Imperial Oil Limited (IMO) Q1 2019 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to Imperial’s First Quarter 2019 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 be given at that time. [Operator Instructions] I would now like to turn the call over to, Mr. Dave Hughes, Vice President, Investor Relations. Sir, you may begin.

Thank you. Good afternoon, everybody. Thanks for joining us. I’d just like to introduce the folks that are in the room right now. We have Rich Kruger, Chairman, President and CEO; John Whelan, Senior Vice President of the Upstream; Dan Lyons, Senior Vice President, Finance and Administration; and Theresa Redburn, Senior Vice President, Commercial and Corporate Development. As usual, I also want 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 first quarter earnings release that was issued earlier today as well as our most recent Form 10-K, and all those documents are available on SEDAR, EDGAR and on our website. So, please refer to them. Again, as typical in this format, Rich is going to start by making some opening remarks and then we'll turn it over to Q&A. And we do have a few questions that were pre submitted, and we’ll mix those in with questions coming live from the Q&A line. So, with that, I'll turn it over to Rich.

Okay. I would add my good afternoon, particularly to those of you out east. We know it’s later in the afternoon on a Friday. I'll start out -- before I detail our first quarter results F&O results, I’ll offer a few comments on the overall business environment in the quarter. When WTI at $55 a barrel in the quarter was lower than both the fourth quarter of ‘18 and the first quarter of a year-ago by $5 and $8 a barrel, respectively, but that said, the story in the first quarter really relates to both absolute Canadian prices and price differentials. And more specifically Canadian light or MSW was up $17 quarter-on-quarter, averaging $50, and Canadian heavy WCS was up $22 quarter-on-quarter, averaging $42. And both of these movements have material impacts as we talk about Imperial Oil. So, with these opposite movements of global prices down, Canadian prices up, differentials greatly reduced relative to the fourth quarter, with WCS/WTI moving from minus 40 to minus 12, and MSW/WTI decreasing from minus 27 to minus 5. Of course, as opposed to market forces, the Government of Alberta's mandatory production curtailment order, which went into effect January 1 of this year, was the primary driver behind these big price movements. So, with that, let me get into our net income with $293 million, $0.38 a share. For Imperial, our integration and our balance being defined as roughly 400,000 barrel a day equity producer or roughly 400,000 barrel a day refiner, and then petroleum product sales of 450 to 500, with that balance across the upstream, refining and petroleum product sales line, they work to help moderate the impacts of dramatic price and/or differentials switch. So, first quarter, net income, $293 million, it was down for the first quarter a year ago by about $220 million and down materially $560 million from the fourth quarter. Relative to the fourth quarter, upstream earnings increased by approaching $400 million, driven to a large extent by higher crude prices. However, we experienced a negative impact to downstream earnings of nearly $900 million, in large part due to higher refining feedstock costs. Other factors like upstream volumes and some downstream reliability events also factored into the overall kind of quarter-on-quarter change. Continue with cash, cash gen. Cash generated from operating activities was right at $1 billion in the quarter, very similar to the first quarter of ‘18. Cash generated from earnings was about $700 million with working capital changes making up the remaining $300 million. What you saw here is the positive working capital effect in the first quarter of this year was driven by net payables and receivables with rising crude prices, and that was offsetting about half of the negative working capital effect we saw in the fourth quarter of last year with falling crude prices. On capital and exploration expenditures, they totaled $529 million in the quarter, upstream expenditures were $370 million, about 70% of the total. That's quite consistent with where we are kind of roughly year in, year out. Spending on key projects upstream and downstream like our Kearl crusher, Aspen, Strathcona cogen and our Alberta products pipeline totaled $235 million out of the $529 million total. Our original full-year capital expenditure guidance that we issued in January, we suggested investments would be in the range of $2.3 billion to $2.4 billion. This included monies for Aspen, SA-SAGD in situ development. After we sectioned Aspen in November of last year, we announced in mid March of this year that we would slow down the pace of development, largely due to market uncertainties stemming from the government of Alberta's intervention in crude markets and other competitiveness issues. We stated that given the limited winter drilling season and site preparation season, the ramp down would likely result in a delay of at least one year to the original 2022 start-up. So, our original plan called for capital expenditures on Aspen of about $800 million this year with the ramp down, which we’re executing in such a way that will enable us to efficiently resume full scale project actives when we judge the time is right. We now anticipate capital expenditures on Aspen of roughly $250 million this year. Consequently, total CapEx guidance would now be expected to be in the range of $1.8 billion to $1.9 billion versus the year-over-year $2.3 billion to $2.4 billion. Dividends and share purchases, refresh your memory, capital allocation strategy, strong balance sheet, pay a reliable and growing dividend, invest in attractive projects and if and when and as we have surplus cash to return that to shareholders via buybacks. Balance sheet remains strong, debt is at 5.2, debt to capital is 17% to 18%. We have about $1 billion cash on hand at the end of the quarter. In the f quarter, we paid $149 million in dividends at $0.19 a share. Today, we announced a 16% increase or $0.03 a share to $0.23 per share payable in the third quarter. And then, for those who keep track of these things, 100 plus years of dividend, consecutive payments, 20 plus years of consecutive payments. And if you assume 19 at this current declared level, that would be a bit over 10% five-year compound average dividend growth rate. In addition, in the quarter, we continued share buybacks, consistent with our TSX approved NCIB program that allows us to purchase up to 5% of outstanding shares over the June 18 to June 19 period. We execute this program ratably roughly 10 million shares a quarter. ExxonMobil has continued to participate maintaining its ownership share flat. And so for the first quarter that was about 10 million shares, $360 million or so. Each NCIB program runs for a 12-month June to June cycle that I mentioned. We renew this annually. So, we're preparing our June 2019 renewal as we speak, we will have more to comment a bit later. But I think it’s safe to assume that we will seek a renewal similar to the current program. Upstream production averaged 388,000 oil equivalent barrels per day, up 18,000 year-over-year or about 5%. In full perspective, if you look over the prior three years first quarter production average right at 390, essentially flat with where we were first quarter this year. Liquids were 364 or 94% of our total. Getting into the assets, Kearl, on a gross basis, we produced 180,000 barrels a day in the quarter that compares to 182,000 in the first quarter of last year. I would say, we were a bit below where we had hoped to be this year in the first quarter. And I would attribute the majority of that to uniquely cold weather, which caused a bit of havoc with our shovel operations in the mine. That said for perspective, first quarters are typically more challenging due to the colder weather. This year, it was more acutely cold, I’ll comment on that in a minute. But if you look back over the last three years, our first quarter has averaged in the mid 180s, roughly. So, we're not atypical for this year. Second quarter production expected to be in the same range as the first quarter, impacted by annual turn around work at what we refer to as our K2 facility. Second quarter production last year was 180 as well and that included a turnaround at the K2 facility. The specific work we are going to be doing for turnaround this quarter be about 32 days or so, starts in mid-May. We will have a cost of about $100 million total, $73 million or so IOL share, and the scope will include normal inspections with payers, plus some supplemental crusher related work, hydro transport line installation and some select tie in that's preparatory work for the ongoing project. In the quarter, the impact of this work, we'd estimate roughly about 50,000 barrels gross, 35,000, 36,000 barrels Imperial share. And note, the turnaround a year ago, 30 days, $90 million a little bit less work items at the time, but generally comparable. Our outlook for the full year remains unchanged at 200,000 barrels a day, quite consistent with what we did in 2018 end of the year at 206,000. The supplemental crushing capacity in the flow interconnect project continues on schedule. And what that means is at year-end '19, from that point forward, we will have the facility to support 240,000 barrels a day annual average basis in 2020 and beyond. Cold Lake, 145,000 barrel a day in the first was down 6 from the fourth quarter. Similar to Kearl, extremely cold weather, particularly in February, affected us. And for context, we think it affected us by about the tune of perhaps 3,000 barrels a day in Q1. And to say it’s cold in Canada -- in the winter, it sounds a little strange, but I’ll give you a little context. If there was a coldest February in 15 years, the daily average temperature was minus 23 degrees C versus an average of minus 13 over the last five years. So, what this does? It affects work productivity in both the base operations and all well work because workers -- their time on tools, their productivity is restricted due to safety considerations when we have to limit exposure to the elements. So, it just simply takes more time to get things done when we have that extreme cold weather. In the second quarter, at Cold Lake, we anticipate we’ll be in the range of 130 to 135. This is with major turnaround work at our Mahkeses plant. You may recall, Cold Lake has five major steam plants, Mahkeses is being one of them. Mahkeses averages about 30 -- 31,000, 32,000 barrels a day. This turnaround -- we turn around these five facilities roughly on a once every five-year interval. So, we tend to have one of the plants down each year. So, depending on what that plant’s production happens to be, that will give you the impact. It’s is a 36-day work. We started -- 36-day duration. We started it this week. Cost is about $30 million. We’ll have about 13,000-barrel a day impact in the quarter. Technical work, regulatory inspections kind of base maintenance repairs, line cleaning, turbine generator maintenance, kind of the normal kinds of things we will do. And this turnaround this year is quite similar to the work we did last year at the Maskwa plant in terms of scope, duration cost and production impact. Moving on to Syncrude. Our 25% share of Syncrude averaged 78,000 barrels a day in the quarter. We have continued high reliability following the fourth quarter of ‘18, best quarter ever. And Syncrude as a designated operator in Canada, is subject to specific orders with the Alberta government’s curtailment program that became effective the first this year. The negative impacts of these orders partially offset the strong reliability performance. So, in other words, we could have done better if we were not artificially constrained. In the second quarter, our share of production from Syncrude is expected to be similar to the first quarter, maybe there is a couple of KBD upside to that. The big thing here is we have no major maintenance plant in the second quarter. The next turnaround work at Syncrude will be in the third quarter where we will take down one of the three cokers, the 8-1, and we will have more to say that work during our second quarter call. Crude by rail. With market forces working unconstrained and pipelines full, industry crude by rail out of Western Canada was increasing rapidly in late ‘18 and peaked at more than $350,000 barrels a day in December. With the government’s mandatory curtailment order, crude by rail dropped dramatically in the first quarter as higher Canadian crude prices and reduced differentials essentially evaporated the true economic incentive to transport. Industry went from 325,000 barrels a day in January to about 145,000 in February, 150,000 in March, probably 165,000, 175,000 in April. Imperial, we went from 168,000 in December, 89,000 in January, zero in February and 16,000 in March. And what I’d offer is this highlights a negative unintended consequence of the curtailment order with a similarly negative and a directly related impact being on the inability to reduce provincial inventory levels, and that's quite important. So specifically, at the end of the year, crude inventories were essentially tank tops across the province, roughly 34, 35 million barrels. With the initial curtailment, rail continued before it started to drop off dramatically. Inventories dropped to about 28 million barrels in February, things generally looked good, they were going in the right direction. However, since then, inventories have increased with reduced curtailment and reduced rails. And a week ago, today Genscape reported crude inventories at essentially 34 million barrels again, right where they were before the curtailment order went into effect. Now, as we look ahead, we think some of the major spring maintenance activities, particularly at the mines may help to alleviate some of the pressure over the next couple months. But clearly, the explicit curtailment objective of not only increasing prices but reducing provincial crude inventories is not being achieved. On rail, for Imperial, in the month of April, we’ve averaged about 25,000 barrels a day that’s kind of what we refer to as kind of one -- a set of rail movement. We ramped up a little bit while we resumed limited operations in mid-March. And so, you get 25,000 barrels a day for the month. We targeted this with select customers, so we have 30 plus refiners we sell to And whatever, depending on the terms of those sales, there may or may not be an incentive to move by rail. There was a slight incentive at this tier. We're finalizing May and June plans at this time. But what I can tell you is our rail will go up or down, based purely on economics. If there is money to be made, we will work to resume rail operations. And if there is not, we will discontinue them. On the refinery throughput, 383,000 barrels a day. I would just -- 91% utilization. To me, this was a disappointing quarter operationally. For a context, throughout averaged about 400,000 barrels a day in the first quarter of the year, over the last four years. Last year, it was particularly strong at 408,000. This year, we were plagued by a series of individually small but collectively significant reliability events and we had them at each of our three refineries. And I’d say here again, extremely cold weather worked against us in terms of our ability to respond and recover when relatively small events occurred. Our estimates are it cost us about 20,000 barrels a day of refinery throughput. And if we put an earnings impact to that, we would estimate that was about $60 million in the quarter or about $0.08 per share. Now, these things are behind us, but it’s just like all of our operations, the challenge is all to achieve the highest level of reliability each and every week, each and every month, each and every quarter. Going back to overall financial performance. I commented earlier how the Alberta government’s action worked to increase Canadian crude prices and reduce, both heavy and light differentials. If we exclude the absolute change in global crude prices, WTI that I commented on, we would estimate fourth quarter to first quarter, the corporate earnings impact to Imperial were a negative $250 million due to the net upstream, downstream affects of curtailment, isolating curtailment. And I’d offer you -- for those that are -- suggesting how do we figure that out, I’d point you to our 10-K where we have a earnings sensitivity in there and we detail it for each barrel or for each dollar of barrel of differential movement in heavy and light -- both heavy and light, would equate to about $40 million a year or $10 million a quarter. So, quarter-on-quarter, light differentials reduced by $22 a barrel, heavy by $28 somewhere in there, the $24, $25, $26 on average, hence you can get to the $250 with math of that sort. Looking into the second quarter. We are in the midst of a turnaround at our Sarnia refinery. It's about a 60-day duration mid-March to mid-May scope, various catalysts, change-outs, reliability upgrades, some replacement of end-of-life for absolute equipment, kind of the normal kind of stock, the cost, $60 million to $65 million. We think we’ll have the earnings impact when you factor in the margin as well as the cost of about $100 million in the quarter, $0.12 to $0.13 a share. All product sales commitments are being met with preplanned third-party purchases, but therein lies a rub. We had to purchase product to sell it, because we don’t make as much money when we purchase and sell it, as when we manufacture and sell it. I will note though, last year in the second quarter, we had a large turnaround at Strathcona in the estimate, we shared at that time for that event was on the order of $250 million. So, this is a material turnaround at Sarnia, but not nearly of the same financial impact as what we did a year ago. I’ll also comment for addressing an incident at Sarnia that occurred outside of quarter but on April 2nd, and this was in preparation for some of the turnaround work. We had a fractionation tower, 150-foot tall tower that fell inside the plant. The tower was out of service at the time, it was hydrocarbon-free. Fortunately, no one was hurt and we had no spills or air issues with it. The tower is used to manufacture, both jet fuel and some select gasoline components. Now inspections and repairs are underway; cost, timing and financial impact are to be determined. We do have insurance on this; it's for damage, not consequential loss, because we have a deductible as well. We're evaluating options to reconfigure other units to produce the products, jet and gasoline components, although it will be slightly at reduced rates. We will have more to say on this as the continued investigation and repair work goes on. Petroleum product sales, 477,000 in Q1, consistent with seasonal product demand, essentially flat with the first quarter of last year. And if I look at the prior five years in average, the first quarters, they have happened to average 477,000 barrels a day, each first quarter on average over the last five years. Our strategy is very consistent what we have communicated in the past, to grow our sales via branded sales in the stronger Canadian markets and product channels to continue to strive for a longer-term strategic supply agreements with major customers and provide a superior suite of product offerings to meet our customers’ needs. Kearl autonomous haul truck program. During our Investor Day last November, we described our ongoing autonomous truck pilot at Kearl. Specifically, then we detailed that we had 797 trucks in productive service. We talked about our workforce engagement plan to ensure that our whole team was focused on making this work. We talked about testing programs for oil sands conditions. And our expectation that a full fleet implementation could deliver a cost reduction of greater than $0.50 a barrel. We’ve made excellent progress on this work over the last six months, continue to build confidence in the technology and developing the required suite of operating procedures that would go with the 12 months of operating conditions you would see in a Northern Alberta mining operation. Most recently, the big news is we attend regulatory approval for a ramp-up in full fleet conversion. So, we will be expanding autonomous fleet today from today's eight vehicles to about 20 or so over the course of 2020. And by the end of the year 2020 or early 2021, I would expect that we will be in a position to make a final decision on the conversion to full autonomy. If we do that and the time -- and sometime in 2022 by year end, we would maybe anticipate that, that could be 75 to 80 trucks or so at that point in time. And what I would also add is on our evaluation is also solidifying the cost savings potential of indeed more than $0.50 a barrel. I'm quite excited about this work. The team is doing a great job. We'll continue to expand it and it's yet another example of technology helping enable and lower supply costs in the oil sands. With that, we outlined a couple other things in the press release, I'll skip on that, but I'll just -- before I open up to your comments, I'll just summarize that, I would characterize our first quarter financial and operating performance is solid, not bad, not great. It was a very dynamic environment operationally, certainly market related, and I would add and politically. Our competitive strength to integration and our balanced portfolio, I think once again highlights our financial resiliency to both changing and uncertain market conditions. And I would suggest you interpret our 16% dividend increase and continued share purchases and expressions of our financial strength and confidence. So, with that, I'll turn it back to Dave to describe and kick off the Q&A process

Okay. Thanks, Rich. As we’ve done in the past, we did provide folks an opportunity to submit questions in advance. We did receive a few. So, I’ll start out with a couple of those and then we’ll move over to the live Q&A line. So, the first question comes from Manav Gupta of Credit Suisse. On the last call, Imperial had indicated that crude by rail volumes will be cut to zero, given lower debts. But then, we heard you guys are restarting the crude by rail. So, I wanted to understand what changed on the ground.

Yes. I think, I hit on that in my comments that we have a host of customers. And at various points in time the barrels we sell can be on different terms, different conditions including price. And we will look at meeting those customers’ needs in the most economic manner possible. So, in mid March through largely through April, we’ve had an opportunity to resume limited shipments, i.e. that 25,000 barrels a day that I’ve commented on, because that makes economic sense. If going forward if differentials and customers, if it continues, we will look to increase or conversely, if it doesn’t make economic sense, we would once again decrease those crude shipments. So, it's largely a month-to-month decision. Of course to bring railcars, put them back in service, this is not a switch you can flip on overnight. So, there is some preplanning involved with it. But, you can interpret that, limited resumption in March as saying -- for that tranche of volumes that made economic sense to move it in that way.

Okay. We also had a question around an update on the Sarnia refineries, but you -- I believe you provided that in your comments. So, the next question we will go to is from Benny Wang, Morgan Stanley. Can we get an updated on your capital allocation strategy, given the extra free cash flow? You’d expect with higher oil prices and tighter differentials. Where will the freed up capital from delaying Aspen development go?

Yes. I think, if I go back to fundamentals, balance sheet is strong; we’re comfortable with our debt level. So, if you kind of go to the pecking order, and I would put these two kind of hand in hand. We talked about how our sustained capital on a year-on-year basis averages about 1.1 billion. Our dividend, the annual dividend amount at current rate is about $600 million, so 1.6 roughly. If I look back over our last 10 years, our cash from operations averaged about $3.3 billion a year. So, our dividend and sustaining capital if you look at it over time would be about half of that cash flow. It was $3.9 billion in 2018. So, what do we do is beyond that; it’s an incremental capital that we think makes good economic sense for growth. Currently, that would be Kearl supplemental crusher, Strathcona cogen, for example. But beyond that if and when we have surplus, it will go to buybacks as it has now for the last couple of years. So, I think it would be safe to assume that with a reduced spending at -- on capital overall driven by Aspen, then what that would mean is that will likely mean those monies would be directed to additional buybacks or continuing the buybacks at the rates we’ve talked about. Here again, I’d comment that we’ll have a renewal for the mid-19 to mid-20, 12-month period coming up. We’ll probably have more -- we will have more specific to say about the level of buyback. Of course we’re allowed to go up to 5% of outstanding shares. I think what it does it just solidifies the outlook for continued buybacks at the more recent higher level.

[Operator Instructions] And our first question comes from the line of Prashant Rao from Citigroup. You may begin.

Rich, you alluded to this -- I shouldn’t say alluded, you explicitly kind of stated it in your prepared comments about the sort of the unintended consequences of curtailment, so that inventories are right back where we started. I think maybe perhaps you would agree that there’s been a bit of thesis drift here with the government going from targeting excess inventories to perhaps of claiming victory on price, and rising oil prices helps with that in addition to differential. It was early days but with the new incoming administration, do you think -- do you get a sense in your conversations that we’ll be going back to the original thesis of targeting with excess inventories. And then, sort of thinking beyond that if oil supply globally loosens up a bit or let's say gets less tight in the back half of the year, we should see some mean reversion on benchmark pricing. And that puts us in a different a bucket than we are right now temporarily. So, I wanted to get your thoughts on those two points? And then, I had a follow-up rail.

I guess, I’m an engineer versus a politician for a reason. But, I'll offer you some thoughts on this. When the program is put in place, I think the most -- there were two objectives and they were quite explicit. And it was obviously to get a higher price. And you could describe that as fair and competitive or whatever, but not higher price. And the other parallel objective was to drive in for inventories down from their tank top levels to something more historical. And there were numbers, instead of 34 and 35, there were numbers like 16 million to 17 million barrels or so, kind of thrown out there, drive inventories down, so as seasonal events, or production increases or decrease go that there was a cushion in the system to absorb much, that would help take out some of the price volatilities. But, those two assumptions -- or excuse me, objectives were hand-in-hand. And clearly, the increase in price has occurred, and some are declaring victory or success with this. When I step back and I look at that, say okay, price -- if you are a big or small upstream player that has certainly helped you. But, I also look at the unintended consequence of rail economics and the fall off in rail takeaway capacity. I think that's a big negative. In the short-term, that's really the only saving grace for increased takeaway capacity. I'll look at the prudential inventories that here we are four months into this and they are right where we started. So, that objective clearly has not been met. I would say, another one that’s not talked about as much is companies and crude markets trade, they trade in short-term intervals, 3 months, 6 months, 12 months. And increasingly, traders are reluctant to buy or sell Canadian crude because it's considered too risky to predict 3 and 6 months out, what prices it may be due to uncertainty around what government may or may not do. And I think the other unintended consequence that in the short-term we don't talk about as much is investor confidence. Canada was already suffering from a confidence issue before this. And I can quite confidently you, it's been exacerbated by this. And the most vivid example of that is our decision to slow down investments in assets. So, I think if price is your only measure, you might be inclined to say this has worked. But I view this as, this is a little bit of a short-term euphoria, it's temporary. And if I use kind of analogy, it’s like kicking the can down the road a little bit. The issue, the fundamental issues have not been addressed. We have a -- there's no lasting improvement in this. And we're going to have to face this, come up. And I don't -- we're quite on record of let markets work, don't incur the trade risk that go along with this, and it's about time we start doing things to restore investor confidence. So, what we would strive for and hope that we can achieve is we've got to get rail back in business. We've got to get it where there is a clear market incentive for parties to do exactly what we were doing late last year and procuring power and people and cars and loading terminals and offloading terminals, so that we can maximize the takeaway capacity out of Western Alberta and produce what we expect billions of dollars to develop as opposed to shutting it in and artificially attempting to inflate prices. So, I work off of facts. And when I look at the facts other than price going up, I don't like what I see on most any of the other parameters associated with this policy.

That's a very thorough answer. Thanks. I appreciate that. On the rail then, perhaps segues into that. Assuming that you get rail economics working on the margin going forward, we now also have the previous administration’s railcar program that they’ve entered into, the incoming administration has at least talked about maybe looking at that and revisiting the viability of that program. Is there room that the rails have capacity to take on both that rail program as well as yours and other producers’ contracted in the free market agreements? And if there was some sort of way to -- I don't want to say to rescind but to reform the contract that Alberta government has, where would that capacity go? I think, it’s been scant on details in terms of how we think about that. But, do you have a sense of how that would move around in the market and maybe what that means overall for available rail capacity. And of course, this is all assuming that the economics work on incrementally going forward. If we assume that, is there -- does the capacity work out in terms of contracts versus what the rails are able to ramp in your conversations?

Yes. I think, I'll start on that as well, we're not privy to the contract or contracts that the province has. I don't really know. But, what I do know and if I look, we have a terminal that has 210,000 barrel a day capacity. Late in the year, we were ramping it up we were at a 168 in December, we had plans to get to 180 to 190 in the first quarter with the goal of filling that terminal up. And then in February we went to zero because it made no sense. So, buying anybody, buying and building new rail capacity when right now there's several hundred thousand barrels a day of unutilized capacity, I'm not sure that makes sense. I think what does make sense is let's do everything to get the currently existing capacity back in business and then the collective we, whether that's the government, whether that’s industry, if there is further incentive to build, expand whatever, then that can be decided. and I think just like industry late in the year, we were responding rapidly, we were expanding our rail deals with CPCN, we were bringing in new cars. There was a market incentive to increase crude by rail and I’ve got a lot of really smart people that were doing everything they can to do that. That’s what we do and that’s what business does. I would suggest that if the business environment’s right, industry will meet that need because there is a economic incentive to meet that need. But, it seems kind of odd to me that we’re talking about building more capacity when we have several hundred thousand barrels a day of idle capacity today.

And our next question comes from the line of Neil Mehta from Goldman Sachs. You may begin.

Hi, this is Emily Chieng on behalf of Neil. Thanks for taking the time today. Can you guys discuss some of the progress that’s been made at Aspen so far? And how should we think about the capital spend associated with that going into 2020 and sort of the profile to I guess currently the 2023 start-up please?

Yes. When we made the decision in November, we were just -- like any upstream project, the first months, six months or so is kind of a slower ramp-up on the spend. The first year is a bit lower on capital spend, the last years is a prepare for startup. The big spending years are the couple years in the middle. So, we were just getting started on the spending. And so, the question before us, the decision we made was, do we jump on that curve a very rapid ramp-up or not. So, in the quarter, for example, we spent around $100 million. And I said that we plan to spend about 250 this year. These are round numbers. But we’re doing things right now to complete select work that’s in progress, maybe that’s some site preparation work or some equipment that’s been ordered. We will put that in a place and a condition where it can be maintained in the short-term. And so, this orderly slowdown in activities that I’ve described versus slamming on the brakes. And we think, in doing that that will best position us. When we feel the time’s right, we can resume a ramp-up in activities, and we’ll do that also efficiently with the lowest absolute cost impact to the project. So, I think, I said with winter construction seasons and things here. What we will be faced with this later this year decision, do we have business conditions evolved enough where we’re ready to ramp it up again? And if so, I think you can look at the amount of money that we would have spent this year, i.e. I’d say roughly $800 million. If we're in that position, that’s about the amount of money we would spend next year. You just get back on the project execution curve. If later this year, we're not there yet and we don’t feel that we’re ready to do that, then what you see is a very minimal spend less than this year in 2020 and you see likely another year because of delayed startup. But, I think the time to talk about this will be later in the year as we start wrapping up all of the things that are going in the right direction and the things that aren’t going in the right direction yet to make that decision, are we ready to resume a more full project execution. I think in our investor day, we kind of recall, I don’t have the page in front me, we talked about $2.6 billion of the project and we said kind of spending will peak in the ‘19, ‘20 ‘21 time period, and they would be roughly 700 to $800 million or so each year. I recall, we were something in that. So, you’ll have kind of three years of peak capital spend, and then the shoulder years will be a little bit less. So, we will just be moving that. Right now we’ve moved it one year. And then the question later this year is that what we do move it is the one or do we elect to move it yet another. But, the spend profile has just been shifted out.

And then, just moving back to Kearl. So, it sounds as though the second quarter production would be in similar levels to the first quarter, given some of downtime at the K1 facility. This sort of implies if you are still targeting that 200,000 barrels today of average production, quite a step-up in the run rate then second half. Is that sort of similar to what we saw last year?

Emily, it was probably because when last year we talked -- or actually late ‘17, we talked about a lot of the enhancements we have made to improve the reliability of Kearl to get it from the 180ish range over the prior few years to the 200 on an annual average, and we detailed very specifically the things we did on the crusher, on hydro transport, on conveyors, on teeth and bearings chains et cetera, et cetera. But the confidence in 200 was quite high. And if you are a sports fan, when we’re at the middle of last year and when we’re at 181, if you are a U.S. football fan, that might be -- it might have looked like we were down by a couple of touchdowns at have time. But, we knew that with the second half, particularly the third quarter and in the fourth quarter, we have less overall maintenance work, that's when the productivity is highest, weather conditions are right. So, we said all throughout last year, our commitment is unchanged that 200. And we delivered on that in the third quarter at I think 244, in the fourth quarter at somewhere around 220, something like that, and we ended up 206 for the year. That's exactly where we are this year. The first quarter is 180, the second quarter we would turn around, it’s going to look the same way. At mid-year, folks are going to say do they realize that the second half is going to take 220, to get to 200, yes we do realize that. And our confidence is as high this year as it was last year. And it's because of the nature of the timing of things. The minds are not steady state across the year. And the reason is 200 again this year is the real big bump up comes with the supplemental crusher and the flow of interconnects that will occur at the end of this year. So, we've looked at ‘18 and ‘19 as fundamentally the same kit. Now, we are always looking at optimizing can we do better, can we squeeze more, can we debottleneck, and we may be able to do that. But, those are we're really talking about a few or several thousand barrels a day optimization or reliability relative to that last year’s 206 and not a step change. So, that’s a long answer to, yes, we are quite confident we're going to deliver 200,000 barrels a day this year and the profile will look quite similar to 2018. Perfect. That’s exactly what I wanted to hear. Thank you .

Okay. So, we've got a couple of more pre-submitted questions which we will go through and then we will go back to live Q&A to finish this up. So, from Manav Gupta, Credit Suisse. Given the progress we are seeing at Kearl, supplemental pressures proceeding ahead of schedule, is the 240 KBD guidance for 2020 on conservative side?

I love that question. I love that confidence, because it wasn't too long ago when I was being asked -- in fact, it might have been just two minutes ago, can you deliver on your commitment for 200? And then prior year, last year is the same thing. I love that people are now asking, are you going to do better than you said. Obviously, I'm a little bit tongue in cheek as I say this. How we arrived at the increment between 200 and 240 is we looked back at start-up and said with reliability events, either the crusher, whether that’s chains, whether that’s bearings, weather that’s crusher teeth, the incremental downtime that we incurred, what was the opportunity cost? And then, not having the facilities interconnected further downstream of the crushers and hydro transport, what was the opportunity we could have had if we could redirect slurries and fluids from one facility to another facility. And we quantified that based the lost opportunities that we saw. And when we did that that became the incremental 40. So, the confidence in the 40, I would say is high. And now, your question is, can we do better than that. I don't know yet. I'm hesitant to promise it, but what I can promise you is, if you look at our operations, whether it's upstream or downstream, when we reach a level of reliability and stability, our workforce is always looking at okay, now what is the next bottleneck, what’s the next opportunity to stabilize, enhance. And maybe those increments don't come in 40,000 barrels a day at one time, but maybe they come in 3,000 or 4,000 barrels a day or 5,000 or 6,000 barrels a day. So, with the redundancy we are building in, I believe we will have a more stable operation, a more reliable operation, and that will allow our incredibly capable work team at Kearl to look at what's next and what are we be able to deliver. So, I don't know that I can quantify anything above that. But, the 240 was based on good, solid experienced-based quantification of lost opportunity, and we're quite comfortable on that. That said, I do look forward to doing better but I’m not ready to say at this point that we’ll be able to do that right out the blocks in 2020.

Okay. And final pre-submitted question is from Benny Wang, Morgan Stanley. Your Chemicals business had a tougher quarter than we were expecting, can you talk about the dynamics weighing on margins here? And do you expect these to be persisting headwind?

Yes. Good question, Benny. If you look back over the last five years or so, in our chemicals business, they have been the five most profitable years in our history in chemical. We've averaged earnings of about $240 million a year, a range from a low of $185 million in ‘16 to high of about $285 million or so in ‘15. The five years prior to that, our chemicals business averaged about $110 million to $120 million with a even a wider swing in high and low. So, when you look at our first quarter of 34, we're certainly well below our most recent highs and a bit more typical or a bit higher than our historical earnings. The driver behind this in the quarter is polyethylene margins, they are down year-on-year. The biggest driver behind that is there has been major industry capacity in the U.S. Gulf Coast that has been long anticipated. We’ve seen as crackers and the like have been built and installed, and they're now on line. So, specifically you’ve seen ethane feedstock cost are higher with increased demand for ethane. And you combine that with as new capacities come on and markets are trying to absorb that capacity. You’ve got a bit of oversupply in North America on polyethylene. And both of these have worked to decrease North American margins. We’ve talked before about some of our feedstock cost advantages, some of our location to our customers, so the transportation advantages we have on that. So, it is too early to definitively predict. But going forward, in my mind and in our own business model, we would expect an earnings to be closer to that $140 million, $150 million a year as opposed to the $240 million a year that we’ve enjoyed over the last five years. I’m not giving up on that higher number yet but we’re looking at all the market factors behind it and recognize there are some headwinds. It will stay a very profitable business, just don’t know if it will stay as uniquely profitable as it has been in recent years.

Thank you. And our next question comes from the line of Greg Pardy from RBC Capital Markets. You may begin.

The rundown was quite through, so lots of notes there, good work. I got two quick ones for you. One is, as it relates to just when you are not using your rail cars, then generally are you able to redeploy those into the U.S to the Exxon network?

Do you want me to go one at a time, answer that one?

Yes.

I think it's important, the context on rail is we decided to get into rail when rail wasn’t cool. We decided in 2013, looked at our business, looked at all the pipe on the drawing board, everybody else said, there is going to be pipe going in every which direction, east, west, south. And we sat back and said, but what if things -- bad things happen. So, you've heard me say many times Greg that it was an insurance policy. So, the beauty on that is we were able to test the time to design and build and structure agreements, whether that’s not only the facility itself but whether that was offloading agreements with key customers, whether that was getting the most absolute direct path from Alberta to the Gulf Coast we could, and we constructed a very efficient, cost effective, rail terminal. I will put it up against anybody in industry. And part of that is we brought land to the table next to our Edmonton refinery, Kinder Morgan, our partner brought expertise. And then ExxonMobil as a partner, not as a majority owner in us, we negotiated deal and they operate the largest fleet of railcars in North America. And they can be deployed to a wide range of services. So what we were able to do there when there was economic incentive, we place a call and we get more railcars. They might have to finish up and offload what’s in them right now but we can get those railcars back in service. And similarly, when it does not make economic sense, we return them back to ExxonMobil. So, what that does, it gives us a very and much lower fixed cost to our rail operations because we can offload those costs by spinning those cars back. And similarly when we need them again, we can call. Now, they are not there the next day but that flexibility is huge and it’s fundamental to our efficiency and the low cost structure of our rail operations. Whereas if we were -- if didn’t have that relationship and you had either bought or leased cars, you are paying for them either way. If they’re idle, you’re staring them, looking at them in the yard, and you say well, we’re paying for them anyway, we might as well move them. And even if we’re losing money on per barrel. So, we have a unique situation. And I really attribute it Greg that we have the time and the foresight to plan this venture and position with a great deal of flexibility. We're able to roundtrip cars on the order of about twice a month. So, i.e. 15 to 16-day round trips from Edmonton to Gulf Coast and back. I would challenge anyone to see who else can do it in that period of time. And all of that drives down the unit cost because cars are full and transport include more days than they are meandering back home to get loaded again. So, I thought I’d give you more than you ask for on that one Greg. But yes, the answer -- quick answer to your question is yes.

Yes. No, no. That’s helpful. Okay. Here is the other one is, I mean it's not just Imperial-Exxon, but I mean there is a lot of turnaround. So, we’re obviously going into now in terms of maintenance and so forth. But, given the turnarounds that you've outlined at both Kearl and then Cold Lake, would it be fair to say that you were building i.e. putting barrels into storage just in advance of that to kind of modulate what your sales would be that period of time?

Not so much on the upstream. We will build inventory or buy product to meet customer needs on the downstream. But, I think it's important to know, yes, we produce 400 and we refine 400. But those barrels we produce don’t necessarily go to our same facilities. Our downstream guys are looking to buy the lowest cost feedstock and our upstream guys are looking to sell their barrels to whoever will pay the highest for it. So, on the upstream, it's not really a storage gain. We produce and sell and try to get at each market. But the buying inventory, the ramping-up storage levels is more of a downstream practice in advance of the turnaround, so we can continue to meet customer product needs while those facilities are out of service.

Okay. Last one for me. Kearl…

You said two, that’s three…

Okay. Well, you’re going to like this question. So, just Kearl operating costs, and this is where we really need that enhanced disclosure on the progress you are making. Can you give us an idea where OpEx was in Q1 ideally in Canadian dollars and then just what it might be at 200,000 barrel a day run rate, like even like even approximate is okay. But, I have no idea where your operating costs are at Kearl?

Greg, that’s probably because we don’t necessarily want you to where our operating costs are at. I’m just kidding. I’m going to ask somebody kind of flip and get the number on that. I would say thought in the first quarter they were higher than they typically are on a -- we've talked in recent kind of like for the year, 2018 for example, they average, we talk about kind of in the $25 a barrel range U.S., and then we talked about kind of a longer-term objective of driving that down through things like autonomous trucks, going from 200 to 240, driving that down to on the order of $20 a barrel or less. That remains the outlook. In the first quarter of ‘19, we were higher than that. And part of that is the producing of 180 versus 200 or -- and you know that the incremental barrel comes much cheaper than the average barrel. But also in the first quarter, we had some work that would -- I would describe one, we had higher energy costs year-on-year that would be about, let's see, perhaps -- somebody do -- keep the math. That would almost be 30 -- would that be approaching a $1 a barrel, almost a $1 a barrel higher energy cost year-on-year. I think -- somebody do the math to check me on that how many barrels we have produced in the quarter. I think that’s probably pretty close. And we did some work on road construction and preparatory work recognizing that next year we’re going to go from 200 to 240. So, we're going have to be expanding the mine phase to be able to accommodate more earth moving. So, we started to do some of that work now. And if I take that, I would put that into a couple of dollar of barrel also in the first quarter of this year. Some of that will continue, not all of that but I would say the first quarter of this year was $3 to $5 a barrel higher than we would have been in ‘18. So, I'm giving math, I’ll let you add the numbers up, but that it really relates to higher energy costs, electricity, natural gas pricing, some of the provinces greenhouse gas costs, and then preparatory work for an expanded mine front as we prepare for 2020.

And our next question comes from the line of Phil Gresh from JP Morgan. You may begin.

Yes. Thanks. Actually just a very quick follow-up to Greg's question around the OpEx. I appreciate that color on the quarter-over-quarter. If I look at the past couple of quarters, it looks like the OpEx has been may be 1.1 billion a quarter or so on the upstream side. It sounds like you're saying that there is some preparatory costs. Obviously, second quarter, you tend to have turnaround cost occur as well. So, I'm just trying to calibrate, like what is like the normal run rate for OpEx for the upstream our business moving forward? And then, as we think about layering in the additional 40,000 barrels a day of Kearl production in 2020, how do you think about the incremental OpEx of those barrels? Thanks.

Yes. One of the things I said Phil was on the kind of normal run rate. And I know this is going to sound weak, but it depends, because the second quarter for example, I talked about the turnaround work that will go on at Mahkeses and Cold Lake at K2 in Kearl. We often have a turnaround at Kearl that bridges the third and the fourth quarter. So, kind of looking at it monthly-to-monthly and quarterly-to-quarterly, it's not upstream, it's not as smooth and even run rate. You really have to kind of -- you almost better to look at second quarter one year, second quarter another and kind of quarter it, because you do have the unique aspect in the upstream in Canada. The heavy plant operations, you have a lot of work there. I do think, your comment on kind of 1 billion to 1.1 billion, that's where we’ve been this quarter is up higher than that run rate of a year ago, some of the things I have mentioned. I don't think we've reached a new norm or anything like that on a higher run rate. If I get to the second part of your question on Kearl, the incremental barrels do come cheaper than the average. So, yes we will be operating supplemental crushers and doing some other things. But those -- that 40,000 barrels a day will not be at the 25, for example, the $25 a barrel U.S. run rate. They will be less than that. They won't be as low as the marginal barrel of 7,000 to 8,000 barrels a day because of -- generally because you are also operating some new equipment. I was just handed something that’s saying that that 40,000 barrels a day, John, be sure and keep me honest that that may add on the order of $90 million a year. So, if you are back into that that would say that that’s pretty cost-effective at $6 to $7 a barrel. So, just to kind of negate what I just said about, it will be somewhere between the 6 and 7, and the 25, it will be closer to 6 and 7. And that’s because -- you got the energy to run a crusher and things. But the bulk of the aspects, certainly on the plant downstream, we have the capacities. So, those incremental barrels are going to come quite cost effective and continue to work to drive down the average unit cost of the whole operation. And then, I’ll complete that. Our goal is to keep on driving that down. I used the autonomous trucks as an example. If you go back to John Whalen's investor day material in November, he listed a suite of other things that included autonomous trucks, included digital work, other things. And the goal was to get back to $20 a barrel or less.

Okay Got it. I appreciate it I wasn’t trying to get so granular on quarter. The question was a little bit broader, which was if I look last year, the OpEx was up $400 million, 2018 over 2017 on upstream. I thought may a lot of it was Syncrude but then we see some higher number this quarter. So, that was one of the essence of the question.

I think a lot of it was Syncrude. And that’s clearly a factor. Syncrude got much lower this year. But, I think some of the things that we’ve seen this year are not -- they are not necessarily sustainable each and every quarter.

Sure. And was that $90 million Canadian that you're mentioning for the incremental OpEx dollars for the 40,000?

Yes.

Thank you. And our next question comes from the line of Dennis Fong from Canaccord. You may begin.

Just quickly on Aspen. I’ll just follow up one of the previous questions. You kind of indicated that the timing was maybe around the winter, start of winter there in for potentially having to make a subsequent decision. What are some of the business factors that you guys are going to be analyzing or looking at as qualification to make decision around, either kicking out -- kicking the can further down the road, to use your analogy with respect to CapEx spending on Aspen, and following the existing timeline or moving it further down the line.

I think Dennis, if you kind of step back is, I described early on that Aspen has this kind of ace in the hole of rail, I would like to see rail back in business where it makes money in a free market operating business environment, and so we get that rail terminal back up and running. I would to see what happens on curtailment the rest of the year, the outgoing administration put a program in place. They articulated what their expectations were kind of quarter-by-quarter and that we would be largely out of the curtailment world at the end of the year where we have a new administration coming in. We will see some of the objectives the outgoing administration outlined have not been met inventory levels. So, I would like to see what kind of a world are we. I personally like a free market, a world without government intervention. And then, we will also look at -- there is a lot of things in play right now on longer term pipeline access. There is a federal decision coming up. In theory it should be coming up in June on TMX. There are some important decisions coming up on KXL. We’d have some recent progress -- movement on Line 3 in Minnesota. So, I would say it's that whole spectrum of things. I wouldn’t necessarily say, I need to see everything going in exactly the direction I would like. But that's what we will look at. And it was largely those same things that we looked at when we said alright are we ready to go on that. But then, a new and an incremental risk was brought into the marketplace with the government intervention and what it did to rail and some of -- our confidence and the ability to always have a way to move Aspen to market in an economical manner. So, I think that's the gamut of the things we’ll be looking at. And I think as the year goes on, and whether it’s these calls or other actions, we will certainly opine on how do we see those things unfolding and what does that mean for us on either our confidence to reinitiate large scale Aspen activities or to continue in more of a slowdown mode.

And then, does that mostly apply to just allocating capital or spending dollars effectively on building out new production and supply into the market or does that more kind of follow velocity around further investment to increment your exposure to local market?

Well, we talked about the sustaining capital in our world, on the upstream sustaining capital largely keeps us flat in terms of production. The oil stands with the long life, low decline are quite unique in that area. And the mines can be essentially flat. And then, Cold Lake with the level of drilling can mitigate the decline on it. So, I think those monies will make sense and that we will want to spend that money to take care of our existing asset base. Similar comments would go on the downstream. And so, the question on capital allocation really comes above and beyond that $1.1 billion a year of sustaining, what monies above that makes sense, given the volatility and the uncertainties we see in the marketplace, and whether they are upstream or downstream.

And I guess my final question here just is maybe a bit of a follow-on to Greg’s question around repurchasing some of the railcars. Just given a little bit of the dislocation around, call it retail local sites and so forth, as well as dislocations around pricing in the refined market space. How much of some of those railcars that would have been using -- you would have been using to transport crude by rail would then be potentially be potentially refurbished to transport something like refined product instead of actually a raw bitumen number or a raw crude barrel?

Yes. The railcars that we've used for our Edmonton rail terminal, when they are not in use for transporting heavy crudes and they go back and redeploy it, they go into ExxonMobil and go into ExxonMobil service for whatever use they may choose to use therefore. It's not deployed or redeployed to alternate Imperial use. John, fair?

Largely.

That's perfect. Thank you. Those are all my questions.

Very good.

Okay. So, that’s the end of our questions. So, Rich, just some closing remarks.

Yes. I’d kind of reiterate what I said. When I look at the quarter, solid, not bad, not great, we can do better, dynamic business environment. I like the way we're positioned in that environment with the integration and balance, and there is no doubt it’s -- questions around kind of market conditions, price differentials remain, and each and everything we do over the subsequent quarters will be about maximizing value. And a like the asset base and the flexibility we have, whether that's the core upstream or downstream assets, whether that's access to midstream logistics, and we will -- you give us a level playing field, and we will be on it competing and I like what we have to compete with. So I will just end it there.

All right. I'd just like to close out by thanking everybody again for your time. And as always, if you have any further questions or would like any further follow-up discussions, please do not hesitate to reach out and contact us.

We're 24x7, 365. You can call him any day, any time of the day.

And with that, thanks everybody for your time and interest today.

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