Cenovus Energy Inc. (CVE) Q2 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy Second Quarter 2018 Financial and Operating Results. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Cenovus Energy. I would now like to turn the conference call over to Mr. Kam Sandhar, Senior Vice President, Strategy & Corporate Development. Please go ahead, Mr. Sandhar.

Thank you, operator, and welcome, everyone, to our second 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 second quarter and annual MD&A, and our most recent Annual Information Form and Form 40-F. The 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 Q&A portion of the call with Cenovus’ leadership team. Please go ahead, Alex.

Thanks, Kam, and good morning, everybody. I’m pleased to report we had a very strong quarter. We delivered record operating results and solid financial performance, even after a sizeable realized hedging loss. I’d also like to remind you that at the end of the quarter, our corporate hedge positions were significantly decreased to 37% of our forecast liquids production for the remainder of the year. With a continued strong performance of our assets, our low operating costs and our increased exposure to higher oil prices, I’m confident that Cenovus has turned the corner and is well positioned for the remainder of 2018 and into 2019. I will expand on that in a minute. Combined, our Foster Creek and Christina Lake oil sands projects, achieved record production in the second quarter of nearly 390,000 barrels per day, an 8% increase from Q1. We also achieved record low oil sands operating costs of $7.32 a barrel. This performance is the result of our team’s ability to consistently deliver reliable operations, as well as our decision to defer some of our oil sands production from the first quarter to the second quarter, by using the dynamic storage capability of our oil sands reservoirs. You will recall that we did this in response to very wide oil price differentials due to transportation constraints in Q1. By strategically slowing oil sands production, while maintaining steam injection to continue mobilizing oil, we were able to take advantage of our significant capacity to store barrels in our reservoirs. As heavy oil prices improved, we ramped oil sands production back up to above-normal operating levels and we’re able to recover essentially all of those stored barrels in the second quarter. Furthermore, deferring those volumes from Q1 to Q2 has helped to improve our bottom line in the second quarter, by increasing our net-back on those stored barrels. And as expected, we have not seen any impact on the integrity of our reservoirs due to temporarily storing barrels underground. This is proven to be a very effective tool in times of light price differentials and takeaway capacity constraints to help improve value for our shareholders. And you can expect us to use it again, if we believe we can create additional value. Even with the temporary rate reductions in the first quarter, we continue to expect our oil sands volumes for the year to be within our original guidance of 364,000 to 382,000 barrels per day. I believe this is a great example of our ability to adapt to changing market conditions. As I said at the outset, I believe we have now turned the corner on our potential to generate free funds flow. Even after the impact of our $697 million realized hedging loss, we generated adjusted funds flow of $774 million in the second quarter. And after $292 million of capital investment, we had free funds flow of $482 million. Going forward, with our corporate hedge positions now significantly reduced, we expect to generate significant free funds flow in the second half of the year and into 2019, based on current strip prices. With a direct line of sight to our ability to generate strong free funds flow from our operations, I want to reassure all of you that our first priority for these funds and the proceeds from any asset sales is to continue to deleverage. I believe that a strong balance sheet is the best defense against volatile commodity prices. We have a sense of urgency to delever the company to two times debt to adjusted EBITDA with a longer-term goal to meet this target at the bottom of this cycle. I’d now like to turn to our Deep Basin operations, which delivered solid results in Q2. We substantially completed our planned capital program for the year in the first quarter, and kept production relatively flat compared with Q1, while bringing on three net new wells in the second quarter. We continue to review opportunities to divest a portion of our Deep Basin assets. Our East Clearwater sale process continues to proceed as expected with good interest from capable and qualified buyers. We’re looking at additional divestitures in 2018. But we will only go through with the sale, if we believe we can realize value that make sense and is beneficial to our shareholders. In the refining and marketing segment, we had very strong throughput in the second quarter at both the Wood River and Borger refineries, following major planned turnarounds earlier this year. Our refining and marketing segment generated $357 million in operating margin in the second quarter, compared with an operating margin shortfall of $48 million in the first quarter of 2018. The increase was primarily due to discounted crude feedstock prices, strong realized crack spreads, high utilization rates, and the completion of planned turnarounds at both refineries in the first quarter. We expect to face some market access challenges for the foreseeable future. We continue our negotiations with rail companies to move our crude to stronger markets. That said, crude-by-rail is just part of the solution. New pipeline capacity is also very important to our industry. And as I said before, we do not plan to sanction a new oil sands expansion until we have confidence in future pipeline capacity increases. Last but not least, I’m pleased to announce that Kam Sandhar recently joined the Cenovus leadership team. As Senior Vice-President, Strategy & Corporate Development, Kam continues with his current portfolio reporting to Jon McKenzie, our CFO. Kam’s portfolio was instrumental to our success as a company and in maximizing value for our shareholders. Please join me in congratulating Kam on his promotion. The Cenovus leadership team is now ready to take your questions.

[Operator Instructions] We will now begin the question-and-answer session and go to the first caller. Your first question comes from the line of Phil Gresh with J.P. Morgan. Please go ahead.

One is just your latest thoughts on crude-by-rail and securing some kind of long-term takeaway agreement. Your commentary earlier suggested you’re continuing to work on things. But it also sounds like maybe from prior commentary of yours that the costs aren’t quite where you would want them. So I’m just wondering what it would take from your perspective to get there, and are we close?

Sure. Thanks, Phil. It’s a good question. And I didn’t – I’d take everyone back to the comments I made at the last earnings call. And I think you guys will remember that I said at that time that rail was a real priority for us. And as evidence of what we expected, I said that, it was very important to me that we saw our volumes ramping up through the Bruderheim terminal and that we expected that to start ramping up in the second half of the year and to continue in the future. And what I can tell you is we are seeing a significant ramp-up in activity at Bruderheim, and we are moving significantly more of our barrels through that facility today. And we would expect to see that continue. Now, that been said, these movements, although they’re going in the right direction are what I would kind of describe as more spot movements. And when I talk about rail, I’m really thinking about something that is material and structural. So for our shareholders, like for me, that looks like something like 50,000 to 60,000 barrels per day and a multi-year commitment, so really moving kind of on a unit train basis. And the one thing I would say about that is that is a very, very complex transaction. So it isn’t as easy as just getting a deal done with the rail companies. To do it on that kind of scale requires further car leasing, tank leases, liability management. And so, we’re talking about a very material commitment. And from my perspective, it is important that we do this on an urgent basis, but it is way more important that we get it right rather than we get it quickly. I am really focused on maximizing shareholder value. And it is taking us a bit of time to make sure that we have the right deal. But I do – as I said, it continues to be a priority, probably taking a little bit more time, just because of those issues that you told you about and our focus on getting it right and not doing anything that is going to destroy value. So I would ask for a little bit of patience, but I want everybody to understand that we take this very seriously.

So I guess to clarify – and I appreciate the color – would you say that you’re hopeful you could get something done by yearend or do you have a timeline in mind that you’re hoping to accomplish it?

Yeah, I mean, yeah – it’s really tough to say. I mean, I certainly would like – as I said, we are significantly ramping up Cenovus volumes across Bruderheim as we speak. And we expect that to continue. But I would like to ultimately end up with what I would describe as kind of the structural unit train deal. And I think give us – we’re going to need a few more months to kind of get – to get the kinks worked out and to see if we can get something done along those lines.

Okay. Fair enough. My second question is just on your comments in the release about the royalty rates at Christina Lake moving to a post-payout. I know you guys didn’t change your guidance or anything like that for 2018. But if I were to think about the royalty rates that you’re seeing, say, for Foster Creek in the quarter, would that be the right proxy to think about for where Christina Lake will head in a post-payout world?

Phil, I’m going to pass this one over to Jon. I just know enough to be dangerous on this, so I’ll let Jon answer them.

Hi, Phil. It’s good to hear from you and thanks for the question. So what we’ve included in the release, Phil, is our expectation of where we’re going to be with regard to payout at Christina Lake based on where we see strip pricing. And we would believe that we’ll be in a post-payout world sometime later into the second half of this year. So that has come forward with the increase that we’ve seen in the commodity price environment. There is nothing new or unique about the actual structure. And I can refer you to the MD&A, in the oil sands section. There is a section in there that will help you with the calculation of the royalty in the post-payout world.

Okay. I’m just looking for a rough proxy. Is there anything different between Christina and Foster?

No, they are the same.

[indiscernible].

No. They are under the same royalty regime. And you’ll see similar type numbers in the post-payout world.

Right, okay, thanks. Good to talk to you, Jon.

Your next question comes from Neil Mehta with Goldman Sachs.

Hey, thanks very much. Welcome, Jon, and congrats, Kam, on the new opportunity. The first question I had was just your thoughts in terms of the Deep Basin and where you stand in terms of prosecuting the opportunity set there. And whether that – you still view that as a core asset or if there is potential for further divestment to sort of monetize your acreage?

Hey, Neil, it’s Alex. And I’ll take a shot at this and I may pass it off to one of the guys for a bit of color. But here is how I would describe the Deep Basin business. I do believe that over the longer-term that Deep Basin can be a meaningful addition to Cenovus’s business. But – and I’ve said this before even under really benign commodity price conditions, it’s such a large acreage position that it really isn’t reasonable to think that Cenovus could have all the capital resources to develop it as efficiently as you’d like in the time that I expect that we would have for that. So I think under any scenario, I’ve said nobody should be surprised to see us continue to streamline the Deep Basin. We’ve done a good piece of work internally to really prioritize, what assets in the Deep Basin are going to be the most meaningful for us, and conversely, we think there is a number of assets in the Deep Basin that are probably going to be more valuable to companies other than Cenovus. And so that’s really what we are looking at, we have identified those assets. And we are advancing on a path of this streamlining. The other thing, I would say is that right now, even the stuff that we’re going to keep, it is we are in a challenged gas price environment. And so I think, people should not expect us to significantly ramp up or deploy, significant incremental capital to that Deep Basin asset position, until we see some evidence of sustained improvement in gas pricing. Just one other thing, I would say is, when you think about what could streamline Deep Basin position look like, I would think about, we could potentially, if we see value divest up to somewhere towards 50% of the portfolio over a longer time period.

That’s really helpful context. The follow-up is just about Midland differentials. The refining side of the business has performed very well, Borger and Wood River, well certainly, one of the things specifically at Borger, you’re benefitting from is the wider Midland spreads, which should persist through 2018 and into 2019. Can you just remind us of the sensitivity if the business to those Midland spreads and how you guys are going about capturing those differentials. And to some extent the widening WTI Brent spread as well.

Sure. Keith is going to answer that.

Yeah, thanks, Neil for the question. We came out of the turnarounds we have very extensive turnarounds for both refineries in Q1. And I’ll tell you that both refineries in May and June have been performing at record rates through utilization. Obviously, there are significantly benefitting from the differentials both the WTS, the WTI spread which we see at same way persisting through 2019 until new pipelines are built out of the Permian. But Wood River is also benefitting from accrued events associated with the heavy crude out of Canada. So really what drove our results is that higher utilization that we saw. We are seeing the crude advantage at both refineries, a little better crack spreads. And as we head into the IMO in 2019, diesel prices should be healthy, and then lower costs both operating costs and then kind of the rents costs. So all-in-all things are running really well for our 50% ownership.

That’s great. Last question for me is just, Alex, I just curious on your views on how WTI-WCS or Brent WCS evolves? From here there are lot of moving pieces right there, Enbridge Line 3 that theoretically should be online at the end of 2019 there is IMO 2020, in 2020 there is real. How do you see all this playing out, as we try to forecast the price of your netback?

No. I mean, it look, you identify if there is a lot of moving parts. I kind of tend to look at it in time buckets, in the short-term bucket, I think the material relief that we would expect to see would be ramping up of the rail capacity coming our Alberta. There is a well over $0.5 million barrels a day of rail loading capacity in the province. Right now, on average only a fraction of that is actually working much as, we’re seeing volume of Bruderheim ramp up. We are seeing that sort of across the rail loading spectrum. And I think a big part of that issue you heard me talk about sort of how our discussions with the various rail companies have gone. I think the rail companies, they have been very clear, they intend to move more oil. They are starting to ramp it up, but they also had some pretty significant capital investments they need to make a new cars, new sitting, they’ve been training new crew. So I think what we are seeing a little bit, it’s just a normal kind of delay that you would see as a rail companies start to mobilize that capacity. But so that, my view on that is that from now until kind of late 2019, when Line 3 comes in, my expectation is that we should see that rail cap WCS-WTI differentials, more or less in that sub $20 range over that time period. Then, the next bucket is what I would call kind of the pipeline as we start seeing pipelines come in. We are feeling pretty quiet good about Enbridge’s Line 3 given the outcome – the regulatory outcome that they have had. They are – the last I heard, they are still talking about late 2019 timeframe to get that into service and that’s going to bring on. If I recall above 370,000, 380,000 barrels a day of incremental production, which I think should be an impetus to keep differentials continuing below – hopefully below 20 and trending lower as the other pipelines come on. And if we are able to get one or both of TMX and Keystone XL on, then I would expect will be in a world of differentials back kind of in that kind of $10 to $14 range over the longer term.

That’s great. Thanks a lot, team.

Yeah, no worries.

Your next question comes from Paul Cheng with Barclays. Please go ahead.

Hey guys, good morning.

Good morning.

Alex, if I may go back into the rail, you’re saying that is a very compact negotiation, obviously that I fully understand. Can you share with us that one may be the biggest hurdle between what the rail operator want and what the oil company would be willing to offer? Is that related to the time duration of the contract that they want or is it related to the minimum volume requirement that they want or fee that they may want to charge?

Thanks for the question, Paul. And I’d hate to put words in the rail companies mouths, but I think if I could kind of describe, what I think the issue is. The rail companies are looking for a book of business that is reliable and repeatable. And the shorter term that business is in the more spot that business is, the less the rail companies will be able to rely on it and the higher return I would expect they would demand for it. So I think a lot of it is trying to find that sweet spot between sort of what the industry is looking for and what the rail companies are looking for. And I would say to you that I have some sympathy for the rail companies looking for some business that is reliable and stable. The last time, they ramped up this capacity for the industry, I think it left them in pretty short order once pipeline capacity came back online. So I think that’s kind of the discussion and as I said we look at it from a perspective. But if we’re going to go down this path, we would be looking for a material volume moving, we’d look to move it on a regular ratable basis and we would be doing that for – it would be a multiple year type deal. So I do – I ultimately think there is a reasonable ability for people on both sides of this to get what they’re looking for ultimately.

Will you be able to share with us what kind of general demand the rail operator currently is asking?

Yeah, I am not going to negotiate over on a conference call. But let me just say this, I mean, I think, between the bid offer, I expect there is probably a deal that words for both sides.

Second question then with the Syncrude outage, I mean, it seems like in theory that Enbridge have some feed lines to be, but primarily for light oil and that you can’t really ship the heavy. So is your marketing people see any opportunity to do there are between buying the heavy oil and moving into that currently they just moving in Enbridge, moving into the Keystone and then moving to Keystone light oil into the main line for Enbridge? Is there an update or that the time duration is so short that is really impossible to do anything?

Yeah, Paul, it’s Keith Chiasson here. There’s always opportunity to move heavy oil on Enbridge’s system, and Enbridge does optimize their system they will move heavier oil on their light line. And we are seeing and expecting them to do that kind of with the Syncrude outage. With regards to apportionment, Enbridge have apportioned actually both their heavy and their light lines. So we are taking advantage in Enbridge would be taking of advantage of moving as much product on the system as possible and they really do treated like a system. And historically, we have seen that through kind of like Syncrude and some of the upgrading turnaround activity, some of that product – heavier product moving on the light system.

Keith, have you already seen that happen or you think is going to happen?

Yeah, I think, it’s happening as we speak as Syncrude work through their restart.

Okay. And final one, Alex, you’re saying that you already recover most of the oil that you stored in the reservoir, so should we assume that in the third quarter both Christina and Foster Creek pretty much they would be back in terms of the run rate?

Drew will give you some color there.

Hey, Paul. Yeah, it’s – I mean, if you look at Q2, I just want to do a shout out to the operation teams here in oil sands. I mean it was a phenomenal quarter on what they’ve been able to do to produce in the reservoir and the up time, the reliability that both facilities were able to demonstrate, quite phenomenal operating result. So you can expect here is that with essentially all the oil that we were storing in Q1 coming out now that both Foster and Christina, as we come through July here, we’ll get back to normal levels that we would have budgeted and that we guided to originally. And so I think what this demonstrates is just a phenomenal job that the teams were able to do kind of create this new tool now as something to use to help in our marketing and/or maximizing the value in the cash flow all of our barrels. So considering the circumstance of where we are right now, expect us to be back to normal rates. But just also know now that we reserve the right that if we want to use this tool and lever this volume gain in the second part of this year, if we think that it maximizes more value for our barrels as we will do it again. But where we sit today, expect the facilities to come back to the normal budgeted rate in the middle of guidance that we had originally put out.

Just Paul – sorry, Paul, I was just going to it might be worthwhile to have Harbir just talk a little bit about sort of our experience with dynamic storage and how it is impacted or how it is not impacting our reservoir.

Yeah, Paul, a few years ago, we actually couldn’t do this. But what’s changed here in the last few years is a few things. And one is that, about a third of the 390,000 barrels a day has actually recovered more than 50% of the oil in place, which creates a lot of voidage in each well peer. And so that’s what changed. The other thing that changed is the conformance. The conformance is really helping us that we can use the storage in the reservoir. And like Drew said, we’ll do it again. And the third thing you need to know about SAGD is that, it’s gravity drainage. So even if – even though we’re shutting down the wells or slowing them down, you cannot turn gravity off. So the oil still continues to drain. So the fact that we’ve tested our reservoirs with 60,000 to 80,000 barrels a day slowing down, we feel very comfortable in the future, that not only can we do those rates or higher, but we can actually maintain it for a longer period of time. So we’re in pretty good shape to handle high differentials going forward.

Thanks, Harbir.

Just curious that – I mean, with the production return to normal, should we assume the unit operating rate comparing to the second quarter as a result will be going higher?

Yeah, it will come back to. Just like production would come back to the midpoint of guidance, Paul. You can expect OpEx to fall into the same midpoint of guidance that we would have budgeted for. Yes.

Thank you.

Thanks, Paul.

Your next question comes from Travis Wood with the National Bank of Canada. Please go ahead.

This question might be for Keith. And it’s somewhat reverting back to the rail commentary. But if the certainty and the timing of rail contracts is still kind of getting pushed out and we haven’t seen that bid/ask close in terms of the negotiations. And if you anticipate, some of your competitors have been talking about continued growth, is there – and I know, Alex, you’ve suggested in the past that hedging is not going to be on the table going forward. But is there an opportunity as you look at the differential, is there an opportunity to walk that in at least in the short term as you have more transparency and certainty around the contracts and the timing of rail.

Hey, thanks, Travis. I am going to let Jon answer this. He and I are pretty aligned on this. And he is probably the right guy to talk.

Sure, so I’m going to come back something that Alex said in his opening remarks. And if anybody leaves this call with the belief that safe reliable production isn’t our first priority they should be thinking that a close second will be debt reduction. We really believe that over the long-term, the best way to manage commodity price and volatility is through under-levered balance sheet. So we do have sense of urgency. As we communicated to begin that deleveraging process through free cash flow and proceeds from asset disposition. So that would be our preference in terms of how we go forward with commodity price and volatility management. Now, what I would say as well is one of the issues that we have as an industry is that hedging dry bitumen is not a simple exercise where there is a robust market with depth and tenure to it. So hedging bitumen prices going forward is always difficult. And then there is multiple legs under the stool that need to be fixed simultaneously. So we always look at that and we’re concerned about that. And we watch the market and we manage the risk. But there is not a simple and easy way to do that on a one-to-one basis. I think the last thing that I would say is what does give us some relief is that we have about 20% of our molecules physically integrated into our downstream. So we’re not entirely exposed to the WCS volatility and that some of that is off the table. But if I were to put those three points together, I would say that hedging is something that is difficult for us, but we look at it. We’re not in a mood today where we would be taking a position on WCS, going out more than what we have through the hedging program in 2018 and 2019.

Okay. Thanks for the color.

Thanks, Travis.

Your next question comes from Joe Gemino with Morningstar. Please go ahead.

Thank you. Do you just have an update on how you plan to incorporate your [solvents in terms of] [ph] technologies at your current productions, operations?

Hi, Joe. So currently, what we’re doing is testing our propane, which we started at the end of last year. And those two pilots are going really well. Basically, we’re testing anything from 3%, 8% solvents to as high as 60%. So the results of those are so far so good. But we want to see how the results come in the third and fourth quarter. And then we’ll plan to – what we are planning to do is not convert the whole plants to solvents, but do it on a pad by pad basis. You will hear more from us on how we’re going to do that towards the end of the year once we get more information from the pilot data.

Great. And if the information is what you’re expecting, would you start to see this is something you’d roll out in 2019 or would you look further out?

No. But the results so far are looking very encouraging as we expected or better. But we just want to see for longer time period. And so, we will look at implementing probably if we make a decision at the end of this year probably sometime in 2020.

Great. Thank you.

Joe, it’s Alex. Just one thing I would add. I think with the work that Harbir and his team have done, I think there is a great deal of confidence on the solvent technology. Technically, it’s going to be a success. I think there is very little concern about that and one of the other pieces of work we’re doing right now is really thinking about the logistics of getting the solvent site, how we’re going to do that, how we’re going to – what kind of pricing we can get for the solvent, which all kind of goes into that decision to implement it on a commercial basis on that timeline Harbir discussed.

Great. Thank you.

Okay.

Your next question comes from Phil Skolnick with Eight Capital. Please go ahead.

Yeah, thanks. How much of your 75,000 barrel a day capacity on [planning at seaway] [ph] were you able to utilize in second quarter, given the apportionment?

Yeah, thanks, Phil. It’s Keith Chiasson on here. Obviously, Enbridge apportionment impacts our capability to utilize that. We were able to use though I would say kind of in that 80% range of our pipeline commitments.

And then did you use any rail to get to the Gulf Coast?

As Alex had indicated in our conversation, we’re moving more of our barrels on rail. But predominantly we’re moving it through third parties that have service contracts with the rail companies.

Okay. Thanks.

After our next question, we will take questions from the media. [Operator Instructions] And your next question comes from Harry Mateer with Barclays. Please go ahead.

Hi, good morning. Just a follow-up question on the debt reduction, can you walk us through how you see that taking place? Obviously, outlook for free cash flow is pretty good. I know you have a chunky bond maturity in the fourth quarter next year. Is that what you think you go after? And could that start soon or is that something you think you’ll address in 2019?

Hi, Harry, it’s Jon. I think we’ve been pretty clear that our anticipation with the price deck being what it is at a strip level for 2018, 2019. This company is going to generate free cash flow that would be used for debt reduction. And in addition to that, when you think about capital for 2019, you should be thinking that the capital budget for 2018 is going to look suspiciously close to where we go in 2019, which again will provide level of free cash flow. Our debt portfolio today is largely bonds, it’s almost entirely bonds. We’re not into our bank lines today. So when we start to accumulate that cash from free cash flow and from asset dispositions, we are going to be looking for opportunities to reduce those bonds and reduce the carry on the interest rate cost versus the interest gained on the cash. Certainly, the bonds in 2019 would be of interest to us.

Okay. Thanks. And then, if you’re willing to, just put a slightly finer point on timing. Is that something that could begin this year or is it more likely 2019 as that free cash flow really starts to come in?

I mean, it’s really going to be driven by our accumulation of cash and it’s really going to be driven by the pricing of the bonds.

Got it. Okay. Thank you.

Your next question comes from Deborah Jaremko with Daily Oil Bulletin. Please go ahead.

Hi, there. Good morning. Thanks very much for taking my questions. I just was recalling that, I believe at last year’s Investor Day it was mentioned that there will be a commercial demonstration of solvents in 2018. And I just – from what was just said, I’m just wondering, am I hearing that right, that’s kind of now been delayed a bit or…?

Sorry, Deborah, you kind of broke up there. Would you mind repeating the question?

Sure, give me one second. No, I was recalling at last year’s Investor Day it was mentioned that there will be a commercial demonstration of solvents in 2018. And so what was just said about the timeline now, am I hearing it right that that’s been delayed a bit?

Why don’t I let Harbir just give you an update on that.

Yeah, so, Deborah, like we are – we did say we were starting to plan to do something in 2019. And now, we are being cautious on our capital because we are focused on our debt. And so, we found that delaying it a little bit is probably in our favor, because we’re learning lot. And the fact that we changed our minds on how to implement solvents, by not going to central plant and doing it in the plant stage, we think we can do the solvents implementation a lot faster by doing it on a pad level. And we feel we can do it a lot cheaper too. And so, because we’ve changed the design, we’re not time – schedule driven. And so, I’d like to use the time to see how the pads do that we put on propane too. So basically not schedule driven, we are trying to keep our cost low. So letting things slip by 6 months to 12 months is not a bad idea where we sit today.

Okay. Thank you very much.

Thank you.

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

Thank you, operator. Just on behalf of the Cenovus team, I want to thank all of you for taking the time with us this morning. And with that, this will end the conference call.