| Imperial Oil -- Focused on Long-term Growth
Remarks by Paul Smith, controller and senior vice-president, to the Peters &
Co. 2006 North American Oil & Gas Conference
| | Toronto, Ontario |
September 13, 2006
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Listen to the Web cast of Paul Smith's presentation.
Download the remarks and slides.
Good morning. I'd like to thank Peters & Co. for the opportunity to speak to
you today and to share with you an update on Imperial Oil's current production
and future opportunities.
Following my remarks, I'd be
pleased to address your questions.
Before we begin, I want to remind you that the presentation this morning
contains forward-looking information and actual results could be different as
a result of many factors -- which are noted on this slide.
Let me begin with an overall look at Imperial Oil...
Imperial has been a leader in Canada's petroleum industry for over 125 years
-- we remain one of the largest producers of crude oil and a major producer of
natural gas.
Net proved reserves totaled over 1.6 billion
oil-equivalent barrels at the end of 2005, with a reserve-life index of 14
years. However, this is just a portion of our potential. Our non-proved
resource base was more than 12 billion oil-equivalent barrels, yielding a
total resource base of over 13 billion barrels at the end of last year -- said
another way -- our resource base represents over 130 years of production at
current levels -- all in all a leading resource position in Canada.
We are a major oil-sands producer with almost 200,000 barrels a day produced
last year from our wholly-owned Cold Lake operation and our 25 percent
interest in Syncrude Canada.
We are the leading refiner and
marketer of petroleum products in the country and supply about 25 percent of
total demand.
The company's total chemical sales were over
1.1 million tonnes and polyethylene operations remain among the most
cost-competitive in North America.
And -- a fundamental
competitive advantage for Imperial -- we remain the leader amongst our
competitors in Canada with the highest return on capital employed at over 30
percent.
As you can see, Imperial is distinguished in the market in many ways. But
fundamentally it is our disciplined management approach that sets us apart and
provides a significant advantage to our shareholders.
The
company has a solid track record of enhancing shareholder value through a
consistent management approach and sustained emphasis on four corporate
priorities.
The first priority is to achieve operational
excellence and strive for flawless execution in all we do.
A
second priority is to grow profitable sales volumes.
The
third is to achieve and maintain a best-in-class cost structure in every part
of the business.
And finally, the fourth is to improve the
productivity of our asset mix. This includes further investments in
high-performing assets, divestment of non-core assets and acquisition of new
opportunities.
It is this commitment and approach over many
years that distinguishes Imperial Oil in the marketplace.
I'd like to say a few words about our downstream operations before I focus on
Imperial's upstream business...
Imperial is a market leader
in the downstream in Canada -- and some of the components of that leadership
position are listed on this chart:
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The leading market share in the retail service station business at about 19
percent.
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The largest refiner with over 500,000 barrels a day of capacity and the
largest producer of asphalt.
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The number one position in finished lubricants at more than 30 percent and
growing. We are the only Canadian competitor with manufacturing, blending and
packaging capability for lubricants in both the east and the west -- a key
strategic advantage.
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The largest share of the domestic solvents market in Canada at close to 50
percent.
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And we have the #1 and #2 North American market share positions for the two
key end use polyethylene segments that we participate in -- rotational molding
and injection molding applications.
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Turning to the upstream....
Conventional oil and gas is a
profitable business for us, and delivers strong returns. Current conventional
production is about 150,000 oil-equivalent barrels a day.
This is a mature business with limited growth potential, and our underlying
strategy is to maintain a strong focus on keeping unit costs flat, regardless
of price. We have also divested selective assets recently to take advantage of
the premium the market sees on some of these assets.
Where
oil reserves have been economically depleted, we are selectively producing the
remaining gas caps, including Wizard Lake -- shown just southwest of Edmonton
on the map -- which will be complete later in 2007.
We
continue to pursue new gas development to offset the inevitable decline.
An active shallow gas drilling program in southeastern Alberta is highlighted
in gold on the map. We will be participating in more than 300 wells this year,
with additional drilling planned for 2007 and beyond.
East
Coast production remains stable, and additional compression facilities are
being installed at Sable to maintain production levels.
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Let me now turn to our opportunities in oil sands...
Imperial
has been a pioneer in development of Alberta's vast oil sands -- both mining
and in-situ -- and our oil-sands assets are enormous in size, scope and growth
opportunity.
This map shows the three major oil-sands
deposits and illustrates how we are positioned in both current oil-sands
production shown as the red stars and in undeveloped oil sands leases shown as
the gold stars.
The table in the lower right shows that
Imperial holds about 465,000 acres of oil sands leases including Cold Lake --
the largest in-situ oil-sands operation in the world and the premier in-situ
project in Canada.
Imperial also has extensive oil-sands
interests which are currently undeveloped -- mostly in the Athabasca area of
Alberta.
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Cold Lake produces as much as all other Canadian in-situ thermal operations
combined -- currently more than 150,000 barrels a day.
Net
proved reserves at the end of 2005 were about 700 million barrels, enough for
15 years of production at today's rates.
We have taken a
deliberate, phased approach to developing this high-quality asset -- bringing
on production in stages over the past 20 years. This has allowed for advances
in technology -- many of them developed and patented by Imperial -- to be
fully incorporated into new production phases.
You can see
changes in production on this graph as we brought on more phases since
commercialization in the mid-1980's.
Volume has come on in
measured, staged additions and has been absorbed into the North American
refining markets. Currently we are producing from 13 commercial phases, with
Cold Lake blend being marketed to refineries here in Canada -- including our
own Sarnia, Nanticoke and Strathcona refineries -- as well as refineries in
PADD II (Chicago) and PADD IV (Rocky Mountain). And, with the reversal earlier
this year of the 20-inch ExxonMobil pipeline south from Patoka, Illinois,
Canadian heavy crudes can now reach the Gulf Coast -- the single largest high
conversion market in North America.
Across the top of this
graph are listed the changes in bitumen recovery factor over the last 20
years. The increase from 13 percent to 30+ percent is a direct result of our
continued focus on research and technology development and our
industry-leading expertise in thermal operations.
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The circles at the top of this chart highlight the numerous technology
milestones we have achieved at Cold Lake.
Imperial invested
$250 million on research and technology development before the start-up of the
commercial project in 1985. Since then, expenditures have averaged more than
$25 million a year -- both at our research centre in Calgary and field pilots
at Cold Lake.
Many may not be aware that Imperial invented
and held patents on both cyclic steam-stimulation (CSS) and steam-assisted
gravity drainage (SAGD), the processes underpinning all commercial in-situ
thermal production in Canada today.
Our on-going commitment
to technology is unwavering. Our process to develop new technology is as
disciplined as our major project management and we take a staged "gate-based"
approach to bring new technology on-stream.
These "gates"
start with testing the fundamental physics of a project and progress through
analytical modeling and lab-based simulations before a field pilot is launched.
As one recent example, we patented a process late last year to enhance CSS
recovery with liquid addition. In the bottom left is a picture of this pilot
-- in operation since 2002. Results are encouraging and plans for larger-scale
implementation are now being developed. This technology has the potential to
increase recovery in late-cycle areas already developed, using existing wells
and facilities.
The diagram on the lower right is a schematic
representing another recovery process we are also investigating which will be
pilot tested on company leases in the near future. This pilot is focused on
improving the economics for resources where SAGD is currently the leading
recovery technology for development. The enhancement involves the addition of
solvent to the injected steam, and is currently being tested in scaled models
at Imperial's research centre in Calgary.
In 2004, we
established the Imperial Oil Centre for Oil Sands Innovation at the University
of Alberta. With a funding commitment of $10 million over five years, the
Centre's mandate is to focus on breakthrough research to develop more
efficient, economically viable and environmentally responsible ways to produce
Alberta's vast oil sands resource.
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The Cold Lake lease area (shown as the dashed black line on the map) is about
300 square miles. The approved development area shown as the solid black line
is about 140 square miles and we are currently active in about half of that.
Our efforts from now to the end of the decade are to develop the area shown in
red, one of the new areas which we received regulatory approval for in 2004.
Over the next five years, we plan to develop 10 new pads in this area. The
first investments were made in 2005 with the drilling of two new pads in the
southern part of this area. These are now complete and we are steaming one pad
with the other to follow shortly. We will see first production from these pads
by year-end.
This development is another example of our
commitment to continuous improvement through technology application and shows
how we continue to apply new technology at Cold Lake today;
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The well design and layout in this development has been custom-fit to the
resource.
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Looking at the illustration in the bottom right of this slide, you can see
that these new 'mega' pads use horizontal as well as vertical wells. One pad
can now access the same resource as three standard Cold Lake pads, which
reduces the overall capital required -- and the surface footprint -- for this
development.
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For successful thermal operations, it is essential to control the steam
distribution in a horizontal well to achieve optimal production results.
Imperial has developed a patented completion technique with a unique wellbore
assembly to achieve this objective.
Imperial is a founding member of the Syncrude consortium established in 1964
and remains the operation's second-largest owner, holding a 25 percent
interest.
Syncrude is the largest oil-sands operation in the
world, with a resource base to support decades of production. Annual
production from Syncrude has steadily increased since its start-up 25 years
ago.
Stage 3 expansion included the addition of a third,
100,000 barrel a day coker which increased the site capacity by 40 percent.
The expansion project was completed and started up in early May, but
unfortunately had to be brought down to deal with a persistent odour problem
associated the start-up of the new flue gas desulphurization unit.
Syncrude has been working with experts from ExxonMobil to resolve this
unexpected problem and feed was re-introduced to the new coker at the end of
August.
Let me turn now to Kearl, a proposed bitumen mining project in Fort McMurray.
Imperial owns a roughly 70 percent interest and is operator of the project.
The remaining 30 percent is held by ExxonMobil Canada.
The
Kearl leases hold sufficient bitumen to support a 300,000 barrel a day mine.
We plan to develop the Kearl project in phases with the initial phase sized at
100,000 barrels a day, and two subsequent phases to follow.
To date, we have completed conceptual engineering and process selection for
the project.
The regulatory application was filed in July
2005 and public hearings by a joint provincial/federal panel begin October 30.
We hope to have a decision by the Alberta Energy and Utilities Board early
next year.
Kearl is arguably the best undeveloped resource in the Athabasca region.
This chart plots projects based on the relative size and quality of the
bitumen resource.
The "x" axis plots "TV to BIP" (total
volume to bitumen in place) -- a key quality metric for mineable oil sands.
This measures the total volume that has to be mined -- overburden plus ore --
relative to the amount of bitumen-in-place. Low numbers are better. Less
material is handled for each barrel of bitumen produced, so there is a natural
operating expense advantage for a mine.
The "y" axis plots
recoverable resource. The "sweet spot" on this graph is the upper left hand
corner indicating high quality and large recoverable resource.
The red circles represent industry projects -- both producing and proposed.
The blue symbols represent the projects that Imperial is participating in --
you can see that Syncrude and Kearl are both high quality projects and Kearl
is the best of the bunch.
For the entire Kearl mine -- all
three phases -- TV to BIP is 7.8. The combination of the high quality of the
Kearl resource on the site and large recoverable resource -- 4.6 billion
barrels at a TV:BIP prescribed cut-off of 12 -- is a significant long term
economic advantage for development of this project.
I'd like
to add that although the current mine plan filed in our regulatory application
for Kearl is 4.6 billion barrels of recoverable bitumen, total
bitumen-in-place on the Kearl leases is over 13 billion barrels.
For the first phase of Kearl, we plan to market the bitumen as a blended heavy
or sour crude, selling into the increasingly expanding North American markets
for Canadian heavies. Marketing plans for volumes from additional phases are
being developed.
Our assessment is that the most economic approach for the first
100,000 barrel a day phase of Kearl bitumen is to market to existing upgrading
facilities.
Imperial refineries already process a significant
amount of heavy crude oil and we will advance low-cost expansions to take
more. But, more broadly, we expect that there will be additional heavy crude
capacity in North American markets.
For capital-intensive
industries, the most attractive investment is incremental expansion, or
"creep" -- and this is especially true for the refining business.
The blue bars on this chart illustrate current coking capacity, expressed in
thousands of barrels of heavy crude equivalent -- over 7.5 million barrels a
day in the North American market.
Modest creep shown in the
blue hatched bar of only two percent a year will yield an additional 1.7
million barrels a day of capacity by 2015. In addition, there are proposed
upgrading projects in Canada, shown in the red checkered bar -- either
stand-alone or with dedicated bitumen supply -- that could deliver an
additional two million barrels a day by 2015.
We'll continue
to evaluate upgrading facilities at our Edmonton refinery. But a decision to
do so will not be made until we're convinced that over the long term this
capital investment will be profitable, competitive and yield attractive
returns for our shareholders.
I'd now like to update you on our opportunities outside of oil sands.... I'll
start with the Mackenzie Gas Project.
The Mackenzie Gas
Project is an important new source of gas for North America.
This multi-billion dollar initiative proposes to develop six trillion cubic
feet of onshore gas from three "anchor" fields in Canada's north.
With three trillion cubic feet of natural gas, the 100 percent Imperial-owned
Taglu field accounts for half of the discovered gas resource in the Mackenzie
Delta, and is one of the continent's best undeveloped gas resources.
Provision is being made to accommodate other companies' natural gas as well.
Anchor field production is projected to be about 830 million cubic feet a day,
with the ultimate capacity potential of the pipeline being more than twice
that volume -- 1.8 billion cubic feet a day.
Much progress
has been made on this project in the past year. Regulatory hearings began in
January, and between the National Energy Board and the Joint Review Panel, a
total of 150 days will take place in some 26 communities. Hearings will
conclude in mid-December as originally scheduled for the NEB but the Joint
Review Panel has asked for additional hearings day into 2007. Given this
extension, we anticipate a regulatory decision by late-2007 at the earliest.
We continue to progress negotiations on benefits and access agreements and we
have made substantial progress with agreements with four of the five First
Nations groups affected by the pipeline.
Our intent remains,
as it always has, to negotiate benefits and access agreements with the other
major First Nations group -- the Deh Cho -- and to have those agreements fully
ratified and executed. We are encouraged by the recent Deh Cho land claim
settlement offer tabled by the federal government, which could help clarify
land issues and progress discussions between the Deh Cho and the Mackenzie
project.
As with all major energy projects today, the
Mackenzie project is facing cost and schedule pressures brought on by
unprecedented global demands for energy infrastructure. The upfront capital
costs for frontier pipeline projects are significant and the Mackenzie Gas
Project is facing upward pressure on costs, including commodity pricing for
equipment, steel, labour and fuel, with an unprecedented regulatory process.
We continue to develop plans aimed at refining and reducing all aspects of
cost, and we expect to have a revised cost and schedule estimate later this
fall.
Once we have regulatory approval to proceed and better
understand the economic conditions, we will be in a position to make a
decision on the project.
The Mackenzie project represents the most advanced project we have
in the Arctic, but our position in this exciting region extends far beyond the
delta of the Mackenzie River.
Imperial has an interest in
some one million acres of resource in Canada's Arctic, shown on this map in
yellow (industry in green).
We have interests in 44
significant discovery licenses and we are the designated operator for over
half of these (shown as the yellow blocks outlined in black).
And, not shown on this map, we hold a significant lease position in the Arctic
Islands, much further north.
There are many barriers to cross
before we are able to see the true potential of these resources, but they
remain another future source of production in our diverse and high-quality
resource portfolio.
Finally, turning to the East Coast, I'd like to update you on our efforts in
the Orphan Basin.
This large, unexplored frontier basin
offshore Newfoundland's east coast has favourable characteristics for
hydrocarbons.
Eight deepwater parcels -- shown in yellow --
were acquired in 2004. The project co-venturers include ExxonMobil, Chevron
and Shell. Imperial's interest position is 15 percent.
The
leases cover over five million acres -- a very large position in a promising,
unexplored basin.
3-D seismic was acquired in 2004 and 2005
and the first exploration wildcat well, operated by Chevron, was spud in
mid-August by the 'Eirik Raude' -- a deepwater drill rig pictured in the
bottom right. There is the potential for two or more additional wells on these
leases in the future.
Icebergs and a short weather window in
this deepwater area present challenges. However, should a discovery be made,
the technology exists to progress a development.
This chart illustrates our near-term production profile, with conventional oil
and gas operations in Western Canada in red, and the oil-sands contribution in
green.
The far right is a projection of potential production
by 2015.
Conventional volumes are expected to decline over
time, but this decline will be more than offset by growth from the oil sands,
Mackenzie gas and other opportunities.
I want to point out
that there is essentially no resource risk for most of the components of this
projection. All of this resource has been delineated and our focus now is on
development.
Everything below the top orange portion -- which
is indicative of some success in the Orphan basin or other frontier areas --
is already in our non-proved resource base.
This projection
illustrates that Imperial's resource base and potential new discoveries could
support an increase in upstream volumes of almost 50 percent over the next 10
years.
Let me close with a summary of the key points that I believe distinguish
Imperial in the marketplace.
Our resource base represents
significant future development and growth opportunities.
We
have industry-leading technology and operating experience with a high
commitment to research and technology development.
We are
financially strong and possess a disciplined management approach focused on
growing shareholder value.
Imperial's strong financial
position has earned and sustained a triple-A rating from Standard & Poor's
-- the only Canadian industrial with this rating.
Earnings
are excellent and our return on capital is the highest of the Canadian
integrated group.
Annual per share dividends have increased
eleven years in a row -- and we have an ongoing share repurchase program.
And the bottom line, for any investor, underpinning our strengths is the
continued focus on long-term quality earnings growth.
Thank
you.
For more detailed investor information, or to receive annual and interim
reports, please contact:
Investor Relations
Imperial
Oil Limited
237 Fourth Avenue SW
Calgary, Alberta T2P 3M9
Email: investor.relations@esso.ca
Phone: (403) 237-4538
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