Imperial Oil Ltd

TSX:IMO

Earnings Call Transcript 2019-Q3

[Operator]

Ladies and gentlemen, thank you for standing by, and welcome to the Imperial Third Quarter 2019 Earnings Conference Call. [Operator Instructions]I would now like to hand the conference over to your speaker today, Mr. Dave Hughes, Vice President of Investor Relations. Thank you, and please go ahead, sir.

[Dave Hughes, Manager of Investor Relations]

Thank you, operator. Good morning, everyone. Welcome to our third quarter earnings call. Let me start by letting you know who's in the room. We have Rich Kruger, Chairman and CEO; Brad Corson, President; John Whelan, Senior Vice President, Upstream; Dan Lyons, Senior Vice President, Finance and Administration; and Theresa Redburn, Senior Vice President, Commercial and Corporate Development.Before we get going, I'd 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 the number of factors and assumptions. Forward-looking information and the risk factors and assumptions are described in further detail in our third quarter earnings press release that we issued this morning as well as our most recent Form 10-K, and all of these documents are available on SEDAR, EDGAR and on our website. So I would ask you to please refer to them.We'll follow the same format today as we have in prior quarters. We'll start with Rich offering some opening remarks, then Dan is going to take us through our financial overview, and then it will go back to Rich to provide some more color on our operating performance. And once we're through those opening remarks, we will go to Q&A.So with that, I will turn it over to Rich.

[Richard M. Kruger, Chairman & CEO]

Okay. Good morning. My comments upfront will be pretty brief. I'll really focus them on the overall kind of pricing environment we've experienced. And if you look at 2019, despite a lot of activities around the world, crude prices were relatively stable throughout the quarter and largely in line with where we are on a year-to-date basis. WTI in the quarter at $56, consistent with year-to-date; Canadian light or MSW $52, also quite consistent with the first 9 months; and WCS at $44, very much in line with the year-to-date. Similarly, third quarter differentials, MSW to WTI and WCS to WTI, largely unchanged from the year-to-date averages of about minus $5 a barrel and minus $12 a barrel, respectively.Year-on-year in absolute terms, WTI and MSW are down considerably from '18, both relatively in the third quarter as well as the first 9 months. On average, light crude prices year-on-year down roughly $10 to $12, and the differentials have been, on average, slightly narrower by $1 or $2. Canadian light crude prices have been generally in line with the kind of a global benchmark of Brent, which is down $7 to $8 year-on-year -- on a year-to-date average. So all that said, the storyline in '19 continues to be heavy crude prices with absolute WCS prices this year on par with 2018 WCS prices. This phenomenon, of course, is largely due to the effect caused earlier this year when the government of Alberta imposed mandatory production curtailment and what that has done to artificially bump up or increase prices over the course of '19.So I think I'll just pause there and turn it over to Dan to go through our financial performance in the quarter.

[Daniel E. Lyons]

Thanks, Rich. Our third quarter net income was $424 million, down $325 million from the third quarter of '18, primarily due to lower margins in the Downstream. Looking sequentially, our second quarter 2019 earnings were slightly over $1.2 billion and included a nearly $700 million gain from the Alberta government's corporate income tax rate reduction enacted in June. Excluding this impact, third quarter net income of $424 million was down $126 million from the second quarter of '19.Third quarter Upstream earnings of $209 million decreased $87 million from the second quarter of '19, excluding the tax impact I talked about above. Lower crude prices quarter-on-quarter drove this decrease. Third quarter Downstream earnings of $221 million were down $37 million from the second quarter of '19, primarily due to lower margins, partially offset by lower turnaround impacts and improved reliability performance. Moving on to cash flow. Cash generated from operating activities was nearly $1.4 billion in the third quarter, an increase of $350 million from the second quarter of '19. On a year-to-date basis, cash generated from operating activities was $3.4 billion, also an increase of $350 million from the 9 months of 2018. It's interesting to note that for the full year '18, we had negative working capital effects of about $700 million. And those have essentially been offset by positive working capital effects year-to-date 2019 of about the same quantum.Moving on to capital expenditures. Capital expenditures in the third quarter totaled $442 million bringing year-to-date '19 CapEx to $1.4 billion. Upstream expenditures of $975 million represent about 70% of the year-to-date total. Spending on key projects, Upstream and Downstream, including the Kearl crusher, Aspen, albeit now ramped down, Strathcona cogen and the Alberta products pipeline, totaled $566 million year-to-date.Recall that after the first quarter, we modified our full year corporate CapEx guidance to $1.8 billion to $1.9 billion, down from an original $2.3 billion to $2.4 billion communicated in January. Our current outlook for the year is consistent with the $1.8 billion to $1.9 billion guidance. Looking ahead, you can anticipate guidance for 2020 CapEx at our Investor Day in Toronto on November 12. Rich?

[Richard M. Kruger, Chairman & CEO]

Sorry about that, talk about dividends.

[Daniel E. Lyons]

I'm going to talk about dividends and returns to shareholders more generally. In the third quarter, we paid a $169 million in dividends at $0.22 a share, an increase from a $155 million at $0.19 a share in the third quarter of '18. We also continued share buybacks in the third quarter totaling $343 million, consistent with our Toronto Stock Exchange approved NCIB program.Our balance sheet remains strong. Total debt of $5.2 billion, a 17% debt-to-capital ratio, and we have $1.5 billion of cash at the end of the third quarter. Earlier today, we declared a fourth quarter 2019 dividend of $0.22 per share payable in the first quarter of 2020.Now back to you, Rich.

[Richard M. Kruger, Chairman & CEO]

Very good. Let's start with the Upstream. Upstream production averaged 407,000 oil equivalent barrels a day in the third quarter. This is 14,000 or 3.6% from the third quarter of a year ago. It's worth noting that the third quarter this year represented our highest third quarter production in some 30 years. And we achieved this result despite significant maintenance turnarounds in the quarter at both Kearl and Syncrude. The combined impact of this work from an Imperial share was an estimated 39,000 barrels a day, 24,000 barrels a day at Kearl and about 15,000 barrels a day, our share, at Syncrude.As we look to the fourth quarter, we would anticipate total production to be in the 380 to 390 kbd range, Kearl and Syncrude, both coming out of major maintenance work in October and November, respectively, and I'll comment a bit more on those turnarounds here in a moment. Moving to Kearl. On gross basis, we produced 224,000 barrels a day in the third quarter. This was up from 207 kbd in the second quarter, and this is our second highest quarterly production on record at Kearl with last year's third quarter being the highest. You may recall, during our second quarter earnings call, I gave some third quarter guidance suggesting we would produce somewhere between 215,000 and 220,000 barrels a day in the third quarter at Kearl. So our actual result's up about 5 to 10 kbd versus these earlier expectations.Year-to-date, we're at 204,000 barrels a day through 9 months, and this puts us a couple thousand barrels a day above our 9 months a year ago. We -- regarding the turnaround, we began planned turnaround at 1 of our 2 plants at Kearl in the first half of September, and it was successfully completed by mid-October, about 33 days in total duration. The work scoped ores, slurry prep equipment overhauls, utility froth, regulatory inspections and then hydro transport line installation and water tie-ins that are activities very key for our supplemental crusher startup and its operation thereafter.Cost of the turnaround work here at Kearl was about $70 million total, $48 million to $50 million our share. I mentioned the duration, 30-some days. And the work scope here was quite similar to the turnaround we had at this plant a year ago and the earlier in the year at our, what we call, our K2 plant in terms of duration impact, cost a bit lower. We're getting better and better at planning and executing turnarounds.I mentioned supplemental crushing capacity of the project. That project continues on schedule for a year-end start-up. So we're coming down to the final weeks in a lot of commissioning work, getting ready. And this, again, will support 240,000 barrels a day annual production in 2020 and beyond. Given the big increase year-on-year, during our November 12 Investor Day, we'll give a sense of what to expect on Kearl, not only in terms of the annual average, but we'll give you the kind of the seasonalized effect in the mining and how that occurs, with first quarter being a bit lower than an annual average due to weather and other constraints. Second quarter often has some maintenance. Third quarter is when we get up and running in a big way. But we will take that 240,000 and give you kind of how we would suggest you consider that from a profiling standpoint.Moving on to Cold Lake. Cold Lake produced 142,000 barrels a day in the quarter, up 7% from the second quarter. Relative to what I had conveyed earlier, this is about 4,000 to 5,000 barrels a day lower than the guidance a quarter ago, largely steam management production variations, and we'll have much more on this in Cold Lake overall again on November 12. Fourth quarter, we anticipate a quarter similar to the third quarter, although somewhat as we get later in the year always the potential for somewhat weather dependent. But at this point, we wouldn't anticipate that to be a big factor in the fourth quarter.Continuing on with Syncrude at 69,000 barrels a day, our share in the third quarter. This was at the high end of our earlier communicated expectations where I had mentioned a quarter ago we anticipated 60 to 70 kbd. The turnaround work on one of SynCrude's 3 cokers, the 8-1, began on August 23, as planned, and it's expected to extend for about 75 days or into the first half of November. A lot of work scope here. Double-digit processing units. The coker itself, of course, a hydrogen plant, a lot of integrity and reliability upgrades, improvements, and our share of cost is a bit more than $90 million. So this is a big bit of work. We commented in the release it impacted production, about 15,000 barrels a day, our share in the third quarter. Then, we would anticipate a fourth quarter impact to be comparable to that.So as we look to the fourth quarter, we would expect production similar to the third quarter's 69,000 barrel a day. And if you roll that all together, that would point to a full year outlook of plus or minus about 74,000 barrels a day, our share. And a year ago at our Investor Day, we pointed to the improvements we were striving to achieve at Syncrude and suggested a target over time of 75,000 to 80,000 barrels a day at Syncrude. We're kind of bumping up against that now in 2019.Crude-by-rail. With the -- when I thought through some of the comments I'd make here today, we have even more information on what the government announced yesterday. But I think it's important to put it into context with the government of Alberta's curtailment order over this year, crude-by-rail economics were certainly damaged and have largely throughout the third quarter continued to be weak. Shipments in the quarter for us declined each month from 76,000 barrels a day in July to 35,000 barrels a day in September, 52 kbd average for the quarter. And in fact, our last rail shipment was made in late September.And at this point, based on kind of the -- an outlook, fourth quarter rail shipments would have been expected to decrease from the third quarter level. Well, with the TC Energy's key based -- Keystone leak government's announcement yesterday, I would say the fourth quarter is -- I would have more confident saying it's kind of to be determined at this point than giving any specificity on what we expect rail movements to be. But I do think the quarter itself and over the course of the year the volatility has continued to highlight this negative unintended consequence of curtailment overall.Provincial inventories over the quarter have stayed and continued to drop a bit. You'll recall late last year, at the end of the year and then largely through the first 4, 5 months of this year, provincial inventories were at or near tank tops, roughly 35 million barrels or so. Inventories have declined over the past several months. The most recent data that I've seen per Genscape would report inventories somewhere 23 million, 23.5 million barrels in kind of in the second half of October.And that, we believe, provides the industry cushion to continue to alleviate or reduce curtailed volumes and incent additional export capacity through rail or however. And there's a lot of flex in the system that did not exist late last year, nor largely for the first several months of this year. On August 20, the government announced some revisions to the curtailment program, increasing the operator threshold for those subject to curtailment from 10 kbd to 20. So as a result, we are 1 of only 16 producers in Alberta that are subject to this order.Moving on, on the Downstream, in refining, we averaged 363,000 barrels a day throughput in the quarter. This compared to 388,000 a year ago. July and August, the first couple months of the quarter, we're in the 390,000 range, September closer to 310,000, to get to that average. September was impacted by start of a planned turnaround at our Nanticoke facility. Specifically, that work started on September 9, part of regular periodic maintenance activities. 4 large units are out of service for catalyst replacement, other general maintenance activities.The impact was an estimated 27,000 barrels a day or so in the third quarter and will be even more so in the fourth quarter, plus or minus 50,000 to 60,000 barrels a day in the fourth quarter as we complete this roughly $90 million turnaround over a roughly -- a 70-day duration. That cost is a bit higher and the 70-day duration somewhat longer than I had suggested in the second quarter as we've had a bit more discovery work in just some challenges on workforce and productivity over it. But our current estimate would be about $90 billion -- or $90 million, excuse me, and about a 70-day duration.At Sarnia, we also had a turnaround start very late in the quarter, September 29. This is about a 55-day activity with restart in the second half of November. The work scope is more limited here as 1 key unit, the fluid cracker with inspection and repairs. On a throughput basis, the impact is quite minimal for the third quarter, of course, and also quite small for the fourth quarter just based on the nature of this work. Total cost of this turnaround is anticipated to be $45 million to $50 million, 55 duration. And these are precisely the estimates that we had shared when we outlined we'd be going into this work during our second quarter earnings call.A little bit of an update on the fractionation tower incident that occurred at Sarnia in early April. Work continues to replace the tower. The new tower has arrived at Sarnia in mid-October. It's been successfully lifted into place. Installation and commissioning is ongoing, and we're on target for a restart expected sometime in the first half of December. And the throughput impact of it was -- I commented earlier, it was about 35,000 barrels a day in the second quarter, and it was about 20,000 barrels a day in the third quarter. It'll have about half that impact in the fourth quarter before we're up and running in a more regular manner. The cost and margin impacts of the Sarnia tower are generally consistent with our second quarter earnings call, what I did feel at that point in time.If I look out over the remainder of the year and factoring the comments I've just outlined, we would anticipate fourth quarter refining throughput with the major turnaround work continuing and ramping up and the commissioning of the new tower at Sarnia to be in the plus or minus about 320,000 barrels a day range, and that would put a full year estimate of 350,000 to 355,000 somewhere. The last time we were at that level goes back to kind of 2016 when we had very similar high turnarounds in that year. And in fact, 2019 is a much higher than a typical maintenance year with major work at 2 turnarounds at Sarnia and a major turnaround at Nanticoke. And I'd say the good news is that we can expect lower turnaround impacts in 2020, 2021. This is a topic for another day, but the timing and what you see this year is largely related to the periodic cycles, 3-year, 5 year, 7 year, whatever they happen to be, on various units at our specific refineries.On petroleum product sales, we were 488,000 barrels a day in the third quarter, up 11 kbd from the second quarter. This, again, is consistent with the -- what we had earlier communicated in terms of somewhere between 480,000 and 500,000 barrel a day expectation. The Sarnia refinery addition or issues, excuse me, in addition to the higher than the planned maintenance across our sites is really largely behind where we were in the third quarter of this year versus where we were in the third quarter last year. And the third quarter last year was a record high, a 30-year record high for us in terms of our product sales.Over the course of the third quarter, volumes -- sales volumes increased coming out of planned and unplanned outages in the second quarter. But then here, again, they were impacted in September by the start of the turnaround in Nanticoke. Looking over the rest of the year, fourth quarter, I think something in the 480,000 barrel a day range would be a pretty reasonable assumption, the end of the summer driving season. And if we look back over the last 5 years or so, a 480,000 range would be consistent with kind of the mid-range of what we have seen in recent years' history in terms of fourth quarter sales.So with that, I would characterize the third quarter financial and operating performance as generally strong, but more particularly in the Upstream and also in terms of kind of cash flow from operation, Upstream performance, record third quarter production, even though we have significant maintenance activities and Downstream performance continued to recover from the Sarnia tower incident and was impacted by planned turnaround, again, most notably at Nanticoke.So I think I'll stop there, turn it back to Dave, and he can kick off our Q&A.

[Dave Hughes, Manager of Investor Relations]

Okay. Thank you. We did have some questions pre-submitted. But when we had to look through them, felt that probably the remarks that you just heard addressed them for the most part. So I think, operator, we're going to move straight to the live Q&A.

[Operator]

[Operator Instructions] And our first question comes from the line of Emily Chieng with Goldman Sachs.

[Emily Christine Chieng, Associate]

My first question is just around the crude-by-rail, in particular with respect to the announcement yesterday from the government. Is there a change in strategy for Imperial to increase utilization of rail? Or is it still really an economic decision here? How do we think about the curtailment versus that?

[Richard M. Kruger, Chairman & CEO]

Thanks, Emily. Just kind of stepping back a little bit. We've long -- as opposed to curtailing production capacity, we've long supported increasing takeaway capacity, whether that's new and expanded pipelines or new and expanded crude-by-rail. And that really is behind, if you go back several years back, our decision to build a rail terminal in 2013. Our preference in all this is that market forces and market factors would be at play here and that, that would incent the industry to make either the necessary decisions or investments. So yesterday's announcement, it's early. We're still going through it. I would say, in a form of a compliment to the government, they're trying to make the best of a bad situation. They're playing the cards that were dealt. The bad situation is that we're in curtailment in the first place. I've highlighted before multiple times that 1 of the negative unintended consequence is the impact on crude-by-rail economics. With economics over the course of this year, the incentive has not been there to build new facilities, and the incentive to utilize existing facilities has been highly volatile.So getting back to what was announced, we need to dig into it deeper to understand the devil's in the details, and there are a lot of provisions in there. As I commented, we're 1 of only 16 companies subject to curtailment. And by my understanding, we have industry's largest rail terminal. It's been significantly underutilized, and we would prefer to use it. So we will strive to maximize the value from an Imperial standpoint of the announcement and whatever it means on us. But from a strategy standpoint, everything we do is based on, does it add value and make money for our shareholders. And that has been true in our rail utilization each and every month of this year. And I'd say going forward, it will be true again. We'll look at it across our business, the Upstream, the rail terminal itself, and the actions we take will be about maximizing value.

[Emily Christine Chieng, Associate]

And just one follow-up, if I may. What is the trajectory of deferred taxes over the next couple of years? Can you remind me sort of the level of roll-off that you're seeing?

[Richard M. Kruger, Chairman & CEO]

Yes. We're going to detail a bit more of this on November 12, but let me ask Dan to comment today.

[Daniel E. Lyons]

Yes. As you know, we've had a significant tax loss carryforward that we've benefited from over the last few years on a cash flow basis. We expect to chew through most or all of that in the fourth quarter. So going forward -- the way cash taxes work, there's a bit of a lag. So we expect 2020 to be relatively low cash tax year. But by 2021, you'll probably start seeing cash tax rate closer to the statutory tax rate as we've lost the benefit of that tax loss carryforward.

[Richard M. Kruger, Chairman & CEO]

As I said, on November 12, we can -- we'll -- we're still kind of going through some of that work right now, and we can comment further on it, if it's warranted.

[Operator]

And our next question comes from the line of Prashant Rao with Citigroup.

[Prashant Raghavendra Rao, Senior Associate]

Rich, I wanted to wish you all the best, but we'll see you in November, and Brad wanted to say hello and welcome and look forward to speaking with you.

[Richard M. Kruger, Chairman & CEO]

We'll have his coming out party in November when we're all in Toronto.

[Prashant Raghavendra Rao, Senior Associate]

Sounds good. I wanted to follow-up on the crude-by-rail just a little bit. I think a longer-term question here, there's been a lot of moving parts. We had a lot of recent announcements, as you mentioned. But 2 points. One, we get a lot of questions on is sort of the expectations, and I think you talked about this a little bit. For the government contracted volumes transferring fully into the private sector, where they should have been arguably all along. And secondly, total kind of ceiling capacity on rail takeaway. There's been sort of a firm number north of 500,000 barrels per day can go by rail over -- as it gets contracted or as it starts to fill up. But do you think now that landscape is changing that we're going to see the rails free up a little bit more in terms of what they bring to the table that you can bid on? Or has there -- is that sort of static for other structural reasons?

[Richard M. Kruger, Chairman & CEO]

Yes, fair question. And let me just kind of step back briefly. When you look at rail economics, you often see in reports or in the media, there's oftentimes a reference to differentials as it relates to WTI versus WCS. And what it really gets to in terms of the economic incentive is take a lifetime barrel, take a barrel of WCS in Alberta and a barrel of WCS in the Gulf Coast and their relative valuations. And that difference is what determines the incentive for various transportation modes, particularly rail. And so oftentimes, I see too often folks reaching conclusions on a WTI-WCS differential. It's really not the pricing basis that we decide is rail in the money or is it not in the money. Now -- and I think that -- I just -- I offer that as a little bit of a tutorial.But now getting back to the capacity, it's been largely reported, and I think there's a general consensus that there's 500,000 to 600,000 barrel a day of the existing rail capacity. And that capacity comes about in a whole host of ways. The terminal itself, it comes out and other sufficient railcars, is there sufficient people and power? So it's not any one -- you don't look at the nameplate of a terminal and say that's the industry rail capacity. And capacity varies over time. When it's being utilized and all the cars are in service and people are employed and that's when you get to the 500,000 and 600,000, but I don't think -- 500,000 and 600,000 barrels a day. But it's not a switch that you can flip on and off.So industry more recently has been at 300,000. There was suddenly a call on 500,000 to 600,000. There's a ramp-up required. And that can vary by individual operation, whatever arrangements they have with the CPs, the CNs, and that can be on the order of several or many months. But I think if there was a properly incented crude-by-rail business, the consensus is that there's 500,000 to 600,000 barrels a day of -- of existing capacity available for industry. But you have to get that differential in a range where not only on operating on variable costs, but we all see -- you can make money in a crude-by-rail. And that differential of WCS in the 2 locations has been very, very tight for the bulk of this year.So you've seen parties going up and down on rail, us, most notably, and it's all been on variable cost basis, what makes the most economic sense. But you haven't seen anyone putting big new commitments behind new rail because those -- that differential incentive is far from what it takes for a full capital recovery of new rail. So that's kind of a windy answer to your question, but I -- we need to let market forces come into this that differential exists in a confident way where companies like ours and others look to either expand what they have or invest in new.I think the government continuing to relax curtailment and allow more barrels to flow is certainly a part of that. We would urge and have urged the government to go further. Put more -- relieve all constraints, let those barrels get into the market, let the market settle out with inventories where they are. We think there's flex in the system to avoid a price blowout that everyone -- that parties would be concerned about, like it happened last year. But let the market work, and we think it will normalize in a place where rail is an ongoing and sustainable part of industry takeaway capacity, certainly, until and perhaps after new pipe becomes available. That was a long answer. I hope I got kind of near you.

[Prashant Raghavendra Rao, Senior Associate]

I think there's a lot in there, and I appreciate it, as always, Rich. One really quick follow-up. There's been some -- looking at sort of your -- what you're supplying in the U.S. -- to the U.S. Downstream, there's been some reports that Exxon is looking to market the Billings Refinery. And just wanted to see if you could comment maybe on what that means for your integration level, what potential impact or lack of impact that may have on that -- on your production barrels where they land?

[Richard M. Kruger, Chairman & CEO]

Certainly, if I started our own refineries, we -- out east -- and I promise I'll get to your question, but out east, Sarnia and Nanticoke, 2 facilities, but we have a level of integration with those facilities that we can take advantage of scale, processing capabilities, delivering products to the market, and there's a value in that. Strathcona, a big high-performing stand-alone, but because of being in the same part of the world notionally as Billings, we're -- through our relationship with ExxonMobil and commercial transactions, we've been able to use Billings at times to kind of help in some of our marketing commitments, particularly in terms of ensuring we can provide supplies to customers while we do periodic maintenance work at Strathcona. So projecting what Exxon may or may not do with Billings, I probably can't go that far. But if it were to change hands, we would continue to do what we always do and look at commercial arrangements with other parties, whether they're ExxonMobil or other third-parties that would allow us to ensure we meet all our customer demands in the highest reliable manner possible while we periodically do work on our facilities. And that would be largely -- in a Billings case, that would be largely -- have a Western or a Strathcona impact.

[Operator]

And our next question comes from the line of Dennis Fong with Canaccord Genuity.

[Dennis Fong, Exploration and Production Analyst]

First thing there, Rich. It just seems maybe reading between the lines with respect to your commentary around crude-by-rail as well as kind of the -- we'll call it, the government adjustment to the mandatory curtailment situation, it sounds like you view there's still to be a fair amount of potential risk associated given that the fact that the curtailing program itself hasn't been completely alleviated. Should I translate that into how you guys feel about capital allocation and what you guys are thinking about spending on, namely potentially the Aspen project they are in?

[Richard M. Kruger, Chairman & CEO]

Yes. I think the -- we need to see curtailment go away from a -- we need to see the government out of modifying, altering the market and affecting thoughtful decisions that we make where we look and evaluate market conditions, future projections, the quality of our assets. We take in the -- in oil and gas business, we readily take a whole series of risks, but what makes it hard when there are incremental risks added that are beyond our ability to predict and/or manage for. And curtailment, as I've said before, has been one of those. With a stroke of a pen, it altered the equation.So for the -- there's a lot talked about investor confidence. I won't speak for other investors, but I will speak from Imperial Oil. For our confidence to continue to invest large amounts of capital money on growth, particularly in the Upstream, you mentioned Aspen, we need to see the government out of the business. And crude-by-rail, I described it, and it was moderately complementary. It's making the best of a bad situation. Government inherited this, a long history, a lot of opinions on it. But in a sense, what we worry about here is crude-by-rail and kind of how it's being worked to get special production allowance, are you trading one form of government involvement for another form of government involvement? So yes, it concerns us. It's going in the right direction, anything that provides incremental takeaway capacity.But as I said, the devil's in the details. We'll look at those, and we'll -- whatever the rules are, we'll operate within those rules. So I'm not trying to read or give you messages between the lines yet. It's too early to predict the outcome in markets when you start changing parameters, and now another parameter has been changed. Let's just see what impact it has on the market, and we'll make investments accordingly. I don't -- as I say all that, I'm not trying to be additionally negative to any comments I've said over the last 9 months. I've been quite consistent on that. And I recognize how we got into this situation. And we just continue to hope that we get out of it as fast as possible. And this government has said that, that my statement there is aligned with its intents, and that's what we really hope to see in the -- as near future as it possibly can be.

[Dennis Fong, Exploration and Production Analyst]

Great. And then just a quick follow-up there is just on the supplemental crusher, it sounds like from your prepared comments that the hydrotreating component was online and that you're still expecting the supplemental crushing unit there to come onstream before the end of the year. Is there a subsequent turnaround that you have to engage in to be able to attach all of the equipment and so forth? How should we be thinking about going into year-end, especially pending colder weather and the final bits of commissioning around that piece of equipment?

[Richard M. Kruger, Chairman & CEO]

Yes. No, there's not any supplemental work. In the 2 turnarounds we did this year, 1 that we just completed on 1 of the plants and the facilities and the other earlier in the year, we did work in those turnarounds in preparation some of the early tie-in work. So we sequenced the supplemental crusher project so that we could take advantage of planned maintenance intervals to prepare for it. So what we'll be doing -- of course, there's 2 new crushers, 1 on each of the facilities. So we'll be starting up one of them initially with the other to follow shortly thereafter. And when I say year-end, there's actually kind of 2 start-ups that occur. But we're on target for -- whether the first one is in the last 2 weeks of the year and the second one is in the first 2 weeks of the year, I'm not quite there yet. But they will be starting up consistent with the year-end and an ability to deliver 240,000 annual average next year, and there's no incremental turnaround activities required for those start-ups because we've already completed the necessary work in earlier turnarounds.

[Operator]

And our next question comes from the line of Jon Morrison with CIBC Capital Markets.

[Jon Morrison]

Rich, normally the calculations on whether to ship on rail are fairly simple, and that to your point, you've got a regional diff and when that location differential either covers your full rail costs or variable, depending on how you want to look at it, you elect to ship or not. But things are obviously different here with the railroad curtailment and that you get to capture an Upstream netback that you otherwise wouldn't be able to. So can you just give any sort of goalpost how you think about what is a little bit more complex economics in this type of a dynamic is the math isn't just as simple as in the money or out of the money? So any early thoughts you can give would just be helpful.

[Richard M. Kruger, Chairman & CEO]

Yes. Jon, you're spot on. It does introduce another considerations, and I've seen some others' comments in it. You can describe it as it almost introduces kind of a second market because there's a different set of considerations. You're looking at not only how you ship, but in many cases, you're looking at do you produce and ship or do you not produce, if you're talking about curtailed volume? So you're more directly bringing kind of Upstream or production economics into the equation. And that's really why I said earlier is that we -- for us, we've got the big terminal. So we've got the rail capacity. We can utilize that for our own equity volumes or if there are third-parties, that if it's in their economic incentive to come talk to us about their utilization. So we have that ability to use the terminal as a service provider to others.And then for our own volumes, we can look at it, and we'll make the same judgments that you've just kind of hit on, where it's not just in the money, out of the money, but can we or should we produce incremental barrels through the use of that terminals? But I would say -- and, of course, these announcements always come out when you're busy. And we had Imperial Oil's Board of Directors here. And I've been pretty busy the last 24 hours. And I got to get into the details with my team on this thing to understand that if you do this, that precludes you from doing something else. And there are those kind of provisions in this. So I'm not trying to predetermine an outcome because, in all honesty, I just haven't -- my team has been going through it over the last 24 hours. And Brad and I need to sit down with them to get in and say, okay, what does this mean to us? How do we -- with whatever the rules, provisions are, how do we best compete in that and make most money, whether it's providing third-party services through the use of our rail terminal and/or whether it's producing incremental barrels that would otherwise be curtailed? So I just -- it's -- we're just too -- it's just too hot off the press for me to get more definitive than that.

[Jon Morrison]

Okay. There's been a lot of speculation both Brad's past experience in M&A with Exxon and maybe that being a precursor to Imperial pursuing more inorganic growth in Canada on a go-forward basis. Can you share any thoughts on whether people should be placing any weight into that thesis? Or is M&A just part of Brad's very lengthy CV, and we shouldn't overthink the recency effect?

[Richard M. Kruger, Chairman & CEO]

Absolutely. Well, first of all, Brad and I've known each other for literally 30 years this year. We have worked together on -- in many capacities, many assignments, several continents. And I smile when I read that because Brad's been with the Exxon and now Imperial for 36 years. And for 4 or 5 of it, he's worked in that, but I'm kind of interested in why people aren't talking about his other 31 years and all of the other things he has done. I look at it. I'm smiling as I look at it. I look at his experience in that area along with all of his other experiences over the course of 36 years is what is positioned him to be an outstanding candidate for this job. And is that trying to be any signal that he's -- there'll be more or less M&A, I think that's grasping for straws. I don't think that -- well, I can go beyond what I think. That was not part of the judgment and the determination from an Imperial Oil Board of Directors to elect Brad to his current position. But it's the totality of his experience internationally, various parts of the business, Upstream, Downstream, a series of commercial roles, a series of operational roles that made him the strong candidate that he was for being named President and then succeeding me in a couple of months. And on November 12, Brad's going to -- as we say, we're going to kind of unveil him. He's going to have some things to say. And I think if you -- if that question is still out there, that would be a good time that we can -- or Brad can expand on it further.

[Jon Morrison]

Rich, even given that background, there is a lot of, obviously, public small conventional producers that have seen massive dislocations in their stock prices. Does that interest you from a cash and cash return opportunity of buying some of those smaller platforms that are somewhat disadvantaged right now, especially in light of the fact that you could probably tie some of that production into Strathcona and become more physically integrated? Or is your focus really on what you focused on recently, which is the heavy projects where you're -- you were the operator?

[Richard M. Kruger, Chairman & CEO]

Well, our focus at the simplest level is adding value, and it's really however we can add value. And we have a big integrated asset base that gives us lots of opportunities to improve performance, capture market opportunities as Upstream and Downstream incentives move around and particularly in kind of interesting and volatile times like today. But beyond that, we also have a series of internal opportunities. The Upstream ones have been largely named kind of things, the Aspens, the Corners, things like that. The Downstream ones, we've increasingly talked about some of the things we've been doing, particularly in the logistical area to strengthen our ability to serve markets. But then you look at those, can we also have and continue to look at external? So you've talked about various size participants in the market.I think if you'll look at it and you'd say, well, what might be we interest -- are interested in adding to our portfolio that's not in our portfolio today? Look at our business model and think in things -- in terms of things that are larger, longer life, high-quality resource, things that we think we can bring our -- either our scale, our historic expertise or our existing or evolving new technology to make it even more valuable than what its current owner might have. If you think in that framework, those would be the kinds of things we would be interested in. We're less likely to be interested in things where it's simply a price play, where we're betting prices are going to be x and somebody else is betting they're going to be 0.8x, so do that.It's things where we can take it and add value above and beyond what others could be. So I get this question quite often. I can't point to, well, look at what we've done or bought in the market over the last few years. And I think you can interpret that as, as we've looked at things -- I mean as we look at what we have, we're comfortable with what we have and its value today and for future investments, and we haven't found anything out there that we just felt we've had to have. Now does that change in the future? That's a bit more speculation. But we always have our nose to the ground, our ears to the ground, our nose to the ground in terms of looking for opportunities that can add value.

[Operator]

And our next question comes from the line of Benny Wong with Morgan Stanley.

[Benny Wong, Vice President]

I've just got a couple questions around some of the pipelines we're seeing in the news. One is the Keystone. Obviously, we've had a disruption there. Just can't remember you guys are actually a shipper on that. How does that impact your business in any way? And the second one, I think we've seen some positive court rulings out of Michigan pushing back efforts to decommission Line 5. In your perspective, is that kind of cleared a risk around that pipeline?

[Richard M. Kruger, Chairman & CEO]

Thanks, Benny. Base Keystone, we've all read over the last couple days that what's happened in the TC line, I guess it was Tuesday night, things like that. And we're all industry. We're all very interested in what TC finds, concludes and they want to do about it. It's a material part of the takeaway capacity. I have said before we ship. We have contracted space. I don't think I've ever detailed exactly how much, but it's important not only to industry, but important to us specifically. So when something like that happens in a system that's tight, it's all hands on deck for what do you do to keep barrels flowing, whether those are barrels that are Upstream equity barrels or whether those are barrels that we've purchased or are moving for delivery to third-parties in Downstream businesses.So not knowing what the situation is on base Keystone, know how it will be offline or how long it may be offline, what our typical approach is, we look at tiers of preparation. What can we do in the immediate, in the next several days, and what can we do if this is something that goes on longer than that? We've got fingers crossed that it's not something of a longer duration. But I think it comes back to pointing on the absolute necessity of added takeaway capacity out of Canada. And that's why, whether that's expansion of Line 3, whether that's TMX, whether that's Keystone XL, the industry -- Canada and industry and each of our participants, we need that. So I think this highlights that one. And going back to your original question, yes, we do move -- move barrels on base Keystone.The Michigan, the positive news out of Michigan, the state court ruled on the legality of continued operation of Line 3. I think I also saw that the Attorney General is contemplating further appealing that. Line 5 is important to us. It's important to many others as well, not only north of the border, but south of the border. And so I think I'll leave any specific comments on that to Enbridge and its dealings with the State of Michigan. But in today's world, we take all positive news with a smile on our face, and I smiled when I read that one.

[Benny Wong, Vice President]

Great. I appreciate those thoughts. And the follow-up question is really on Cold Lake, which doesn't really get a lot of airtime. Just wanted to get a high-level update around that asset there. And if I remember correctly, it was an asset a couple years ago was experienced fluid excursions, and that was maybe moderating volumes there. Are we -- is that kind of situation is already passed that? Or not -- could that be an area where we could see higher volumes with the relatively little spend going forward?

[Richard M. Kruger, Chairman & CEO]

Yes. We will -- on November 12, John Whelan, our Senior VP of the Upstream, is going to give a pretty deep dive into Cold Lake, not only current performance and then -- but where we expect going forward. And what you commented on relates to Nabiye, the most recent expansion to Cold lake and what we experienced with steam injection, pressures in volumes and some of the kind of, I'll call it, the caprock or the top seal in not being able to put as much or as high a pressure steam in the ground as our original plan or for fear that, that steam wouldn't stay there, that it would go to the shallower Grand Rapids reservoir. That has been an issue from the beginning. It continues to be an issue. And what I'd say is at the risk of doing that nearly as good a job as John will do if I can hold off kind of the further conversation on that to November 12, I can commit to you John will take you through good detail on it, where we are, what we're doing, and then, most importantly, kind of what you can expect going forward in terms of production operations at Cold Lake, not only quarter-by-quarter, but over the next several years. And I might be tempted further that we've been so busy on the quarterly call and all this, that we're working on that November 12 presentation as we speak. So I can't go much further because it's -- I'm smiling looking at John. It's a work in progress right now.

[Operator]

And our next question comes from the line of Mike Dunn with GMP FirstEnergy.

[Michael Paul Dunn, Director of Institutional Research]

Rich, just wondering if you could provide an estimate of how much you think the Imperial's -- I guess, your gross production at bitumen -- at Kearl and Cold Lake has been restricted due to curtailments this year. And second question, unrelated. I've never asked this before of you or your predecessors, but can you just walk us through a little bit what the process is like in terms of the nomination and acceptance of a new CEO at Imperial? I mean, it's -- I guess, the tenure is typically of several years, but just wondering if there are candidates that are brought to the Board, the Board decides or if it's more of a mutual discussion between Imperial, Exxon and Imperial's Board?

[Richard M. Kruger, Chairman & CEO]

Sure. Mike, on the -- well, those 2 questions are kind of opposite end of the spectrum, my friend. They are -- one is a very specific, but I like it. Thank you, Mike. The first one, recall, in the curtailment world, the orders are issued by operator. So we are the operator for both Cold Lake and Kearl. So we get a production allocation each month that's combined for those 2 assets, and we have the flexibility to decide which asset, how much within the construct of that curtailed order. And so that gives us flexibility. And I have not talked about actual volumes that we've not produced throughout the year, very intentionally because what we have been doing is we've been looking at when we do work, what work we do and how can we sequence that to minimize the volume impact because of the flexibility of 2 large assets, significant maintenance activities at each asset and how can we dovetail those in a world where you're getting month-by-month quotas, not quarters or 6 months or annual. So you're having to optimize month by month. So I've not gotten into explicitly what limits that has had to us on production, and I prefer not to. But what we have done is we worked awfully hard to minimize those impacts. But that's not to say that curtailment has had a minimal effect on us at all. It's had a big effect on us in terms of the added work of doing things that might not have been the preferred plan, so that we can minimize the negative effects on it.Now the process on my replacement, I will -- I'm coming up on 7 years. I think it's important to note, in Imperial's history, including me, there have been 2 non-Canadian CEOs, and so it's not the norm, and Brad will make the third. So I think you get 3 in a row, folks assume that's a trend. That may or may not say anything about the future. It's important to note as a publicly-traded company with an independent Board of Directors, it is the Imperial Oil Board's responsibility and decision for senior management executive succession planning. And so it's that group that makes the decision on who is in my job and when it's time for me to move on who replaces me. That dialogue, of course, would look at within Imperial, individuals within Imperial, their readiness, their capabilities. If the Board wants to broaden that, we have the benefit of this unique relationship with ExxonMobil. And because of ExxonMobil's ownership in Imperial, they're obviously very interested and would likely have thoughts on who best individuals in the job would be.So in this particular case, the Board engaged with ExxonMobil. That's not something that just happened over a month or so. I can attest to it because I've been a part of it. That's happened over a period of time. I had a significant input in that, which I'm very pleased on that. And because my interest is what's in the best interest of Imperial Oil for the long term. And as I've kind of insinuated, I'm really pleased that it's Brad. I've known him forever. We have -- we're not only professional colleagues, but we're personal friends. I have the utmost respect in his capabilities. And I think what we've been working on for the last 1.5 months now, what we'll do for the next 2 months, is to make that as smooth, effective transition as possible. Brad's participated now in 2 full Board meetings, and he met the Board months ago before that. And that is helping not only on the internal aspect of it, but we've been spending time with major investors. November 12 will be a big day. So increasingly, we've been spending time outside the company to also ensure that part of the transition is as smooth and effective as possible.

[Operator]

And our last question comes from the line of Asit Sen with Bank of America.

[Asit Kumar Sen, Research Analyst]

Rich, I had a quick question on whether you have any thoughts on the merits of diluent recovery unit or DRU. Any thoughts on the economics that you might have worked on? And any advantage that you see, particularly given your rail footprint, infrastructure and relationship with Exxon?

[Richard M. Kruger, Chairman & CEO]

Sure. This is something that a few years back we talked about it a bit more and I'd say was probably a little bit higher on our priority list in terms of working it. And then as I've described before, there are so many assumptions on a DRU. And a lot of the economics of it depend on the differences between big numbers, when you start taking one big number, subtract another big number, what's left. And what I'm talking about is transportation rates. So if you ship something without the diluent, you're shipping round numbers, 75% of the barrel without having to transport the diluent. So you're looking at what are dilutes cost availability, and then you're looking at, okay, when you get that product, whether it's neat bitumen or diluted bitumen to refiners, what's its worth in the market? So what a refiner is willing to pay for it? What can they get out of it?And over the last couple of years, all of these inputs that go into a DRU economic evaluation. It's been a bit of a jump ball on so many things, transportation, rail versus availability of pipe, cost of rail, economic incentive of rail versus cost and economic incentive on pipe. Refining, you go -- you think about the U.S. Gulf Coast market, availability of heavy crude supplies from other sources. So there have been so many variables in this thing that I would say right now, DRU, a detailed evaluation of it is not at the top of our work plan. That's not to say it won't be at some point in time, but it's not today. You rightly point out we have a rail asset, and that's a very valuable asset, and that can be very valuable, whether it's shipping diluted bitumen or neat bitumen. And so it's something we will continue to look at, but I think it's safe to say it's -- I wouldn't hold my breath anticipating any big announcement on a DRU in the foreseeable future. That's something that we start getting serious about, we'll start talking about it well in advance of a final decision.

[Operator]

And that does conclude today's question-and-answer session. I would now like to turn the call back to Dave Hughes for any further remarks.

[Dave Hughes, Manager of Investor Relations]

Thanks, operator. Just before we end, I'll pass it over to Rich for any closing comments.

[Richard M. Kruger, Chairman & CEO]

Well, thank you for your question, your time today. I made reference several times to November 12. I wasn't trying to necessarily kick the can down the road, but we look forward to hopefully seeing many of you in person and others, if you're not in person on the line. We've got a fulsome day planned, and we'll get into our -- not only our business of today, but our outlook for the future and our plans in great detail. I've also commented -- I jokingly said it will be Brad's coming out party a little bit. He and I have been spending a lot of time together. I didn't think it was fair to put him into the mix on the call today, but you can expect to meet him, hear from him on November 12 and thereafter. So thank you very much, and hope to see you soon.

[Dave Hughes, Manager of Investor Relations]

Thanks, everybody. As always, if you have any further questions, do not hesitate to contact the Investor Relations team here. Thank you.

[Operator]

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.