastructure
Enbridge Ozark reversal (part of BP Enbridge Gulf Access Phase 2)
Appendix C.3 Crude Oil Pipeline Expansions and Proposals to the West Coast Pipeline
Originating Point
End Point
Proposed In-service Date
Kinder Morgan TMX2
Edmonton, AB
Kamloops, BC
2012
80
Kinder Morgan TMX3
Kamloops, BC
Sumas, BC
2013
320
Enbridge Northern Gateway
Capacity (thousand b/d)
Edmonton, AB
Kitimat, BC
2012 to 2014
500
TransCanada Alberta to California
Fort Saskatchewan, AB
San Francisco, CA and/or Los Angeles, CA
2016+
400
Kinder Morgan TMX Northern Leg
Rearguard/Edmonton, AB
Kitimat, BC
2014+
400
Crude Oil Forecast, Markets & Pipeline Expansions
38
(A47595)
Appendix D Crude Oil Pipelines and Refineries Upgraders Syncrude (Fort McMurray) .............465 Suncor (Fort McMurray) ..................350 Shell (Scotford)...................................155
Vancouver to: Japan - 4,300 miles Taiwan - 5,600 miles S.Korea - 4,600 miles China - 5,100 miles
Prince George Husky...............12
Edmonton Imperial...........................187 Petro-Canada ................125 Shell..................................100 Lloydminster Husky................................. 29 Husky Upgrader............. 82
San Francisco - 800 miles Los Angeles - 1,100 miles
Vancouver Chevron ...........55
Puget Sound BP ..................................230 ConocoPhillips...........100 Shell...............................145 Tesoro ...........................115 US Oil ............................. 39
Regina Co-op Refinery/ Upgrader .......................100 Moose Jaw Moose Jaw Asphalt..... 15
Great Falls Montana Refining..... 10 Billings Cenex ............................ 60 ConocoPhillips........... 58 ExxonMobil................. 60
San Francisco Chevron ...................240 ConocoPhillips.......120 Shell...........................165 Tesoro .......................166 Valero........................170
Superior Murphy.......
Mandan Tesoro ..............60
Wyoming Frontier (Cheyenne)......................52 Little America (Casper) ................25 Sinclair Oil (Sinclair) ......................66 Wyoming (Newcastle)..................14
Salt Lake City Big West ..............35 Chevron ..............45 Holly.....................31 Tesoro ..................58
St. Paul Flint Hills .............320 Marathon.............. 74
McPherson NCRA.......................................... 85 El Dorado Frontier....................................130 Coffeyville Coffeyville Resources .........115
Denver/Commerce City Suncor ............................. 93
F
Oklahoma ConocoPhillips (Ponca City)............... 187 Sinclair (Tulsa)............................................70 Holly (Tulsa)................................................85 Valero (Ardmore) ......................................87 Wynnewood...............................................70 Los Angeles BP ........................................ 275 Chevron ............................. 270 ConocoPhillips.................139 ExxonMobil....................... 150 Tesoro ................................. 100 Valero ................................. 135
D
EA RH EA TH P S OU S
Borger/McKee WRB ..................................146 Valero...............................171
IL
Artesia
N XO
EX
Slaughter
Artesia Holly.............. 85
EXXON
MOBIL
EX
XO
NM
OB
ON
X EX
El Paso Western Refining .........125
OB
M
N
URIO CENT
S
BIL
MO
IL
Three Rivers Valero..............................100 Corpus Christi CITGO..............................156 Flint..................................288 Valero..............................315
39
Canadian Association of Petroleum Producers
Houston/Texas City BP ....................................460 ConocoPhillips.............247 Deer Park .......................330 ExxonMobil...................567 Houston CITGO............271 Marathon......................... 76 Valero (2)........................390
Port Arthur/ Beaumont
Port Arthur/Beaumont ExxonMobil................... 349 Motiva............................. 285 Valero.............................. 310 Total................................. 175
(A47595)
2008 Canadian Crude Oil Production 000 b/d 000 m3/d British Columbia Alberta Saskatchewan Manitoba Northwest Territories
5 297 70 4 3
34 1,869 439 24 18
Western Canada Atlantic Canada Total Canada
379 54 433
2,383 342 2,725
For Information Contact: (403) 267-1141 / www.capp.ca
Newfoundland North Atlantic .................. 115
Come by Chance
Saint John Irving....................250
Sarnia Imperial............... 121 Nova ........................80 Shell.........................74 Suncor ....................85 Nanticoke Imperial............... 120
...... 35
Montreal/Québec Petro-Canada ........130 Shell..........................126 Valero.......................235 Halifax Imperial............... 82
Chicago BP ............................. 400 ExxonMobil............ 239 PDV .......................... 167
Warren United ......... 70
Flanagan
Detroit Marathon...................102 Toledo BP ................................155 Sunoco .......................160 Lima Husky ..........................165 Canton Marathon..................... 78 Catlettsburg Marathon...................226
New Jersey ConocoPhillips...............238 Sunoco .............................145 Valero................................185
Philadelphia ConocoPhillips (Trainer)............. 185 Sunoco (Marcus Hook) ............... 178 Sunoco (Philadelphia)................. 335 Wood River WRB .....................................306 Robinson Marathon...........................204
Pipeline Tolls (US$ per barrel) Edmonton to Burnaby (Trans Mountain) Anacortes (Trans Mountain) Sarnia (Enbridge) Chicago (Enbridge) Wood River (Enbridge/Mustang/Capwood) USGC (Enbridge/Mustang/ExxonMobil) Hardisty to Guernsey (Express/Platte) Wood River (Express/Platte) USGC (Express/Platte/MAP/ExxonMobil) USEC to Sarnia (Portland/Montreal/Enbridge) St. James to Wood River (Capline/Capwood) Freeport to Wood River (Seaway/Ozark)
1.60 1.85 2.75 2.40 3.25 4.55 1.45 1.75 3.40 2.00 0.65 1.50
Notes 1) Heavy crude adds 20-30% 2) Tolls rounded to nearest 5 cents 3) Tolls in effect July 1, 2009
Memphis Valero...................195 El Dorado Lion......................... 70
St. Charles
9 5 0 5
Lake Charles/Garyville ConocoPhillips...............239 CITGO................................440 Marathon.........................256 Valero................................250
Approved Crude Oil Pipelines
Crude Oil Forecast, Markets & Pipeline Expansions
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The Canadian Association of Petroleum Producers (CAPP) represents 130 companies that explore for, develop and produce natural gas, natural gas liquids, crude oil, oil sands, and elemental sulphur throughout Canada. CAPP member companies produce more than 90 per cent of Canada’s natural gas and crude oil. CAPP also has 150 associate members that provide a wide range of services that support the upstream crude oil and natural gas industry. Together, these members and associate members are an important part of a $120-billion-a-year national industry that affects the livelihoods of more than half a million Canadians.
Calgary Office:
(A47595)
St. John’s Office:
2100, 350 - 7 Avenue SW Calgary, Alberta, Canada T2P 3N9
www.capp.ca
[email protected] June 2009
Phone: 403-267-1100 Fax: 403-261-4622
2009 - 0017
403, 235 Water Street St. John’s, Newfoundland and Labrador Canada A1C 1B6 Phone: 709-724-4200 Fax: 709-724-4225
Disclaimer: This publication was prepared by the Canadian Association of Petroleum Producers (CAPP). While it is believed that the information contained herein is reliable under the conditions and subject to the limitations set out, CAPP does not guarantee the accuracy or completeness of the information. The use of this report or any information contained will be at the user’s sole risk, regardless of any fault or negligence of CAPP.
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Canadian Association of Petroleum Producers
