Crude Oil 2011 June Attachment JRP IR 2.2(a) and 2 · 2005 2007 2009 2011 2013 2015 2017 2019 2021...

Crude Oil Forecast, Markets & Pipelines 1

Crude OilForecast, Markets & Pipelines

2011June

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JRP IR 2.2(a) and 2.5

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2 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

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.

© Material may be reproduced for public non-commercial use provided due diligence is exercised in ensuring accuracy of information reproduced; CAPP is

identified as the source; and reproduction is not represented as an official version of the information reproduced nor as any affiliation.

Crude Oil Forecast, Markets & Pipelines i

EXECUTIVE SUMMARY CAPP annually releases its 15-year outlook for Canadian crude oil production to provide industry stakeholders, government

agencies and other interested parties with an informed view of prospective changes in supply. This report integrates the

forecast with an updated assessment of the potential market options and the corresponding pipeline infrastructure needed

to reach these markets. While the forecast calls for more robust growth in Canadian crude oil production compared to the

previous year, it remains less than forecast in 2008. This report also highlights the challenges that producers face in finding

new markets for this growing production.

20252023202120192017201520132011200920072005

Conventional Heavy

Conventional LightPentanes

Oil Sands Growth

Oil Sands Operating & In Construction

0

1,000

2,000

3,000

4,000

5,000

thousand barrels per day

Atlantic CanadaForecastActual

June 2010 Forecast

6,000

Canadian Oil Sands & Conventional Production

Canadian Crude Oil Production

and Supply

Consistent with the 2010 report, CAPP has prepared both

an expected forecast or “Growth” Case and an “Operating

& In Construction” Case to provide a foundation to the

expected case. CAPP’s “Growth” Case for oil sands

production is similar to the 2010 forecast for the first half

of the outlook period. However, starting around 2018, this

latest outlook is higher than the 2010 view.

Of note, CAPP’s recent forecast for conventional

production shows a slight annual increase for the next

several years in contrast to the steady annual decline

shown in the previous outlooks. This can be attributed

to the success of horizontal multi-fracturing technology

over the last three years combined with the expectation of

continued strong oil prices in the medium term which will

continue to stimulate investment.

Canadian Crude Oil Production

million b/d 2010 2015 2020 2025

Total Canadian

(including oil sands)2.8 3.5 4.2 4.7

Oil Sands 1.5 2.2 3.0 3.7

Oil Sands (Operating

& In Construction only )1.5 2.1 2.3 2.2

Overall, total Canadian oil production is expected to grow

from 2.8 million b/d in 2010 to 4.7 million b/d in 2025.

This is about 401,000 b/d higher than previously forecast,

due primarily to the higher conventional production and

the inclusion of some additional in situ projects that were

previously put on hold.

ii CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

Crude Oil Markets

The U.S. Midwest is the primary export market for

western Canadian crude oil supplies due to its strong

demand, geographic proximity and established pipeline

infrastructure. Several key factors suggest that growing

supplies of crude oil from western Canada could find a

market on the U.S. Gulf Coast or world markets once they

reach Canada’s west Coast, including California and Asia.

With the recent startup of the Keystone Pipeline to Patoka,

Illinois, followed by the extension of this pipeline into

Cushing, Oklahoma, crude oil supplies from western

Canada into the U.S. Midwest market are expected

to grow. In the meantime, western Canadian crude oil

producers have growing supplies and are looking at

accessing new markets for this supply. Producers currently

have limited transportation options to serve alternative

markets on the U.S. Gulf Coast. This is the largest refining

market in the world and over half of the existing capacity

can process heavy crude oil. Refineries in this market are

looking to replace declining supplies historically coming

from Mexico and Venezuela.

Imports of crude oil in U.S. western states, specifically

California and Washington, could increase since the

refineries in this market get the majority of their crude oil

supplies from California and Alaska and production from

these states has been steadily declining. The Asian market

is expected to grow substantially and access to these

markets is an important part of achieving market diversity.

The International Energy Agency estimates China’s

demand for oil will grow by 10 per cent in 2011, and high

rates of growth are anticipated to continue. This, along with

growth in other parts of Asia and India, will increase world

crude oil demand, which in a global context, will enhance

the global importance of Canadian supplies.

PADD II

PADD I

PADD V

PADD III

55 [+10]

119 [+380]

3,736

1,231 [+483]

2,731

Non-US25 [unknown]

205 [+64]

276 [+11]

Supply

2010 - 2,700

2015 - 3,549

1,312

8,996

393

PADD IV

237 [+8]

613

2011 Total Refining Capacity

2010 ActualDemand

2015 Potential

Additional Demand

552 [+82]

632

Market Demand for Western Canadian Crude Oil – Actual 2010 and 2015 Additional


Crude Oil Forecast, Markets & Pipelines iii

Portland

Montréal

Sarnia

Chicago

Cushing

St. Paul

Salt Lake City

Houston

Edmonton

Anacortes

Burnaby

TransCanada Keystone

& Cushing Extension

Enbridge Alberta Clipper

TransMountain

BP

Enbridge

Mid

Valle

y

Cap

lin

e

Flanagan

Hardisty

Centurion Pipeline

Express

Platte

Enbridge (North Dakota) Expansion

Spearhead SouthSpearhead North

Superior

WoodRiver

ExxonMobil Pegasus

Clearbrook

Guernsey

TransCanada

Keystone XL

Kinder Morgan

TMX2 Expansion

TMX3 Expansion

Kitimat Enbridge GatewayKinder Morgan

TMX Northern Leg

Port Arthur

Mustang

Patoka

Canadian and U.S. Oil Pipelines

Enbridge Pipelines, Alberta Clipper

and connections to the U.S. Midwest

Kinder Morgan Express

Kinder Morgan Trans Mountain


Proposed pipelines to the West Coast

Existing / Proposed pipelines to PADD III

Expansion to existing pipeline

1 - Enterprise/ETP Cushing-Gulf

2 - Enbridge Monarch

3 - Keystone Cushing MarketLink

Enbridge Line 9

Reversal

Lima

TransCanada

Keystone East

Canadian & U.S. Crude Oil Pipelines - All Proposals

Crude Oil Pipelines and

Expansions

The Keystone Base Pipeline and the Cushing Extension

provided 591,000 b/d of new pipeline capacity that connects

western Canadian supplies to market hubs in Illinois and

Oklahoma. These pipelines provide ample capacity to

traditional U.S. Midwest markets. With the forecast of growing

supplies, the industry is: strategically looking to expand

access to markets; focused on addressing the need for more

capacity into the U.S. Gulf Coast; and increasing pipeline

capacity to the west coast. A number of pipeline projects are

being proposed to provide both market access and additional

capacity that will be needed by Canadian producers in the

future.

There are a number of new pipeline proposals from Cushing

to the U.S. Gulf Coast being proposed that would provide an

outlet for the current oversupply of Canadian and U.S. crude

that has been building in the U.S. Midwest. There are also

pipeline proposals to expand export capacity to the west

coast, providing access to new markets with strong growth

potential.

iv CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

TABLE OF CONTENTSEXECUTIVE SUMMARY i

LIST OF FIGURES AND TABLES v

1 INTRODUCTION 1

2 CRUDE OIL PRODUCTION AND SUPPLY FORECAST 2

2.1 Canadian Crude Oil Production 2

2.2 Western Canadian Crude Oil Production 3

2.2.1 Conventional Crude Oil Production 3

2.2.2 Oil Sands 4

2.3 Western Canadian Crude Oil Supply 6

2.4 Methodology 7

2.5 Crude Oil Production and Supply Summary 8

3 CRUDE OIL MARKETS 9

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 16

3.4 Methodology 17

3.5 Markets Summary 17

4 CRUDE OIL PIPELINES 18

4.1 Existing Major Oil Pipelines Exiting Western Canada 19

4.2 Oil Pipelines to the U.S. Midwest 20

4.3 Oil Pipelines to the U.S. Gulf Coast 21

4.4 Oil Pipelines to the West Coast 23

4.5 Other Pipelines 23

4.6 Diluent Pipelines 24

4.7 Pipeline Summary 24

GLOSSARY 25

APPENDIX A: Acronyms, Abbreviations, Units and Conversion Factors 27

APPENDIX B: CAPP Canadian Crude Oil Production and Supply Forecast 2011 – 2025 28

APPENDIX C: Crude Oil Pipelines and Refineries 31

Crude Oil Forecast, Markets & Pipelines v

LIST OF FIGURES AND TABLES

FiguresFigure 2.1 Canadian Oil Sands & Conventional Production 3

Figure 2.2 Growth Case - Western Canada Oil Sands & Conventional Production 4

Figure 2.3 Oil Sands Regions 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 – Actual 2010 and 2015 Additional 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 2010 PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil 11

Figure 3.6 2010 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 13

Figure 3.10 2010 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 2010 PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil 15

Figure 3.13 Washington: Forecast Western Canadian Crude Oil Receipts 16

Figure 3.14 2010 PADD V (California): Foreign Sourced Supply by Type and Domestic Crude Oil 16

Figure 4.1 Canadian & U.S. Crude Oil Pipelines - All Proposals 18

TablesTable 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 Demand in Major Asian Countries 17

Table 4.1 Capacity of Major Crude Oil Pipelines Exiting the WCSB 19

Table 4.2 Summary of Oil Pipelines to the U.S. Midwest 21

Table 4.3 Summary of Oil Pipelines to the U.S. Gulf Coast 22

Table 4.4 Summary of Oil Pipelines to the West Coast 23

Table 4.5 Summary of Diluent Pipelines 24


INTRODUCTION

CAPP annually releases its 15-year outlook for Canadian crude oil production to

provide industry stakeholders, government agencies and other interested parties

with an informed view of prospective changes in supply. Although the primary

focus for the report is to provide such a forecast, the report also includes a

discussion of the market outlook for Canadian crude oil. In addition, an overview

is provided of the pipelines that currently transport Canadian crude oil supplies

as well as new pipeline projects that could be constructed in order to provide

the industry with transportation to alternative markets. This annual update also

discusses emerging developments and their potential impacts on the industry.

1

The upstream Canadian oil industry continues to face

many risks and challenges but there were some positive

developments for the industry in 2010 as compared to

the previous year. In 2010, WTI crude oil prices averaged

around US$80 per barrel and exhibited less volatility than

was seen in 2009. This more stable pricing environment

created a better investment climate for the industry. Also,

production in both the Atlantic and conventional wells in

Western Canada performed better in 2010 than forecast in

last year’s report. While there were operational challenges

for a number of the mining projects, this production loss

was offset somewhat by higher growth in production from

the in situ projects.

With WTI oil prices in the first half of 2011 surpassing

the US$100 per barrel level and growing success

in the industry from applying advanced oil recovery

techniques, this latest forecast has an improved outlook

for conventional production with respect to previous years.

The first half of the forecast is similar to last year’s forecast

but from 2019 to 2025, the forecast is now higher. This

is the result of a more accelerated startup of production

phases and the revival of certain development projects

that had previously been put on hold. CAPP’s estimate

of industry capital spending for oil sands development is

$16 billion for 2011 compared to $13 billion spent in 2010.

The U.S., particularly the U.S. Midwest, continues to be the

largest market for western Canadian crude oil. However,

industry players need to continue working to establish

market diversity. Industry efforts are currently concentrated

towards ensuring that the potential demand from the U.S.

Gulf Coast can be accessed. In addition, strong interest

remains to supply at least some of the anticipated growing

demand from the Asia Pacific region.

The report consists of 4 main chapters as follows:

• Chapter 1 is the introduction to the report.

• Chapter 2 provides the crude oil production and supply

forecast.

• Chapter 3 identifies the existing and potential crude oil

markets.

• Chapter 4 describes the existing crude oil pipeline

network and the proposed projects designed to enable

Canadian supplies to expand the reach into key

markets.


In early 2011, CAPP surveyed all oil sands producers on

their anticipated production over the next 15 years in order

to form the basis of this latest update of CAPP’s long-term

crude oil forecast. This data, by project, was subsequently

risked through adjustments to projected start dates and

production profiles to produce an expected outlook in

consideration of historical production capacity. CAPP’s

forecast of conventional production was developed from

information provided by various provincial government

departments and agencies that was incorporated with

internal staff analysis.

2.1 Canadian Crude Oil Production

Although most of Canada’s crude oil production comes

from western Canada, 11 per cent is produced from

Atlantic Canada. In 2010, Canada’s production was

comprised of almost 2.6 million b/d sourced from western

Canada and 276,000 b/d sourced from Atlantic Canada.

Atlantic Canada’s oil industry is located offshore from

the province of Newfoundland, and consists of three

independent oil developments - Hibernia, Terra Nova and

White Rose. Production from Atlantic Canada increased

three per cent in 2010 - the first time a year-over-year

increase has been recorded since 2007. Production in 2010

was higher than originally forecast due mainly to decreased

downtime compared to 2009, better-than-expected

recovery from several wells at Hibernia, and the startup of

the North Amethyst field. The North Amethyst field is the

first satellite field development at White Rose.

Overall, future declines in production from existing fields

will be partially offset with new production from newly

connected satellite fields and the start up of the Hibernia

South Extension. The Hebron heavy oil project is also

expected to begin production before the end of 2017. Most

of this oil is around 20° API gravity.

The forecast continues to show significant production

growth in western Canada, particularly the oil sands,

as discussed in more detail in the following sections.

Consistent with CAPP’s 2010 report, this year’s Growth

Case is the expected production outlook. The secondary

case includes only projects that are either currently

operating or are in construction. (Figure 2.1). Table 2.1

shows that in the Growth Case, total Canadian production

is expected to reach 4.7 million b/d in 2025. Under the

Operating & In Construction Case, production increases

but then declines in the latter part of the forecast to

3.3 million b/d by 2025 due to the natural declines in

production from both mature conventional fields and

Atlantic Canada.

Table 2.1 Canadian Crude Oil Production

million b/d 2010 2015 2020 2025

Growth 2.83 3.48 4.21 4.74

Operating

& In Construction 2.83 3.44 3.48 3.25

CRUDE OIL PRODUCTION

AND SUPPLY FORECAST2

Canada has proven oil reserves of over 175 billion barrels, which are the third

largest in the world. According to the Oil and Gas Journal, Canada also ranks as

the world’s sixth largest oil producing country. Future growth in oil production is

expected to be primarily sourced from the oil sands areas. However, the near-

term outlook for conventional production from Saskatchewan and Alberta has also

improved with the greater use of new technologies being anticipated.


2.2 Western Canadian Crude Oil

Production

The Western Canadian Sedimentary Basin (WCSB), which

underlies most of Alberta, parts of Saskatchewan, British

Columbia, Manitoba and the Northwest Territories, contains

the world’s third largest reserves of oil. Oil production

from western Canada can be further differentiated by

production coming from conventional drilling or from oil

sands production, which consists of both mining and in

situ projects. In 2010, 2.6 million b/d of oil was produced,

comprised of about 42 per cent from conventional oil fields

and 58 per cent from oil sands.

Table 2.2 shows the forecast for total western Canadian

crude oil production. Compared to CAPP’s 2010 forecast,

conventional production is higher. In fact, the natural

decline in production that has been exhibited for over

10 years is expected to be reversed in the near term.

Higher production from oil sands projects in the latter

part of the forecast is also now expected due to greater

certainty surrounding the development of a number of

in situ projects (Figure 2.2). The production forecast in

the Operating & In Construction Case is slightly higher

than in the previous forecast due to higher conventional

production and the inclusion of additional projects that

have moved into the construction phase. (Figure 2.4).

Table 2.2 Western Canadian Crude Oil Production

million b/d 2010 2015 2020 2025

Conventional

(including condensate)

1.08 1.10 0.99 0.86

Oil Sands 1.47 2.16 3.00 3.73

Growth Case 2.55 3.26 3.99 4.59

Operating & In

Construction 2.55 3.23 3.26 3.10

2.2.1 Conventional Crude Oil

Production

From an oil exploration and development standpoint,

conventional oil fields in the WCSB are relatively mature.

However, future technology improvements could increase

the rate of recovery for the oil-in-place, which is currently

only around 26 per cent. In fact, the use of horizontal wells

and multi-stage fracturing techniques in conventional wells

has yielded better than expected results in recent years,

suggesting that we may have previously underestimated

the impact. In 2010, the decline in conventional crude

oil production was effectively halted for the first time in

over 10 years, which can be attributed to the increased

use of this technology that was encouraged by a higher

price environment and favourable royalty changes in the

province of Alberta.

20252023202120192017201520132011200920072005

Conventional Heavy


Oil Sands Growth

Oil Sands Operating & In Construction

0

1,000

2,000

3,000

4,000

5,000


Atlantic CanadaForecastActual

June 2010 Forecast

6,000

Figure 2.1 Canadian Oil Sands & Conventional Production


Although the WCSB spans several provinces, most of

the oil resources are located in the provinces of Alberta

and Saskatchewan. The successful use of horizontal

drilling and multi-fracturing in the Bakken formation in

Saskatchewan provided the earliest indications that this

technology was a game changer for the industry. Over the

medium term, moderate growth in Saskatchewan light

oil production is estimated. The Bakken play is expected

to continue to perform strongly; and there is increased

interest in horizontal drilling in emerging oil plays like the

Lower Shaunavon in the southwest of the province, the

Viking in west-central Saskatchewan around Kindersley

and the Birdbear in the northwest of the province near

Lloydminster. Similarly, the Cardium formation in Alberta

and the Viking formation in central and eastern Alberta

and west central Saskatchewan have been identified as

formations well suited for increased use of this technology

since they contain large deposits of oil-in-place with

historically low recovery rates. Industry continues to focus

on acquiring oil well licenses as a result of strong oil prices.

Oil well permitting licenses are up significantly in Alberta,

Manitoba and Saskatchewan – at decade high rates across

western Canada.

2.2.1 Oil Sands

Production from oil sands currently comprises 58 per cent

of western Canada’s total crude oil production. In the

Growth Case, production is expected to grow from

1.5 million b/d in 2010 to 2.2 million in 2015 and to

3.7 million b/d in 2025. The increase in the latter part of the

forecast results from a combination of the acceleration of

the startup of certain project phases and production from

projects that were previously placed on hold.

Figure 2.3 Oil Sands Regions

20252023202120192017201520132011200920072005

Conventional Heavy


0

1,000

2,000

3,000

4,000

5,000


June 2010 Forecast

6,000

In Situ

Mining

ForecastActual

Edmonton

Calgary

Lloydminster

Peace

River

Fort

McMurray Area of

Potential

Athabasca

Deposit

Cold Lake

Deposit

Peace River

Deposit

Figure 2.2 Growth Case - Western Canada Oil Sands & Conventional Production


Canada’s oil sands deposits are divided into three major

regions in northern Alberta referred to as the Athabasca,

Cold Lake and Peace River deposits (Figure 2.3). The

Alberta Energy Resources and Conservation Board (ERCB)

estimated at year-end 2009, that these areas contain

remaining established reserves of 170 billion barrels.

Of the remaining established reserves in Alberta,

136 billion barrels, or 80 per cent, is considered

recoverable by in situ methods and 34 billion barrels can

be recovered by surface mining. In situ recovery includes

both primary methods, which are similar to conventional

production, and other methods whereby steam, water, or

other solvents are injected into the reservoir to reduce the

viscosity of the bitumen, allowing it to flow to a vertical or

horizontal wellbore.

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.

In 2010, 53 per cent of the total bitumen produced from oil

sands deposits was mined. Currently, all mined bitumen

is transformed into upgraded light crude oil as part of an

overall integrated operation. However, bitumen production

from the Imperial Kearl Lake mining project, which is slated

to come online in 2012, will likely come on to the market as

a diluted bitumen as it does not have an affiliated upgrader.

Also, a recent update on the future expansion at Syncrude

notes that bitumen production will exceed the upgrader’s

processing capacity. However, in early 2011, Northwest

Upgrading and Canadian Natural Resources Ltd (CNRL)

signed an agreement to build, manage and operate a new

bitumen refinery near Redwater, Alberta. This facility would

be able to upgrade some of the growing volumes of diluted

bitumen available from both in situ and mining projects.

Recovery of raw bitumen using in situ methods is set to

surpass production from mining methods by 2016. Currently,

of the in situ projects in operation, only the Long Lake

project operated by Nexen Inc. is coupled with upgrading

facilities. Also, production from the Suncor Firebag and

MacKay River projects are upgraded at Suncor’s facilities.

Otherwise, the majority of in situ bitumen production is not

upgraded prior to reaching markets.

20252023202120192017201520132011200920072005

Conventional Heavy


0

1,000

2,000

3,000

4,000

5,000

June 2010 Forecast

6,000

In Situ

Mining

ForecastActual


In Situ

Figure 2.4 Operating & In Construction - Western Canada Oil Sands & Conventional Production


The integrated mining and upgrading projects in operation

are listed below:

• The Suncor Steepbank and Millennium Mine;

• The Syncrude Mildred Lake and Aurora Mine;

• The Athabasca Oil Sands Project (AOSP); and

• The CNRL Horizon Project.

In September 2010, Shell’s Jackpine mine started

production and an accompanying expansion of upgrading

capacity is expected sometime in 2011. Imperial’s Kearl

Lake Project and expansions by both Syncrude and

CNRL’s Horizon are the major mining projects currently

under construction.

In the Operating & In Construction Case, oil sands

production is expected to grow from over 1.5 million b/d in

2010 to approximately 2.2 million b/d around the end of the

forecast period. (Figure 2.4). Please refer to Appendices

B.1 and B.2 for detailed production data tables.

2.3 Western Canadian Crude

Oil Supply

In order to be transported by pipeline and because

refineries are configured to process particular types of

crude oil, the production discussed in the previous section

is transformed into a variety of crude oil types. It is these

volumes that comprise the crude oil supply, or volumes

available to markets.

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 Oil Sands Heavy. Oil Sands Heavy

includes upgraded heavy sour crude oil, bitumen diluted

with upgraded light crude oil (also known as “SynBit”) and

bitumen diluted with condensate (also known as “DilBit”).

An example of such a DilBit would be Cold Lake crude,

which has a density of about 930 kg/m3 (21° API) and a

sulphur content of 3.6 per cent. Blending for DilBit requires

a 70:30 bitumen to condensate ratio while blending for

SynBit changes the blending ratio to approximately 50:50.

Bitumen is so viscous that it needs to be diluted with

a lighter hydrocarbon, to create a type of crude oil that

meets pipeline specifications for density and viscosity.

Although the main source of diluent is condensate that is

recovered from processing natural gas in western Canada,

the needs of growing bitumen production exceed this

diluent supply. In 2010, an average of over 116,000 b/d

of combined butane, diluents from upgraders, and

imported condensates supplemented the locally produced

condensate supply. This latest forecast is not constrained

by the availability of condensate imports as new sources

of condensate are assumed to be available to meet market

requirements. For example, higher volumes of imports are

expected going forward given that Enbridge’s Southern

Lights Pipeline started up in 2010.

Some producers have indicated their intention to use

upgraded light crude oil to blend with their bitumen

production instead of condensate. This latest forecast

reflects a similar use of upgraded synthetic crude oil as a

source of diluent as the 2010 forecast. Overall, decreases

in the reported yield losses for some projects, higher

production and the required accompanying increase in

condensate imports results in a higher supply forecast than

in 2010.

Table 2.3 Western Canadian Crude Oil Supply

million b/d 2010 2015 2020 2025

Growth 2.70 3.55 4.47 5.25

Operating & In

Construction 2.70 3.51 3.55 3.39

Table 2.3 shows the projections for total western Canadian

crude oil supply. Please refer to Appendices B.3 and B.4

for detailed data. In the Growth Case, light crude oil supply

is projected to grow from about 1.2 million b/d in 2010 to

1.5 million b/d in 2015 and eventually decline slightly by

2025. Heavy crude oil supply is projected to grow from

1.5 million b/d in 2010 to 2.0 million b/d in 2015 and to

3.8 million b/d in 2025.


Figure 2.5 Growth Case - Western Canada Oil Sands & Conventional Supply


* Oil Sands Heavy includes some volumes of upgraded heavy sour crude oil and bitumen blended with diluent or ugpraded crude oil.

0

1000

2000

3000

4000

5000

6000

20252023202120192017201520132011200920072005

Conventional Light

Oil Sands Heavy*

Upgraded Light

Conventional Heavy

0

1,000

2,000

3,000

4,000

5,000

June 2010 Forecast

6,000

ForecastActual

Note that the Upgraded Light crude oil supply includes the

light crude oil volumes produced from:

• Upgraders that process conventional heavy oil,

e.g., the Husky Upgrader at Lloydminster 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

• the Northwest Upgrader.

Compared to the 2010 forecast, the Upgraded Light

crude oil supply has been revised slightly downward. This

reflects the recent announcement that Suncor and Total

are cooperatively planing to build one shared upgrader for

production from two mining projects, instead of separate

upgraders. The Oil Sands Heavy category, is forecast to

increase from 1.2 million b/d in 2010 to 1.7 million b/d in

2015 and up to 3.6 million b/d in 2025. (Figure 2.5).

In the Operating & In Construction Case, with the increased

conventional production forecast, the overall decline in

production has been pushed back until 2019. (Figure 2.6).

The supply of Upgraded Light crude oil is forecast to grow

from 660,000 b/d in 2010 to 927,000 b/d in 2015 and

remain flat thereafter. Oil Sands Heavy is forecast to grow

from 1.1 million b/d in 2010 to 1.7 million b/d in 2015 and

increases to an average of 1.8 million b/d for the remainder

of the forecast period.

2.4 Methodology

CAPP did not survey conventional crude oil producers

but instead used our internal analysis that incorporated

historical trends, recent announcements and discussions

with provincial government representatives to derive the

forecast.

From the results of the survey of oil sands producers,

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 to meet pipeline

specifications;

b) Condensate is the preferred diluent over upgraded light

crude oil;

c) The Southern Lights Pipeline can deliver additional

diluent to western Canadian producers;

d) Railed imports could supplement a shortfall of

condensate that could be required by producers beyond

the capacity provided by Southern Lights and before an

expansion of the pipeline or other alternative is in place.

2.5 Crude Oil Production and

Supply Summary

Conventional production is significantly higher in this latest

forecast compared to the 2010 outlook. This is primarily

due to the expectation for continued strong oil prices

encouraging drilling and the use of horizontal drilling

techniques which has been increasing the productive

capacity of individual wells. A slight growth is forecast for

the next several years compared to earlier forecasts calling

for a steady decline in 2010 and beyond.

On the oil sands side, the forecast reflects an improved

performance trend for in situ projects and the inclusion

of some additional projects that were previously put on

hold. Most of the growth in oil sands production will be

blended with a diluent and transported to a market capable

of processing heavier crude oil types. Production from

Atlantic Canada is expected to increase in 2017 once the

Hebron Project is online.

0

1000

2000

3000

4000

5000

6000

20252023202120192017201520132011200920072005

Conventional Light

Oil Sands Heavy*

Upgraded Light

Conventional Heavy

* Oil Sands Heavy includes some volumes of upgraded heavy sour crude oil and bitumen blended with diluent or ugpraded crude oil.

0

1,000

2,000

3,000

4,000

5,000


June 2010 Forecast

6,000

ForecastActual

Figure 2.6 Operating & In Construction - Western Canada Oil Sands & Conventional Supply


3

Canada produces more crude oil than it can consume domestically. This section

provides an assessment of the crude oil markets that are accessible to exports

from Canada. The potential for further market penetration into existing markets

in the U.S. is examined as well as the prospects for expanding into new markets.

Each year, CAPP surveys refineries in Canada and the U.S. to determine their

current capability and future plans to process additional supplies from Canada

(Figure 3.1).

CRUDE OIL MARKETS

PADD II

PADD I

PADD V

PADD III

55 [+10]

119 [+380]

3,736

1,231 [+483]

2,731

Non-US25 [unknown]

205 [+64]

276 [+11]

Supply

2010 - 2,700

2015 - 3,549

1,312

8,996

393

PADD IV

237 [+8]

613

2011 Total Refining Capacity

2010 ActualDemand

2015 Potential

Additional Demand

552 [+82]

632

In 2010, available crude oil supply from western Canada

was 2.7 million b/d. Domestic demand for western Canadian

crude oil was 828,000 b/d and the remaining supply of over

1.9 million b/d or 69 per cent was exported (Figure 3.1).

Eastern PADD II (particularly, Illinois, Indiana, Michigan, Ohio

and Minnesota) is the largest market for western Canadian

crude oil. The other primary markets are currently: British

Columbia; Alberta; Saskatchewan; Ontario; PADD IV;

California and Washington in PADD V.

Figure 3.1 Market Demand for Western Canadian Crude Oil – Actual 2010 and 2015 Additional



3.1 Canada

Canadian refineries that have access to western

Canadian crude oil have a total refining capacity of over

one million b/d. In 2010, these refineries processed

about 828,300 b/d of western Canadian crude oil. This

is expected to increase to approximately 921,900 b/d by

2015 with planned refinery expansions.

3.1.1 Western Canada

There are eight refineries located in western Canada

with a total refining capacity of about 632,000 b/d.

These refineries process western Canadian crude oil

exclusively. In 2010, they received 551,800 b/d of crude

oil and this is expected to increase to 634,400 b/d in

2015 (Figure 3.2). The Moose Jaw asphalt plant in Moose

Jaw, Saskatchewan produces mostly asphalt while other

refineries manufacture a wide range of petroleum products.

Figure 3.2 Western Canada: Forecast Western

Canadian Crude Oil Receipts

Minor refinery operational and supply issues lowered

the amount of crude processed at Suncor’s refinery in

Edmonton in 2010. This refinery is configured to process

oil sands feed stock. Future additional western Canadian

crude oil receipts is related to expansion plans for the

Consumers’ Co-operatives refinery, located in Regina,

by the end of 2012 and the start up of CNRL’s Northwest

Upgrader.

3.1.2 Ontario

There are four refineries (excluding the Nova Chemical

refinery and petrochemical complex in Sarnia) located in

Ontario with a total refining capacity of 393,000 b/d. These

refineries process western Canadian crude oil as well as

foreign imported crude oil and Atlantic Canada production.

The supplies from the latter two sources arrive by tankers

and are then moved through the Portland-to-Montréal

Pipeline and, subsequently transported on the Enbridge

Montréal-to-Sarnia Pipeline (Line 9). Note that Ontario

refineries have, for a number of years, selected their

feedstock sources based on both availability and pricing.

According to Statistics Canada, Ontario refineries

received 362,700 b/d of crude oil in 2010 from the

following sources: Western Canada (276,500 b/d or

76 per cent); Eastern Canada (11,800 b/d or 3 per cent);

United Kingdom (23,700 b/d or 6 per cent); United States

(10,900 b/d or 3 per cent); and other foreign sources

(39,600 b/d or 11 per cent). Receipts of western Canadian

crude oil are projected to increase slightly during the

forecast period assuming that Enbridge’s current Line 9

reversal proposal proceeds. (Figure 3.3).

Figure 3.3 Ontario: Forecast Western Canadian Crude

Oil Receipts

3.1.3 Québec

Québec has two refineries with a combined capacity of

395,000 b/d. Suncor’s refinery in Montréal has a capacity

of 130,000 b/d and Ultramar’s refinery in Québec City has a

capacity of 265,000 b/d. The Montréal refinery can process

crude from both Atlantic Canada and foreign sources

received from the Portland-to-Montréal pipeline. If market

thousand barrels per dayTotal refining capacity = 632

0

100

200

300

400

500

600

700

Light Synthetic

Conventional Light Sweet

Conventional Medium SourHeavy

201520142013201220112010

Source: 2011 CAPP Re�nery Survey


0

50

100

150

200

250

300

350

400

Light Synthetic



201520142013201220112010



conditions permit, the reversal and use of Line 9 would

also enable this refinery to access western Canadian crude

oil supplies. Suncor has estimated that its refinery could

process between 20,000 b/d to 60,000 b/d of oil sands

feedstock.

3.2 United States

Based on a total refining capacity of almost 18 million b/d,

the United States is the world’s largest oil market. In 2010,

Canada was by far the largest exporter of crude oil to

the U.S., exporting almost double the volumes of each

of the next three largest exporting countries – Mexico,

Venezuela and Saudi Arabia. Canada exported almost

2.0 million b/d, which was equivalent to around 21 per cent

of total U.S. imports from foreign sources. Of this volume,

1.8 million b/d was sourced from western Canada

(Figure 3.1). The U.S. demand for western Canadian

oil supply is expected to reach 2.7 million b/d in 2015.

Although overall U.S. crude oil demand is not expected to

increase significantly, western Canadian crude oil should

supply a growing share of this market if the necessary

pipeline infrastructure is put in place to enable greater

access to major U.S. markets. Declines in imports from

other major suppliers to the U.S. is expected in the near

term due to a combination of falling production, increased

domestic consumption, or a focus on expansion into new

export markets such as Asia.

Figure 3.4 Petroleum Administration for Defense

Districts

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 remain the convention for describing U.S. oil market

regions.

3.2.1 PADD I (East Coast)

PADD I is located along the east coast of the United States.

There are 10 refineries in Georgia, New Jersey,

Pennsylvania, and West Virginia with a total refining

capacity of 1.2 million b/d. Refineries on the east coast are

more vulnerable to closures due to age, location and easy

access to refined petroleum products from refineries in

Europe and the Middle East. Of note, Sunoco shut down

its Eagle Point refinery in New Jersey in February 2010

while Western Refining closed the only refinery that was

located in Virginia in September 2010. This largely

accounted for the slightly lower overall volumes of crude oil

processed in PADD I in 2010 compared to 2009.

Figure 3.5 2010 PADD I: Foreign Sourced Supply by

Type and Domestic Crude Oil

In 2010, imports of foreign crude oil by refineries in PADD I

totaled over 1.1 million b/d and around 71 per cent of these

volumes were light crude (Figure 3.5). PADD I imported

202,500 b/d of crude oil from Canada. About 54,600 b/d

was sourced from western Canada and was primarily

delivered by pipeline to United’s refinery in Warren,

Pennsylvania. Deliveries of western Canadian crude oil into

this market are expected to remain flat through to 2015.

Domestic crude

Light Sweet*

Light/Medium

Sour

Heavy

thousand barrels per dayTotal refining capacity = 1,312

126

194

776

22

* Includes small volumes of Medium Sweet

Source: EIA

PADD II:

Midwest

PADD I:

East Coast

PADD IV:

RockiesPADD V:

West Coast,

AK, HI

PADD III:

Gulf Coast

AL

AK

AZ

AR

CACO

CT

DE

GA

ID

IL IN

IA

KSKY

LA

ME

MD

MA

MI

MN

MS

MO

MT

NE

NV

NH

NJ

NM

NY

ND

OH

OK

OR

PA

SD

TN

TX

UT

VT

VA

WA

WV

WI

HI

SC

NC

FL

RIWY


3.2.2 PADD II (Midwest)

PADD II has a total refining capacity of 3.7 million b/d and

in 2010, received almost 1.4 million b/d of foreign sourced

crude oil, over 60 per cent of which were heavy crude

oil volumes. (Figure 3.6). Crude oil from western Canada

totaled over 1.2 million b/d, making Canada the primary

supply source.

Figure 3.6 2010 PADD II: Foreign Sourced Supply by


PADD II can be further divided into the Northern, Eastern,

and Southern PADD II states. The primary market hubs

within PADD II are Clearbrook, Minnesota (Northern PADD

II states), Wood River – Patoka, Illinois (Eastern PADD II

states), and Cushing, Oklahoma (Southern PADD II states),

and will be discussed in the following subsections.

The Midwest region is currently Canada’s largest market

due to its close proximity, large size and established

pipeline network. In the past there was very little need for

pipeline infrastructure to export oil beyond this market

due to the large refining capacity within the region. This

situation has changed with both the increase in local

production and the increasing imports of crude oil from

western Canada, resulting in supplies exceeding the

region’s crude oil processing capacity. There are plans for

some refineries to upgrade and increase their capacity for

refining heavy crude oil in the near future but the growth in

supplies of heavy western Canadian crude oil is expected

to exceed the additional volumes that could be processed

at refineries in this market. In addition, there is a growing

build up of light crude oil inventory as domestic production

increases as well as the expectation of increased Canadian

exports into the region with the recent startup of the

Keystone Pipeline.

Northern PADD II

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 487,000 b/d. In 2010, foreign imports into

northern PADD II were 279,800 b/d , all sourced from

western Canada. Imports of western Canadian crude oil are

expected to grow to 348,600 b/d by 2015. (Figure 3.7).

There is ample pipeline capacity through the Minnesota

Pipeline system to enable Minnesota refineries to be

exclusively supplied by western Canadian crude oil if market

conditions align.

Figure 3.7 PADD II (North): Forecast Western Canadian

Crude Oil Receipts

Domestic Crude

Light

Sweet*

Light/

Medium Sour

Heavy


830

208

1,915

329


Source: EIA


0

50

100

150

200

250

300

350

400

450

500

Light Synthetic

Conventional Light SweetConventional Medium SourHeavy

201520142013201220112010



Eastern PADD II

Eastern PADD II consists of Michigan, Illinois, Indiana,

Kentucky, Tennessee and Ohio and has 13 refineries

with a total refining capacity of 2.4 million b/d. In 2010,

western Canadian crude oil accounted for 874,500 b/d or

85 per cent of the total foreign imports into the region.

There are several refining expansion projects that will

be starting up in the next few years that are designed to

process heavy crude oil sourced primarily from western

Canada. (Figure 3.8). Table 3.1 summarizes the projects

designed to process additional volumes of Canadian crude

oil.

Figure 3.8 PADD II (East): Forecast Western Canadian

Crude Oil Receipts

Southern PADD II

Southern PADD II has seven refineries located in Kansas

and Oklahoma with a total refining capacity of 807,000 b/d.

Cushing, Oklahoma is a hub that receives crude oil

predominantly from pipelines transporting offshore crude

oil delivered by tanker to the U.S. Gulf Coast. This crude oil

is then distributed by a number of pipelines exiting the hub

which serve refineries throughout the PADD II and PADD III

regions. Thus with the recent startup of the Cushing

Extension phase of the Keystone pipeline, western

Canadian oil producers now have ample access to the

Cushing hub and the associated pipeline network in the

region.

In 2010, refineries in this market received 79,900 b/d of

western Canadian crude oil (Figure 3.9).

Figure 3.9 PADD II (South): Forecast Western

Canadian Crude Oil Receipts


0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Light Synthetic

Conventional Light SweetConventional Medium SourHeavy

201520142013201220112010



0

20

40

60

80

100

120

140

160

180

200

Light Synthetic



201520142013201220112010


Table 3.1 Summary of Major Announced Refinery Upgrades in Eastern PADD II

Operator Location

Current Capacity

(thousand b/d)

Scheduled

In-Service Description

WRB Refining Roxana, IL 306 2011 Add a 65,000 b/d coker; increase total crude

oil refining capacity by 50,000 b/d; increase

heavy oil refining capacity to 240,000 b/d

BP Whiting, IN 400 Late 2012 to mid

2013

Construction of new coker and a new crude

distillation unit

Marathon Detroit, MI 102 Mid 2012 Increase heavy oil processing capacity by

80,000 b/d and increase total crude oil refining

capacity to 115,000 b/d


3.2.3 PADD III (Gulf Coast)

PADD III is comprised of Alabama, Arkansas, Louisiana,

Mississippi, New Mexico and Texas. The 50 refineries in

this market have a total refining capacity of 8.9 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 2010, PADD III imported 5.3 million b/d of crude oil from

foreign sources, of which 2.4 million was heavy crude oil.

(Figure 3.1). The top five sources of these imports are as

follows: Mexico (21 per cent), Venezuela (16 per cent),

Saudi Arabia (14 per cent), Nigeria (11 per cent), and

Columbia (5 per cent). Deliveries of western Canadian

crude oil to this market totaled 119,100 b/d, of which

96,800 b/d was transported through Exxon Mobil’s

Pegasus Pipeline, which was utilized at capacity and is

currently the only pipeline access for Canadian crude oil.

In addition, approximately 22,300 b/d was shipped off the

Westridge dock in Burnaby, British Columbia and arrived

via tanker. About 14,200 b/d of light sweet crude oil was

also imported from Atlantic Canada by tanker.

Mexico remains the largest heavy crude oil supplier

to the U.S. Gulf Coast despite a five-year decrease in

production. Exports are expected to be reduced by at

least 110,000 b/d once a long-delayed expansion of the

Minatitlan refinery in Mexico is completed in mid-2011. The

cutback will reduce Mexican exports to its lowest level in

15 years.

According to the Oil and Gas Journal, Venezuela has

211 billion barrels of proven oil reserves as of 2011,

which represents a significant upward revision making

Venezuela’s reserves the second largest in the world. This

recent update results from the official recognition of the

huge reserves of extra heavy oil in Venezuela’s Orinoco

belt. In 2009, Venezuela signed bilateral agreements

to develop four major blocks in the Junin area starting

in 2012 and extending to 2014 which would increase

total production capacity by 1.2 million b/d. In 2010,

Venezuela awarded two more development licenses in the

Carabobo region scheduled to start in 2014 that would

add another 800,000 b/d of productive capacity. However,

considerable uncertainty surrounds future production from

the Orinoco region given recent regulatory and operational

uncertainties.

In recent years, Venezuela’s oil production has been

declining due to the natural decline at older fields,

maintenance issues and compliance with OPEC production

cuts. As domestic consumption continues to rise, the

result is a decline in net exports. Venezuela has also

been diversifying its export destinations away from the

U.S. market. One of the fastest growing destinations for

Venezuelan crude oil exports has been China.

Despite the expected decline in exports from Mexico and

Venezuela, Canadian heavy producers are prevented from

increasing their market share on the Gulf Coast due to

infrastructure constraints. In 2015, CAPP has estimated

that this market could receive at least 380,000 b/d

of western Canadian crude oil based on contractual

commitments on the Keystone XL pipeline if this pipeline

receives its U.S. regulatory approvals. A number of other

pipeline projects are also being proposed to transport the

current glut of domestic U.S. and Canadian light crude oil

in PADD II to the PADD III refinery market.

Figure 3.10 2010 PADD III: Foreign Sourced Supply

by Type and Domestic Crude Oil

Table 3.2 summarizes the major refinery upgrades

completed over the last year and future upgrades

announced for the region.

Domestic

Crude

Light Sweet*

Light/Medium

Sour

Heavy


2,399

1,223

2,138

1,671


Source: EIA


3.2.4 PADD IV (Rockies)

PADD IV includes the states of Idaho, Montana, Wyoming,

Utah, and Colorado. It has 14 refineries located in four of

the five states (there are no refineries in Idaho), and has a

total refining capacity of 613,200 b/d. Although PADD IV is

smaller than the other core markets, it has been a stable

market and foreign imports are supplied exclusively from

western Canada.

In 2010, PADD IV processed 236,600 b/d of Canadian

crude oil or about 44 per cent 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 forecast to remain relatively

flat (Figure 3.11).

Figure 3.11 PADD IV: Forecast Western Canadian

Crude Oil Receipts

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. It 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 a large portion of its requirements

(Figure 3.12).

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.

Figure 3.12 2010 PADD V: Foreign Sourced Supply by



0

100

200

300

400

500

600

Light Sweet*

Light/Medium Sour

Heavy

201520142013201220112010

*Includes small volumes of Medium Sweet


Domestic

Alaska

Other

DomesticLight

Sweet*

Light/Medium

Sour

Heavy


530

593

639

207


Source: EIA

383

Table 3.2 Summary of Major Announced Refinery Upgrades in PADD III

Operator Location

Current Capacity

(thousand b/d)

Scheduled

In-Service Description

Hunt Refining Tuscaloosa, AL 72 Dec 2010 Increased capacity from 52,000 b/d to

72,000 b/d. Delayed coker was expanded to

double in size to 32,000 b/d.

Total Port Arthur, TX 232 Mar 2011 Increased capacity from 175,000 b/d to

232,000 b/d. Project included a 50,000 b/d

coker; a 55,000 b/d vacuum distillation unit and a

64,000 b/d distillate hydrotreater.

Motiva

Enterprises

Port Arthur, TX 285 2012 Increase capacity by 325,000 b/d to over

600,000 b/d.

Valero McKee, TX 170 2014 Increase capacity by 25,000 b/d. Expansion will

process WTI and locally produced crude oil.


Washington

There are five refineries in Washington that have a

combined capacity of 638,000 b/d. Alaska is still the

primary source of feedstock for these refineries, however,

Alaskan production continues to decline. As a result, these

refineries are becoming increasingly dependent on imports

from Canada and other countries. In 2010, these refineries

imported 216,600 b/d of crude oil from foreign sources.

The top three foreign sources were Canada (65 per cent),

Angola (16 per cent) and Saudi Arabia (7 per cent).

In 2010, receipts of western Canadian crude were

151,800 b/d. These receipts are expected to increase

slightly in 2011 and remain flat afterwards. Note that 2010

receipts were lower than normally expected due to refinery

operational issues during the year (Figure 3.13). Given the

small size of this niche market, further development of this

market is limited.

Figure 3.13 Washington: Forecast Western Canadian

Crude Oil Receipts

California

California has 17 refineries with a total refining capacity of

2.1 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 per cent of

the refining capacity in the state. Partly because California

has the strictest environmental requirements in the United

States for refined petroleum products, these refineries are

among the most sophisticated in the world. 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.

Although Californian refineries receive the majority of their

supplies from California and Alaska, in 2010, 781,200 b/d

of crude oil was imported from foreign sources.

(Figure 3.14) The top three exporting countries were Saudi

Arabia (24 per cent); Ecuador (21 per cent); and Iraq

(20 per cent). Canada only accounted for seven per cent of

the foreign imports.

Production from Alaska has been declining annually since

2003. In 2010 production decreased seven per cent from

2009. The downward trend in production from both

California and Alaska is expected to continue, therefore,

California refineries will need to replace their domestic

crude oil sources with more imports.

Figure 3.14 2010 PADD V (California): Foreign Sourced

Supply by Type and Domestic Crude Oil

3.3 Asia

Asia is the second largest oil market after North America.

Of note, China is the second largest consumer of oil after

the United Sates and its economic growth rates are

expected to be very strong compared to other countries.

Table 3.3 shows oil demand from 2008 to 2011 in the major

Asian countries. The International Energy Agency (IEA)

forecasts that oil demand from China will grow by

six per cent in 2011 with continued strong growth

anticipated in the longer term. In 2010, there were

increased exports to Asia.


0

100

200

300

400

500

600

Light Synthetic



201520142013201220112010

*Includes small volumes of Medium Sweet


Total refining capacity = 2,093

339

422

20

634

237

Light/MediumSour

Heavy

Light Sweet*

Other Domestic

Domestic -Alaska



Source: EIA and the California Energy Commission


However, there is currently limited pipeline capacity

available for the transportation of western Canadian crude

oil to the west coast. The earliest that Canadian crude oil

producers would be able to increase their market share in

Asia is in 2016, if a new pipeline project is approved.

Table 3.3 Total Oil Demand in Major Asian Countries

million b/d 2008 2009 2010 2011

China 7.75 8.37 9.38 9.97

India 3.09 3.26 3.34 3.44

Japan 4.79 4.37 4.42 4.45

Korea 2.14 2.18 2.25 2.26

Source: IEA Oil Market Report, May 2011

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.

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° 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

The United States remains the primary export market for

western Canadian crude oil supplies due to its strong

demand, geographic proximity and established pipeline

infrastructure. Several key facts suggest that growing

supplies of crude oil from western Canada could find a

market on the U.S. Gulf Coast or world markets once they

reach Canada’s west coast, including California and Asia.

With the recent startup of the Keystone Pipeline to Patoka,

Illinois, followed by the extension of this pipeline into

Cushing, Oklahoma, crude oil supplies from western

Canada into the PADD II market are expected to grow. In

the meantime, western Canadian crude oil producers have

growing supplies and need to access new markets for this

supply. Producers currently have limited transportation

options to serve alternative markets in the U.S. Gulf Coast,

which is world’s largest refining market and over half of the

existing capacity can process heavy crude oil. Refineries

in this market are looking to replace declining supplies

historically coming from Mexico and Venezuela.

Demand in California could increase since these refineries

get the majority of their crude oil supplies from California

and Alaska and production from these states has been

steadily declining. The Asian market is expected to grow

substantially and access to these markets is an important

part of achieving market diversity. This, along with growth

in other parts of Asia and India, will increase world crude

oil demand, which in a global context, will enhance the

importance of Canadian supplies.


Pipelines are an efficient method of transporting large volumes of crude oil over

land. Recent decreased pipeline capacity connected to key markets proved that

pipeline constraints have a severe impact on the netbacks realized by Canadian

producers. Some excess pipeline capacity is essential for industry to manage in

times of pipeline maintenance or to ensure flexibility to accommodate new market

developments. As crude oil production in western Canada continues to grow, the

petroleum industry recognizes the need for new pipeline capacity to both existing

and new markets. This chapter reports on the status of and demand for crude oil

pipelines into markets in the U.S. and world markets, including Asia, that can be

accessed once Canadian supplies reach the west coast.

4 CRUDE OIL PIPELINES

Figure 4.1 Canadian and U.S. Crude Oil Pipelines - All Proposals

Portland

Montréal

Sarnia

Chicago

Cushing

St. Paul

Salt Lake City

Houston

Edmonton

Anacortes

Burnaby


& Cushing Extension


TransMountain

BP

Enbridge

Mid

Valle

y

Cap

lin

e

Flanagan

Hardisty

Centurion Pipeline

Express

Platte

Enbridge (North Dakota) Expansion

Spearhead SouthSpearhead North

Superior

WoodRiver

ExxonMobil Pegasus

Clearbrook

Guernsey

TransCanada

Keystone XL

Kinder Morgan

TMX2 Expansion

TMX3 Expansion

Kitimat Enbridge GatewayKinder Morgan

TMX Northern Leg

Port Arthur

Mustang

Patoka

Canadian and U.S. Oil Pipelines

Enbridge Pipelines, Alberta Clipper

and connections to the U.S. Midwest

Kinder Morgan Express

Kinder Morgan Trans Mountain


Proposed pipelines to the West Coast

Existing / Proposed pipelines to PADD III

Expansion to existing pipeline

1 - Enterprise/ETP Cushing-Gulf

2 - Enbridge Monarch

3 - Keystone Cushing MarketLink

Enbridge Line 9

Reversal

Lima

TransCanada

Keystone East


The existing pipeline network provides access to the

primary markets for western Canadian crude oil which

include: western Canadian refineries; Ontario, the

U.S. Midwest; PADD IV; and the West Coast. There is

very limited access to the U.S. Gulf Coast. The major

pipeline proposals currently being assessed are primarily

expansions into the U.S. Gulf Coast and for exports off

Canada’s west coast. Figure 4.1 shows all existing and

approved pipelines to date.

4.1 Existing Crude Oil Pipelines Exiting Western Canada

There are five major pipelines that are directly connected

to the Canadian supply hubs at Edmonton and Hardisty,

Alberta – Enbridge Mainline, Enbridge Alberta Clipper,

Kinder Morgan Trans Mountain, Kinder Morgan Express,

and the TransCanada Keystone pipeline. Cumulatively,

these pipelines provide a total pipeline capacity out of

western Canada of 3.5 million b/d (Table 4.1). Although

this capacity is currently constrained somewhat by the

available takeaway capacity of connecting downstream

pipelines, there will be excess capacity out of this region

until 2015, based on CAPP’s forecasted growth in western

Canadian crude oil supplies.

Table 4.1 Capacity of Major Crude Oil Pipelines

Exiting the WCSB

Pipeline Crude Type

Annual

Capacity

(thousand b/d)

EnbridgeLight 1,069

Heavy 796

Express Light/heavy (35/65) 280

Trans Mountain Light/heavy (80/20) 300

Alberta Clipper Heavy 450

Keystone Light/heavy (25/75) 591

Total Capacity 3,486

Enbridge Pipelines

The Enbridge system delivers crude oil and other refined

projects from western Canada to markets in western

Canada, the U.S. Midwest and Ontario. It also receives

crude oil from U.S. pipelines in the upper Midwest for

delivery to markets in the U.S. Midwest and Ontario.

Further downstream, it connects to various pipelines in the

U.S. such as the Minnesota Pipeline and the Spearhead

Pipeline, the latter providing access to the Cushing,

Oklahoma pipeline and storage hub.

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. The North Dakota

System Expansion Phase 6, which expanded capacity of

the system by 51,600 b/d, was completed and placed into

service on January 1, 2010 and increased capacity of the

system to 185,000 b/d.

The Bakken Expansion program is designed to

accommodate for the future increases in crude oil

production from the Bakken and Three Forks formations.

The initial program includes the Portal Link Reversal project

in phase 1, which will increase capacity of the North

Dakota system by 25,000 b/d, once operational in early

2011. This involves the reactivation and flow reversal of

an existing pipeline between Berthold, North Dakota and

Enbridge’s Steelman terminal in Saskatchewan.

The second phase would add another 120,000 b/d of

capacity that would transport the crude oil north into

Enbridge’s Saskatchewan System and then on to the

Enbridge Mainline system, at the Cromer, Manitoba

terminal. This phase could be operational by late 2012.

Total incremental capacity from both phases would be

145,000 b/d while the ultimate expansion capacity of

this program is up to 325,000 b/d with modifications and

additional facilities.

Downstream of Superior, Wisconsin, Enbridge has a

capacity of 1.88 million b/d including 400,000 b/d of

capacity added in 2009 with the startup of the Southern

Access pipeline, which terminates at Flanagan, Illinois.

The full capacity of Southern Access is not currently used

because Spearhead South and Spearhead North provide

the only connection to the pipeline and the combined

capacity of these pipelines is only 320,000 b/d.



The Alberta Clipper pipeline is a pipeline extending from

Hardisty, Alberta to Superior, Wisconsin and essentially

functions as an expansion to Enbridge’s mainline system.

This pipeline started operating in 2010 and has a capacity

of 450,000 b/d, which can be further expanded to

800,000 b/d.

Kinder Morgan Trans Mountain Pipeline

The Trans Mountain system originates in Edmonton,

Alberta and transports crude oil and petroleum products to

delivery points in British Columbia, including the Westridge

dock for offshore exports, and to a pipeline that provides

deliveries to refineries in Washington State.

Trans Mountain is currently operating as a common carrier

pipeline where shippers nominate for space on the pipeline

without a contract. Since May 2010, the pipeline has been

in steady apportionment. Excess demand for this space

is expected to continue until there is additional capacity

available to transport crude oil to the west coast for export.

The available pipeline capacity depends on the amount of

heavy crude oil transported. In 2010, about 27 per cent of

the volumes shipped were heavy crude oil.

Of the current pipeline capacity of 300,000 b/d (assuming

20 per cent of the volumes being transported are heavy

crude oil), 248,000 b/d is allocated to refinery and terminal

locations in British Columbia and Washington State and

52,000 b/d is allocated to Westridge dock shippers. In

November 2010, Kinder Morgan filed an application with

the National Energy Board (NEB) proposing to change the

allocation to 221,000 b/d to land locations and 79,000 b/d

to the Westridge dock, of which 54,000 b/d would be

underpinned by firm contracts. The NEB has scheduled

an oral public hearing on this application to commence on

August 22, 2011.

Kinder Morgan Express-Platte Pipelines

The Express Pipeline system is a batch-mode, common

carrier pipeline system comprised of the Express Pipeline

and the Platte Pipeline that connects Canadian and U.S.

crude oil producers to refineries in PADD IV and the U.S.

Midwest. The Express Pipeline is a 24-inch diameter

pipeline with a capacity of 280,000 b/d that originates at

Hardisty, Alberta and terminates at the Casper, Wyoming

facilities on the Platte Pipeline. The Platte Pipeline is a 20-

inch diameter pipeline that runs from Casper, Wyoming to

refineries and interconnecting pipelines in the Wood River,

Illinois area. The Platte Pipeline has a current capacity

of 150,000 b/d downstream of Casper, Wyoming and

approximately 140,000 b/d downstream of Guernsey,

Wyoming.

Express does not operate at capacity due to the lower

available capacity on Platte, which limits the takeaway

capacity on Express for Canadian crude oil. In recent

years, increased U.S. domestic production from the

Bakken shale formation has been competing for the limited

capacity on the Platte pipeline. In 2010, Express receipts at

Hardisty averaged 200,000 b/d.

TransCanada Keystone and Cushing

Extension

In June 2010, TransCanada began operating the first

phase of the Keystone pipeline system, which ran

from Hardisty, Alberta to terminals in Wood River and

Patoka, Illinois. Subsequently in February 2011, the

Keystone Cushing Extension, which runs from Steele City,

Nebraska to Cushing, Oklahoma went into service. The

system can deliver a combined capacity of 591,000 b/d.

Average throughputs in the fourth quarter of 2010 were

186,000 b/d.

4.2 Oil Pipelines to the U.S.

Midwest

The U. S. Midwest is the largest market for western

Canadian crude oil. The major market hubs in the U.S.

Midwest from which oil is further distributed are found at

Wood River/Patoka in Illinois and at Cushing, Oklahoma.

Table 4.3 summarizes the crude oil pipelines delivering

crude to the Midwest.

Each refinery centre in the region has connected pipeline

capacity to Canadian crude oil in excess of the refining

capacity in the area. In addition, with the recent start up

of the Keystone Pipeline in 2010, there is an oversupply

of crude oil flowing into the region, most notably at

the Cushing hub, with no further crude oil pipeline

infrastructure to transport either excess western Canadian

crude volumes or domestic U.S. production to other

more distant markets. A number of pipeline proposal

projects have been designed to address this issue and are

discussed in the following section, entitled Oil Pipelines to

the U.S. Gulf Coast.


Minnesota Pipeline System

The Minnesota Pipeline system is connected to the

Enbridge system at Clearbrook, Minnesota, which enables

it to deliver crude oil from Canada to Northern Tier’s

refinery in St. Paul Park and the Flint Hills refinery in

Rosemont. This is the primary route for Canadian crude

destined for the Minnesota refineries. The system has a

capacity 465,000 b/d from two pipelines running along the

same route. One of the pipelines can be further expanded

from 165,000 b/d to 350,000 b/d if needed.

Koch Wood River Pipeline

The Minnesota refineries are also connected to western

Canadian crude oil supplies via one other route to the

Enbridge system. This is the Wood River Pipeline that

delivers western Canadian crude oil that arrives at the

Wood River hub via the Express system.

Spearhead Pipeline

The Spearhead South Pipeline and Spearhead North

Pipeline provide the only connections to Enbridge’s

Southern Access pipeline at Flanagan, Illinois. Spearhead

South has a capacity of 190,000 b/d and delivers light

and heavy crude oil from Canada to Cushing, Oklahoma.

Spearhead North has a capacity of 130,000 b/d and

delivers heavy crude oil to the Chicago area. Refineries in

the Chicago area could access additional crude supplies

that reach the Wood River / Patoka hub through the Chicap

Pipeline, which has a capacity of 360,000 b/d.

4.3 Oil Pipelines to the U.S. Gulf

Coast

The Gulf Coast is the largest refining region in the U.S.

with the capacity to process a wide range of both light and

heavy crude oil types. Currently, Western Canadian crude

oil producers only have 96,000 b/d of pipeline capacity

connected to refineries in the Gulf Coast although tanker

shipments originating off the Trans Mountain Westridge

dock can also be delivered. There are a number of pipeline

projects to the Gulf Coast currently being proposed

that are targeted to be in service around 2013. These

projects are designed to alleviate the current market

access constraints on producers. In the meantime, rail

transportation of crude oil out of the Midwest is increasing.

ExxonMobil Pegasus Pipeline

ExxonMobil’s Pegasus Pipeline is currently western

Canadian producers’ only pipeline connection to refineries

in the U.S. Gulf Coast. Pegasus Pipeline receives crude oil

at Patoka, Illinois and delivers to Nederland, Texas.

Canadian crude oil, primarily heavy sour crude oil,

originating from Hardisty, Alberta arrives either through

1) the Enbridge system followed by a connection on the

Mustang Pipeline, which has a capacity of 100,000 b/d

or;

2) the Express/Platte system to Wood River, Illinois

followed by a connection on the WoodPat Pipeline,

which has a capacity of 250,000 b/d or;

3) the Keystone Pipeline.

Enterprise/ETP Cushing-Gulf Pipeline

Proposal

Enterprise Products Partners and Energy Transfer Partners

have formed a joint venture to build a 400,000 b/d crude oil

pipeline that would originate at Cushing, Oklahoma and

extend to Houston, Texas. Approximately 40 per cent of

this proposed pipeline project would utilize existing

facilities and could begin operations in the fourth quarter of

2012 depending on regulatory approval and firm

commitments from shippers. This pipeline could transport

both light and heavy crude and could be expanded. The

pipeline would help move increasing supplies of U.S.

domestic light crude oil expected from the Bakken crude

oil producing regions in the Williston Basin or heavy crude

oil from western Canada.

Table 4.2 Summary of Crude Oil Pipelines to the U.S. Midwest

Pipeline Originating Point End Point Status Capacity

(thousand b/d)

Kinder Morgan Express-Platte Guernsey, WY Wood River, IL Operating 145

Enbridge Spearhead Flanagan, IL Cushing, OK Operating 190

ExxonMobil Mustang Lockport, IL Patoka, IL Operating 91

TransCanada Keystone Hardisty, AB Patoka, IL Operating 435

TransCanada Keystone Extension KS/NE border Cushing, OK Operating 155


Houston to El Paso Pipeline Reversal

Magellan Midstream Partners is continuing to evaluate the

reversal and conversion of its Houston to El Paso pipeline

in Texas, to crude oil service. Specifically, the project

entails the reversal of the pipeline segment from Crane,

Texas to Houston. The 18-inch diameter pipeline currently

transports refined petroleum products and would have a

capacity of 200,000 b/d if put in crude oil service. Nearby

pipeline infrastructure could still transport 60,000 b/d of

refined products to the El Paso market.

West Permian crude oil competes with Canadian light and

medium crude oil. With the recent start up of the Keystone

Cushing Extension pipeline, more Canadian crude oil has

been flowing into the US Midwest market, resulting in

record inventory levels. With this project, crude oil from the

Permian Basin of West Texas could be diverted to the Gulf

Coast instead of the Cushing market where it would

otherwise be destined. The pipeline could be operational

by the end of 2012 or mid-2013, pending regulatory

approvals.

Enbridge Monarch Pipeline

The Monarch Pipeline project would be a new 24-inch

diameter pipeline that would transport light crude oil from

Cushing, Oklahoma to a terminal north of Houston, Texas.

This pipeline would have a capacity of 350,000 b/d and has

a target in-service date of Q4 2013.

TransCanada Keystone XL and Louisiana

Access options

If U.S. regulatory approvals are obtained, Keystone XL

would transport crude oil from western Canada and

domestic U.S. crude from the Bakken to the Gulf Coast

and thus reduce congestion at Cushing, Oklahoma.

TransCanada concluded a successful open season that

obtained firm contracts of 65,000 b/d for its Bakken

Marketlink from Baker, Montana, to Cushing, Oklahoma

using capacity on the northern leg of Keystone XL.

The Cushing to Gulf Coast (Port Arthur, Texas) section,

dubbed the Cushing Marketlink Project, is scheduled for

in service in the first quarter of 2013, slightly ahead of the

full project, with an initial capacity of 150,000 b/d. The

total capacity of Keystone XL is 700,000 b/d, of which

380,000 b/d has been secured by long-term contracts.

Keystone XL could be further expanded if needed.

Other options for expanded access are also being

discussed that could be in place by 2014, including a

lateral to Houston and Texas City refineries. Access to

Louisiana refineries is possible by using existing facilities

from Patoka, Illinois to New Orleans or building a new line

from Port Arthur, Texas to New Orleans, Louisiana.

Table 4.3 Summary of Crude Oil Pipelines to the U.S. Gulf Coast


(thousand b/d)

ExxonMobil Pegasus Patoka, IL Nederland, TX Operating 96

Enterprise/ETP Cushing-Gulf Cushing, OK Houston, TX Proposed - for 2013 400

Enbridge Monarch Cushing, OK Houston, TX Proposed - for 2013 350

TransCanada Keystone XL

Keystone Cushing MarketLink

Hardisty, AB

Cushing, OK

U.S. Gulf Coast

Port Arthur, TX

Approved - for 2013

Approved - possibly Q1 2013

700

150

TransCanada Louisiana Access

Option #1

Patoka, IL New Orleans, LA Proposed - for 2014

TransCanada Louisiana Access

Option #2

Port Arthur, TX New Orleans, LA Proposed - for 2014


4.4 Oil Pipelines to the West

Coast

Kinder Morgan’s Trans Mountain Pipeline is currently

the only pipeline route to markets off the west coast.

(Figure 4.2). There is strong interest from Canadian

producers to increase access to the west coast to serve

markets in California and Asia. Currently both Kinder

Morgan and Enbridge have pipeline projects that could

meet this demand.

Kinder Morgan TMX2, TMX3 and

Northern Leg Expansion

The TMX2 expansion could increase capacity by 80,000 b/d

by 2016, if there is sufficient market commitment by

2012. TMX 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

240,000 b/d to 400,000 b/d of capacity depending on

market demand.

Enbridge Northern Gateway

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. This batch

pipeline is designed to provide 525,000 b/d of crude oil

export capacity, which could be expanded to an ultimate

capacity of 850,000 b/d. Crude oil would be loaded

on tankers for delivery to PADD V and Asia. Enbridge

submitted an application to the National Energy Board

(NEB) at the end of May 2010. The NEB has scheduled a

hearing on the project for January 2012.

4.5 Other Proposals

Enbridge Line 9 Reversal

Enbridge’s Line 9 Pipeline, which extends from Montréal,

Québec to Sarnia, Ontario has been flowing in westbound

service since the late 1990s. Enbridge is proposing to

reverse the portion of the line between Sarnia and Westover,

Ontario to flow in a west to east direction. This would

provide incremental western Canadian crude oil access

to the Ontario market and is targeted to be in service by

the second quarter of 2012. The current capacity of the

pipeline is 240,000 b/d. Once reversed, about 50,000 b/d is

expected to flow through the pipeline to Westover. Phase II

reversal to Montreal may be developed at a later date if and

when market conditions dictate.

Keystone East Options

TransCanada is proposing to extend its Keystone Pipeline

System from Patoka, Illinois to delivery points in Lima, Ohio;

Toledo, Ohio and Detroit, Michigan. This extension would

have a capacity of 300,000 b/d and could in-service by

2017.

Railway Transport

Although pipelines transport almost all of the crude oil

produced in western Canada to markets, both Canadian

National Railway (CN) and Canadian Pacific Railway (CP)

are using their railway networks to ship crude oil. CN has

shipped bitumen to California; heavy oil to Chicago, Illinois

and Detroit, Michigan; and Bakken crude oil to the U.S.

Gulf Coast. Rail does not have the same reach access into

production fields as pipe and rail cars are typically loaded

and unloaded by truck. However, rail transport does not

require long term commitments and provides options when

pipeline constraints exist.

Table 4.4 Summary of Crude Oil Pipelines to the West Coast


(thousand b/d)

Enbridge Northern Gateway Bruderheim, AB Kitimat, BC Proposed 525

Kinder Morgan TMX2 Edmonton, AB Kamloops, BC Proposed 80

Kinder Morgan TMX3 Kamloops, BC Sumas, BC Proposed 240-300

Kinder Morgan TMX Northern Leg Rearguard/Edmonton, AB

Kitimat, BC Proposed 400


For CN, the Bakken trade alone is now filling 250 to 300 rail

cars a month; altogether, the company is moving roughly a

unit train worth of crude oil per week. A unit train typically

consists of 80 to 150 cars; each car can hold 550 barrels,

which translates into 10,000 b/d. CP moves 80 car unit

trains every week out of the U.S. Bakken.

4.6 Diluent Pipelines

The diluent pipeline proposals address the potential

demand by western Canadian heavy crude oil producers

for additional diluent supply needed to transport growing

volumes of bitumen production at the same time as local

Canadian pentanes plus and condensate supplies decline.

Enbridge Southern Lights

The Southern Lights pipeline project includes a new diluent

line which flows from Flanagan, Illinois (near Chicago) to

Clearbrook, Minnesota, and the reversal of Enbridge’s

existing Line 13 from Clearbrook to Edmonton, Alberta.

The initial capacity of the diluent import line is

180,000 b/d, of which 77,000 b/d is for committed

shippers. It can be expanded to 330,000 b/d with minor

looping and to over 400,000 b/d with full looping. The

pipeline has been in service since July 2010.

Enbridge Northern Gateway Diluent

As part of its Northern Gateway crude oil pipeline project,

Enbridge is proposing a 193,000 b/d diluent import

pipeline that would extend from Kitimat, British Columbia

to Edmonton, Alberta. The National Energy Board has

scheduled a hearing on this project for January 2012.

4.7 Pipeline Summary

The Keystone Pipeline and the Cushing Extension, provides

591,000 b/d of new pipeline capacity exiting the western

Canada and connecting supplies to market hubs in Illinois

and Oklahoma. These pipelines provide ample capacity to

traditional U.S. Midwest markets. With the forecast of growing

supplies, the industry is: strategically looking to expand

its access to markets; focused on addressing the need

for more capacity into the U.S. Gulf Coast; and increasing

capacity pipeline capacity to the west coast. A number of

pipeline projects are being proposed to provide both the

market access and additional capacity that will be needed by

Canadian producers in the future.

There are a number of new pipeline proposals from Cushing,

Oklahoma to the Gulf Coast being proposed that would

provide an outlet for the current oversupply of Canadian and

U.S. crude that has been building in PADD II. There are also

pipeline proposals to expand export capacity to the west

coast to provide access to new markets with strong growth

potential.

Table 4.5 Summary of Diluent Pipelines


(thousand b/d)

Enbridge Southern Lights Flanagan, IL Edmonton, AB Operating since July 2010

180

Enbridge Northern Gateway Kitimat, BC Edmonton, AB Proposed 193


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.

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 A combined mining and upgrading operation where oil sands are mined from open pits.

project 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 by drilling.

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.

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.

Oil Sands Heavy In this report, Oil Sands Heavy includes upgraded heavy sour crude oil, and bitumen to which

light oil fractions (i.e. diluent or upgraded crude oil) have been added in order to reduce its

viscosity and density to meet pipeline specifications.

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 End products in the refining process (e.g. gasoline).

Products

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.


APPENDIX A ACRONYMS, ABBREVIATIONS,

UNITS AND CONVERSION FACTORS

Acronyms

API American Petroleum Institute

CAPP Canadian Association of Petroleum Producers

CSS Cyclic Steam Stimulation

DRA Drag Reducing Agent

EIA Energy Information Administration

ERCB (Alberta) Energy & Resources Conservation Board

IEA International Energy Agency

PADD Petroleum Administration for Defense District

SAGD Steam Assisted Gravity Drainage

U.S. United States

WCSB Western Canada Sedimentary Basin

WTI West Texas Intermediate

Canadian Provincial Abbreviations

AB Alberta

BC British Columbia

MB Manitoba

NWT Northwest Territories

ON Ontario

QC Québec

Units

b/d barrels per day

Conversion Factor

1 cubic metre = 6.293 barrels (oil)

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

MI Michigan

MN Minnesota

MS Mississippi

MO Missouri

MT Montana

NE Nebraska

NV Nevada

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

TN Tennessee

TX Texas

UT Utah

VT Vermont

VA Virginia

WA Washington

WV West Virginia

WI Wisconsin


AP

PE

ND

IX B

.1

CA

PP

Canad

ian C

rud

e O

il P

rod

uction F

ore

cast

2011 –

2025

tho

usand

barr

els

per

day

Actuals

Fo

recast

CO

NV

EN

TIO

NA

L2005

2006

2007

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

2017

2018

2019

2020

2021

2022

2023

2024

2025

Lig

ht

& M

ed

ium

A

lbert

a374

360

347

34

73

18

31

93

36

34

53

53

35

63

60

35

9360

349

339

331

325

319

312

305

300

B

.C.

30

28

26

23

22

22

21

20

19

18

17

16

15

14

14

13

12

12

11

11

10

S

ask

atc

hew

an 1

,2148

155

162

18

31

85

18

61

90

19

41

98

20

12

03

20

3203

199

193

186

181

176

171

163

156

M

anito

ba

14

21

22

24

26

32

38

39

39

39

39

36

35

34

33

33

32

31

31

30

30

N

.W.T

.19

19

18

16

16

15

14

13

13

12

11

11

10

10

99

88

87

7

To

tal C

on

v. L

igh

t a

nd

Me

diu

m585

583

576

59

35

67

57

35

99

61

06

21

62

66

30

62

5623

606

588

572

560

546

533

517

502

Heavy

A

lbert

a C

onv.

Heavy

197

183

178

15

61

43

14

01

38

13

71

36

13

41

32

12

9125

120

114

108

103

98

93

88

84

S

ask

atc

hew

an C

onv.

Heavy

1,2

271

273

264

25

52

37

23

52

33

23

02

28

22

62

21

21

6213

208

202

195

190

184

177

169

163

To

tal C

on

ve

nti

on

al H

ea

vy

468

456

442

41

13

80

37

53

71

36

73

64

36

03

53

34

5338

329

316

304

293

282

270

258

247

TO

TA

L C

ON

VE

NT

ION

AL

1,0

53

1,0

39

1,0

17

1,0

04

94

79

48

97

09

77

98

59

85

98

39

70

961

935

904

876

853

828

803

774

749

PE

NTA

NE

S/C

ON

DE

NS

AT

E160

153

151

14

51

38

13

41

28

12

51

23

12

01

20

11

9118

117

116

114

113

112

111

110

109

OIL

SA

ND

S (

BIT

UM

EN

&

UP

GR

AD

ED

CR

UD

E O

IL)

O

il S

and

s M

inin

g

536

630

661

62

96

89

72

77

79

88

39

12

1,0

08

1,0

36

1,0

71

1,1

09

1,1

44

1,2

00

1,2

86

1,3

46

1,3

60

1,3

71

1,3

81

1,4

28

O

il S

and

s In

Situ

437

489

529

57

26

51

74

37

97

88

29

70

1,0

45

1,1

20

1,2

22

1,3

05

1,4

27

1,5

93

1,7

14

1,8

32

1,9

57

2,0

87

2,2

17

2,3

05

TO

TA

L O

IL S

AN

DS

974

1,1

19

1,1

90

1,2

01

1,3

41

1,4

70

1,5

76

1,7

65

1,8

81

2,0

53

2,1

56

2,2

93

2,4

13

2,5

70

2,7

93

3,0

00

3,1

78

3,3

17

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58

3,5

97

3,7

33

WE

ST

ER

N C

AN

AD

A O

IL P

RO

DU

CT

ION

2,1

87

2,3

11

2,3

59

2,3

50

2,4

25

2,5

52

2,6

74

2,8

67

2,9

89

3,1

59

3,2

59

3,3

82

3,4

92

3,6

22

3,8

12

3,9

90

4,1

44

4,2

57

4,3

72

4,4

81

4,5

92

AT

LA

NT

IC C

AN

AD

A O

IL P

RO

DU

CT

ION

305

304

369

34

22

68

27

62

60

27

02

50

23

02

20

19

5205

235

250

220

220

205

185

165

145

TO

TA

L C

AN

AD

IAN

OIL

PR

OD

UC

TIO

N2,4

92

2,6

15

2,7

27

2,6

92

2,6

93

2,8

28

2,9

34

3,1

37

3,2

39

3,3

89

3,4

79

3,5

77

3,6

97

3,8

57

4,0

62

4,2

10

4,3

64

4,4

62

4,5

57

4,6

46

4,7

37

OIL

SA

ND

S R

AW

BIT

UM

EN

**

O

il S

and

s M

inin

g

626

769

784

72

48

26

85

79

10

1,0

35

1,0

67

1,1

67

1,1

97

1,2

36

1,2

67

1,3

39

1,4

40

1,5

60

1,6

53

1,6

75

1,6

93

1,7

04

1,7

52

O

il S

and

s In

Situ

439

494

536

58

46

65

75

98

28

91

91

,00

61

,08

21

,15

61

,25

71,3

39

1,4

62

1,6

30

1,7

51

1,8

71

1,9

98

2,1

28

2,2

58

2,3

48

TO

TA

L O

IL S

AN

DS

1,0

65

1,2

63

1,3

20

1,3

07

1,4

91

1,6

16

1,7

38

1,9

54

2,0

74

2,2

49

2,3

54

2,4

92

2,6

06

2,8

02

3,0

69

3,3

11

3,5

23

3,6

73

3,8

21

3,9

62

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99

Note

s:

1. C

AP

P a

llocate

s S

aska

tchew

an A

rea III

Med

ium

cru

de a

s h

eavy

cru

de. A

lso 1

7%

of A

rea IV

is >

900 k

g/m

3.

2. C

AP

P h

as r

evi

sed

fro

m t

he J

une 2

007 r

ep

ort

his

torical l

ight/

heavy

ratio for

Saska

tchew

an s

tart

ing in

2005.

** R

aw

bitum

en n

um

bers

are

hig

hlig

hte

d. The o

il sand

s p

rod

uction n

um

bers

(as h

isto

rically

pub

lished

) are

a c

om

bin

ation o

f up

gra

ded

cru

de o

il and

bitum

en a

nd

there

fore

incorp

ora

te y

ield

losses fro

m

inte

gra

ted

up

gra

der

pro

jects

. P

rod

uction fro

m o

ff-s

ite u

pgra

din

g p

roje

cts

are

inclu

ded

in t

he p

rod

uction n

um

bers

as b

itum

en.

Gro

wth

Ju

ne 2

01

1


AP

PE

ND

IX B

.2

CA

PP

Canad

ian C

rud

e O

il P

rod

uction F

ore

cast

2011 –

2025

tho

usand

barr

els

per

day

Actuals

Fo

recast

CO

NV

EN

TIO

NA

L2005

2006

2007

20

08

20

09

201

02

01

12

01

22

01

32

01

42

01

52

01

62017

2018

2019

2020

2021

2022

2023

2024

2025

Lig

ht

& M

ed

ium

A

lbert

a374

360

347

34

73

18

31

93

36

34

53

53

35

63

60

35

9360

349

339

331

325

319

312

305

300

B

.C.

30

28

26

23

22

22

21

20

19

18

17

16

15

14

14

13

12

12

11

11

10

S

ask

atc

hew

an 1

,2148

155

162

18

31

85

18

61

90

19

41

98

20

12

03

20

3203

199

193

186

181

176

171

163

156

M

anito

ba

14

21

22

24

26

32

38

39

39

39

39

36

35

34

33

33

32

31

31

30

30

N

.W.T

.19

19

18

16

16

15

14

13

13

12

11

11

10

10

99

88

87

7

To

tal C

on

v. L

igh

t a

nd

Me

diu

m585

583

576

59

35

67

57

35

99

61

06

21

62

66

30

62

5623

606

588

572

560

546

533

517

502

Heavy

A

lbert

a C

onv.

Heavy

197

183

178

15

61

43

14

01

38

13

71

36

13

41

32

12

9125

120

114

108

103

98

93

88

84

S

ask

atc

hew

an C

onv.

Heavy

1,2

271

273

264

25

52

37

23

52

33

23

02

28

22

62

21

21

6213

208

202

195

190

184

177

169

163

To

tal C

on

ve

nti

on

al H

ea

vy

468

456

442

41

13

80

37

53

71

36

73

64

36

03

53

34

5338

329

316

304

293

282

270

258

247

TO

TA

L C

ON

VE

NT

ION

AL

1,0

53

1,0

39

1,0

17

1,0

04

94

794

89

70

97

79

85

98

59

83

97

0961

935

904

876

853

828

803

774

749

PE

NTA

NE

S/C

ON

DE

NS

AT

E160

153

151

14

51

38

13

41

28

12

51

23

12

01

20

11

9118

117

116

114

113

112

111

110

109

OIL

SA

ND

S (

BIT

UM

EN

&

UP

GR

AD

ED

CR

UD

E O

IL)

O

il S

and

s M

inin

g

536

630

661

62

96

89

72

77

79

88

39

12

1,0

08

1,0

27

1,0

42

1,0

67

1,0

75

1,0

75

1,0

75

1,0

75

1,0

75

1,0

75

1,0

75

1,0

75

O

il S

and

s In

Situ

437

489

529

57

26

51

74

37

97

88

29

69

1,0

44

1,0

97

1,1

48

1,1

71

1,1

89

1,2

04

1,1

93

1,1

89

1,1

84

1,1

79

1,1

75

1,1

70

TO

TA

L O

IL S

AN

DS

974

1,1

19

1,1

90

1,2

01

1,3

41

1,4

70

1,5

76

1,7

65

1,8

81

2,0

52

2,1

24

2,1

90

2,2

38

2,2

64

2,2

79

2,2

68

2,2

64

2,2

59

2,2

55

2,2

50

2,2

45

WE

ST

ER

N C

AN

AD

A O

IL P

RO

DU

CT

ION

2,1

87

2,3

11

2,3

59

2,3

50

2,4

25

2,5

52

2,6

74

2,8

67

2,9

88

3,1

58

3,2

27

3,2

79

3,3

17

3,3

16

3,2

99

3,2

58

3,2

30

3,1

99

3,1

68

3,1

34

3,1

03

AT

LA

NT

IC C

AN

AD

A O

IL P

RO

DU

CT

ION

305

304

369

34

22

68

27

62

60

27

02

50

23

02

20

19

5205

235

250

220

220

205

185

165

145

TO

TA

L C

AN

AD

IAN

OIL

PR

OD

UC

TIO

N2,4

92

2,6

15

2,7

27

2,6

92

2,6

93

2,8

28

2,9

34

3,1

37

3,2

38

3,3

88

3,4

47

3,4

74

3,5

22

3,5

51

3,5

49

3,4

78

3,4

50

3,4

04

3,3

53

3,2

99

3,2

48

OIL

SA

ND

S R

AW

BIT

UM

EN

**

O

il S

and

s M

inin

g

626

769

784

72

48

26

85

79

10

1,0

35

1,0

67

1,1

67

1,1

88

1,2

05

1,2

23

1,2

31

1,2

31

1,2

31

1,2

31

1,2

31

1,2

31

1,2

31

1,2

31

O

il S

and

s In

Situ

439

494

536

58

46

65

75

98

28

91

91

,00

61

,08

11

,13

31

,18

51,2

08

1,2

26

1,2

41

1,2

29

1,2

26

1,2

20

1,2

16

1,2

11

1,2

07

TO

TA

L O

IL S

AN

DS

1,0

65

1,2

63

1,3

20

1,3

07

1,4

91

1,6

16

1,7

38

1,9

54

2,0

74

2,2

48

2,3

21

2,3

90

2,4

31

2,4

57

2,4

72

2,4

61

2,4

57

2,4

52

2,4

47

2,4

43

2,4

38

Note

s:

1. C

AP

P a

llocate

s S

aska

tchew

an A

rea III

Med

ium

cru

de a

s h

eavy

cru

de. A

lso 1

7%

of A

rea IV

is >

900 k

g/m

3.

2. C

AP

P h

as r

evi

sed

fro

m t

he J

une 2

007 r

ep

ort

his

torical l

ight/

heavy

ratio for

Saska

tchew

an s

tart

ing in

2005.

** R

aw

bitum

en n

um

bers

are

hig

hlig

hte

d. The o

il sand

s p

rod

uction n

um

bers

(as h

isto

rically

pub

lished

) are

a c

om

bin

ation o

f up

gra

ded

cru

de o

il and

bitum

en a

nd

there

fore

incorp

ora

te y

ield

losses fro

m

inte

gra

ted

up

gra

der

pro

jects

. P

rod

uction fro

m o

ff-s

ite u

pgra

din

g p

roje

cts

are

inclu

ded

in t

he p

rod

uction n

um

bers

as b

itum

en.

Op

era

tin

g &

In

Co

nstr

ucti

on

Ju

ne 2

01

1


AP

PE

ND

IX B

.4 2

011 –

2025 W

este

rn C

anad

ian C

rud

e O

il S

up

ply

Ble

nd

ed

Su

pp

ly t

o T

run

k P

ipelin

es a

nd

Mark

ets

t

ho

usan

d b

arr

els

per

day

Actu

als

Fo

recast

CO

NV

EN

TIO

NA

L2005

2006

2007

20

08

20

09

20

10

20

11

20

12

201

32

01

42

01

52

01

62017

2018

2019

2020

2021

2022

2023

2024

2025

Tota

l Lig

ht

and

Med

ium

581

579

572

58

95

63

56

95

95

60

661

76

22

62

66

21

619

602

584

568

556

542

529

513

498

Net

Co

nve

ntio

nal H

eavy

to

Mark

et

405

386

382

35

03

08

30

93

00

28

928

62

81

27

42

65

257

246

233

219

207

195

181

168

156

TO

TA

L C

ON

VE

NT

ION

AL

985

965

954

93

98

71

87

88

95

89

590

29

02

89

98

86

876

849

817

787

763

737

710

680

654

OIL

SA

ND

S

Up

gra

ded

Lig

ht

(Syn

thetic)1

507

575

618

55

76

46

66

07

23

84

687

88

94

92

79

37

945

936

919

910

910

910

910

910

910

Oil

Sand

s H

eavy

2678

774

822

91

69

96

1,1

62

1,2

04

1,3

00

1,4

11

1,6

22

1,6

83

1,7

49

1,7

94

1,8

33

1,8

64

1,8

56

1,8

51

1,8

46

1,8

41

1,8

35

1,8

30

TO

TA

L O

IL S

AN

DS

AN

D

UP

GR

AD

ER

S

1,1

85

1,3

50

1,4

40

1,4

73

1,6

42

1,8

22

1,9

27

2,1

46

2,2

89

2,5

16

2,6

09

2,6

87

2,7

40

2,7

69

2,7

83

2,7

66

2,7

61

2,7

55

2,7

51

2,7

45

2,7

40

Tota

l Lig

ht

Sup

ply

1,0

87

1,1

54

1,1

90

1,1

46

1,2

09

1,2

29

1,3

19

1,4

52

1,4

95

1,5

15

1,5

52

1,5

58

1,5

64

1,5

39

1,5

02

1,4

78

1,4

65

1,4

52

1,4

38

1,4

22

1,4

08

Tota

l Heavy

Sup

ply

1,0

83

1,1

61

1,2

04

1,2

66

1,3

04

1,4

71

1,5

04

1,5

89

1,6

97

1,9

03

1,9

56

2,0

14

2,0

51

2,0

79

2,0

97

2,0

75

2,0

58

2,0

41

2,0

23

2,0

03

1,9

86

WE

ST

ER

N C

AN

AD

A O

IL S

UP

PLY

2,1

70

2,3

15

2,3

94

2,4

12

2,5

13

2,7

00

2,8

22

3,0

41

3,1

91

3,4

18

3,5

08

3,5

72

3,6

15

3,6

18

3,6

00

3,5

52

3,5

24

3,4

92

3,4

61

3,4

25

3,3

94

AP

PE

ND

IX B

.3 2

011 –

2025 W

este

rn C

anad

ian C

rud

e O

il S

up

ply

B

len

ded

Su

pp

ly t

o T

run

k P

ipelin

es a

nd

Mark

ets

th

ou

san

d b

arr

els

per

day

Actu

als

Fo

recast

CO

NV

EN

TIO

NA

L2005

2006

2007

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

2017

2018

2019

2020

2021

2022

2023

2024

2025

Tota

l Lig

ht

and

Med

ium

581

579

572

58

95

63

56

95

95

60

66

17

62

26

26

62

1619

602

584

568

556

542

529

513

498

Net

Co

nve

ntio

nal H

eavy

to

Mark

et

405

386

382

35

03

08

30

93

00

28

92

86

28

12

74

26

5257

246

233

219

207

195

181

168

156

TO

TA

L C

ON

VE

NT

ION

AL

985

965

954

93

98

71

87

88

95

89

59

02

90

28

99

88

6876

849

817

787

763

737

710

680

654

OIL

SA

ND

S

Up

gra

ded

Lig

ht

(Syn

thetic)1

507

575

618

55

76

46

66

07

23

84

38

69

88

59

22

93

6942

954

973

998

991

981

975

970

969

Oil

Sand

s H

eavy

2678

774

822

91

69

96

1,1

62

1,2

04

1,3

01

1,4

17

1,6

28

1,7

28

1,8

86

2,0

31

2,2

09

2,4

60

2,6

81

2,8

87

3,0

67

3,2

51

3,4

38

3,6

22

TO

TA

L O

IL S

AN

DS

AN

D

UP

GR

AD

ER

S

1,1

85

1,3

50

1,4

40

1,4

73

1,6

42

1,8

22

1,9

27

2,1

45

2,2

85

2,5

13

2,6

50

2,8

22

2,9

72

3,1

63

3,4

33

3,6

79

3,8

78

4,0

49

4,2

26

4,4

09

4,5

91

Tota

l Lig

ht

Sup

ply

1,0

87

1,1

54

1,1

90

1,1

46

1,2

09

1,2

29

1,3

19

1,4

50

1,4

85

1,5

06

1,5

47

1,5

57

1,5

61

1,5

57

1,5

57

1,5

66

1,5

47

1,5

23

1,5

03

1,4

83

1,4

67

Tota

l Heavy

Sup

ply

1,0

83

1,1

61

1,2

04

1,2

66

1,3

04

1,4

71

1,5

04

1,5

90

1,7

02

1,9

09

2,0

01

2,1

51

2,2

87

2,4

55

2,6

93

2,8

99

3,0

94

3,2

62

3,4

32

3,6

06

3,7

78

WE

ST

ER

N C

AN

AD

A O

IL S

UP

PLY

2,1

70

2,3

15

2,3

94

2,4

12

2,5

13

2,7

00

2,8

22

3,0

40

3,1

88

3,4

15

3,5

49

3,7

08

3,8

48

4,0

12

4,2

50

4,4

66

4,6

41

4,7

86

4,9

36

5,0

89

5,2

45

Note

s:

1. Inclu

des u

pgra

ded

conve

ntional.

2. In

clu

des: a) im

port

ed

cond

ensate

b) m

anufa

ctu

red

dilu

ent

from

up

gra

ders

and

c) up

gra

ded

heavy

volu

mes c

om

ing fro

m u

pgra

ders

.

Op

era

tin

g &

In

Co

nstr

ucti

on

Ju

ne 2

01

1

Gro

wth

Ju

ne 2

01

1


APPENDIX C

Crude Oil Pipelines and Refineries

Vancouver to:

Japan - 4,300 miles

Taiwan - 5,600 miles

S.Korea - 4,600 miles

China - 5,100 miles

San Francisco - 800 miles

Los Angeles - 1,100 miles

Prince George

Husky...............12

Flanagan

Port Arthur/Beaumont

Artesia Slaughter

CENTURION

SPEARHEAD

SOUTH

St. Charles

EXXONMOBIL

EXXONMOBIL

EXX

ON

MO

BIL

EXXONMOBIL

KE

YS

TON

E

KE

YS

TON

E

Vancouver

Chevron ...........55

Puget Sound

BP ..................................234

ConocoPhillips...........100

Shell...............................145

Tesoro ...........................120

US Oil .............................. 39

San Francisco

Chevron ...................240

ConocoPhillips.......120

Shell...........................165

Tesoro .......................166

Valero........................170

Great Falls

Montana Re"ning..... 10

Billings

CHS ................................ 55

ConocoPhillips........... 58

ExxonMobil................. 60

Los Angeles

BP ........................................ 265

Chevron ............................. 285

ConocoPhillips................. 139

ExxonMobil....................... 150

Tesoro ....................................97

Valero ................................. 135

Edmonton

Imperial...........................187

Suncor .............................135

Shell..................................100

Lloydminster

Husky.................................28

Husky Upgrader.............82

Regina

Co-op Re"nery/

Upgrader .......................100

Moose Jaw

Moose Jaw Asphalt .....15

Wyoming

Frontier (Cheyenne)......................52

Little America (Casper) ................25

Sinclair Oil (Sinclair) ......................66

Wyoming (Newcastle)..................14

Houston/Texas City

BP ....................................475

ConocoPhillips.............247

Deer Park .......................340

ExxonMobil...................584

Houston Re"ning .......268

Marathon......................... 76

Valero (2)........................390

Three Rivers

Valero..............................100

Corpus Christi

CITGO..............................165

Flint..................................300

Valero..............................315


ExxonMobil................... 365

Motiva............................. 285

Valero.............................. 310

Total................................. 174

El Paso

Western Re"ning .........125

Oklahoma

ConocoPhillips (Ponca City)............... 187

Holly .......................................................... 125

Valero (Ardmore) ......................................90

Wynnewood...............................................70

Borger/McKee

WRB ..................................146

Valero...............................170

Denver/Commerce City

Suncor ............................. 93

Salt Lake City

Big West ..............35

Chevron ..............45

Holly .....................31

Tesoro ..................58

Mandan

Tesoro ..............58 St. Paul

Flint Hills .............320

Northern Tier....... 74

McPherson

NCRA.......................................... 85

El Dorado

Frontier....................................135

Co!eyville

Co!eyville Resources .........115

Superior

Murphy............ 35

Upgraders

Syncrude (Fort McMurray) .............407

Suncor (Fort McMurray) ..................428

Shell (Scotford)...................................155

CNRL Horizon......................................135

OPTI/Nexen Long Lake...................... 72

Artesia

Holly ............100


Saint John

MontréalMONTREAL

Approved Crude Oil Pipelines

MONTREAL

MONTREAL

MONTREAL

MONTREAL

For Information Contact: (403) 267-1141 / www.capp.ca

2010 Canadian Crude Oil Production

000 m3/d 000 b/d

British Columbia 5 31

Alberta 326 2,052

Saskatchewan 67 421

Manitoba 5 32

Northwest Territories 2 15

Western Canada 405 2,552

Atlantic Canada 44 276

Total Canada 449 2,828

Pipeline Tolls Light Oil (US$ per barrel)

Edmonton to Burnaby (Trans Mountain) 2.70

Anacortes (Trans Mountain/Puget) 2.90

Sarnia (Enbridge) 3.90

Chicago (Enbridge) 3.50

Wood River (Enbridge/Mustang/Capwood) 4.65

USGC (Enbridge/Mustang/ExxonMobil) 6.05

Hardisty to Guernsey (Express/Platte ) 1.50*

Wood River (Express/Platte) 1.85*

Wood River (Keystone) 4.70**

USGC (Express/Platte/MAP/ExxonMobil) 3.70

USEC to Sarnia (Portland/Montréal/Enbridge) 2.90

St. James to Wood River (Capline/Capwood) 1.00

Freeport to Wood River (Seaway/Ozark) 1.85

Pipeline Tolls -Heavy Oil (US$ per barrel)

Hardisty to Chicago (Enbridge) 3.90

Cushing (Enbridge/Spearhead) 5.90

Cushing (Keystone) 5.85**

Cushing (Keystone) 6.20*

Wood River (Enbridge/Mustang/Capwood) 5.40

Wood River (Keystone) 5.30**

Wood River (Express/Platte) 2.25*

Notes 1) Assumed exchange rate = 1US$ / 1C$

2) Tolls rounded to nearest 5 cents

3) Tolls in e!ect July 1, 2011

* 10-year committed toll

**20-year committed toll

Major Canadian Crude Oil Pipelines

Flanagan

Come by Chance

St. Charles

Newfoundland

North Atlantic .................. 115

Lake Charles/Garyville

ConocoPhillips...............239

CITGO................................440

Marathon.........................436

Valero................................250


ExxonMobil................... 365

Motiva............................. 285

Valero.............................. 310

Total................................. 174

Saint John

Irving....................300

Halifax

Imperial............... 82

Detroit

Marathon...................106

Toledo

BP-Husky ...................160

PBF...............................170

Lima

Husky..........................160

Canton

Marathon..................... 78

Catlettsburg

Marathon...................212

New Jersey

ConocoPhillips...............238

PBF.....................................180

Wood River

WRB .....................................306

Robinson

Marathon...........................206

Memphis

Valero...................195

El Dorado

Lion......................... 80

Murphy............ 35

Chicago

BP ............................. 405

ExxonMobil............ 250

PDV .......................... 167

Sarnia

Imperial............... 121

Nova ........................80

Shell.........................74

Suncor ....................85

Nanticoke

Imperial............... 112

Montréal/Québec

Suncor .....................130

Ultramar..................265

Philadelphia

ConocoPhillips (Trainer)............. 185

Sunoco (Marcus Hook) ............... 175

Sunoco (Philadelphia)................. 330

Warren

United ......... 70


Calgary Office:

2100, 350 - 7 Avenue SWCalgary, Alberta, CanadaT2P 3N9

Phone: 403-267-1100Fax: 403-261-4622

St. John’s Office:

403, 235 Water StreetSt. John’s, Newfoundlandand LabradorCanada A1C 1B6

Phone: 709-724-4200

Fax: 709-724-4225

www.capp.ca

[email protected]

June 2011

2011-0010

The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP’s member companies produce more than 90 per cent of Canada’s natural gas and crude oil. CAPP’s associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP’s members and associate members are an important part of a national industry with revenues of about $100 billion-a-year.

CAPP’s mission is to enhance the economic sustainability of the Canadian upstream petroleum industry in a safe and environmentally and socially responsible manner, through constructive engagement and communication with governments, the public and stakeholders in the communities in which we operate.

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