31015785 2009 CAPP Crude Oil Forecast Markets

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Crude Oil Forecast, Markets & Pipeline Expansions

June 2009

Crude OilForecast, Markets & Pipeline Expansions


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2 CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS


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ii CANADIAN ASSOCIATION OF PETROLEUM PRODUCERS

Crude Oil Markets

CAPP also surveyed refineries in Canada and the U.S. to

obtain information on their current capability and plans to

process additional volumes of western Canadian crude oil.

This information is intended to help industry gain a better

understanding of the potential markets for the expected

growth in oil sands supply, and in turn, assist the industry

in the evaluation of pipeline projects connecting supply to

these potential markets.

Based on the survey results, the potential demand for

Canadian crude oil in most markets is relatively flat.

However, the U.S. Midwest is expected to take more

western Canadian crude oil, as a result of a number of

planned refinery expansions and conversions to process

heavier crude oil. The U.S. Gulf Coast is considered a

market with significant potential given its large refining

capacity and the ability of many of these refiners to

process heavy crude. Also, the steep decline in Mexicos

production and Venezuelas recent shift towards exporting

oil to non-U.S. markets such as China, are factors that

could make securing supply from Canada more attractive

in the future. The full potential of this market remains

uncertain at this stage, however, given limited pipeline

access to this region from western Canada.

Crude Oil Pipelines and

Expansions

The major pipeline projects that are currently under

construction will add over one million b/d in pipeline

capacity exiting western Canada by the end of 2010.

A corresponding growth in supply of one million b/d is not

expected to occur until 2016. Current pipeline capacity

underway or in the regulatory process will provide excess

capacity for a number of years and sufficient pipeline

capacity available exiting Western Canada throughout the

forecast period.

There are numerous pipeline project proposals presented.

However, many of these proposals were developed in

response to earlier expectations that additional capacity

was required to meet more rapid growth in oil sands

production than is currently being forecast. Given the

current supply outlook and market conditions, the timing

of most of these pipeline proposals has been delayed.

PADD II

PADD I

PADD V

PADD III

68 [74]

89 [380+]

3,746

1,155 [2,005]

482 [547]

623

2,708

Non-US8

149 [171]

230 [253]

Supply

2008 - 2,436

2015 - 3,308

1,796

8,378

398

PADD IV

255 [257]

612

2009 Total Refining Capacity

2008 ActualDemand

Additional Demand- 2015 Potential

Market Demand for Western Canadian Crude Oil Actual 2008 vs 2015 Potential thousand barrels per day


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Portland

Montreal

Sarnia

Buffalo

Philadelphia

Toledo

Lima

Chicago

Patoka

Cushing

St. PaulSalt Lake City

St. JamesHouston

Edmonton

Anacortes

Burnaby

TransCanada Keystone

BP/Enbridge GAP

Phase 1

BP/Enbridge GAP

Phase 2

BP/Enbridge GAP

Phase 3

Altex

Enbridge Southern Access Expansion

Enbridge Southern Access Extension

TransCanada

Louisiana Access

Mustang Expansion

Enbridge Alberta Clipper

TransMountain

BP

Enbridge

Mid Valley

Capline

Flanagan

WoodRiver

Hardisty

Centurion Pipeline

ExxonMobil/Enbridge

Pegasus Expansion

Enbridge Spearhead

Expansion (North)

Express

Platte

Guernsey

Enbridge Gateway

1

Kinder Morgan

TMX2 Expansion

TMX3 Expansion

2

3

Kinder Morgan

TMX Northern Leg

5

6Enbridge (North Dakota) Expansion

9TransCanada

AB-USGC

Keystone XL

8

TransCanada

AB-California7

22 Sunoco to USGC21

23

18

10

15

4 Enbridge Ohio Access16

Sunoco to Toledo

19

14

13

12

11

Sunoco

Buffalo to Philadelphia

20

17

Enbridge Trailbreaker

Portland Pipeline Reversal17

Canadian & U.S. Crude Oil Pipelines All Proposals


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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 22.1 Canadian Crude Oil Production 2

2.2 Western Canadian Crude Oil Production 3

2.2.1 Oil Sands 3

2.2.2 Conventional Crude Oil Production 5

2.3 Western Canadian Crude Oil Supply 6

2.4 Methodology 7

2.5 Production and Supply Summary 8

3 CRUDE OIL MARKETS 9

3.1 Canada 10

3.1.1 Western Canada 103.1.2 Ontario 10

3.1.3 Qubec 10

3.2 United States 11

3.2.1 PADD I (East Coast) 11

3.2.2 PADD II (Midwest) 12

3.2.3 PADD III (Gulf Coast) 14

3.2.4 PADD IV (Rockies) 15

3.2.5 PADD V (West Coast) 15

3.3 Asia 17

3.4 Methodology 17

3.5 Markets Summary 18

4 CRUDE OIL PIPELINES 19

4.1 Major Crude Oil Pipelines 19

4.1.1 Existing Major Crude Oil Pipelines 19

4.2 Crude Oil Transportation Requirements 21

4.3 Crude Oil Pipeline Expansions/Proposals 22

4.3.1 Crude Oil Pipeline Expansions/Proposals to the U.S. Midwest,

Ontario, Qubec and the East Coast 22

4.3.2 Crude Oil Pipeline Expansions/Proposals to the U.S. Gulf Coast 25

4.3.3 Crude Oil Pipeline Expansions/Proposals to the West Coast 27

4.3.4 Other Proposals 28

4.3.5 Diluent Pipeline Proposals 29

4.4 Pipeline Summary 29

GLOSSARY 30

APPENDIX A: Acronyms, Abbreviations, Units and Conversion Factors 32

APPENDIX B: CAPP Canadian Crude Oil Production and Supply Forecast 2009 2025 33

APPENDIX C: Canadian and U.S. Crude Oil Pipeline Expansions/Proposals 37

APPENDIX D: Crude Oil Pipelines and Refineries 39


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LIST OF FIGURES AND TABLES

FiguresFigure 2.1 Canadian Oil Sands & Conventional Production 3

Figure 2.2 Oil Sands Regions 4

Figure 2.3 Growth Case - Western Canada Oil Sands & Conventional Production 4

Figure 2.4 Operating & In Construction - Western Canada Oil Sands & Conventional Production 5

Figure 2.5 Growth Case - Western Canada Oil Sands & Conventional Supply 7

Figure 2.6 Operating & In Construction - Western Canada Oil Sands & Conventional Supply 8

Figure 3.1 Market Demand for Western Canadian Crude Oil 2008 Actual vs 2015 Potential 9

Figure 3.2 Western Canada: Forecast Western Canadian Crude Oil Receipts 10

Figure 3.3 Ontario: Forecast Western Canadian Crude Oil Receipts 10

Figure 3.4 Petroleum Administration for Defense Districts 11

Figure 3.5 2008 PADD I: Foreign Sourced Supply by Type and Domestic Crude Oil 11

Figure 3.6 2008 PADD II: Foreign Sourced Supply by Type and Domestic Crude Oil 12

Figure 3.7 PADD II (North): Forecast Western Canadian Crude Oil Receipts 12

Figure 3.8 PADD II (East): Forecast Western Canadian Crude Oil Receipts 13

Figure 3.9 PADD II (South): Forecast Western Canadian Crude Oil Receipts 14

Figure 3.10 2008 PADD III: Foreign Sourced Supply by Type and Domestic Crude Oil 14

Figure 3.11 PADD IV: Forecast Western Canadian Crude Oil Receipts 15

Figure 3.12 2008 PADD V: Foreign Sourced Supply by Type and Domestic Crude Oil 16

Figure 3.13 Washington: Forecast Western Canadian Crude Oil Receipts 16

Figure 3.14 2008 PADD V (California): Foreign Sourced Supply by Type and Domestic Crude Oil 17

Figure 4.1 Current Crude Oil Expansions from Western Canada 21

Figure 4.2 Pipeline Proposals to the U.S. Midwest, Ontario and U.S. East Coast 22Figure 4.3 Pipeline Proposals to the U.S. Gulf Coast 25

Figure 4.4 Pipeline Proposals to U.S. West Coast 27

Figure 4.5 Diluent Pipeline Proposals 28

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 Product Demand in Major Asian Countries 17

Table 4.1 Approved Oil Pipeline Expansions from Western Canada 21


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INTRODUCTION

Historically, CAPP has prepared an annual Canadian crude oil production and

supply forecast to provide industry and the general public with a view of the

long-term outlook for Canadian production trends and available supply to

markets. Beginning in 2007, CAPP expanded the report to include a synopsis

on the potential markets for this crude oil supply in an attempt to capture and

summarize the market choices available to industry participants as they evaluate

proposed pipeline expansions or new pipeline projects.

1

For several years, the forecasted growth in Canadian

crude oil supply, primarily due to the development of the

Alberta oil sands, led industry to conclude that there was

an urgent need for additional pipeline capacity to connect

to new and expanded markets. Growth in crude oil supply

is still being forecast; only at a slower rate than previously

anticipated. While access to markets remains an important

consideration for producers, the need for additional

pipeline capacity has been tempered by a lower outlook

for supply growth.

Over the past 12 months, the industry has witnessed

a dramatic change in oil prices. The benchmark WTI

crude oil price dropped from a peak in July 2008 of

over US$140 per barrel to less than US$40 per barrel

by year-end. On average, current prices are significantly

lower than in recent years. The economic downturn in

major market areas has also impacted the industry and

the global financial crisis has hindered the ability of

companies to attract investment capital.

CAPPs estimate of industry capital spending for oil sands

development was reduced to $10 billion dollars for 2009

compared to $20 billion in 2008.

The forecast for market demand growth is also lower

than in the previous report, which is in line with the lower

forecasted growth in supply. As a result, many pipeline

proposals have been deferred but remain as options that

could respond to future market needs.

The outline of the report is as follows:

t $IBQUFSQSPWJEFTBOJOUSPEVDUJPOUPUIFSFQPSU

t $IBQUFSEJTDVTTFTUIFMBUFTUDSVEFPJMQSPEVDUJPO

and supply forecast

t $IBQUFSTVNNBSJ[FTUIFNBKPSQPUFOUJBMDSVEF

oil markets

t $IBQUFSEFTDSJCFTUIFFYJTUJOHNBKPSDSVEFPJMQJQFMJOF

network and proposed expansions


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Crude Oil Forecast, Markets & Pipeline Expansions 2

CAPP conducted a survey of oil sands producers in early

2009 to determine their planned production of bitumen and

upgraded crude oil for the period from 2009 to 2025. These

results were subsequently adjusted to reflect: the historical

performance trends of oil sands projects following start

up, the status of projects, and potential labour and capital

constraints. The majority of oil sands projects, particularly

in situ, are executed in multiple phases. Historically,in situ

projects require some time to ramp up to capacity while

new mining projects typically require some fine tuningbefore full capacity is maintained on a consistent basis.

From this data, CAPP has prepared a Growth Case,

representing the expected outlook which assumes the

eventual return of higher oil prices and investment activity.

In addition, a lower forecast has also been prepared using

the same risk factors but includes only projects currently in

operation or under construction. This latter case represents

a minimum potential growth from the oil sands.

2.1 Canadian Crude Oil Production

Western Canadian crude oil production averaged

2.4 million b/d in 2008 and is projected to grow significantly

over the forecast period due to development of the oil

sands. On the conventional side, both light and heavy

production in the WCSB is declining. Production in Atlantic

Canada is expected to grow in 2017 with the expected

start of production from the Hebron heavy oil project.

In 2008, production in Atlantic Canada was 342,000 b/d,

which accounted for about 13 percent of total Canadian

crude oil production of 2.7 million b/d.

Table 2.1 Canadian Crude Oil Production

million b/d 2008 2015 2020 2025

Growth 2.72 3.29 4.00 4.17

Operating

& In Construction 2.72 3.02 3.03 2.84

Table 2.1 shows the forecast for Canadian crude oil

production under the Growth Case and the Operating

& In Construction Case. In the latter case, production is

forecast at only 2.8 million b/d by 2025 due to the decline

in conventional production (Figure 2.1).

CRUDE OIL PRODUCTION

AND SUPPLY FORECAST2

According to the Oil and Gas Journal, Canada has total proven oil reserves of over

178 billion barrels. The two major oil producing areas in Canada are the Western

Canada Sedimentary Basin (WCSB) and Atlantic Canada. While CAPP has

included a forecast of production from Atlantic Canada in this report, the primary

focus will be on production from Western Canada since most of the growth in oil

production is expected to be derived from the oil sands areas located primarily in

the western province of Alberta.


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in recent experience. The decline in heavy crude oil

production in Saskatchewan has been offset somewhat by

the production from the Lower Shaunavon field.

In Manitoba, production rose 6 percent in 2008. However,

it should be noted that the Sinclair field, which wasdesignated in 2005, and was the first major discovery in

Manitoba in many years, accounted for 30 percent of the

provinces crude oil production. Production is expected to

start declining within the next 2 years as the field matures.

2.3 Western Canadian Crude

Oil Supply

Of particular interest to market participants is the supply

of actual crude oil types that will be available from initial

production. On a volumetric basis, supply is greater than

production because supply includes pentanes/condensate

volumes that have been imported to supplement the

locally produced volumes of condensate for use as diluent.

Diluent is necessary in order to transport the non-upgraded

bitumen production to market.

The CAPP forecast categorizes the various crude oil types

that comprise western Canadian crude oil supply into four

major categories: Conventional Light, Conventional Heavy,

Upgraded Light and Bitumen Blend. The Bitumen Blend

category includes upgraded heavy sour crude, bitumen

diluted with upgraded light crude oil (also known as

SynBit) and bitumen diluted with condensate (also known

as Dilbit). The most common form of Bitumen Blend

is bitumen blended with a standard condensate such as

pentanes plus, which is mainly recovered from processing

natural gas, to create a type of crude oil that meets pipeline

specifications for density and viscosity. An example of

such a Dilbit would be Cold Lake crude oil, which has a

density of about 930 kg/m3 (21 API) and a sulfur content

of 3.6 percent.

As discussed above, the main source of diluent is natural

gas condensates that are produced in western Canada.

However, this diluent supply has not been sufficient to meet

the needs of growing bitumen production. Companies

imported over 60,000 b/d of diluent into Alberta by rail in

2008. To meet growing demand for diluent, Enbridge is

building the Southern Lights diluent pipeline from Chicago

to Alberta. The pipeline will have an initial capacity of

180,000 b/d and is expected to be in service in July 2010.

Demand for condensate imports will exceed the initial

capacity of this pipeline by 2015 in the Growth Case.

Subsequently, rail and truck imports could be used to

increase the condensate supply available to market in the

interim. Potential longer-term solutions include blending

more upgraded light crude oil with bitumen or the

consideration of additional diluent pipeline options.

It should be noted that this latest forecast incorporates

the fact that fewer companies reported an intention to

use upgraded synthetic crude oil as a source of diluent

this year than in the past. Blending with a traditional

condensate diluent requires a 70:30 bitumen to condensate

ratio. When upgraded light crude is used as the diluent,

the blending ratio is approximately 50:50.

Table 2.3 Western Canadian Crude Oil Supply

million b/d 2008 2015 2020 2025

Growth 2.44 3.31 3.94 4.24

Operating & In

Construction 2.44 3.02 2.95 2.87

Table 2.3 shows the total western Canadian crude

oil supply projections for both cases. Please refer to

Appendices B.3 and B.4 for detailed supply data. In the

Growth Case, upgraded light crude oil supply is projected

to grow from about 564,000 b/d in 2008 to 1.0 million b/d

in 2015 and 1.3 million b/d by 2025. The upgraded light

crude oil supply includes the upgraded light crude oil

volumes produced from:

t 6QHSBEFSTUIBUQSPDFTTDPOWFOUJPOBMIFBWZPJM

e.g., the Husky Upgrader at Lloydminister and the

CCRL Upgrader in Regina;

t *OUFHSBUFENJOJOHBOEVQHSBEJOHQSPKFDUTFH4VODPS

Syncrude and CNRL operations;

t *OUFHSBUFEin situ projects, e.g., the Nexen Long Lake

project;

t 0GGTJUFVQHSBEFSTFHUIF"UIBCBTDB0JM4BOET

Project; and

t 4PNF.FSDIBOU6QHSBEFST

Bitumen Blend, which makes up the heavy crude oil

supply from the oil sands, is forecasted to increase from

933,000 b/d in 2008 to 1.6 million b/d in 2015 and up

to 2.4 million b/d in 2025 (Figure 2.5).


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3

In addition to examining the prospects for crude oil production, it is useful to have

an understanding of the potential market demand for the expected growth in oil

sands supply. This assessment will, in turn, assist the industry in the evaluation

of the various pipeline projects that are being proposed. In this context, CAPP

surveyed refineries in Canada and the U.S. to obtain information on their current

capability and plans to process additional volumes of western Canadian crude oil

and, in particular, oil sands to 2015.

CRUDE OIL MARKETS

PADD II

PADD I

PADD V

PADD III

68 [74]

89 [380+]

3,746

1,155 [2,005]

482 [547]

623

2,708

Non-US8

149 [171]

230 [253]

Supply

2008 - 2,436

2015 - 3,308

1,796

8,378

398

PADD IV

255 [257]

612

2009 Total Refining Capacity

2008 ActualDemand

Additional Demand- 2015 Potential

In 2008, total crude oil supply from western Canada

was over 2.4 million b/d. Domestic demand for western

Canadian crude oil was approximately 712,000 b/d and

the remaining supply of over 1.7 million b/d or 70 percent

was exported (Figure 3.1). The primary markets for western

Canadian crude oil are currently: British Columbia; Alberta;

Saskatchewan; Ontario; Minnesota; eastern PADD II

(particularly, Illinois, Indiana, Michigan, and Ohio); PADD IV;

California and Washington in PADD V. Since the reversal

of the Enbridge Spearhead pipeline and the ExxonMobil

Pegasus pipeline in early 2006, western Canadian crude

oil has flowed to the Cushing, Oklahoma hub and the U.S.

Gulf Coast, respectively.

Figure 3.1 Market Demand for Western Canadian Crude Oil Actual 2008 vs 2015 Potential

thousand barrels per day


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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 2008, these refineries processed about 712,000 b/d

of western Canadian crude oil. This is expected to

increase to approximately 788,000 b/d by 2015 with

planned refinery expansions.

3.1.1 Western Canada

There are eight refineries located in western Canada

with a total refining capacity of about 622,500 b/d.

These refineries process western Canadian crude oil

exclusively. The Moose Jaw asphalt plant in Moose Jaw,

Saskatchewan produces mostly asphalt while other

refineries manufacture a wide range of petroleum products.In 2008, they received 481,800 b/d of crude oil and this is

expected to increase to 547,200 b/d in 2015 (Figure 3.2).

Figure 3.2 Western Canada: Forecast Western

Canadian Crude Oil Receipts

Receipts of conventional light sweet crude oil are

expected to fall, in part due to the maturity of the basin

as well as refinery conversions. Receipts of light syntheticand heavy crude oil are expected to increase throughout

the forecast period.

Of note, the Petro-Canada conversion project at its

Edmonton refinery has been completed; the refinery

began to process 100 percent oil sands feedstock in

January 2009. Also, there are plans for the Consumers

Co-operative refinery located in Regina to expand by

30,000 b/d and to use some light synthetic crude oil as

feedstock by 2012.

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 398,000 b/d.

These refineries process western Canadian crude oil as

well as crude oil (foreign imports and Atlantic Canada

production) that is received by tankers via the Portland-

to-Montral pipeline and, subsequently, the Enbridge

Montral-to-Sarnia pipeline (Line 9). 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

367,400 b/d of crude oil in 2008 from the following

sources: Western Canada (230,300 b/d or 63 percent);

Eastern Canada (18,700 b/d or 5 percent); the United

Kingdom (33,200 b/d or 9 percent); Saudi Arabia

(31,200 b/d or 8 percent); United States (23,900 b/d

or 6 percent); and other foreign sources (30,100 b/d or

8 percent). Receipts of western Canadian crude oil are

projected to remain flat for the forecast period (Figure 3.3.)

Figure 3.3 Ontario: Forecast Western Canadian Crude

Oil Receipts

3.1.3 QubecQubec has three refineries. The two refineries located in

Montral have a combined refining capacity of 260,000 b/d

and the refinery in Qubec City has a capacity of 215,000 b/d.

The Montral refineries process both crude from Eastern

Canada and foreign sources received from the Portland-

to-Montral pipeline. If the Enbridge Montral-to-Sarnia

pipeline (Line 9) is reversed in the future, the Montral

market could be a new outlet for western Canadian crude

oil supply. As noted in the 2008 report, Petro-Canada

thousand barrels per dayTotal refining capacity = 622

Light Synthetic

Conventional Light Sweet

Conventional Medium Sour

Heavy

2008 2009 2010 2011 2012 2013 2014 20150

100

200

300

400

500

600

Total refining capacity = 398

Light Synthetic



Heavy

2008 2009 2010 2011 2012 2013 2014 20150

50

100

150

200

250

300

350

400



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had previously announced that it was considering adding

a 25,000 b/d coker at its refinery in Montral, which

would displace some light crude oil with heavy crude oil.

However, a decision on this project had been deferred.

The Suncor and Petro-Canada merger was announced in

March 2009. At this time, it is uncertain if the merger will

have any impact on the timing of this project.

3.2 United States

The United States, with a total refining capacity of almost

18 million b/d, is Canadas largest market for crude oil

exports. In 2008, Canada was the largest exporter of

crude oil to the U.S., ahead of both Mexico and Saudi

Arabia. Canada exported over 1.9 million b/d, which was

equivalent to almost 19 percent of total U.S. imports

from foreign sources. Of this volume, 1.7 million b/d wassourced from Western Canada (Figure 3.1). The U.S.

demand for western Canadian oil supply is expected

to reach 2.9 million b/d in 2015. The bulk of this growth

is expected to be heavy crude oil. The U.S. is a natural

market for much of Canadas rising crude oil supply, in

CAPPs view, because of its geographic proximity to the

U.S. and the geopolitical stability in the country.

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 purposesand are helpful in this report to facilitate the following

discussion on the various markets in the U.S.

Figure 3.4Petroleum Administration for Defense

Districts

3.2.1 PADD I (East Coast)

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

There are 14 refineries in Delaware, Georgia, New Jersey,

Pennsylvania, Virginia and West Virginia with a total

capacity of over 1.8 million b/d.

In 2008, refinery imports of foreign crude oil totaled

1.4 million b/d and over half of these volumes were light

sweet crude oil (Figure 3.5). Over 259,000 b/d (or 2 percent)

of the crude oil processed in PADD I refineries was sourced

from Canada. Of these volumes, 68,200 b/d came from

western Canada. These receipts, with the bulk being heavy

crude oil, were delivered by pipeline. Without additional

pipeline access to this market, western Canadian crude

oil deliveries are expected to remain relatively flat through

2015. PADD I refineries have the potential to process

western Canadian crude oil by displacing imports of other

foreign sourced crude oil, in particular, light sweet crude

oil. There are pipeline proposals being assessed to serve

this market with western Canadian crude oil.

Figure 3.5 2008 PADD I: Foreign Sourced Supply by

Type and Domestic Crude Oil

thousand barrels per dayTotal refining capacity = 1,796

307

304

803

7

Light/MediumSour

* Includes small volumes of Medium Sweet

Source: EIA

Heavy

Light Sweet*

Domestic Crude

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

SCNC

FL

RIWY


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3.2.2 PADD II (Midwest)

PADD II is located in the U.S. Midwest and has historically

been the largest market for western Canadian crude oil

with a refining capacity of 3.7 million b/d. In 2008, PADD II

refineries received over 1.5 million b/d of foreign sourced

crude oil and over half these volumes were heavy crude oil

(Figure 3.6). Crude oil from western Canada totaled over

1.1 million b/d, making Canada by far the largest supplier.

Figure 3.62008 PADD II: Foreign Sourced Supply by


In recent years, however, growth in heavy oil production

in western Canada has saturated this traditional market.

As a result, producers are looking for refiners in traditional

markets to increase their capacity for refining heavy crude,

as well as increased access to new markets such as the

U.S. Gulf Coast.

The U.S. Energy Information Administration further divides

PADD II into three refining districts, which is used in the

following discussion.

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 489,000 b/d. In 2008, imports into northern

PADD II were 287,000 b/d and western Canadian crude oil

accounted for almost all of it. Imports of western Canadian

crude oil are expected to grow to 370,000 b/d by 2011 and

remain flat afterwards (Figure 3.7).

In 2007, Flint Hills Resources completed a project to

increase the capacity of its refinery in Minnesota by 50,000

b/d. This increased capacity can be more fully utilized

with the completion of the pipeline expansion in the third

quarter of 2008 (see the MinnCan Project in the Pipeline

section of this report). Murphy Oil had previously discussedplans to expand its 35,000 b/d refinery to 235,000 b/d. This

expansion would essentially be a tear-down and rebuild

of the facility. However, it has been announced that these

plans will not proceed until a financial partner is found.

Figure 3.7 PADD II (North): Forecast Western Canadian

Crude Oil Receipts

thousand barrels per dayTotal refining capacity = 3,726

342

1,718

844

318

Light/MediumSour

Heavy

LightSweet*

DomesticCrude


Source: EIA


Light Synthetic



Heavy

2008 2009 2010 2011 2012 2013 2014 2015

0

50

100

150

200

250

300

350

400450

500thousand barrels per day


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Figure 3.8 PADD II (East): Forecast Western Canadian

Crude Oil ReceiptsSouthern PADD II

Southern PADD II has eight refineries located in Kansas

and Oklahoma with a total refining capacity of 823,500 b/d.

With the reversal of the Enbridge Spearhead pipeline in

March 2006, western Canadian producers were able to

deliver up to 125,000 b/d of crude oil into Cushing,

Oklahoma. In April 2009, Enbridge completed the

expansion of this pipeline to 190,000 b/d. Access to the

Cushing market offers western Canadian crude oil

producers some opportunities to penetrate other markets

(e.g. PADD III) through existing pipelines. Based on thesurvey responses, this market is not expected to be a large

growth area for western Canadian crude oil. In 2008,

refineries in this market received about 64,900 b/d of

western Canadian crude oil, and this is projected to rise

to 96,600 b/d in 2015 (Figure 3.9).

Eastern PADD II

Eastern PADD II consists of Michigan, Illinois, Indiana,

Kentucky, Tennessee and Ohio and has 14 refineries

with a total refining capacity of 2.4 million b/d. In 2008,

western Canadian crude oil accounted for 802,800 b/d

or 74 percent of the total foreign imports into the region.

Proposed expansions and conversions could result in

higher runs of western Canadian heavy crude oil in the

next several years (Figure 3.8). Table 3.1 summarizes

announced projects designed to process additional

volumes of Canadian crude oil.

Total refining capacity = 2,414

Light Synthetic



Heavy

2008 2009 2010 2011 2012 2013 2014 2015

0200

400

600

800

1000

1200

1400

1600

1800

2000thousand barrels per day

Table 3.1Summary of Announced Refinery Upgrades in Eastern PADD II

Operator Location

Current Capacity

(thousand b/d)

Scheduled

In-Service Description

ExxonMobil Joliet, IL 239 TBD Increased ability to process heavy crude oil

WRB Refining Roxana, IL 306 2011

(originally

end 2009)

Add a 65,000 b/d coker; increase total crude oil

refining capacity by 50,000 b/d; double heavy

oil refining capacity to 240,000 b/d

BP Whiting, IN 160 2012

(originally 2011)

Construction of new coker and a new crude

distillation unit

Marathon Detroit, MI 100 Mid 2012

(originally Q4 2010)

Increase heavy oil processing capacity by

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

capacity to 115,000 b/d

BP Toledo, OH 155 (60 heavy) Dependant on market

conditions (originally

2015)

Reconfigured to process 120,000 b/d of

bitumen (180,000 b/d total capacity)

Husky Lima, OH 165 TBD Conversion to process 105,000 of heavy crude

oil (170,000 b/d total)

Valero Memphis, TN 195 2012 (originally 2009) Cat-cracking unit upgrade


21/48


Figure 3.9PADD II (South): Forecast Western

Canadian Crude Oil Receipts

3.2.3 PADD III (Gulf Coast)

PADD III is comprised of Alabama, Arkansas, Louisiana,

Mississippi, New Mexico and Texas. There are 51 refineries

in this market with a total refining capacity of over

8.4 million b/d, of which a significant portion has heavy

crude oil processing capabilities. It is the largest and

most complex refining district in the United States and is

considered to be potentially well suited and capable of

processing Canadian heavy crude oil.

In 2008, PADD III imported 5.3 million b/d of crude oil from

foreign sources, of which 2.2 million b/d was heavy crude

oil (Figure 3.10). These imports came from 43 different

countries with the top suppliers being Mexico (22 percent),

Saudi Arabia (17 percent), Venezuela (17 percent) and

Nigeria (11 percent). Deliveries of western Canadian heavy

crude oil to this market totaled about 88,800 b/d. The only

pipeline access for delivery of western Canadian crude

oil to the Gulf Coast is through the ExxonMobil Pegasus

pipeline. This pipeline originates at Patoka, Illinois and

ends at Corsicana, Texas and has a capacity of 66,000 b/d.

This pipeline is currently being expanded by 30,000 b/d,

and is expected to be in-service in June 2009. In 2008,

approximately 22,800 b/d that were shipped off the

Westridge dock in Burnaby, British Columbia arrived via

tanker. In addition, about 11,700 b/d of light sweet crude

was also imported from Atlantic Canada by tanker.

Figure 3.10 2008 PADD III: Foreign Sourced Supply

by Type and Domestic Crude Oil

The steep decline in production from Mexicos Cantarell

field could make securing supply from Canada more

attractive in the future. In addition, Canadas other major

competitor, Venezuela, has recently signed agreements to

ship oil to other markets such as China. In recent years,

PADD III refineries have added several new cokers which

will enable them to run heavier and more sour grades of

crude oil, which are becoming increasingly predominant in

the worlds oil production slate. Table 3.2 summarizes the

major refinery upgrades announced for the region.

Although these upgrades may not all be specifically

designed to process Canadian crude oil, many of these

companies have confirmed that their refineries are

planning to take more Canadian crude. Thus the main

constraint to the growth of supply of western Canadian

heavy crude used in this region is not available refining

capacity but is in fact the availability of pipeline capacity

to the region. There are a number of pipeline proposals

to increase pipeline capacity to the U.S. Gulf Coast

scheduled for as early as 2012 or 2013. CAPP hasestimated that this market could receive at least 380,000 b/d

of western Canadian crude oil by 2013 based on

announced contractual commitments.


Light Synthetic



Heavy

2008 2009 2010 2011 2012 2013 2014 2015

020

40

60

80

100

120

140

160180

200thousand barrels per day thousand barrels per day


2,237

1,834

1,204

1,623


Source: EIA

Light/MediumSour

Heavy

LightSweet*

DomesticCrude


22/48


3.2.4 PADD IV (Rockies)

PADD IV includes the states of Colorado, Montana, Utah,

Wyoming and Idaho. It has 14 refineries located in four of

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

total refining capacity of 611,500 b/d. Although PADD IV is

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

market for western Canadian crude oil supply.

In 2008, PADD IV processed 255,000 b/d of Canadian

crude oil or about 48 percent of its feedstock requirements.

Canada is the only source of foreign crude oil to this market.Throughout the forecast period, western Canadian crude oil

receipts are forecasted to remain relatively flat (Figure 3.11).

Some refiners have indicated, however, that once crude oil

production from certain areas of PADD IV declines, there

could be opportunities for Canadian crude oil to replace

these supplies. In addition, a few refiners have either

recently invested in upgrading projects that could enable

their refinery to process oil from the oil sands or have plans

to do so in the future. As a result, the feedstock slate for this

market could become slightly heavier.

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, and has very good accessto tankers, and is located in close proximity to production

from Alaska and California. Nonetheless, this market still

depends on foreign imports for almost half of its

requirements (Figure 3.12).


Light Sweet*

Light/Medium Sour

Heavy

2008 2009 2010 2011 2012 2013 2014 2015

0

100

200

300

400

500

600

*Includes small volumes of Medium Sweet


Table 3.2 Summary of Major Announced Refinery Upgrades in PADD III

Operator Location

Current Capacity

(thousand b/d)

Scheduled

In-Service Description

Marathon Oil Garyville, LA 256 4Q 2009 Increase capacity to 425,000 b/d

Valero St. Charles, LA 250 2012 (originally

2011)

New 50,000 b/d hydrocracker and 10,000 b/d

expansions to the crude and coker units

Holly Artesia, NM 85 2009 Additional 25,000 b/d capacity and capability

to run up to 40,000 b/d of heavy crude oil

Motiva

Enterprises

Port Arthur, TX 285 2012 (originally

late 2010)

Increase capacity to over 600,000 b/d

Valero Port Arthur, TX 310 2011 (originally

2010)

New 50,000 b/d hydrocracker. Plans for

previously announced 45,000 b/d coker addition

is on hold

WRB Refining Borger, TX 146 2009+ Debottleneck to add 20,000 b/d bitumen capacity


23/48


Figure 3.12 2008 PADD V: Foreign Sourced Supply by


For the purposes of the remainder of this report, the PADD V

market region will focus only on Washington and California

as these states represent both the current demand and

future prospects for western Canadian crude oil.

Washington

There are five refineries in Washington that have acombined capacity of 629,000 b/d. Alaska is still the

primary source of feedstock for these refineries, however;

Alaskan production continues to decline. As a result, these

refiners are becoming increasingly dependent on imports

from Canada and other countries. In 2008, these refineries

received 221,000 b/d of foreign crude oil, sourced primarily

from Canada (56 percent), Angola (18 percent) and Saudi

Arabia (15 percent).

In 2008, receipts of western Canadian crude were

123,000 b/d. These receipts are expected to remain

flat throughout the forecast period (Figure 3.13).ConocoPhillips has delayed its proposed addition of a

25,000 b/d coker unit at its refinery located at Ferndale.

Construction is now scheduled to start in 2012.

The Washington market has the potential to process

additional volumes of western Canadian crude oil but given

the latest supply forecast and the small size of this niche

market, development of this market may be limited.

Figure 3.13 Washington: Forecast Western Canadian

Crude Oil Receipts

California

California has 19 refineries with a total refining capacity of

over 2 million b/d. Most of the refineries are located near

the coast in the Los Angeles area and in the San Francisco

Bay area. These refineries account for almost 95 percent

of the refining capacity in the state. These refineries are

among the most sophisticated in the world, partly due to

California having the strictest environmental requirements

in the United States for refined petroleum products. They

have the capability to process a wide variety of crude oil

types and are designed to yield a higher proportion oflight products, such as gasoline. The three refineries in

Bakersfield are smaller and process local California crude

oil; they would not be expected to receive Canadian crude.

In 2008, California refineries received about 38 percent

of their supply from California; 13 percent were domestic

imports sourced from Alaska with the rest of their supply

from foreign sources, delivered by tanker through marine

terminals. The top three sources of the 853,000 b/d

in foreign crude were Saudi Arabia (27 percent); Iraq

(24 percent); and Ecuador (20 percent). Canada only

accounted for about 3 percent of foreign imports(Figure 3.14).


416

590

187

698

678

Light/MediumSour

Heavy

LightSweet*

OtherDomestic

Domestic -Alaska


Source: EIA

thousand barrels per day Total refining capacity = 629

Light Sweet*

Light/Medium Sour

Heavy

2008 2009 2010 2011 2012 2013 2014 20150

100

200

300

400

500

600

*Includes small volumes of Medium Sweet



24/48


Figure 3.14 2008 PADD V (California): Foreign Sourced

Supply by Type and Domestic Crude Oil

The rate of decline of California production has eased

over recent years compared to historical trends but the

California Energy Commission still expects production

to fall by 2 to 3 percent per year in the future. Alaskan

crude production is supplied primarily to Alaska and

Washington, with the balance going to California. As

production in Alaska continues to decline, the California

refineries will need to replace their domestic crude oil

sources with increased imports.

Given Canadas proximity to California, this would appear

to be a potential market opportunity for western crude

oil. The California Air Resources Board has recently

introduced a new low-carbon fuel standard to be

implemented by 2012. However, greenhouse gas (GHG)

reductions in the oil sands along with Canadian GHG

policies may qualify oil sands to continue to supply this

market. With less optimistic views currently with respect

to oil supply growth, pipeline proposals to serve this

market have been deferred and are being re-evaluated.

3.3 Asia

The Asian market has attracted significant interest over the

last few years because of its rising demand for energy.

Undoubtedly, Asia has also been affected by the global

economic downturn, but this market, particularly China and

India, remains a prospect in the longer term. China is the

largest consumer of oil after the United States and

economic growth rates are expected to be relatively strong

compared to other countries. Table 3.3 shows oil demand

from 2006 to 2009 in the major Asian countries.

The International Energy Agency (IEA) forecasts that oil

demand from China will decline slightly in 2009 but growth

in the longer term is anticipated. There are a number of

pipeline project proposals that could take western

Canadian crude oil to these markets.

Table 3.3 Total Oil Product Demand in Major Asian

Countries

million b/d 2006 2007 2008 2009

China 7.21 7.54 7.86 7.80

India 2.80 2.95 3.08 3.13

Japan 5.20 5.01 4.74 4.05

Korea 2.18 2.21 2.15 2.13

Source: International Energy Agency (IEA), April 2009

3.4 Methodology

CAPP did not put any constraints on the data submitted

by refiners nor were any alternate cases prepared. Some

assumptions were made based on discussions with

refiners and publicly available information.

The CAPP survey categorizes western Canadian crude oil

into four main types as follows:

1. Conventional Light Sweet (greater than 27 API and less

than or equal to 0.5% sulphur) including condensatesand 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


351

468

34

683

240

Light/MediumSour

Heavy

LightSweet*

OtherDomestic

Domestic -Alaska



Source: EIA


25/48


For the purposes of the historical data in this section of

the report, the following crude types and definitions apply:

t 4XFFUDSVEFPJMXJUIBTVMQIVSDPOUFOUPGMFTTUIBO

or equal to 0.5%

t 4PVSDSVEFPJMXJUIBTVMQIVSDPOUFOUPGHSFBUFS

than 0.5%

t -JHIUDSVEFPJMXJUIBO"1*PGBUMFBTU

t .FEJVNDSVEFPJMXJUIBO"1*HSFBUFSUIBOCVU

less than 30

t )FBWZDSVEFPJMXJUIBO"1*PG"1*PSMFTT

No differentiation is made between sweet and sour crude

oil that falls in the heavy category because heavy crude oil

is generally sour.

3.5 Markets Summary

Based on the survey results, the forecasted potential

demand for Canadian crude oil in all markets is lower than

in the last report. However, in 2015, PADD II is expected

to be able to take more western Canadian crude oil due

to the planned refinery conversions in the area. PADD III

is considered a market with significant potential given its

large refining capacity and the ability of many of these

refiners to process heavy crude. Also, the steep decline in

Mexicos production and Venezuelas recent shift towards

exporting oil to non-U.S. markets such as China, are

factors that could make securing supply from Canada more

attractive in the future. The full potential of this market

remains uncertain at this stage, however, given limited

pipeline access to this region from western Canada.


26/48


Pipelines are the main connection between the crude oil supply areas to the

end markets since they are generally the most efficient and reliable mode of

transporting crude oil. As such, pipeline developments determine the destination

of Canadian crude oil. The additional capacity from all currently active

(i.e. in construction or in the regulatory process) pipeline projects would result

in total available pipeline capacity in excess of forecast supply through to the end

of the forecast period. In addition, there remain a number of proposals that havebeen grouped into three main areas: U.S. Midwest, Ontario, Qubec, U.S. East

Coast; the U.S. Gulf Coast; and the West Coast. However, the proposed timing

for many of these proposals is uncertain.

4 CRUDE OIL PIPELINES

4.1 Major Crude Oil Pipelines

Historically, major Canadian crude oil pipelines such as the

Enbridge Pipeline and the Kinder Morgan Trans Mountain

pipeline operated as common carriers. The exceptionsare the Kinder Morgan Express pipeline and the Enbridge

Line 9 (Montreal, Qubec to Sarnia, Ontario) that operate

as contract carriers (i.e. require long-term take-or-pay

commitments). On common carrier pipelines, shippers

nominate monthly for space on the pipeline without a

contract. The TransCanada Keystone pipeline, which is

scheduled to be in-service by the end of 2009, will operate

as a contract carrier while the Enbridge Alberta Clipper

pipeline will be a common carrier.

4.1.1 Existing Major CrudeOil Pipelines

Western Canadian crude oil is delivered to markets or other

pipelines by three major Canadian trunklines Enbridge,

Trans Mountain and Express pipelines.

The following table provides the estimated current crude oil

capacity on these trunklines.

Pipeline Crude Type

Estimated

Annual Capacity

(thousand b/d)

EnbridgeLight 692

Heavy 1,186

Express Light/heavy (35/65) 280

Trans Mountain Light/heavy (80/20) 300

TOTAL 2,458

Enbridge Pipelines

The Enbridge system which operates in Canada and the

U.S. is the world's longest crude oil pipeline. It can deliver

more than 2 million b/d of crude oil and other commodities

from primarily western Canada to other markets in western

Canada, the U.S. upper Midwest and Ontario. In addition,

it connects to various pipelines in the U.S. such as

Spearhead and Mustang. It also receives crude oil from

U.S. pipelines for deliveries to markets in the U.S. Midwest

and Ontario.


27/48


In 2007, Enbridge added about 45,000 b/d of capacity

downstream of Superior, Wisconsin while no additional

capacity was added upstream of Superior. In April 2008,

Enbridge completed Stage 1 of the Southern Access

program (Line 61) from Superior to Delavan adding about

46,000 b/d of capacity, while the remainder of Line 61 from

Delevan to Flanagan began operating in May 2009.

Kinder Morgan Trans Mountain Pipeline

The Trans Mountain system originates in Edmonton,

Alberta and transports crude oil to the Vancouver area,

including its Westridge dock for vessel or barge loadings,

and by pipeline to refineries in Washington State.

The system also ships refined petroleum products from

the Edmonton refineries to Kamloops, British Columbia

and Vancouver.

It can currently transport about 300,000 b/d assuming

20 percent of the volumes are heavy crude oil. Note that

the actual available capacity varies depending on the

amount of heavy crude oil transported. Currently, about

25 percent of the volumes shipped are heavy crude oil.

In 2008, Trans Mountain completed TMX1, which consisted

of a Pump Station Expansion (PSE) and the Anchor Loop

Expansion (ALE) project.

Kinder Morgan Express-Platte Pipelines

The Express pipeline ships crude oil from Hardisty, Alberta

to PADD IV and has a capacity of 280,000 b/d. The pipeline

is underpinned by contracts, many of which expire in

2012, totaling 231,000 b/d with the remaining space being

available for spot shippers.

The Platte system connects to Express at Casper,

Wyoming and extends to Guernsey, Wyoming then to

Wood River, Illinois. Capacity from Guernsey to Wood

River is about 145,000 b/d and because of strong demand,

pipeline capacity has been constrained since January

2007. Therefore, Express is not operating at capacity dueto insufficient capacity on the Platte system.

Enbridge Spearhead (South) Pipeline

The Spearhead pipeline is connected to the Enbridge

Lakehead system at the Enbridge terminal near Chicago

and delivers light and heavy crude oil to Cushing,

Oklahoma. As of May 2009, the initiation point has been

changed to Flanagan, Illinois and the pipeline capacity

was increased by 65,000 b/d to 190,000 b/d.

Committed shippers have been allocated 30,000 b/d out

of this expanded capacity. This portion of the pipeline will

continue to operate in southbound service and is referred

to as Spearhead South. There are plans to reverse the

remaining portion of the pipeline that runs from Flanagan

to Hartsdale, Illinois to operate in northbound service. The

pipeline originally operated in northbound service but was

reversed in March 2006.

Enbridge Light Sour Line

As part of its Southern Lights diluent project, Enbridge

constructed a 20-inch diameter light sour crude oil line

from Cromer, Manitoba to Clearbrook, Minnesota. This line

came into service in February 2009 and has a capacity of

185,000 b/d. This expansion was built to provide access

to growing crude oil deliveries into the Enbridge Cromerterminal from southeast Saskatchewan.

ExxonMobil Mustang Pipeline

The Mustang pipeline is jointly owned by Enbridge

Pipelines and ExxonMobil and is connected to the

Enbridge Lakehead system at Lockport, Illinois and

extends to the Patoka, Illinois terminal. It has a heavy

crude oil capacity of about 91,000 b/d of which 88,000 b/d

is committed capacity. Nominations on the pipeline have

exceeded capacity since December 2005 and this trend is

expected to continue until there is new pipeline capacity

into the region.

ExxonMobil Pegasus Pipeline

The Pegasus pipeline was reversed in March 2006 and

runs from Patoka, Illinois to Nederland, Texas. It currently

provides western Canadian crude oil producers with the

only pipeline access to the U.S. Gulf Coast. It has a heavy

crude oil capacity of 66,000 b/d, of which 50,000 b/d is

committed capacity. Pegasus is scheduled to be expanded

to 96,000 b/d by the end of June 2009. Nominations haveexceeded capacity since it was reversed.

MinnCan Project

The Minnesota Pipeline is connected to the Enbridge

system at Clearbrook, Minnesota and transports crude oil

from Canada to Minnesota refineries owned by Flint Hills

in Rosemount and Marathon Oil in St. Paul.


28/48


Figure 4.1 Current Crude Oil Expansions from Western Canada

This line was operating at its capacity of 300,000 b/d. The

MinnCan project was designed to bring additional crude

oil supply from Canada to these refineries. It is a new

24-inch diameter pipeline that follows most of the original

systems route but ends at the Flint Hills refinery. This

endpoint provides a direct interconnection with that facility

and a direct interconnection, through existing pipeline

facilities, with Marathons refinery. The MinnCan project

was completed in the third quarter of 2008, providing up to

165,000 b/d additional crude to these refineries. This new

pipeline can also be expanded up to 350,000 b/d.

4.2 Crude Oil Transportation

Requirements

Given that the growth in western Canadian crude oil supplyis expected to be lower than in recent forecasts, the main

driver behind the proposals for new pipeline projects has

diminished substantially.

In 2008, the three major trunklines from western Canada

transported over 1.8 million b/d of crude oil. These pipelines

operated close to full available capacity for most of the year.

The pipeline expansion projects that have already been

approved and are in construction will add over one million b/d

in pipeline capacity by the end of 2010 (Table 4.1).

This capacity will meet and exceed the forecast supply

through to 2019 (Figure 4.1).

Table 4.1Approved Oil Pipeline Expansions from

Western Canada

Pipeline Proposed in

Service Date

Capacity

(thousand b/d)

TransCanada Keystone Dec 2009 435

Enbridge Alberta Clipper Jul 2010 450

TransCanada KeystoneExtension 4Q 2010 155

TOTAL Capacity 1,040

PortlandSarnia

Buffalo

Philadelphia

Toledo

Lima

Chicago

PatokaWoodRiver

Cushing

Flanagan

St. PaulGuernsey

Salt Lake City

St. JamesHouston

Hardisty

Edmonton

Anacortes

Burnaby

Express

Trans

Mountain

Platte

BP

Enbridge

Mid Valley

Capline



4

6

Montreal


29/48


Portland

Montreal

SarniaBuffalo

Philadelphia

Toledo

Lima

Chicago

PatokaWoodRiver

Cushing

Flanagan

St. Paul

GuernseySalt Lake City

St. JamesHouston

Hardisty

Edmonton

Anacortes

Burnaby

Express

TransMountain

Platte

BP

Enbridge

Mid Valley

Capline


4

Enbridge Ohio Access


Enbridge

Southern Access Expansion


10

16

Sunoco

Buffalo to Philadelphia

Sunoco to Toledo19 20

Enbridge Trailbreaker

Portland Pipeline Reversal17

17

Mustang Expansion

Enbridge Spearhead

Expansion (North)

Enbridge (North Dakota) Expansion

96

10

15

18

4.3 Crude Oil Pipeline

Expansions/Proposals

The remainder of this section focuses on pipeline

expansions and proposals to ship western Canadian crudeoil to the various markets and is divided into three areas:

U.S. Midwest, Ontario, Qubec, East Coast; the U.S. Gulf

Coast; and the West Coast.

There are currently two major crude oil pipeline expansions

in construction from western Canada to the U.S. Midwest:

the Enbridge Alberta Clipper and the TransCanada Keystone.

In addition, there are many other expansions or proposals

that will connect to these two pipelines to deliver western

Canadian crude oil to markets outside the U.S. Midwest such

as, Ontario, Qubec, PADD I and the U.S. Gulf Coast

(Figure 4.2). These projects are summarized in Appendix C.1.

4.3.1 Crude Oil Pipeline

Expansions/Proposals to the U.S.

Midwest, Ontario, Qubec and

the East Coast

TransCanada Keystone and Extension 4

The Keystone pipeline will run from Hardisty, Alberta to

terminals in Wood River and Patoka, and is scheduled to

be in-service in December 2009 with an initial capacity

of 435,000 b/d. The pipeline will include both new

construction and the conversion of existing pipe that is

currently in natural gas service. All key Canadian and

U.S. regulatory approvals are in place and construction

commenced in the second quarter of 2008.

Figure 4.2 Pipeline Proposals to the U.S. Midwest, Ontario, Qubec and U.S. East Coast


30/48


TransCanada is also proposing two extensions to the

Keystone pipeline. The first one is an extension to Cushing,

Oklahoma, which would connect at the Nebraska/

Kansas border. The extension would increase capacity by

155,000 b/d to an ultimate capacity of 590,000 b/d, and is

scheduled to be in-service in the fourth quarter 2010.

The second one is a Heartland Extension, which is a

600,000 b/d oil pipeline from Fort Saskatchewan to the

Keystone connection at Hardisty. It is scheduled to be in

service in the 2012 or 2013 timeframe.

TransCanada DilBit Pipeline

TransCanada is proposing a 400,000 b/d DilBit line from

the oil sands area of Fort McMurray to Hardisty, Alberta

with multiple receipt points. Potential timing for this project

is sometime between 2012 and 2014.

Enbridge Alberta Clipper 6

The 36-inch diameter Clipper pipeline is an expansion of

the Enbridge existing mainline system and will extend from

Hardisty, Alberta to Superior, Wisconsin with a connection

to the Minnesota pipeline at Clearbrook. The initial capacity

is 450,000 b/d of heavy crude oil and could be further

expanded to 800,000 b/d. It is scheduled to be in-service

in July 2010.

In May 2009, Enbridge extended Line 4 from Hardisty toEdmonton by connecting currently deactivated 48-inch

diameter segments with a new 36-inch diameter pipeline.

This extension was built to ensure sufficient heavy crude oil

capacity for Enbridge Alberta Clipper and has a capacity of

450,000 b/d. It can be expanded to an ultimate capacity of

800,000 b/d.

Enbridge Southern Access Expansion/

Extension 10

Enbridge completed construction of its Southern Accessexpansion program. The first phase, completed in April

2008, was a new 42-inch diameter pipeline from Superior

to Delavan, Wisconsin. The second phase build out to

Flanagan, Illinois was subsequently completed in May 2009

adding about 400,000 b/d of capacity. Further expansions

to 600,000 b/d and 800,000 b/d can be achieved by

adding pump stations. The Southern Access pipeline will

connect to the Enbridge Spearhead pipeline at Flanagan.

See sections on Enbridge Spearhead South and Enbridge

Spearhead North.

Enbridge is also proposing to extend the Southern

Access pipeline to the Patoka, Illinois hub from Flanagan

with a 36-inch diameter line that would have an initial

capacity of 400,000 b/d. The pipeline could be in-service

as early as 2012 but the actual timing will depend on the

market and regulatory approvals.

Enbridge Spearhead North 15

Since May 2009, the Southern Access pipeline has

connected with Spearhead at Flanagan. Currently,

Spearhead flows southbound but Enbridge intends to

reverse the segment of the pipeline between Flanagan,

Illinois to Hartsdale, Indiana (near Chicago) as part of the

Southern Access project. This segment, referred to as

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

scheduled to be in-service by Q3 2009.

Bow River Pipeline

The Bow River Pipeline system gathers oil production in

southern Alberta for delivery north to Hardisty, Alberta and

south to interconnecting export pipelines near the Montana

border. Inter Pipeline Fund (Inter Pipeline) plans to expand

oil delivery capabilities on the Bow River Pipeline system

and has received support in terms of 7-year contractual

commitments to transport 30,000 b/d. The project includes

the construction of 135 kilometres of new pipeline and will

enable the shipment of segregated crude oil streams from

Hardisty, Alberta to refining markets in Montana. The intent

of this project is to allow crude oil types sourced at

Hardisty to be shipped south as a distinct, segregated

stream and give Montana refineries access to multiple

grades of oil available at Hardisty without commingling with

the locally gathered Bow River oil stream. The project is

scheduled for completion in the first quarter of 2010.

Enbridge Line 5 Expansion

Line 5 extends from Superior, Wisconsin to Sarnia, Ontario.The expansion consists of adding Drag Reducing Agent

(DRA), and is expected to add 50,000 b/d of new light

crude oil capacity. Total capacity will then approximate

540,000 b/d. The timing for this project is undetermined.


31/48


Enbridge Line 6B Debottleneck and

Expansion

Enbridge is exploring various options to expand Line

6B which extends from Chicago, Illinois to Sarnia. Tankconstraints are currently limiting usable capacity from

290,000 b/d to 190,000 b/d. The project scope includes

two new tanks and pump stations which could add

between 65,000 and 135,000 b/d of capacity. Total new

capacity would approximate up to 425,000 b/d and the

projected in-service date is in the first quarter of 2010.

This new capacity would be required should Enbridges

Line 9 be reversed.

Enbridge Trailbreaker 17

Enbridge had been in discussions with industry to reverseLine 9 from Sarnia to Montreal in order to access markets

in Ontario, Quebc, the Maritimes and U.S. markets.

If reversed, Line 9 could ship up to 215,000 b/d of crude.

The project proposal included the reversal of one line on

the Portland Pipeline system to ship 200,000 b/d that

would be loaded on tankers. Portland Pipeline conducted

an open season for the reversal but did not receive the

level of firm volume commitments required to proceed.

At this time Enbridge is continuing its discussions with

industry with respect to appropriate timing and market

conditions needed to reconsider this proposal.

Enbridge North Dakota 9

The North Dakota pipeline connects to the Enbridge

Lakehead pipeline at Clearbrook, Minnesota and provides

producers in Montana and North Dakota with access to

markets in PADD II and Ontario. Increased production in

these areas has resulted in a need for additional pipeline

capacity. Enbridge added 30,000 b/d of capacity to the

North Dakota system in January 2007 and is planning

another expansion of 52,000 b/d by January 2010, which

would increase total system capacity to 162,000 b/d.

ExxonMobil Mustang Expansion 18

The Mustang expansion proposal would increase

throughput by adding new and modifying existing pump

stations. The pipeline can transport both light and heavy

crude. With the proposed expansion, the capacity could

increase by 38,000 b/d to 131,000 b/d.

Enbridge Line 6C

Enbridge is considering a new 36-inch diameter line from

its Griffith/Hartsdale terminal to Stockbridge, Michigan that

would parallel Line 6B. The intent is to deliver additional

supply to refineries in Michigan and Ohio. The estimated

capacity would be 400,000 b/d with an in-service date

of 2012. If needed, the line could be extended to

Sarnia, Ontario.

Sunoco Pipeline 19 20

Sunoco is proposing a crude oil pipeline to refineries in

the Philadelphia area. The market in this area includes

Sunocos two refineries in Pennsylvania and its New Jersey

refinery as well as the ConocoPhillips and Valero refineries

in Pennsylvania, New Jersey and Delaware. The projectincludes an expansion on the Enbridge system to Buffalo

and the use of the existing Sunoco right-of-way to build a

new 24-inch diameter pipeline from Buffalo to Philadelphia

The capacity of the pipeline would be about 400,000 b/d.

Sunoco is also considering expanding its Marysville to

Toledo pipeline from 190,000 b/d to 288,000 b/d.

Enbridge Ohio Access 16

Enbridge is proposing a phased approach to increase

the ability to transport additional deliveries of westernCanadian crude oil. The timing is scheduled to coincide

with the timing of expansions and conversions to process

more heavy crude oil at refineries in Detroit and Ohio. The

first phase would entail a debottlenecking of Line 17 and a

new pipeline ex-Griffith which would increase capacity by

20,000 b/d to 120,000 b/d to serve increased demand by

Marathons Detroit refinery.

Phase 2 would increase pipeline capacity from 120,000 b/d

to 400,000 b/d to serve the refineries in Toledo and Lima,

Ohio. Phase 2 includes a new 36-inch diameter line from

Stockbridge to Samaria and then 20-inch diameter lateralsto Toledo and Lima.


32/48



Expansions/Proposals to

the U.S. Gulf Coast

The U.S. Gulf Coast began receiving western Canadian

crude oil by pipeline in April 2006 through the reversed

ExxonMobil Pegasus pipeline, which is scheduled to

be expanded in June 2009. Prior to this, there wereand continue to be spot vessel movements of western

Canadian crude oil from the Trans Mountain Westridge

dock. Due to the large refining capacity of the PADD III

market, Canadian producers have been assessing various

pipeline proposals to the Gulf Coast (Figure 4.3).

There are two proposals for bullet lines from Alberta to

the U.S. Gulf Coast: the TransCanada Keystone XL and

Altex Energy - with total capacity of about 1,565,000 b/d.

Four pipeline companies (ExxonMobil/Enbridge, Sunoco,

ExxonMobil and Centurion) are proposing new pipelines,

expansions or reversal of existing lines to transport western

Canadian crude oil from the U.S. Midwest to the Gulf

Coast. The in-service dates for these proposals will depend

on market conditions. Proposals for projects targeting the

U.S. Gulf Coast are summarized in Appendix C.2.

BP/Enbridge Gulf Access Pipeline 12 13 14BP and Enbridge are proposing the Gulf Access Pipeline

which, in Phase 1, consists of the reversal and expansion

of BP #1 pipeline which will interconnect with Southern

Access at Flanagan, Indiana to move between 150,000 b/d

and 200,000 b/d of crude oil to Cushing, Oklahoma. From

Cushing, a new 250,000 b/d crude oil pipeline would be

built to the U.S. Gulf Coast with interconnections to the

Houston, Texas area refineries. Extensions could also be

built to reach either Port Arthur, Texas or Nederland, Texas.

Portland

Montreal

Sarnia

Buffalo

Philadelphia

Toledo

Lima

Chicago

Patoka

Cushing

St. Paul

Salt Lake City

St. JamesHouston

Edmonton

Anacortes

Burnaby

TransCanada

Keystone XL

Altex

Express

TransMountain

Platte

BP

Enbridge

Mid Valley

Capline

Flanagan

Guernsey

WoodRiver

Hardisty

4

5

8 6

10

11

12

13

14

22

21

23


BP/Enbridge GAP

Phase 1

BP/Enbridge GAP

Phase 2

BP/Enbridge GAP

Phase 3

Enbridge Southern Access Expansion


TransCanada

Louisiana Access


Centurion Pipeline

ExxonMobil/Enbridge

Pegasus Expansion

Sunoco to USGC

Figure 4.3 Pipeline Proposals to the U.S. Gulf Coast


33/48


Phase 2 of this project requires the building of the Enbridge

Southern Access Extension and the reversal of the

Enbridge Ozark pipeline. The Southern Access extension

pipeline would extend from Flanagan to Patoka, Illinois.

From Patoka, the crude oil could be transported to Wood

River, Illinois then flow on the reversed Ozark pipeline,

which has a capacity of about 200,000 b/d, to Cushing.

The system capacity to the U.S. Gulf Coast would be

approximately 400,000 b/d with an in-service date as early

as 2012.

With market support, Phase 3 of this project would

include another new pipeline that will extend from Patoka

to either Port Arthur or Nederland.

Sunoco Pipeline to U.S. Gulf Coast 21

Sunoco has a proposal to construct a new pipeline line

from Cushing, Oklahoma to its Wortham, Texas terminal

and then reverse a 26-inch diameter pipeline to Nederland,

Texas. The Cushing portion would have an initial capacity

of 300,000 b/d.

ExxonMobil Pipeline Enbridge Pipelines

Joint Initiative

ExxonMobil and Enbridge are proposing the Texas

Access pipeline which consists of a new 30-inch

diameter crude oil pipeline from Patoka to Beaumont,

Texas with a capacity of 445,000 b/d, and a connecting

lateral to Houston. With horsepower additions, the

pipeline could expand to more than 550,000 b/d.

TransCanada Keystone XL and Louisiana

Access options 8 23

The TransCanada Keystone XL project is a proposal for a

36-inch diameter pipeline from Hardisty, Alberta where

it would connect with the proposed Cushing Extension at

the Nebraska/Kansas border, and then to Port Arthur andHouston, Texas. The intent is to have a bullet pipeline from

Hardisty to the U.S. Gulf Coast by the end of 2012.

The initial pipeline capacity would be 700,000 b/d;

380,000 b/d of this capacity has been secured by

contracts. The pipeline could be further expanded to

1.5 million b/d.

Additional options being proposed include access to

Louisiana by either building new or using existing facilitiesfrom Patoka to New Orleans or building a new line from

Port Arthur, Texas to New Orleans. Proposed project timing

is between 2014 and 2016.

Altex Energy 5

In light of the lower crude oil supply forecast, industry

has been re-evaluating the timing and need for the Altex

proposal. Altex is proposing a 36-inch diameter pipeline

employing proprietary technologies that would use less

diluent per barrel of bitumen than is required by otherpipelines. The pipeline would transport heavy crude oil

or bitumen from various locations in Alberta to the Port

Arthur/Beaumont, Texas area. The initial capacity is

estimated at 425,000 b/d and could expand to

one million b/d with additional pumps.

ExxonMobil Pegasus Expansion 22

The Pegasus expansion would increase capacity by 30,000 b/d

from Patoka, Illinois to Nederland, Texas with a start up

date of June 2009.

Centurion Pipeline 11

Centurion Pipeline, owned by Occidental Petroleum,

will reverse an existing 16-inch diameter common carrier

pipeline to deliver western Canadian heavy crude oil

from Cushing to Slaughter, Texas. In July 2008, Holly

Corporation (Holly) agreed to build additional infrastructure

from Slaughter to its Navajo refinery in New Mexico. These

projects are expected to be complete and in service by

the fourth quarter of 2009. Previously, Holly had entered

into shipping commitments on both the Keystone and

Spearhead pipelines for Canadian crude oil delivered

to Cushing, Oklahoma.


34/48



Expansions/Proposals to

the West Coast

The map in Figure 4.4 illustrates crude oil pipeline

expansions from western Canada to the West Coast.

Appendix C.3 provides a summary of all proposals.

Kinder Morgan TMX2, TMX3 and

Northern Leg Expansion 2 3

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

by 2012. The scope of TMX2 includes a new line from

Edmonton, Alberta to Kamloops, British Columbia.

TMX3 includes a new line to the Washington State

refineries and a second berth at the Westridge dock.

TMX3 could provide an additional 320,000 b/d of new

capacity by 2013. These expansions would provide

additional access to Vancouver, Washington State and

other markets served by oil tankers and barges which load

at its Westridge dock.

TMX Northern Leg is a pipeline with a capacity of

400,000 b/d, extending from its existing system near

Rearguard, British Columbia to a deep water port facility

at Kitimat, British Columbia that would accommodateVery Large Crude Carriers (VLCC) for delivery to PADD V

or the Far East. Depending on industry support, the

pipeline could be in service as early as 2014.

Portland

Sarnia

Buffalo

Philadelphia

Toledo

Lima

Chicago

PatokaWoodRiver

Cushing

Flanagan

St. Paul

Guernsey

Salt Lake City

St. JamesHouston

Hardisty

Edmonton

Anacortes

Burnaby

Express

TransMountain

Platte

BP

Enbridge

Mid Valley

Capline

Enbridge GatewayKitimat

Kinder Morgan

TMX2 Expansion

TMX3 Expansion

3

1

2

TransCanada

AB-California7 Montreal

Figure 4.4Pipeline Proposals to the U.S. West Coast


35/48


Kinder Morgan Vancouver Port

Development

Kinder Morgan is proposing further development at

the Vancouver port area by building a pipeline from theWestridge Dock to the Vancouver Wharves and/or building

a line to the Delta Port enabling access to larger tanks

thereby increasing export capacity.

Enbridge Northern Gateway 1

The Northern Gateway project includes the construction of

a new 36-inch diameter pipeline from Edmonton, Alberta

to a deep water port at Kitimat, British Columbia and is

being designed to provide 500,000 b/d of crude oil export

capacity. Crude oil would be loaded on tankers for delivery

to PADD V and the Far East. Enbridge is, depending onindustry support, anticipating submitting an application to

the National Energy Board in the second quarter of 2009.

TransCanada AB California 7

TransCanada is in discussion with parties to transport

400,000 b/d of western Canadian crude oil by pipeline

to California to access over 1.8 million b/d of refining

capacity. The estimated in-service date is 2016.

4.3.4 Other Proposals

Canadian National (CN) Railways and Altex are jointly

explorting a Pipeline on Rail strategy. This proposal could

transport as little as 10,000 to 20,000 b/d of undiluted

or under-diluted bitumen in heated railcars. Through

connections to other railroads, CN can access the majority

of U.S. Gulf Coast refineries. This rail solution would also

be suitable for condensate imports. CN has expressed that

if there was interest, there would be no upper limit to thevolumes that could be transported via rail.

Portland

Sarnia

Philadelphia

Toledo

Lima

Chicago

Cushing

St. Paul

Salt Lake City

St. JamesHouston

Anacortes

Burnaby

Express

TransMountain

Platte

Enbridge

Mid Valley

Guernsey

Hardisty

Capline

Capline/Chicap

Enbridge Southern Lights

Enbridge

Gateway Condensate Import

TransCanada

Edmonton

PatokaWoodRiver

24

25

26

27

Montreal

Figure 4.5 Diluent Pipeline Proposals


36/48


4.3.5 Diluent Pipeline Proposals

Figure 4.5 shows the current diluent pipeline proposals.

Enbridge Southern Lights 26

The project is in response to demand by western Canadian

heavy crude oil producers for additional diluent supply from

various sources in the U.S. Midwest. The project includes

a new 16-inch diameter diluent line from Flanagan, Illinois

(near Chicago) to Clearbrook, Minnesota, and the reversal

of Line 13 from Clearbrook to Edmonton, Alberta.

The capacity of the diluent import line is 180,000 b/d,

of which 77,000 b/d is for committed shippers, and

can be expanded to 300,000 b/d. The in-service date

of July 2010 will coincide with crude oil expansions onthe Enbridge mainline system (i.e. Southern Access and

Alberta Clipper/Line 4 extension) in order that eastbound

capacity is unaffected.

Joint Capline/Chicap Industry Initiative 27

The owners of both Chicap and Capline are co-operating

to enable the movement of a limited amount of diluent

from the U.S. Gulf Coast to Chicago by mid 2010. The

plan is for the Chicap pipeline to connect to the Enbridge

Southern Lights pipeline. Chicap runs from Patoka, Illinois

to Manhattan and Mokena, Illinois. Ultimate capacity onthe pipeline is estimated to be 320,000 b/d operating in

batched diluent and light crude oil service. Initial total

capacity of the pipeline in 2010 will be about 50 percent

of the ultimate capacity. Capline extends from St. James,

Louisiana to Patoka and has a capacity of more than

one million b/d. The level of diluent deliveries is not known

at this time.

Enbridge Northern Gateway Diluent 24

As part of its Northern Gateway crude oil pipeline project,

Enbridge is proposing a 20-inch diameter, 175,000 b/d

diluent import pipeline that would extend from Kitimat,

British Columbia to Edmonton, Alberta. It would supply

diluent to western Canadian heavy crude oil producers.

An application to the National Energy Board is expected

in the second quarter of 2009.

TransCanada Diluent Pipeline 25

TransCanada is proposing a diluent line from Fort

Saskatchewan, Alberta to Fort McMurray, Alberta with an

initial capacity of 120,000 b/d and multiple delivery points.

The possible in-service date is between 2012 and 2014.

4.4 Pipeline Summary

The major pipeline proposals that are currently under

construction will add over one million b/d in pipeline

capacity exiting western Canada by the end of 2010.

A corresponding growth in supply of one million b/d is not

forecasted until 2016. Pipeline projects that are currently

underway or in the regulatory process will provide excess

capacity for a number of years and sufficient pipeline

capacity available exiting Western Canada throughout the

forecast period.

There are still many pipeline proposals being presented.

However, many proposals were developed in response to

earlier expectations that additional capacity was required

to meet more rapid growth in oil sands production than is

currently being forecast. Given the current supply outlook

and market conditions, the timing of many of these pipeline

proposals has been delayed.


37/48


GLOSSARYAPI Gravity A specific gravity scale developed by the American Petroleum Institute (API) for measuring the

relative density or viscosity of various petroleum liquids.

BarrelA standard oil barrel is approximately equal to 35 Imperial gallons (42 U.S. gallons) orapproximately 1

Documents

31015785 2009 CAPP Crude Oil Forecast Markets