Exhibit 99.1
2017 Update Call
Wednesday, 1st November 2017
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Wednesday, 1st November 2017 |
Welcome
Dave Hughes
Investor Relations Manager, Imperial
Good morning everyone, or good afternoon. Welcome to Imperial’s 2017 business update. Thank you all for joining us today. This morning, Rich Kruger, Imperial’s Chairman, President and Chief Executive Officer, is going to be providing a company update, as well as provide some highlights on certain aspects of our business. The slides we are going to go through are going to be available on our website shortly after the webcast, and the webcast itself will also be made available as soon as possible on our website.
Following Rich’s remarks, there is going to be a short Q&A period. Imperial’s covering analysts have been invited to submit their questions at that time but for anybody who has any questions or further questions, please feel free to contact the investor relations team directly.
Just before we start, I would like to draw your attention to our cautionary statement which is at the front of the presentation. The statement contains important information on forward-looking statements, risks, uncertainties and reserves, and resource disclosure. I would encourage you to fully review it if you have not already done so.
And now I would like to turn it over to Rich Kruger.
Group Overview
Rich Kruger
Chairman, President & Chief Executive Officer
Good morning. In addition to Dave this morning I have the Imperial Oils Management Committee, Beverley Babcock, John Whelan and Theresa Redburn here with me. In a typical face-to-face meeting we have spent time in the past talking about the energy outlook, comments on the business environment. Today, I will be a bit briefer up front and spend more time on the business and the performance update.
Global Energy
That said, let me start with a few comments on global energy. Our belief is, and our analysis supports, that based on economic growth, population growth, rising incomes globally, that we see global energy demand increasing by some 25% through about 2040. And we continue to see oil and gas remaining key in that outlook. Shown on the chart is global liquids production approaching 100 million barrels per day at this point in time. And what is important to recognize is with the natural base decline of a depletable resource, that significant new production will be required over time to meet the world’s demand. In the outlook here, with a 5% annual base decline, numbers that we have received from the International Energy Agency and other sources, you can see some 80-90 million barrels a day of new production will be needed by the year 2040.
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There is no one location that will be able to meet this need; it will take OPEC, non-OPEC sources, conventional, unconventional, deep water, heavy oil – the full suite. And it goes without saying that major ongoing investment will be required. The International Energy Agency estimates that some $1 trillion a year in oil, gas and coal investments will be required over the period here. So we continue to believe there will be strong markets for our products over the decades ahead.
Canada’s Opportunity
If we comment briefly on where we see Canada fitting in on this, we think Canada is uniquely positioned to help meet global demand, but it is premised on global competitiveness. You can see from a resource standpoint the Canadian industry has access to some 170 billion plus barrels of oil, third by a global count. When you factor in the stable trade driven economy, sanctity contract, rule of law, we have an investment climate that we think will be attractive for investment over time. The world scale resources certainly open to private investment; the environmental, regulatory standards here, in terms of securing approvals or regulations, all support social responsibility in terms of the development of the Canadian resource sector.
Technology we believe will be key to the future growth with some 97% of Canada’s liquids, hydrocarbons associated with the oil sands. We think Canada fits in well; it will depend on economic, environmental competitiveness. And we will offer more comments on this throughout the rest of the review.
Winning Formula
Traditionally we have shared and we have talked in terms of our business model and what are some of the key components or attributes of it. We have recast it a bit differently this year to really convey, how do we intend to win? Short and simple, we believe increasing cash flow while delivering industry-leading returns throughout the business cycle is the winning formula. Shown below that are the areas where we have a particular priority in what we strive to achieve:
| • | Industry-leading performance and reliability; safety; operational integrity. |
| • | The competitive advantages of levering technology integration and ExxonMobil; the relationship with ExxonMobil we believe will differentiate us. |
| • | Continuing to achieve improvements in our organizational efficiency and effectiveness. We have talked in the past about above the operating level, how we have brought down our workforce, contractors and employees through contract expiries, through natural attrition, through retirements, by some one-third over the past several years, and have taken more than $300 million out of our above-field cost structure. |
| • | We believe in today’s world being the most valued partner with key stakeholders is critical, whether that is aboriginal groups, whether that is federal or provincial governments, or those industry players that we partner with. |
| • | And last but not least, as we see new opportunities to capture those while continuing to manage our large existing asset base to maximize value. |
Throughout the course of the review we will illustrate or amplify many of these components of our winning formula.
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Enhancing our Portfolio
Reflecting back over the last several years, if you look at what the company has done to enhance our portfolio, focusing on our highest value assets and our core competencies, we have just summarized in a timeline manner the activities, the items we have done here to strengthen our competitiveness and position us for the future. Directionally, at the top of the timeline, are those areas where we have added or invested in new assets. We have invested to the tune of about $19 billion in new capital expenditures over the past five years. And on the bottom part of the timeline are generally those things where we have made decisions to either sell or rationalize assets in some way. And we have received cash from asset sales to the tune of approaching $5 billion over the same time period.
We will hit many of these as we go but I think some of the more notable ones include acquiring the interest in the Celtic liquid-rich gas assets; the start-up of the two phases of Kearl; expansion at Cold Lake; and then more recently on the retail fuels marketing side of things, teaming with Husky by rebranding their truck transport sites. And then most recently the deal with BG Fuels and Loblaws, where we will rebrand some 200 retail sites under the Mobil brand.
Along with that, the closure of the Dartmouth refinery, sale of some upstream assets, and then the most notable, last year’s sale of the remaining 500 company-owned retail sites.
Scope of Operations
So we have positioned ourselves where we believe we have a high-quality asset base; we remain integrated across that asset base. We are quite balanced and resilient to whatever business environment we believe we will operate in. So it leaves us largely with a scope of operations shown here. We have upstream assets that have a productive capacity on the order of 400,000 barrels per day. We have a downstream refining network that can refine about 400,000 barrels a day. And from a petroleum product sales, at any given period, we sell between 450,000 and 500,000 barrels a day across all product types. We also have a chemical facility integrated with our Sarnia refinery, where in round numbers we manufacture about 1 million tonnes per annum. Approaching 50% of which is special products, polyethylene most notably.
To support our efforts, we have a distribution network on the fuels marketing side that we believe is unparalleled coast to coast. And last but not least, our investment in science and technology is best represented through our upstream and downstream research efforts, where, on any given day across our company, we have some nearly 900 engineers working for us, about 80 or so of which have PhDs.
Upstream Assets
Shown here over the last 30 years or so is the transition we have made which positions us today where we have a handful of large, long-life predominantly oil sands assets. Kearl, Syncrude, Cold Lake. I will talk about each of these here in a moment. And you can see that with the liquids production growth over the last couple of years – in fact, 2016 was an all-time liquids high production for us.
Over the last five years, this business has generated some $7.5 billion in cash from operating activities, with a relatively wide range over that period. On the low end, on the order of about $300 million a year, when prices were at their lowest, to, on the high end in excess of $2 billion a year when prices were higher.
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So with that as an upstream introduction, let me now dive in and start with Cold Lake.
Cold Lake
Cold Lake is one of those assets. It has been around now 30+ years. It is just a rock star in terms of performance. Industry leading in situ; continued growth potential. A strong history of performance; we would measure that by reliability, by unit cost, by profitability. We more recently added the Nabiye project, our expansion in 2015. Shown to the left are the three most recent full years of operation. And then where we are through nine months in the year to date 2017. We have detailed for you, for the first time, the base production and then the additions on top of that base. Cold Lake in the absence of investment would have a base decline of on the order of about 5% per year, or 7,000-8,000 barrels a day per year of just natural decline.
Now, we seek to maintain that through our workover programs, through our infill drilling, and then with the addition of projects such as Nabiye. In the near-term, for the next year or two, we see Cold Lake remaining at about the 160,000 barrel a day level, with an attractive cost structure of unit cash costs on a US dollar basis in the $10-12 a barrel range, with about a third of that associated with the energy required to generate steam.
We have had conversations about Nabiye over the last year or two. Nabiye was originally intended or designed for a nameplate capacity of about 40,000 barrels a day. However, due to steam excursions from the producing Clearwater to the immediately shallower Grand Rapids, we have had to limit steam injection volumes and pressures initially, as we manage that and ensure we keep the energy in the productive reservoir. So Nabiye has peaked out in the order of the last couple of years at 27,000-28,000 barrels a day. This is not atypical for projects in Cold Lake field, where you continue to work with the producing reservoirs, enhance the top seal, and then inject higher pressure, higher volume of steam over time. But that is the range we have been, and continue to be, in at Nabiye at this point in time
It is also worth noting that when oil prices collapsed in the latter part of 2014, we wrapped up a drilling program, and we have taken a pause in 2016 and 2017, so you have seen that base decline more prominent in the absence of drilling. I will talk more about our activity plans here on the next slide.
Cold Lake enhancement
What are we doing to continue to drive performance and improve the contribution of the Cold Lake outset? Well, I have listed three areas here. Steam management: we look to place steam anywhere in the field to optimize its distribution to the highest value areas, looking at where we are on cycle life in various assets, looking at performance. On average, the activities that we do to enhance performance leads to some 4,000-5,000 barrels a day per year uplift, through managing the production volumes, our steam cycles, water management.
Areas that we are focused on right now are the LASER application, where we are adding a liquids addition to the steam to enhance recovery. We anticipate LASER will be contributing 2,000-3,000 barrels a day by the end of this year, growing thereafter, and continuing to de-bottleneck our facilities to get the most out of the existing investment base.
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On the wellbore side, it is all about maximizing the use of existing wellbores. With some 5,000 wells, the surveillance and how we deploy service reutilization remains key to keep as many of those wells up and running at any point in time.
And last but not least I commented on the drilling program. After the past couple year pause, we will be restarting a drilling program in 2018 with a one rig line. We will drill for part of the year and then we will start the steaming. And although there will be limited volumes over the course of 2018 that program will contribute to continue to keep Cold Lake in this 160,000 barrel a day range for the near term that I have commented on.
Kearl
Large, long-life mining operation and the focus is on proving its reliability. Shown in the chart are the volumes since the phases of start-up. The first phase started up in 2013, the expansion in 2015. And what we have been able to achieve is an operation that, quarter to quarter, depending on what activities we have going on, has been able to deliver about 180,000 barrels a day. That is below its design capacity. We have advertised 220,000 barrel-a-day capacity. When you look at the Kearl operations, it is really three phases: the hard-core mining aspect; the area that we would call the ore prep, which includes the crusher and the slurry preparation; and then the extraction or the paraffinic froth treatment process. The mining has operated fine; the paraffinic froth treatment and the extraction is fine. Where we have had challenges is in the ore preparation area, which is the crusher, conveyers, and the slurry prep. I will speak more to those challenges here in a moment.
We have commented briefly, and will talk more today, about the improvement plan we have at Kearl. And make no mistake, the goal is to meet or exceed the 220,000 annual average that we believe this asset should deliver. And we are targeting US cash costs, all in, fully allocated from top to bottom at $20 a barrel US or less.
And now let me continue and talk about specifically improvements that we put in place throughout the course of the year.
2017 Reliability Improvements
Just a little bit of a chronology. When we started up the asset, we went through the normal start up activities, looking to stabilize operations to ensure that in summer and winter we had steam distribution appropriately. That we had the process tuned and operating. That we dealt with things like filters from some of the initial debris that is associated with mining ore early on. So a lot of activities dealt with the plant and achieving a level of stable operation. Once that was done, we started to see some of the ore prep challenges develop. We had premature equipment failures; specifically things like bearings and chains on a crusher that were not high-tech necessarily, but where we had fatigue life that shortened the service intervals and some of the key components.
So this year we have made modifications to our crushers to reduce the load as trucks dump into the crusher and then feed that crusher through the ore conveyer, the drive systems, the chains, the pins. We have enhance the crusher teeth and the bearings. All with the objective of achieving longer run times before you would need scheduled maintenance of replacement on this front-end ore prep materials.
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We have also taken the opportunity to learn from the first several years of operation and looked at our piping where we have seen erosion in various components of the piping. Again, primarily in the front end or the hydro-transport and the ore prep components of the plant. But also throughout the plant. We have added high strength steels, carbon overlays, to enhance performance, reduce costs. Where we are today, we believe, with modifications we have made and have now completed in 2017, an expectation going forward is that we have an operation that should be able to reliably deliver on the order of 200,000 barrels per day going forward. Variation on quarter, based on scheduled or unscheduled maintenance. But the bump up from a 180,000 to a 200,000 is where we are at this point in time.
What that will also achieve is a reduction in the unit cash cost. We have delivered 180,000 somewhere in the range – depending on exchange rate – of $22, $23, $24 a barrel US. With the 200,000 barrels a day capacity we anticipate we’ll drop a couple dollars a barrel out of that unit cash cost and be somewhere in the $20-21 per barrel range. The incremental barrel is produced and processed on a small fraction, a $6-7 a barrel unit cost, versus the overall average that is somewhere in the low $20s.
We are not done yet.
Ongoing Reliability Improvements
We are progressing plans to increase annual production, not just to the 220,000 but to 240,000 barrels per day. We are going to be doing that by adding supplemental crushing capacity up front to create an offset for when we have equipment downtime scheduled or unscheduled. We are putting in some redundancy on surge bin conveyers that would feed the slurry preparation processes. And then now we have operated and looked at the reliability of component parts, we are putting some slurry piping interconnections in place that will allow us to maximize the use of facilities, minimize downtime, and optimize flow to all the facilities independent of the origin of any mined or crushed ore.
The investment that we believe we will be making here will be about a two-year program on a 100% share, we see somewhere in the order of $550 million. And our 71% ownership we anticipate it will be about a $400 million investment spread out over 2018 and 2019. And then that will deliver us the 240,000 barrels a day capacity expected annual delivery of the facility. Looked at a different way, if you divide that out, you looked at $400 million or the gross amount or the uplift, this equates to somewhere in the range of about $14,000 per flowing barrel for the incremental 40,000 barrels.
Syncrude
Syncrude is an asset with high potential value, but it is an asset which has had a level of unreliability primarily triggered by one-time events. What we have shown here is quarterly production over the last couple of years. The solid blue bars are the actual production; the hatched-in areas are those areas that were impacted by a particular event – not just ongoing wear and tear and reliability, but where we had an event that took us offline for some appreciable period of time. In 2016, a lot of that was the Alberta wild fires. And more recently in 2017 it was the fire we had in one of the units earlier in the middle of March this year and then the recovery time.
The mission at Syncrude is to reduce this unplanned downtime and eliminate these one-time events. We have been on a journey; we believe we are making progress on that in terms of
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our inspection, our maintenance plans, our operator training, competency assurance. And it has an acute focus on the bad actors which have largely been associated with the coking operation to get back to a steady state operation here. And I will comment on the target here in a minute.
We are also leveraging the collective capabilities of the owners. Operationally and administratively, increasingly our vision is to evolve Syncrude to where it is an operating asset, as opposed to a standalone corporate entity. So areas like tax, treasurers, controllers, procurement, IT services, as opposed to having standalone Syncrude services in those areas, the owners most notably to date, Imperial have taken on those responsibilities. We are also working now with Suncor, with their 54% ownership; are looking at the best practice application, and how we can bring the best of Imperial, ExxonMobil, and Suncor to get a higher reliable operation here. Our target is 75,000-80,000 barrels per day. Our share, the Imperial share, if you get to that 80,000 barrels a day, you are approaching the 90% reliability that is notionally the best-in-class for an operation of this sort.
Near-Term Production
If you take the summation of the big three assets plus the rest of our operation together, I would like to give you a little bit of a near-term production outlook. Year to date, in 2017, we have produced 367,000 barrels per day gross production before royalty. With the enhancements we have made at Kearl, which have recently wrapped up, with the coming out of the fire recovery at Syncrude now that is fully complete, for the rest of the year we think the average by the end of the year will be bumped up some 5,000 or 6,000 barrels a day annual average, from where we are through the first nine months. Then as we get into 2018, if you take Kearl at the 200,000, Cold Lake in the 160,000 range, and Syncrude at the 75,000 barrels a day – the lower end of the target – we see an annual production, with our other assets, of about 396,000 barrels per day. That is the bar that is shown on this chart. And again, it is based on the component parts that I just shared with you.
Upstream Resources
Looking ahead, from upstream resources, we have a large resource base that offers significant continued growth potential. We have shown here our 2P reserves: proved and probable, proved 4.4, probable another 2.5 billion. And we have shown those in contrast to contingent resource. Both those that we are progressing development on and those that are in the inventory but would incur an on-hold definition. And then we have further split the contingent resources into those amenable to in situ development, mining and other. And you can see that we are progressing development on the order of a couple of billion barrels of potential resource, and those are predominantly in situ. And I will talk more about that here briefly.
In Situ Growth
Here we believe technology is key to meeting the economic environmental objectives. The technology that we are progressing toward development at this point in time is the SA-SAGD technology, or Solvent Assisted SAGD. And I will draw your attention to the graph on the upper left: we have shown from a capital intensity and then as an indicator of either environmental efficiency and/or operating costs a cumulative steam oil ratio. We have taken the kind of industry represented in the blue bar and then indexed it to what we believe our
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SA-SAGD technology can deliver. And the quick answer is we think we have a technology set here that will be 25% more capitally efficient and have 25% lower greenhouse gas emissions. We think this is a winning technology; we have applied for regulatory approval for two projects. Aspen, two phases at 75,000 barrels a day each. It is well into the regulatory review process and we would hope and anticipate approval in the months ahead. And then Cold Lake expansion that early in 2016 we submitted the application for a single phase, 55,000 barrel per day operation. Each of these projects have been submitted proposing SA-SAGD technology as the recovery technology.
Below that are shown proprietary technologies that we have under development. LASER, I have mentioned we are applying at Cold Lake. SA-SAGD, of course. And then CSP, or Cyclic Solvent. Each of these we design, experiment, test them in the lab. We have a dedicated upstream research facility here in Calgary that we opened up about a year ago. We then apply the lab-tested technologies to the field to prove them via pilots. We use Cold Lake. Cold Lake happens to be a bit of a playground for us with 5,000 wells and the range of facilities to test new technologies. And then we tailor technologies to maximize the benefits for a particular resource we have.
So SA-SAGD is where our focus is now and what we see the next tranche of commercial development. But we have a suite of other technologies that we believe will also continue to improve both economic and environmental performance.
Unconventional Growth
Beyond oil sands, on the unconventional side, we purchased jointly with ExxonMobil in 2013 a resource referred to as Celtic. And over the past several years, as we have looked at and monitored the business environment, we have completed a resource assessment, shot seismic, exploratory and delineation drilling, and a series of subsurface analyses. The acreage was predominantly Duvernay and Montney, which you have heard me talk about in the past as providing optionality for either developing liquid-rich individual gas opportunities to flow into the North American grid, or to look at as a potential supply for a longer-term gas export project. We are in the midst of finalizing plans for initial development. We anticipate it will be Duvernay focused and our share of a development, as we look to 2020 and beyond, can be somewhere in the 30,000, 40,000, 50,000 oil-equivalent barrel per day range. Those plans are not yet finalized but we have completed enough resource assessment. Now we are doing the commercial economic evaluation and determining what is the best approach in terms of the scope and pace of development of the unconventional.
Downstream Assets
I will now shift to our downstream. And the tag line on offer here is that we continue to leverage operational excellence in integration to capture market value. Shown on the left are the three refineries we have. To the west, Strathcona, nearly a 200,000 barrel a day operation. Then to the East in Ontario, Sarnia and Nanticoke, that combined exceed 200,000 barrels a day. And due to their proximity we have an interconnectedness there that allows us to operationally optimize those facilities to a certain extent as if they were one larger facility. Also, if you look at the last ten years, you see our refinery throughput in the darkest part of the graph. And then on top of that the top line that would represent the petroleum product sales over this period. I think you will note a distinct strategy change here, where over the last five years or so we have sold more into the market than we have manufactured. And I will talk more about that on the following slides.
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The downstream business has generated more than $8 billion in cash from operating activities over the last five years. And unlike the upstream, the stability here, the high to low range has roughly ranged from about $1.5 billion to about $2 billion per year. So it has a level of stability that is uniquely different than what you would see with an upstream operation.
Refining Performance
Continuing on, I would characterize our refining performance. And I would characterize it as a relentless pursuit of reliability and profitability. Much like an oil sands mining operation, the incremental barrel is refined at a much, much lower unit cost than the average. So our focus has been on applying global best practices across our three refinery network, but in particular in coordination with ExxonMobil and its global network, to get the absolute highest performance out of our equipment, to ensure that our maintenance planning and execution is best-in-class. And then that we execute those periodic turnarounds on our major units to maximize the efficacy of the maintenance work and shorten the cycle time, and obviously the cost.
What you see on the left is we have shown the most recent three-year average for our crude unit utilization and then we have shown the prior six years. The reason we have shown three year intervals is with our three facilities, they have maintenance turnarounds that occur largely on a three-year cycle for each of the facilities. So looking at these assets over a three-year period gives you the best sense of aggregate performance. And then the prior two periods or six years we provide as a bit more of a benchmark.
So you can see we have increased use on the order of 2-3% from an 87% to approaching 90%. And we have largely done that by reducing what we refer to as regretted capacity loss, which you can think of as an unscheduled downtime, or downtime where you are losing money in the market by not being online. And we have reduced that from about 6% to a smidgen over 2% in the most recent three years. This enhances profitability not only in its own right through the economy of scale and the throughput, but also coupled with our disciplined cost management, looking at how we address the market from an economic sparing and economic optimization. And everything we do in the downstream is premised on integrated marketing plans that look through from the acquisition of the feedstock all the way through the final customer in maximizing the value across that integrated asset base.
Competitive Ranking
If I take refining and look at performance in a relative competitive manner, we participate in the biannual Solomon surveys. The most recent survey, 2016, includes some 96 refineries across North America, 13 of which are in Canada. So to make sense of this graph, you see the quartile performance, first through fourth, first being the highest performance. And then we split it here on energy efficiency, non-energy cash OPEX, total cost which would include energy cost, and then net margin. If you are going to be in the refining business, in the last several years being in the refining business in Canada has been the place to be because of landlocked markets, cost-advantaged feedstock, and a relatively strong market demand for the products. What you can see, starting on the far right, is that Imperial is in the top quartile in America on net cash margin. The Canadian sector is also in that because of these
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advantages that I have just outlined. But then when you look at the dimensions to the left of that, you look at the operating efficiency, total cost, non-energy cash cost, energy efficiency, you can see that the Imperial refineries, with 400,000 barrels a day capacity, largely represent a quartile in Canada. We are top tier in Canada and we are top tier quartile across North America.
The Canadian refineries, exclusive of Imperial, would on average be in the third quartile from a performance standpoint, from a North American frame of reference. The one area we are not in top quartile is our energy efficiency. With low natural gas prices and things over the last several years, we have not paid an inordinate price for that. But it is an area where we see improvement potential. And let me talk about how we plan to improve.
Strathcona Refinery Cogeneration
The Strathcona refinery where we will be installing cogeneration capacity. And a little tutorial on the left: what is cogeneration? Well, it is the production of power and steam at the same time from the same fuel for use in operations. So your natural gas fuels a generator to produce electricity. And off of that generator the hot gasses or the exhaust are then used to produce steam that you will use in your operations. Cogen not only improves energy efficiency, it reduces greenhouse gas emissions and ultimately lowers operating costs. Throughout Imperial’s operation we have cogen installed in a number of locations: at our Sarnier refinery; at Cold Lake, Kearl and Syncrude in the upstream. And they achieve the same objectives of energy efficiency, environmental performance, and lower operating costs. At Strathcona, we will significantly lower our greenhouse gas emissions while achieving these other objectives. We have a $250 million project advancing where we have spent about $60 million to date in this project. It is robust under a range of conditions and we target start-up of the Strathcona cogen project in 2020. That will further strengthen what is already a strong, competitive refining business for Imperial Oil.
Downstream Synergies
We do not consider ourselves a refiner; we do not consider ourselves a fuels marketer. We are an integrated downstream company that captures value through our integrated manufacturing and marketing plans, shown by the pictures on the left: from refining ad supply, through logistics and distribution, ultimately to fuels and lubricants and to our customers. We believe we offer a premium customer offer slate, through our quality brands, our loyalty and our marketing programs. We can supply coast to coast, provide customer support; and here again through our relationship with ExxonMobil, the global leadership in product R&D.
We have an exceptionally strong position in core markets, particularly Ontario, the greater Toronto area, and the expanded trib in that. And then the western region supported by our Strathcona refinery in Edmonton. We have a comprehensive distribution network and our decision-making again is value-chain based on how from the feedstock through to the customer we can best compete. Our simple description to customers, we strive to deliver what they want, where they want it, when they want it, at a competitive price. Our objective is to achieve this better than any of our competition.
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Fuels and Marketing
Let me highlight a few of the things most recently on the fuels and marketing side, where we have been capturing new business and meeting the customer needs.
Particularly on new offerings we have had the introduction of synergy fuels, of superior quality fuel into the marketplace, now nationwide. We are now also part of a deal with Brookfield and Loblaws on the conversion of some 213 former Loblaws locations to the Mobil brand. And where we stand today on a market share, we are number one in wholesale; we are number two in retail. We are number one in aviation, number one in marine, number one in asphalt, number one in lubes. With the Loblaws deal and the addition of some 213 sites, we will go from about 1,800 sites nationwide to more than 2,000. We believe that will put us into the number one retail market share position in Canada.
Long-term supply agreements. We have reached an agreement with Husky, where the entire Husky truck transport network – some plus or minus 75 sites – will be converted to the Esso brand. That work is in process so there will be 150 Esso-branded truck transport sites nationwide that will take the Husky and Esso from number three and four market position in truck transport and move us up there to compete with number one and number two in the market place. We also are now the exclusive lubricant supplier to Mr. Lube across Canada, a large account.
And then nationwide, strategic accounts in areas like rail and aviation, where we are looking to leverage our supply chain strength to grow with existing customers. But also to expand into new markets, markets like aviation out of Vancouver, other areas where we think because of our strong, reliable supply chain network, we can meet our customers’ needs, tailored to those needs in a superior manner.
Chemicals
For completeness let me hit chemicals. We do not talk a lot about chemicals but we have a very attractive chemicals business, collocated with the Sarnia site, where we are a leader in North American polyethylene. That integration with the Sarnia refinery puts us in close proximity, within a day drive, to 60% of our customers. So we have a location, a cost advantage associated with the refinery and low-cost refinery off gas as feedstocks. We have been enhancing profitability over the past few years, investing in a new gas cracker furnace. Now to the point where 90+% of our feedstocks are cost-advantaged refinery off gas, Marcellus ethane. This is a business that has thrown off $1.2 billion in cash from operating activities over the past five years. $230-240 million per year. And here again a bit more like the downstream sector, a bit more stability on the order of $150-350 million per year roughly on average. So a strong business that we continue to look at how we can maintain our competitive advantage and incrementally strengthen ourselves for the long term.
Financial Performance
I will now shift and get into a series of slides that wrap up before your questions that deal with financial performance. Shown here is cash from operating activities over the last five full years. And then year to date 2017 through nine months. Colour coded and split into upstream and downstream and others. And I think what you will see from this graph and then the companion pie chart is the value of integration across the business cycle. We have consciously selected this period of time because the earlier two to three years in this period
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we were in a high crude price environment, and now for the past few years we have been in a much lower crude price environment. If you add that up, there is more than $18 billion in cash from operating activities since 2012. What is not shown on here is about $4.6 billion in cash from asset sales that have also occurred since 2012 through year to date 2017.
Where this places us, from a financial strength standpoint, is a very strong balance sheet with optionality and priority access to financial markets. We have shown, from a competitive standpoint, at mid-year the debt to capital ratios of us and peers. This is gross debt to capital. Through the third quarter we have about $5.2 billion on debt, $200 million current, $5 billion in long term. And that excludes the $800 million cash on hand at the end of the quarter. This is down from $7.3 billion on debt that we had at the end of the third quarter in 2016.
So the halo effect, the shadow effect of leveraging the ExxonMobil relationship, the ability to borrow on most attractive terms, and the significant capital structure flexibility is what leads me to say we have significant strength and optionality associated with our balance sheet.
Dividends
Now, an area that is high on our priority list are our dividends and I have said repeatedly our commitment to paying shareholders a reliable and growing dividend. What we have shown here are the last 20 years of annual dividend payment, our dividends per share. And then in the background there we have overlaid the dividend payment with the quarterly average of WTI on a US dollar per barrel basis over those same 20 years. And I think our commitment to reliable and growing is evidenced in all business cycles. We have now had 100+ years of consecutive payment. 2017 will mark the 23rd consecutive year of growth. And over the last ten years our dividends have grown at a 6.5% compounded growth rate. At the $0.16 per share per quarter, the current rate, on an annual basis, that would represent some $536 million a year in dividend payments a year. And I will come back to that when I talk about financial resilience here in a slide or two.
Share Buybacks
From share buyback, we have a history of returning cash to shareholders and preserving value. We have repurchased some 50% of our shares over the last 22 years, show by the bar charts on the left, where we had 1.75 billion shares outstanding in 1995, and through the end of the third quarter that will be closer to 840 million shares. Earlier this year we expanded our share buyback program. We increased our NCIB to 3% of shares outstanding; roughly 25 million shares. And through the first nine months we have returned $375 million, year to date. That includes $250 million roughly of buybacks in Q3. And we have also communicated that we anticipate another $250 million buyback program in Q4. We believe buybacks remain an efficient, effective way to return cash in excess of current business needs to our shareholders. And when you couple the share buybacks with the nearly $400 million in dividends that we have paid year to date, through the first nine months we have returned about $800 million to our shareholders.
Financial Resilience
From a financial resilience standpoint, we believe that our strength provides us a flexibility under a range of prices. Let me take a moment to describe the chart. The left bar represents dividend and capital spend. It makes assumptions of dividend at the current rate. So for
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example, at $0.16 per share per quarter, that would be the $536 million that I just referenced. That is what would be shown on here. Last year, the equivalent bar would have been $510 million. On top of that we put sustaining CAPEX estimates and growth CAPEX estimates for the period 2017 through 2021 or a five-year outlook.
On any given year you can get variation in sustaining capital or growth capital so we felt looking at it over a multiyear period would be the best way to look at it. Last year we showed you the 2016 through 2020 period.
I mentioned the dividend; in sustaining CAPEX, as we look out over the next five years, we see a spend to maintain our existing asset base upstream, downstream, chemical, on the order of $1-1.1 billion per year. Last year we talked about that in the $900 million a year range. The year before was about $1.2 billion. So it varies, based on the work we anticipate doing in the period we are looking at. But here it is shown as about $1 billion to $1.1 billion. And the growth on top of that, we anticipate over the next five years somewhere on average of about $900 million per year. Last year, again, a different time period. This was a bit lower number, $600 million a year. Now as we look at the five years out, we look at what I described as the potential for an Aspen project, the potential increase in activity on the unconventionals. Our ongoing downstream program. And then the additional redundancy expenditures at Kearl. It would total about $900 million a year. If you add up these bars, you get about $2.5 billion.
Now I will take you to the bar on the right, which are our cash flow from operations assumptions at various oil prices. Note the US dollar, Brent, $40/bbl, $50/bbl, and $60/bbl nominal cash flow. We have made some inflation assumptions, FOREX assumptions. Obviously there is a series of assumptions behind this.
What you can see though, the messages I would convey in a $45 dollar a barrel Brent world or something in the $40-42 a barrel WTI, we believe we will have cash flow from operations to cover a dividend and sustaining CAPEX. In a $50 a barrel Brent world or something $45, $46, $47 WTI, we will be able to cover dividend, sustaining, plus our growth plans shown here. And then if you looked at a $55 a barrel Brent world or a low $50s a barrel WTI world, we expect to have sufficient cash from operations to cover dividend, sustaining CAPEX, growth CAPEX, and a level of share buyback program comparable to what we are pursuing at this point in time.
So my message here is we have a strong ability to meet our highest priority needs. We have significant cash flow leverage with oil price. And certainly coupled with our balance sheet, we have the flexibility to respond, and pursue new opportunities, whether those are opportunities within our existing resource or inventory portfolio, or whether those are opportunities that would be outside of the company at a point in time.
Why Imperial?
So I will wrap up, before I turn it to you and your questions, with a slide I have described as ‘Why Imperial?’ We think the competitive advantages we have deliver long-term value in terms of our asset base. Our operational excellence across all aspects of risk management, technical, operational, financial. The level of value-chain integration, not only within the downstream but from the upstream all the way through the downstream. The growth opportunities; the inventory that I flagged. The technology; the history of creating value through innovation in technology. And last but not least, our commitment to shareholder value, as represented by dividends and share buyback in all business environments.
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I will stop there and we will open it up to any questions those of you on the line may have.
Q&A
Neil Mehta (Goldman Sachs): Thanks for doing this today. The first question I had was just your thought process around Aspen. What are the gating factors to ultimately get to FID here, and how should we think about the probability of execution?
Rich Kruger: We have been in a pretty extended regulatory review process. When we first put Aspen in, it was for a SAGD development. But we flagged to the regulator that we were working on and we anticipated a revision or an amendment to amend it to an SA-SAGD project. And that is indeed what we have done. In the meantime, while that process has been going on and that is working with the Alberta Energy Regulator, it is also working consultation with indigenous groups in the area. We have been working on the market aspect of it with potential contractors, on how we can get the most capitally efficient project. We have continued to do technical work on looking at optimization of the subsurface, the injection profiles. So we are getting to the point where managing the risk and uncertainty, we have done about everything we can do.
I will assume we get regulatory approval. Part of it will come with, are there any conditions that come with that? And I would like to think that we have checked every box and we are good, but until I see that and have that in hand, there are some assumptions I would have to make about any potential conditions. And I am not flagging that but I do not have it yet. If we assume, early somewhere in the first half of 2018 we will piece that together, look at the project. We certainly want something that I would describe as globally competitive. What I mean by that is we need to confidently be able to deliver double-digit returns in a price environment that we see the potential. It may not be a prediction; in the past I have talked about that as I know we want to deliver double-digit returns in a $50 a barrel world. Increasingly I have challenged our team to bring me a project that delivers double-digit returns in a $40 a barrel world. Again, not a price forecast, but recognizing the inevitable swings in the liquids or oil markets, that we want something that we know we will be proud of and adds value.
So it is kind of a long answer. It depends on the regulatory approval of the timing. I think we have a robust project to work with and I think the timing for this question will likely be somewhere in the first half of 2018. And certainly if we choose to launch at that time we will broadly share that.
Neil Mehta: That is helpful. Thanks a lot, Rich. And the follow-up question is, embedded in the forecast, can you talk about the differential assumptions for WCS crude? And just how do you think about pipeline takeaway issues coming out of Canada over the near term? So it is more a 2018, 2019 question.
Rich Kruger: Yeah, I think there is obviously some new industry capacity coming on. The industry, we have not largely had any trouble getting into existing pipe. The pipelines have been doing things to enhance their reliability and further incrementally debottleneck their
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pipe. But no doubt with some of the production that is coming on, I read everything that has been written. And our own work would agree that rail will get called upon to a bit greater degree than it has in the last year or so. You also have some underinvestment going on in conventional assets and some other areas. So there is a lot of moving parts to it, not only the oil sands growth that will occur.
We are quite fortunate with the investment we made in the Edmonton rail terminal to have the flexibility. And that flexibility is not only to ensure we get to market access; but increasingly we have used that rail to get, for example, Kearl to refineries where we think we can get a premium value for that bitumen. I forget the number, but we are approaching 30 refineries now that have had access to Kearl. Not just Gulf Coast refineries in the more conventional manner. So what we will do is we will continue to use the Enbridge mainline. We will continue to use the contract pipe we have. We see the major markets predominantly being, of course, in the US and in the Gulf Coast. We will strive to use the lowest transportation mechanism we can to get the most for that crude.
Differentials, you tell me what Brent or WTI is. We see WTI trading lower than Brent, obviously, in the near-term. Then when the differentials come down to the traditional quality aspect of it, any diluent cost. But, we are going to be looking at ensuring that we get barrels at the lowest transportation cost. What I would say is rail is increasingly competitive with the investment we have made, both on either a fixed cost or a variable cost basis. There are times when we look at the pipeline alternative, the variable cost aspect of rail is a more attractive means for us to get to, whether that is Midwestern markets and/or Gulf Coast markets. I did not give you a number on differential, I am quite conscious of that, because we typically do not get into that. But, I think we are very well-positioned in the near-term as new capacity comes online and we do not have any material new pipeline additions, at least in the short-term.
Neil Mehta: Rich, last question for me is just how you see M&A getting into the go-forward strategy for Imperial, given your advantaged currency but also your strong balance sheet. Are there opportunities to bolt onto your existing asset base?
Rich Kruger: Yeah, I think for us it is always going to be about value. It is not just if something is for sale, but do we believe it adds value? Do we think we can uniquely add value so it does not become just a price play between a seller and a buyer? We are going to look at what we can do and how can we make something better than the current owner, either through technology, operational synergies or things. We have, throughout the recent market periods, and we continue to look at M&A activity to see where it adds value. We have done some relatively small things with ExxonMobil and the unconventionals that fit in with the earlier Celtic acquisitions. They are not big banner headlines but they have been things that strengthen the continuity and contiguousness of our resource base in core areas.
On the other areas, we have that flexibility. I think I have talked about that from the balance sheet strength and we do not feel pressured to do it. We have a healthy inventory of internal opportunities for growth. We talked about the capital efficiency of an SA-SAGD, for example. It needs to compete, and it needs to add value and it needs to be something that we think we can make even better. That is kind of a long answer. We look. We are always looking but we do not feel pressured to do anything unless we think it is of unique value for our shareholders.
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Neil Mehta: Thanks, you guys, for doing this.
Operator: Thank you. Our next question comes from Paul Cheng with Barclays. Your line is now open.
Paul Cheng (Barclays): Hey, guys. Good morning.
Rich Kruger: Hi, Paul.
Paul Cheng: Rich, just curious, you are going to enter into the next phase of your growth project in Aspen and maybe other replicator projects. If we look back, what lessons did you learn and then may have changed the way you go forward with the development from the lesson of Kearl and Nabiye development?
Rich Kruger: Yeah, Paul, we have talked a lot about Kearl over the last few years and it is really a tale of two cities. A lot of the lessons that we learned on the initial project, we applied on the expansion project. From a cost, a schedule, we had some of the same ore-prep reliability issues because of the ‘design one, build two’ aspect on Kearl. But, what I will say, Paul, is the in situ projects in an Aspen are a totally different game than the oil sands mining.
When you look at our history and then the support of ExxonMobil on Cold Lake and whether that is the cost and schedule on Nabiye, it is these facilities on the in situ are largely industry-proven. They are not massive-scale, like the mining side of it. A bulk of the cost is the facilities, steam generation capacities, steam injection, water-handling plants, which we in industry, do quite well. The other part of that investment component is the drilling of wells. We have drilled wells for 137 years and in fact, we have drilled 5,000 or more of them at Cold Lake. I think the capital risk exposure and uncertainties associated with in situ is really not even a point of comparison for Kearl.
Now, that said, when we look at lessons learned, we always look at what can we learn broadly. Industry-proven technologies, modules of a size where you have a demonstrated ability to design and fabricate, quality contractors, contracts that have the right kind of incentives for all parties to perform. But, all of those things are things that we, and through the relationship with ExxonMobil, look to bring to all of our capital projects, whether they are those we pursue in Canada or Exxon pursues elsewhere. I think all that is a way of saying that from a cost and execution standpoint, we would have a lot of confidence if we were to launch on a project like Aspen anywhere in the near-term.
The last point I will make on it, Paul, and you and I have talked personally, I have worked in a number of areas before. The thing you learn in Western Canada in Alberta is when everybody is out there executing projects, the contractor community becomes strained in quality labor, in productivity. To the extent you can be a bit countercyclical, you get the highest quality contractors, the best labor force, you do not have as many logistical constraints. We are in a different environment right now. And for the foreseeable future, if you were to proceed on a project such as Aspen, then we and industry were three or four short years ago, while projects like Kearl were being executed.
Paul Cheng: How about the lesson from Nabiye? Given that I think the company, we need then expand Nabiye. At this point we will still be running at 27-28, even though, yes, we need more of a steam chamber than hot water you can keep the steam backup issue. Is there a lesson that you think you need to learn from here, or that you think is a really one-off situation?
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Rich Kruger: I think we have encountered this excursion from the Clearwater to the Grand Rapids before at Cold Lake. It just was not in what was characterized as a standalone project like Nabiye was. There are always lessons that can be learned. As we went through the appraisal work on resources like Aspen, our Cold Lake expansion, as we drill delineation wells, as we conduct in the field – we will call them pilots – but tests in terms of the reservoirs’ ability to withhold, whether that is natural gas or steam, which we do to help build our subsurface confidence in any projects, model the range of uncertainties, the ‘what ifs’, looking at economics. If at our base plan, if we are not correct on that, what does it look like?
I would say there are always lessons to be learned, Paul. There is not anything acute or unique about Nabiye that would give us any hesitation or cause for pause on Aspen, relative to the subsurface, the technical work, that we have completed on Aspen.
Paul Cheng: Okay. Two final questions for me. One, in terms of the rail terminal, I think we have more than sufficient rail terminal in Alberta. But, do you think we have sufficient with receiving terminal capacity in the Gulf Coast for the heavy oil? Not so much for you guys but for the Canadian industry as a whole.
And the last question is on dividends. Your yield at this point, about 1.5%, which is noticeably lower than Suncor and in some of the companies as your peers. Several years ago, Exxon was also at the very low point and then they made a one-time big adjustment to bring it a little bit closer to their peers. Just curious whether that may be something that the Board may consider.
Rich Kruger: Okay, why do I not take the first one? I think on the heavy oil side of it, the refiners in the Gulf Coast, as they look at their crude supplies, of course, from us, from other areas, Venezuela’s other heavy crudes, they are always looking and anticipating. For us, today, a fair bit of our crude is sold through third-party commercial transactions to ExxonMobil. Of course, they are familiar with their ownership at Kearl, what we are doing and things. I am not particularly fussed about terminal capacity for growing heavy crude supplies. Individual companies and refiners maybe have a different perspective from their standpoint. But, how we fit in through the relationship with ExxonMobil, I do not think that is an area where we are particularly fussed with. There have been enhancements both north of the border and south of the border on storage to take the pulses out of the system a little bit. But, changes there are not typically uniquely high capital cost, nor do they take an inordinately long amount of time to put in place. I do not think that that is going to be any kind of a constraint going forward.
On the dividend side, we have talked about the 100 years and the 23 years. They are reliable and growing. I look at the yield and I see it on a competitive standpoint. That said, I do not fuss yields too much. I would rather have a high share price and apologize for a lower yield. But, I do not mean to say that flippantly. As we look at our business plans, our investors and our shareholders were quite patient with us over the last seven, eight years, as we went through uniquely high capital-spend periods. Of course, during that period we had suspended the buybacks. We have reinstituted that. I think if you look at our dividend recent-increase cycles, you see it shortening a bit. Without making promises on it, as we look at sources and
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uses of cash and the Board and I deliberate on it, dividend will continue to be an area that we look at and judge what is in the best interest of our shareholders. Yield will be a part of that. But, that will not be the only think we look at, as we decide what the right dividend strategy going forward is.
Paul Cheng: Thank you.
Rich Kruger: Thanks, Paul.
Operator: Thank you. Our next question comes from Benny Wong with Morgan Stanley. Your line is now open.
Benny Wong (Morgan Stanley): Yeah, thanks. Thanks for the opportunity, Rich. I really appreciate the large amount of color and details. My first question builds on Neil’s question earlier on why there are heavy differentials in your integration strategy. How do you think about the changes the new marine fuel regulations in 2020 will bring? How do you think Imperial is positioned for that?
Rich Kruger: Yeah, it is an area we are still working through right now. Benny, I do not mean to minimize these things, but we are continually under evolution on the regulatory front on fuel specs, whether that is marine standards, whether that is some of the motor gasoline in different areas and things. What we want to do is, if there are areas of the business that we think we are competitive in and add long-term value, then we will invest and we will modify accordingly. If they are not, there are areas that we will look at, ‘What are the other alternatives on it?’ We are going through the standards now, understanding it. They will have an impact. I would not say we are inordinately fussed with what is going to change. We will just adjust and adapt to market conditions with these standards, much like we have and continue to do with any others.
We do not talk about them all but in most all of our product lines, whether that is upstream or downstream, there have been just a continual stream of regulatory challenges that we and others have needed to adjust to. I know that is not very specific, Benny. If you want more on that, maybe I would ask you to contact our IR guys. If you wanted a more detailed discussion on it, we would be glad to have that with you.
Benny Wong: Sure. I appreciate that. My second question relates to Cold Lake, maybe beyond the 160,000 barrels per day you outlined over the next couple of years. Is there a path closer to the 190,000 barrels per day capacity with more optimization? Or would any growth above that come from new expansions?
Rich Kruger: Yeah. One thing I would say, and maybe you got that sense as I went through it, I do not think we have done as good a job over the last couple of years of describing to the analyst community and the shareholders all the moving parts at Cold Lake. Because when the prices went down in 2014, we had bitumen prices in January of the next year that were quite, quite low. We decided to scale back and literally suspend the ongoing drilling program. I think the world has assumed that an operation like Cold Lake is like a manufacturing facility, it stays flat and you just add on to it. We did not get into it as explicitly as I hope I did today, on things like base decline, how the drilling activity supplements that. There were a lot out there that rode on, ‘Okay. Here is where you were. We added the Nabiye on. We were looking for something 180,000 to 190,000. Why do we not see it?’ The lesson learned for us in that is, we could have, should have and will do a better job helping folks understand all the moving parts going forward.
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Now, Cold Lake, getting back to your question. The ability in this 160,000 barrels a day range, while we have this base decline that takes away 7,000-8,000 barrels a day per year, will come through restarting a development drilling program. One rig initially. We will see where that goes over time. The ongoing debottlenecking management of steam, continuing to work with Nabiye and seeing if we can get that 26,000-27,000 barrels a day up to a higher level, a 30,000+. I think in the near-term, the 160,000-ish. We may be a little higher, maybe a little lower. But, I would not anticipate anything grossly different from that. The Cold Lake expansion and think of that as adding new facilities for steam injection, and more pads of wells, that is where you start to see more of a step-function change from that 160,000 to something more like, as you referenced, a 180,000-190,000.
It will take new facilities to see that material growth. We may get some growth out of it. John is in the room with me. I am looking at him now on the pace and scope of the drilling program and the kinds of things we are doing just running the base business. But, they are not going to take a 160,000 to a 180,000 in a short period of time.
Benny Wong: Got it. I appreciate that. And just my final question is just regarding Syncrude. Maybe if you could provide a little more color on how you guys are feeling about the asset today after its recovery from the outage and fire? Any early thoughts on the new CEO stepping in, and if she will bring any differences in philosophy or approach? I will leave it there.
Rich Kruger: Let me start with that last one first. Of course, we were partners with Suncor well before their Canadian Oil Sands and their Murphy additional working interest. Now, with the two biggest owners holding essentially 80% of it, experienced miners, hardcore operators, that there is nothing but good that can come for Syncrude out of that. We work together closely. Now, it is a very important asset within Suncor’s asset base; it has been and continues to be for Imperial. Steve Williams, as I know he has referenced several times, he and I talk regularly on Syncrude. The whole focus is applying the best of the best from Imperial, ExxonMobil and, increasingly, Suncor, to improve its operation and its performance.
On the people side of things, there is Suncor employees, there are – excuse me, there are long-term Syncrude employees, there are Imperial secondees in there, there are ExxonMobil secondees. Now increasingly there will be Suncor folks. We want best available athletes in there to help manage this business. The new CEO, a very qualified, oil-sands-experienced operator. Of course, now we brought a whole bunch of years of experience of Shell through there, through Doreen.
In change of philosophy and things, I do not think I would expect that at all because I think you have a great deal of alignment amongst the owners on continuing to reduce the cost structure, make it more of an operating asset, less of a corporate entity. And absolutely eliminate the one-time unreliability events that have and have continued to plague this asset. When it is up and running, as it was all the second half of last year as it is now, as it was early this year, this is a highly valued, high-performing asset. But, just like anything in life, if I take out the bad things it looks good. We have to eliminate the bad things and that is exactly what the owners are focused on doing. But, I do not think you should anticipate or expect any change of philosophy in that because there has been and continues to be a great deal of alignment.
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Benny Wong: Great. Thank you very much again.
Operator: Thank you. Our next question comes from Phil Gresh with JP Morgan. Your line is now open.
Phil Gresh (JP Morgan): Yes, hi. Good morning.
Rich Kruger: Hi, Phil.
Phil Gresh: My first question on the growth projects that you laid out, and with respect to the cash flow from operations you talked about over a five-year period, I am just trying to get a ballpark of how you think about what kind of contribution to that CFO is embedded in that outlook? I assume, over time, that even at a flat price environment that should be going up as these things come on.
Rich Kruger: Phil, I am sorry, I rustled around and I missed a couple of words in your question. Would you mind asking it again? I am sorry.
Phil Gresh: Yeah, no problem. With the amount you are spending on growth capital, I was just wondering what kind of contribution we should be expecting to the cash from operations and what is embedded in that five-year outlook? I assume at a flat price, over time you are going to have a higher CFO from the investments you are doing.
Rich Kruger: Yeah, I think in the five-year outlook that we outlined there, what you will see breaking in component parts, is if we were to launch on in situ, like in Aspen, or as we finalize plans on the unconventionals, for the bulk of this five-year period you will see it more as the spending. And the cash flow from operations, that will come near the end of that five-year period. I do not think it would be a big number in the period of time we have shown here.
The additional supplemental capacity at Kearl, I mentioned that we will be at 200,000 barrels a day now. As we finalize our plans for bumping that up, that is something that will take us about a two-year period. For the last few years of this five-year period, you would see that bump up there. But, I think for the in situ and the unconventionals, you would not necessarily see, in that bar shown on this page, a big contribution because of the time period shown. It would largely come a bit after this.
Phil Gresh: Okay. So it is basically just Kearl we should be thinking about, and it is only a couple of years of Kearl.
Rich Kruger: Yeah. A couple of years of Kearl and some of the unconventionals that has a little bit different of a ramp-up profile than a major project, so you may get a little bit there. But, it would be predominantly Kearl in this period shown.
Phil Gresh: Okay. That is helpful. Thank you. Second question is, in the past couple of quarters in your cash from investing, the cash outflows from investing have exceeded your cash CAPEX numbers that you generally guide to. I think it is because of some of these Ontario cap and trade credits. I was just wondering, is that something that is specifically baked into these capital-spending numbers or is that something separate? Do you think about it differently? I am just wondering how to factor that in and generally how much you think those will be over the next couple of years?
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Rich Kruger: Phil, you are right in looking at the financial statements and seeing those differences. Largely, that is translated and captured in the market at market prices. It is the cost of doing business that goes in there. When you look at these CAPEX numbers, you do not see those in this kind of a CAPEX number.
Phil Gresh: Okay. But there will be outflows in your cash from investing that will continue as a result of the cap and trade, is that correct?
Rich Kruger: That is correct. As long as you are then able to capture those in the market, they will come back to you pretty timely.
Phil Gresh: Okay. Any amount you could give us for that on an annual basis?
Rich Kruger: It is at auctions and stuff, so it is not a number that we have typically projected externally. I do not really have anything for you there, Phil.
Phil Gresh: Okay. Last question would just be, you talked about the sensitivities for CFO generation and what you could cover. I just wanted to compare the priorities and the ability to do the buyback against where you are with the balance sheet. And what kind of level of leverage, whether it is maybe net debt to EBITDA, net debt to CFO, that you are comfortable with, in the event that the macro-environment were to get worse or something like that, how you manage that scenario.
Rich Kruger: We do not have a target. But, where we are with the gross or the net debt, we are quite comfortable with it. We have invested in a series of high-quality large long-life assets coast to coast, upstream, downstream. We need to be sure we take care of those assets. Largely, when I think of sustaining CAPEX, I largely think of it in that way of ensuring that we keep the productive capabilities, the quality, the safety, the integrity, the reliability, the asset base. I will talk about sustaining CAPEX in dividend in the same kind of sentence. Because our commitment to the dividend – they are reliable and growing and we have already gone through the history on it – that and sustaining CAPEX are why I always start with those two. If we are ever in an environment where we or others are stressed in ability to cover that, it usually says that it is something in the external environment that is going on that may then very well effect your incentives or desire to make growth investments. Attractive growth investments would be after those too and then would compete with the other alternatives.
We are not feeling pressured or the need for continued debt reduction, although, we have the ability to do that. I think when we talked about the buybacks, we looked at it in the aggregate of our priorities and we saw that we had cash in excess of near-term needs. That was a very efficient way to return that cash to shareholders. Hypothetically, if the business environment were to change or weaken, taking good care of our existing assets, our commitment to our reliable and growing dividend would be first and foremost on that. Then we would look at the attractiveness of growth opportunities and/or other uses of cash, i.e. buybacks and/or continued strengthening of the balance sheet as the next tier of priorities in it.
But I just comment that with what we have done – and we did not spend a lot of time today on cost reduction and the ongoing downstream predictability, reliability performance. Upstream, of course, has a big oil price swing to it. The flexibility we have in this page, the page titled ‘Financial Resilience.’ I showed a comparable page a year ago. It had some
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different numbers in it because of the time period. We, me and the Board, feel like we are in a good, strong position to be able to meet not only the priority needs but then other opportunities that may come our way.
Phil Gresh: Yeah, that is helpful. The question was more along the lines of what would be a scenario where you would want to pull back on the buybacks? How long would we have to be lower? Or if the Canadian exchange rate was worse than your assumptions, etc., would you be comfortable with the balance sheet maintaining the buybacks for a period of time?
Rich Kruger: When we started into the buybacks, we did not start into it with the idea that, ‘Well, we will do it a quarter and we will flip it on and off.’ That was not our intent. We obviously looked at the expected performance of the enterprise, we looked at a range of market conditions. It is not something that we proceed come hell or high water. But, we looked at it in a very diligent and prudent manner with the expectation that once started, this is something we would be able to continue for a period of time. If the world as we know it changed, well, then we would have to relook at it the same way we looked at it when we launched off on the large investment or the growth profile seven or eight years ago.
Phil Gresh: Okay. That is helpful. Thanks a lot.
Rich Kruger: Okay.
Operator: Thank you. Our next question come from Jason Frew with Credit Suisse. Your line is now open.
Jason Frew (Credit Suisse): Hi, Rich. Just wondering how you look at technology such as automation and digitization, whether that can be further incorporated into your business. More specifically, whether there is an opportunity on autonomous haul trucks at Kearl?
Rich Kruger: Yeah. No, we think there is significant potential in the technologies you referenced. What I would say is, this is another area, not surprising – we work on a lot of technical innovations with ExxonMobil. But, when you look at our business, I will use Cold Lake as an example, with 5,000 wells and the magnitude of that, when you look at Kearl with all the trucks and the information that you are gathering there, we think there is significant potential for these technologies to enhance our operations. We have not talked a lot about it because we have a lot of work going on. When we have something to say, we will obviously share it.
Then on the autonomous haul trucks, the oil sands on the mining side of it, if we want to be globally competitive long-term, we just have to continue to find ways to become more efficient, more reliable and drive down cost. We are looking at all aspects of cost. Autonomous haul trucks, we were working with some equipment suppliers. We are planning to conduct some further tests on it. We went and benchmarked, in other sectors, hard rock mining in other areas and we do see potential on this. It is not ready to yet say if for sure, or when. But, yes, we think it is an area that offers potential. For the long-term health and viability of mining, we and industry, we have to continue to come up with new innovations to drive down unit cost. Autonomous haul trucks are on the table. And I will tell you, there are a lot of other things on that table too, to be sure that we are as absolutely competitive long-term as we can be.
Jason Frew: Thanks.
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| 2017 Update Call |
Wednesday, 1st November 2017 |
Operator: Thank you. I am not showing any further questions at this time. I would like to turn the call back to Dave Hughes for closing remarks.
Dave Hughes: Okay. Thank you. This concludes the 2017 business update. I would like to thank everybody again for their participation. As I mentioned earlier, if anybody has any further questions, please do not hesitate to contact our Investor Relations team directly. Thank you.
Rich Kruger: Thank you for your time and interest today.
Operator: Ladies and gentlemen, thank you for participating in today’s business presentation update. This concludes today’s program. You may all disconnect.
[END OF TRANSCRIPT]
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