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Imperial Oil Limited (IMO) Q1 2019 Earnings Call Transcript

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Imperial Oil Limited (NYSEMKT: IMO)
Q1 2019 Earnings Call
April 26, 2019, 3:00 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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 follow at that time. If anyone should require operator assistance during the call, please press * then 0 on your telephone keypad.

I would now like to turn the call over to Mr. Dave Hughes, Vice President, Investor Relations. Sir, you may begin.

Dave Hughes -- Vice President of Investor Relations

Thank you. Good afternoon, everybody. Thanks for joining us. I would 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.

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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 at 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 will turn it over to Rich.

Richard Kruger -- Chairman, President, and CEO

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 F&O results, I'll offer a few comments on the overall business environment in the quarter. When WTI hit $55.00 a barrel in the quarter, it was lower than both the fourth quarter of '18 and the first quarter of a year ago by $5.00, $8.00 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 MSW was up $17.00 quarter-on-quarter, averaging $50.00, and Canadian heavy WCS was up $22.00 quarter-on-quarter, averaging $42.00, and both of these movements have material impacts as we talk about Imperial Oil.

With these opposite movements of global prices down, Canadian prices up, differential is greatly reduced relative to the fourth quarter. With WCS/WTI moving from -40 to -12 and MSW/WTI decreasing from -27 to -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 bug price movements.

So, with that, let me get into a net income with $293 million, $0.38 a share. For Imperial, our integration and our balance -- be defined as roughly a 400,000 barrels a day equity producer, roughly 400,000 barrel a day refiner, and then petroleum product sales of 450-500. With that balance across the upstream refining and drilling product sales line, they work to help moderate the impacts of dramatic price and/or differential swings.

So, first quarter, net income 293. It was down from the first year ago by about $220 million and down materially 560 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 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 expiration expenditures, they totaled $529 million in the quarter. Upstream expenditures were at $370 million, about 70% of the total. That's quite consistent with where we are roughly year-in, year-out. Spending on key projects Upstream and Downstream in key projects 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 expected investments would be in the range of $2.3-2.4 billion. This included monies for Aspen, the SAGD in situ development. After we sanctioned 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 competiveness 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 activities when we judge the time is right. We now anticipate capital expenditures on Aspen of roughly $250 million this year. Consequently, the total capex guidance would now be expected to be in the range of $1.8-1.9 billion versus the earlier $2.3-2.4 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, 17-18%. We have about $1 billion cash on-hand at the end of the quarter. In the first 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 that 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 a 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 regularly, roughly 10 million shares a quarter. ExxonMobil has continued to participate maintaining its ownership share -- 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'll have more to comment and 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-on-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 of 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 is the quarter. That compares to 182 in the first quarter of last year. I would say we're 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, the first quarters are typically more challenging due to the colder weather. This year 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 turnaround work at what we refer to as K2 facility. Second quarter production last year was 180, as well, and that included a turnaround at the K2 facility. The specific work we're going to be doing, for a turnaround this quarter, it will be about 32 days or so, starts in mid-May. We'll have a cost of about $100 million total, $73 million or so IOL share, and the scope will include normal inspections, repairs, 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, 35-36,000 barrel Imperial's 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. We ended the year at 206. The supplemental crushing capacity and flow interconnect project continues on schedule, and what that means is that 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 barrels a day in the first quarter was down six from the fourth quarter. Similar to Kearl, the 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 always sounds a little strange, but I'll give you a little context. It was the coldest February in 15 years. The daily average temperature was -23C versus an average of -13 over the last five years, so what this does, it effects 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 when we have that extreme cold weather.

In the second quarter at Cold Lake, we anticipate we'll be in the range of 130-135. This is with major turnaround work at our Mahkeses plant. You may recall Cold Lake has five major steam plants, Mahkeses being one of them. Mahkeses averages about 31-32,000 barrels a day. 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'll give you the impact.

It's a 36-day work. We started at 36-day duration. We started it this week. Cost is about $30 million. We'll have about a 13,000 barrel a day impact in the quarter. Typical work, regulatory inspections, kind of base maintenance repairs, line cleaning, turbine generator maintenance, 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 had continued high-reliability following the fourth quarter of '18, best quarter ever, and Syncrude had a designated operator in Canada, is subject to specific orders with the Alberta government's curtailment program that became effective the first of this year. The negative impact of these orders partially offset the strong reliability performance, so in other words, we would have done better if we were not artificially constrained.

In the second quarter, our share production from Syncrude is expected to be similar to the first one. Maybe there's a couple of kbd upside to that. The big thing here is we have no major maintenance plan 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'll have more to say on 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 increasingly 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 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.

What I'd offer is this highlights a negative unintended consequence of the curtailment order with a similarly negative and a directly related impact, the inability to reduce provincial inventory levels and that's quite import. So, specifically, at the end of the year, crude inventories were essentially ten tops across the province, roughly 35-35 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 the right direction. However, since then, inventories have increased with reduced curtailment and reduced rails. 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 of 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 referred to as a set of rail movement. We ramped up a little bit -- or 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 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's money to be made, we will work to resume rail operations, and if there's 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 context, throughput has averaged about 400,000 barrels a day in the first quarter of the year over the last four years. Last year 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 effect 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 10K where we have an earnings sensitivity in there, and we detail it for each dollar a barrel of differential movement in heavy and light, both heavy and light. It would equate to about $40 million a year or $10 million a quarter. So, quarter-on-quarter, light differentials reduced by $22.00, heavy by $28.00. Somewhere in there, the $24-25-26.00 on average, hence, you can get to the $250 million 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, scoped various catalyst change outs, reliability upgrades, some replacement of end of life or obsolete equipment, the normal kind of stuff. The cost, $60-65 million. We think we'll have an earnings impact when you factor in the margin as well as the cost of about $100 million in the quarter, $0.12-0.13 a share.

All product sales commitments are being met with preplanned third-party purchases, but therein lies the rub. We've had to purchase product to sell it, so we don't make as much money when we purchase it 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 and 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 the 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 under way. Cost, timing, and the financial impact are yet to be determined. We do have insurance on this. It's for damage, not consequential loss. Of course we have a deductible, as well. We're evaluating options to reconfigure other units to produce the products, jet and gasoline components, although it'll be likely at reduce rates. We'll have more to say on this as the continued investigation and repair work goes on.

Petroleum product sales, $477 million 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 and 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 with what we've communicated in the past, to grow our sales via branded sales in the stronger Canadian markets and product channels, to continue to strive for longer-term strategic supply agreements with major customers, and provide a superior suite a product offerings to meet our customer's 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 seven Cat 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 our 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 obtained regulatory approval for a ramp up in full fleet conversion, so we will be expanding our autonomous fleet 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 '21, I would expect that we'll be in a position to make a final decision on the conversion to full autonomy. If we would do that, and at the time -- and sometime in 2022, is by year-end, we would maybe anticipate that. That could be 75-80 trucks or so at that point in time.

And what I would also add is 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 to enable a lower supply cost in the oil sands.

We outlined a couple other things in the press release. I'll skip on that, but just before I open up to your comments, I'll just summarize that I would characterize our first quarter financial and operating performance as solid. Not bad, not great, it was a very dynamic environment operationally, certainly market related, and I would add in politically. Our competitive strength through integration and are 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 as 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.

Questions and Answers:

Dave Hughes -- Vice President of Investor Relations

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 at Credit Suisse. On the last call, Imperial had indicated that crude by rail volumes will be cut to zero given lower depths, but then we heard you guys are restarting the crude by rail, so I wanted to understand what changed on the ground.

Richard Kruger -- Chairman, President, and CEO

Yeah, I think it's -- 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 and in the most economic manner possible. So, in mid-March 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. Going forward, if differentials and customers -- if it continues, we'll look to increase, or conversely, if it doesn't make economic sense, we would once again decrease those crude shipments. It's largely kind of 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's some preplanning involved with it, but you can interpret that limited resumption in March as saying, for that [inaudible] of volumes, that made economic sense to move it in that way.

Dave Hughes -- Vice President of Investor Relations

Okay, we also had a question around an update on the Sarnia refinery incident, but I believe you provided that in your comments, so the next question we'll go to is from Benny Wong at Morgan Stanley. Can we get an update 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?

Richard Kruger -- Chairman, President, and CEO

Yeah, I think if I go back to fundamentals, the balance sheet's strong, we're comfortable with our debt level, so if you kind of go through the pecking order, and I would put these two kind of hand in hand, we talked about how our sustaining capital on a year-in/year-out basis averages about $1.1 billion. Our dividend, the annual dividend amount at kind of current rates 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 with beyond that? It's any incremental capital that we think makes good economic sense for growth. Currently, that would be a Kearl supplemental crusher, Strathcona cogen, for example, but beyond that, if and when we have surplus, it will go to buy back as it has now for the last couple years, so I think it would be safe to assume that with a reduced spending on capital overall driven by Aspen, that what that would mean is that will likely mean those monies would be directed to additional buy backs or continuing the buy backs at the rates we talked about. Here again, I commented that we'll have a renewal for the mid-'19 to mid-'20 12-month period coming up, and we'll probably have more -- well, we will have more specific to say about the level of buy back. 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 buy backs at the more recent higher level.

Operator

All right, ladies and gentlemen, if you have a question at this time, please press the *then the number 1 key on your telephone keypad. If your question has been answered of your wish to remove yourself from the queue, please press the # key. Once again, that's *1 for questions, *1. And our first question comes from the line of Prashant Rao from Citigroup. You may begin.

Prashant Rao -- Citigroup -- Analyst

Thanks. Good afternoon and thanks for taking the question. Rich, you alluded to this -- I shouldn't say alluded. You explicitly kind of stated it in your prepared comments about the unintended consequences of curtailment so that inventories are right back where we started. I think perhaps you would agree that there's been a little bit of a thesis drift here with the government going from targeting excess inventories to perhaps claiming victory on price, and rising oil prices have helped with that in addition to the differential. It's early days, but with a 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 those 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 bucket than we are right now temporarily. I wanted to get your thoughts on those two points and then I had a follow up on rail.

Richard Kruger -- Chairman, President, and CEO

Yeah, I guess I'm an engineer versus a politician for a reason, but I'll offer you some thoughts on this. When the program was 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 a higher price, and the other parallel objective was to drive inventories down from their near tank top levels to something more historical. And there were numbers -- instead of 34 or 35, there were numbers like 16-17 million barrels or so kind of thrown out there driving inventories down so as seasonal events or production increases or decreases go that there was a cushion in the system to absorb that that would help take out some of the price volatilities.

But, those to assumptions -- excuse me, objectives were hand-in-hand, and clearly, the increase in price has occurred and some are declaring victory or success of this, but I step back and I look at that and say, OK, price, if you're 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 look at the provincial inventories that here we are four months into this and they're 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, three, six months, 12months, and increasingly, traders are reluctant to buy or sell Canadian crude because it's considered too risky to predict three and six 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 calmly tell you it's been exacerbated by this, and the most vivid example of that is our decision to slow down investments in Aspen.

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 a kind of analogy, it's like kicking the can down the road a little bit. The issue, the fundamental issues have not been addressed. 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 risks 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's 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've spent 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.

Prashant Rao -- Citigroup -- Analyst

That's a very thorough answer. Thanks, Rich. I appreciate that. On the rail then, and this 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. I think the incoming administration has at least talked about maybe looking at that and revisiting the viability of that program. Is there room -- do the rails have the 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 rescind, but to reform the contract that the Alberta Government has where would that capacity go? I think it's been scant on details in terms of how we think about that. Do you have a sense of how that would move around in the market and what that means overall for available rail capacity? And of course this is all assuming the economics work incrementally going forward, but 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?

Richard Kruger -- Chairman, President, and CEO

Yeah, I think -- I'll start out on that is 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 barrels a day capacity. Late in the year, we were ramping it up. We were at 168 and 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's 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. That's what business does. I would suggest that if the business environment's right, industry will meet that need because there's an economic incentive to meet that need. 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.

Prashant Rao -- Citigroup -- Analyst

Makes sense. Thanks very much for the time. I appreciate the answers. I'll turn it over.

Richard Kruger -- Chairman, President, and CEO

You're welcome. Thanks for your questions.

Operator

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

Emily Chang -- Goldman Sachs -- Analyst

Hi, this is Emily Chang on behalf of Neil. Thanks for taking the time today. Can you perhaps 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 phase?

Richard Kruger -- Chairman, President, and CEO

Yeah, well, when we made the decision in November, we were -- just like any Upstream project, the first month, six months or so, it's kind of a slower ramp up on the spend. The first year is a bit lower on capital spend. The last year is to prepare for start-up. The biggest spending years are the couple years in the middle, so we were just getting started on the spending. And so, the question before us and 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're planning to spend about $250 million 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'll put that in a place in a condition where it can be maintained in the short-term, and so that's 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 so 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 the winter construction seasons and things here, what we will be faced with is later this year a decision, do we have business conditions evolved enough where we're ready to ramp it up again? And if so, I think you could look at the amount of money that we would have spent this year, i.e. I said 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'd see likely another year to the delay to start-up. But, I think the time to talk about this will be later in the year as we start racking 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 fuller project execution?

I think in our investor day we -- if I recall, I don't have the page in front of me, but we talked about the $2.6 billion of the project and we said spending will peak in the '19, '20, '21 time period, and they would be roughly $700-800 million or so each year. And I recall that we were something in that, so you'll have kind of three years of the peak capital spend and then the shoulder years will be a little bit less, so we will just be moving that right when we moved it one year, and then the question later this year is that what we do, move it as the one, or do we elect to move it yet another? But, the spend profile has just been shifted out.

Emily Chang -- Goldman Sachs -- Analyst

Got it. That makes sense. And then just moving back to Kearl, so it sounds as though second quarter production will be similar levels to the first quarter given some of the downtime at the K1 facility. You sort of implied if you're still targeting that 200,000 barrels a day of average production quota step up in the run rate there in the second half. Is that sort of similar to what we saw last year?

Richard Kruger -- Chairman, President, and CEO

Emily, it was funny because last year, we talked -- actually, late '17, we talked about a lot of the enhancements we had made to improve the reliability of Kearl to get it from th 180-ish range over the prior few years to the 200,000 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 change, etcetera, etcetera, but the confidence in 200,000 was quite high.

And if you're a sports fan, when we're at the middle last year and we're at 181,000, if you're a US football fan, that might have looked like we were down by a couple of touchdowns at halftime, but we knew that with the second half, particularly the third quarter and in the fourth quarter, we had less overall maintenance work. That's when the productivity is the highest, weather conditions are right, so we said all throughout last year our commitment is unchanged at 200,000, and we delivered on that in the third quarter at I think 244,000, in the fourth quarter at somewhere around 220,000, something like that, and we ended up 206,000 for the year. That's exactly where we are this year. The first quarter is 180,000. The second quarter with turnaround is going to look the same way. At midyear, folks are going to say, do they realize that the second half is going to take 220,000 to get to 200,000?

Yes, we do realize that and our conference is as high this year as it was last year. It's because of the nature of the timing of things. The mines are not steady state across the year, and the reason it's 200,000 again this year is the real big bump up comes with a supplemental crusher and the full interconnects that will occur at the end of this year. So, we look at '18 and '19 as fundamentally the same kit. Now, we're always looking at optimizing. Can we do better? Can we squeeze more? Can we de-bottleneck? 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 206,000 and not a step change. That's a long answer to, yeah, we're quite confident we're going to deliver 200,000 barrels a day this year, and the profile will look quite similar to 2018.

Emily Chang -- Goldman Sachs -- Analyst

Perfect, that's exactly what I wanted to hear. Thank you.

Dave Hughes -- Vice President of Investor Relations

Okay, so we've got a couple more pre-submitted questions, which we'll go through and then we'll go back to the live Q&A to finish this up. So, from Manav Gupta at Credit Suisse, given the progress we are seeing at Kearl with supplemental crushers proceeding ahead of schedule, is the 240,000 kvd guidance for Kearl in 2020 on the conservative side?

Richard Kruger -- Chairman, President, and CEO

I love that question. I love that confidence because it wasn't too long ago that I was being asked -- well, in fact, it might have been just two minutes ago -- can you deliver on your commitment for 200? And then prior years, last year's the same thing. I love that people are now asking, are you going to do better than you've said? Obviously, I'm a little bit tongue-in-cheek as I say this. How we arrived at the increment between 200,000 and 240,000 is we looked back at start-up and said, with reliability events, either the crusher, whether that's chains, whether that's bearings, whether 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 on 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 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, OK, now, what is the next bottleneck? What's the next opportunity to stabilize or enhance? And maybe those increments don't come in 40,000 barrels a day at one time, but maybe they come in 3,000-4,000 barrels a day or 5,000-6,000 barrels a day.

So, with the redundancy we're 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 we are able to do a deliver. So, I don't know that I can quantify anything above that, but the 240,000 was based on good, solid, experience-based quantification of lost opportunity and we're quite comfortable in 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 of the blocks in 2020.

Dave Hughes -- Vice President of Investor Relations

Okay and the final pre-submitted question is from Betty Wong, Morgan Stanley. Your chemicals business had a tougher quarter than we were expecting. Can you talk about the dynamics weighing on margins here and you expect these to be persisting headwinds?

Richard Kruger -- Chairman, President, and CEO

Yeah, good question, Betty. 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 about $185 million in '16 to a high of about $285 million or so in '15. The five years prior to that, our chemicals business averaged about $110-120 million with even a wider swing in high and low, so when you look at our first quarter of $34 million, we're certainly well below our most recent highs and a bit more typical, although a bit higher than our historic earnings.

The driver behind this in the quarter is polyethylene margins. We are down year-on-year. The biggest driver behind that is there's been major new industry capacity in the US Gulf Coast that has been long anticipated. We've seen as crackers and the like have been built and installed, and they're now online. So, specifically, you've seen ethane feedstock costs are higher with increased demand for ethane and you combine that with as new capacities come on and the 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 kind of decrease North American margins.

We've talked before about some of our feedstock cost advantages, some of our location to our customers, some of the transportation advantages we have on them, so it's too early to definitively predict, but going forward in my mind and in our own business models, we would expect an earnings to be closer that $140-150 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 of the market factors behind it and recognize there are some headwinds. It will stay a very profitable business. I just don't know if we'll stay as uniquely profitable as it has been in recent years.

Operator

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

Greg Pardy -- RBC Capital Markets -- Analyst

Yeah, thanks. Thanks, Rich, and the rundown was quite thorough, so lots of notes there. Good work. I got two quick ones for you. One is, as it relates -- just when you're not using your railcars then. Generally, are you able to redeploy those into the US through the Exxon network?

Richard Kruger -- Chairman, President, and CEO

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

Greg Pardy -- RBC Capital Markets -- Analyst

Yeah.

Richard Kruger -- Chairman, President, and CEO

Well, Greg, one other thing. 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, and looked at all the pipe on the drawing board. Everybody else said, there's going to be pipe going every which direction, east, west, south, and we sat back and said, but what if? What if bad things happen? So, you've heard me say many times, Greg, that it was an insurance policy, but the beauty on that is we were able to take 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'll put it up against anybody in industry. 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 a deal and they operate the largest suite 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's 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 much lower fixed cost to our rail operation because we can offload those costs by spinning those cars back. And similarly, when we need them again, we can call.

Now, they're 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 operation, whereas if we didn't have that relationship and you had either bought or leased cars, you're paying for them either way, and if they're idle, you're staring at them, looking at them in the year, and you say, well, we're paying for them anyway, we might as well move them, even if we're losing money of them per barrel. We have a unique situation, and I really attribute it, Greg, that we had the time and the foresight to plan this venture and position it with a great deal of flexibility. We're able to round trip cars on the order of about twice a month, so 15-16 day round trips from Edmonton to the 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 transporting crude more days than they're meandering back home to get loaded again. So, I'm probably giving you more than you asked for on that one, Greg, but yes, the quick answer to your question is yes.

Greg Pardy -- RBC Capital Markets -- Analyst

Yeah, no, that's helpful. Okay, here's the other one. I mean, it's not just Imperial/Exxon, but there's a lot of turnarounds that we're obviously going into now in terms of maintenance and so forth, but given the turnarounds that you 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 through that period of time?

Richard Kruger -- Chairman, President, and CEO

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 we produce 400,000 and we refine 400,000, 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 game. We produce and sell and try to get it to each market, but the buying inventory, the ramping up storage levels is more of a downstream practice in advance of the turnarounds so we can continue to meet customer product needs while those facilities are out of service.

Greg Pardy -- RBC Capital Markets -- Analyst

Okay, last one for me.

Richard Kruger -- Chairman, President, and CEO

Greg, by my count, you said two. That's three. [Inaudible] doesn't like it so much. Go ahead, though.

Greg Pardy -- RBC Capital Markets -- Analyst

Okay, well you're gonna like this question. Kearl operating cost, and this is where we really need that enhanced disclosure on the progress you're making, can you give us an idea where opex was in Q1, ideally in Canadian dollars, and then just what it might be at a 200,000 barrel a day run rate. Even approximate is OK, but I have no idea where your operating costs are at Kearl.

Richard Kruger -- Chairman, President, and CEO

Well, I guess probably because we don't necessarily want you to know what our operating costs are at Kearl. I'm just teasing you. I'm going to have somebody kind of flip and get me a number on that. I would say, though, in the first quarter, they were higher than they typically are. We talked in recent time, for the year 2018, for example, they average -- we talked about kind of in the $25.00 a barrel range US, and then we've talked about the longer-term objective of driving that down through things like autonomous trucks, going from 200,000 to 240,000, driving that down on the order of $20.00 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 180,000 versus at 200,000, 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 I would describe -- one, we had higher energy costs year-on year. That would be about, let's see -- perhaps, somebody keep me honest on the math. That would almost be -- would that be equivalent [inaudible] buck a barrel? Almost a buck a barrel higher energy cost year-on-year. Somebody do the math to check me on that. I'm talking about how many barrels we 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 200,000 to 240,000, so we're going to have to be expanding the mine face 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 dollars a barrel also in the 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 three to five dollars higher than we would have been in '18. I'm giving you 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 province's greenhouse gas cost, and then the preparatory work for an expanded mine front as we prepare for 2020.

Greg Pardy -- RBC Capital Markets -- Analyst

Terrific. Thanks very much. Have a good weekend.

Richard Kruger -- Chairman, President, and CEO

You too, Greg. Thanks.

Operator

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

Phil Gresh -- JP Morgan -- Analyst

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

Richard Kruger -- Chairman, President, and CEO

One of the things I'd say, Phil, is on the normal run rate, it -- 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 month-to-month and quarter-to-quarter in the upstream, it's not a smooth and even run rate. You really have to kind of -- you're almost better to look at second quarter of one year, second quarter of 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 you're coming on kind of the 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've 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'll be operating supplemental crushers and doing some other things, but that 40,000 barrels a day will not be at, for example, the $25.00 a barrel US run rate. They will be less than that. They won't be as low as the marginal barrel of 7,000-8,000 barrels a day because of the -- generally because you're also operating some new equipment. I was just handed something that saying that that 40,000 barrels a day, John, be sure to keep me honest here, that that may add on the order of $90 million a year.

So, if you backed into that, that would say that that's pretty cost-effective at $6.00-7.00 a barrel, so just kind of negate what I just said about it'll be somewhere between the $6.00 and 7.00 and the $25.00. It'll be closer to the $6.00 and $7.00, and that's because the -- you've got the energy to run a [inaudible] but the bulk of the aspect, 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 just complete that. Our goal is to keep on driving that down. I used autonomous trucks as an example. If you go back to John Whelan'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 that $20.00 a barrel or less.

Phil Gresh -- JP Morgan -- Analyst

Okay, got it. Yeah, and I appreciate. I wasn't trying to get so granular on quarters. The question was a little bit broader, which was if I look last year, opex was up $400 million 2018 over 2017 on upstream. I thought maybe a lot of it was Syncrude, but then we see some higher numbers this quarter, so that was more the essence of the question.

Richard Kruger -- Chairman, President, and CEO

I think a lot of it was thin crude, and that's clearly a factor. Syncrude's much lower this year, but I think some of the things that we've seen this year are not necessarily sustainable each and every quarter.

Phil Gresh -- JP Morgan -- Analyst

Sure, and was that $90 million Canadian that you were mentioning for the incremental opex dollars for the 40,000?

Richard Kruger -- Chairman, President, and CEO

Yes.

Phil Gresh -- JP Morgan -- Analyst

Okay, thank you very much.

Operator

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

Dennis Fong -- Canaccord -- Analyst

Hi, good afternoon and thanks for taking my question. Just quickly on Aspen and just to follow up with one of the previous questions, you kind of indicated that the timing with maybe around the winter, the start of winter they're 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 qualifications to make a decision around either kicking the can further down the road, to use your analogy, with respect to capex spending on Aspen and kind of following the existing timeline or moving it further down the line?

Richard Kruger -- Chairman, President, and CEO

I think, Dennis, if you got to step back, I described early on that Aspen had this kind of ace in the hole of rail. I'd like to see rail back in business where it makes money in a free market operating business environment, and so we get that rail back up and running. I'd like 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 quarter-by-quarter and that we would be largely out of the curtailment world at the end of the year when we have a new administration coming in. Some of the objectives the outgoing administration outlined have not been met, inventory levels, so I'd like to see what kind of a world are we? I personally like a free market, a world without government intervention, and then we'll also look at -- there are 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've had some recent 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, all right, are we ready to go on Aspen?

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 the confidence in the ability to always have a way to move Aspen to market in an economical manner. I think that's the gamut of things we'll be looking at and I think as the year goes on and whether it's these calls or other interactions, 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?

Dennis Fong -- Canaccord -- Analyst

Okay, 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 a philosophy around further investment to increment your exposure to, we'll call it, local market?

Richard Kruger -- Chairman, President, and CEO

Well, we've talked about the sustaining capital. In our world on the upstream, sustaining capital largely keeps us flat in terms of production. The oil sands with the long life, low decline are quite unique in that area, the mines can be essentially flat, and then Cold Lake with the level of drilling you can mitigate the decline on it. So, I think those monies will make sense and we'll want to spend that money to take care and feeding 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 and sustaining. What monies above that make sense given the volatility and the uncertainties we see in the marketplace and whether they're upstream or downstream.

Dennis Fong -- Canaccord -- Analyst

Okay, perfect, and then I guess my final question here just is maybe a bit of a fall on to Greg's question around repurposing the rail cars. Just giving a little bit of a dislocation around, we'll 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 rail cars that you would have been using to transport crude by rail would then be potentially repurposed to transport something like refined products instead of actually a raw [inaudible] raw crude barrel? Or is that something that you guys consider?

Richard Kruger -- Chairman, President, and CEO

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

Dennis Fong -- Canaccord -- Analyst

Okay, perfect. Thank you. Those are all my questions.

Dave Hughes -- Vice President of Investor Relations

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

Richard Kruger -- Chairman, President, and CEO

Yeah, I'd kind of reiterate what I said. When I look at the quarter, solid. Not bad. Not great. We can do better. A dynamic business environment, I like the way we're positioned in that environment with integration and balance, and there's no doubt, it's questions around market conditions, prices, differentials remain, and each and everything we do over the subsequent quarters will be about maximizing value. And I 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, so I'll just end it there.

Dave Hughes -- Vice President of Investor Relations

All right, I'd just like to close off 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.

Richard Kruger -- Chairman, President, and CEO

Dave works 24/7/365. You can call him any day, any time of day.

Dave Hughes -- Vice President of Investor Relations

And there's that.

Richard Kruger -- Chairman, President, and CEO

Thanks everybody for your time and interest today.

Operator

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.

Duration: 72 minutes

Call participants:

Dave Hughes -- Vice President of Investor Relations

Richard Kruger -- Chairman, President, and CEO

Prashant Rao -- Citigroup -- Analyst

Emily Chang -- Goldman Sachs -- Analyst

Greg Pardy -- RBC Capital Markets -- Analyst

Phil Gresh -- JP Morgan -- Analyst

Dennis Fong -- Canaccord -- Analyst

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