Imperial Oil Limited (IMO) Q2 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentleman. And welcome to the Imperial 2018 Midyear Update Conference Call. At this time, all participants are in a listen only mode. Later we will conduct a question-and-answer session and instructions will follow at that time [Operator Instructions]. I would now like to turn the conference over to Manager of Investor Relations, Dave Hughes. Sir, you may begin.

Good morning everybody. Thank you for joining us today on this midyear updates call. Just before we start, I would like to introduce you to the Imperial management committee who are in the room today. We have Rich Kruger, Chairman, President and CEO: Daniel Lyons, Chief Financial Officer: Theresa Redburn, Senior Vice President, Commercial and Corporate Development: and John Whelan, Senior Vice President of Upstream. I will start today by noting that today's comments may contain forward-looking information. Any forward-looking information is not a guarantee of future performance, and actual future financial and operating results could differ materially, depending on the number of factors and assumptions. Forward-looking information and the risk factors and assumptions are described in further detail on our second quarter earnings release that was issued earlier today, as well as our most recent form 10-K and these documents are available on SEDAR, EDGR and imperialoil.ca, and I would encourage you to refer to them. As the conclusion of Rich’s remarks, we’re going to begin the Q&A. We’re trying something a little different, maybe a little bit out of the ordinary and we provide the analyst the opportunity to submit questions in advance. We have a lot of questions submitted. So at the conclusion of Rich’s remarks, we’re going to go and address some of those questions first and then move to the more traditional live Q&A. And probably we’ll maybe bounce back and forth a little bit between the two. So, now without further ado, I will turn it over to Rich.

Good morning. What my objective or intent is this morning is to give you a bit more color, commentary and clarity on our second quarter results but in addition, to give you a bit of a sense of what we expect as we look forward over the rest of the year. You’ve seen the results, net income just shy of $200 million for the quarter, $0.24 a share; well below consensus, I'll talk about the factors or the drivers as to why that result. From a cash generating and from operating activities, we were a bit over some $800 million, significant increase over last year. If I look at the first half of the year, that $200 million in the second quarter is a bit of $700 million in earnings for the first half and our cash generated from operating activities is a bit over $1.8 billion. That is up about $1 billion year-on-year. If I step back broadly from an operating environment standpoint, we've seen over the course of the year, a significant growth in WTI. We've also seen that growth from the first quarter to the second quarter. Year-over-year, we’re up about $15 a barrel WTI and then the second quarter is about $5 a barrel higher than the first quarter. Similarly, we’ve seen increases in the heavies as measured by WCS in the -- to the point where the right oil prices that went up on the year about $15 a barrel but heavy oil prices, if I represent it by bitumen realizations have only risen by about $5 a barrel, market access, considerations constraints behind those differentials. On the downstream and chemical side of the business, both market conditions and margins have remained strong throughout the first half of the year and I'll comment more there on performance. The bottom line results of both the operating and the market conditions we’ve had strong cash generated in each of our upstream, downstream and chemical business lines. Continuing on, I’ll make a couple of comments on capital and expiration expenditures. In the first half of the year, we spent $558 million a run rate for the full year would point to something in the $1.1 billion, $1.2 billion range. However, in the second half, we expect higher spend than the first half. However, we think we’ll end the year at the low-end of our earlier guidance. Earlier guidance was about $1.5 billion to $1.7 billion on the year, we think it will be something on the lower end around or closer to that $1.5 billion. The drivers in the second half, why a bit higher spend, we continue to execute the Strathcona refinery cogeneration project. We’re continuing to invest in the Kearl, supplemental crusher and flow interconnect project. I will talk more Kearl here shortly. And then we are advancing at a measured pace our Aspen in situ oil sands project, while we still await the final regulatory approval. On dividend and share repurchases. We detailed in our release a fair bit about; both on a program timing basis and then within each of the quarters; but I'll step back broadly and from a capital allocation strategy what we seek to do is maintain a strong balance sheet; pay a reliable and growing dividend; invest in attractive growth opportunities, attractive to find that as globally competitive, I will comment more on that if we like Q&A; and then ultimately, return surplus cash to shareholders via buybacks. If you look at where we are at midyear balance sheet, we have about $5.2 billion in debt at midyear; debt-to-capital ratio of 18%, we’re quite comfortable with that strength. From a dividend, we declared a $0.03 per share increased earlier in the year; so we’re currently at $0.19 per share per quarter, or about $600 million at the current rate in aggregate; and you're well aware of our 100 plus years of consecutive payments and 23 years of consecutive year-on-year growth. Attractive projects, I’ve commented on those where we’re spending money on projects that we believe are attractive globally competitive; Strathcona cogen and Kearl supplemental crusher and potentially Aspen in situ projects. And lastly, relative to that capital allocation, over the last year in the 12 month program that ended here a few days ago -- a month ago in June, we bought back about $1.6 billion over that 12 month period. Production, upstream production, 336,000 barrels a day in the quarter characterized by a lot of maintenance activity. I will talk specifically each of our core assets and that activity here in a moment. If you look at the first half, we’re at about 353,000 barrels gross oil equivalent barrels a builder date, essentially flat with where we were a year ago. This is bit below where we had expected to be, at the end of the first half is really largely due to Syncrude performance and to a little bit lesser extent Cold Lake, and I'll talk about both of those. With the majority of our scheduled maintenance complete for the year and Syncrude recovery from its recent power outage ongoing, we are positioned for what we expect to be very strong volumes performance in the second half of the year. Going specifically to the asset, I’ll start with Colace. We completed a large turnout at our Maskwa facility; 38 days were split between May and June; work included required regulatory inspections on our steam, flare and fuel gas systems, and then periodic steam and water system cleaning and repairs, quite typical of maintenance turnarounds at steam injection facilities. Cold lake, for context, we have essentially five separate steam plants that require periodic maintenance of this sort. We have worked very well over time on equipment strategies, maintenance practices. And these improvements have allowed us to extend each plant’s major turnarounds cycle to roughly a six year interval. So on average, we’ll have about one turnaround a year. Now those plants vary in size. Maskwa was the second-largest of Cold Lake plants. And then on the odd, on the sixth year, we’ll go a year without it. Post turnaround, Cold Lake’s average has increased to about 150,000 barrels a day. We expect continued ramp-up in the second year and expect that we’ll be at or approaching 160,000 barrels a day by the end of this year. Kearl, gross production in the quarter averaged 180,000 barrels a day that followed on 182,000 barrel a day first quarter, leaving us at 181,000 gross. These are gross numbers our share of course is 71%. In the second quarter, we had a 32 day maintenance turnaround at one of the facilities’ two plants. And this included a number of vessel inspections and continued enhancements to reliability with both piping and/or prep equipment. Throughout the rest of the year, we have one more turnaround at the second plant. We think it’s going to be a bit shorter, 20 to 25 days. We’re finalizing the details right now. That’s scheduled to start in mid-September and then overlap into October. Let’s talk about the second half. We have, in the last four weeks since the start of third quarter we've achieved several best evers at Kearl. We’ve had the highest week ever at 297,000 barrels a day. We’ve had the highest day ever at 340,000 barrels a day. We’ve had the highest days ever at each of the two facilities at essentially -- at or above 170,000 barrels a day each. And we’ve had seven of the 10 days highest days since start up. The daily rate for June as of 6 AM this morning was about 255,000 barrels a day gross. And with June's performance alone in 3.5 weeks, we've taken the annual average at Kearl from the 181 through the first half to as of 6 AM this morning we were at 190,000 barrels a day for essentially the first seven months of the year. These performance and these expectations, which were in our plan, both the maintenance, the reliability enhancements, we knew our first half of the year would be lower than the second half. But it’s this performance that we’re seeing now and expect to continue that gives us confidence in averaging 200,000 barrels a day for the full year. Longer-term, in addition, we have the construction of our supplemental crushing capacity at each of the two plants ongoing, as well as the flow interconnections further downstream that will give us flexibility for directing fluid flows to maximize reliability and equipment utilization. Our objective is that when these projects are complete by the end of next year that we’ll achieve an annual average production of 240,000 barrels a day starting in 2020. The cost, timing and plans with this work are unchanged from any of our earlier conversations our commitments on Kearl. Going to Syncrude, we averaged our share of 50,000 barrels a day. In the quarter, it was up a bit from the disappointing quarter of last year and this quarter was disappointing. Although, the biggest deviation in the quarter versus expectation -- versus capacity was the 25,000 barrels a day impact our share associated with planned turnaround activities. Specifically, a 71 day turnaround occurred on Coker 8-3, fully during -- they essentially started at the end the first quarter and wrapped up in the second quarter. But the other event in the quarter was the major power outage that occurred on June 20th. Specifically, a high-voltage transformer failed, backup systems also then failed to respond. It resulted in a hard shutdown of the full facility, caused some damage to steam systems and fouled select processing units. A complete investigation by Suncor with Imperial, Exxon Mobil and Suncor support is ongoing. We have resumed production from Coker 83. It's now roughly 140,000 barrel a day capacity. Coker 8-2 is going through its restart procedures, and we anticipate full rates will be achieved sometime in September following the decoking of unit 8-1, an activity that was originally planned for next year. In the downstream refinery throughput averaged 363,000 barrels a day, up a bp from the second quarter of last year. The biggest news in the quarter is we completed a 72 day schedule turnaround at our Strathcona refinery and this was the largest such event in the refinery's history. The work included major maintenance on the fluid cat cracker or the FCC and this is the gasoline engine or machine in the facility. And for reference, the FCC fundamentally converts heavier molecules into lighter gasoline and distillate products. And as a rough rule of thumb, about 70% of Strathcona's gasoline is derived from the FCC. This is a moneymaking unit. Consequently, the earnings impact of the event in the quarter relative to the first quarter was about $250 million. That's based on the incremental OPEC and the volume and margin impact of the overall event, $250 million equates to roughly $0.31 earnings per share in the quarter. Very fortunately, the FCC only goes through maintenance of this magnitude about once every 10 years or so, so it will be a long time before we talk about an impact such as this, again. More broadly, we continue to improve our overall competitiveness in the downstream by optimizing feedstock and taking advantage of discounted heavy crudes. Statistics for you over the last four years about 17% of our refining feedstock or roughly 64,000, 65,000 barrels a day on average were heavy crude were primarily a light crude refiner. However, through the first half of ‘18, we've increased our heavy crudes to a full 25% of our feedstocks, approaching nearly 100,000 barrel a day average in the first half. We’ve achieved this through our utilization of our coker at Sarnia through our asphalt plants at both Strathcona and Nanticoke, and increasing heavy crudes in our overall raw material mix. Actions like this are what are continuing to strengthen overall downstream performance. On petroleum product sales, we sold 510,000 barrels a day in the quarter, up from 46 a year ago. The last time we had quarterly sales at 510 or above was 1990, immediately after our Canada, Texaco acquisition. We achieved this result despite the Strathcona turnaround by leveraging our own refinery network, building pre-turnaround product inventories and securing third-party product purchases in advance and as a result, we were able to reliably supply our customers throughout the entire period. Fundamentally, if you step back our strategy in the fuel side is to profitably grow via branded sales, longer-term strategic partnerships and superior product offerings. And as a statement of fact, if you include our aviation sales in our overall branded business, three out of every four barrels that we sell are sold under the Esso our Mobil brands, and we derive added value through branded sales. Earlier this year, we announced that Esso and Mobil our branded network exceeded 2,000 sites nationwide. Since we shared that, the brand count has now grown by 150 to 2,150 sites nationwide, largely driven by the introduction of the Mobil brand in Canada and the conversion of existing Loblaws retail fuel sites. Quickly on the chemicals business; we matched our best ever quarterly chemical earnings of $78 million; the second quarter performance matched the previous quarterly high of $78 million achieved in the third quarter of 2015; and for the first half of the year, earnings of $151 million are a record first half; polyethylene leads the way for us; it's about 40% of our sales, but more than 70% of our chemical earnings; fundamentals to our chemical performance, our feedstocks largely Sarnia refinery off-gas and Marcellus ethane that provide us sustainable cost advantage feedstocks, supporting the overall profitability of the chemicals business. So just in wrap up, before we go to your questions, the second quarter can be characterized by a uniquely heavy planned maintenance schedule to safely and reliably operate our facilities over time. And with this work successfully completed in both the upstream and the downstream, we’re positioned for what we expect to be a strong second half of the year performance. With that, I am going to turn it back to Dave, and Dave will get us kicked off in the process for addressing your questions.

Okay. So as I mentioned at the outset, we’re trying something a little differently with the new technology. We do have a number of questions that were pre-submitted by the analysts. We’re going to go through two or three right now and then move over to a live Q&A, and then probably come back to some of the pre-submitted questions as we move through. So the first question comes from Mike Dunn from GMP First Energy. Regarding our spin, can you provide any more color on what's holding up regulatory approval? If the current price environment holds, if you receive the Aspen approval tomorrow, do you think you would fully utilize your current 5% NCIB?

And just for that are not familiar, Aspen, we’ve submitted the regulatory approval for two phases 75,000 barrels a day of bitumen per phase on a solvent assisted SAGD project, a project with this technology that would result in about 25% improvement in capital efficiency and 25% improvement in greenhouse gas reductions versus industry SAGD, so economic and environmental benefits. We anticipate it would be about $2.5 billion to $2.6 billion investment. And we’ve said all along that our investments need to be globally competitive. And we would define that as delivering 10% return in $48 barrel of WTI world and we believe Aspen will meet that criteria. We initially submitted our first application back in December of 2013. We amended it or updated it in October of 2015, to the SA-SAGD. We have responded to three rounds of supplemental questioning. Our environmental impact assessment was deemed complete by the Alberta energy regulator in April of 2016. And we have engaged for 4.5 years extensively with stakeholders and indigenous groups on this project in all regards. There were delays in determining the adequacy of the consultation that has now occurred. And what we’re waiting on is the decision from the AER regarding closure of any further statements of concern and ultimately, the decision that the project is in its public best interest. I will tell you, I'm quite disappointed in the timeline on this. I think this is extremely attractive project, both economically and environmentally. And it should be the type of project that we should, as a province as an industry, we should be striving to pursue asap, inordinately long timelines and uncertainty are quite disappointing. Now that said, if we get the approval, we will look and see what if any conditions come with it to make a final investment decision. And as it relates to any impact on our NCIB, when we expanded NCIB program here recently, we had Aspen clearly in the view screen then. So our thought is, just like my comments back on the capital allocation strategy that we will have both the capacity to pursue an Aspen, as well as pursue a continued NCIB program at or near the level here that we have applied for.

The next question came from Justin Bouchard at Dejardins. Are there any specific details, examples you can share that can help us understand your confidence that Syncrude is on the right path?

There is no question about it as we look back overtime that Syncrude’s performance has been disappointing. And it’s an asset that has tremendous potential to generate cash, but the issue is the reliability. And yet again, we hear with the power outage, we had yet another event. If we look at the steps we are doing both as under the management services agreement that Imperial and Exxon Mobil have had with venture and now with the expanded ownership and support of Suncor in it. As the owner step back on the table, we look at and we continue to believe all the things we're doing to enhance ultimate reliability of this facility remain the right things, equipment strategies, maintenance procedures, operator training on and on. We need to eliminate the so-called one-offs that occur. So the frustration is there with the overall performance, but the confidence and clarity in the steps we are taking remains high. And the belief that we are on -- that we continue to be on the right path. It’s difficult to make promises and commitments and then continually disappoint on them, that we do think something on the order of 90% reliability, which would lead to something in our share of 75,000 to 80,000 barrels a day is the ultimate target, the objective that we will achieve at Syncrude overtime.

Next question from Jennifer Rowland at Edward Jones. How is the new solvent based recovery technology impacting Cold Lake’s volumes?

Specifically, right now -- Cold Lake has always been identified as a cyclic steam operation. But in actual operation, Cold Lake is a bit of a patchwork, it has cyclic steam, we have a large part of the field under steam put. And we’ve used and continue to use it to test and pilot new technologies, solvent based technologies. The project that we’re expanding or the application we’re expanding, we call laser. It’s a liquid addition to steam to enhance recovery. It’s a high-pressure process that put a mixture, 5%, 6%, 7% of solvent in the steam. You injected it and you let it soak like you did cyclic steam and then you turn around and produce it back. We had -- last year, we communicated that this was a part of our plan. We’ve had some delays in starting it up. We completed some casing integrity work, some of the steam strategy use in the other area. So we’re a bit behind, probably on the order of current rate, somewhere about 5,000 to 6,000 barrels a day behind where we have thought late last year we would be, that is timing. The confidence in the technology and the confidence in the economic remains high, and that's part of the ramp-up will see at the second half of the year as now that as laser as we implemented it and it kicks in a production performance, we’ll see that growth continue in the second half of ’18 and that on into ’19. And it is a technology that we are looking at and we anticipate further expanding in its application at Cold Lake as the field continues to transform from a pure cyclic steam operation to other enhanced forms of recovery. Okay. Operator, I think we’re going to turn over the phone line now for the next couple of questions.

Thank you [Operator Instructions]. And our first question comes from Dennis Fong from Canaccord Genuity. Your line is now open.

So the first question that I just have is around Kearl. So I really appreciate the color as to some of the operating conditions and level that you guys are currently at right now. I think just out of curiosity in terms of -- I think it’s more like a consistency situation in terms of being operate at such a high level for an extended period of time. What additional level of confidence you guys have or the interim, call it, the next six to 12 months versus after you complete the redundancies that you’re employing at Kearl, in terms of being able to achieve a stronger rate of production? And then secondarily, how much further from the -- about 240,000 barrel a day capacity that you guys are indicating, you think you may be able to achieve with some form of consistent operation?

If I start at the back end of that question and come back. When we have the supplemental crushing capacity in the flow interconnect, it will give us a lot of operational flexibility for crushers instead of two crushers that each one of them, or any one of them at a point in time, can provide essentially half or 150,000 barrel of day of ore feed. So when we have that work completed, the confidence and the reliability, I would say, would be quite high. In the meantime, what it takes is with the two crushers, we still have a bit of that vulnerability to any downtime on any one of the two. So the regular maintenance, the ongoing inspections we do, we’ve done -- we took a number of steps last year to lessen the load on the crushers, to enhance bearing life, change strength and life. So we’ve a number of things that we think have made a material difference to bump up the current reliability. But there’s no question that we’ll have -- continue to have a bit more vulnerability until the supplemental crusher is in place. That said that eyes wide open awareness has been factored into our expectation of achieving 200,000 barrels a day gross this year and next year. And then bump up to 240 beyond that. At personal level, when we have that work in place, we will be testing it certainly to see is there any magic about the 240, or can we do better than that. But I think that will be a conversation on the day once we’ve completed the work in progress.

And then just secondarily on egress and your current exposure to rail. I was hoping to find out a little bit more about, it seems like a number of your peers are looking at potentially ramping up production to some degree and how you guys are managing around, we’ll call it, potential tightness in egress out of Western Canada?

If you step back fundamentally strategy, we seek to -- first and foremost, we seek to take and put as much heavy oil into our own refineries as we can. And there’s a bit of our left pocket right pocket, a natural hedge within that. And I talked about -- I made comments on the refining, how we significantly increase the heavy feeds to about 25% or roughly 100,000 barrels a day of deal bit heavy crude into our refineries. That’s priority one. Secondly, we strive to get as many barrels to the Texas, Louisiana Gulf Coast via contract pipe commitments as possibly can. It’s the highest value market. It’s the largest concentration of heavy oil processing facilities in the world. And from feedstock reliability with declines in places like Venezuela and things, that continues to be the market that offers the highest value, so that’s priority two. Priority three then would be to use rail capacity to fundamentally achieve the same thing, to get barrels to the highest value markets, which back to the Baton Rouge, Louisiana, Belmont, Texas, the Gulf Coast. We decided in 2013 to build a rail terminal, a joint venture 50-50 with Kinder Morgan adjacent to our Strathcona refinery. At the time, we said it would be a bit of an insurance policy if market access, i. e. new pipelines didn't come about in immediate timeframe. We like any insurance policy, our intent -- our hope was that we didn’t have to use it too much. While over time, we have used it. We’ve increased volumes at it. Earlier in the year, we were in the 50,000 to 60,000 barrels a day capacity -- are using 50,000 to 60,000 barrels a day of the capacity. We’ve ramped that up to closer to about 100,000 barrels a day of its capacity now. And I look to the second half of the year I expect that we’ll be using more of it, mostly targeting something in the 125,000 barrels a day of the roughly 210,000 barrel a day capacity in the facility. And here again, it’s allowing us to cost-effectively through the use of unit trains and our existing ownership in this facility compete on a net debt basis with pipe alternatives to get to markets -- again, primarily Texas, Louisiana, and Gulf Coast and get the highest realization for our production. Last but not least, our volumes that go into the mainline system, which would largely be exposed to ahead of pipe differential or discount. And the bulk of that will go -- if it doesn’t go to our own refineries, it will go into the U.S. Midwest, places like Joliet and widening things like this to large refineries in that area. So we continue to reduce our overall exposure to differentials through our own refineries, contract pipe to the Gulf Coast and continued to expanded use of rail.

Our next question comes from Travis Wood from National Bank of Canada. Your line is now open.

You touched on in the release this morning, you touched on autonomous haul vehicles and the success that you're having, at least, early on here. Could you walk us through how you guys are thinking through the short, mid, long-term plans around rolling that out in a larger scale? And then what that could mean on cost savings, both on an absolute cost per barrel or just even more of a higher-level efficiency conversation?

I think if step back before I dive into the question, for all of our operations it’s all about achieving the lowest long-term reliable cost of supply to enhance or maintain our competitors in good times and in bad. And Kearl was no different than that. On the mining side, the economy of scale is key to it, hence the supplemental crushing capacity, et cetera. But then it’s looking at what other opportunities do we have in our business to continue improve performance. We do think autonomous trucks offers significant potential. And for example, we commented in the release about the current pilot and the expansion of that pilot. These are existing trucks that are in our service to-date that we’ve retrofitted with the equipment, the sensors and the controls that are required for autonomous operation. So ramping it up here to the seven trucks by the end of the year, we’ll be to -- just continue to see how this pilot, how you have more and more trucks that are autonomous, how you can direct their movements and their ultimate performance relative to a driver fleet. Very key to this is our workforce where we have worked very closely to ensure people don’t view this as a threat, a threat to jobs. And so that they are embracing and helping support this, there’s ultimate success. Now in terms of what kind of value might it provide? If we just do straight up math and think about autonomous trucks, the incremental cost to make them autonomous, the money you might save on having fewer drivers as our truck fleet would grow in the future, you can come up with something in the $0.50, $0.60 a barrel. That doesn't include necessarily productivity improvements, which we believe there are. So we don’t have absolute number yet but something -- and I saw there was a question asked on the expectations, can it be on the $1 a barrel range. I don’t see any reason why it could not be in that type of range. And so continuing to expand this pilot, we’ll see where it goes. But I would say, we are optimistic and have a level of confidence that a form of autonomous operation in the future will be an economic enhancement to the operation.

And then just an extension on this. If along the supply and value chain through the integrated business, are there any technologies that you’re thinking about today, whether it's autonomous vehicles or something else where we could see some step function where the sustaining capital, continue to be trying to down or overhead lower. What other types of disruptions can we see, or some improvements on the technology side as we look out?

You're well aware, our commitment to fundamental science, technology and innovation, we would hold that up to anyone in terms of --. We spent about $150 million to $200 million a year in good times and bad on this, because of the type of assets and the long life nature of our assets. We can do that and it pays out over the long-term. I think the areas I am most excited about now, we talked a little bit about Cold Lake, our solvent-based technology, because for a given amount of steam, you can get material production uplift and an incremental resource recovery over time. That's largely been the story of Cold Lake over its 33 years commercial life is applying new technologies, operational innovations, continued enhanced recovery. I think solvent-based technologies will give a bit of a step function improvement. And it will do that consistent with the societal aspirations of lower greenhouse gas emissions and performance. So I think that the key. Another area, we haven't talked a lot about this yet, is the overall digital aspect of things. We think there are several hundred million dollars of potential that we are scoping now in process optimization to places like Kearl again at steamflood optimization at Cold Lake. And with 5,000 wells at Cold Lake and the complexity and size of the operation at Kearl, small things can make big differences. And so I’m really -- I'm focused on the upstream right now. But I think a lot of the same things -- the digital enhancements can apply in the downstream as well. You call those breakthrough step function. I think largely they can have big, big material impacts to our competitors and we are aggressively pursuing those types of things.

And our next question comes from Greg Pardy from RBC Capital Markets. Your line is now open.

Rich, just a couple of quick one for you, you may want to not give precise numbers on the first question, which is really just trying to get a sense as to where is the OpEx running at Kearl. And maybe, where do you expect it to go as you go through the year and your volumes ramp up?

Greg, I think our earlier conversations and guidance on Kearl remains the same. The first half of the year, we’re in the mid-20s or so U.S. dollar basis, but that is because of the volume performance at the 180. And the major turnaround -- we spent a fair bit of money on the turnaround itself. And as you and I have talked before, the incremental barrel mining operation comes at a fraction of the cost, 25% to 30% of the cost of the full barrel. So as we increase volumes in the second half of the year, we expect that to drop down. And then in particular as the supplemental crushers comes on at the end of the ’19 and into ’20 that we get to the 240. That’s when we will start to see that $20 a barrel or below cost. You always have competing offsets as we mine further distances out, and the haul distances, and needs for truck increase. But that’s where things like the autonomous truck or other opportunities we’re pursuing are aimed at, at more than offsetting any natural increase you might have just by the nature of your operation. So I think, Greg, fundamentally guidance and conversations we’ve had on Kearl and costs really remain unchanged. There's not anything -- if anything I think with digital and some of these other things, I probably would see more opportunities to further drive down unit cost now than we might have been talking about a year or two years ago.

And I know there has been some questions asked around Syncrude. I mean I am not speaking out of school here when I say on Suncor’s call yesterday, they did talk about the necessity, I think, for perhaps just more cohesion amongst the owners in terms of accelerating that reliability game plan. But in your view, is everybody on the same page at Syncrude? Or is it a situation where actually fewer owners would be better?

I didn’t hear there was a lot of interest there, quite a few questions on that yesterday during their call. What I would say is we are all about anything that can add or enhance value to any asset we own, and Syncrude clearly fits in that. With a fewer number of owners in the recent past few years, we focus on like a laser on further dismantling the corporate structure of Syncrude and making it more and more on operating organization through the economies of scale and synergies of support services, whether that's IT, procurement, et cetera. For example, each and every day right now, there are 120 Imperial and Exxon Mobil people that are assigned to and working on Syncrude from a seconded standpoint, management, technical, IT, procurement, financial services. And we this lowers the overall cost of Syncrude. In recent months/years with Suncor, the operating efficiencies looking at logistics and warehousing, because they’re adjacent operations, have been high priorities. Now we’re looking at things about are there commercial arrangements that can be constructed that can help on both sides of the fence on that. And I think like all commercial arrangements, they need to make sense for all parties in the deal. And we are working on and believe there are commercial enhancements that can be achieved here at Syncrude and there’s no reason. Well, say go back to where I started, if it can enhance value at Syncrude, we are 100% behind it and that hasn’t and doesn’t change with the ownership.

Thank you. And our next question comes from Mike Dunn from GMP First Energy. Your line is open.

Rich, I wanted to ask about the interlinking of your Strathcona refinery profitability to Syncrude, given that light synthetic is a big part of the feedstocks there. And maybe could you frame for us how unexpected -- if you have unexpected downtime at Syncrude. Can you provide some numbers around how that impacts your Strathcona profitability? I mean, obviously, we would see probably spikes in the price of, let’s say, a benchmark synthetic crude if there’s unplanned outages at Syncrude or Suncor, or Horizon, for example. But just wondering if you could frame for that, how much maybe that's impacted your downstream or your Strathcona profitability over the last several years relative to Syncrude was running at 90%.

Mike, you’re correct in connecting the importance of Syncrude to Strathcona. It’s a feedstock that is right up Strathcona Valley in terms of what it needs. And at our share, when it’s up and running at roughly 70,000 barrels a day or so, essentially all those barrels do go to Strathcona. And that can be a third of the refineries’ feedstock. So when Syncrude has unexpected unplanned upsets, it’s important -- it has an impact on Strathcona. Now, when we have planned events, we’re able to work ahead of time, get alternate supplies and things. But when Syncrude has that unplanned event, the supply folks for Strathcona do need to scramble. And unfortunately, they’ve had to scramble more than they -- over the last few years, more than they would have liked. Similar things we’re doing. We are testing and looking at alternate crudes, whether they’d be synthetics or other light. We’re looking at does it makes sense to direct every barrel of Syncrude there every day or should we have a plan that maybe takes a part of it, directs it to Strathcona, secure supply agreements with other synthetics and then use the remainder of Syncrude a little bit as a swing, because the vulnerability, the exposure to Strathcona -- and Strathcona is a very high performing facility. The Syncrude events are more troubling than Syncrude because of their impact on Strathcona. On a numbers standpoint, you can do math on it. I don’t have explicit numbers necessarily to share. But when we find alternate supply, it can be in the millions of dollars over a course of a quarter on the upset it’s not gigantic. The impact of the loss at Syncrude as the upstream and the Syncrude alone is bigger. But it does affect the ability to run that refinery at the highest level of reliability without disruptions. And we keep looking at what we can do to not only benefit from the synthetic crudes that it likes but maybe lessen the absolute reliance on it on a day-to-day basis.

Rich, we’re going to go to some more of the pre-submitted questions now. So I've got one here from Jason Frew of Credit Suisse. I'm interested in the relative attractiveness of the upstream versus downstream investment in the current and projected environment. Do you see more balanced investment going forward? Or does upstream still dominate the opportunity set?

Jason I think it’s -- our view of course is it’s less of an upstream or downstream. It’s where do we see the greatest value. In the upstream, we tend to talk about big bites, an Aspen like projects, maybe programmatic drilling at Cold Lake things like this. Whereas the downstream, it tends to be generally smaller incremental investments, cogen at Strathcona, terminals, logistics in the Greater Toronto area, things that either strengthen the competitive position we have or work to further enhance it. And I would say and you’ve seen this over the last five years or so, when you look at our downstream performance and the cash generated there. The integration and balance we have there is strong financial performer that we want to continue to strengthen. I’ve talked about efforts to expand our branded network, some of the relationships, the long-term strategic partnerships we have, whether that's with aviation service providers, whether that's what rail. We have recently now are supplying aviation fuel into the Vancouver airport that we haven’t been able to do. We, on an asphalt standpoint, we figured out how to run our facilities year-around even in winter and store asphalt for sales and use in the warmer weather months. So there are opportunities in the downstream. On an absolute dollar basis, they may not compete year-in year-out with where some of the upstream growth is. But we are certainly looking at and pursuing opportunities to strengthen our performance, our cash gen in the downstream. And it’s like the old saying you need to spend money to make money. And increasingly, we are doing that with and around many of our downstream assets. I don't see -- for example, you didn’t ask it this way. But if you said, a big new refinery or something like that that’s certainly less likely you look at we’re -- relatively North America, relatively flat to declining petroleum product demand market. There are surplus capacities in some areas. So it wouldn’t be necessary in that an investment but really investments to further add on or strengthen what we have. So one exception could be the chemicals business, we’re looking at -- we continue to look at both our Sarnia facility, as well as opportunities in the west that can take advantage of cost or price advanced feedstocks. We’re bit earlier in that. I would say that’s been area that over time we may talk more about as we look at the overall business environment and the relative attractiveness. But it’s not an upstream versus downstream one or the other, it’s where do we think we have the highest value opportunities in whatever business line they happen to be in.

We have a question from Benny Wong, Morgan Stanley. Can you give us an update on the five year CapEx plan you provided in your business update in November. How is your outlook evolved since and where the main levers to pull if there’re changes?

I think, Benny, we haven’t announced this year, I guess I’m announcing it right now. We’re going to have an Investor Day in late October, or early November. We’re landing on the date right now. We’ll go through and give some pretty comprehensive updates on all these. But if I sit here today relative to the capital plan that we outlined in last November, I think the component parts are still quite similar. We’ve talked about Kreal. We’ve talked about Strathcona. We had some moderate growth opportunities in there, including Aspen in that outlook. So I think, notionally, it will be similar to what we’ve talked about, but we’re going through our planning process as we do every year right now. We will update and dust all that off, and we’ll put both sources and uses of funds as we see them out there in front of the investment community here later this year.

And question from Matt Murphy, Tudor Pickering Holt. How’s the mainline portion affected out of our most ability to move barrels on committed pipeline space?

I think it gets back to some of the market access comments that I had earlier when we look at our priorities, getting heavier crudes in our own refineries, using contract pipe capacity to get to the Gulf Coast rail. And we move a lot of volumes on the mainline. We had some limitations on market access. In the first quarter, I think we talked about 12,000 barrels a day impact. In the second quarter, we really haven’t. It is tight. But because of our integrated nature, our refineries and the way the nomination system works with both confidence and the production we can provide to the pipe and in the purchasers or the refineries’ commitments to run the pipe, we have advantage in that mainline system because of the integrated and balanced nature of it. And so it’s tight, I will sleep better when there are new pipes in the ground and expanded market access. And so it’s a month-to-month challenge that keeps our production folks and our supply folks on their toes to ensure we have coinsurance for our equity production and to ensure we get the most cost advantaged feedstocks to our refineries.

We’re going to go to couple of questions on the phone again.

Thank you. We have a question from Neil Mehta from Goldman Sachs. Your line is now open.

This is Emily on behalf of Neil. I was just interested in seeing how Imperial was positioned in an IMO 2020 world. Are there any projects that the Company is taking out that could help position it better?

Emily, I think first of all, let’s take compliance out of the equation, there’s a lot of discussion and debate about what the level of compliance will be. But from a planning standpoint, we’re starting with, okay, the industry complies. We think, and when this topic first came up a while back, we sought and were a bit concerned about -- from the threat standpoint, what might this mean, but overtime as we’ve continued to analyze it, understand and look at our opportunities, we feel less threatened by it. We do have a level of heavy crude conversion capacity that gives us advantage or access to the WCS linked crudes and the ability to create differentiated high-value marine fuel offers. If you look at our distillates, which we think will benefit in a post IMO 2020 world. We had about 180,000 barrels a day round numbers of distillate sales, our heavy sales are less than 5%. So these are things that we’re looking at, we’re working on how can we operate in that world. But I would say it's not a topic that gives us a great deal of anxiety in terms of what impact it may have on the Company. Now, if you talked about what it might do more broadly to heavy crude prices. Here again, we’ve got the refinery network that works to give us a bit of an offset and a hedge. And you’ve got that massive complex that I’ve mentioned a couple of times now in the Texas, Louisiana, and Gulf Coast, that has all the facilities to maximize value from heavy crudes and our ability to get our crudes there, and will remain a priority. And we expect that that will continue to be -- there’ll be a strong high demand for those heavy crudes.

And I’ve got a second question, just on the chemical segment. Chemicals performed really well for Imperial this quarter. Just wondering what you guys can comment on with respect to margins, particularly as you’re seeing crushers come online in the Gulf Coast?

I think there’s a couple of things. We have, over the last two years, we’ve taken a number of steps to continue to reduce our feedstock costs; I mentioned Marcellus ethane; of course, all the Sarnia off gas. So that keeps our costs quite low. And where we make the bulk of our money is in the polyethylene, particularly the rotation and injection molding. I think I forget the exact number. But the majority of our customers are within a day's drive for our polyethylene; so when you start looking at -- we've got a feed stock cost advantage and then a location advantage relative to our customers. So as you look at other facilities that would strive to compete in those markets, they may have scale and they may or may not have the feedstock situation but they have a greater logistical cost to get into those markets. So our strategy here, as we put in a new furnace over the last couple of years; it gave us a more cost effective operation; it gave us an incremental 7% to 8% increased crude capacity; is take what is a strong, not a niche business, I don't mean to minimize it that way; but it’s not massive in its size or scale but continue to do all the things to keep it fit in shape and profitable that we’re able to weather any competition wherever it may come from.

Our next question comes from Phil Skolnick from Eight Capital. Your line is now open.

You had mentioned that, because you all need the railcars in the facility that you have competitiveness relative to pipe down the U.S. Gulf coast. Can you help us just to quantify the individual pieces, how competitive it is to the pipe economics?

And a lot's been written on there, so I'll give you -- I’ll reference some of the industry numbers but also ours. And Phil, these are round numbers. But generally, if we look at moving a barrel on contract pipe from Alberta to the Gulf Coast and these are out there and you can see it, but if you talk in plus or minus $8 a barrel or thereabouts. On the rail terminal, our variable cost on rail is something a couple of dollars a barrel, perhaps higher than that, $9 or $10 a barrel. Of course we’ve got the fixed -- the investment in the terminal things. We look at it and from earnings you’ll certainly see the full or fixed cost, which for us is in the $15 a barrel range. You’ve seen industry talking about 17 to 20 full costs -- whether that’s a unit train or manifest rail. We’re a bit lower than that, because the ownership of the facility. And then when it comes time to literally optimize week-to-week, month-of-month, yes, we look at that full cost. But the optimization can come on that variable cost. And so our traders are looking at with that contract pipe, with the head of market -- head of price in Edmonton, where do we get the highest netback the highest value. And as I said earlier that continuing to increase volumes via rail is providing, and we think for the foreseeable future, will continue to provide a higher value than a head of pipe sale in Edmonton or Hardisty.

And just a follow up on the rail side, you mentioned you’re going to get to 125,000 in second half of the 210,000. Is that going to be third party, is that your own volumes? And also -- so what gives you confidence on 125,000 in second half? And then are you going to look at all the new third-party rail to get to the full 210,000, or would you just continue to maybe do more of your own internal volumes?

I think, from our standpoint, our owned -- the terminal we own 50% of, our view is again for the foreseeable future that will meet our needs as we continue to ramp up and optimize the overall disposition of our crude. The determinant on the rate of increase in the capacity and utilization has largely been on the rail service providers, getting necessary power, locomotives and trained people on it. So it’s probably at a bit slower than we would have hoped over the course of this year, but that's something that we keep working. We’ve entered into arrangements where -- and that supports the growth that I've commented from the 50,000, 60,000 barrel a day utilization early in the year to the more 80,000, 90,000, or 100,000 of late and then growing to the 125,000ish range over the course of the year. So I think our terminal will meet our needs. And we’ll continue to look at if it is attractive to expand that utilization, either for our own needs or third-party needs and take advantage of it as not just a market access mechanism, but its ability to make money by providing service to others.

So I think that brings us to the end. So Rich, I turn it to you for any summary remarks.

First of all, I’d like to thank you for your time and your questions today. I do appreciate Dave and your use of this technology to allow some questions ahead of time, so we can see where do folks’ interests are. I hope you feel you have a better explanation, not only of the second quarter results but also our outlook for the rest of the year. And our commitment continues to be to provide greater clarity, transparency on our performance and our results, and we will look at how we do this going forward. But as I mentioned, we will have a full fledged Investor Day around the time of our third quarter release. We’re locking it down now but I look forward to your continued engagement as the year goes on. So thank you for your time and attention today and I hope you found this of value.

Okay, I just like to repeat my thanks for everybody joining us this morning. I recognize we didn't get to all of the pre-submitted questions, but we did make an effort to try to cover a wide range of topics. So as always, please don't hesitate to reach out to Jeff or myself if you have any further questions. I think everybody has our contact information. If not, it is our on Imperial Web site under the Investors’ tab. Thank you very much everybody. Have a safe weekend.

Ladies and gentleman, thank you for participating in today’s conference. This does conclude today’s program. You may all disconnect. Everyone, have a great day.