Cenovus Energy Inc

TSX:CVE

Earnings Call Transcript 2018-Q3

[Operator]

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's third quarter 2018 financial and operating results. As a reminder, today's call is being recorded. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Cenovus Energy.I would now like to turn the conference call over to Mr. Kam Sandhar, Senior Vice President, Strategy and Corporate Development. Please go ahead, Mr. Sandhar.

[Kam S. Sandhar]

Thank you operator, and welcome, everyone, to our third quarter 2018 results conference call. I would like to refer you to the advisories located at the end of today's news release. These advisories describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today, and outline the risk factors and assumptions relevant to this discussion. Additional information is available in our annual MD&A and our most recent annual information form and Form 40-F. Quarterly results have been presented in Canadian dollars and on a before royalties basis. We've also posted our results on our website at cenovus.com.Alex Pourbaix, our President and Chief Executive Officer, will provide brief comments and then we will turn to the Q&A portion of the call with Cenovus' leadership team. Please go ahead, Alex.

[Alexander J. Pourbaix, CEO, President & Director]

Thanks, Kam. I'm pleased to say we delivered excellent performance in the third quarter. Our upstream assets are running extremely well and the refining business continues to show its value. Our financial results were also strong, especially from the downstream side of the business. And our free funds flow grew by 30% compared with the same period last year even as differentials widened. Overall, we managed the things that are within our control very well.I want to cover some of our highlights from the third quarter. Our net debt is down by about $1.6 billion from the end of the second quarter. We told shareholders that deleveraging would be our number one priority and it will continue to be over the next few quarters.We sold our Pipestone partnership in the Deep Basin, a great step towards streamlining our Deep Basin portfolio. We have other confidential divestiture processes underway in the Deep Basin and are moving on multiple fronts. We're encouraged by the interest we're seeing.Moody's upgraded our corporate credit rating, citing our improved leverage and our ability to generate strong free funds flow. That upgrade is recognition for the hard work we're doing to reduce our debt and should be a positive signal to our shareholders of our future potential.We signed strategic rail deals in the quarter. I know there was a lot of anticipation in the investment community about these deals and I'm very pleased with the volume, pricing and commercial terms we negotiated.At our oil sands operations, we continue to see reservoir and production improvements. As a result of this along with our strong operational performance and efficient use of capital across our business, we have reduced our forecast 2018 capital spend by almost $250 million with no expected impact oil sands production volumes or the safety and reliability of the assets. We achieved record low operating costs in the oil sands of $6.59 per barrel, down 10% over our previous record low in Q2 of this year.When WCS prices are low relative to WTI, our refineries gain a feedstock cost advantage. That, together with record high throughput rates, contributed to significant operating margin from our refineries in the quarter. And we subleased a substantial additional space in The Bow building, one more step towards reducing our overall costs. All in all, a great quarter with a lot of achievements checked off.As you know, the Western Canadian oil and gas industry is challenged right now largely due to continued pipeline capacity constraints and corresponding crude oil price differentials that have reached record levels in recent weeks. We believe the pressure from differentials will start to ease with U.S. refineries coming back online later this quarter, the ongoing ramp up of crude by rail out of Alberta, and the startup of Enbridge's Line 3 Replacement project next year. In the meantime, we're taking additional steps to mitigate our exposure to widening differentials by temporarily ramping down a portion of our production until prices improve.We're also pursuing additional oil storage options in our existing salt caverns at both Foster Creek and Bruderheim. We will continue to explore ways to mitigate the impact of current wide differentials without sacrificing long-term value. The ultimate solution to differentials though is still increased takeaway capacity. I cannot stress that enough. Canadian companies are selling their oil to the U.S. at fire sale prices and it is having a significant impact on our economy.That's why we're working hard with our peers and with governments to address these and other key competitive issues facing our industry and the country. We've been closely involved as a company, and I have been personally engaged in high level discussions between industry and the federal government aimed at getting Ottawa to pause and review its plans for Bill C-69 so that we establish a project review process that encourages investment in Canada.We're offering solutions to government we believe will help achieve real and meaningful policy changes to improve Canada's competitiveness in a manner that will allow us to continue to grow the economy by responsibly developing the country's vast oil and gas resources.Despite some challenges outside of our control, I remain very optimistic about the future of our company. I'm extremely pleased by our strong operational performance and our growing ability to generate funds flow. We will continue to focus on deleveraging, reducing costs and maintaining capital discipline.With that, let's get straight to your questions.

[Operator]

[Operator Instructions] Phil Gresh with JP Morgan.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

First question I guess would just be you made a comment about asset sales and just any additional color you could offer there around kind of confidence levels and timing of asset sales and just generally where you think you are in the process? What order of magnitude you still want to achieve in asset sales as you try to reach some of these debt targets?

[Alexander J. Pourbaix, CEO, President & Director]

Hey, Phil, it's Alex. Why don't I pass it over to Jon and he can give you his thoughts.

[Jonathan M. McKenzie, Executive VP & CFO]

Sure. I think we've been pretty clear on asset sales and I'm going to reiterate some of the past guidance that we've given, but asset sales in this company are really limited to our Deep Basin business unit. And in the past, we've talked about being willing to sell up to 50% of the production in that business unit assuming we get the value that we need for those assets. So we're still pursuing a number of different dispositions. We've got multiple irons in the fire and these are in various stages of negotiations. So we still remain optimistic, but we do recognize it's a challenging environment and as we've always said, we're not willing to give these assets away for anything less than our retention value. So we continue to progress it and stay tuned.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

And Jon, just, you talk about production. I'm just wondering is there any kind of willingness or desire to include more of the infrastructure? Obviously, you got a nice value on the infrastructure recently, so just wondering where you stand on that?

[Jonathan M. McKenzie, Executive VP & CFO]

Yes. So as it relates to the Deep Basin, yes, when we do sell those assets we typically white map those areas. So we not only sell the infrastructure, but we sell the reclamation liability that goes with it. But as far as infrastructure sales in the oil sands assets, that's something we're not considering at this time.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

And second question I guess would just be on the production. Any order of magnitude that could be shared about how much you're planning to curtail and for how long?

[Alexander J. Pourbaix, CEO, President & Director]

Sure. Phil, it's Alex. Maybe I'll -- I'll maybe give some general thoughts on that and then I can probably pass it on to Keith. I mean I think that we've demonstrated over the last several months and particularly in Q1 of this year that dynamic storage, I think we proved that concept and we -- we view it as a strategic tool. We've used it in the past. We're going to continue to use it if we believe we can add value by deferring production into future periods. And I want to be clear on this, the industry right now has a production problem. We're going to do our part, but we are not going to carry the industry on our back. I think this is something that has to be dealt with on an industry-wide basis. The other point I would say which I think is worth noting is that with our cost structure continuing to go down, we really do feel in many ways we're going to be the last man standing with respect to our variable cost of production, so we're going to be disciplined about how we use this tool going forward. And I don't know, Drew, if you have anything you want to add on that?

[Drew Zieglgansberger]

Yes, Phil, it's Drew. So we have slowed some production in both Foster and Christina. I mean in Q1 you saw upwards of 40,000 to 50,000. We did that for a 6-7 week period. We probably wouldn't go that high if we are expecting to have to store for longer than what we did in Q1. And so we have slowed things down here just as of late, but we're not going to get in specifics on actual numbers on any given day or any given week, but as Alex noted, I mean this is obviously a tool that we can use and we have started to use it again.

[Philip Mulkey Gresh, Senior Equity Research Analyst]

Got it. Last question would just be on the capital spending reduction, just talking about the efficiency there. And you kind of just say I guess the midpoint as a guidance for the year. Can you remind me how much growth capital is in that number for Christina Lake and then as we look at the next year, doesn't -- that growth capital number would come down so to suggest maybe even lower '19 or it might base there?

[Drew Zieglgansberger]

Yes. It's Drew again here, Phil. So we've been very pleased with the state of the business and how well the teams have been executing capital this year. I think I just need to remind everyone, I mean in 2014 we were at $13, $14 per barrel on sustaining and we're basically showing everyone now we're down below $5 and we know what this is really kind of transpiring is really the outcome of all the kind of good work we've done in the last number of years and we're finally getting to a point where the teams are getting so efficient and the well times and the tie-in times are getting so strong that we can just reduce the amount of capital we need in any given calendar year to still maintain a sustaining capital or the production profile in these oil sands. So as far as your specific question on capital, I mean we were a couple of hundred million this year on growth that was being spent at Christina G. That will come down quite a bit in 2019 because that project is getting near its end and it will come on in the second half of next year. And also maybe give you a little color that if I look at the sustaining pads that actually are needed next year to maintain production or even if we do bring Christina G on, those are basically already landed, the capital's already all spent and the wells are basically done. So we're in a very good position coming out of 2018 and we go into 2019 for the actual scope that we need to maintain our production levels and even bring on Christina G., if we choose to do that. And so this is just an outcome of how well we've continued to challenge the cost structure, change the designs and the efficiency in our execution. And we're now reaping all this benefit that's going to be sustainable here as we look forward.

[Alexander J. Pourbaix, CEO, President & Director]

Yes, Phil, it's Alex. There's just maybe one point I would add at the end of Drew's comments and that would be from our perspective, I think it's -- we really want to get the message across to our investors that these operating cost improvements see sustaining capital improvements that you're seeing and we're talking about today, these are in our view entirely sustainable, these are not onetime cost savings. We're not starving the assets. This really is the outcome of the very disciplined focus that Drew and his team have had on driving those costs down to an industry leadership position and we're very confident that we can continue with this kind of cost structure.

[Operator]

[Operator Instructions] Your next question comes from Greg Pardy with RBC Capital Markets.

[Greg M. Pardy, Managing Director and Co]

My questions will sit right into that. I guess first question is just with respect to rail, you increased Bruderheim from 77,000 to 100,000 barrels a day. Are you contemplating an expansion on that front at some point?

[Keith Chiasson, Senior VP of Downstream]

Hi Greg, yes, it's Keith Chiasson. We've articulated that Bruderheim has capacity of 100,000. We're actually progressing as we speak some pretty low-capital projects that will actually get that facility up to or above two unit trains capacity in early 2019, so that's over 120,000 barrels a day. So that work is underway, it's pretty low cost to get there and we're progressing that work as we speak.

[Greg M. Pardy, Managing Director and Co]

Then just second question for me, a couple of years ago -- 2-3 years ago, you guys had talked about just partial upgrading, I know [indiscernible] was pretty keen on that. Is work underway on that front, is that something that you would look at over the medium term?

[Unknown Executive]

Yes. Greg, we were -- we're still looking at that. Technically the reduction by 50% or $1 billion is proven with a pilot to 1,000 barrels a day. Right now we're just looking at the cost they would take to build that facility and what the returns would be and what the value uptick is. So it's work in progress. But we're very excited about the technology.

[Operator]

Your next question comes from Neil Mehta with Goldman Sachs.

[Neil Singhvi Mehta, VP and Integrated Oil & Refining Analyst]

The first question I had was around just your outlook for Western Canadian crude differential and as you think about 2019, but then also looking out to 2020 how much oversupply do you see relative to pipeline capacity? How do you see crude by rail coming to meet that -- meet that delta and Enbridge Line 3 fix it all or do we truly need a [ Transmount ] or a Keystone XL? It's a big picture question, but I think, Alex, you're really uniquely equipped to talk about it, so would love your perspective?

[Alexander J. Pourbaix, CEO, President & Director]

Well, thanks for that vote of confidence. I'll give my best shot at it and I might ask Keith to take over after I give you my general thoughts. I mean, I think our perspective on this is I think we expect we're going to see continuing tough Q4 and probably a reasonably tough Q1 of 2019. We are -- we do expect to see some of these refineries that are down on turnaround coming back here relatively shortly. And we really expect to start seeing rail ramp up out of the province in the first half in sort of Q1 and Q2 of next year. From everything I'm seeing and I'm hearing, I would expect Enbridge Line 3, I mean we're hearing it's going to be in service in Q4, that will mean there will be an extended period of line fill proceeding that and I think that line fill should see -- should give some significant easing to the differentials kind of by midyear on next year. And once we have Line 3 in service and we have rail ramping up in 2019, I would expect that by the second half of 2019 we should be seeing differentials that are looking very close to rail economics. And then 2020 I would expect to see rail economics plus, so somewhere south of 20 bucks a barrel differential in 2020. I don't know, Keith, if you have some more color to provide on that?

[Keith Chiasson, Senior VP of Downstream]

Yes, I think just to put some numbers behind that, we think we'll exit the year 2018 out of 200,000 barrels a day. The province on rail, that will grow to 450,000, so to kind of get to Alex's comment, by the end of 2019 with Line 3, so potential the bottlenecks that Enbridge have available to them and that rail volume, we think there will be sufficient capacity to not only move all of the upstream production, but also to start to empty storage. And obviously production will continue to grow and so we do need another pipeline to come on-stream eventually to make sure that those differentials continue to narrow down. One point I would like to make though, this is really a location differential, so any barrels that we are getting to the U.S. Gulf Coast, we are realizing significant value for and people should be thinking with a $40 differential between WTI and WCS for the barrels that we actually get to the coast, we're seeing prices better than WTI today.

[Neil Singhvi Mehta, VP and Integrated Oil & Refining Analyst]

Yes. And to that point, it's a very important one, is there a sensitivity that you could provide in 2019 for every dollar change in Western Canadian crude, what that ultimately means to your cash flow given the nature of the different pricing notes that you're selling to?

[Jonathan M. McKenzie, Executive VP & CFO]

Yes. So if you look in our guidance document, Neil, we do give you a sensitivity today and it's about $100 million per dollar and then what we'll do is we'll update that for the 2019 budget period when we come up with that in December.

[Neil Singhvi Mehta, VP and Integrated Oil & Refining Analyst]

Jon, theoretically it should be lower in 2019 I would think, just given that you have more rail --

[Jonathan M. McKenzie, Executive VP & CFO]

Yes.

[Neil Singhvi Mehta, VP and Integrated Oil & Refining Analyst]

-- takeaway?

[Jonathan M. McKenzie, Executive VP & CFO]

Yes, and we'll build all that in and we'll get that out to you as we lay out our budget in December of this year.

[Operator]

Your next question comes from [ Dennis Wong ] with Canaccord Genuity.

[Dennis Wong]

Just quickly going back to dynamic storage there, I just wanted to kind of ask a quick question in terms of -- and due to the nature of it, the length of time that you hold kind of production back is also kind of related to how much production or total production you're actually storing in that period of time. So even at the lower end of your guidance, it implies about 45,000 barrels a day of we'll call it shut-in or stored production. What's the approximate length of time that you guys have before you have to essentially turn that production back on because you run out of the space in the reservoirs?

[Drew Zieglgansberger]

Yes, Dennis, it's Drew here. So I mean I understand how you're back calculating what you think we're probably shut-in right now, so that would be probably a high-end goalpost if we wanted to do this for more than 3, 4, 5 months. At a lower level than that, what we would do is -- we've got enough pads that we can move this storage around basically. So you do it for a period of time on a number of wells or a few pads at a certain rate and then once we kind of get the fluid levels to a point where we want to start bringing them back down, so we still manage the temperature and pressure effectively in the reservoir, we just start storing on other pads at a similar rate. So you keep the asset at a reduced rate, but you spread the love around I guess as far as where we store it in the reservoir. So we manage the pressure and the integrity of the reservoir still and that allows us time to manage this. So in Q1 we did it for 6 or 7 weeks. Right now we may have the same amount of time we have to do this, could be potentially little bit longer. And we would have -- and then we would potentially just look at different volume levels depending on time and it's -- they all kind of work together to your point which is also why we're not going to comment on any specific level at any specific time because there is a time factor to it as well.

[Alexander J. Pourbaix, CEO, President & Director]

Yes, and the other thing I probably should draw your attention to is the fact -- and I think we mentioned this in our press release that we are looking at bringing back significant salt cavern storage that we have at Foster Creek and Bruderheim and maybe I can have Keith comment on that.

[Keith Chiasson, Senior VP of Downstream]

Yes, thanks Alex. So we have the capability to store in caverns at both Foster and Bruderheim up to the tune of 2.5 million to 3 million barrels. So we anticipate that in the fourth quarter here we'll be starting to move some of our production into that that low-cost storage as well.

[Dennis Wong]

Okay, so that should just help kind of the long -- the period of time in which you will be able to hold back production in the fourth -- with the hopes of selling it a higher price down the line. That's a fair assessment?

[Keith Chiasson, Senior VP of Downstream]

Exactly, yes.

[Dennis Wong]

And then the second question that I have here is kind of what market or what do you essentially need to see either quantity or kind of outlook in terms of e-brand. Do you feel comfortable starting the -- both steaming as well as starting up production on Christina G. next year and whether or not you -- like at what points are you going to make a decision around that, because I know you commented that on a previous quarter.

[Keith Chiasson, Senior VP of Downstream]

Yes, I mean I can give you my thoughts and Drew may want to jump in, but as Drew alluded to all of those pads are all ready to go into service. And I've been pretty clear in my time in this company that we are way more focused on cash flow and earnings per share than we are on any production targets. And we're going to make that decision as we complete the work on Christina G. We are not going to -- likely not going to exacerbate this problem by bringing 40,000 or 50,000 more barrels a day into production if we think we're actually going to drive a worse outcome overall for the company. So we're going to be thoughtful about it and we're going to be disciplined about it and we'll bring it on as soon as it makes sense.

[Operator]

Your next question comes from Matt Murphy with Tudor, Pickering, Holt.

[Matt Murphy]

On the rail side of things, just wondering if you guys could comment on whether or not capturing the new spec [ 117 J ] models has been a constraint, so all given commentary from rail operators as well as specific commentary from a U.S. operator on a lack of interest in moving the retrofits.

[Keith Chiasson, Senior VP of Downstream]

Hey Matt, it's Keith here. Yes, with regards to the recent regulations, it actually doesn't have any impact on us. Our current fleet meets the new specifications and the fleet that we're acquiring will meet the revised specifications that are supposed to come into service in 2025. So really no impact on the volumes that we have announced.

[Matt Murphy]

And then just as an follow-up with local condensate pricing obviously looking quite attractive from a purchaser perspective, just wondering if you could comment on the mix of your imported volumes versus those purchased in the local spot market? Or how we should think about your realizations there for blend going forward?

[Keith Chiasson, Senior VP of Downstream]

Yes, thanks Matt. We have capability, we have pipeline capacity out of the Gulf Coast. So we look at that on a daily basis to optimize our reacquiring condensate from the Gulf or reacquiring condensate out of the Western Basin. We also have significant storage capacity. So that's something our teams are doing to optimize on a daily basis and take advantage of any of the [indiscernible] that are available.

[Operator]

Your next question comes from Prashant Rao with Citigroup.

[Prashant Raghavendra Rao, Senior Associate]

I wanted to circle back to your improvement in OpEx cost per barrel. Clearly, even on a non-fuel -- to sort of a non-cash related metric, you had significant improvement Q-on-Q and year-on-year. My question is really 2 part on that. One, how should we be thinking about further structural gains that you alluded to as we go forward in the next few quarters? And maybe some specific items if you can provide any color that could help us to sort of fill that out. And secondly, in the event that gas prices do start to recover, how do you think about that interplay on the sort of the -- I guess the total OpEx cost per barrel on production and sort of how does that play in with where you see production overall going in the back-half of '19?

[Drew Zieglgansberger]

Yes, thanks Prashant, it's Drew here. So if I look at OpEx, I mean the teams have continued to just really scrutinize the business really, really well. I think some of the things that we did this year that have given us some good OpEx improvements really been around our ESP run life. If we look at the cost of our work-overs in some of the areas that we were budgeting, they're getting better performance out of the ESP run life. So we're not having to replace as many ESPs against the budget assumptions that we made, which has been good news. The other areas that we've continued to scrutinize and make sure that we're doing the right maintenance at the right times. We've also -- we did push out the Christina Lake turnaround here from earlier this last quarter. We are going to do it here next year, but on a kind of a non-fuel basis, if I look at both assets and oil sands, I mean we're kind of materially gotten to a point I think that we're definitely leading industry. I don't think there's a lot of room for any material improvements from where we are. I mean, we're going to continue to chisel away where we believe it's smart and necessary to keep challenging some costs, but we're also going to make sure we keep the reliability in a safe operation front and center and so we are going to make sure that we still do the right maintenance at the right time. So as I look forward, I mean we're going to continue to push for continued better ESP run lives, get our work-over concentrations down to a manageable level, which has helped this year. If I look into 2019, I expect that we can hold fairly flat relative to kind of what we've accomplished so far. So our cost structure is in really, really good shape, but I think as far as any big material levers to keep this trend going in the last 3-4 years, I think we've pulled the vast majority of them. Now as far as gas price on a fuel side, I mean we don't hedge ourselves against our Deep Basin production if that's what you're kind of alluding to. So in the event that we had a higher gas price from a bottom line for the company, we're better off from a cash flow perspective to actually have a higher gas price for the company, considering we've got good -- lot of gas production in the Deep Basin assets. So in the event we had a higher healthier gas commodity price in the long term, it's actually better for us from a cash flow generating standpoint as a company. And so it's not something we actively manage against from a pure oil sands OpEx because we'd be actually be better off from a company perspective with a higher gas price.

[Prashant Raghavendra Rao, Senior Associate]

Thanks Drew, and yes, that was kind of what I was looking to, so thanks for taking that head-on. The second question I had as a follow-up was on the rail takeaway capacity and as I put the picture together here, if we start to get pipe takeaway capacity in the back-half of '19, you have the second part of the rail contract you announced at second further capacity coming on in mid-2019. And I understand it's take or pay. Is there a world in which you don't necessarily need that given where we are today and if that were the case what would -- how should we be thinking about what that does to overall rail unit economics? Does that bring down the average cost per barrel and what you will be using rail for if I fast-forward a year from now?

[Alexander J. Pourbaix, CEO, President & Director]

Yes, it's Alex, I'll give my general thoughts on that. I -- honestly we put a lot of thought into the negotiating of these agreements and at the end of the day I think the term for us is probably optimum, I think is there a possibility at the backend of the term that we could be in a pipeline glut. I guess that is a possibility, but given our experience in this country and in this province for the last many years, I think being overly optimistic on pipelines hasn't worked out too well. So I mean I think we're pretty confident that we're going to be making use of that rail capacity over the term and maybe I'll throw it over to Keith, see if he has any thoughts.

[Keith Chiasson, Senior VP of Downstream]

Yes, thanks Alex. Yes, I see it the same way even with Line 3 coming on in latter half of 2019, there is still significant storage at kind of record levels in Alberta that will have to start to clear and then there will be additional production ramp until we get another line coming on-stream which is kind of forecasted in that 2021 time frame, so we see these rail deals directionally optimal from a term perspective.

[Prashant Raghavendra Rao, Senior Associate]

Just one very quick follow-up...

[Jonathan M. McKenzie, Executive VP & CFO]

It's Jon McKenzie, I'm just going to chime in as well and one of the things we do talk about with these rail deals is take or pay, but you shouldn't be thinking that the entire payment or the unit cost is take or pay. It still is largely a variable cost transportation movement to which there is a take or pay component. So as we set these deals up, we are very cognizant of what you were thinking in terms of the likelihood that these may be underwater at some point in time and we've adjusted the terms and conditions accordingly, but please don't leave the discussion thinking that these are full take or pay commitments.

[Prashant Raghavendra Rao, Senior Associate]

That's very helpful. And one very quick follow up and I will turn it over. Given the Canadian government's sort of interest in -- at the economic interested there should be in getting the energy sector moving in the right direction, obviously you have a lot of purview into that. I sort of wanted to ask correlated question on rail takeaway if foreseeing any assistance from the government or other sort of authorities and sort of bringing heads to the table and we could see maybe more -- a better -- more contracts coming forward with some help from a national interest in the background, is that a factor that's in play here, anything you could say to that so that would be helpful.

[Unknown Executive]

Yes, I mean I've been very involved at both the federal and the provincial government level for quite some time in trying to bring forward some solutions to this challenge and I would say the federal government has not really been involved so much on the rail issue. The provincial government actually has got involved in the early days of this challenge. They really did kind of provide a convener function to doing everything they could to see that as -- we were ramping rail as an industry both from our side, but also from the rail company side as fast as possible. So it's definitely been a priority for the government and I -- as I alluded to earlier we have a production problem right now in the short term in the province where the production by a relatively small volume is exceeding the takeaway capacity and that is driving unheard of impacts both to our industry, but not just to our industry, to provincial royalties, to taxation, to investment and anything that either level of government can do to step in and help this situation I think would be welcomed by most Albertans and most Canadians.

[Operator]

Your next question comes from Michael Dunn with GMP FirstEnergy.

[Michael Paul Dunn, Director of Institutional Research]

Couple of questions. I think earlier, Drew, you had alluded to a lot of the sustaining spending for next year in the oil sands having already been incurred, I know you don't have your 2019 budget out yet, but just wondering if it's still the case that you don't expect significant spending at Narrows Lake next year and if that's so, are we thinking about a capital budget similar to '18?

[Drew Zieglgansberger]

Yes, thanks Mike. Yes, I would probably give everybody that message that you can expect to probably see a similar level to what we're going to come out of '18 with for a 2019 capital level. Yes, there really is going to be essentially no spending at Narrows. We're going to still do the right thing by these -- all these collective assets and get some things ready, but I think you've probably heard Alex, a number of us, say here for a while that don't expect us to sanction anything very quickly here till we see some real material movement of egress out of this province and this country. So you have to also remember too on our sustaining capital, just we do have our pads and our wells ready for the actual calendar year next year, but we will still be spending some to get ready for pads that would come on in 2020. So it's still just a normal sustaining profile of capital, but we are able to bring it down because of our continued performance and improvement by the teams, but yes, you can expect us to probably be at a similar level in '19.

[Michael Paul Dunn, Director of Institutional Research]

And then I noticed the 2018 budget for Deep Basin spending went up a little bit. Can you -- why don't you just talk around that?

[Drew Zieglgansberger]

Yes, sure. So in the first half of the year we had a number of working interest parties go penalty on some of the work that we were doing in the first half of the year, so obviously we covered that capital and got the working interest which we were -- that's totally fine by us, so these are some good pieces of reservoir and some good areas that we focused on. So this is just a small adjustment to kind of cover some of that kind of capital that other people should have been spending, but went penalty, so we increased our working interest in those properties.

[Operator]

Your next question comes from Paul Cheng with Barclays.

[Paul Cheng, MD & Senior Analyst]

And I just want to first compliment you guys taking a very pragmatic approach about phase G. I hope that all your peers that you're taking a similar approach and they're still talking about they want to add more production in sense of new projects, doesn't seem that makes sense at this environment, so I just want to compliment you on that. And that -- just curious that -- 2 question, one, Alex, given your previous profession when Enbridge is talking about want to revise the nomination process, do you actually believe that that will help in terms of the freeing up additional takeaway capacity and help the process? And how much do you think that you may have?

[Alexander J. Pourbaix, CEO, President & Director]

That's a good question, Paul. I -- and this one, I -- Keith has been very heavily involved with Enbridge on looking at solutions, so I'm definitely going to pass it off to him for some of his thoughts, but I think if -- and I don't want to put words in Enbridge's mouth, but I think everybody acknowledges that the present rules reflecting apportionment or determining how apportionment is done are creating a situation either where there are air barrels or where the upstream industry sees further discounts as a result of apportionment that subsequently perhaps wasn't ultimately necessary. So I do think there is a price there, this is a complex issue and I know Enbridge has made several sort of attempts over the years to try to resolve it, but I -- certainly they've shown some interest in it, why don't I pass it on to Keith and he can give a bit of color.

[Keith Chiasson, Senior VP of Downstream]

Yes. Thanks, Alex. There are teams that are working to try to help Enbridge with what that would look like on a go-forward basis. And I guess what I would leave you with is we are seeing price differences from a pre-apportionment to post-apportionment announcement and really that's where we think the impact and the benefit could be from getting the rules for nominating on to that common carrier system right.

[Paul Cheng, MD & Senior Analyst]

And second question that -- and is will you be able to share what is your expected well volume in the fourth quarter? And also that -- just curious that the theory I think among some of investor, the reason why we have not seen a more rapid increase in the volume for well, not because that the producer willing to sign the contracts, it's because the well operator whether it's [ CPNC ] and they actually don't have the ability to wind it up because they are running so tight on their nice base already. Just want to see that -- where you stand on that?

[Alexander J. Pourbaix, CEO, President & Director]

Sure. Paul, I've spent a lot of time with my counterparts at both of Canada's national rail companies. So I think I have a pretty good understanding of the situation. I think it is fair that a year ago they had significant -- or certain volume constraints and exacerbated by a bumper crop of grain et cetera. The commitment that I have heard from both rail companies is that with the commitments that company -- that we have made and other companies have made that they are making the capital additions to their system. They are moving, they are bringing more locomotives forward either purchasing, accelerating the purchase of new locomotives, or accelerating the refurbishment of existing locomotives, and they're training crews in order to meet the needs of both -- of all of the industries that need their service. And I think I would tell you and from what I've seen they are doing that and they are going to be in a position to meet their obligations. I'm confident of that. I mean, one of the challenges and I might just take a moment to kind of describe this, but if you look at our case and you think about our 100,000 and maybe to make this easier I'll round it up 120,000 because that's 2 unit trains a day potentially for Cenovus ultimately, but just to make the numbers round, it is a 25-day roundtrip from Bruderheim to the Gulf Coast and back. So that actually, if you think about it from that perspective, that is 50 train sets, each train set with 3 locomotives and 100 cars. And so a lot of this ramp up is honestly just getting all of those locomotives, all of those cars and it is a not inconsiderable job to get all of that ready. So I think that they're going to ramp up on the same schedule that we're going to be able to bring our cars into service and I'm confident that we're going to meet that ramp-up that you heard me describe earlier.

[Paul Cheng, MD & Senior Analyst]

And your fourth quarter well volumes, we assume about 20,000 barrel per day or so?

[Keith Chiasson, Senior VP of Downstream]

Hi Paul, it's Keith. With regards to exiting volumes at Bruderheim facility, we've seen that facility ramp up from 17,000 barrels a day in the first quarter January time frame and we think we're going to exit here in October at about 70,000 barrels a day. We had released in our press release that we would start moving our own freight volumes as well in the fourth quarter and we're seeing that in that 15,000 to 20,000 barrels a day range as well.

[Operator]

Your next question comes from Jon Morrison with [ CIBC Capital Markets ].

[Jon Morrison]

You obviously being an industry leader in terms of your decision to curtail volume as much as we witnessed earlier in the year, but as you referenced, this is an industry challenge. If your peers don't follow suit and we remain stuck in this game of prisoner's dilemma, how long are you willing to curtail your own output if it isn't having an impact at the diff level and in turn your own realized cash flows?

[Alexander J. Pourbaix, CEO, President & Director]

I mean, yes, I mean, very much as I said we're not going to carry the industry on our backs. We're going to do this as long as we can justify that we're creating value for our shareholders by deferring this production into future periods. And -- but we are not doing this for charity, we're doing it because it's the right thing for our company. And hopefully other industry players would have a similar view.

[Jon Morrison]

Just as a point of clarification, when you talk about the expectation for the diff tightening on the back of 2 refinery turnarounds, is that really from a timing perspective underpinned by when Whiting comes back online? And in your view would that be more of a December phenomenon from a diff perspective since we've seen a push in that schedule to-date?

[Unknown Executive]

Yes, we -- I mean they would be starting to buy their barrels for late November kind of into this trade cycle. So we do see that kind of strengthening in that December time frame. And the other part that will strengthen is they can consume high total asset number TAN barrels, so we should see some of the spreads that we're seeing between some of the higher TAN barrels improve as well.

[Jon Morrison]

If I could squeeze in one last one. Jon, just on the CapEx disclosures in the quarter, you said little bit more than $300 million of spending on acquisitions in the quarter, but that didn't really come from the cash flow statement. Was that just an adjustment to a prior acquisition or something related to Pipestone or what drove that number in the quarter?

[Jonathan M. McKenzie, Executive VP & CFO]

Yes, that was related to a swap of land position that we did with another company. So outside of the Pipestone, everything else in there was really related to that swap.

[Operator]

Your next question comes from Travis Wood with National Bank Financial.

[Travis Wood, Analyst]

Just kind of extending on the shut-in volumes and the potential impact that that could have, is there the option or can you have the conversation, Alex, as you converse with the province, could we see an outcome where there is a royalty holiday underpinned by an independent on a kind of producer-by-producer basis? So if you continue to shut in volumes potentially given the market, can that conversation exist?

[Alexander J. Pourbaix, CEO, President & Director]

Yes, I mean I -- as I alluded to earlier, it is a surprisingly small volume of dry bitumen that were oversupplied in this province right now. And I just see and I know one of the brokerage firms came out with an idea of a royalty holiday. I see that as kind of a version of sort of a volume curtailment strategy and I think that -- I would assume that people are looking at the various permutations and combinations. And I would just make the observation that a very, very small reduction in production coming out of this province would result in I think an incredibly surprisingly positive impact on the net back for our barrels and all of the follow-on issue -- follow-on benefits that would flow both to the province and to Albertans and Canadians.

[Operator]

Your next question comes from Joe Gemino with Morningstar.

[Joseph J. Gemino, Equity Analyst]

If you think about growth outside of Christina Lake phase G, would you need a situation where you have both pipelines in play or would either the Keystone XL or Trans Mountain expansion be sufficient?

[Alexander J. Pourbaix, CEO, President & Director]

I think we're going to -- we will have to assess that at the time and see what other volumes are scheduled to come on in the province, but I would say that probably KXL on its own might be sufficient just given the very large size of that project. But in a perfect world we'd like to see and frankly I believe that ultimately all 3 of the expansion projects are going to go ahead, but as Drew alluded to and I've said many times, we are going to have to see shovels in the ground and a real clarity to those projects going ahead in order to make further like phase expansion commitments.

[Operator]

We will now take question from the media. [Operator Instructions] Your next question comes from Deborah Jaremko with Daily Oil Bulletin.

[Deborah Jaremko]

Actually, my question has been answered, so thanks very much.

[Operator]

Your next question comes from Dan Healing with The Canadian Press.

[Dan Healing]

Alex, just referring to your points about reducing volume overall in the province, is anything actually being done from an industry perspective say through the Canadian Association of Petroleum Producers to get people to actually do that?

[Alexander J. Pourbaix, CEO, President & Director]

No, I'm just -- I've seen commentators in the press and make comments for that effect. And I was -- the point that I was really making is I think people would be surprised at how a relatively small reduction in volume could be a very, very significant benefit for Alberta and for Canadians.

[Dan Healing]

And if the federal or provincial governments were to enact some kind of regulatory reform that would allow them to restrict that kind of thing, is that something that the industry would welcome as a market intervention?

[Alexander J. Pourbaix, CEO, President & Director]

I can't speculate on that. I mean, I think it would have to -- it would depend so much on what was proposed. I was -- as I said I was really just commenting on the fact that a very small physical imbalance drives a very significant financial outcome.

[Operator]

There are no further questions at this time. I will turn the call back over to Mr. Pourbaix.

[Alexander J. Pourbaix, CEO, President & Director]

Well, I just want to end off by thanking everybody for your interest in our company and your time with us today. So thanks everyone and good luck.