Imperial Oil Limited (IMO) Q4 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to Imperial's Fourth Quarter 2018 Earnings 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 introduce your host for today's conference, Mr. Dave Hughes, Vice President, Investor Relations. Sir, you may begin.

Good morning, everybody. Thanks for joining us. Just before we get started I'd like to introduce who we have here in the room. We've got Rich Kruger, Chairman, President and CEO; John Whelan, Senior Vice President of the Upstream; Dan Lyons, Senior Vice President of Finance and Administration; and Theresa Redburn, Senior Vice President of Commercial and Corporate Development. I'm also going to start 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 a number of factors and assumptions. Forward-looking information and the risk factors and assumptions are described in further detail in our fourth quarter earnings release that was issued earlier this morning, as well as our most recent Form 10-K, and these documents are available on SEDAR, EDGAR and at our website. So I encourage you to refer to them. Rich is going to start making about 20 minutes of remarks or so, and then we'll turn it over to Q&A. And as we've done before, we did offer the opportunity to folks to submit questions ahead of time. We did get a couple of questions. So we'll probably go through those first and then switch over to the live Q&A. So, with that, I'll turn it over to Rich.

Good morning. Before I detail the fourth quarter and the full year Imperial results, I'd like to offer a few comments on the overall business environment. Stepping back, if you look year-over-year, we saw WTI increase by about $14 a barrel. It was $51 a barrel, round numbers, in 2017. It was about $65 a barrel in 2018. WCS or Canadian heavy on the other hand was flat in both years, at $39 a barrel. So set differently, the differential increase to the full extent of the WTI growth, a really sovereign phenomenon for Canadian heavy oil producers who haven't enjoyed that, what you've seen in terms of the global price growth. I'll come back to us here in a moment. Now more specifically to the fourth quarter, I would characterize it by even higher price volatility with the largest WCS/WTI differentials that we've seen at $40 a barrel. And also Canadian light differentials blew out with MSW trading in the quarter, $27 below WTI. Now all that said, given the differentials, Imperial -- our corresponding financial results illustrate the competitive advantage of operating under an integrated business model with a uniquely balanced portfolio across the value chain. Balanced in terms of roughly 400,000 barrel a day Upstream production, 400,000 barrel a day of refining throughput and some 500,000 barrels a day or so of petroleum product sales. With widening differentials, our Downstream benefits from price advantaged feedstocks, while our Upstream realizations with lower -- absolute prices are adversely impacted. However, we partially offset that by a series of advantage logistics. Now, of course on December 2, the government of Alberta took an unprecedented action of intervention in a free market, by imposing mandatory Upstream production curtailment effective January 1. The order to artificially withhold production resulted in the immediate manipulation of market prices, some material shifts in company-specific market capital valuations heading into the New Year. And I'll have more to say on this topic at the end of my overall fourth quarter and full year comments. So, with that I'll dive in specifically to the performance. For the full year, net income $2.3 billion, up $1.8 billion versus 2017. This is our highest annual earnings since 2014. 2017 has some Upstream non-cash impairments on the order of about $560 million. If I look at across, kind of, by business line, the Upstream after climbing into the black due the first nine months and despite very strong operational performance in the fourth quarter, the price environment resulted in negative earnings for the quarter and negative earnings of $138 million for the full year. Downstream conversely on the heels of three strong quarters, the fourth quarter set a record with low cost feedstocks and strong operations and that also resulted in a full year earnings record of nearly $2.4 billion. I'll offer more comments specifically on Upstream Downstream as well as Chemical here shortly. Relative to cash generation, full year cash generation from -- generated from operating activities approached $4 billion for the year. And I think it's interesting to note that this performance is comparable to our annual average in the 2012, 2013, and 2014 time period where for those four -- three years, we averaged just a bit above $4.1 billion a year. So, just we're $100 million, $150 million or so, but it's even more interesting to note that during those three years, WTI averaged $95 a barrel and WCS averaged $73 a barrel. So, $30 a barrel higher than what we experienced in 2018. And I think underlying that comparable cash gen despite a much lower price environment are a number of enhancements we've made to the organization over time; Upstream, Downstream, Chemical, and I'll flag some of those as we go forward. Now, relative to that cash gen, working capital changes reduce cash generated from operating actions by our activities by about $700 million in 2018, essentially all in the fourth quarter associated with accounts payable and receivable balances with lower Downstream feedstock prices in particular. Capital and expiration expenditures, for the full year, we averaged just a bit above -- we finished a bit above $1.4 billion consistent with previous guidance that we had issued throughout the year 2018. We were just shy of $1 billion or 70% of our total spend in the Upstream, again consistent with previous communications. And nearly $400 million of vast majority of the rest of our CapEx was invested in the Downstream. Our investments were largely sustaining capital in nature along with previously announced projects. So, the sustaining capital on the order of $1 billion and the projects on the order of $400 million to $500 million. The biggest piece within the projects was our Kearl supplemental crusher at just shy of $200 million investment on the year and I'll offer more comments on Kearl shortly, but that project is on schedule and on budget for year-end 2019 startup. Dividends paid and share repurchases. Just to recap, our capital allocation strategy is to maintain a strong balance sheet, pay a reliable and growing dividend, invest in attractive growth opportunities, and return surplus cash to shareholders through buybacks as and when available. Balance sheet continues strong, $5.2 billion total debt, 18% debt to capital. We had just essentially $1 billion cash balance at year-end relative to dividends, 24th year of consecutive growth. $572 million paid. That was about 10% higher than dividends paid in 2017. Our per share dividend declared was $0.73 for the year versus $0.63 in 2017. And, of course, this morning we declared a dividend of $0.19 a share payable on April 1st to shareholders on record on March 4th. Share purchases nearly $2 billion for the year, almost 49 million shares. This was up from $600 million and 16 million shares in 2017. Combined at more than $2.5 billion our dividend and share repurchases are highest cash return to shareholders since 2007. Shifting to operational performance, starting with the Upstream production. Had a very strong fourth quarter with production of 431,000 oil equivalent barrels a day. This included liquids production of 407,000 barrels a day, our highest quarterly liquids production in company history. For the full year, 383,000 oil equivalent barrels a day, up eight kbd or about 2% year-on-year. And it was really a bit of a tale of two halves. The first half, we were at 353,000 followed by a second half of 413,000 oil equivalent barrels per day. So, up 60,000 oil equivalent barrels per day, half-on-half or 17%, and I would take you back to our mid-year earnings call where we commented on how we were positioned for a strong second half with the vast majority of our maintenance for both Upstream and Downstream behind us in the first half. And I think the second half unfolded precisely as we would have expected it. For the full year, liquids at 361. This was our second highest liquids production ever on a full year basis. Going to Kearl, following a series of liability improvements. Our unconditioned commitment was to deliver 200,000 barrels a day annual average at Kearl in the year 2018. In the first half we were -- through the first half, we averaged 181. So we were down by a couple of touchdowns at halftime. And in the second half we averaged 230,000 barrels a day, bringing the annual average at Kearl to 206,000 barrels a day consistent with what we expected and what our commitment was. This is -- was our best year ever at Kearl, topping last year's 178,000 barrels a day by 28,000 barrels a day or 16%. The fourth quarter results, they were reduced by an estimated roughly 20,000 barrels a day. We had a few weeks of planned maintenance at one of our two plants that carried over from September with the work completed as planned by mid-October. Typical activities crusher ware plate replacements, vibration screen repairs, hydro transport line, inspection rotations, valve inspections, and the like activities typically associated within oil sands mining operation. Looking ahead, I commented on the supplemental crusher. All of that work continues to go well, not only the crusher but flow interconnections that we will make to optimize and improve the overall utilization of all of our equipment. And that is on target, on budget for year-end 2019. What that will do is take us full from the annual average of the current roughly 200,000 barrels a day we delivered in 2018. The roughly 200,000 barrels a day, we expect to deliver in 2019 and then will bump this up to reliably a 240,000 barrel a day level starting in 2020. Continuing with Cold Lake, we had previously communicated we expected Cold Lake to ramp-up through out the fourth quarter and approach 160,000 barrels a day by year-end and average about 148 for the year. We did ramp-up somewhat. We averaged 147,000 barrel a day for the year. We fell a bit short of our year-end target production of that plus or minus 160, with some short-term steam management challenges, but also coupled with optimizations that we undertook late in the year, as a result of very low bitumen prices, such as reduced well work of this sort for the last few months. Moving onto Syncrude. When we last spoke about Syncrude November 2nd, we were fully ramped-up and running following the extended recovery from the June 20th, the high-voltage transformer failure and the resulting site-wide power outage we had. The operations ran extremely well for the entire quarter resulting in a best-ever quarterly production of any quarter at 89,000 barrels a day Imperial share. The previous best were two different quarters back in time at 87,000 barrels a day. Norman Wells averaged 7,000 barrels a day in the quarter. You'll recall that, a bit more than two years ago. Enbridge proactively suspended shipments on their Line 21. This is the export pipeline for Norman Wells. There were integrity questions. And after a lengthy regulatory process, two kilometers of the nearly 900-kilometer pipeline were ultimately replaced, that enabled us then to start resuming operations essentially at the start of the fourth quarter, with some 300 wells in associated flow lines. We had expectations that we would ramp-up over time, to roughly where we were before the shutdown, at about 10 kbd that ramp-up progressed well ahead of schedule averaging seven in the quarter. And we were at 9,000 kbd in the month of December. Refinery throughput at 408,000 barrels a day. It was a strong operational quarter with no major maintenance work performed and capacity utilization at 96% was also quite high. For the full year, 392,000 barrels a day, up nine from the prior year, a bit more than 2% and we had a full year utilization at 93%, up from 91% in the prior year. This has been a -- with margin the attractiveness of the Downstream business this has been a high priority area for us. And just – I would comment that ex-turnarounds over the last five years we've averaged capacity utilization of about 96%. And that compares to the prior five years 2009 through 2013 where we were at 89%. So this has been a very concentrated focus effort to fully utilize our facilities and make hay while the sun shines, and that's exactly what that organization has been doing. 2018 concluded a number of best-evers at each of our three refineries. Sarnia, worked the entire year without a single recordable injury of any type. The first time in it's a 121 year history. Nanticoke had it's highest-ever facility utilization improving 6% from its previews best. And Strathcona achieved record performance in asphalt manufacturing. These are a few of the best-evers we delivered in the Downstream on the refining business. In the first quarter, all three refineries are up and running. Expected to do so until about mid-March, when we will kick-off a regularly scheduled maintenance turnaround at Sarnia, which is part of the typical periodic three year cycle that we will undertake. We'll comment more at this at the end of the first quarter. And then as it wraps up in the second quarter with more fully detailed the impact of that work. Turning to petroleum product sales; 510,000 barrels a day for the quarter. Our strategy remains to profitably grow petroleum product sales via branded sales into strong markets and product channels, long-term strategic supply agreements with major customers, superior product offerings to meet our customers' need. In 2018 relative to the strategy, we focused our growth areas in several areas: expanding the ExxonMobil nationwide branded retail network, increasing sales into high-value asphalt markets and increasing aviation fuel sales into major commercial hubs; most recently Vancouver. For the full year, we averaged 504,000 barrels a day, our highest annual sales in nearly 30 years. And 2018 was one of only three years in our history with sales about 500. The others go back some 30 years and this was immediately after the merger acquisition that we had with Texaco Canada back then. The record full year was led by record sales in asphalt from 18,000 barrels a day to 23,000 in 2018. And jet fuel sales had increased from 37,000 barrels a day to 41,000. We now have the largest retail fuel network in Canada with some 2200 sites nationwide, up 200 sites versus the prior year and a large part due to the relationship with Loblaw and the introduction of the mobile brand into Canada. Third-party data suggest that as of the fourth quarter, we're now the number 1 in branded retail volumes nationwide with a bit more than 21% market share. Downstream earnings at nearly $2.4 billion, our highest-ever annual earnings when you exclude 2016 when we had a material gain on the sale of retail sites. Our previous best was 2014 at $1.6 billion. So we were $800 million better than our best ever. Historic high price advantage heavy crude runs were a part of our story throughout the year. We averaged 94,000 barrels a day into our facilities versus 64,000 barrels a day averaged over the last several years, at nearly at 50% increase taking advantage of those - the price advantage of feedstocks. I previously mentioned retail asphalt and jet fuel volumes growth. They were all part of the story the fourth quarter with earnings of $1.1 billion was also a record quarter. And the previous best here was in the fourth quarter of 2013 at $625 million. Chemicals, second highest earnings ever at $275 million for the full year, this was $12 million short of our 2015 best ever of 287. Polyethylene continues to lead the way. That's the storyline some 40% of volumes and more than 70% of earnings. In our press release we highlighted a few other areas of importance during the quarter including a series of agreements with indigenous communities in the Athabaskan region. These are areas we work very closely. And we look to enhance opportunities for consultation, environmental performance, economic benefit to community funding, employment and business contracting opportunities. So we were pleased to include a -- conclude a series of agreements at that point in time. I had a couple of other comments in our release around some environmental efforts where we relinquished some land to support a biodiversity area and then our continued major sponsorship of Esso Minor Hockey Week where some 13,000 kids play a nearly 1,000 games in a week here in Calgary. And it's -- for those of us in Calgary, it's a real highlight earlier in the year. So to wrap up 2018 quickly. I didn't detail at any great length, but we have strong safety in our operational integrity and risk management performance. Our net income and cash flow were the highest since 2014. What we returned to shareholders via dividends and share purchases, the highest since 2007. The growth in liquids production record at Kearl. Record Downstream earnings. Highest in company history. Refinery, throughput up year-on-year. Petroleum product sales also up. Chemical, second-best year ever. And we did a number of things that helped position and prepare us for future growth and value addition. Most notably continuing the grow investments with a supplemental crusher. Progressing Strathcona cogeneration project to improve energy efficiency. And then the approval of $2.6 billion for our 75,000 barrel a day Aspen in situ project which will use SA-SAGD technology. So before I turn it over to you for your questions, I want to offer a few comments on the government of Alberta's curtailment order. And so if I take us back to the fourth quarter, we had a perfect storm occurring with increasing industry production, seasonally higher refining and maintenance inventories at tank tops. No new pipelines and rail ramping up, but lagging overall takeaway needs. The result was a blow up in both heavy and light spreads. And also absolute low crude prices for heavy and lights that occurred. Driven by financial and political considerations, December 2, the government announced the curtailment order, 325,000 barrels a day; shy of about 9% of provincial production, effective January 1. There was a 10,000 barrel a day exception for each operator, the implication being 28 producers out of 421 would bear the full burden this. I publicly commented that we disagreed with this government action on a number -- for a number of reasons. Three fundamental principles. One, we think free markets work and we think the market was indeed working and economic production was being shut in. We believe that intervention to artificially manipulate markets introduce free trade risk, particularly in an integrated market such is North America. And last but not least, we think investor confidence can be -- Canada is damage at a time when we already have a confidence issue in Canada. The assertions that government intervention will quickly rebalance the market. Our view is they're ill informed. The fact of the matter is, predictions and consequences are uncertain in terms of timing and ultimate impact, time will tell here. The relationship with United States, our largest trading partner with the North American energy market, was designed and built to allow free and unrestricted flow of energy across borders and actions to manipulate or influence affect prices, we again fundamentally disagree with. For prospective investors, we think Canada and Alberta, we already have some challenges. Market access, regulatory uncertainty, relative fiscal competitiveness. And for our existing investors, government intervention that deliberately and artificially alters the value of assets and investment decisions denies our investors the opportunity to benefit from their prior independent and informed decision. So in short, with a stroke of a pen, the government began picking winners and losers. We think this action is unfair, anticompetitive and not representative of free economy in a modern democracy. Now everything I've just said I've said before, so I felt the need to say it again. From an industry perspective, each company makes independent and informed decisions on strategies and investments over time. And our view is, just like each one of us in our individual lives must live with the consequences of our decisions. We think companies also should live with the consequences of their decisions. So, the stump speech aside that said, where are we at Imperial or what are we doing? We're doing everything to maximize the competitive value from our assets and our investments. We're doing everything to limit their curtailment, scope, and duration. And we're doing everything we can to encourage or deter government from taking any future or further intervention actions. We're a month into this. Market factors continue to unfold. We've seen absolute crude price changes. We've seen heavy and light differential changes. The -- we are rapidly seeing crude by rail utilization change, market-clearing costs. We're seeing some producers who encouraged and now are complaining about actions they have taken. So, it's going to be -- and we expect it will be a very continued active period. At the end of the first quarter, we'll be better able to describe and perhaps quantify the impacts on Imperial and we intend to do so. At this point in time, I imagine you have questions in that, but estimates or projections are going to be difficult and in many cases, speculative. So, with that, I'll turn it back to Dave and we will kick-off the Q&A process.

Okay. Thank you. As I mentioned at the outset, we did provide the analysts an opportunity to pre-submit questions. So, we do have a couple here and we'll start with those and then we'll go over to the live Q&A. So, the first question was from Mike Dunn of GMP FirstEnergy. How was mandated curtailments in Alberta impacted Imperial's previously stated plans to ramp-up crude by rail volumes in 2019 from approximately 125,000 barrels a day in Q4 and your hopes to eventually use all of the terminal's 210,000 barrel a day capacity?

Mike thanks for your question. The -- our Edmonton rail terminal utilization -- maybe step back context. We -- the industry saw crude by rail increasing dramatically at the end of the year with the incentive to move crudes to the U.S., in particular, Texas, Louisiana, Gulf Coast, highest-value market and we're -- for the last several months, we're exceeding 300,000 barrels a day. We were a big part of that ramp-up after the first nine months of the year where we averaged round number 75,000 barrels a day in facility utilization in October. We bumped it up to 117,000 in November, we were at 153,000 and at December, we were at 168,000, a full likely a bit -- around or a bit more than half of the full industry crude by rail utilization. We averaged -- doing the math on that, 146,000 barrels a day for the quarter and that was above what we had communicated earlier we thought we would achieve. And that was all good because of the big differentials and the tremendous incentive to provide takeaway capacity by rail. We were also on plan for the first quarter. I think we had said something that we expect in the first quarter 170,000, 175,000 roughly. We were on plan on track to achieve 180,000 to 190,000 of the facility's full utilization 210,000 barrel a day capacity. So, all that was unfolding perhaps a bit better than we said. Today, the differentials have collapsed and the incentive to move crude by rail has been erased. It's negative. It's uneconomic to move crude by rail at this point in time. So, unfortunately, we are ramping down rapidly in the month of January. I anticipate -- I think our average will have been about 90,000 barrels a day, half of what we had targeted in February. With current conditions as they are in differentials, we expect to be at or near zero. I think this is a great -- the implication is that crude by rail should be helping to alleviate this situation in the province. But now because of the drastic, dramatic, manipulation and impact and differentials takeaway capacity is now being idled. That is a sad state. A very tangible example of what we believe is ill-advised, ill-informed negative consequence of this curtailment order. I can't say it and describe it any other way. So, thanks for your question Mike.

Okay. The next question is from Phil Skolnick of Eight Capital. Were you one of the only seller of crude to Valero in the U.S. Gulf Coast by a rail in Q4? And are the Venezuela sanctions making you look to increase your rail efforts today?

Well, I take that kind of the reverse, and the heavy crude demand in the Gulf Coast is high. And if you look at their traditional supply sources whether that's Venezuela or other sources, there is less supply from traditional sources. And that makes Canadian heavy highly valued. And that is the optimum, the best market for Canadian producers to strive to get their crude to. So we have contract pipe commitments that we've talked about roughly 100,000 barrels a day that allows us to get there. And then, of course, our rail terminal was the other major mechanism to get to that market. So that still remains the best market. We want to get there all, but we need to get there in an economic manner. And I just commented on rail. So that we've kind of had one leg taken out from under us on that, but still getting barrels there is the right thing to do. Now rather – specifically to who we sell to, we typically don't talk about the commercial dealings of who we sell. We give prices and volumes, and see I think you know who they -- the big consumers of heavy are in the Gulf Coast. And any and all of those parties are, customers are but we typically don't detail specific customers and certainly not volumes to any particular customer.

Okay. So now we're going to turn it over to the operator to initiate the live Q&A.

Thank you. [Operator Instructions] Our first question comes from Manav Gupta from Credit Suisse. Your line is now open.

Thank you guys for taking my question. A quick question on Aspen. You guys planned clearly well ahead. And by 2022 you should have KXL and you have capacity on it. So and should not be issue at Aspen at all. But just in case that there are some delays at KXL again, what's the back up plan to get to the Aspen volumes out of honesty?

I appreciate your question. It's very timely question. And just reflecting on Aspen, it was five years in the making from a regulatory review and approval standpoint. We're excited about the technology, the economic and environmental benefits that come with it. We like a bit of a countercyclical investment timing, when investing, when there is a lot of industry capacity and things. But I will tell you that as we funded Aspen last year, the uncertainties around pipeline market access were there. Of course, Line 3 was progressing. If there were still some issues to be resolved, Keystone XL has to prevent -- the challenge in Montana and the case in front of the Nebraska Supreme Court. But those are moving. They're difficult to guarantee or predict outcomes on it. But we knew eyes wide open that we have uncertainty around material new expanded market access via pipe. And underpinning Aspen, our ace in the hole was our rail terminal. It was we were using less than half of its capacity with our base business in the normal operation. I commented on the first half of the year. So, the rail in our – in the wide range of scenarios that we look at before we make major commitments. Rail was our backstop, or you've heard me describe it as our insurance policy for future growth that went with Aspen. At Aspen, at 75,000 barrels a day with diluent, it's roughly 100,000 barrels a day at dilbit and that's – we had spare capacity on the order of that amount. Now the curtailment order, it's introduced a new risk and a new uncertainty. And we can say, well, yes, but in short-term and things like this. Let's see. Is it short-term? I don't know. So what we're doing is we think it's prudent on an investment like that to reevaluate and look at the assumptions. The latest outlooks on various pipes and it's easy to say, we'll certainly by 2022 we'll have Keystone over this. That's easy to say. But as I look back, there haven't been a lot of new pipes in quite a while. And it's fundamental to the strong economics. So we're reevaluating your assumptions, looking at market access timing. We're looking at now with intervention, the impact of curtailment. What could that have? And you say, well, fast forward few years, certainly will be out of this situation. I don't know. A lot of things, I would have said, six months ago, well, certainly we would never intervene in a pre-market. So we're going back. We're looking at these things. This is exactly what we're doing is reevaluating. The project quality is high. I don't think the question is if. The question is what's the right or optimum timing for Aspen? Is it continuing exactly as we've outlined? Or is it something different? And that's what we're taking a look at right now, and if and when we have any changes to it, those would be things we would communicate.

Thank you so much. I have a very quick follow-up. Do you have any insights or any color you can provide on Enbridge Line3? What are you seeing over there? Any possibilities of delay? And the reason is I'm asking this is, because I -- we agree with you that government should not pick winners and losers here. And there's a possibility that, if Enbridge Line 3 is on track than the government might fully rollback the cut. So that's why I'm asking the question.

Yes. I think you bring up a good point in it. Get to Enbridge Line 3, but if you're -- what we're looking at right now in the marketplace to give us confidence in whatever expenditures are growing. Well, certainly the curtailment situation how it unfolds. And we're literally only a month into this. You saw differentials collapse from well beyond rail parity to now differentials are at pipe clearing in rails not economic. Do we start to see as the government relaxes curtailment? Do we see those differentials move back into where rail incentive for clearing by rail now is incentivized again? That could happen. So let's -- we'll see that over the few weeks. The political situation, just the workings of -- intervening pre-market is not an easy and as definitive as we thought. Do we see further intervention? Do we see less? Do we back out of it? Line 3 is a key one. The approvals are largely in place, but it's not across the goal line yet. There's a lot of construction in -- certainly Wisconsin, the Canadian side, a bid in North Dakota bid, we've got Minnesota that were -- is the last piece of that puzzle and then Keystone XL. So all of these things are the things that we're paying very close attention to, so that as we develop our business plans, not only short term but longer term we do that with eyes wide open and the best understanding of what risks and uncertainties and value is there for us. So Line 3, a lot’s been public on what is going on, on it, it Enbridge I think the latest we’re talking about is the target of having an operation at the end of the year. We are certainly supportive of that. Line 3 will help in this with the incremental capacity nearly 400,000 barrels a day. And I don't have anything that I would add other than what Enbridge already says. So I think that's the current target. But they're not out of the woods yet, in getting some of the final resolutions they need in the state of Minnesota. Some construction permits and some things, I believe after the Public Utilities Commission has provided the necessary approvals, there are still some other things they require before they can start laying in well and pipe. And we'll pay very close attention to that. And it will be a real good barometer of the timing of a material new addition to market access capacity above and beyond what the potential of rail is.

Thank you so much for taking my questions.

You’re welcome.

Our next question comes from Emily Chieng from Goldman Sachs. Your line is now open.

Thanks Rich. My first question is just around Syncrude. It delivered a very strong quarter production in the fourth quarter. I guess how sustainable is this going forward? Can you talk a little bit about, what were the past cultural changes that took place that drove that strong production? And just on a slight tangent but still on the Syncrude, there were reports from Conoco yesterday around same on perhaps looking for alternate sources of diluent this year. Has that got any impact on the way Syncrude needs to market its product?

Emily, I look forward to the quarter when I can say was there. And you can expect this from Syncrude each and every quarter. And so many times over the last several years when have had strong quarters which we have I've been tempted to say that. And I've learned that, it's a never-ending challenge. Now that said, there is no question that we are seeing fundamental structural improvements in Syncrude over time with the introduction of best practices, the support of Imperial ExxonMobile and now increasingly Suncore. So the identification and addressing what have been some of the root cause challenges in many cases particularly associated with the upgrading, the cokers. So we both -- we continue to believe we're on the right path. And we see a quarter like the fourth quarter. That does give us a lot of confidence going forward that things we are collectively doing, the ownership we're doing are the right things. But then I go back to June 20th and the power outage we had and we didn't see that coming also. So it's hard to make promises and all. But our -- what we have seen and what you said is we see Syncrude as -- our share 75,000 to 80,000 barrel a day kind of an annual average as they have varying degrees of turnarounds and maintenance work that continues to be what we expect. And as we look to the New Year 2019, that's when we have in our business plan. And I think all the actions are supporting that progress. Now, specifically, the marketing of the product, again, it's kind of like the earlier question. I don't tend to get into that. What we do is we're always looking to get the highest value for any production. And on the Downstream side, we're looking to get the most prized advanced feedstocks, so if there are opportunities here in the market with you mentioned ConocoPhillips with some more or others. And that affects what we can do or provide to maximize value of Syncrude, that's exactly what we will be doing. But I'm not coming in specifically on that one. One, I don't know enough about it right now, but we're always looking to get the highest value wherever we can in the marketplace for anything we produce.

Appreciate the color. And just one follow-up, on the share repurchase program in light where the macro environment is today. And then coupled with the spending levels that are associated with Aspen. I guess, what is a reasonable run rate to think of going forward, knowing that you guys are still -- when you sanctioned the Aspen project that was -- you guys can think that it was in conjunction with the capital allocation program that you had?

Yes. Emily, fair question. And what I've said before is, we would not -- a year-and-a-half, almost coming up on two years, we would not have reinstituted a share buyback program if we thought it was going to be something that would be short term in nature. Now we've also said that, if you look at our capital allocation strategy and kind of that pecking order I described about paying -- strong balance sheet, the dividend, quality investment, sustaining CapEx, we've always looked at the share buybacks as kind of the flywheel to go up and down if and when we have surplus cash. But now, if I get -- and I take the environment today, this year we generated about -- just shy of $4 billion. WCS was $39 a barrel. I'll get to differentials in a minute. Last year, at 2017 WCS was $39 a barrel. And we generated just shy of $3 billion. So, the storyline in the year were differentials and what that did on our Downstream in 2017, the differentials, the heavy-light differential -- excuse me, the Canadian light differential was $3 or $4 a barrel, the WCS was $12 or $13. That was 2017. And we generated $3 billion. In 2018, those differentials were much bigger, we generated 4. Whereas if I look today, or literally yesterday, WCS $44 a barrel. The Canadian light differential about $4. The Canadian heavy differential about $10. So all of that is about where we were in 2017, when we had strong Downstream performance we had strong Upstream cash generation. WCS is a bit higher today. So it's hard to predict for the year, because we're looking at a snapshot in time. But the dividend, roughly $600 million a year, we've released that kind of the capital guidance, 2.3, plus or minus $1 billion including some $800 million in Aspen. And so, you march down from the dividend, the CapEx. I think the share buybacks, it will be dependent on the macro environment, what it does and how our true spending unfolds. Our intent is that we will continue at a ratable level, but it will depend. We also have $1 billion cash on hand and that we typically don't carry a lot of cash. So I think we still have a great deal of flexibility to do all those things that are important to us. Strong balance sheet, reliable and growing dividend, fund attractive growth projects and a sustaining capital in there, and then continue to return surplus cash to shareholders if and as available. And I still see that as a part of our 2019 business plan. Absolute quantum is difficult to say. It always is difficult to say, because it depends on a number of things. But I don't think my earlier comments, including with spending on Aspen. I stand by my earlier comments. I think 2019 will be much the way we've described it in the past.

Appreciate the commentary. Thank you.

Thanks, Emily.

Our next question comes from Prashant Rao from Citi. Your line is now open.

Hi, good morning. This is Joe on for Prashant. Two questions. First, I'd like get your thoughts on Canadian light pricing and expectations for the differential through WTI. Seems to be back near WTI now as we head into back half of the year and IMO 2020 related incremental demand on distillates, is it reasonable to expect that Canadian light pricing and the market could take a premium to other light benchmark, specifically to WTI?

Okay. Well, I think, first of all, if you start with Canadian light, you've got to start with Brett and you've got a start with WTI and kind of the global macro-economic. On the Canadian light side of things, broadly, we -- the -- we're selling at a bit of a discount from WTI, of course. The differentials have come back in. So, on an absolute level, it's a tough question because it depends on first kind of global activities and then it comes back. Now, for us with -- when we have a growing differential with Canadian light that net-net is a benefit to us because our refining, we tend to be a heavy oil producer a lighter oil refiner. But also with where differentials are right now that's where we -- 2018 was kind of the anomaly year and it's back to kind of where we were in 2017 or beyond. But I'll go beyond what I usually do in forecasting and I'll give you a few thoughts. For the curtailment strategy to work, I think a healthy rail takeaway capacity needs to be up and running. And with where differentials have led to now, that's not happening. And so you've seen reports of inventories dropped down in the month of January, well that's why rail was still providing a level of export capacity. Although the incentives may not have been there throughout the month, folks were unwinding and I described us, we have largely unwound our rail terminal. So, half of that capacity that was there in December supporting -- reducing inventories and clearing the market here has evaporated. So, what I think you'll see here now is -- and I hope you see because I hope you see differentials start to move into the range where rail economics are positive and then industry rail and our terminal can provide -- can start providing a material takeaway capacity. And that would say differentials would need to be somewhere in the $15 to $20 a barrel range or largely where they were for the first nine months of last year before the fourth quarter and all the events of the fourth quarter. So, I hope we've seen kind of a swing on differentials where they're uniquely tight and we're in a pipe-clearing mode and I hope you see them start to swing back maybe with -- a little bit of a relaxation of the curtailment order, any number of things. And when we get in that range, rail business for industry will be back and running, make good economic sense. And I think that will help get the province back into the balance it strives, and in particular, get us back to where we're operating under free market conditions without government feeling the need to try to move the dials and -- because that's what we learn here is that's quite difficult to move a dial and predict an outcome. And we're not a big fan of negative unintended consequences. Now IMO -- we've talked about that point most recent at our Investor Day. We -- again here, a lot of assumptions around what goes on on there. But I would say if you look at us relative to our fuel oil production and our distillate, we think net-net, it's going to be good for distillate. We produce, I think, was higher -- not the number of permit, it was 183,000 barrels a day at distillates. And so in the year so -- and then with our flexibility in our facilities, we feel that we're quite well positioned to deal with IMO specs. However, and at whatever pace they unfold. And I'll just refer back to our comments I think it was Dan Lyons talk about it in November at our Investor Day, we went into that in a bit more detail and our views on that really haven't changed in the last couple of months.

Thank you for the comments. And the second question like past Line 3, any thoughts on potential alternative logistics or transportation solution into the U.S. Gulf Coast other than Keystone XL perhaps maybe involving a series of connections, including the current top line reversal plan?

Well, I think you -- the kind of the foundation of your question is getting heavy crude to the Texas, Louisiana, Gulf Coast. And it's a no-brainer in terms of this is largest confrontation of heavy oil processing facilities in the world. There is a large and growing demand for it and supply sources have either been choked of or diminish over time. That's the winner-winner. That's where we want to get as a producer. That's where we want to get heavy all too. Obviously U.S., Midwest provides some strong markets too and we want to do that. But for growth opportunity and long-term for the industry it's getting it to the Texas, Louisiana and Gulf Coast. And it reminds me of an old movie, Planes, Trains & Automobiles. Anything we can get there in the light market conditions make sense. We've invested in contract pipe, we've invested in a rail terminal, we support Keystone XL, the contract commitments for expanded access. We're the -- I think we remain the largest shipper and the average mainline today, and there are some further tentacles that go down beyond the mainline that gives you Gulf Coast access. So any and all of those avenues, I think you'll find the Imperial Oil quite supportive of because it gives us the long, a long-term market access capacity to advantage of the strongest market for heavy oil. And I'll have my hand up on any or all of those to help with the long-term growth of our industry and our company and get into the highest value markets. And the Line 3 and KXL are the two furthers along on the drawing board. And I think I can safely say that any pipeline sponsors are proponents are looking at any and all ways that can continue to enhance capacity whether it's new and/or existing lines to get production to those markets.

Thank you. I appreciate the color.

Our next question comes from Dennis Fong from Canaccord Genuity. Your line is now open.

Hi, good morning guys, and thank you for taking my question. The first one is just a bit of a follow on to the share buyback program. From what you were essentially outlining there is it safe to assume that when -- or at the timing of the announcement back last June for your 40-odd million share buyback and you guys being about halfway through that right now, should the assumption still be despite we’ll call it the volatility in the current market both on a WTI business as well as differential basis that -- your attention is still to complete the first half or the second half of this NCIB? And then reevaluate the go forward, well, call it levels that you can renew the NCIB at June at the time of renewal?

Yes. I think when you get to June at the time of renewal and things; that gets a little more difficult. I'd like to have a few more months under our belt and see where things lie. But as we sit here today and what we're continuing to do is quite consistent with the renewal of middle of last year and as we look at sources it uses of funds. A lot can change in one month or two. And we saw that here in the last month or two. But our execution of that, I would -- certainly would never describe it as we're blindly executing that. But where we are today, we are continuing that and I expect that we will continue. On the renewal, itself, I really need -- Dennis I really a few more months and just seeing what kind of transpires in the market to be able to have any really -- offer you any comments with any degree of confidence. But I go back to the year before when we institute this thing. We wouldn't have done it if we thought it was something we would turn on and turn off, but we've -- for the first -- largely for the first almost year of that program, we were at a lower pro rata rate, about $250 million of quarter round numbers. So, we bumped that up last year with improved performance and higher cash flow to something that has averaged more recently kind of $400 million to $500 million a quarter. And moving up and down at a consistent averaging ratio is kind of -- that's kind of the way we want to do it. I don't see us going all-in in one quarter then slamming the brakes on in the next quarter. So, we'll look at continuing it, but I think the next several months will give us -- it's -- hold that question, ask it at the end of the first quarter call, give me a few more months of financial performance, and I'll be in a little bit better position to kind of speculate with you looking ahead.

All right. I will do that. The second question here is just at your Investor Day, you highlighted the view for the debottleneck projects at Kearl and frankly fairly strong capital efficiencies. How should we think about potentially these projects in light of not just your current view of the market, but kind of how you're thinking about the project in aggregate here as well?

Yes. I think you hit on a well there. We're very attractive from a capital efficiency, capital intensity. And to describe it as something on the order if I recall, round numbers 40,000 barrels a day of incremental capacity potential above and beyond the post supplemental crusher. So, from John Whalen did a good job of articulating how we go from 200,000 to 240,000 and then describe what a pathway to 280,000 could be. And with a series of enhancements debottlenecks that we would think of in aggregate would be quite capitally efficient. So, near-term, all eyes are focused on getting the supplemental crusher in the flow interconnect, done, complete by the end this year and then up and running. And at the same time, we have a set a really smart folks that are working on these supplemental debottlenecks that could get increment-by-increment. When we get supplemental crusher up and running and determine are we truly at 240,000 is it something other than 240,000? Is it 245,000? Is it 250,000? Then we'll be able to sharpen the pencil on the true value of each increment. But I do think it's safe to say that given the overall capital intensity attractiveness of that basket of opportunities, those will be things we will be looking to pursue. And if we're -- if the performance of supplemental crusher were off by a little bit, I don't think that's going to take these opportunities and say they're not attractive. This is going to help us determine how attractive. But first things first, supplemental crusher flow interconnect this year and those things -- and I think John describe it as kind of they would unfold over the following few years. And the next time, we talk at either at an Investor Day or somewhere else this year goes on. We'll probably able to get more definitive on those. But everything we've outlined in November remains true to form in terms of kind of what our expectations are for Kearl over the next several years.

Okay, perfect. And then just kind of the last follow-up there. Just given, will call it the potential operating cost impact of being able to expand production at Kearl for fairly low cost, how should -- and I don't want to make it sound like it agnostic frankly to market egress situation. But, how should I be thinking about those potential just influencing factors on deciding around the potential of this project or projects?

I'm sorry. Just not sure I have -- how market access would play into further expansion?

Exactly.

Yes. I think it gets backed to a lot of the conversations that we had either on Aspen at all. Clearly, we're going to need to be able to move this stuff and with -- if you look at the timeframe out of the 40,000 barrels a day, the supplemental we're working on now in today's world, it would compete for a pike space like others. We have some -- we have strong position with the production that we've had, with the Downstream take away capacities we have. I hope, as I've said that, we get back into -- well, rail makes economic sense. But as you keep adding increments, whether that comes at Aspen at 75,000 barrels a day, or another two increments of 4D at Kearl you got to have confidence you could be able to get it to attractive markets in that. Now the benefit of that second 4D at Kearl is kind of like Aspen. It's a little bit further out there in time. And we'll have the time and the benefit to see how the dust settles on the current situation we're in. And I know I'm repeating, but Line 3, Keystone XL, rail and any other way to get crude to market. So, you can't say, we're indifferent, or oblivious to expanded market access. But I think in Kearl, we'll have time to see how these things unfold. And those potential investments debottlenecks, I would expect with market access, would be – incrementally would be quite attractive.

Great. Thank you.

Thanks, Dennis.

Our last question comes from Greg Pardy from RBC Capital Markets. Your line is now open.

Thanks. Thanks. Good morning. Thanks, Rich for doing the call, again. I'd probably suggest that your indication on the ramping down rail is going to have a pretty immediate impact on the market. But I did want to come back and just ask you little bit about that in terms of what your cost structure is then in terms of crude-by-rail call it Alberta to the Gulf Coast? And then, how you think about ramping-up or ramping-down? Is that thought process in the context of fully loaded cost or is that -- do you also think about a variable cost just trying to get your thinking there? And then, how fast can you ramp-up crude by rail than if the differential does blow it again? Thanks very much.

Thanks, Greg. Welcome your questions. What we've said before that with the efficiency of our terminal. The direct access we have to markets and just kind of all the component parts that have built-up crude by rail. And it's more than a terminal and it's more than having access to tank cars. It's having the power and people agreements and rail service provider. It's having the offloading capabilities with customers. So, you don't put a rail deal together overnight. And we've been working on this for several years. And feel that we have a rail facility that is on the low end of the cost curve in terms of rail. And numbers we said before is kind of round numbers, $15 a barrel roughly, fully loaded cost. But we do look at, just as you say and you rightfully say it, is when we're making decisions on economic optimizations, that's the cost that will be in it, but we're looking at variable cost. And the variable costs is $9 or $10 a barrel, and that's more attractive than what a differential is. We'll move it by rail and that -- so with current differentials of what's happened, for us, I would say, that it's on a variable cost basis, we're kind of -- we're close that, right now at full cost rail doesn’t makes sense, variable cost for us, it's close to it. And the question you ask about ramp up, that's one that we -- within our interactions with the government, I think, has been really important, because as you redeploy things because they're no longer economic and we in our rail terminal, we put together a quite an attractive deal there with the relationship with ExxonMobil and access to railcars. We can we deploy them. We can pull them back, but you don't do that overnight. If cars go away in they're in West Texas Permian service and now the economic incentive is there to bring it back to Canadian service. Well, they've got to complete what they're doing in the Texas. And then you got to get them on a track and you got to bring them back here. And that takes time. And so, there have been numbers of estimates. And so, it really depend -- specific answer your question, depends on, well, restoring what level of capacity. Is it 30,000 barrel a day? 60,000? 90,000 or 120,000? And each of those come with different timelines to do it. But what I would tell you, it's certainly not days and weeks. Its months. Now is it a lot of months or short months, it kind of depends on the capacity you would seek to reinstate. And what we have done, because we believe this rail terminal is very valuable to our company, but we also believe it is very valuable to the situation here to expand takeaway capacity and get us back into a market operating world again. We're trying to do the absolute best we can, so that as the differentials may incentivize rail at the end, we can get back into the rail business as fast and efficiently as we can. Now all of that said, I'm not much for waiting on the bus in cold weather if I'm losing money. So we have been redeploying, because that's what makes the most economic sense to do it.

Okay. Thanks very much, Rich.

Yes, you're welcome, Greg.

So that takes us essentially to end of our time. Did you want to offer some closing remarks Rich?

I'd just say we talked a lot about reflecting back on the quarter and the year. I think it was -- we've got a lots of very strong things here. And now the questions here we're largely on, okay, that was interesting but where are we today? And we're in a very dynamic situation today and then my soon to be 38 years in this industry. I'm kind of hard pressed to say whenever I had a period of time that wasn't dynamic. That is the nature of the oil and gas business. But as I sit here with Imperial Oil and I look at the level of integration we have, the balance we have, Upstream, Downstream, Logistics, I think we are designed and built to deal with and address and prosper in most any business environment we operate in. Differentials go up, differentials go down, heavy, lights. We've got a lot of tools and levers at our disposal. And we will do exactly what we've always done in particular what we have been doing of late to find ways to capitalize, make money, do all the things that are important to us for our shareholders and the current situation we're in is no different, the issues are bit different, but the challenges are the same and I’ll put my money on Imperial Oil to operate and address those challenges today just like we've done in the past. So, I think I'll conclude there.

Okay. Well, thank you everybody once again for calling in. As always if you have any further questions please don't hesitate to reach out to the IR team here at Imperial. Thank you very much. Thank you, operator.

Thanks folks.

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