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Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Fourth Quarter and Year-End 2018 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 over to Ms. Sherry Wendt, Director, Investor Relations. Please go ahead, Ms. Wendt.
Thank you, operator, and welcome, everyone, to our fourth quarter and year-end 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. The quarterly results have been presented in Canadian dollars and on a before royalties basis. We have 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's leadership team. We ask that you please keep your questions to a strategic level and follow up with the Investor Relations team on any modeling questions after the call. Please go ahead, Alex.
Thanks, Sherry. I'm pleased to say we had strong operating performance throughout 2018. We also continued to deliver on our commitments to shareholders, demonstrating capital discipline and continuing to reduce debt while maintaining our focus on safe and reliable operations. While our financial results last year were significantly impacted by volatile Canadian commodity prices caused by market access constraints, we remained financially resilient. We demonstrated significant improvement in cost structures in the oil sands, captured the value of integration through our refining assets, improved our market access strategy and made progress on deleveraging our balance sheet despite severe headwinds. In the fourth quarter, when heavy oil differentials were at historic highs of over $40 a barrel and we were proactively decreasing our oil sands production levels in response, we finished the quarter essentially cash flow neutral and continued to reduce our debt. Our financial resilience is a result of all the hard work our teams have put in over the last year, looking for ways to further improve how we run our business. In addition to record-high differentials, our results last year were impacted by large realized hedging losses related to risk management contracts entered in 2017 that have now expired. We reset the pace of our development plan for the Deep Basin, which resulted in us recording a significant noncash write-off of the carrying value of our exploration and evaluation assets. During the year, we also recorded a substantial provision for office space commitments that exceed our requirements. Both of these contributed to our net loss for 2018. Our financial results were further impacted by timing factors related to inventory drawdown. For example, the price of condensate can vary significantly between the time we purchase it and the time we blend it with our production to sell. The same principle applies to refinery feedstock. The sharp decline in benchmark prices from October through December resulted in lower earnings in the fourth quarter due to blending of condensate and use of refinery feedstocks purchased earlier in the year at higher prices. We expect that in a rising price environment, the lower cost condensate and refinery feedstock purchased in the latter half of the fourth quarter will benefit our Q1 results. Despite our net loss for 2018, I was extremely encouraged that in the second and third quarters when commodity prices were somewhat normalized, we had combined free funds flow of nearly $1.2 billion. That performance should give you a good indication of our ability to generate significant free funds flow in a more normalized price environment. We also made strong progress in deleveraging our balance sheet last year. From late October through January, we reduced our gross debt by USD 1.2 billion or 16%. This includes redeeming USD 800 million of our 2019 notes and repurchasing a further USD 400 million of our outstanding debt at a discount for USD 365 million. We remain committed to getting our net debt down to our long-term target of less than 2x adjusted EBITDA at low-cycle commodity prices or somewhere around $5 billion. Following the September sale of our Pipestone business in the Deep Basin, we've decided not to pursue additional significant asset divestitures unless we can generate strong value for them. However, our 2019 corporate budget has been set at a level that we believe will continue to show additional progress on deleveraging without further asset sales. In 2018, we decreased capital spending compared with 2017 with our expenditures on continuing operations down largely due to our continuing focus on capital discipline. Our teams have been doing an excellent job on this. For example, our capital investment to complete Christina Lake phase G is 25% below what we expected to spend to achieve our planned scope of work. This is largely due to improvements in well pad design, longer well lengths and increased efficiencies in facilities construction. Construction of phase G is 5 months ahead of schedule. And we achieved first steam in January. The full expansion is expected to be complete and ready for production in Q2. However, we have flexibility for when we bring on incremental volumes depending on market access and commodity prices and when the government-mandated production restrictions are lifted.Both upstream and downstream operational performance were excellent in 2018. Even before the government-mandated curtailments were announced, we were proactively managing our oil sands production volumes in response to market access constraints and wider crude oil differentials, particularly in the fourth quarter when the WTI-WCS differential reached as high as USD 52 per barrel. We also achieved industry-leading per barrel oil sands sustaining capital and operating costs. And in the second quarter, we reached record daily production levels. Our refining operations continue to demonstrate their value as part of our integrated business strategy. After completing major planned turnarounds earlier in the year, both of our jointly owned U.S. refineries operated above nameplate capacity in the second half of 2018, and were able to benefit from a feedstock cost advantage created by the wide heavy oil price differentials. This helped offset some of the impact of the differentials on our upstream results in 2018. Both Wood River and Borger set new crude processing rates, which led to an increase in their nameplate capacities in 2019. Together, these factors contributed to nearly $1 billion of operating margin from our refining and marketing business last year. Earlier this week, there was a fire in a crude unit at the Wood River refinery. The fire was isolated and quickly extinguished. At the time of the incident, the crude unit was being restarted following planned maintenance and the refinery was operating at reduced rates. Wood River will continue to operate at reduced rates while the operator, Phillips 66, makes repairs. P66 is investigating the cause of the incident as well as progressing repair and restart plans. Turning to market access. We improved our position in 2018 with increased takeaway commitments out of Alberta. In September, we signed 3-year agreements with major rail companies to ramp up crude-by-rail transport in 2019. With pipeline congestion and crude oil differentials as acute as they were in the second half of 2018, we ramped up the volumes we ship by rail to get more oil to higher-priced markets, exiting the year moving approximately 20,000 to 25,000 barrels per day by rail. Our ramp-up will continue throughout 2019.Ultimately, we still need new pipelines to improve market access and to address the problem of wide differentials. To that end, we recently increased our committed capacity on the Keystone XL project to 150,000 barrels per day. A portion of the incremental capacity we took on was assumed from the government of Alberta. And I commend the government for providing early commercial support for the new Key KXL project by signing on as a shipper. In 2019, we're optimistic that we'll see continued progress on KXL and other pipeline projects. With the advancement of Enbridge's Line 3 replacement project and the continued ramp-up of rail takeaway capacity, we expect light-heavy oil differentials to settle somewhere around rail economics, likely in the mid- to high-teens. Before I'd wrap up, I'd like to address 2 other issues, safety and the government-mandated production curtailments. On the safety front, we had our best-ever total recordable injury frequency. But tragically, we had a fatality at our Christina Lake site in February of 2018 involving a third-party contractor. We completed a thorough investigation of this incident to ensure we fully understood what happened. This tragic event weighs on us every day. And our most important priority is always to ensure everyone who works for us returns home safely.With respect to the mandated production curtailments that are now in place, I want to express our continued support for the difficult decision the government of Alberta made on December 2. I remain convinced that this curtailment is the right thing for our industry and for Albertans. And I'm pleased that our government had the courage to quickly tackle such a serious issue facing our province. At Cenovus, we are confident in our ability to manage our production levels accordingly. Ultimately, people need to keep in mind that this has been a short-term solution for an extreme situation that was many years in the making. Since the curtailment has implemented, we have seen differentials narrow significantly. When the government announced this curtailment, it indicated the effects would be measured each month to ensure production is not reduced any more than necessary and that it would be willing to make changes along the way to address any unintended consequences. We've seen some adjustments already. And we believe the government will continue to manage the curtailments in the best interest of all Albertans. In closing, I see this past year as an inflection point for our company. We continue to make improvements in our business. We remain focused on deleveraging, capital discipline and cost leadership. And we were actively managing the challenges our industry is facing. We'll continue to do all of that in 2019. While our financial results last year didn't match the rest of our performance, our achievements have left us well positioned to generate significant free funds flow and create value for our shareholders. Our accomplishments should demonstrate to investors the strength and long-term potential of our company. I feel we've proven Cenovus has the right strategy, assets and people to be successful over the long term. I remain very optimistic about the future of our company. With that, let's get straight to your questions.
[Operator Instructions] Your first question comes from Phil Gresh with JPMorgan.
First question would just be in light of the curtailments, you've given some color about how the first 2 months look. But I guess, with respect to the full year guidance, maybe additional thoughts as to how we progress through the remaining 3 quarters just based on the way the current plan would look. And then secondarily, how do you think about the ramp of the rail here in light of where the differentials are? I understand it's a bit circular. The idea of the cuts is to get to a point where the rail is fully ramped up. But now the differentials are tight. So any thoughts about those would be helpful.
Yes, sure, Phil. What don't I -- I'll give you my thoughts on the rail ramp and then maybe I'll pass it to Keith and maybe Drew to talk a little bit about sort of our views on curtailment over the balance of the year. When you think about rail, I think it's really important -- and the government has been very clear on this, I think I recall the Premier even mentioning this publicly recently. But I think the government very much gets that curtailment needs to be managed over the longer term so as to ensure that there are incentives for rail to continue to be added. I remind everybody that although we're in a very low differential period right now, we are literally 6 weeks into this curtailment, this curtailment initiative. And I think there's been a lot of noise. I think there's been some short covering going on. But I do expect that the government is going to act to continue to look at those volumes to ensure they're at the right level to incent rail to get on. If you look at us, we're adding 100,000 of barrels of rail -- crude-by-rail this year. We're probably at, give or take, 20,000 right now. And our rail starts ramping in the beginning of Q2. And people should expect it to ramp linearly from thereon. I am highly confident that over the course of the year that rail is going to be an attractive strategy for us. And we tend to look at it as a structural element of our logistics of getting our crude to higher-value markets. Why don't I pass it to Keith and you can maybe give a little more color?
Yes, thanks, Alex. Phil, the government was obviously focused on monitoring this on a real-time basis. They've recently modified some their rules of engagement for the curtailment. So they're monitoring obviously the differential as well as the crude-by-rail and inventory levels and adjusting real time to try to get to those differentials that would incent crude-by-rail, as Alex alluded to. Most recently, they've put additional production back in, so additional supply back in for the month of February and March and are really managing this real time. For us, we have our rail cars starting to come off the assembly line in February and fully plan to continue to execute on our ramp-up strategy. Starting mostly in the Q2 time frame will be the ramp-up. In Q1, we are moving around 20,000 barrels a day out of our Bruderheim facility, which we own. And obviously, when we look at netbacks, the prices that we're realizing down in the Gulf Coast, just have to look at kind of January pricing, where WCS and WTI were almost par and even WCS trading slightly above WTI. So we see kind of the economics of getting our barrels into that Gulf Coast market as a key part of our diversification strategy to move barrels out of Alberta.
Yes. And just on that point Keith made, I think people have a tendency to look just at that WTI-WCS spread. But it is really important to understand that when you get that oil by rail down to the Gulf, you aren't getting WTI, in fact, as Keith said. For much of the first part of this quarter, we've been getting WTI plus pricing down in the Gulf. Drew, did you want to -- maybe you could talk a little bit about production expectations?
Sure. So Phil, it's going to be probably pretty premature for us to try to give you any guidance here looking forward. So what we plan to do here is just update real-time every quarter. So when we talk again here in April, we'll be able to kind of likely explain a little bit about the range for Q2 as we did here just recently for Q1 now that we know what kind of the February and March numbers are getting kind of curtailed or pushed to. So how we're managing that is our Deep Basin and other conventional volumes, we are not restricting at all because they receive generally a better netback against any other barrel we've got. So we are managing this between Foster and Christina right now. And considering the level that we're curtailed to now is actually a lot more manageable for us relative to our own curtailment or our own kind of reduction we put in even in Q4. So I'm not concerned about being able to manage to the levels and having any production or operating risk or issues that would concern us here for even for the balance of the year, depending on how, as Keith alluded to, the government will continue to monitor kind of market access, rail volume shipments and obviously inventory levels. And so for us to predict right now how we expect that to come off is probably a little premature.
Yes, okay, I understand that. I appreciate it. I guess, the second question I just had would be, do you have any recent color or latest thoughts on the timing of the Line 3 startup and when the line, Phil, might happen and how that might impact all these macro dynamics at play?
Why don't -- Keith, why don't you answer that?
Sure. Thanks, Phil. Basically, really what the government is doing with regards to the curtailment is looking for market access to balance the overall supply and demand. And one of those key levers obviously is the Line 3 startup as well as kind of the ramp in crude-by-rail in the province. Obviously, there's some recent announcements out of Minnesota with regards to Line 3. I don't think any of these are unexpected through from Enbridge's perspective. And they're still on track to potentially start that line, Phil, in the third quarter with an in-service date in the fourth quarter.
Your next question comes from Benny Wong with Morgan Stanley.
Just wondering around your rail capacity and its ramping, just wondering, is there any flexibility in that trajectory to augment it as needed with market pricing?
Yes, thanks, Benny. It's Keith here. Really, the limiter for us is the ramp-up profile of the rail cars. To put in the logistics infrastructure associated with a 100,000 barrel a day crude-by-rail operation, we need about 4,000 rail cars. Those rail cars will start coming off of the assembly line here in February and that really drives our kind of trajectory and ramp-up timing.
I mean, if differentials remain tight for whatever reason or the cuts kind of remain in place and the economics don't really support it, are you able to pull back on the rail volumes? Or are you committed to that kind of trajectory?
Yes, Benny, it's Alex. We have -- the features of those rail contracts is they have relatively low fixed cost to them. So we certainly have the flexibility if differentials were to remain extremely narrow there, we do have quite a bit of flexibility in that regard. From my perspective, as I said, it's really nice to see $10 differentials. I believe it highly, highly unlikely we'll be enjoying those differentials for very long into the future. So I expect that, that rail component that we have is going to be quite active in the second half of the year.
Great. And just as a follow-up, appreciate your thoughts on the mandated cuts and how it's played out. Just wanted to get your view in terms of just given how differentials narrowed in and we've been hearing from rails and producers that they stopped ramping up their rail capacity initiatives. Do you think that has actually impacted or hindered the industry as a whole visibility to ramp rail capacity when needed for the second half of the year?
Yes. No, I don't think so. As I said, if you look around, I think our government is still actively looking at ramping up their capacity. I think this -- as I said, I really view this as a short-term sort of scenario. As I said in my prepared or in my initial comments, we're literally 6 weeks into this and there's a whole bunch of noise going on. And I expect you've already seen the government adjust volumes once. They are -- in my discussions with them, they are very aware that differentials that are too low do not aid them in what they're trying to achieve. And so I expect that if differentials remain low, I'd be very surprised if we didn't see further reaction from the government in terms of level of curtailment.
Great. And just as a final one, just wondering if you can talk about your assumption of the Keystone XL capacity and how that came about and if there's any thoughts associated with that. And I'll leave it there.
Sure. Sure, it's -- I mean, quite simply, I kind of view this as very much a no-regret strategy. We have a very attractive toll on Keystone XL to the Gulf Coast, well under $10 a barrel. And obviously, Keystone XL has a couple of regulatory or legal challenges that it has to get by. But I'm an optimist. And I ultimately think it is going to get by. And in that world, I think -- I can't think of many scenarios where I wouldn't be happy with 150,000 barrels of committed Keystone XL capacity bullet line to the Gulf Coast for well under $10 a barrel. There really is not -- there's really no material cost associated with it in the event it doesn't proceed.
Your next question comes from Manav Gupta with Crédit Suisse.
A quick question. The realizations at Foster Creek were pretty much in line. But Christina Lake was a little lower. Was it just condensate timing? And more importantly, do we expect those to reverse in 1Q?
Yes, thanks for the question. It's Keith here. Predominantly, there's 3 factors that impacted the Christina Lake netbacks. The diluent timing is a big one. As a proxy kind of for diluent prices, WTI was in the mid- to high 60s in October and dropped to the mid-40s in December. Condensate pricing kind of tracks WTI pricing, so you can see a huge swing in the condensate pricing. And we acquire that condensate and move it through our system, but there is a lag on that timing. So we should see that reverse as we head into Q1. A lot of our Christina Lake barrels are sold at Hardisty versus our Foster Lake -- Foster Creek netbacks realize some of the transportation commitments that we have to get to the Gulf Coast in higher pricing. And I think the third thing that obviously happened in the fourth quarter, Christina Lake has higher TAN and there is a fair amount of refinery outages that consume that type of product that drove that differential between a high $10 and a low $10 netback a little wider, which has also essentially reversed itself coming into the first quarter.
And a quick follow-up is, like when the government is looking at the situation, obviously it doesn't really want to be involved. But its hand was more or less forced by what we saw out there. What is their exit strategy? Are they looking for Line 3 startup as an exit point? Or are they actually looking at a certain inventory level alone as an exit point? What do you think they are looking at to eventually roll back these cuts?
I mean, how I would kind of describe it, and I can't speak for them, but I think I understand how their thinking goes. But they're really looking for a situation where takeaway capacity is meeting supply. And I'm sure they would like to see those inventory levels continue to be lower. So I kind of think that the reason they gave that profile that they did in December of last year was, I think, they were really thinking about the ramp-up of rail and Line 3 and really being in a situation for them to kind of be out of this curtailment business towards the end of next year. And I think they're -- I would expect that, that still is where their thought process is. I don't know, Keith, if you have any color on that.
No, I think that's exactly right, Alex. And I think the other thing that they're doing with their rail commitment is really trying to put that buffer in place that allows kind of continued differentials in that rail economic range.
[Operator Instructions] Your next question comes from Neil Mehta with Goldman Sachs.
The first question I had was just your thoughts on the refining business here in 2019 and just how you think about some of the moving pieces. And in particular, you still have very favorable Brent-WTI but some compression in Midland in WCS. And just any color on Wood River in particular, given some of the headlines that were out about the unplanned downtime there.
Yes, sure. Thanks, Neil. Maybe I'll start with the back half of your question first and then get into kind of our view on the refinery business in 2019. Phillips obviously reacted to that fire pretty quickly. The unit was in the process of startup when the fire started, so they quickly took it offline, isolated the event and have the investigation team as well as the repair and restart plans are underway. So we'll know more here shortly on the extent of that outage and kind of the impact, overall impact of that. But the facility is still running. It was running at reduced rates and it's still running at those rates as we speak. As we think about the longer term, with the growth in the Permian and WTS-WTI, it's really going to be about how fast some of those export pipelines come online. We've seen that differential widen as well as narrow. And we're anticipating that it will widen back out a little bit here through 2019. So that puts Borger well-advantaged to a crude advantage. The other thing, obviously cracks narrowed significantly but have since widened out back a bit. And so the refining business is performing. And for us, obviously with the narrowed WTI-WCS differential, it's significantly improving obviously our upstream business. So we kind of look at the refining business as a bit of a natural financial hedge for us for when differentials are wide. And as they narrow in, some of that economic benefit shifts to our upstream.
That's really helpful. And then the follow-up is just if you guys can expand a little bit more on your comments around asset sales. You've done a terrific job monetizing different assets in your portfolio. It sounds like you've gotten to the point where you're happy with the portfolio you have and you don't need to -- see the need to sell further assets. And just tying into that. You think you're getting to that point where you can start thinking about either growing the dividend or buying back stock?
Yes, Neil, it's Jon. The way we think about asset sales, and I think we were pretty clear when we started this process is that so long as it made sense for the company there were certain assets that we were looking to divest ourselves of. And I would put this in the broader context of where we're going with our deleveraging program. And I would say that we would have a sense of urgency including asset sales to get down to that $7 billion range. But we were really clear as well that we weren't going to do anything to limit the long-term profitability of this company. So when we think about asset sales, they were really limited to the Deep Basin. And as it relates to that, we think that we've pretty much exhausted the supply of buyers or of credible buyers that were looking at the assets that we're potentially selling. So long story short, I think we put that on hold, and we still have the sense of urgency to get down to that $7 billion, but it's probably going to be without significant asset sales going forward.
Your next question comes from Paul Cheng with Barclays.
Keith, when we're looking at whether it makes sense to continue to ramp up the well, should we be looking at the price defense on WCS down in Gulf Coast like Latin Am and then comparing to in Hardisty? Right now, it's about say, call it, $11. I think your variable cost is probably about in the $12 or $13. So if that is the case, should we really going to ramp up the volume get discount defense sort of thing?
Yes, thanks, Paul. I guess the thing I would offer up is a bit of what Alex alluded to earlier to a question. When we look out throughout the year, we see that differential widening a little bit further. I think the other thing that we have to remember, most of our current crude-by-rail is moving through our own facility at Bruderheim. The ramp-up that we're anticipating to happen throughout the year will be at both our facility as well as a third-party facility in the province. So right now, we are seeing some advantaged costs because we're moving it through our own facility. And as we look forward, the differentials are wide enough to incent crude-by-rail.
Yes. Paul, if I can -- it's Alex. If I could just sort of maybe give a little color there. I mean, we -- with the economics of our own facility at Bruderheim, coupled with that crude advantage that we get in the Gulf by getting to the Gulf Coast, I mean, the rail movements even at these narrow differentials, they are economic for us and -- but not super economic. But we are definitely not losing money on those movements.
Great. Second question then on Deep Basin. Should we assume that even after you deleverage the balance sheet, say, down to, say, call it, $5 billion net debt as you mentioned in the press release, Deep Basin probably is not going to receive a lot of funding. Your next batch of incremental CapEx is -- what you're going to spend is probably going to be nothing?
Yes, Paul, it's Jon. I think that's a reasonable assumption on your part. And you'll notice that we've taken a write-off of some of the E&E accounts related to the Deep Basin. That really reflects what we've done, which is rethink the development plan in the Deep Basin. So we still think it's a good business going forward. It's something that's going to generate free cash flow, but it's going to be developed at a slower pace with less capital. But we think within that, again, we've got a good business for this company going forward. It's just not going to happen as quickly or to the extent we might have thought 1.5 years ago.
Just a quick question or comment. Jon, is there any reason why the write-down on the Deep Basin not treated as a special item? It's a big number comparing to the size of the company. And also that maybe I missed it, but the management D&A, it doesn't seem that is on your website.
Yes, I'll address the first comment, Paul. And I apologize, I missed the second one. But what I don't want to get into is constantly redefining how we get from operating earnings to other measures and the like. So we've kept a pretty consistent definition through time and this write-off that we have of the future development of the Deep Basin, you could argue, yes, it is a special item, but we've run it through our operating accounts based on the standardization of the definitions that we've put up.
Yes. Just the second one is just the management discussion and analysis. Maybe I look at the wrong pages but I couldn't find it in your website. So wondering if you guys already post it?
Paul, it's Kam here. You should be able to find it on the Annual Report section of our website, but it's on there.
Your next question comes from Dennis Fong with Canaccord Genuity.
The first is just on, I guess, the curtailments that you guys underwent through Q4. Given some of the, we'll call it production management themes, including dynamic storage as well as the use of salt caverns in, as described in I think in your Q3 call. How should we think about kind of the go-forward use or availability of those storage capacities if these curtailments get to be extended a little bit longer?
Yes, thanks, Dennis. It's Drew here. So when we chatted about it at the Q3 call, what we were -- we were just anticipating other mechanisms to help manage to these kind of wide differentials. Since the curtailment is actually coming from the government, the rules around that are actually measured directly at wellhead. So for any company that's got different assets or different potential storage options at the surface, like we do with caverns and different tankage, to manage your curtailment it's still all measured at wellhead, which means those other assets become more of just a marketing option if you chose to do that. So long story short is the current curtailment rules and the way that -- and where they are measured, those steps of other assets cannot be utilized to manage to a curtailed level because everything is measured and regulated at the wellhead.
Okay. I guess then the follow-up there is any of the store volumes that you may have done, call it in between sort of late Q3 and the end of Q4 within -- we'll call it storage within the context of the salt caverns. Is there a possibility that you guys could draw down your inventory levels and see higher-than-expected sales above and beyond your Q1 production levels as a methodology of kind of taking advantage of narrow differentials similar to some other marketers in the space?
Dennis, it's Keith here. Yes, you're bang on. All of those volumes that are in storage whether it be caverns or tanks are available for sale. They're past kind of that metering point that Drew alluded to, so we can place those into the market as we see fit.
Okay, perfect. And then my last question here is just on Christina Lake G. I was just wondering in terms of you've already started seeing operations, how should we think about notwithstanding the current mandatory curtailments from the Alberta government, what specific factors could we expect, we'll call it first production from it? And if the curtailments are extended, are there other operational uses potentially for the steam or how should we be thinking about the actual operations of Christina Lake G's expansion?
Yes, Dennis, it's Drew again. Yes, we're obviously very, very pleased with the team's performance here to be able to bring steam on already at that project. And obviously, being about 5 months ahead of schedule here, we know the facility and the infrastructure will be ready for us if we wanted to choose to start ramping up production here in Q2. Our limiting factor obviously is we were going to continue to only bring on production when it makes sense that it will add more incremental value and the precursor to that is obviously, can we actually have more market access. If we're still under curtailment, obviously, that will be limited. So what we are going to do is we'll utilize the equipment as well as the reservoir in where we distribute steam here in the rest of Q1 into Q2, where it makes the most sense to put us in the best possible position to leverage price and markets when they're available for ramp up. And today, I can't give you a time when we would be able to do that because we're still under curtailment for the foreseeable future.
But, Drew, it's probably worth talking a little bit about the efficiency of the new boilers and...
Yes, so the project itself, I mean, we -- the fact that we were able to come on early at this point in time of the year is pretty phenomenal, and we're going to utilize the equipment and the boilers. And to be able to build that project for between $15,000 to $16,000 of flowing is pretty economic even in these times right now and particularly, as the differential comes in, and we see a better netback price for any new facilities that we're going to utilize. So it's just a phenomenal project and to be able to have it available to us now at this point, as we come out arguably in the later part of this year, puts us in an extremely good position to get a lot of great cash flow for an extremely, extremely efficient project. So we're very happy with the timing that we've been able to execute this project on. And the fact that we have it available to us sooner than anticipated is excellent, which gives us a lot of optionality now to bring new barrels into a market when it's going to be very, very constructive and provide a lot of value here to the shareholders. So pretty happy with that project.
Your next question comes from Prashant Rao with Citigroup.
I wanted to circle back on the deleveraging and the progress you've made on the balance sheet especially given this commodity environment has been, I think, commendable. But sort of some clarification on some of the detail you gave there. So it feels like the $5 billion is more of the back-half achievement. I just wanted to confirm that, that's still on -- with -- on your current plan, something that happens within 2019? And then sort of wanted to talk about upside or downside risks on timing as far as you're seeing when you're internally planning here as to when we hit those hurdles, the $7 billion and the $5 billion, obviously a very dynamic commodity environment. A lot of moving parts here. But sort of the way you're thinking about kind of your baseline assumption for those as we look into -- further into 2019 and maybe spilling over into 2020, that will be great.
Yes, it's Jon. What I would say is if we got to $5 billion in the back half of 2019, I'd be absolutely thrilled. But I'm not counting on getting there in that kind of a time frame. And the way I would context this, and I think we've been very clear and very consistent with our approach to deleveraging and I'll reiterate it, is I would say that we have a great sense of urgency to get from where we are today to $7 billion. But what we are not going to do is make long-term strategic decisions to get there that impair the future profitability of this company. What we are going to do is make sure that the free cash flow that we generate beyond the dividend and beyond the capital budget that we've laid out goes to the balance sheet. The difference between the $7 billion and the $5 billion, and make no mistake, our goal is to get to $5 billion, that's where we're headed. But there will be other sources of capital that compete at the margin for free cash flow. So we've talked about returns to shareholders. We've talked about investments in the business in a range between $7 billion and $5 billion. Those will come back onto the table in terms of competing for some of that free cash flow but the priority will be getting to $5 billion. So I can't give you a time frame as to where we're going to get there but I can give you a prioritization of how we're going to allocate free cash flow between the balance sheet and then at some future time, between shareholder returns and investing in the business.
And if I would -- Prashant, it's Alex. If I would make one other comment. You saw in my prepared remarks, I talked about the cash flow generating ability of this company in a more normal commodity price environment. I talked about Q2 and Q3. I think a lot of people don't appreciate the free cash flow-generating capability of this company, once we've got out of these really, really cripplingly wide differentials.
Appreciate that. Just one quick one on current Keystone situation. Sort of, your thoughts on where things stand with identifying the source of the leak and how much -- what's the timing looks like from here from boots on the ground kind of view?
Yes, Prashant, it's Keith here. As -- I was in a conversation with TransCanada yesterday. It sounds like they've identified the location and are currently working through kind of a repair strategy on that one as well. As you know, the main Keystone line is still functioning and running at full capacity. It's the line that goes into Patoka that's off, and they're anticipating, I think, days not weeks.
Your next question comes from Mike Dunn with GMP FirstEnergy.
Just wanted to hear your thoughts, gentlemen, on your strategy for crude-by-rail ramp up. Given that you are potentially one of the major crude-by-rail shippers here, what you do you has some impact on the differential. So I'm just wondering if your plans to ramp up quickly in Q2 are relatively, I guess, insensitive to what you're seeing in terms of spot differentials or whether or not it's going to be dynamic and quite responsive to what you're seeing through differentials.
Yes, thanks, Mike. It's Keith here. I'll kind of reiterate a little bit of what I said. In order for us to facilitate our ramp up, we need to start taking possession of leased rail cars. Those rail cars, I think, we should be thinking about it as ratable. So those rail cars will start coming off the assembly line ratably starting kind of here in March and progressing all the way through to the end of the year to get us the capacity to actually ramp up to the 100,000 barrels a day that we had previously talked about. So we shouldn't be thinking about Q2, us being at 100,000 barrels a day. It's kind of a ratable ramp up throughout the year. And as we look at the forward markets on differentials, we see it as supportive of that type of ramp-up strategy.
Your next question comes from Jon Morrison with CIBC Capital Markets.
As we think about price realizations in the back half of '19, is there any guidance that you can give in terms of the mix of Foster Creek and Christina Lake barrels that you're expecting to shift to the Gulf Coast on your expanded crude-by-rail capacity? I guess the real question is, is it fair to assume that you're going to clear all Foster Creek barrels before Christina Lake?
Jon, it's Jon. What I would say is it really depends, Jon. It really depends on what kind of realization we can get in Alberta versus the Gulf Coast. And what we'll do is to -- what we'll stick-handle towards is maximizing the overall revenue for the company. So I can't give you any guidance as to which barrels are going to go. But what we will do is we'll make those short-term optimization moves as price signals come into play.
Okay. You talked about having the ability to not ramp Christina phase G depending on what happens with a number of market access factors, specific to Line 3 replacement. What are the principal things you're watching closest at this stage that could ultimately cause you to not ramp up phase G? Like, is it local permits at this point? Or are you waiting to see if there's further legal challenges that could delay things?
Jon, it's Keith here. Obviously, the facility is progressing extremely well. We hit first steam here in January. We're anticipating to be ahead of schedule on our ability to ramp up. So there's nothing at the facility that prevents us from ramping up. It truly is just a market access perspective. So obviously, under curtailment limits our ability to ramp up; following a post-curtailment world then it's just really market access. And so we watch Line 3 and our build on our crude-by-rail capacity.
Okay. Just a point of clarification and sorry to keep coming back to the same question, but naturally, a lot of shippers have talked about reducing their crude-by-rail volumes, but as soon as the curtailments came off, the arb will return to the market. So from your perspective, is there any reason that we shouldn't think about the temporary falloff in crude-by-rail volumes from an industry perspective being temporary? Or do you see any structural issues in the industry reramping volumes if they do come down for 2 or 3 months?
No. Jon, it's Alex. And I kind of go back to the point I made earlier. I think the government is watching this very, very carefully. I think they understand that single-digit differentials do not achieve their goals. And I think it would be highly, highly irrational for people to expect that those narrow differentials are going to continue for any extended period of time without the government reassessing their curtailment strategy. So I get the point -- yes, okay.
Maybe just a last one for me on the sustaining CapEx number, obviously it came in very low in 2018 and you guided to a very low number for '19. Should we be thinking about that '19 number as a new run rate? Or is it, perhaps, artificially low just considering some of the CapEx that you already spent in '18?
Yes, Jon, it's Drew here. So first off, I have to probably state that we continue to improve the cost structure of this company and particularly at oil sands sustaining number. I'm -- continue to be impressed by this team and what they are able to do as far as their ability to kind of redesign, redistribute kind of into the reservoir itself, and then obviously, the productivity of the teams that actually end up spending the capital against all that. If you look at the 2019 number versus the 2018, this was going to be our plan regardless of curtailment, if I could say it that way. We've got a long-standing kind of schedule of when we need and have to develop pads, depending on current SOR rates and current production rates and levels. So the current curtailment kind of does give us a little bit of room from a timing perspective, but it's likely not enough to make a material change in kind of the capital profile we need to sustain our oil sands production. So what I'm really trying to say here is, a lot of this work that we've done to get it to this level is structural in nature, which means it's kind of a new level of, kind of, unit cost that we have. Now the only thing I would add to that though is on any given year, depending on what parts of the reservoir need to be replaced with new well pairs to offset current production, we may have fluctuations on any given year for capital. But it's the structural change that has gotten us down into this $4 to $5 range, those are all structural in nature. Now it may fluctuate from time to time in the coming years as we may have 6, 8 pads that need to come on versus a year that may only have 2 or 3. So that's the only fluctuation that might change in a capital kind of guidance range. But the structural change in our cost structure here is fairly sustainable.
Your next question comes from Asit Sen with Bank of America.
I just had a quick question on the cost comments that you made. On Slide 4, you mentioned holding per unit operating costs flat despite upward pressure. Can you talk a little bit about the key sources of the upward pressure that you're seeing currently, outside of perhaps fuel costs? And how do you think the cost environment changes heading into next year?
Yes, sure. Thanks, Asit. So the comment we put in there was really about the continued kind of performance that the operating teams both in oil sands and Deep Basin have achieved. I'll just touch on Deep Basin here quickly. I mean, we're going to hold operating costs flat in the 17% production decline environment, which is still a pretty significant improvement in the underlying cost structure of that asset. So we're pushing the teams pretty hard to kind of do the right thing. In oil sands, if you look at the structural change we made in the last 3 years, it's quite phenomenal particularly on our nonfuel. We are getting down to a level where I think is still fairly sustainable, but we are definitely pushing a lot of our suppliers and a lot of our input costs on both the fixed and variable side. And so some of the pressure that we have seen is a little bit on just general unit costs around chemicals and some other commodities that aren't directly tied to the actual commodity business we're in. So there's a little bit of pressure there. But at the same time, the teams are still engineering other ways to overcome actual usage volumes, which means as your kind of unit costs might have some pressure, if we can start to utilize better usage and volume against that pressure increase, we're expecting to still remain flat overall. But we're always going to have different pressures, but they're not material. And I think for us to continue to hold at these types of levels in a -- obviously a fluctuating production environment with curtailment in oil sands, I think is still pretty phenomenal performance by the team.
That's great. And then on -- your comment on a sustainable -- or a per barrel sustainable cost and you mentioned productivity and design elements to it. Again, it's probably nitpicking, but the $3.50 to $4 per barrel number, what gets us closer to the $3.50? It's mostly productivity at this point, or it's the volume?
To be honest, it's been both. I mean, we are -- our longest -- our wells are continuing to get longer on average. The productivity rate and the amount of resource recovery we're getting actually continues to improve. So when you look at that on a per barrel basis, you also have to remember that we're actually increasing our actual recovery of barrels. So in the last number of years, not only have the teams done a great job on actual redesigns literally of both the on-surface facilities as well as the subsurface and well designs. And the productivity gains on the construction side, both in the facility and the drilling completion groups has been phenomenal, but the reservoir teams have actually increased recovery on -- and the actual well pairs that are now getting put in. So we're getting benefits across all 3 platforms, which allows us to structurally change into this range that we're getting to.
Your next question comes from Harry Mateer with Barclays.
First question is should we view the liability management you did in January with your bonds out the curve as an ongoing tool for the company this year? And then related to that, what's the minimum cash balance the company is comfortable running with?
It's Jon. I'm going to be very reluctant to answer your questions directly. But what I would say is we continue to look at our liability management options on a day-to-day basis, and I would be remiss to telegraph exactly what we're going to do through open market operations. But what you should take from what we've done over the last couple of months is what we would view as an opportunity to take advantage of a market situation. And going forward, it wouldn't surprise me if we were going to continue on that path assuming we can get the same kind of economics.
And minimum cash balance, is that something you could share?
No.
Okay, that's fair. And then just to follow up, is your expectation right now that you'll be able to retire the remaining piece of the 2019 maturity with cash flow?
Yes, we've been very clear. That's our intention is that we will be retiring the October maturity with the balance sheet.
[Operator Instructions] I will now turn the call over to Mr. Pourbaix.
Thanks, everyone, and thanks for your interest in our company, and we'll get back to work now. Take care.
Okay, this concludes today's conference call. Thank you for your participation. You may now disconnect.