EX-99.2
Exhibit 99.2
Imperial Oil Investor Day 2013
Mr. John Charlton: Good
morning and welcome. My name is John Charlton and I’m the Investor Relations Manager for Imperial Oil. This morning Imperial’s senior management will take you through all aspects of our business.
With us today on my left is Rich Kruger, the Chairman, President, and Chief Executive Officer of Imperial Oil; Glenn Scott, the Senior
Vice President, Resources; and Paul Masschelin, the Senior Vice President, Finance and Administration, and the company Controller. Also joining us today is George Bezaire, our Director of Corporate Planning.
We plan to finish the formal presentations around 11:15 a.m., leaving about one hour or so for questions. When you wish to ask a question,
would you kindly wait until a microphone is brought to you so participants on the webcast can also hear your question. Shortly after noon, we’d be pleased if you would join us for a brief luncheon.
Before we begin, I’d like to take a moment to review some important safety information. In the event of an emergency here at the
Stock Exchange, an alarm will sound. At this point, please remain alert and listen for further instructions.
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If an evacuation is required, please follow the instructions of the Deputy Warden on this
floor. You can recognize this official as the uniformed security guard stationed on this floor for the duration on the event today. Should any emergency arise, this officer will assist us directly.
At this time, I’d also ask everyone to please turn off your cell phones and other electronic devices.
I’d like to draw your attention to the fact that this presentation today does contain forward-looking statements, and actual results
may differ as a result of many factors, some of which are noted on this slide.
Canadian reporting standards require that we
provide clarity with respect to the non-proved resource basis, and the fourth paragraph provides for this requirement.
Unless
otherwise specified, all figures are in Canadian dollars.
It’s now my pleasure to introduce our Chairman, President, and
Chief Executive Officer, Rich Kruger.
Mr. Rich Kruger: Thanks, John.
Good morning. Welcome, and welcome to those of you not only here in the room with us but also those of you joining us on webcast.
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I haven’t had the opportunity to meet most of you, and I look forward to doing so. So,
what I thought I would do is take a minute or two and introduce myself a little bit.
I’m an engineer by background.
I’ve spent nearly 32 years with ExxonMobil on a wide variety of assignments around the globe. I have worked primarily in the upstream, a lot of drilling projects, operations work, of course business planning, and some commercial assignments.
I’ve had the opportunity to work on--I think the last count was probably 20-some countries on six continents with a heavy
focus on major capital projects and operations, onshore, offshore, oil, gas, and Arctic LNG. And for the last five years I was the President of ExxonMobil’s Global Production Company. And that involved 20-some countries and a little shy of four
million oil equivalent barrels per day.
The relevance of that, and why I wanted to emphasize it, is because it has really
provided me with an opportunity to look at a diverse set of operations and best practices, standards, and really see where and what is the best of the best. And when we talk about Imperial Oil--and I hope you get this sense today--our mission is to
ensure that it is the best of the best. So, I think my background is relevant.
When I look at Imperial, I think it’s a
very exciting time. We have not only a very large, profitable base business but
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we’re on a significant growth path. And we’ll talk a lot about that today.
A theme you’ll hear from us is that all of our efforts are underpinned in some way or another by technology and innovation and the value that it creates for the shareholder. So, we will weave that
into our upstream, downstream, and chemicals storylines.
Today we’re going to talk about our share performance and our
plans. We’re going to talk about not only what we are doing, but also how we are going about it and how we believe we uniquely create value for the shareholder.
We’ll cover all segments of the business. We’ll have a heavier emphasis on the upstream because of the investment in growth. You’ll hear a great deal about Kearl--Kearl’s status plans
and what makes Kearl unique and different. And we look forward to any questions you may have on it. We’ll focus most of our comments on the next several years and the rest of the decade. But, we will give you a glimpse beyond that and what
we’re working on today that will position us for even longer term growth.
So, with that as an introduction, what I’d
like to do is just take a few minutes, and I’ll be brief, and give you a bit of what underpins our business strategies and plans. And I’ll use the energy outlook as the vehicle to do that.
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I believe most of you are familiar with the fact that ExxonMobil develops a very
comprehensive energy outlook each year looking at supply-demand trends, technologies, social trends, population trends--assembles all that, looks at a wide variety of sensitivities and variations. But, what it does, really, is helps guide our
strategies that underpin our long-term investment plans.
If you go back in time, this was something that ExxonMobil held
internal and used for the purposes I mentioned. But, over the last many years, it’s been shared externally to help increase energy literacy and help policymakers understand the challenges, the timelines and the investments that are involved
with the energy industry. So, I’ll just give you a quick rundown on some of the highlights and then bring it back to Imperial.
So, first and foremost, I’ll start out with economic growth. The world’s population is growing. It’s projected to grow from about 7 to about 9 billion over the period shown by 2040. Along
with that, that growing population will produce a growing economic output.
That economic output is going to take energy to
fuel it, and the relationship is shown here on this chart. So, we roll that together, and the anticipation is that global energy demand
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will be up about 35 percent over the 30 year period from 2010 to 2040.
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think when you look at this, it’s interesting to look at the relative disparity between the developed and the developing world. And it’s also interesting, when you look to the right, to look at the expected savings from efficiency gains as
technologies, fuels, energy practices, building standards in all sectors in all countries strive for a greater energy efficiency.
And if you were to be a skeptic and say it wouldn’t unfold, well, I think what you’d conclude is there’ll be an even greater demand for energy. So, as we look at this, the long-term
fundamentals for demand growth are there as economic growth and standards of living continue to improve. So, that’s kind of at a high level.
Now let me take you to the next one. To meet this demand growth, the world will need diverse, reliable, affordable supplies of energy. And in the outlook that we share, it’ll be demand for energy
from all energy sources.
We see oil continuing to remain the largest single source at about 30 percent or so of the total
energy picture, yet significant growth is anticipated over this time period. I’ll talk some more about liquids here shortly.
We see gas overtaking coal as the number two energy source and, among the largest sources, the fastest growing. Many
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advantages: its abundance, the technologies involved, the environmental benefits.
And then, I’d just draw your attention to the other category. Other includes a range of energy types and resources. Significant growth--but over this period it’s still a relatively small part of
the total picture. And, of course, this includes renewables. So, as you step back from it, there is a significant challenge to deliver the energy, technology involved, investment capital, and then of course human ingenuity over the time period.
If I bring you a little bit closer to liquids and look at the liquids supply we see it going from about 80 million
barrels per day in 2010 to roughly 100 million barrels per day in 2035. I would note this is an International Energy Agency forecast, so the timelines are a little different. And I like to show this to you, because I think as we look at the
numbers and the relative changes in totals, what’s important is to look at the new supplies that would be required when you take into account the natural decline of existing resources, fields around the world.
And the IEA, in doing this, looked region by region, in some cases major field by major field, at where these assets are in their
lifecycle, and projected year by year declines over the period. It’s not linear over the period. In fact, the decline
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gets a bit steeper later in the period. But, that’s how they come up with this. And the implication, again, being large new investments are needed to develop the liquids supply to meet the
world’s demand.
If I zoom in even a little closer here to North America specifically, a lot has been written and said of
late about the shale oil boom, tight oil activities in North America, US in particular, about concepts around energy independence. And when we look at this, what we certainly see is the outlook reflects shrinking imports over time. And the outlook
here shows that North America, from a supply-demand standpoint, could be balanced in the post 2030 period.
I would ask you to
note that in achieving that balance, you would see significant growth for Canadian oil sands. Now, where crude supplies come to are more complex than just where they’re produced. But, I think, as we look at this, we see that there is room.
There’s a home for Canadian oil sands to continue to grow and develop through the period, in fact a several fold increase
over the current level. And there are a lot of outlooks on this. I’ve seen outlooks significantly higher for the oil sands than is shown in here. And I’ve seen many others in this same range.
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So, those three charts are a very quick summary of the energy outlook. But, again, I want to
emphasize that the importance of this is it’ll provide context and perspective that underpin Imperial’s business plans in the years ahead. So, I’ll move past that and now I’ll bring us closer to home and we’ll talk about
Imperial.
We’re going to talk about three broad areas. I’ll talk briefly about our business model, the fundamentals,
the approach that we take to deliver value. We will then get into a series of discussions on performance trends and plans for downstream, chemical, and upstream. We’ll look at absolute performance from year to year, and then we’ll show you
a number of relative comparisons to competition. And then, we’ll start to wrap up a bit later with this kind of view to the future.
The overriding message, if you walked away with one thing and one thing only, is that we have a very large, profitable base business across our business lines. And we are entering into a period of
significant growth and creation of long-term value.
Let me continue with our business model. The words here are consistent and
describe upstream, downstream, and chemical. And at its core, it’s all about delivering superior long-term shareholder value. The fundamentals for us is that we have and we seek to have long-life advantaged assets. We’ll describe to
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you the life and nature of our assets and what we believe to be the competitive advantage associated with them.
We’re very focused on ensuring a very disciplined investment and cost management approach. As we decide on our investments, we’re very, very rigorous in the analysis and upfront evaluation. And
then, once we’ve made a decision, that shifts to a very systematic approach to project planning and execution and then it continues on its lifecycle of operation. I’ll talk more about that.
Integration and synergies is a big part of our story. Paul will describe to you integration in particular within the downstream: chemicals
and refining, lubes and refining. But, increasingly key to our strategy is the integration with our growing upstream operations as well. Paul will flag that. I’ll talk more about it as we go.
Technologies: underpinning all of our efforts and our improvement over time, our value, our commitment to developing high-impact
proprietary technologies, and then the innovation that goes with applying those technologies in the field, in the facility to deliver value.
Last but not least on the chart, operational excellence and responsible growth. I’ll come back to this. It’s about managing risk and managing it appropriately.
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All of our business model is supplemented and supported by the unique relationship we have
with ExxonMobil. As a majority shareholder, it’s--as I was describing when I was describing my experience--the ability for us to broaden our aperture and benefit from global experiences, global practices, standards, and ways to improve our
business by looking at a bigger view screen than the assets we have. As I come into this new job, it’s an area that I will place a great deal of emphasis on to ensure that we achieve the best of the best, not just in Canada but in a much
broader and global sense. And that relationship with ExxonMobil is very valuable to us. We’ll have more on that as we talk throughout the day.
I commented on operational integrity, operational excellence. Let me pause here for a moment and talk about fundamentally managing risk. Those risks can be financial risks. Those risks can be external
risks in some way when we go outside the property line.
The little diagram shown here, and I know it’s complex,
represents the comprehensive, the systematic approach we take in managing operating risk. Our Operations Integrity Management System is a system we’ve applied for about 20 years now. It has been tested and reflected by many to be kind of the
gold standard, the best of the best in industry.
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But, it’s something that all of our employees countrywide, top to bottom, are skilled
and trained in. They understand their roles and responsibilities. It has components to it that deal with people and training, the work processes and procedures, and then the equipment maintenance and standards. Very comprehensive because we know, in
our business, it all starts with operational integrity and risk management. And that is a never ending quest, journey, day in, day out.
So, on the next few charts, I’d like to highlight a few results that come from our focus on operational integrity. And I’ll start with safety. At Imperial, safety is first in all we do.
And to give you a sense, why is safety so important? Well, there’s the obvious aspect of it. It’s the right thing to
do for people. We have a moral obligation to provide a safe workplace. That’s number one.
I would also add that working
safely is good for the business. When we have a safety incident, it causes you to pause, to stop, to investigate, disrupt your activities, and it disrupts your business plan. So, working safely, good for people, it’s good for business.
And third, or last but not least, is it affects our reputation. It affects how others look at us--whether that’s
governments, whether that’s regulators, partners, contractors,
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customers, or our employees. And the stronger safety performance we have, the more folks want to work with us at all those levels.
So, for us safety is one of those really easy things to put at the top of our priority list, because there’s no tradeoff on it.
It’s good for people, it’s good for the business, and it affects our reputation.
And for us, what that means is
hazard recognition and risk assessment, the quality of our procedures, and more than anything, a workforce culture that believes and supports our mission, our objective, that nobody gets hurt. Independent of the color of an individual’s
hardhat, employee or contractor, nobody gets hurt when you work for us.
And on the left I show a performance trend. And
I’m really pleased to share that 2012 was Imperial’s safest year ever. We’ve had a continuing trend of improvement over time. If you were to benchmark us versus industry, you’d see a significant leadership position on Imperial
Oil. Here again we benefit from interchanges and sharing lessons learned with ExxonMobil, and have the same sense of priority.
Over that time, I would just comment we have essentially doubled our work hours over the period shown here with project growth. And while
we’ve doubled the work hours, we have reduced the absolute number of injures in our workplace, injuries where
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someone required some form of medical attention, from a cut and a few stitches to something more serious.
We’ve reduced that, despite doubling hours. We’ve reduced it by about 20 to 25 percent. So, it’s a two and a half fold improvement over the five year period shown here. This is an area that
we will have continued focus. It’s a never ending quest.
Let me continue. Spills and other releases, these are oil
spills, large produced water spills, and releases to the environment–--chemicals or light hydrocarbons. Our mission here, obviously, is to not lose primary containment of the products we produce. If you look over time, you continue to see a
downward trend. And again, 2012 was the best year ever that Imperial had in operational integrity as it relates to spills and releases.
Air emissions includes three categories: sulfur dioxide, or SOX; NOX, the nitrous oxides; and VOCs, or volatile organic compounds. Now, these are all emissions at our operating facilities. They all are
permitted, and we certainly comply with all of our permits here.
What is shown here is our trend over time. And despite a
growing business, you see a reduced footprint or a reduced impact with lower emissions. 2012, again, lowest ever emissions for Imperial Oil. And the emissions here and certainly the
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spills and other releases all goes back to that commitment to operational integrity and the safety of our workplace.
I share these trends. I’m pleased with the directions on them. But, what I would say is we recognize this is something that’s a never ending journey. You don’t take your eye off the ball.
And our focus in this area, we believe, helps our focus in all those other areas that are so important, including the profitability of our business.
And now I would like to shift to talk about our financial and operating performance. Net income per share is shown in the table. A few highlights: 2012 highest earnings per share ever for Imperial, second
highest earnings in total, just slightly behind 2008. We had a 23 percent return on capital employed, strong operational performance in the upstream in particular.
Glenn will describe strong performance at Cold Lake as it continues to grow, and then a strong performance continuing into the new year. Downstream, with a very advantaged crude slate, taking advantage of
that for the reliability of our facilities and getting the most out of the downstream. You’ll hear that from Paul.
Strong
cash flow, and a lot of significant progress in our major growth investments. So, a strong, strong year, something we look to continue to improve upon.
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As I’ve been in the role for about three months now one of my initial priorities upon
getting to Calgary was to go out and to meet people and see all of our facilities. So, I visited our refineries, chemical plant, lube plant, and upstream operations.
I should have commented earlier. I have been involved with Canada over the years, and my first visits to Cold Lake and Syncrude were about 18 years ago now. So, the upstream in particular has been a
pretty quick learning curve because I have a lot of historic familiarly with the assets.
But, as I went out and I looked at
and I understood in a deeper manner our operations and our folks there, what I was particularly impressed by, and I wanted to summarize it here, is the leadership position we have in virtually all of our business lines. Cold Lake obviously is a
large, high-quality in-situ operation.
Syncrude, we’ll talk more about it, but the scale of the mining operation here.
Kearl we’ve described as next generation. We’ll spend some time talking to you about what we mean by next generation, what makes it unique.
Our strong refining position, which has increasing integration value with the upstream. A fuels marketer, a major fuels marketer, lubes, polyethylene, other chemicals, and then asphalt. I like this
because we’re in a position of strength
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today. And in each of these areas, I see it as a platform for continued improvement and, in many cases, growth.
What I have enjoyed the most in my first three months is seeing the facilities, meeting the people, aligning around the strategies, and the consistency with which Imperial approaches its business.
Let me continue with return on capital employed. Maximizing our investment value and our lifecycle performance is fundamental.
And I commented a few minutes ago about how, as we undertake an investment, the comprehensive review and evaluation, looking at an investment over a range of possibilities, possible business outcomes, performance. Then, once we make that decision,
rigorously applying project planning and execution, and then, over the long term, the operational excellence that goes with it.
We look to maximize lifecycle value and we think the return on capital employed is probably one of the better indicators of that. We have
a strong industry leadership position. If you look at it in a one year, five year, 10 year, whatever period you look at, you will see Imperial in this strong, strong position.
And that is something that we think represents, reflects how we go about the business. And you can expect from us that
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we will continue to approach the business in the same disciplined manner as we invest and operate in the years ahead.
The second area, continuing with the theme on value to the shareholder, is our shareholder distributions over the last 10 years. And really, it’s dividends and share reductions or share repurchases.
As we look at our use of our cash flow, we’ll look at the dividends, certainly.
And we understand where we are, where we
stand competitively now. We’ll look at the growth investments and the opportunities in front of us. And then, when the opportunity exists, we’ll look at reducing the shares to increase the power, the value on a per share basis.
The last 10 years, relative to the folks shown here, were unmatched in that regard. In the current period, we’re undergoing major
growth, as you’re aware. We’ll talk more about that. So, the bulk of our cash flow, obviously, is going into capital investments for the major growth.
As Kearl in particular comes on-stream in a much bigger way, that position will change and our cash flow position will strengthen significantly in the near term in the years ahead. But, what I would offer
you is our commitment to delivering shareholder value, distributions, dividends, share repurchases, and growth opportunities has not changed. It will not change.
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We look to remain the leader in the areas shown here. We’ll talk more on that.
I thought an interesting way to look at this is over the last 20 years, with the shares that have been repurchased--and you have to look at this after a split basis, kind of apples and apples--we have
repurchased more than half of the company over the last 20 years.
And when you look to the right of the chart, you can see
what that has led to. You look at our fundamental operating parameters: crude production, refinery throughput, chemical sales, and proved reserves, and in essence each share has two to three times the ownership than it did 20 years ago.
And I’d ask you to remember this chart when we look at the upstream, because what we’re going to share with you is our plan
through the end of this decade is essentially doubling the size of our production volumes by the end of the decade. So, this twofold increase you see on crude production, we’ll show that at another point in time and with the same share basis.
That’s on its way to a fourfold increase. I thought this was an interesting way to look at the leverage and the potential value on a share basis.
Going ahead, looking at where we are today on our proved reserves in the upstream, we have a very long-life, high-quality proved reserve portfolio. It’s concentrated in the three main
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asset areas shown here, Cold Lake, Syncrude, and Kearl. Glenn will take us through each of these areas.
When you look at our reserves to current production life, Cold Lake, Syncrude, 20 to 30 years proved reserve life, and we’re not done. We have continued growth opportunities there. Kearl, if you ramp
Kearl up to its initial designed capacity and then you go to the expansion project, you’ll look at an equally or even a longer reserve life.
I like the long life, high quality aspect here. It gives us time to not only ensure the profitability today, but continue to focus our efforts on improving the profitability through technology, through
innovations, and just good, hard disciplined operating practices. And that long life is something that gives us the opportunity.
It’s not something that we say, “Well, we have a lot of time to work on it.” Our urgency, the focus is there today. But,
the bang for the buck, the benefit is seen and observed year after year after year. And I think Cold Lake is probably our strongest story in that regard, and Glenn will take you through how that performance has improved year after year.
Now, on the non-proved, the resources that are not in that proved, producing category. We have 3.6 billion barrels there. We also have,
within our portfolio, 13 billion barrels of non-proved resource to support continued profitable growth. Each of
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these bars are just a representation of that 13 billion barrels. And the first one represents how--as we sit here today--how do we see it materializing, in-situ, mining, or other.
Well, you can see we’re a predominantly liquids portfolio. And then, on the far right, I thought this would be helpful to you. As we
look at that 13 billion barrels, where do we have our sleeves rolled up and what fraction of that are we earnestly progressing today?
We have efforts across the full resource base. For more than three billion barrels, we have focused, concentrated efforts on evaluations, in some cases fieldwork, in some cases pilots, to move that three
plus billion barrels toward a proved reserve.
That’s of a comparable size to our 3.6 billion barrels of proved reserves
today. And there again, I would just ask you to think about that in terms of the long life and the growth potential that provides for us. And we’ll get more specific throughout the review.
I’ve referenced our plans to essentially double by the end of the decade. These are not pencil and paper plans. These are plans that
deal with cutting and welding steel. We are executing these plans as we speak.
In the last decade, we averaged about $1
billion a year of investment. And as you look at the current decade, with the
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plans that we’re executing, we see that more in the range of about $4 billion a year. We’ll spend more than that this year. The last couple years we’ve invested more than that.
So, the plans, as laid out now, later in the decade will taper off a little bit. But, they’re tangible. Kearl is the
biggest single driver behind this. Nabiye, another expansion at Cold Lake, is another piece. Continued growth investment at Syncrude, as well as other Cold Lake base investments.
Later in the period, later in the decade, we’ll have some additional opportunities that we anticipate funding and advancing. And
I’ll give you some names and faces to those later in the review.
So, what will all that do? This is the point. What you
have here is an upstream production outlook by year, then jumping out to 2016 and to 2020. The 2020 bar is shown two ways, by its composition or its make up, but then the bar on the right is its status. Is it existing, proved, developed, producing?
And then, in cases starting up, which is Kearl, the initial development, the under construction, which is Kearl expansion and Nabiye for the most part. And then, projects that are not yet sanctioned, but we anticipate doing so in the years ahead.
So, the 2020 bar, at about 600,000 barrels a day is essentially double a bit less than 300,000 barrels a day at this
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point in time. And 200,000 barrels a day of that increment is funded and in the execution mode.
We have the financial strength to support these plans. Our balance sheet, we believe, will be maintained over a wide range of scenarios. What I’ve shown here is what our debt to capital ratio is
anticipated to be with the plans that I’ve outlined here, and then under two different scenarios. We’ve used a $55 WTI, a $95 WTI, and then, of course, representative discounts for heavier crude off of that.
And as we look at that, you can see we’ll get in a position here shortly where cash flow will be strengthened and improved.
We’ll be bringing down this ratio. In our mind, it continues to support a strong triple A rating, but it also provides us flexibility for any new opportunities we might see in the marketplace and the ability to fund or finance those.
So, our position’s strong. The plans are being executed, double by the year 2020, and we have not only the capability to
execute those plans, but the financial wherewithal to achieve them in a manner that aligns with the long term financial discipline that Imperial Oil has shared.
At this time, I’m going to ask Paul to come up. Paul will talk about our downstream and chemical business, and then we’ll continue on with Glenn on the upstream. And then, I’ll come back
later in the review.
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Mr. Paul Masschelin: Thank you, Rich.
What I’d like to do is spend a couple minutes with you to talk about our refining and chemicals businesses. Being an integrated oil
and gas company not only has significantly added to earnings as we have seen this period of low mid-continent crude prices, it also provides us the flexibility to add value in a number of other ways. And I’ll highlight these as I go through my
slides.
Let me start with refining. We have four refineries, about 500,000 barrels per day, which is equivalent to about a
quarter of Canada’s refining capacity. Critical, of course, for the profitability of that business is to optimize our crude slate, which we do through our own supply and trading organization as well as by leveraging ExxonMobil’s
experience.
And of course, the objectives here are straightforward: to maximize the value of our equity crudes, and second,
making sure that we have cost advantaged feedstock for our refineries. However, integration does not stop there. We are integrated with the chemicals business, where we produce polyethylene, solvents, intermediates, just to name a few. Also, and not
shown on the chart, but we are also integrated with a lubricants and an asphalt business.
And so, being an integrated producer
really allows us to leverage our assets and our organizational capabilities to
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maximize the value of every molecule. We can run our own equity crudes or we can decide to buy crudes for our refineries and leverage our logistics capabilities to get that feedstock to our
plant.
We can direct feedstock to the manufacturing of fuels or chemicals or lubricants, depending on market conditions. We
can export or import products which we can then sell through our own marketing channels, through wholesalers or distributors. And so, underpinning all that is a team of experts and individuals whose sole job it is every day to analyze and make these
optimization decisions.
Now, we do realize that our refining and chemicals business is operating in a mature business
environment and, as such, volume growth opportunities are limited. And so, that is really the backdrop for the strategic priorities which you see listed on this chart: deliver best-in-class reliability and cost performance; leverage our market
know-how and our technological capabilities to deliver high performing products at competitive prices, and, as required, support that with technical expertise; third, relentlessly drive for effectiveness and efficiency improvements; and then lastly,
when it comes to capital investments, be very selective. And what I’ll show you in the next couple of slides is how we put these strategies into action and the results which we will show from them.
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Against the background of the mid-continent crude prices being low as we have observed for
the past two years or so, our downstream business earned $1.8 billion, which was not only a record, it was also about half of Imperial Oil’s 2012 earnings. With a refining throughput, which is about twice our crude equity production, we not
only maximize the value of our upstream production but, of course, add significant value from purchased feedstocks.
As you can
see in this chart, the bar chart on the left, which was compiled by Barclays Research, we have a strong competitive position. But, at the same time, we have further opportunities to improve.
Talking about improvement, obviously ascertaining that our refineries can run on a mid-continent crude diet is an important characteristic
at this point in time. I’ve shown on the chart both Strathcona and Sarnia refineries are currently on a full mid-continent crude diet.
Nanticoke still has about 40,000 barrels a day of imported crude. And the reversal of line 9A, as well as additional rail and loading capacities, which are in place are putting us in a position that,
about a year from now, we should be able to also have Nanticoke on a full mid-continent crude diet.
With regards to Dartmouth,
we had previously announced that we are going through a strategic assessment of that asset. And
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we should be in a position to make a decision with regards to Dartmouth in the next number of weeks.
This chart illustrates our relentless pursuit of efficiency gains as well as selectivity of investments. At about a third, energy costs are by far the largest cost category in running refinery assets. And
as you can see on the chart, over the past 10 years we have worked very hard to improve our energy efficiency by about 5 percent. And as such, we have furthered distanced ourselves from the other North American refineries.
Let me shift to the chart on the right. If you go to the first half of the last decade we had capital expenditures in our downstream and
chemicals business slightly above depreciation. That was mostly driven by investments which we made to remove sulfur from our refined products.
If we go to the more recent five year period, really we have been even more selective with investments and really focused them on renewing our marketing assets and very selectively investing in refining
and chemicals, mostly directed towards environmental and/or safety improvements.
The strength of our integration across
upstream and downstream of course also extends in the way we support bringing Kearl crude to market. The table you see on this chart, which was compiled by Wood Mackenzie, illustrates that a combination of Imperial Oil’s refining assets along
with ExxonMobil’s North
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American refinery assets gives us sufficient capacity to run the entire production of the Kearl Initial Development. And that is, of course, a very relevant contingency plan when we bring a new
crude to market.
Also, as we will be bringing Kearl crude to market, we will be leveraging our own experience with regards to
crude trading as well as leveraging ExxonMobil’s capabilities. On top of that, we have unique modeling capabilities so that we fully understand the economics of every crude as we run it through our refineries. So, in other words, we believe
that we have access to the organizational capabilities as well as the assets to maximize the value of Kearl production.
Now,
the value generation in the downstream does not stop at refining, supply, and trading. It extends into the marketing side of our business. We provide quality products through a number of distribution channels. And as you will see as I take you
through it, we are a significant market player in the markets which we serve.
Let me start out by briefly talking about our
retail business. In Canada, we have just under 1,800 Esso branded retail sites. What that means is that about one in five Canadians fuels their vehicle with Esso-branded distillate or diesel or gasoline.
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If I shift to our aviation business, we have a market participation of 25 percent plus for
commercial and about 20 percent in general aviation. If I look to our lubricants business, we have, through our flagship Mobil 1 products, a market participation of about 30 percent.
In addition to leveraging our own brand strength, we also have alliances and partnerships. And two of them are on this chart. 400 of our
retail outlets also have a Tim Hortons outlet associated with it. If we look at our company-owned retail stations, almost all of them have a Royal Bank of Canada ATM. So, it’s, again, maximizing the value of integration in the brand.
Let me shift and briefly talk about our chemicals business. As you can see on the chart, chemical sales last year exceeded a
million tonnes. The two largest components are our polyethylene business, about 450,000 tonnes per year, the next biggest segment our solvents business, about 150,000 tonnes per year. As you can see, healthy earnings of more than $160 million, and
that’s on sales revenue of about $1.3 billion, and a return on capital employed in excess of 60 percent.
And again, what
this reflects is two things. It’s integration with our downstream business, and secondly, leveraging our technological capabilities to produce value-added
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products. And our polyethylene business in Sarnia is a case in point.
The steam cracker which we have in Sarnia is fed by refinery off-gasses, and it can also crack ethane and propane. And then, that cracker
is integrated directly with a polyethylene plant. These assets greatly benefit from being integrated with the refinery not only from a feedstock perspective, but we have a shared maintenance organization. We leverage logistics assets. Of course, we
coordinate turnarounds, just to name a few.
Then, if you look at the output of the polyethylene plant, we leverage the
location which we have as well as our know-how to direct the production from Sarnia, to a large extent, to the rotational moulding business, which you see in the picture on this chart. And we are the major supplier into the rotational moulding
polyethylene business in North America.
As we look out into the future, further opportunities which we see is that, later this
year, we will be bringing Marcellus ethane to our stream cracker in Sarnia to have additional access to advantaged feedstocks. Also we are looking at further creeping our capacity at our Sarnia chemicals plant.
Let me wrap up and give you some financial data on our downstream and chemicals businesses. As I mentioned, the dislocation in the crude
prices in the mid-continent since the
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fourth quarter of 2010 allowed our downstream business to deliver very strong results and an increasing proportion of our total earnings, a downstream business which returned more than 60 percent
return on capital employed in 2012.
Now, at the same time, we do understand that these arbitrage opportunities which are there
today will not last. And therefore, the strategies which I talked about for the businesses downstream and chemicals are strategies which we adhere to.
And adhering to these strategies will allow us to deliver double-digit returns even at bottom of the cycle conditions. We also ascertain that these businesses continue to generate significant cash flow,
which you can see on the right-hand side of this chart, which we invest in the growth of our upstream business, which Glenn will be talking about here shortly.
But, before Glenn comes and talks about the upstream business, I suggest that we take a six, seven minute break to refresh your coffee. And let’s get back together at 10:25 Eastern time.
Mr. Glenn Scott: Good morning. My name’s Glenn Scott. I manage the upstream for Imperial Oil, and today
I’d like to share with you some of the highlights from that part of our business.
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I’m going to talk about three of our world-class assets, Cold Lake, Syncrude, and
Kearl. These are each supported by multi-billion barrel fields. They are highly profitable assets. They’re long life producers. And we believe all of these factors give Imperial a distinct competitive advantage.
Let me tell you about some of our upstream strategies. We’re, first and foremost, focused on maximizing the value of our base
business, getting the highest uptime achievable from the assets that we’ve already invested in, and being the lowest cost producer from those assets.
We’re also focused on profitable growth. And we’re taking into the designs of those growth opportunities, Kearl and Nabiye, for example, learnings from previous experiences that we’ve had.
And we’re driving those designs to achieve very high reliability and uptime and very low unit operating costs.
We’re
also very focused on developing high-impact technologies to increase value from existing resources like Cold Lake, and I’ve got a slide to talk about ever-increasing recovery of the resource, and also making future elements more profitable. And
then finally, we’re pursuing the highest quality exploration opportunities.
Upstream business is very, very profitable.
We’ve pulled the graph on the left from a report from Barclays. And it shows that, for every barrel that we produce, we deliver significantly
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more earnings than our competitive peer group. The upstream generated just shy of $1.9 billion in earnings last year.
Our return on capital employed was 13 percent, but this includes several billion dollars of capital that’s under construction and not on production. So, if you strip that element of capital away, the
base business is generating north of 50 percent return on capital employed.
We’re currently producing about 300,000
barrels per day, and we’re set to double that. We are in a very, very high investment period, but we’re not just trying to double production for growth’s sake. We view this as highly profitable growth. I’ve got some slides to
show you that a little bit later. But, we do believe that the growth from Kearl and from Nabiye is going to continue to create this distinct competitive advantage we have on earnings per barrel produced.
Let me start with Syncrude. Syncrude is a strategic asset for us. It’s very, very profitable, but it could deliver more profits. We
have improvement potential, and I’ll tell you what we’re doing to improve uptime, reliability, and operating cost performance from that business.
Imperial owns 25 percent of Syncrude. We signed what we call a master services agreement in 2007 with the other Syncrude owners that allows ExxonMobil and Imperial to bring worldwide
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best practices to bear at Syncrude to raise the profitability of that asset.
And we are making some progress. We’ve got a ways to go. We’re currently producing about 72,000 barrels per day, which was last year’s average. We’ve produced over 600 million
barrels our share. But, as you can see, there’s about 2 billion barrels of resource yet to be recovered.
We are very
focused on improving profitability at Syncrude. And that starts with increasing production, and increasing production starts with improving reliability. We’re very, very focused on increasing uptime from the assets that we’ve already
invested in. And what we’re targeting over the relatively near term is to raise the production levels from historic 70,000-72,000 barrels a day our share up north of 80,000 barrels per day our share.
And we are making some progress. We are applying a systematic approach to improving reliability at Syncrude. Our first priority has been
to focus on the upgrader. The bar chart shows that we are. The upgrader has historically contributed most of the downtime at Syncrude. And so, that’s where we applied most of our focus over the last few years.
And you can see that we are making some progress. The downtime contribution from the upgrader is coming down. And
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I’ll dive a little deeper here and tell you how we’re achieving some of that.
We’ve applied some of the practices that ExxonMobil and Imperial have from around the world in operating very large cokers. We’ve developed more robust operating procedures, more robust
operating envelopes, what’s the right temperature, pressure range, etc., to operate a coker in. And as a result, we’ve extended the average coker run life from two years to three years. And that’s translating into more uptime.
We’ve applied root cause failure analysis to what had been a chronic problem area for us in some very large furnaces, the
vacuum distillation unit and the diluent recovery unit, which were at the front-end of the upgrader. Through detailed analysis, we identified that we had significant solids entrained in the bitumen, and those solids were eroding some of the piping
in these furnaces.
So, what did we do about it? Well, we first dealt with the solids and improved the efficiency and
effectiveness of the centrifuges that are just upstream of these units. We also bolstered up the piping that’s in these furnaces, put more metal in place, and we also reconfigured the piping to reduce some of the erosion that was taking place
due to turbulent flow.
And I’m pleased to say that, as a result of these actions we’ve already taken and put in
place, we’ve gone a year and a
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half now without a single downtime event in either of these two units--the diluent recovery unit and the vacuum distillation unit.
We’re applying the same sort of disciplined approach to another chronic area of concern for us. Hydrogen unit heat exchangers undergo
significant stresses through very, very high temperatures. These heat exchangers are two bundles that are on the backend of the hydrogen unit. Temperatures can exceed 700 degrees Celsius in these units.
And by working with ExxonMobil, we identified a design flaw that predates the master services agreement by many years. This design flaw
relates to how the tubes would connect into a sheet at the end of the tube bundle. By correcting the metallurgy on these connections between the tube and the sheet at the end of the bundle, we can prevent failure.
We’ve already addressed this on a couple of the heat exchangers. We’ve got a couple more to go over during the 2013 and the 2014
turnarounds. So, we’ll see steady improvement in reliability after we get those design flaws corrected.
We’re also
very focused on operating costs at Syncrude and improving our cost structure of that business. We’ve worked very hard over the last two to three years to align Syncrude’s organizational structure to match what you would see in
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virtually any other ExxonMobil or Imperial affiliate or a refinery around the world.
We have completed this realignment of the workforce. We believe that we’re getting much greater line of sight between the business teams and how they affect profitability. We have eliminated numerous
redundant interfaces that used to exist in the organization. Syncrude is now using many, many support services like procurement that are supplied by ExxonMobil and Imperial.
And as a result of all these efficiencies that have occurred, we’ve been able to reduce the workforce by about 600 people over the last couple of years. And that translates into lower costs. Now, we
did that not through any layoffs or big cutback programs. We did that through normal attrition and retirement. So, it was fairly painless on the workforce. And we’re achieving already about $90 million per year in operating cost savings from
these efficiency improvements that we’ve driven.
Also, leveraging in to Imperial and ExxonMobil’s global
procurement, we have some more cost improvements that we’ve driven. Alberta is a very expensive place to do business. And by tying into other suppliers of services and goods from around the world using ExxonMobil’s network, we’re able
to bring in some competition and reduce costs.
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We’ve done things like online auctions, setting up platforms for folks to come in from
abroad and lowering the barriers for entry into the Fort McMurray market. And we’re having great success. We’ve already pocketed about $200 million per year in sustainable savings.
Now let me talk about Cold Lake. Cold Lake is also a very profitable asset. Imperial owns 100 percent of Cold Lake. We started producing
in the mid 1980s. We notionally say it produces about 150,000 barrels per day. It’s a cyclic steam operation, so there are some cycles to the production. We’re in an up cycle right now. In fact, the first quarter we set a record production
at 164,000 barrels per day from Cold Lake.
We have about 4,500 wells. We’ve already produced over a billion barrels. But,
I would say the best is yet to come, with proved reserves on the books of more than a billion barrels and a resource base of nearly three billion barrels that we’re already studying and progressing towards development.
Here’s a chart that we pulled from a study by Peters & Company. Reliability is very, very important to us in all aspects of
our business, and achieving high uptime is the measure. And this chart shows uptime as a percentage of nameplate capacity.
And
you can see that at Cold Lake, we consistently deliver about 100 percent of our nameplate capacity. And that’s where
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we want to be. We want to be at the top of the heap on this graph. And I guess the other takeaway that I’d like you to hear on this page is that, when we say Nabiye is going to have a
nameplate capacity of 40,000 barrels per day, that’s what you should expect from us over the calendar year is an average of 40,000 barrels per day.
We achieve this by rigorous application of equipment maintenance. Our equipment needs to last for many, many, many years, and we take really good care of it. And we’ve got very, very proactive plans
that have been developed using best practices from Imperial and ExxonMobil around the world.
Cold Lake has a very competitive
cost structure. Here’s a graph that comes from FirstEnergy. Here you want to be the low-cost producer with low dollars per every barrel that you produce. And we’re very, very competitively positioned. We achieve this through a rigorous,
disciplined cost focus throughout our organization.
These maintenance procedures that drive high reliability also drive lower
all-in costs for us. And so, for a field that’s arguably 30 years old, we’re right up there with brand new fields in terms of unit operating cost, which is right where we want to be.
We’re also very focused on increasing recovery at Cold Lake, and we’re using technology and innovation to do that. In
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the early days, we thought we might get 15 to 20 percent of the reserves in place from our development. Now, through technology application when we develop a pad, we expect to get about 60
percent of the reserves in place.
Some of the technologies that we’ve applied over time include, limited entry
perforations, which is a technology that we patented to direct steam to exactly where we want it to go and not lose any heat where we don’t want it to go.
We’ve applied liquid addition to steam for enhanced recovery, or LASER, to increase recovery from pads that have undergone several steam cycles. Steam flooding sweeps up the last bit of oil between
wells using four dimensional seismic to identify areas in the reservoir that have not received heat so we can direct heat and steam into those areas of the reservoir. And you can see we’re getting great results.
So, when you add all this up, high reliability, low unit operating costs, ever-increasing recovery from existing investments, existing
assets, all of that creates a great foundation for growth. And that’s exactly what we’re doing with Nabiye.
Nabiye
comes on-stream in 2014. The graph here shows our first full year of production in 2015, and shows you that Cold Lake volumes are going to continue to grow.
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Nabiye was sanctioned in 2012 for $2 billion. It’ll have a nameplate capacity of 40,000
barrels per day, will generate about 140,000 barrels per day of steam, will generate all of the electricity required for Nabiye with cogeneration--generating electricity and steam at the same time--and will have surplus electricity to sell to the
grid.
Nabiye is more than 40 percent complete. I’m pleased to say that we’re on schedule and on budget for a 2014
startup. I’m also very pleased to say that we’re rigorously using our design one, build many philosophy. Nabiye is a carbon copy of Mahkeses.
And Mahkeses has performed really, really well for us in the past. It’s contributed very strongly to the uptime chart I showed, the cost chart, and the increased recovery chart that I showed. And so,
we fully expect to get the same results from Nabiye that we’ve gotten from Mahkeses because they’re identical.
Now
let me switch to Kearl. We call Kearl the next generation in oil sands development. Why do we call it that? Well, we have spent a lot of time trying to learn from all the mines in the oil sands that have gone before us. We’ve tried to take
every bit of good performance that we see in existing mines, and we’ve also tried to learn from opportunity areas that
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we’ve seen to drive improvements in reliability and improvements in operating cost structure.
Imperial owns 71 percent of Kearl together with our partner, ExxonMobil. We have started up production this year in 2013. We’ll ramp up from the Kearl Initial Development to 110,000 barrels per day.
And ultimately, once all the construction is done, we’ll ramp up to 345,000 barrels per day, which is our regulatory capacity.
We’ll develop 4.6 billion barrels of resource at $6.80 per barrel. And this is consistent with the previous guidance that we’ve given.
This is a fairly busy chart. I’m not going to go through every detail, but I’m really pleased to say that Kearl is the first oil
sands mine without an upgrader. We are today producing pipeline-quality diluted bitumen. Kearl initial development has three paraffinic froth treatment trains. One of those three trains has been commissioned and is up and running.
We’ve achieved rates of up to 40,000 barrels per day. We’re well within pipeline specifications for diluted bitumen without the
upgrader. So, we’re the first to achieve that success.
We started up in late April. We spent the month of May tuning the
process, lining out various equipment, optimizing the solvent to bitumen froth ratio, and we’re getting to a point
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where we’re feeling pretty stable with the operation from that first froth treatment train. And we’re in the process now of commissioning the second and the third train.
The second train should be ready for operation in the next couple of weeks or so. We want to make sure that the first train is running
very, very stably and we’ve optimized all of that, taken all of the learnings so we can apply them to the start-up of the second and the third train. So, you’ll see us ramp up from 40,000 barrels a day to 110,000 barrels per day over the
summer.
Let me quickly walk you through the process on the diagram. I’ll go clockwise from the top left. Kearl is a truck
and shovel operation. We crush the ore. We then mix the ore with hot water and pump that slurry mixture down a pipeline that’s about three kilometres long.
As we wrap around, we come into the plant into this conical shaped vessel, which is called our primary separation cell. Out the bottom of that vessel comes sand and water that goes to the tailings pond.
Out the top of that vessel comes bitumen froth, which is basically heavy oil, air, a little bit of water, and some clay particles.
Now, up to this point, the process is relatively similar to all the other mines in the industry. As we move to the left, that’s where we differ. Inside of this red box represents the
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kit that is associated with our proprietary paraffinic froth treatment process.
We take that bitumen froth and we run into these two froth settling units, FSUs, on the diagram, where we mix in a hydrocarbon-based solvent, which is a proprietary solvent that we’ve developed.
That, being a hydrocarbon, dissolves most of the components in the heavy oil, but it doesn’t dissolve the asphaltene chains.
Those precipitate out in solid form. They’re long. They’re sticky. They’re dense. And so, they settle in these froth settlers. And as they’re settling, they grab hold of the clay
particles and water droplets to clean up the bitumen.
That mixture of solvent and now clean bitumen goes into the solvent
recovery unit, SRU on the diagram, where we lower the pressure, raise the heat a little bit so we can recover the solvent for reuse in the process. Then we blend in the diluent, and it’s ready to go into the pipeline.
I’m going to have a seat for a moment. We’ve got a video to share with you with real employees and contractors at Kearl
describing the process a little bit more.
Mr. Rich Kruger: I’m Rich Kruger, Chairman, President, and Chief
Executive Officer of Imperial Oil.
It’s a pleasure for me to introduce this video on our Kearl oil sands operation. Kearl
is the result of years of oil sands
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experience and a relentless pursuit to deliver cutting edge research and innovation to create an operation with superior environmental and operating performance.
I hope that through this video you get a better understanding for how Imperial has raised the oil sands bar in environmental and
operational excellence. Welcome to the next generation of oil sands development. Welcome to Kearl.
Unidentified Woman:
By 2030, oil sands production is expected to increase to more than four million barrels per day. Kearl will play a major role in Canada’s energy future, providing a reliable and secure energy supply for North America and the world.
Kearl will play an integral role in setting a new standard for environmental performance in the oil sands. The Kearl operation will use
next generation technologies that raise the bar for environmental performance in oil sands development. That means a barrel of oil produced at Kearl will have about the same greenhouse gas emissions as an average barrel of crude refined in North
America.
Mr. Glenn Scott: From the beginning, we wanted Kearl to be different. We wanted to build off of our
decades of oil sands mining and in-situ experience and our decades of research. We wanted to reduce the environmental footprint of Kearl. And so,
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what you’ll see is Kearl represents the next generation of oil sands development technology.
Unidentified Woman: Responsible oil sands development is part of the Kearl DNA, as is its safety culture.
Unidentified Man: When workers come to our sites, I know nobody wants to get hurt. Our goal, nobody gets hurt, is more than a slogan. It reflects our value and our approach to safety.
Unidentified Woman: The presence of oil sands in northern Alberta was documented over a century ago. Oil sands are a naturally
occurring mix of bitumen, sand, and clay, and mining oil sands is a big job.
After topsoil is carefully removed and stored,
shovels load the oil sands onto trucks, where it is moved to the crusher and the oil sand material is pulverized to break it into smaller chunks. After being crushed, the ore moves up a conveyor to the surge bin.
From there, a second conveyor takes the oil sand to the slurry prep plant. Here hot water is added to begin the process of separating the
oil from the other naturally occurring materials like clay and sand. This mix is then moved using Kearl’s hydrotransport pipeline. The slurry mix continues to separate along the pipeline route to the main plant.
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In the primary separation cell, bitumen floats to the top where it is removed for further
processing, while sand and clay settle to the bottom. The bitumen is then processed through one of three froth treatment trains.
Unidentified Man: Kearl will be the first oil sands mining operation that will not require an upgrader to make a salable crude oil,
meaning a significant reduction in energy use and greenhouse gas reductions per barrel.
Unidentified Woman: With an
upgrader, crude has to be heated to 350 degrees Celsius to separate crude molecules. Kearl does not do this, and there is a significant energy and greenhouse gas savings as a result.
Kearl is the first oil sands mining operation to use paraffinic froth treatment instead of an energy intensive upgrader. This process
produces a diluted bitumen that is ready for pipeline transport.
Increased environmental performance is driven by innovation.
Kearl is proving this. Kearl will also use cogeneration technology. Cogeneration reduces energy requirements by producing electricity and steam at the same time. This also reduces greenhouse gas emissions.
Unidentified Man: Kearl is different. The technology we will be using will make our environmental footprint substantially smaller
than our competitors. Cogeneration will
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help us reduce our greenhouse gas emissions so that we will be in line with many crude oils refined in the United States.
Unidentified Woman: Responsible water use was planned from the very beginning. Kearl will use an on-site water storage system. Built to protect the aquatic ecosystem during winter low flow periods,
Kearl will be the first mine that can completely stop water withdrawals from the Athabasca River while maintaining production.
Unidentified Man: We’ll use a single tailings pond until in-pit space is available. After that, using proven and new
technology, we’ll separate the fine tailings from the water before it reaches the tailings pond. As a result, we’ll have a smaller footprint for a tailings area than most existing operations.
Unidentified Woman: The mine plan at Kearl was designed to return tailings to mined out areas as soon as possible. This further
reduces the amount and size of tailing ponds.
Like mining, reclaiming land is a big job. Original topsoil provides the
foundation for careful, authentic replanting and reclamation.
Unidentified Man: We’re taking a progressive
approach to mining operations. Rather than waiting for the end of mine operations, Kearl will reclaim land as it goes.
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The mining direction at Kearl is circular, not radial. This will allow us for earlier
placement of reclamation material in pit. Reclamation work includes native plants selected with input from local First Nations.
Unidentified Woman: Oil sands investments will result in 33,000 new jobs every year in Canada for the next 25 years.
Businesses and individuals here have the opportunity to participate and share in the benefits of development.
Unidentified
Man: What I experienced working with Kearl is we’ve got a big opportunity here to building out a road maintenance contract. And we have 200 employees onsite here.
Unidentified Woman: And it allows us to create a good base of a business and be able to sustain our business over the long haul.
And also, it allows us to give back to the community.
Unidentified Woman: Kearl will employ nearly 5,000
full-time workers. And Canada’s petroleum industry will grow to more than one million people in the next 25 years. One million people, one million jobs.
From the beginning, the vision for Kearl was long term. More than 30 years of research and development informed every decision and has resulted is significant innovation, innovation that will redefine
sustainable oil sands development, innovation that will grow healthy communities, innovation that will provide
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employment and benefits for generations, innovation that will fuel a nation. Kearl, the next generation oil sands project.
Mr. Glenn Scott: Well, I hope you enjoyed that video. I’ll get back to a few more slides on Kearl.
We believe Kearl has a real value advantage that’s going to lead to near-term and long-term profitability. Kearl is blessed with high resource quality, and that is going to translate into lower unit
operating costs long term.
We’re applying the proprietary paraffinic froth treatment process. We’ve avoided a
multi-billion dollar investment in an upgrader. We’ve avoided the complexity that comes with an upgrader, the cost and some of the downtime that comes with an upgrader. So, we’ll have high reliability from Kearl.
We’ve also built in other reliability improvements that I’ll speak to in a couple of slides. You heard many of the environmental
benefits at Kearl. And I have a slide to share with you that Kearl is going to have a very competitive operating cost structure that will lead to high profitability.
Kearl’s going to be a long-life asset, 40 years of production at a plateau of 345,000 barrels per day. We start with Kearl Initial Development, which is 110,000 barrels per day. We’re currently
constructing the Kearl Expansion Project that will bring on another 110,000 barrels per day by 2015.
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Then, we’ll do what we call our mine de-bottlenecking project, adding another 80,000
barrels. And ultimately, we’ll de-bottleneck the plant to reach our full 345,000 barrels. We’re currently doing the design work around this third ore processing plant to de-bottleneck the mine, and we’re working our way towards
sanction of that project.
Kearl is blessed with high resource quality. This graph depicts that. On the Y-axis, you’ve got
ore grade, which is percent of bitumen in the ore. On the X-axis is the ratio of total volume that you have to move to bitumen in place.
And where you want to be on this chart is up in the far right corner. That translates into the amount of volume of material that you have to move. And that translates directly into cost.
So, at Kearl, we’ll get about 300 barrels of bitumen for every truckload of ore that we move. If you look at the left side of this
graph, other mines will get about 265 barrels of bitumen for every truckload of ore. At 345,000 barrels per day, that difference means 55,000 fewer truckloads per year. And that translates directly to lower unit operating costs for Kearl and higher
profitability.
Kearl is producing pipeline-quality, refinery-ready crude. It’s been designed to have high reliability.
We’ve avoided the complexity and cost of an upgrader. You see the picture on the
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top. Folks estimate that an upgrader for 350,000 barrels per day in today’s market could cost $20 to $25 billion. We’ve avoided that investment.
We’ve avoided the operating costs associated with an upgrader, and the significant complexity that comes from having a big refiner
unit on the backend of a froth treatment train. And so, Kearl, by kicking out the asphaltenes and the solids that go with that, we can meet pipeline specifications and go straight to virtually any refinery in North America or abroad.
We’ve also built in several other reliability enhancements into Kearl. This is a picture of our ore processing plant to show you some
of the enhancements that we’ve built in to increase runtime and uptime from Kearl.
Starting up in the top right of the
picture is the crusher. We’ve oversized the crusher to have more capacity than we need to meet the 110,000 barrels per day. This is a high, rare, highly erosive environment, so building in some spare capacity, we believe, will pay off in terms
of long-term reliability and value.
Moving downstream of that, we’ve got dual conveyors, each oversized relative to its
needs, again for reliability. We’ve created an oversized surge bin to hold and store crushed ore to help us deal with any scheduled or unscheduled maintenance upstream of that point, either in the mine or in the crusher.
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We then go into dual conveyors that go into a dual slurry prep tower that feed dual
hydrotransport lines into the plant. And all of that equipment has been oversized relative to its needs so that when one side is down for scheduled or unscheduled maintenance, the other side can pick up some of the slack. And we believe that this is
going to help Kearl achieve higher reliability than some of the existing mines.
By avoiding an upgrader, meeting pipeline
spec, having cogeneration, which is currently being constructed, and generating electricity and steam at the same time, Kearl is going to have lifecycle greenhouse gas emissions that are about the same as the average barrel of crude refined in the
United States, as shown on this graph.
And if you look below Kearl on the graph, the crudes that Kearl would displace that are
currently being imported into US Gulf Coast refineries have a higher greenhouse gas intensity than Kearl. And so, we view Kearl moving into the US market as a net positive.
We believe Kearl has a very competitive cost structure. This graph comes from a report by FirstEnergy. It shows unit cost in dollars per barrel. The blue components of the bars are ongoing operating costs
and fuel and energy related costs. The red sections of the bar basically reflect depreciation of capital.
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And you can see that Kearl’s total all-in cost structure is pretty darn competitive
with even the best of SAGD operations. And what this means to me is opportunity with more than half the costs at Kearl being ongoing operations costs, ongoing maintenance costs, ongoing fuel costs. This is where we really excel, lowering ongoing
operating costs. You’ve seen it at Cold Lake. You’ve seen it elsewhere. This is a real opportunity for us to reduce those costs and increase profitability.
The other takeaway from this chart is that Kearl will be profitable across a broad range of prices. You pick your price and there appears to be quite a room for margin and earnings per barrel. And so, I
do believe that Kearl is going to generate similarly competitive earnings per barrel as the rest of our base portfolio, if you think back on that first chart that I showed you.
I’m going to give you an update on Kearl Expansion Project. We sanctioned the project in 2011 for $8.9 billion. It will bring on another 110,000 barrels per day. We’re about one third complete
with the project. The project is tracking on schedule and on budget, and we expect startup in 2015.
The picture in the
background shows the Kearl Initial Development. In the foreground of the picture are the pipe racks for the Kearl Expansion Project. The pipe racks are
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essentially done. We’re starting to install the process vessels.
It’s hard to see, but on the very far left of this picture is the solvent recovery unit standing up. It’s been installed. We are
also starting to install the froth settling units. Two out of the six have already been fabricated, hydro tested, and are on their way into place.
All the full-size modules are being constructed in Edmonton, where we have significant experience and learnings out of the Kearl Initial Development. The yards there basically reconstructed the modules
for Kearl Initial Development. We believe they’re now qualified and capable to build all the Kearl large size modules. And that helps us avoid any threat of transportation related delays or costs with the Kearl Expansion Project.
I’m also pleased to say here we’re rigorously using the design one, build many philosophy. Kearl Expansion Project is an exact
replica of Kearl Initial Development. Rich and I have met with some of the contractors. They’re already speaking highly of this approach, and they are claiming they’re seeing improvements in their productivity already by building the same
thing twice.
So, I’ll wrap up and then turn it back over to Rich. I believe our upstream business is highly profitable in
an
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absolute and a competitive sense. That’s based on the highly competitive operating cost structure we’ve designed in to Kearl and Nabiye. And our goal is to have best-in-class
reliability and best-in-class unit operating costs.
We’re driving systematic improvements into Syncrude’s operation.
We’re growing our production, and that production is going to be very profitable. Two hundred thousand barrels a day of the 300,000 growth that we’re projecting is already in start-up mode or under construction. So, I’m really, really
excited about our future.
Back to Rich.
Mr. Rich Kruger: Thanks, Glenn.
What I hope you have heard both
through Glenn’s talk and Paul’s is the strong focus on the fundamentals within the organization. And that certainly will be my priority as we go forward, in fundamentals that add value.
And when I reflect on the fundamentals, it starts with safety. It continues with operational integrity, reliability, and profitability.
Our business is complex in the base case, but what’s critically important is that our organizations have a clarity about what’s expected, what our priorities are, and that all our efforts are directed in that way.
As I’ve went to the locations, talked to the workforce, talked to our leadership teams, that clarity and that focus is
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there. And we believe that is the key to continuing to deliver long-term value.
Now what I wanted to do is talk about a topic that I think is on everybody’s mind, and it’s market access. As we develop this incremental capacity, how are we going to ensure that it gets to
market? And summarized here is--in a distilled manner--our strategy on ensuring market access.
And first and foremost, the
objective is to ensure the full takeaway capacity for each and every barrel of equity crude. What it starts with is optimizing the use of the existing systems. And I’ll come back and describe the strategy briefly, but then I’ll quantify
some things here in a moment.
We shouldn’t think of the existing systems right now as fixed. For example, I’ve spent
time with Enbridge recently looking at what efforts they’re taking to re-rate some of the pipe that they’ve de-rated.
Our technical practitioners are talking to theirs about ways where they can operate their pipelines in a more efficient manner with the
batches and the scheduling to increase the capacity and be less vulnerable to, when someone says they’re going to deliver crude and they can’t deliver crude, what that means on the system. So, the existing system and its ability to
optimize, we see growth capacity in the existing systems.
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Our strategy continues on with new pipeline opportunities. It’s hard to pick a winner
today, debates, schedules. So, what our strategy is participating in multiple new opportunities, be they south, east, or west, so that our plans don’t hinge on any one pipeline, and it’s difficult to say which one and when they come
approved. But, we’re going to look to participate in multiple options to give us that flexibility.
We’re looking at
rail as a bridging strategy and an insurance policy. And the nice thing about rail is the line capacity is there, so it’s about cars. It’s about cars in terms of you have purchase/lease options. You can phase or ladder or stagger your
commitments. So it’s, in a sense, a bit of a dial-up, dial-down strategy.
Clearly, pipelines are preferred as the safest,
most reliable, most cost effective means to transport crude and products. But, recognizing the uncertainties, rail is a key part of that strategy to bridge and/or provide any insurance if and when rail capacity is not there and we need it.
And last but not least, if we find ourselves in the future where we have a surplus of capacity, commitments on rail,
commitments on pipelines, we have the ability to portfolio optimizations, running crude in our network, running crude in ExxonMobil’s network, the commitments we make and the duration
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of those, be they rail or pipeline, to optimize if we would find ourselves in that situation.
A few statistics for you, or some specifics. This chart shows our commitment to new pipeline capacity. But, I think it’s important. We’ve talked about how our equity crude is on the order of
250,000 barrels a day or so of equity crude today. Well, we’re moving from Alberta via pipeline today about 400,000 barrels a day to feed our refineries and to support our equity crude.
We have flexibility there, if we were to need more space for equity crude, to pull back on our third party purchases and ensure our equity
crude moves. So, we have some flexibility right there with what we’re moving.
The 290,000 barrels a day capacity
that’s shown feathering up here is additional pipeline capacity for Kearl Expansion and Nabiye. It includes Keystone, Base Keystone, Gulf Coast Access, Keystone XL, and Trans Mountain. We’re also looking long and hard right now at
TransCanada’s proposal on Energy East. So, this is that kind of portfolio of participating in multiple pipeline options, because at any point in time it’s hard to pick the winner and any particular timeframe on it.
And last but not least, rail options. We are advancing rail options. I’ve read some of the things folks have said or written there.
We’re advancing rail options to mitigate any of
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the uncertainties I talked about, again, as a bridging agent and an overall insurance policy.
It goes back to the objective to ensure we have takeaway capacity for each and every barrel of equity crude. I thought you would be interested in that.
Now, let me shift. We’ve talked a lot throughout the review to this point about technology and innovation and its importance across
all business lines. And it’s really fundamental to the results and the profitability that we generate. And we believe it is a distinct source of competitive advantage to us.
If you look at how we approach it, we’re very selective and value driven, targeted in our efforts. And our capabilities, we believe,
are industry leading. Technology and research is not something you flip on and off. Year to year, if you dial it up and dial it down, you lose the capability, the momentum, the intellectual expertise it takes to generate and advance ideas.
We have a long-term commitment, an unmatched commitment, a very systematic research process. We put our money where our mouth
is in investment. And we have that leverage, that benefit of essentially a billion dollars a year that ExxonMobil commits to research and development. That allows us at Imperial to focus our couple hundred million dollars a year on those areas
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that are most explicitly beneficial to our business, both today and in the future.
And I wanted to flag our status as a founding member of Canada’s Oil Sands Innovation Alliance with 13 other companies, a commitment to collaborate and to share practices and technologies that can
improve the overall environmental performance of the oil sands business.
I want to show you in a moment a video. The video
will be aimed at showing you how do we do this? What makes us different and how do we go about and add value through research and development?
This slide is really geared to reinforce that all of our efforts, high-impact technologies, are truly aimed at improving the business. It’s not research and technology for research’s sake.
It’s for improving reliability and recovery and cost, margins, adding value.
So, with that, I’d like to show you a
short video that will describe how we go about this and what truly makes us different. Thank you.
Unidentified Woman:
Research has been an integrated part of Imperial Oil’s business since 1884, when the company hired a German chemist named Herman Frasch to rid its best selling product, kerosene, of its unpleasant odor. Many groundbreaking
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oil and gas products and technologies were developed in Imperial Oil labs over the years, and we’re not slowing down now.
Canada’s oil sands are a key global resource, and critical to North America’s energy security. At Imperial Oil, we believe that
technology and innovation are the solutions to environmental impacts associated with oil sands development. We are one of the few oil and gas companies in Canada with dedicated research facilities. Approximately 150 scientists, engineers, and
technologists work at our research laboratories in Calgary and Sarnia.
Imperial Oil’s upstream research team in Calgary
is focused on game changing oil sands technology to significantly improve environmental performance such as GHG emissions, water use, footprint, tailings, and the economics of getting oil out of the ground, processed, and to market.
Unidentified Man: Innovation and continuous investment in oil sands technology is the key to long-term sustainable development of
the oil sands.
At this research center, our research is focused in three main areas, in-situ or in place research, oil sands
mining and tailings research, as well as environmental research.
Unidentified Man: It takes many years to progress an
idea to commercial application. We have a systematic process to move a concept from ideas in the lab to experiments, field pilots,
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and ultimately to commercial implementation. We make sure to apply learnings from each step along the way to strengthen the concept as it progresses and increase its chances of being applied
commercially.
Unidentified Man: What we do in this lab is developing new processes for recovery of heavy oil from
underground reservoirs.
Unidentified Man: A key technical objective is to make this bitumen flow a lot easier that it
does. Two ways you can do that is by adding heat to reduce viscosity, or you can add a solvent to make it flow easier.
Unidentified Man: In this research lab, we evaluate the performance of a new process at high pressures and temperatures comparable
to actual reservoir operating conditions.
Unidentified Man: The physical model you see here is state of the art
equipment, the likes of which are found nowhere else. It’s a product of over 40 years of testing and development.
First
I’ll take this model and I’ll fill it with glass beads. I’ll put the lid on and put it inside the confining vessel, at which time I’ll hook up all the instrumentation. The door will be shut, it’ll be filled with bitumen, and
then I’ll run the test. The test will take one day, which is the same as 10 years in the field.
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Unidentified Man: The advantage of these processes is that they can allow us to
produce the oil faster, easier, with lower energy consumption, and lower greenhouse gas emission.
Unidentified Man: CSP
stands for our cyclic solvent process. One of the key advantage of CSP process is the significant reduction in greenhouse gas emission. Burning natural gas accounts for 98 percent of the direct greenhouse gas emission for several base recovery
processes.
In CSP, instead of steam injection into the bitumen reservoir to recover bitumen, propane, which is the same
propane used in your barbeque, is injected into the bitumen reservoir. It mixes with the bitumen, reduces viscosity, and allows it to flow, achieving the same effect as steam but without heat or water addition.
Unidentified Man: In this lab, we have experimental programs that are designed to study the fundamentals of cyclic solvent process,
address the technical challenges, and gain the necessary knowledge and experience before we implement this new technology in the field.
Unidentified Man: In the Athabasca oil sands region, tailings ponds are a growing concern because of its quantity and its associated environmental footprint. Our research in tailings management is
focused on how to deliver a solution faster but also more effectively.
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At Imperial Oil, we’re developing a technology called CIMA, which stands for chemically
induced micro agglomeration. Now, I know that’s a mouthful, but conceptually it’s as simple as making rocks from clays. Whereas nature has had millions of years to make rocks from clay particles, we’re simply speeding up the process
by adding chemicals directly to tailings, forcing the clays to interact with each other, and finally making rocks instantaneously.
Now, these rocks are much denser than water. And, as a result, they phase separate so you can recover much of that water for reuse. And as for the rocks, well, they eventually dry up and help with our
reclamation efforts.
Unidentified Man: We’ve been working on an exciting new technology called non-aqueous
extraction, or NAE, process. The science of the process is quite simple but elegant.
We basically tap into the properties of
two liquids that don’t like to mix. We use the first liquid to dissolve the oil from the sand, and then we add a very small amount of the second liquid, which in this case is water, to bind the fine particles together. Within a few seconds, the
solids form mini balls that can be filtered and dried easily.
Unidentified Woman: Key benefits of NAE are a reduction
in water usage and surface footprint. The NAE process uses a very small amount of water and may eliminate the need to use river
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water entirely. All of the water needed for mining and extraction will come from natural inflows such as groundwater or runoff.
The NAE process also generates dry tailings, eliminating the need to store the wet tailings. So, at any given time, the footprint on the
land is substantially reduced from what we would see with a process that produces wet tailings.
Unidentified Woman:
What you have seen are just a few of the technologies Imperial Oil is working on in our Calgary research lab.
We’ve been
committed to research for over 125 years, and our passion is not slowing down now. We are investing annually and have access to over $1 billion of research through our majority shareholder, ExxonMobil.
In addition to our own research, we participate in industry collaborations to help accelerate improvement in environmental performance in
Canada’s oil sands. Technology will be essential as our company continues to advance our Kearl oil sands, Cold Lake operation, and other exciting initiatives.
Continued investment in research and technology is critical to achieving sustainable development for industry and leaving the world a better place for generations to come.
Mr. Rich Kruger: [Inaudible] glean from that is one our commitment. But, we also have a long history of success. I
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think you can see that in Cold Lake’s performance. And I think you can see that in the uniqueness of Kearl.
The technologies highlighted in the video are just summarized here. I won’t go through them. We see each of them as potential game changing or breakthroughs. What I would add is, as you reflect on
these technologies, we’re not done at Cold Lake and we’re not done at Kearl in terms of the opportunities.
Also,
they can apply to a suite of other opportunities. And as we begin to wrap up, I would like to share with you some of those opportunities that we anticipate maturing throughout the rest of the decade, but will really position us for growth late in
the decade and beyond.
What we’ve shown here is the bars from an earlier chart on our non-proved resource base. And shown
on the map are some of the areas and the types of opportunities they represent. So, I wanted to use that as kind of a launching pad.
What I’d like to do is highlight some of the opportunities that are in that category we referred to as progressing. And you’ll recall my earlier comments. That bar is in excess of three billion
oil equivalent barrels of a comparable size to our proved reserve base today.
So, let me start with new in-situ opportunities.
We see, with the areas highlighted here, Aspen, Corner, Grand Rapids--and Grand Rapids is a formation right above the producing
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formation at Cold Lake--on the order of three billion barrels of commercial opportunity for us through SAGD and SA-SAGD technologies.
Our thought process is that we would advance these in phases, benefitting from the design one, build multiple cost efficiency operability.
And notionally, we’re looking at them in the plus or minus 40,000 barrels per phase, round numbers, capacity.
Aspen in
particular, I’m excited about Aspen. We have a thick, high-quality deposit. It’s about 35 kilometres south of Kearl. It’s 52 sections of land, 100 percent IOL. Right now we’re looking at initially, in the early stages, of two
45,000 barrel a day phases there. We have some consultation going on. We’re looking at when we make some regulatory applications, perhaps in ‘14 on that. Technical and regulatory work permitting, by the end of the decade we see the first
phases here at Aspen as a high possibility/probability.
Going down to Grand Rapids, I mentioned this is a formation above Cold
Lake, also a SAGD, SA-SAGD candidate, similar concept of phases. We have some initial fieldwork here. And what I like about this is we have the opportunity to benefit from the extensive infrastructure at Cold Lake. So, there would be a cost
advantage to any further development in the area.
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This is a little less mature right now than Aspen. But, I think it’s something I would
just ask you to keep your eyes on as you continue to communicate with us.
So, multiple quality opportunities above and beyond
those plans that we’ve shared with you that are all under construction or beyond the drawing board. These are earlier, but there’s a combination of fieldwork and technical work ongoing.
Let me comment a bit on unconventional gas. We have a very large acreage position, and we have some uniqueness here in our gas
opportunities. We of course have Horn River. We have a pilot at Horn River producing about 30 million cubic feet a day. We’re looking at and assessing the reservoir connectivity, the productivity, looking at recovery per well, further work
on cost and how we might develop this resource. Horn River is a bit on the high side for a supply cost, but we’re looking at what we can do to lower that cost.
Now, in addition, with our Celtic acquisition earlier this year, we have with ExxonMobil a very strong, large acreage position particularly in the Montney. And what I like about the Montney is it gives us
optionality. And I’ll comment more on that in a second.
But, the technologies behind our gas position are really
integration of technologies that were developed over many decades and continue to enhance: horizontal drilling, hydraulic
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fracturing, and potentially LNG. I’ll talk more on LNG in a moment.
But, the comment on the Montney, large acreage position, large gas resource, it gives us the optionality to be perhaps part of an LNG
solution. But, its liquids rich nature also gives us the opportunity to progress and advance development on the economics without LNG.
So, let me comment a bit more on LNG for a moment. LNG projects are, by their nature, very involved, very complex. I liken it to a puzzle. There are a lot of pieces that have to fit together. There is the
resource size and quality. There is the plant size and location, size efficiency. There’s economies of scale that come with LNG plants and ships that make a big difference on your relative competitiveness.
There is certainly the market dimension. You have a customer, a reliable customer. There is the project planning and execution, high cost.
You need to execute them well. And then, of course the financing phase. So, many, many pieces to an LNG puzzle.
Imperial
doesn’t have a history in LNG. In fact, most of the folks that you’re reading about in the paper that are talking about LNG in Canada don’t have histories in LNG. LNG experience, knowhow, expertise is critical. Well, who does?
ExxonMobil, extensive experience, history.
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I’ve worked personally on LNG in Indonesia, in Qatar, in Papua New Guinea projects. And
we have, because of our relationship, the unique advantage to benefit from that complete wealth and history of LNG experience.
LNG projects don’t happen overnight. They have to be progressed technically, commercially. They certainly require the appropriate
fiscal and regulatory regimes to enable them. LNG projects are a bit of a coalition of the willing: on the market, the upstream side, the manufacturing side, and then the political and regulatory. So, we will be looking, working with ExxonMobil on
possibilities on LNG.
We’ll be looking at and further enhancing our resource base to support a possible project. But, in
the meantime, with our gas portfolio particularly the Montney, I like the optionality we have to add value while we determine if LNG is a part of our future.
Let me start to wrap it up here. In the earlier slides, we talked about and we emphasized the doubling of our upstream business by 2020. The second bar on this chart shows that, consistent with everything
that we have described. The last bar, 2030, shows you notionally, with the opportunities that are in our non-proved resource base, the in-situ, other opportunities, that we see the potential to continue to grow our business post-2020 to on the order
of a million barrels a day.
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Now, that is a lot of work that will go into that, technical, financial, and everything.
But, we have the quality and size of a resource base for continued growth. And I will tell you again, personally I find it very exciting. I’m very pleased to be here. I think it is a transitionary time for this company.
And the value that we will create in the near term and the potential value we can continue to create longer term is--as I said--it’s
just a fascinating, exciting time to be a part of Imperial Oil.
So, let me wrap up with the final comments, then we’ll
open it up to your questions. I’ll wrap up with where we started, our business model. It’s about delivering value, long-term value. We’ve talked about our assets, the uniqueness, the long-life nature, their relative competitive
advantages, be that downstream, chemicals, or upstream.
We’ve talked about the discipline and how we go about making our
investment decisions and managing our operations, cost over time, the significant benefits and advantages we have through integration and synergies across all of our business lines, technology and innovation, how it underpins everything we do today
and into the future, and last but not least our unwavering commitment to operational excellence and responsible growth.
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The model hasn’t changed. We are in a period now of substantial growth and building off
of the same principles and values you’ve found with Imperial, creating a significant new tranche of value for this company.
So, with that, I want to thank those of you here today, those of you on the webcast. And we really want to open it up to any questions you
may have.
If you have a question, please raise your hand. We’ll get the microphone to you so everybody can hear it.
We’ll start over here on the left. If you would, please indentify yourself so everybody in the room could know who’s speaking.
Mr. Arjun Murti: Thank you. It’s Arjun Murti with Goldman Sachs. I had two questions, one on market access, the other on capex.
On the market access, you mentioned the rail as an option to bridge to pipelines. Can you provide any color in terms of specific volumes
you’ll be prepared to ship, let’s just say within one year and two years? I think primarily heavy oil and bitumen we’re interested in, and then, at least in round numbers, how those tariff costs might compare to pipeline shipping
costs, be it to the Gulf Coast.
Mr. Rich Kruger: I think Paul mentioned that we were talking about Nanticoke. And
we’re looking at expanding rail capacity there so we can fill the rest of that refinery up. I
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think he mentioned about 40,000 barrels a day or so, so we can ensure we have access to advantaged crude there. Rail is a significant part of that, as well as some of the pipeline capacity.
The way to look at rail for us is that bridge and that insurance policy. We’re working the existing pipeline system hard.
In the worst case, if there were no incremental pipelines, for example, we’re looking at plans where we could handle the growth you saw through the end of the decade.
Now, don’t think of that as absolute commitments. I’ll go back to what I said earlier. Rail has the benefit that you can commit, in a sense, car by car. That can be purchased. That can be
leased. You can feather in or ladder in your commitments and your expiries. And as you get new information in the marketplace, whether a pipeline is approved and advancing, whether it’s been delayed, you can adjust accordingly.
So, our rail plans will adjust accordingly. So, I’m not giving you tangible numbers on it. It’s not because I don’t have
them, because it’s a work in progress to bridge the gaps and to provide us the insurance. So, you can really think of it in terms of feathering up with our equity crude growth if pipelines don’t mature.
Your second question?
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Mr. Arjun Murti: That’s great. Thank you so much for that color.
Just on Kearl, the phase one had some cost overruns. Just curious if you could walk through some of the learnings to give
investors confidence in the next 110 it’ll be more on track.
Mr. Rich Kruger: I’m glad--Kearl, initial
development funded in 2009, round numbers, $8 billion. It was based at that point in time on three lookalike phases.
A year
and a half later, after continued work, confidence in the resource, we reconfigured Kearl to two lookalike phases and the de-bottlenecks that Glenn described, mine and plant.
The $8 billion went to $10.9 at that point in time. The majority of that dealt with this reconfiguration, additional capacity, and a level of pre-investment that wouldn’t be needed for the second
phase of expansion. Pre-investment in common utilities, for example, some of the redundancies or the incremental capacities that Glenn described, so $10.9.
Well, it ended up $12.9. That additional two billion we obviously are disappointed in, wish it wouldn’t have occurred. You can connect that to the significant issues with the modules. You’ve
heard the story, the transportation issues, in essence having to cut these large, complex production facilities’ modules in half, then bring them back and reassemble them.
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And it was not as simple as welding the parts of a frame to the steel. It was all the guts
and feathers inside of those modules. A lot of work, a lot of time, a lot of cost, and then the added impact of that timing delay put us in a less advantageous weather window to start up the mining operation. You don’t want to start it up in
the dead of winter.
So, that last two billion clearly is the cost we wouldn’t have wanted to have incurred. So, what have
we learned from it? Glenn described the expansion project. Well, the modules, we don’t have that same exposure. That’s been factored into the expansion project.
Those modules are being assembled in Edmonton. We don’t have that risk. Many of the common utilities and the shared infrastructure is already in place with KID, so you don’t have to do that
again on KEP.
The third piece that--I can assure you, my own experience around the world, and Glenn commented how we’ve
been meeting with contractors--the efficiency and productivity that goes with the designing one and building it twice, don’t underestimate that. That is huge for contractors. They’ve done it before. They knew what problems or challenges
they had the first time and they can correct it.
We’re seeing those efficiencies in schedule and dollars. So, our
expansion project, $8.9 billion, we’ve got a lot of
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confidence. We’re 35, 40 percent of the way there. We will be all over this. Our eyes will be on it at each point in the way. But, I think with the learnings we’ve had from KID are
fully reflected in KEP, and we’re going to get a different outcome there.
The last point I’d make on that--and Glenn
I thought described this really well--this is on the operational and the startup aspects of it. With three trains for the first phase we have the ability for each increment to learn on how to start this up more and more efficiently and effectively
so that, as the ramp up occurs, we’re not going through the same growing pains and lessons learned, the synchronization, the interconnection of the whole operation.
We’re learning significantly on the first phase. We’re about to wrap up the commissioning and startup on the second and the third. And that’ll carry on to the expansion project too.
So, I think this is a bit like our Cold Lake story over time--when you do something repeatedly you get better and better at
it. And I fully expect that’s what we’re going to see at Kearl.
Mr. George Bezaire: Rich, there are a
couple of questions that came in over the Web–and a couple of them relate to transportation. The first one was from Barbara Betanski of Addenda Capital. And she wondered if you could put some
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pontification to optimizing the existing pipeline system to increase market access. What kind of volumes might that result in?
Mr. Rich Kruger: For example, Enbridge. They have --with some of the integrity issues-- taken some lines out of service. They
have had some other lines that they’ve de-rated the pressure capabilities to manage the integrity while they do further integrity inspections and work. And the absolute numbers I’ve seen, on the order of several hundred thousand barrels a
day of de-rating that has occurred.
Well, they’re looking right now. They’re doing inspections, monitoring. In some
cases they’re verifying the condition. They’re replacing or improving some sections of the pipe with the anticipation that those volumes that have been derated will be re-rated. And the kinds of numbers I’ve seen are in the several
hundred thousand barrels a day. It’s significant.
Mr. George Bezaire: The other question came from Matthew
Vita of Beecher Investors. In the scenario where we sell diluted bitumen from Kearl to one of ExxonMobil’s refineries in the Gulf of Mexico, what would be the actual selling point to Exxon? Is it transfer priced at the pipeline mouth leaving
the terminal in Canada, or do you own the bitumen all the way down to the Gulf?
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Mr. Rich Kruger: Well, I think it varies. Each of our commercial arrangements
can be different.
What we’ll look to do certainly is maximize the value to Imperial of Kearl. And if that’s selling
it further upstream closer to the source and the production, we’ll do that. But, we’re looking at making the pipeline commitments so that we can take it and feed our refineries and/or if we have the opportunities to maximize the value to
provide feedstock to ExxonMobil refineries.
So, I think the answer to that is it will vary. But, what you know is whether
it’s our pipeline commitments, our rail commitments, our intent all the way along will be maximizing the value to Imperial Oil wherever that transfer point is.
Mr. Faisel Khan: Hi. Faisel Khan with Citigroup. Two questions. I guess the first one is on capital allocation, capex, dividends, share repurchases. With your debt levels coming down, assuming
commodity prices stay the same, when do you plan to make the decision on share repurchases as you go into next year and those debt levels start to come down and as the expansion phase wraps up or comes to conclusion?
And my second question is on Celtic. Is this transaction going to be accretive, dilutive, or on par with your long term return on capital
employed? And, when are we going to see the results pan out from that transaction?
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Mr. Rich Kruger: Well, I think the first one on the decision, the answer is it
depends. We have showed it over a range of price environments. Of course, we have KID which will be ramping up. So, we’re going to start generating a lot of cash from KID. Nabiye is not all that far behind and the expansion’s not all that
far behind.
We look at it--quite frankly, I look at it quarterly. I look at our dividend. We’ll look at our investment
plans and progress, and that’s really the order. We have 120 years of consecutive dividend, 18 years of per share year-on-year growth.
We know where we are competitively now. We’ll look long and hard at that. We’ll look at our investment needs, the environment we’re in and the cash flow. And then, we’ll look at
returning value to shareholders through repurchases.
So, we’ll look at it on an ongoing basis. When is a little bit
harder to say because it depends on all those variables. But, we know how important it is. We’re committed to the value of the distribution to shareholders. And future repurchases, we would anticipate, would be a part of that.
Now, Celtic. In the same way we make investment decisions, we look at it in terms of adding value. So, your question about the dilutive or
what is it going to look like. I described I like the optionality. Celtic could be part of a larger scale, longer term gas export plan or, because of its liquid rich
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nature in the Montney, it could be part of an ongoing incremental value adding profit activity on its own.
Our technical folks are working with ExxonMobil’s folks, the XTO side, right now. They’re looking at that. We’ve got some activity. And I think the jury’s still out on that. But, I
certainly wouldn’t expect looking to do anything that would be dilutive over time. And so, we have high regards for the ultimate value of Celtic.
Unidentified Man: Hi. A question on Kearl. You’ve got the expansion already going ahead in terms of the capital and the copycat nature of it. But, Kearl has no operating history, unlike Cold
Lake, you had the operating history to copy.
And the paraffinic froth treatment is, again has not been operated at capacity
for an extended amount of time, and yet you’re already proceeding with the next phase. And I’m wondering if there are concerns there or just if you could comment.
Mr. Rich Kruger: Glenn showed the chart that was an assessment of the expected relative operating costs on Kearl. What I’d say is you started it with we have no history on it. True
statement on Kearl.
However, when you look at Syncrude, when you look at the rest of the mining industry, there is an
extensive database in history. And we have been right in there on Syncrude,
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understanding that when you look at the efficiency of the trucks, for example, the quality of the shovel, the mining operation. So, I think we have a pretty good database upon which to base our
thoughts on that.
Of course, our mission is to make it better. And when you have a higher quality ore base to start with with
a bit less overburden, our expectations are that it will be better. It will be better, certainly better than the average. So, we’ve got a fair bit there.
On the treatment side of itself, the paraffinic froth treatment, although it’s new technology or proprietary technology I think we have a pretty good sense. There are a bit fewer moving parts in some
of that relative to a lot of the mining operations.
So, I mean, the proof, at the end of the day, obviously is in the
performance. But, I think we have a good feel going in to where it’ll be positioned. You saw it on the chart. And then, our mission will just be, in the same way we always have, is to continue to dig in, look, and make it better and better and
better.
I like the idea--Glenn flagged it. When you look at the bar on the chart you have, I like the big blue part of that.
Relative to SAGD, there is less of a sustaining capex required,
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and there’s a bigger component of that operating cost bar that is ongoing operating cost.
And Glenn described it. He used an example with the number of trucks per year, the 10 percent or more higher quality than average in terms of a truckload, how much bitumen you can get out of it. I think
we have a lot of opportunity there to further optimize and improve.
Glenn and I were onsite last week. We were up there with
an operations manager who’s the best in the business. ExxonMobil graciously provided him to us. I’ve worked with him for a long, long time, and he’s good. And he and his team are sharply focused on getting it up and running, then
making it the most efficient, cost-effective operation it can be.
And that’s kind of our Cold Lake story. So, you know,
what we plan to achieve over time--and we hope you can see with technology, with the disciplined way we approach our business--we anticipate over time being able to show you and groups after each of us charts that show that continuous improvement
and value at Kearl paralleled in the approach that we’ve taken at Cold Lake.
So, that’s a long answer to your
question. Data will prove us out. But, we are very, very encouraged and positive about the competitiveness of Kearl’s operating cost to the best in-
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situ projects in the business. And a lot of that’s the design. It’s how we built the thing.
Mr. George Bezaire: A couple of questions now on LNG. One, what size gas resource do you think is needed to stand behind an LNG project? And is there sufficient resource size at this point for
Imperial?
And then, the second question around LNG was given that Imperial’s annual return on capital employed was 25
percent, what kind of return would you expect to see on an LNG facility and can it compete with that kind of return on capital employed?
Mr. Rich Kruger: Well, to answer on the resource side, what’s required on an LNG, the answer is it depends. It depends on how big of LNG facility you’re going to build.
And what industry has seen over time, as you go larger and larger trains, you get an incremental unit cost efficiency both on the capital
cost and the operating cost. So, what you want to do is find that sweet spot where you have a size and quality of resource and what train size will that support.
The other thing on LNG that around the world has shown is it’s a bit different than a traditional oilfield that’ll come up to a plateau, it’ll peak, and then it’ll decline. An LNG
facility has a bit more of a downstream or refining characteristic to it is you want to kept it fed. You want to keep gas coming in.
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So, my answer on how big a resource, I can never have too much high quality resource to
support an LNG project. But, the absolute size, what we’ll be looking for at a minimum, it’ll be the evaluation that goes with the facility size and kind of striking that right balance.
Profitability--you’ve seen our return on capital employed. We look to have the most profitable projects in the business. And we will
achieve that by having a large, high-quality upstream resource and gas supply. We’ll achieve that by having the right, most technically advanced trains and ships, and getting good, strong markets and a customer that values our products.
What type return? I don’t have it today. I don’t have the number. And, honestly, it’s not that I’m not
sharing it. I don’t have a number. We don’t look at it that way. We look at taking the components, assembling it. We look at the various risks and uncertainties. And we understand what the expectations of our company for a premier
financial performance. And if we get to the point where we would pursue a project like LNG or any other, we’re expecting it to deliver superior returns.
Mr. Dave Clark: Good morning. Dave Clark from Deutsche Bank. A couple questions about the technologies you discussed in that video.
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I guess when I’m thinking the timing of the commercial applicability of those, the
SA-SAGD and the CSP applications, I guess, are both being piloted at Cold Lake. I’m wondering how long until those can be commercially applied.
And then also, in the tailings management technologies, will CIMA be applied to the second phase at Kearl? And is NAE something that will be eventually applied at Kearl, or would that be at some other
mining operation?
And then also, I guess as a corollary to that, I--just to clarify, is CIMA within OSTC and also is NAE?
Mr. Rich Kruger: The second phase at Kearl is being designed like the first phase. So, CIMA or non-aqueous extraction
are not part of the plan.
When we talk about any of these technologies from the environmental aspect, we didn’t emphasize
it as much in the video, but they all have strong business drivers above and beyond the strict environmental performance. You’re moving less fluids, solids, and so each of these, we think, can enhance the profitability on it.
You know, can you convert things over time? It kind of depends on the technology and when. It’s not part of the expansion plan at
Kearl, but we will certainly be looking at any technologies, either on the full scale for a project or partial scale, its application on Kearl, Syncrude as time goes on.
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The timeline overall, you referenced some of the pilots that we have going on at Cold Lake.
And so, a lot of how we will apply new technologies, we’ll kind of phase into them. If a pilot’s working, we’ll expand that pilot. All of the resources, Cold Lake being included, they’re all not homogenous across the entire
field. So, they have some areas that are thinner. They have a little bit different composition.
And so, as we apply
technologies and pilot them, we have--Glenn, what do we have right now? We have 240-some wells in on LASER?
Mr. Glenn
Scott: Yeah.
Mr. Rich Kruger: On LASER, liquid addition to steam right now. So, we pilot them, and oftentimes
those pilots kind of grow into a commercial application. We have right now 20 percent of our field or so at Cold Lake that’s under a continuous steam, a steam flood--.
Mr. Glenn Scott: --Yeah--.
Mr. Rich Kruger: --For
example, when you look at Cold Lake, we have cyclic steam. We have continuous steam flood. We have LASER application. So, I think what you’ll see in a lot of those is phasing in.
Where you’ll see the upfront difference is when we do something new, an Aspen, a Grand Rapids. And at that point, we’ll look at
what the--whether it’s SAGD, SA-SAGD, that initial
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commitment will be based on a technology. And with the timelines that I shared with you, when we’re looking at some of those developments later in the decade or early in the next decade, we
think we’ll be in a position with those technologies at that point in time to decide what’s the best, most profitable approach to apply.
Unidentified Man: [Inaudible]
Mr. Rich Kruger: I’m sorry.
I forgot that part of your question. I’m sorry. Go on.
Mr. Glenn Scott: The CIMA technology is part of the
consortium, COSIA. We fully shared all of that.
The non-aqueous extraction is just that. It’s an extraction-based
technology. And that is not currently in COSIA.
Mr. Arjun Murti: It’s still Arjun Murti.
You described the paraffinic froth treatment as having three trains. Can they run independently such that, if you have planned or
unplanned downtime in any one train, you don’t have the whole project go down, which I think would be different than the mines with the upgraders? When there’s a problem with the upgrader, the whole project tends to be down.
And then, related to that, can you make any comments on how we should think about the paraffinic froth treatment reliability? Should we
expect those to run similarly to how
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upgraders run, or do they face some of those same risks? Any comments?
Mr. Rich Kruger: The trains, yes, they are independent.
Now, if you go back to that one chart that Glenn showed, if you start in the mine and then the surge bin separational, there’s a
whole chain there that is not as fully independent as the three trains. But, the three trains are.
I thought he did a good job
of describing that where we have, in essence, wide spots in the line, surge bin, hydrotransport capabilities, so it was designed with the idea that it’s not all or nothing.
The surge bin, for example, right now, heavy rains up in the Fort McMurray area affecting everybody. Well, we have stockpile of ore that,
while we’re not able to bring it out of the mine at the pace we need, we have a stockpile that we’re able to draw from. It was put there and designed for just this very thing.
So, we’ve tried to think about reliability and all of the vulnerabilities in it so that we can achieve a reliability that is more
like a traditional upstream operation than a mining operation.
The second part of your question?
Mr. Arjun Murti: I think it was just the nature of how we should think about reliability of the individual trains.
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Mr. Rich Kruger: Well, again, Glenn had that diagram that showed a conventional
mining operation with an upgrader and Kearl. And then, he showed you earlier Syncrude, and he showed you where the vast majority of the reliability problems have been. They were that big old bar that said upgrader.
We don’t have that in the equation. We believe and we have designed Kearl, and the expectation will clearly be that we have a higher
level of reliability than the conventional mines that have upgraders in the oil sands.
Mr. Arjun Murti: And then,
just a market access follow up. Any plans or thoughts, I think the answer is no, to add more heavy oil capability to your Strathcona refinery, or is it primarily to use the rail to get out of the country?
Mr. Rich Kruger: Well, we continue to look at our refineries and look at the most advantaged feedstock.
Right now Strathcona is 160,000 barrels a day, round numbers, advantaged feedstock--you know, the mid-continent crudes right now.
We’ll look at them. I think it was described well is if there are investments, we’ll look at them. You know, we’ll scrutinize them long and hard.
We recognize that the unique situation here with the high margins won’t always last. So, we’d be very prudent about what we would do. But, we will always look at our refineries to see how we can
affect the mix and/or very selectively if there are
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modifications that are needed to further enhance their profitability. I don’t have anything tangible to describe to you today on Strathcona, though.
Mr. Kurt Wulff: It’s Kurt Wulff of McDep. I’m still a little confused on the trains, and then I have a second
question.
Does the three trains mean that you have three of these giant ore crushers, three storage bins, three hydrotransport
systems, three of everything?
Mr. Rich Kruger: No, it’s on that paraffinic froth treatment process. We have a
single crusher, for example. We have dual hydrotransports. We have one large primary separation vessel. And separately from this, if you wanted to understand the kit, we’d be glad to help describe it.
But, the trains are really that paraffinic froth treatment process. The proprietary nature of it is where it splits into three.
Mr. Kurt Wulff: Yes, that helps. I understand.
My second question was, what happens to the asphaltenes that are sent to the slurry--to the tailings area?
Mr. Rich Kruger: They’re separated out. And that’s the key step that allows for pipeline-quality bitumen. If those
asphaltenes were retained in the bitumen, we wouldn’t be able to dilute it and put it in a pipeline without an upgrader.
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So, --along with the clays, the sand, any residual water in it--they’re returned to
mother nature where they came from. And they go into the settling ponds and ultimately go through a reclamation process just like everything else that goes there.
Mr. Kurt Wulff: And presumably they’re not very reactive. They’re somewhat chemically inert and aren’t a problem going forward?
Mr. Rich Kruger: Right. And that’s all within all of the regulatory approvals we’ve received. This is not just an
Imperial assessment on it. This is everybody looking, eyes wide open.
And, it’s going back to where it came from. And we
just need to do that in a manner--Glenn, do you have any other comments on that?
Mr. Glenn Scott: I’d just
add that, after the Kearl Expansion Project starts up, we’ll start to treat tailings. And by the end of the decade, we’ll have enough room in the pit itself to take those treated, thickened tailings and put them right back in the mine and
no longer go to the settling pond.
Mr. Kurt Wulff: Thanks.
Mr. Mohit Bhardwaj: Hi. This is Mohit Bhardwaj from Citigroup. I had a question.
Paul, you mentioned Dartmouth, that the decision is pending in like weeks. Just wondering what’s the thought process over
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there. Is there a buyer or, you know, you guys are looking at alternative options? And I’ve got a follow up, please. Thank you.
Mr. Rich Kruger: We announced, oh, a year ago that we would look at the long-term plans and that we’d look at possibly
marketing it. We’d look at a conversion to a terminal, for example.
And that’s what we’ve been doing. There was
interest in the market, certainly. And we’re wrapping up that work right now. And we don’t have an announcement today. I anticipate we’ll have one here, as it was said, in the near term and what it is. But, we don’t have any real
announcement on the outcome of that, at this point.
Mr. Mohit Bhardwaj: And just to follow up on Kearl--when do
you guys expect to sanction the third ore processing plant and the de-bottlenecking?
Mr. Rich Kruger: Glenn, the
timing, I’m thinking more of when from the phase up and when we’re anticipating it in terms of contribution. Timing, Glenn?
Mr. Glenn Scott: We’re currently doing the front-end engineering work and making progress on that through the balance of this year. I believe sanction could be end of the year or into
2014, but that kind of timeframe.
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Mr. Rich Kruger: And, you know, it depends. But, as Glenn said, we have a lot of
the engineering work. We want to be sure--it’s like we talked about on KEP as we put the costs together and look at it.
And any project sanction, when it’s in that engineering stage--and I’m not signaling this because I don’t know yet. I
haven’t seen it all, is--you know, we’ll look at it. And if there are areas we want to investigate further to make the project plan better, we’ll do so.
But, it’s something that you would say is within the foreseeable future to allow us to get both the plant and the mine de-bottlenecked by the end of the decade, as we showed here.
Unidentified Man: Sorry, just another question on rail. Do you have--I don’t think you do have your own terminal, rail
terminal. But, you know, I guess I’m thinking of how do you access, where would you load from? Do you have pipeline? Is there sort of pipeline capacity to a third-party rail? Do you have reserve capacity at that rail terminal?
Mr. Rich Kruger: Yeah. Well, like on smaller scales, for example, we talked about our refineries out in Ontario. We’ve
commissioned some rail loading racks and terminals there to feed the refineries.
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As we and industry look at larger scale rail from the crude standpoint, from the source,
there are a lot of tank farms up there. There’s a lot of space. And we’ll work with others who are, capable, skilled in this area to build whatever incremental capacity for rail, rail loading would be needed.
Unidentified Man: You have the slide--a lot of the questions are upstream related. But, as of right now, Imperial Oil’s making
enormous amounts of money on the downstream. And one of the slides you have is the debt to cap at different oil prices. I was curious as to what are the assumptions in that debt to cap slide with respect to downstream profitability.
Mr. Rich Kruger: Well, one of the beauties, and Paul highlighted this, is the level of integration for us. Right now
there’s a big discount on the heavy oil crudes. And our refineries that have the vast majority of their capacity to handle it benefit from that greatly.
As that gap would narrow, well, some of that profitability would be squeezed out of the downstream and go back into our upstream. And as our upstream capacity increases, you’ll get more of a balance
between that. Right now the refining capacity is about twice the upstream equity. But, as our growth occurs, you’ll get a bit of a balance there.
And I’m not trying to facetious, but it’s kind of one pocket or another in that. And so, as you look at that cash
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flow, there are elements of it that, on the assumptions you might make, it can be a bit indifferent because if you don’t see it in the downstream, you’ll see it in the upstream. And
that’s that level of integration, and what I would say is, increasingly, balance you’ll see in our upstream and downstream capabilities and portfolio.
Now, there’s assumptions on there around discounted spread relative to WTI, nothing that I think anybody here would find, unusual when you look at the marketplace. And then, of course all the
operational assumptions around cost and volumes are built into that.
But, that balanced integration upstream and downstream,
it’s a cushion a bit as you look at that. There’s not one assumption that’s heavily leveraged one way or another. And again, that’s a bit of the uniqueness of us.
Any others? Well, I will tell you I thank you for coming today, both those in the room and those on the webcast. I’ve said it a few
times. It’s a very exciting time at Imperial.
I think you have a company here that has the same value and discipline
historically, but is on a very different trajectory for the rest of this decade. Personally, I’m pleased to be a part of it. We have a lot of work to do. We have a lot of delivery to make.
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And I look forward to interacting with you in these types of forums or individually as time
goes on. So, thank you very much for being here.
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