JPM - Canadian Oils Sands Primer

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North America Equity Research20 November 2006

Canadian Oil SandsDigging Deep for Value: A Primer

Integrated Oils and IndependentRefiners

Jennifer Rowland, CFAAC

(1-212) 622-6702

[email protected]

Katherine Lucas, CFA(1-212) 622-6451

[email protected]

Daniel Vetter, CFA(1-212) 622-6628

[email protected]

J.P. Morgan Securities Inc.

See page 50 for analyst certification and important disclosures, including investment banking relationships .JPMorgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firmmay have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor inmaking their investment decision.

Albertas Oil Sands Areas

Source: EUB.

Oil Sands Heavy Hauler

Source: Canadian Natural Resources Limited, Horizon

Oil Sands Project.

In this report, we discuss the outlook for the Canadian oil sands industry.

We explain the resource itself, comparing it to other major hydrocarbon

resource plays and discussing some of the properties that differentiate it

from conventional hydrocarbons. We also discuss the production process,

reviewing technologies, methods, and challenges. In addition, we discuss

the economics of the Canadian oil sands. Finally, we highlight major

development projectsboth those currently producing and those slated to

commence production in the next several yearsand major players.

Canadian oil sands have garnered significant attention in recent

years as one of the more prominent and promising resource plays.

As market conditions have changed and technology has advanced, theCanadian oil sands have become a more attractive opportunity.

Moreover, the stability of the government and the fiscal regime in

Canada relative to other regions of the world with large resource bases is

nearly unparalleled, heightening the appeal of the oil sands play for

multinational oil companies.

Production set to triple by 2015. Oil sands production in Alberta has

grown at a healthy rate of 9% over the 1996-2005 time frame to

1 MMbpd. Based on announced projects, oil sands production is

expected to continue at a similar growth rate through 2015, reaching

3 MMbpd.

Oil sands production poses unique challenges and benefits. While

some of the technological and economic challenges are by no means

unique to oil sands, the developments do consume vast amounts of

energy and face relatively stringent environmental regulations. On the

other hand, low geological risk and a friendly fiscal regime add to the

appeal of the play.

Economics support bitumen production outpacing upgrading

capacity. Our economic analysis indicates that the greatest challenge to

oil sands project economics is the cost of upgrading. We believe that at

current capital cost assumptions, stand-alone mining and in-situ

development projects will generate double digit returns even on a

$35/bbl long term crude price, but that integrated upgrading projectsrequire a crude price of $40-45 to generate at least a 10% return. We

believe this will result in a shortage of upgrading capacity and additional

downstream partnerships as producers seek an outlet for bitumen.


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Jennifer Rowland, CFA(1-212) [email protected]

Table of ContentsOverview ...................................................................................3

Worlds second-largest resource base..........................................................................3Physical properties.......................................................................................................4Origin and current position ........... ........... .......... ........... ........... ........... .......... ........... ....4Development history has been influenced primarily by the crude price.......... ............5

Production Outlook ..................................................................6

Marketing Oil Sands.................................................................9

Synthetic crude or bitumen? ........................................................................................9Available refining capacity for crude off-take ........... ........... ........... ........... ........... ....11Recent deals highlight growing integration between US refiners and Canadian oil

sands producers..........................................................................................................12Pipeline transportation another bottleneck in the supply chain..................................13

Challenges Facing the Industry ............................................15

Exploration risk..........................................................................................................16Energy usage..............................................................................................................16Environmental constraints .........................................................................................17Recoverability............................................................................................................18Fiscal regime..............................................................................................................18Cost inflation..............................................................................................................19Crude quality: lower than conventional crude ........... .......... ........... ........... .......... ......20

Economic Analysis: Value Creators or Big Digs?...............20

Mining........................................................................................................................20In-situ development ...................................................................................................23

Production Techniques..........................................................24

Mining: scratching the surface...................................................................................24In-situ: going deeper to access more resource .......... ........... .......... ........... ........... ......31Upgrading: extracting more value from the barrel.....................................................36

AppendicesAppendix I: Glossary of key terms........................................39

Appendix II: Oil Sands Projects ............................................41

Appendix III: Mining Economic Model..................................45

Appendix IV: In-Situ Economic Model ..................................46


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OverviewThough the Canadian oil sands have been under commercial development since the

1960s, they had until the late 1990s largely been the territory of Canadian companies.

Low crude oil prices and the technical and financial challenges of extracting the

bitumen and rendering it refinery-ready made the play less attractive than some of

the more conventional oil and gas plays around the world. As market conditions

have changed and technology has advanced, the Canadian oil sands have become a

more attractive opportunity. Moreover, the stability of the government and the fiscal

regime in Canada relative to other regions of the world with large resource bases is

nearly unparalleled, heightening the appeal of the oil sands play for multinational oil

companies. Recent announcements from major multinational companies, namely

ConocoPhillipss integrated joint venture with EnCana and Royal Dutch Shells

tender offer for the remaining outstanding shares of Shell Canada, emphasize theimportance of the Canadian oil sands as a vast play creeping to the top of the list of

global resource opportunities.

Worlds second-largest resource base

Second only to Saudi Arabia in terms of total reserves. With total crude oil

reserves of nearly 180 billion barrels (of which 174 billion barrels are oil sands),

Canada holds one of the largest concentrations of hydrocarbons in the world, second

only to Saudi Arabia (see Figure 1 below). The only other known deposit of heavy

oil of significant size is in the Orinoco Belt in Venezuela. However, the resources in

the Orinoco Belt are typically considered extra heavy oil rather than oil sands, though

the distinction is largely academic.

Large and under-exploited. Not only are the oil sands reserves one of the largest

concentrations of hydrocarbons, they are also one of the most under-exploited.

According to the Alberta Energy and Utilities Board, as of 2006, less than 3% of the

initial established crude bitumen reserves have been produced since commercial

production began in the late 1960s.

Figure 1: Canadas oil sands are one of the largest deposits of crude in the world

crude oil reserves ranked by country, billion barrels as of year-end 2005

0

50

100

150

200

250

300

Saudi

Arabia

CanadaVenezuela Iran Iraq Kuwait UAE Russia Libya Nigeria United

StatesConventional Oil Oil Sands / Heavy Oil

Source: Oil and Gas Journal, Alberta Energy and Utilities Board, Canadian National Energy Board, JPMorgan.

The stability of the government

and the fiscal regime in Canada

relative to other regions of the

world heightens the appeal of

the oil sands resource play for

multinational oil companies.

Due to its large oil sands

resource base, Canada ranks

second only to Saudi Arabia in

terms of total crude reserves.


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Physical properties

Oil or molasses? Oil sands are a non-conventional source of hydrocarbons

comprised of a mixture of sand, water, and crude bitumen - a thick, heavy oil with ahigh carbon/hydrogen ratio. At normal temperatures, bitumen is in a semi-solid state

with a consistency similar to that of tar or molasses. Bitumen has a very high density

and is extremely viscous, resistant to flow in its natural state. As such, bitumen must

be diluted or upgraded before it can be moved through a pipeline. Bitumen also has

high sulfur content and high metals content. Compared with other world crude oil

grades, it is a very heavy, very sour crude oil (see Table 1 below).

Table 1: Bitumen is very heavy and very sour compared with other crude grades, but the endproduct of oil sands upgrading is a high-quality crudeProperties of various crude grades

Crude grade Gravity (API)Specific Gravity

(15C / 60F) Sulfur (% wt)

WTI 39.6 0.827 0.24Brent Crude 38.3 0.833 0.37West Texas Sour 33.0 0.860 1.60Maya 22.0 0.922 3.30Cold Lake bitum en 8.7 1.009 4.25

Athabasca bitum en 7.9 1.015 4.66Syncr ude Sweet Blend 31.0 0.871 0.15

Source: EIA, Pemex, CERI, Syncrude, JPMorgan.

Bitumen comes in various qualities. Bitumen may comprise up to 18% of the

overall mixture, and concentrations of more than 10% bitumen are considered to be

high-quality rich deposits. By contrast, deposits with less than 6% bitumen are

considered not only poor or lean, but also economically unfeasible to mine. On

average, two tons of oil sands are required to produce one barrel of crude oil.

Origin and current position

The exact origin of the oil sands is under dispute among geologists, but the most

widely accepted theory is that the hydrocarbons originated in shale in the Alberta

Sedimentary Basin and soaked into the silt sediments, the two mixing under pressure.

The result was a deposit of hydrocarbon-laden silt sitting near the surface. In their

current state, the oil sands are resting under a layer of overburden, a deposit that does

not contain hydrocarbons and that, in the case of mineable deposits, must be removed

before extraction can begin. The overburden, in turn, sits under a layer of muskeg, a

swampy layer of decaying vegetation 3 to 10 feet (1 to 3 m) thick.

Over 80% of Canadas oil sands are in the Athabasca area. Canadas oil sands

deposits are located in northern Alberta, and are classified in three designated oilsands areas (OSAs): Athabasca, Cold Lake, and Peace River (see Figure 2). There

are 15 major oil sands deposits located throughout the OSAs. The Athabasca area

contains the largest of these deposits, the Wabiskaw-McMurray deposit, which is

currently under active development. Since the resources in the Athabasca deposit are

close enough to the surface to be mineable, most of todays active development is in

this region. Other significant deposits are Cold Lake Clearwater and the Peace River

Bluesky-Gething (see Table 2 below).

At normal temperatures, bitumen

is in a semi-solid state with aconsistency similar to that of tar

or molasses and is resistant to

flow in its natural state.

The majority of oil sandsdevelopment activity is

occurring in the Athabasca area,

where over 80% of the resources

are located.


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Figure 2: Albertas Oil Sands are located in the nort hern part of the pro vince in th ree OSAs

Source: Alberta Energy and Utilities Board

Table 2: The Athabasca OSA holds the majority of Alberta's bitumen resourcesinitial in place volumes of crude bitumen

Area Size (sq km) Resources (MMbbls) % of resou rceAthabasca 102,760 1,369,478 81%Cold Lake 26,270 195,072 12%Peace River 17,250 129,058 8%Total 146,280 1,693,608 100%

Source: Alberta Energy and Utilities Board, JPMorgan.

Development history has been influenced primarily by thecrude price

After initial studies in the 1910s and 1920s proved that the bitumen could

successfully be extracted from the oil sands, the first proposed use of the resource

was as a paving material. Though technically a successful effort, bitumen was

deemed uneconomic when compared with asphalt. In the 1930s, the Abasand Oils

company began producing diesel fuel from crude bitumen. Interest in this effort

peaked during World War II, but waned thereafter.

In the 1950s, the government made efforts to encourage further development of the

oil sands, indicating that despite the up-front capital costs, the oil sands could becommercially viable. In the early 1960s, the Albertan government put forth a plan

for the orderly development of the oil sands, and later that decade, the pioneering oil

sands development came online.


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Figure 3: Interest in the development of th e oil sands has inc reased as crude prices have risen

crude oil price in 2004 dollars ($/bbl)

0

20

40

60

80

100

1920 1930 1940 1950 1960 1970 1980 1990 2000

Source: BP Statistical Review 2006, CERI, Syncrude, JPMorgan.

Three main projects form the backbone of the oil sands industry. Great

Canadian Oil Sands (GCOS), later folded into what is now Suncor, began initial

development in 1963. Sun Oil (at the time) invested nearly Cdn$250 million in what

was described as the biggest gamble in history to develop a facility to mine and

upgrade crude bitumen north of Fort McMurray. The facility came online in 1967 at

a production rate of 45,000 barrels per day.

In 1964, the Syncrude consortium was formed with an initial objective of

determining the commercial viability of mining the Athabasca oil sands for crude oil.

A proposal was granted approval in 1969 and in 1973, construction on the Mildred

Lake site began. The first barrels were shipped in 1978.

The third flagship project in the development of the oil sands was also the first torecover bitumen from below the surface as opposed to using strip mining techniques.

In 1985, Imperial Oil began commercial development at Cold Lake following

extensive research and a pilot phase in the 1960s and 1970s. The Cold Lake

development employs Cyclic Steam Stimulation (CSS) and produces from the

Clearwater formation, more than 1,300 feet (400 m) below the surface. Initial

production volumes were around 50,000 barrels per day, on scale with early

production volumes at Suncor and Syncrude's mining developments, proving the

viability of in-situ recovery.

Production Outlook

Production is expected to triple by 2015. Unlike conventional crude oil production

in Alberta, oil sands production in Alberta has grown at a healthy rate of 9% over the

1996-2005 time frame to 1 MMbpd, according to the Alberta Energy and Utilities

Board (EUB). By contrast, conventional crude production in Alberta has declined by

roughly 6% annually over the same period. Based on the National Energy Boards

(NEB) base case scenario, which does not assume that all announced projects move

forward, oil sands production is expected to continue at a similar growth rate through

2015, reaching 3 MMbpd, an annualized growth rate of over 10%.

Oil sands production is expected

to grow from 1 MMbpd to

3 MMbpd by 2015E, an

annualized growth rate of more

than 10%.

1920s: Hot water flotationmethods proven tose aratesandandbitumen

1930s: Diesel produced fromoil sands at Abasand Oilsventure near Ft McMurray

1967: Great CanadianOil Sands beginsproduction

1978: Syncrudebegins production

1985: Cold Lakebegins commercialin-situ production

2001: Foster Creekbegins commercialin-situ SAGDproduction


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Figure 4: Oil sands production is expected to triple from 2005 to 2015E

production of conventional crude and oil sands, mbpd

Conventional crude

Oil sands

0

500

1,000

1,500

2,000

2,500

3,000

3,500

1996 1998 2000 2002 2004 2006E 2008E 2010E 2012E 2014E

Source: NEB, JPMorgan estimates.

Production to become more evenly split between mining and in-situ operations

by 2015. The bitumen in Albertas oil sands can be produced using either mining

techniques, for those deposits close to the surface, or in-situ techniques for those

located deeper than 250 feet. Only the Athabasca OSA has oil sands shallow enough

to be recovered with mining techniques, meaning in-situ recovery is necessary for

Cold Lake, Peace River, and a portion of the Athabasca deposits. Mining has been

responsible for nearly 70% of crude bitumen production to date and represents nearly

75% of all current development projects. However, less than 20% of the remaining

established oil sands reserves are recoverable with mining operations, meaning that

in-situ production will become increasingly important as the resource base is

exploited. By 2015, we estimate that 45-50% of oil sands production in Alberta will

come from in-situ operations, up from 28% in 2005.

Figure 5: Most current oil sands production isfrom mining operations

production balance, 2005

Mining

72%

In situ

28%

Source: NEB, JPMorgan.

Figure 6: but by 2015E the split sho uld befairly balanced

production balance, 2015E

Mining

54%

In situ

46%

Source: NEB, JPMorgan.

Future mining projects

At present, there are several large-scale mining projects slated to come online. These

projects are expected to increase mined bitumen volumes by more than 1.6 million

barrels per day by 2015, assuming all announced projects move forward. Major

projects consist of: Athabasca Oil Sands Muskeg and Jackpine, CNRLs Horizon,

For an explanation of mining and

in-situ production techniques,

please see Production

Techniques on page 24.


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Imperials Kearl Lake, Petro-Canadas Fort Hills, Suncors Voyageur, Syncrudes

Mildred Lake and Aurora, Synencos Northern Lights, and Totals Joslyn projects

(see Table 3).

Table 3: Most upcom ing mining projects are new developments, though cur rent projects have planned expansions in the coming years

Mining production (mbpd) Upgrading capacity (mbpd)Operator Project s Type Start-up Current by 2010 by 2015 Current by 2010 b y 2015Athabasca Oil Sands Muskeg Expansion 2010 155 270 270 155 290 290Athabasca Oil Sands Jackpine New 2010 - 100 300 - - -CNRL Horizon New 2008 - 135 415 - - 203Imperial Kearl Lake New 2010 - 100 200 - - -Petro-Canada Fort Hills New 2011 - - 190 - - 190Suncor Voyageur Expansion 2008 260 283 283 260 532 610Syncrude Mildred Lake & Aurora Expansion 2011 350 350 536 350 350 536Synenco Northern Lights New 2010 - 50 100 - 50 100Total Joslyn New 2010 - 50 100 - 50 100TOTAL 765 1,338 2,394 765 1,272 2,029

Source: National Energy Board, Company reports, JPMorgan. Table includes all announced projects.Note: Suncors Voyageur upgrader will take mined and in-situ production.

Future in-situ projects

We estimate that in-situ projects slated to come online through the end of the decade

will increase in-situ production to more than 1.3 million barrels per day, increasing in

the five years thereafter to more than 2.3 million barrels per day by 2015. We expect

the majority of production will be in the Athabasca OSA and will employ steam-

assisted gravity drainage (SAGD) technology.

Table 4: In-situ production is expected to reach over 2 MMbpd by 2015

Production (mbpd)Operator Projects Location Technology Initial start-up 2005 by 2010 by 2015Black Rock Orion Cold Lake THAI 1997 1 21 21CNRL Birch Mountain, Gregoire

Lake, Kirby, PrimroseAthabasca, Cold Lake SAGD 1985 50 110 200

Connacher Great Divide Athabasca SAGD 2006 - 10 10ConocoPhillips Surmont Athabasca SAGD 2006 - 50 100Devon Jackfish Athabasca SAGD 2008 - 70 70EnCana Christina Lake, Foster

Creek, BorealisAthabasca SAGD 2001 50 245 500

Husky Sunrise, Tucker Lake Athabasca, Cold Lake SAGD 2008 - 130 230Imperial Cold Lake Cold Lake CSS 1985 140 170 170JACOS Hangingstone Athabasca SAGD 2002 10 35 60MEG Christina Lake Athabasca SAGD 2007 - 25 25North American Kai Kos Dehseh Athabasca SAGD 2008 - 40 160OPTI/Nexen Long Lake Athabasca SAGD 2003 3 147 219Petro-Canada MacKay River Athabasca SAGD 2002 35 75 75Shell Cadotte Lake, Carmon

CreekPeace River CSS, SAGD 1979 12 30 100

Suncor Firebag Athabasca SAGD 2004 19 170 350Total Joslyn Athabasca SAGD 2006 - 25 40Value Creation Halfway Creek Athabasca SAGD 2009 - 10 10

TOTAL 319 1,362 2,339

Source: National Energy Board, company reports, JPMorgan. Note: Table includes all announced projects.


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Figure 7: Based on announced projects, over80% of in-situ production will come from th eAthabasca OSA by 2015E . . .

%

Peace

River

4%

Cold Lake

14%

Athabasca

82%

Source: NEB, company reports, JPMorgan.

Figure 8: . . . and 90% of in-situ pro ducti on willemploy SAGD technology

%

THAI 1%

CSS

9%

SAGD

90%

Source: NEB, company reports, JPMorgan.

Marketing Oil Sands

The synthetic crude oil and crude bitumen produced in Alberta far exceeds the local

capacity to refine the crude into finished products. Thus, whether fully upgraded

synthetic or a diluted heavy blend, the resulting product must be marketed to

locations outside Alberta, and frequently outside Canada.

Synthetic crude or bitumen?A key decision facing oil sands producers is whether or not to upgrade the

bitumen. Once bitumen has been extracted from the oil sands deposits, either

through mining or in-situ operations, the resulting product is a heavy oil, inferior in

quality to the heaviest of conventionally produced crude oils. Producers are faced

with the choice of selling a heavy crude oil into the market or upgrading the bitumen

into a lighter synthetic crude oil (SCO). Suncor and Syncrude upgrade their

respective bitumen production, producing synthetic crude oil and high-value

products. However, given the costs and logistical constraints associated with

constructing or securing upgrading capacity, many oil sands producers sell a lower-

value, heavy bitumen blend into the market.


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Figure 9: Year to date, the spread between bitumen blends and s ynthetic crude oil h as averagednearly US$30 per barrel

bitumen blend and synthetic crude oil prices, 2006YTD US$/bbl

-

20

40

60

80

Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06

Bitumen blend SCO

Source: Bloomberg, JPMorgan.

Recent crude quality differentials have made upgrading an enticing option.

With the light-heavy (WTI-Maya) differential hovering around $15 per barrel, and

bitumen blends priced at a discount to Maya, upgrading becomes an attractive option

for oil sands operators. At present, all the bitumen that is mined in Alberta is

upgraded, while bitumen that is recovered with in-situ techniques may be either

upgraded or blended with diluent and shipped as a heavy crude via pipelines to

refineries that can handle the lower-grade hydrocarbons.

Figure 10: Bitumen blends trade at a significant discount to even heavy crude oil such as Maya

crude oil and bitumen blend prices, US$ per barrel

0

20

40

60

80

Jan-06 Mar-06 May-06 Jul-06 Sep-06 Nov-06

WTI Maya

Flint Hills Bitumen @Hardisty Lloyd Blend @Edmonton

Source: Bloomberg, JPMorgan.

Synthetic crude easier to market, but can be expensive to produce. Synthetic

crude oil is worth more to refiners, as SCO is very high quality and easily refined

into high-value, light products without requiring special processing capacity such as

a coker. Thus, the product commands a market premium to bitumen. In addition, as

no specific refinery configuration is required, SCO can be marketed without a

specific end-user in mind. However, producing SCO requires either captive

upgrading capacity or a firm agreement with a third-party upgrader, adding both

capital and operating costs. Installing upgrading capacity today can require

significant capital costs up front. Based on recently announced projects, we estimate


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the all-in cost of a new upgrader to average US$25,000-35,000 per barrel per day of

capacity, giving an average-sized 150,000 barrel per day upgrader a US$4.5 billion

price tag, at the midpoint. In addition, expansions to existing upgraders can cost overUS$20,000 per barrel per day of capacity, as is the case with Suncors US$1.8 billion

90,000 barrel per day expansion of its existing upgrader.

Electing to sell bitumen is a less capital-intensive choice, but requires the use of

a diluent. Non-upgraded bitumen must be diluted with a lighter-viscosity product,

known as diluent, before it meets pipeline shipping specifications. Bitumen is

commonly diluted with condensate in order to increase its API gravity and render it

pipeline-ready. On average, blended bitumen requires approximately 30%

condensate by volume this blend is referred to as dilbit. Athabasca Bitumen

Blend contains 33% condensate and increases the API gravity of Athabasca bitumen

from 7.9 to 22.5, approximately the specific gravity of Maya crude. Similarly, Cold

Lake Bitumen Blend contains 28% condensate by volume, raising the API gravity

from 8.7 to 22.5. Synthetic crude is another diluent. However, as synthetic crude isheavier than condensate, about 50% SCO by volume is required to lower the

viscosity of bitumen to a level appropriate for pipeline transport. Bitumen diluted

with synthetic crude oil is commonly called synbit.

Available refining capacity for crude off-take

Refining capacity in Alberta is limited, and coking capacity is even more

limited. There are only five refineries in Alberta with a total of just over 440,000

barrels per day of refining capacity. However, the refineries are of relatively low

complexity, and coking capacity among the refineries is limited to 15,000 barrels per

day. With production of non-upgraded bitumen alone totaling nearly 440,000 barrels

per day in 2005, and total synthetic crude oil and bitumen blends exceeding 1 million

barrels per day, production from the Canadian oil sands must be sent to refinersoutside the region.

Table 5: Refineries in Alberta are ill-equipped to process Canadian oil sands production

Alberta refineries

Company LocationCrude Capacity

(bpd)Nelson

ComplexityCoking Capacity

(bpd)Shell Scotford 97,900 6.5 -Petro-Canada Edmonton 125,200 7.9 7,500Parkland Refining Bowden 6,000 12.7Imperial Oil Edmonton 187,200 7.7 -Husky Oil Lloydminster 25,000 2.9 7,500

Total 441,300 7.3 15,000

Source: Oil and Gas Journal, CERI, JPMorgan.

Much of the Canadian heavy crude blends are sent to refineries in the mid-

continent (PADD 2) region of the United States, where refining capacity exceeds

3.6 MMbbls per day, roughly 20% of overall US capacity. At present, three major

refineries process the majority of Canadian heavy crude: BP's Whiting refinery

(405,000 bpd), ExxonMobil's Joliet refinery (238,000 bpd), and Flint Hills's

Rosemount refinery (280,000 bpd).

Dilbit is a bitumen blend of

roughly 30% diluent, 70%

bitumen.

Synbit is a bitumen blend of

50% synthetic crude oil and 50%

bitumen.


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Figure 11: Refiners wit h signi ficant PADD 2 capacity are likely purchasers of Canadian heavycrude

PADD 2 refining capacity by company, mbpd

-

100

200

300

400

500

600

700

MRO BP COP VLO Flint Hills SUN XOM PDVSA Farmland

Industries

FTO

Source: Oil and Gas Journal, company reports, JPMorgan.

Though there is significant refining capacity in the Gulf Coast region (PADD 3),

where nearly half of all US capacity is located, Canadian heavy crudes must displace

heavy crudes from Latin America as they migrate south. Thus, it is likely that the

majority of Canadian heavy crudes will be sent to refineries in PADD 2.

Recent deals highlight growing integration between USrefiners and Canadian oil sands producers

Recent transaction announcements demonstrate the increasing integration between

US refiners and Canadian oil sands producers. These announcements include the

joint venture between ConocoPhillips and Encana, Marathon's request for proposals

from oil sands producers for the formation of an oil sands joint venture, and BP's

intention to increase Canadian crude oil processing capability at its Whiting refinery.

In our view, this trend will likely continue, as we see a shortage of upgrading

capacity expansion in Canada, and we believe producers will increasingly seek

external markets for their bitumen.

EnCana/ConocoPhillips: spanning the value chain

In October 2006, ConocoPhillips (COP) and Encana (ECA) announced a deal

creating two separate but operationally intertwined joint ventures, linking two of

COPs North American refineries, Borger and Wood River, with ECAs Foster Creek

and Christina Lake in-situ oil sands production operations located south of Fort

McMurray, Alberta. Plans are to grow production at Foster Creek and Christina

Lake from 50 mbpd currently to 400 mbpd by 2015. At the same time, thecompanies will expand the combined capacity of the two refineries from 450 mbpd

today with 30 mbpd of bitumen processing capability to 600 mbpd with 275 mbpd of

bitumen processing capability by 2013.

Marathon: in search of partners

Marathon Oil (MRO) is currently exploring reconfiguring at least two of its Midwest

refineries, Detroit and Catlettsburg, for processing Canadian heavy crude blends. In

addition, the company is seeking proposals from oil sands producers for the

formation of an oil sands joint venture, similar to the one announced between

ConocoPhillips and EnCana. At present, MRO processes just over 100 mbpd of

For a more detailed report on the

EnCana/ConocoPhillips oil

sands joint venture, please see

JPMorgans ConocoPhillips: Oil

Sands Venture Enhances

Portfolio, but Echoes Familiar

Challenges, published 6 October

2006.


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Canadian heavy crude at its PADD 2 refineries. Potential work on the Detroit and

Catlettsburg refineries would enable the company to process a total of

280,000 barrels per day of Canadian heavy crude.

BP: aggressively looking to expand its oil sands processing capability

In September 2006, BP announced that it is in the final planning stage of a $3 billion

investment at its 405 mbpd Whiting refinery located in northwest Indiana. The

company intends to reconfigure its Whiting refinery to increase Canadian heavy

crude oil processing capability by about 260,000 barrels per day. Construction of the

project is tentatively scheduled to begin in 2007 and should be completed by 2011,

pending regulatory approvals.

Pipeline transportation another bottleneck in the supplychain

Both synthetic crude oil and Canadian heavy crude blends must be transported to endmarkets through pipelines. The first step is transporting the product to a nearby hub,

usually Edmonton or Hardisty. Some heavy crude blends may also be transported

directly from the oil sands areas to Lloydminster, to the 25,000 bpd Husky refinery.

From the hubs, the crude is sent on major export pipelines to the broader market.

Intra-Alberta pipelines

Transportation to one of the hubs takes place over one of the smaller intra-Alberta

crude pipelines. At present, intra-Alberta pipelines have the capacity to carry over

1.6 million barrels per day to the larger hubs, with 900,000 barrels per day sent to

Edmonton and 700,000 barrels per day sent to Hardisty. There are also several

projects under development that are scheduled to provide just under 1 million barrels

per day of additional capacity between the Fort McMurray area and Edmonton.

Table 6: Oil sands crude must be transported from the fields to larger hubs over one of thefollowing pipelines

Pipeline Origin DestinationCapacity(mbpd) Status

Athabasca Fort McMurray Hardisty 300 ExistingCorridor Fort McMurray Edmonton 260 ExistingAlberta Oil Sands Fort McMurray Edmonton 389 ExistingOil Sands Fort McMurray Edmonton 145 ExistingCold Lake Heavy Oil Cold Lake Hardisty 194 ExistingCold Lake Heavy Oil Cold Lake Edmonton 118 ExistingHusky Oil Cold Lake Hardisty 133 ExistingHusky Oil Cold Lake Lloydminster 226 ExistingEcho Cold Lake Hardisty 75 ExistingCorridor expansion Fort McMurray Edmonton 240 Proposed for 2009

Horizon Fort McMurray Edmonton 250 Proposed for mid-2008Access Fort McMurray Edmonton 150 Proposed for mid-2006Waupisoo Fort McMurray Edmonton 350 Proposed for 2008

Current capacity Fort McMurray Edmonton 793Fort McMurray Hardisty 300Cold Lake Edmonton 118Cold Lake Hardisty 403

Proposed capacity Fort McMurray Edmonton 989

Source: EUB, CERI, JPMorgan.


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Export pipelines

After the synthetic crude or heavy blend is sent to Edmonton or Hardisty, it is sent to

refineries along major export pipelines. Currently, these pipelines have the capacityto transport 2.6 million barrels per day, primarily to the Midwest and Eastern United

States. Modifications, expansions, and new construction are expected to augment

this to about 5 million barrels per day in the next several years. We expect the

expansions to focus primarily on transporting crude to the Midwestern United States,

though one ambitious project slated for 2010 or later links Alberta with the US Gulf

Coast. In addition, major pipelines such as the Gateway and Trans Mountain

Express will link Alberta with the western coast of Canada and increase crude oil

transportation capacity to ports linking Canada to Asian markets.

Table 7: Major export pipelines transport crude from Alberta to major refining markets

Pipeline Origin DestinationCapacity(mbpd) Status

Enbridge Edmonton Midwest, East Coast, E Canada 1,840 ExistingExpress Hardisty US Rockies, Midwest 282 ExistingTrans Mountain Edmonton British Columbia, US West Coast 285 ExistingMilk River Edmonton Montana 118 ExistingRangeland Cold Lake Montana 65 ExistingGateway Edmonton Kitimat, BC 400 Proposed for 2010Trans Mountain Exp Edmonton Vancouver and/or Kitimat, BC 625 Proposed for 2010Keystone Hardisty Wood River 400 Proposed for 2009Southern Access Edmonton Superior, Wood River 403 Proposed for 2008/09Altex N Alberta US Gulf Coast 250 Proposed for 2010+Alberta Clipper Hardisty Superior 403 Proposed for 2010+

Current capacity Eastern US 1,840Midwestern US 2,122Rockies 465Western US 285

Proposed capacity Midwestern US 1,205Gulf Coast 250West Coast 625

Source: EUB, CERI, JPMorgan.


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Figure 12: Major pipelines are planned to expand Albertas link with US and overseas markets

Source: Alberta Energy and Utilities Board.

Challenges Facing the IndustryOil sands production poses some of the same challenges as conventional crude

oil production, with some unique differences. While some of the technological

and economic challenges are by no means unique to oil sands, the developments do

consume vast amounts of energy and face relatively stringent environmental

regulations. On the other hand, low geological risk and a friendly fiscal regime add

to the appeal of the play.


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Table 8: Oil sands production faces many of the same challenges as conventional crude oilproduction, but also poses its ow n set of challenges

Challenge

Conventional

production Oil sands CommentsExploration risk The extent of the oil sands deposits is well-

documented, unlike conventional reservoirs whichmust be located with expensive drilling programs.

Energy usage Oil sands production uses a significant amount of fuelto run equipment, produce steam, and generateelectricity. Conversely, some conventional productionrequires minimal energy, especially in primaryrecovery when wells flow under natural pressure.

Environmentalconstraints

Oil sands operations have a considerable impact onthe surrounding environment, including water, land,and greenhouse gas emissions. To minimize this,Canada poses strict environmental constraints on oilsands producers.

Recoverability

Less than 20% of the oil sands resources are thoughtto be ultimately recoverable. By contrast,conventional reserves are thought to be up to 60%recoverable with tertiary recovery techniques.

Fiscal terms Canada offers a stable and transparent fiscal regimeand is actively encouraging development of itsresources. Many of the worlds conventional cruderesources are located in countries with captivenational oil companies and unfriendly fiscal terms.

Cost inflation Oil sands developments are currently undersignificant cost pressures in both the capital andoperating cost phases. Conventional crudeproduction operations also face significant costinflation, especially in rising crude price environments.

Crude quality The quality of the bitumen produced from the oilsands is very low compared with world benchmarkcrudes, meaning that the bitumen must be sold at asignificant discount or go through an upgradingprocess.

Source: JPMorgan.

Exploration risk

Though high for most conventional crude production, exploration risk is

virtually zero for oil sands. The extent of the oil sands resource base is well

delineated, and the extent of the economic resource base is also regularly revised and

made publicly available in regular reports from the provincial and federal

governments. Drilling that is undertaken in conjunction with oil sands development

is comparable to appraisal drilling, and usually involves extracting core samples froma deposit that is to be exploited using in-situ techniques. These samples can provide

a breakdown of the quality of the reservoir and aid in determining the most efficient

configuration of the development.

Energy usage

Oil sands developments are notoriously energy-intensive, with substantial

volumes of fuel and natural gas consumed at virtually all stages of the

production process. Mining operations use considerable fuel to power the trucks

and shovels, and in-situ operations use natural gas to generate heat in thermal

- challenge is sufficient to b e a majorconsideration in project developmentand operations and may impede

progress

- challenge is a factor in developmentand operations, but is rarely an

impediment to progress

- challenge is rarely a factorinfluencing development or operating

decisions


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recovery. Upgrading facilities also use natural gas to generate heat and electricity

and as a source of hydrogen to add to the bitumen. On average, producing one barrel

of bitumen requires one mmbtu of natural gas. This adds to the field-level operatingcosts, making the economic recoverability of bitumen dependent on the market prices

of not only crude oil but also natural gas.

Environmental constraints

Oil sands operations have significant impacts on the surrounding environment.Though environmental regulations are fairly strict and every effort is made by the

producers to minimize the operations impact on the environment, the projects attract

substantial scrutiny and ample criticism from environmental advocates. The oil

sands operations effects on surrounding land and water, as well as their greenhouse

gas emissions, attract perhaps the most attention.

Water and land impacts

Bitumen production requires considerable amounts of water, which is used

throughout the production process. On average, producing one barrel of bitumen

requires three barrels of water. Water is used in mining operations, where it is mixed

with the oil sands in the hydrotransport and bitumen extraction stages; in in-situ

recovery operations1, where it is heated to a vapor and injected into the subsurface

formation; and in upgrading, where it is used as a cooler. Current mining projects

are licensed to divert up to 2.3 billion barrels of water per year from the Athabasca

River, the vast majority of which ends up in tailings ponds.

Steam-oil ratios

A steam-oil ratio (SOR) indicates the amount of steam used to produce a given

quantity of crude bitumen. The SOR is a key indicator of the operational efficiency

of an in-situ operation. A project with a steam-oil ratio of 2.0 uses 2.0 barrels ofsteam for every barrel of bitumen produced.

Tailings disposal

Disposal of the tailings generated from mining operations spans both the water and

land impacts of oil sands production operations. Water used in the ore processing

and bitumen extraction phases of mining operations are ultimately extracted from the

mixture along with the other tailings. These tailings are sent to tailings ponds, which

are in essence large bodies of water held back with dykes created with the

previously-removed overburden. Though every effort is made to contain the tailings,

the sheer volume of tailings opens the possibility of groundwater or nearby soil and

surface water contamination. Technological advances are currently being made

toward minimizing the environmental impact of the tailings.

Land usage and reclamation

The overall surface footprint of oil sands operations can range from modest, in the

case of in-situ production and upgrading operations, to very large, as in the case of

mining operations. Companies make substantial efforts to minimize the surface

footprint of their operations, though for mining ventures there is little that can be

done to minimize the scope of surface-level disturbance. As a result, operators

1Though research is progressing on technologies that use little water to recover in situ

bitumen, such as THAI and VAPEX, commercial in situ operations still employ CSS andSAGD, both of which use steam.


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attempt to restore the disturbed land to a reclaimed state once an operation has been

exploited. This involves replacing the tailings into the landscape and rendering the

land suitable for another use similar (but likely not identical) to that in the pre-minedstate.

Following criticism that land was not being reclaimed quickly enough, producers

have adopted a practice called progressive reclamation in an effort to reclaim land

as soon as is technically feasible. However, it is estimated that even the first steps

toward reclamation will not be taken for the first 20 to 30 years after operations

commence.

Greenhouse gas emissions

Oil sands operations are the largest contributors to the growth in Canadas increasing

greenhouse gas emissions, and greenhouse emissions resulting from the production

of bitumen and synthetic crude oil are more intense than for conventional production.

Though considerable progress has been made to reduce the intensity of thegreenhouse gas emissions from the oil sands operations, the rapid expansion of the

oil sands operations has resulted in a net increase in greenhouse gas emissions.

Currently, researchers are exploring the possibility of capturing the CO2 emitted in

oil sands operations. The CO2 would be stored and used in CO2flooding enhanced

oil recovery efforts at mature conventional reservoirs. However, these studies are

still in early stages.

Recoverability

Despite the vast expanse of the Canadian oil sands, less than 20% of the

resources are thought to be ultimately recoverable, even with technological

advancements. This is considerably lower than the recoverability factor ofconventional crude oil production, which, according to the EIA, can range 30%-60%

once tertiary and enhanced oil recovery methods have been employed.

Fiscal regime

Canada has a relatively stable fiscal regime, providing oil sands projects with a

tremendous advantage over projects in many other resource-rich areas.

Especially in the current high crude price environment, many countries are

renegotiating contracts and overhauling legislation in an effort to increase their take,

often retroactively. This behavior is by no means limited to any particular location

or type of regime, as evidenced by recent production tax hikes in the UK North Sea

as well as murmurings of windfall profit tax proposals in the US.

Royalty rates

In mid-1997, Alberta adopted a generic royalty regime for its oil sands projects,

rather than having individual agreements with respective projects. The terms

adopted in 1997 apply to all new and expansion projects. Similar to a production

sharing contract, the royalty regime views projects in two separate phases: (1) a pre-

payout period, before capital costs are recovered, and (2) a post-payout period,

following the recovery of capital costs. During the pre-payout period, the royalty

rate is set at 1% of gross revenue. During the post-payout period, the projects pay

the greater of 1% of gross revenue or 25% of net revenue. According to the Alberta

Department of Energy, the post-payout royalty is about 11% of gross revenue.


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Impact of oil sands on Alberta

We expect the fiscal regime in Canada to remain friendly and open to oil sands

investment given the contribution the industry has made to the Albertan and greaterCanadian economies. Oil sands operations have a positive impact on both

government revenue and GDP, according to the Canadian Energy Research Institute

(CERI). CERI estimates that the oil sands operations will contribute nearly

Cdn$800 billion to Canadian GDP over the 2000-2020 period, with 57% of this

contribution coming directly from the industry itself and the remaining 43% coming

from the impact on other sectors, from retail to education to financial services. Oil

sands operations are expected to result in more than US$100 billion

(Cdn$123 billion) in additional government revenue throughout Canada, with 40%

going directly to the federal government and 35% to the Alberta provincial

government.

Table 9: Oil sands have a substantial im pact on the Canadian economy bo th dir ectly and

indirectlyoil sands cumulative contributions to GDP, employment, and government revenue, 2000-2020E

Alberta CanadaGDP impact (Cdn$ MM, 2004)

Oil sands direct impact 404,573 448,581Total impact 633,903 789,147% direct impact 64% 57%

Employment impact (thousand person years)Oil sands direct impact 1,043 1,150Total impact 3,649 5,425% direct impact 29% 21%

Albert a Provi ncial Federal Total CanadaGovernment Revenue impact (Cdn$ MM, 2004)

Royalties 26,762 - 26,762

Indirect tax - 14,089 18,742Corporate income tax 5,989 16,280 24,517Personal income tax 6,521 20,721 30,586Property tax 4,522 - 22,684

Total 43,794 51,090 123,291% Royalties 61% 0% 22%

Source: CERI: Economic Impacts of Alberta's Oil Sands, JPMorgan.

Cost inflation

Like many other energy projects, oil sands projects have faced considerable cost

inflation of late. Capital and operating costs have increased as more projects

compete for scarce material, labor, and fuel resources. Capital cost escalations have

been significant in recent years, with several large projects revisiting and revising

their cost estimates several times over. For example, the last expansion at Syncrude,

Stage Three, was originally estimated to cost about US$3.3 billion (Cdn$4 billion).

The estimate was revised upward by 40%, then by 95% eighteen months later.

Completed this year, Stage Three came in at a final cost of US$7 billion

(Cdn$8.4 billion), exceeding the original budget by 110%. The Athabasca Oil Sands

Project, including the Muskeg River Mine and the Scotford Upgrader, was originally

budgeted at nearly US$3 billion (Cdn$3.5 billion). The final cost, however, was

more than 60% over budget, at over US$4.7 billion (Cdn$5.7 billion).

Operating costs are similarly not immune to upward pressure. Operating costs

have increased appreciably across oil sands projects, at both mining and in-situ


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operations, as a result of higher fuel and higher labor costs. At Suncor, current non-

fuel cash operating costs are up more than 60% on a per-barrel basis since 2003, with

total cash operating costs (including fuel) up nearly 75% over the same period.

Crude quality: lower than conventional crude

As discussed earlier, bitumen is by its nature an inferior grade of hydrocarbon, both

heavy and containing high amounts of sulfur. In order to be transported in a pipeline,

bitumen must be diluted, and even in its diluted state, the resulting bitumen blend is

comparable to a low-grade crude such as Maya. Bitumen blends sell at a discount to

higher-quality benchmark crude oils, such as WTI. The only way for oil sands

producers to capture the spread between the bitumen blends and the higher quality

crudes is to upgrade their bitumen into a light sweet or light sour crude. This can be

capital intensive and raise operating costs.

Economic Analysis: Value Creators or BigDigs?

Throughout their history of development, the oil sands have usually been

considered a marginal source of crude oil supply because of the capital-intensive

nature of development projects. White elephants of sorts, the projects held

tremendous potential, but required significant capital investment and lofty operating

expenditures. Sharply rising crude prices and improvements in technology have

made the developments more lucrative and brought them into the mainstream, but the

sudden deluge of new development projects has strained the development

environment, pressuring prices for raw materials and labor. On an ongoing basis,

fuel cost considerations pose another challenge, as the projects are energy-intensive.

In analyzing the economics of oil sands development projects, we have developed a

set of cash flow models for generic oil sands development projects. We review the

output of these models to determine the economic viability of the projects under

various assumptions regarding crude price, capital expenditures, operating costs, and

upfront capex.

Mining

One major economic consideration for a mining project is whether to construct an

upgrader. As discussed previously, all the commercial mining projects currently in

operation are fully integrated, that is, they have a dedicated upgrader and sell

synthetic crude rather than a bitumen blend. However, examining the current set ofannounced mining projects, we estimate that mined volumes will exceed upgrading

capacity by 2010, and we expect that difference to further increase by 2015.

Economics of a stand-alone mining project

A stand-alone mining project, whether a new mine or an expansion of an existing

project, will likely sell a heavy blend of bitumen and diluent into the market. While

the project will be unable to capture the differential between light, sweet crude and

heavy crude, the project will see upfront savings without the cost of an upgrader in

addition to fuel cost savings throughout the life of the project. However, operating

costs will include the purchase of diluent for blending with the bitumen.

Our analysis shows that a stand-

alone mining project is

economical even at a long-term

WTI price of US$35/bbl.


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We use the following set of standard assumptions to analyze a stand-alone mining

project.

Table 10: Our generic mining model uses a standard set of operating assumptions

mining project cash flow model inputs

Project details Operating costs and taxesMining capacity (mbpd) 100 Natural gas consumption (mmbtu/bbl) 0.30

Product sales mix Non-fuel costs (Cdn$/bbl) 7.50Bitumen 0% Overburden removal (Cdn$/bbl) 2.50Heavy crude blend 100% Diluent addition cost (Cdn$/bbl) 6.00

Maintenance capex (Cdn$/bbl) 1.00Diluent as % of volumes 30% SG&A (Cdn$ MM/yr) 10

Production start 2009 Cost escalation factor (annual) 2%Ramp-up period (years) 2

Tax rate 38%Terminal year 2035 Deferred tax rate 33%

Environmental remediation (Cdn$ MM) 1,000 Cash tax rate 25%

Crude quality d ifferential (% of WTI) Exchange rate (Cdn$/US$) 1.20Bitumen 50% Capital costs (Cdn$ per bpd capacity) 20,000Heavy crude blend 35%

Source: JPMorgan.

The above set of assumptions results in a non-fuel cash cost per barrel of heavy

blended crude of more than Cdn$16.4, including SG&A, and an all-in cash cost per

barrel of Cdn$19, including fuel costs. We also apply the standard Alberta royalties

to the project, with royalties equal to 1% of revenue before project payout and the

greater of 1% of gross revenue or 25% of net revenue after project payout. We also

apply our JPMorgan commodity price forecast for crude oil and natural gas through2008, reverting to various long-term crude prices thereafter. On these assumptions,

we find that a stand-alone mining project with capital cost of Cdn$20,000 per barrel

per day of capacity will generate an unlevered after-tax return of 11% on a long-term

WTI crude price assumption of US$35/bbl. The following table shows various rates

of return on several sets of capital cost and crude price assumptions.

Table 11: Estimated IRRs of a stand-alone mining project on various capital cost and crude priceassumptions

project IRR

Long-term crude price WTI (US$/bbl)Capital cost(Cdn$ per bpd capacity) 35 40 45 50 55 60

10,000 17.8% 25.5% 30.1% 35.2% 39.8% 44.0%15,000 13.6% 19.5% 23.8% 28.0% 30.5% 33.9%

20,000 10.9% 15.7% 19.9% 22.9% 26.2% 29.2%25,000 9.5% 13.6% 17.0% 20.2% 22.4% 25.1%30,000 8.4% 12.1% 15.2% 17.7% 20.3% 22.1%

Source: JPMorgan.

JPMorgan Commodity Price

Forecast

WTI crude oil (US$/bbl)

2007: $64

2008: $55

Henry Hub natural gas (US$/mcf)

2007: $7.5

2008: $7.0


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Economics of an integrated mining project

Including an upgrader changes the economics of the project considerably. Using the

same set of assumptions as above, we include an upgrader with a production capacityof 80,000 barrels per day (to match the assumed bitumen yield factor of 80%), with a

configuration yielding only light, sweet synthetic crude oil, that is, with

hydrotreating capacity sufficient to remove sulfur from all the processed barrels of

bitumen. Our new set of assumptions is listed below, with the upgrading-specific

assumptions highlighted.

Table 12: Our generic integrated mining model includes the fol lowing additional assumptions

mining and upgrading project cash flow model inputs (upgrading-specific inputs shaded)

Project details Operating costs and taxesMining capacity (mbpd) 100 Natural gas consumption (mmbtu/bbl)Upgrading capacity (mbpd) 80 Mining 0.30

Upgrading 0.70Bitumen yield factor 80%

Mining non-fuel costs (Cdn$/bbl) 7.50Product sales mix Overburden removal (Cdn$/bbl) 2.50Sweet synthetic crude 100% Diluent addition cost (Cdn$/bbl) 6.00Sour synthetic crude 0% Upgrading non-fuel costs (Cdn$/bbl) 5.00

Maintenance capex (Cdn$/bbl) 2.00Production start 2009 SG&A (Cdn$ MM/yr) 15Ramp-up period (years) 2

Cost escalation factor (annual) 2%Terminal year 2035Environmental remediation (Cdn$ MM) 1,000 Tax rate 38%

Deferred tax rate 33%Cash tax rate 25%

Crude quality d ifferential (% of WTI) Exchange rate (Cdn$/US$) 1.20Sweet synthetic crude discount 0% Capital costs (Cdn$ per bpd capacity)Sour synthetic discount 6% Mining 20,000

Upgrading 30,000

Source: JPMorgan.

This set of assumptions results in a non-fuel cash cost of about Cdn$21 per barrel of

synthetic crude oil in 2012, when the project is at full run rates. This includes SG&A

and allows for a yield factor of 80%, that is, 20% of the bitumen is lost in the

upgrading process. On this set of assumptions, all-in cash costs, including fuel, are

just under Cdn$28 per barrel. We assume the mining project costs Cdn$20,000 per

barrel per day. Our model then indicates that an upgrader costing Cdn$30,000 per

barrel per day needs a long-term WTI crude price of over $40/bbl in order to

generate returns of more than 10%.

Table 13: Estimated IRRs of an integrated mining project on various capital cost and crude priceassumptions

project IRR

Capital cost (Cdn$ per bpd capacity) Long-term crude price WTI (US$/bbl)Total Upgrader 35 40 45 50 55 6040,000 20,000 7.9% 10.6% 12.7% 14.7% 16.8% 18.3%45,000 25,000 7.5% 9.9% 12.0% 13.9% 15.6% 17.0%50,000 30,000 7.2% 9.4% 11.3% 13.1% 14.6% 16.3%55,000 35,000 6.9% 9.0% 10.8% 12.5% 14.0% 15.3%60,000 40,000 6.6% 8.6% 10.4% 11.8% 13.3% 14.8%

Source: JPMorgan.

Our analysis shows that an

integrated mining project is

economical at a long-term WTI

price of US$40-$45/bbl.


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In-situ development

We believe that most in-situ developments will not include an upgrader, and as such,

these projects will be stand-alone, selling a heavy blend of diluted bitumen into themarket rather than upgraded synthetic crude oil. In-situ developments are much

more energy-intensive than mining operations, though they are less labor-intensive.

Examining the economics of in-situ development, we have modeled a generic project

employing SAGD, as this is one of the more commonly-employed production

methods for new in-situ projects. We pay close attention to the steam-oil ratio as a

gauge for the amount of fuel the project will require on an ongoing basis. In

addition, we note that in-situ developments trend toward their design steam-oil ratio

over a period of time, as steam is initially injected into the reservoir with little or no

resultant production.

Table 14: Our generic in-situ pro ject model uses the followin g assumptions

in-situ project cash flow model inputs

Project details Operating costs and taxesDesign capacity (mbpd) 100 Design steam-oil ratio 2.0

Years to reach design SOR 5Product sales mix Natural gas usage (mcf/bbl steam) 0.5

Unblended bitumen 0% Non-fuel costs (Cdn$/bbl) 4.00Heavy bitumen blend 100% Diluent addition cost (Cdn$/bbl) 6.00

Diluent % by volume 30% Maintenance capex (Cdn$/bbl) 2.00SG&A (Cdn$ MM/yr) 10

Production start 2009 Cost escalation factor (annual) 2%Ramp-up period (years) 5

Tax rate 38%Terminal year 2035 Deferred tax rate 33%Terminal EBITDA multiple 3.0 Cash tax rate 25%

Crude quality d ifferential (% of WTI) Exchange rate (Cdn$/US$) 1.20

Bitumen 50% Capital costs (Cdn$ per bpd capacity) 20,000Heavy crude blend 35%

Source: JPMorgan.

On these assumptions, our project has non-fuel cash costs of Cdn$8.25/bbl and

trends toward an all-in cash cost of Cdn$12/bbl when the design steam-oil ratio is

reached. Our model then indicates that at a project cost of Cdn$20,000 per barrel per

day of production capacity, the project will generate a return of nearly 20% on a

long-term WTI crude price assumption of $35/bbl.

Table 15: Our in-situ model shows various rates of return on different sets of capex and crudeprice assumptions

project IRR

Long-term crude price WTI (US$/bbl)Capital cost(Cdn$ per bpd capacity) 30 35 40 45 50 55 60

10,000 23.8% 27.2% 30.7% 33.9% 36.9% 38.7% 41.1%12,000 21.5% 25.3% 27.8% 30.8% 33.5% 36.0% 37.4%14,000 19.8% 23.2% 26.3% 28.3% 30.8% 33.1% 35.3%16,000 18.9% 21.6% 24.4% 26.3% 28.7% 30.8% 32.9%18,000 17.8% 20.2% 22.9% 25.3% 26.9% 28.9% 30.8%20,000 16.8% 19.6% 21.6% 23.9% 26.0% 27.3% 29.1%22,000 16.3% 18.6% 20.5% 22.6% 24.7% 26.5% 27.7%24,000 15.6% 17.8% 20.1% 21.6% 23.5% 25.3% 27.0%

Source: JPMorgan.

Our analysis shows that an in-

situ project is economical at along-term WTI price of

US$35/bbl.


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Production Techniques

Production will come mainly from mining projects, though in-situ will grow in

importance. The bitumen in Albertas oil sands can be produced using either

mining techniques, for those deposits close to the surface, or in situ techniques for

those located deeper than 250 feet. Only the Athabasca OSA has oil sands shallow

enough to be recovered with mining techniques, meaning in-situ recovery is

necessary for Cold Lake, Peace River, and a portion of the Athabasca deposits.

Mining has been responsible for nearly 70% of crude bitumen production to date and

represents nearly 75% of all current development projects. However, less than 20%

of the remaining established oil sands reserves are recoverable with mining

operations, meaning that in-situ production will become increasingly important as the

resource base is exploited.

Figure 13: Though min ing represents the majority of p roduction to date, in-situ recovery will berequired to reach the majority of reserves

initial reserves and cumulative production by recovery method, billion barrels

35.2

143.4

3.4 1.6

Mining (10% exploited) In situ (1% exploited)

Initial established reserves Cumulative production

Source: EUB, JPMorgan.

Mining: scratching the surface

Mining is the pioneering method of oil sands development, and the first two

commercial oil sands projects employed mining techniques to recover bitumen. Oil

sands are considered mineable if they sit no deeper than 250 feet (80 m) below the

surface.


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Figure 14: Over 80% of remaining reserves willrequire in-situ recovery techniques

remaining reserves

Mining

18%

In situ

82%


Figure 15: However, most active developmentfocuses on mining operations

reserves under active development

Mining

74%

In situ

26%


Mine planning

As with other mining operations, successful commercial development of a mine

begins with a solid mine plan. In the case of oil sands mining, the mine plan must

take into account not only space for the overburden and tailings, but also must

incorporate an extraction facility and often an upgrader. Ideally, these facilities

would be located on a relatively low-value section of the mine, for example, an area

with low bitumen concentration, as oil sands located beneath the plants will

obviously not be recovered. In addition, the mine plan must consider the overall

distance the oil sands must travel. As hauling costs are a considerable factor for the

mining operation, they must be minimized over the life of the mine. Environmental

factors may also come into play when developing a mine, as certain sites will belocated near bodies of water or other natural resources that constrain the

development. Finally the economically recoverable deposits of oil sands may look

markedly different on various ore grade and crude price assumptions. Thus, the mine

plan may be re-optimized before groundbreaking begins.


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Figure 16: Mine plans may be re-optimized under different physical and market assumptions

Fort Hills mine plan

Source: Petro-Canada.

Overburden removal

Mineable oil sands deposits sit beneath a layer of earth called the overburden, which

is up to 250 feet (80 m) deep. The overburden, in turn, is covered with muskeg, a

swampy layer of moist, decaying vegetation, often covered by moss, sitting one to

three meters thick. Mining operations require removal of the muskeg and any

surface vegetation before the overburden removal can begin. In Canada, the muskeg

is frequently removed during the winter when it is frozen and is stored to be replaced

or used elsewhere.

The overburden is then removed using the same trucks and shovels that are used in

the oil sands mining operations. Once the overburden is removed, the site is

prepared for mining operations. The overburden itself may be used to create dykes

or, in the case of mine extensions, may be used to back-fill pits that have already

been mined.

Heavy haulers

Perhaps the most iconic figures in the Canadian oil sands operations are the

enormous trucks that are used to haul the oil sands from their original locations in themine to the ore preparation and extraction facilities. The largest of these trucks is

nearly 30 feet (10 m) wide, 50 ft (15 m) long, and, when loaded, over 50 ft (15 m)

high, approximately the size of a two-storey house. The larger trucks have over

3,500 horsepower and come with a price tag of US$5-6 million. During the mining

process, these massive machines are loaded with up to 400 tons of oil sands at a time.


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Figure 17: An oil sands truck is comparable in size to a two-storey house

Source: Canadian Natural Resources Limited, Horizon Oil Sands Project.

Oil sands mining operations

Extracting the bitumen from the oil sands takes several steps, from processing the ore

to separating the bitumen from the sand, water, and clay. The process is energy-

intensive, and produces a substantial amount of by-product in the form of tailings.

Once the bitumen has been extracted from the oil sands, it is ready for upgrading or

for blending into a heavy crude blend.

Figure 18: Extracting bitumen from oil sands i s an involved process

Truck and shovel

mining

bitumen

sand

Crusher

bitumen

sand

hot water

slurry

Primary

separation

vessel

ORE PROCESSINGwater

sand

water

Tailings

disposal

froth

middlings

Secondaryseparation

froth

sand

water

BITUMEN EXTRACTION

FROTH TREATMENT

bitumen

Bitumen now ready

for upgrading or

blending with diluent

Truck and shovel

mining

bitumen

sand

Crusher

bitumen

sand

hot water

slurry

Primary

separation

vessel

ORE PROCESSINGwater

sand

water

Tailings

disposal

froth

middlings

Secondaryseparation

froth

sand

water

BITUMEN EXTRACTION

FROTH TREATMENT

bitumen

Bitumen now ready

for upgrading or

blending with diluent

Source: JPMorgan.


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Ore processing

Trucks are loaded with oil sands in the excavated portion of the mine and then

transport the oil sands to a crusher, which breaks up larger clumps. Next, the oilsands are mixed with hot water, forming a slurry, and transported in a pipeline to an

extraction plant. This method, called hydrotransport, has been one of the more cost

effective advancements in oil sands operations. Hydrotransport replaced the older

conveyor belt system and eliminated the need for a separate conditioning step, as the

hot water mixes with the oil sands in transit, conditioning the bitumen by loosening it

from the sand and water mixture.

Bitumen extraction

The next step involves extracting the bitumen from the rest of the mixture. The

slurry is sent to Primary Separation Vessels (PSVs) that allow the mixture to settle

into three layers: sand falls to the bottom, bitumen floats to the top as froth, and a

mixture of sand, water, and bitumen remains in the middle layer, known as

middlings. The sand is drawn from the bottom of the PSVs and sent to tailingsponds, the froth is drawn off for additional treatment, and the middlings are sent

through a secondary separation process. In secondary separation, air is added to the

mixture to extract additional froth, which then joins the froth from the primary

recovery. The froth is then heated with steam and de-aerated before being treated.

Froth treatment

The final step in bitumen extraction is treating the froth, removing lingering sands

and water. In froth treatment, bitumen diluted with naphtha is sent through inclined

plate settlers and centrifuges that further separate the bitumen from the heavier rocks

and clays and from water. These tailings are further cleaned of residual naphtha

before being sent to tailings ponds. The resultant bitumen, containing less than 5%

water and less than 0.5% other solids, is then ready for upgrading into synthetic

crude oil.

Recovery factor

The overall recoverability of the commercially viable deposits of mineable bitumen

in Alberta is well less than the in-place volumes. Despite all attempts to recover

maximum bitumen from the deposits, two key limiting factors hinder full

recoverability. First, environmental and logistical constraints make it extremely

difficult to mine an entire lease. As discussed above, mine plans must take into

account tailings ponds, processing and extraction facilities, and often upgraders,

which sometimes must consume space on commercially viable deposits. In addition,

environmental constraints often limit the extent of mining operations on a lease,

especially when the lease is adjacent to a river, for example. The Alberta Energy and

Utilities Board estimates that this reduces commercial recovery by 10%, on average.

In addition, inefficiencies in the mining operations and extraction processes result in

an additional combined loss of 15-20% of mineable bitumen, on average. Thus,

overall recoverability of the initially mineable volumes is only 70-75%.


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Figure 19: Only three quarters of the initial mineable volumes are actually recovered in miningoperations

percent loss from various factors in oil sands mining

100%

10%

70-75%

15-20%

Initial mineable volume Logistical and

environmental loss

Processing and extraction

loss

Ultimate recovered

volumes


Major projects currently online

Despite all the attention focused on oil sands mining operations, there are at present

only three major mining operations actively producing bitumen in Alberta. The first

two forays into oil sands production, Suncor and Syncrude, discussed earlier, are still

in operation, albeit with expanded scope since their initial start-ups. A third project,

the Athabasca Oil Sands Project, came online in 2002.

Table 16: Three projects are responsible for the current commercial oil sands mining operations

Development Partners / OwnershipStart-up

year

Designcapacity(mbpd)

PrimaryMines Upgraders

Athabasca OilSands Project

Shell Canada (60%)Chevron (20%)Western Oil Sands (20%)

2002 155 Muskeg River Scotford

Suncor Suncor (100%) 1967 260 SteepbankMillennium

Tar IslandMillennium

Syncrude Canadian Oil Sands Ltd (32%)Imperial (25%)Petro-Canada (12%)ConocoPhillips (9%)Nexen (7%), Mocal (5%)Murphy (5%)Canadian Oil Sands Partship (5%)

1978 350 Base MineNorth MineAurora North

Syncrude

Source: EUB, company reports, JPMorgan.

Athabasca Oil Sands Project

The newest of the mining operations to come online, the Athabasca Oil Sands Project

is a venture between Shell Canada (60%), Chevron (20%), and Western Oil Sands

(20%). The AOSP came online in 2002 and currently produces around

175,000 barrels per day, beyond its design capacity of 155,000 barrels per day.

As part of the structure of the partnership, Albian Sands Energy mines oil sands from

the Muskeg River mine north of Fort McMurray. The oil sands are processed and

bitumen is extracted at the mine. Diluted bitumen is then sent more than 280 miles

(450 km) to the Scotford upgrader near Edmonton via the Corridor Pipeline.


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Suncor

As discussed earlier, Suncor pioneered oil sands mining operations by bringing the

first oil sands mining project online in 1967. From an initial production rate of45,000 barrels per day, the project has since expanded to over 200,000 barrels per

day, with production more than doubling since the late 1990s. Suncor has

260,000 barrels per day of upgrading capacity at its operations north of Fort

McMurray, and upgrades all the bitumen it mines.

Mining takes place at the Steepbank/Millennium mines, and an expansion into the

northern part of the Steepbank mine is planned. In addition to expanding into the

northern portion of the Steepbank mine, the company also holds leases on two other

mineable sites, Lease 23 and Audet; however, these sites will likely not be mined

until after the company pursues other growth initiatives.

Syncrude

The Syncrude consortium operates the largest oil sands mining initiative in Alberta.Syncrude is a joint venture between eight entities, with Canadian Oil Sands Ltd,

Imperial, and Petro-Canada holding the three largest portions and collectively

holding two-thirds of the operation. The project sold its first production volumes in

1978 and has expanded from initial volumes of about 50,000 barrels per day to a

design capacity of 350,000 barrels per day at present. Syncrude upgrades its bitumen

into a synthetic crude oil called Syncrude Sweet Blend (SSB). SSB is a high-quality,

light sweet crude with a sulfur content lower than that of West Texas Intermediate.

There are three mines currently being exploited by Syncrude: the Base Mine, the

North Mine, and the Aurora North Mine, with the latter two having commenced

operations in 1997 and 2000, respectively. The Aurora North Mine was responsible

for 50% of the oil sands volumes mined in 2005, and according to Syncrude, its share

is expected to increase in the next several years, and the Base Mine will be the first tobe decommissioned. The operations use 15-20 shovels and 70-80 hauling trucks.

Syncrude recently completed its Stage Three growth initiative, encompassing

increases to both mining and upgrading capacities. Stage Three included an

expansion of the Aurora Mine and a 100,000 barrel per day expansion of the

upgrader. The expansion suffered significant cost overruns, more than doubling its

original cost estimate of US$3.5 billion (Cdn$4 billion). The final cost of the

expansion is reported at US$7 billion (Cdn$8.4 billion).

For additional detail on Suncors

oil sands operations, please see

our initiation report on Suncor,

published 20 November 2006


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Figure 20: The mineable resources und er active development have been approximately 30%recovered

cumulative production and remaining reserves at current oil sands mining operations

145

1,271

1,969

975

2,529

4,063

Albian Sands Suncor Syncrude

Cumulative prod'n Remaining reserves

Source: EUB, JPMorgan.Note: Remaining reserves represent those remaining in the initial project approval areas, and do not include reserves in expansions

that have not yet been approved.

In-situ: going deeper to access more resource

In-situ recovery is appropriate for those resources that sit more than 80m (250 feet)

below the surface. In-situ techniques are required in the Cold Lake and Peace River

OSAs, as well as in parts of Athabasca. Latin for in-place, in-situ refers to bitumen

extraction from below the surface, that is, the surrounding sands are not removed

from their position. As the majority of oil sands resources are not mineable, in-situ

recovery will be increasingly important as the full resource base is exploited.

In-situ recovery is similar to traditional conventional oil and gas production, in whichwells are drilled and hydrocarbons are brought to the surface, either under their own

pressure or aided by advanced techniques. Since crude bitumen is very viscous and

resistant to flow in its natural state, most in-situ projects will employ enhanced

recovery techniques.

Primary recovery

In primary recovery, hydrocarbons flow through the reservoir to a well under their

own pressure. Though primary recovery of the bitumen in the oil sands is not

impossible, the recovery factor is very low, at around 5%-10%.

Secondary recovery

Secondary recovery techniques, such as waterflooding, can improve the recovery

factor of crude bitumen somewhat over that seen in primary recovery. In theAthabasca area, Canadian Natural Resources and EnCana have employed

waterflooding techniques at the Brintnell area. However, according to the most

recent project updates filed with the EUB, the incremental recovery from

waterflooding does not increase the overall recovery factor to a level competitive

with thermal recovery.

Thermal and solvent-based tertiary recovery

The addition of heat into the in-situ recovery process can drive significant

improvements in crude bitumen recovery factors, heating the bitumen and reducing

the viscosity, enabling it to flow more easily (or, in some cases, at all) to a producing


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well. According to the EUB, the recovery factors for in-situ projects range from 25%

in the Cold Lake area to 50% in the Athabasca area. Thermal recovery may use

steam or, in the case of Toe to Heel Air Injection, air to heat the bitumen.

Cyclic Steam Stimulation (CSS)

The first in-situ project, Imperials Cold Lake development, employed the Cyclic

Steam Stimulation method to heat bitumen and increase reservoir pressure, forcing

bitumen to flow through the reservoir to the well. CSS uses a single well, rather than

a well pair, throughout the entire cycle. In CSS, high-pressure steam is injected into

the reservoir. The steam injection step may take one to two months. In the second

stage of CSS, the steam is allowed to soak into the reservoir, heating the bitumen and

fracturing the formation under increased pressure. The soaking may also take several

weeks, depending on the reservoir. The final step in CSS is producing the now

loosened bitumen from the reservoir. Water is also produced with the crude bitumen,

which must then be separated and treated. At Imperials Cold Lake operation, the

produced water is reclaimed and recycled.

The production phase may last for several months, again depending on the

characteristics of the reservoir. The cycle may be repeated several times over the

producing life of the reservoir.


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Figure 21: CSS recovers bitumen in s tages, using th e same well to in ject steam and produ cebitumen

CSS multi-stage process graphic

Source: Petroleum Communication Foundation, CERI.

In 2005, projects employing CSS cumulatively produced over 150,000 barrels per

day, with Imperials Cold Lake operation producing the majority, at approximately

140,000 barrels per day. By 2015, this is expected to increase to 220,000 barrels per

day.

Steam Assisted Gravity Drainage (SAGD)

A newer technology, SAGD has become increasingly popular among in-situ

producers and is currently the in-s

Documents

JPM - Canadian Oils Sands Primer