Cenovus Energy Inc. (CVE) Q4 2019 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Fourth Quarter and Year-End 2019 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 Ms. Sherry Wendt, Director, Investor Relations. Please go ahead, Ms. Wendt.

Thank you, operator, and welcome everyone to our fourth quarter and full-year 2019 results conference call. I 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 will provide brief comments, and then we will turn to the Q&A portion of the call with Cenovus' leadership team. We would ask analysts to hold off on any detailed modeling questions and follow-up directly with our Investor Relations team after the call. We would also ask that you keep to one question with the maximum of one follow-up question and then rejoin the queue for any other questions. Please go ahead, Alex.

Thanks, Sherry, and good morning, everybody. As always, I'm going to keep my prepared remarks short and to the point. I'm sure everybody has seen our fourth quarter and full-year financial and operating results that we released a few hours ago, and most of you will recall our news release from December 10th of last year when we announced our budget for 2020. Today I want to highlight the achievements of the past year and give some color around how we believe 2020 will shape up. But first, I want to thank our teams for continuing to run safe and reliable operations across our asset base. Our overall health and safety performance improved last year from 2018 due to our continued focus on risk management and asset integrity, and we achieved the second lowest recordable injury frequency in our history. Safety is fundamental to our business and the safety of our people and assets will continue to drive our performance. Throughout 2019, we continue to deliver on our commitments to our shareholders. We maintained our industry-leading low cost structure, continue to exercise capital discipline, strengthen our balance sheet, increase market access, and enhance shareholder value. We also exceeded an important milestone in our crude-by-rail business last year, moving more than 100,000 barrels of oil per day by the end of 2019. We set an ambitious goal to grow our rail capacity from essentially zero to 100,000 barrels of oil per day by December, and I am happy to report we exceeded that goal. Our rail program is an important part of our strategy to improve market access, so we can achieve greater exposure to global oil pricing. Through the recently announced Special Production Allowance or SPA program, rail also allows us to exceed the government of Alberta's mandated production curtailment levels. I am extremely proud of the work our teams did to successfully build our rail program in 2019. This year, we will continue to optimize our rail operations to maximize value. This could mean shipping more or less than 100,000 barrels a day in any given month. For example, in January, we loaded approximately 120,000 barrels a day from our Bruderheim Energy Terminal and Hardisty, Alberta Terminal combined. As a result of the SPA program and our increased rail shipping capacity, we have returned to unconstrained oil sands production, which allows us to bring on volumes from our Christina Lake phase G expansion. The ramp up of Christina Lake phase G is expected to occur over the next six to 12 months. Looking at the financial highlights for the fourth quarter of 2019 and the full-year, I want to point to the continuing cost discipline we demonstrated even well under mandatory curtailments. Our oil sands operating costs were $8.06 per barrel in the last quarter of 2019, essentially flat with the same period a year earlier. Full-year per barrel operating costs rose 7% from 2018, primarily due to lower volumes as a result of mandated curtailment and the largest ever turnaround at Christina Lake completed in the second quarter. We also continued to see progress on the Deep Basin with full-year total operating costs declining 16% from 2018. In addition in 2019, we continue to achieve further reductions in our oil sands sustaining capital costs, which declined 10% to approximately $4 per barrel of capacity from the previous year. All this is a testament to the great work our teams have been doing to keep our costs under control, while managing crude oil production levels under mandatory curtailment. We are confident that the majority of our cost improvements over the last few years are structural in nature and are sustainable. Fourth quarter oil sands volumes averaged more than 374,000 barrels per day, up from approximately 355,000 barrels per day in the third quarter of 2019. While mandatory curtailment reduced our overall production volumes in 2019, it helped keep light, heavy oil price differentials from reaching the record highs we saw at the end of 2018. This resulted in a substantial benefit for Alberta with significantly higher royalty payments to the province. Cenovus alone contributed more than $1.1 billion in royalties to the provincial government more than double the amount of royalties we paid in 2018. To put that into context, Cenovus accounts for roughly one fifth of all royalties paid to the province. When you think back on the fourth quarter of 2018 when differentials rose as high as $50 per barrel and Cenovus was in a net royalty credit position, it was our view that mandatory curtailment would play a significant role in correcting the imbalance in the market. Our current view is that a market imbalance still exists and that production curtailment is still necessary to ensure Alberta receives fair value for its oil. To achieve fair value, we believe the government should manage the WTI, WCS price differential at Hardisty to approximately US$10 per barrel or essentially the crude quality difference, plus the cost of pipeline transport from Alberta to the Gulf Coast. Any differential higher than that means that Alberta is transferring value to the downstream buyers. Deleveraging remains a top priority for Cenovus as we continue to pursue our net debt target of $5 billion. We made significant progress towards this goal in 2019, reducing net debt to $6.5 billion by year-end from $8.4 billion at the start of 2019. At a net debt level of $5 billion, we anticipate being in a position to maintain a target ratio of less than 2x net debt to adjusted EBITDA at bottom of the cycle commodity prices. As a result of our low cost structure and focus on maintaining capital discipline and balance sheet strength, we continue to demonstrate strong financial performance in 2019. We generated adjusted funds flow of more than $670 million in the fourth quarter, bringing total adjusted funds flow for 2019 to approximately $3.7 billion more than double the adjusted funds flow generated in the previous year. Our full-year upstream results benefited from a significant narrowing of the differential between WTI and WCS as well as increased sales of locations outside of Alberta, where we were able to achieve higher realized prices. Refining margins were lower compared with 2018 primarily due to reduced crude cost advantage as heavy and medium sour crude oil differentials narrowed. With the actions we have taken over the past several years, we've built a business we believe is resilient and sustainable even at bottom of the cycle commodity prices of around $45 WTI. Our business plan includes significant capacity to generate free funds flow across the cycle, while also continuing to increase returns to shareholders. Based on these achievements, I am confident we can be very optimistic about the future prospects for our company. We will continue to work with the government on a reasonable and responsible Canadian energy policy. We believe the best path forward to improve global emissions is to support a vibrant Canadian energy sector that can invest in emissions-reducing technologies while continuing to make a strong contribution to the national economy, create jobs, invest in local communities and support indigenous business and employment. As you will have noticed just last month, we announced ambitious new targets in four environmental, social and governance focus areas: climate and greenhouse gas emissions; indigenous engagement, land and wildlife and water stewardship. These targets include a goal to reduce our upstream GHG emissions intensity by another 30% and keep absolute emissions flat by 2030 as well as a 2050 aspiration of net zero emissions. Our commitment to advancing performance in our four ESG focus areas reflects a continued integration of sustainability into our strategy and business plan to help foster long-term resilience. In addition, on January 30 of this year, we announced a commitment to spend $10 million per year for at least five years to build much needed new homes on six First Nation Métis communities located closest to our oil sands operation in Northern Alberta. We see this initiative as an important way to contribute to reconciliation with indigenous peoples, investing in indigenous communities near our operations and ensuring that they share on the benefits of resource development have always been part of how we do business. With the housing initiative, we are acting on an opportunity to step up and do more. Just before we take questions, I would like to introduce Norrie Ramsay, who as you know on January 1, officially took on the role of Executive Vice President-Upstream. As you know, Drew Zieglgansberger has moved into his new role as EVP Strategy and Corporate Development, while Kam Sandhar has transitioned to Senior VP, Deep Basin. So welcome Norrie. And with that, why don't we get straight to your questions.

[Operator Instructions] We will now begin the question-and-answer session and go to the first caller. Your first question comes from Greg Pardy with RBC Capital.

Thanks. Good morning. A couple of questions, but maybe the first one is, is just having to do with the volatility in oil prices that we've seen here over the last couple of months. How are you now thinking about your hedging policy?

Thanks, Greg. It's Jon. And this is a question that often comes up as we kind of trend into the bottom of the commodity cycle. But I think we've been really clear on how we think about hedging. And we have said emphatically that the balance sheet is the right way to manage the commodity price volatility. We still believe that we don't believe that a hedge program is the right way to handle commodity price volatility, and it’s certainly not the right way to manage the balance sheet. So we'll continue to put the balance sheet in a condition where it can withstand bottom of the cycle pricing. And to a large degree, we're probably getting closer and closer to that point. I think we've also said that we don't have a fundamental objection to hedging, but we do recognize the dry bitumen is a very difficult, if not impossible product to hedge perfectly. So that all being said, we do it time step into the market at a limited way to take some minor positions on WTI and the differential, the WCS-WTI differential, and I would see that continuing through time. But the reality is the financial model is predicated on a strong balance sheet and the ability to withstand commodity price fluctuations, notwithstanding the fact that we do or will look at doing some of this opportunistically.

Okay, great. And then maybe just shifting gears, coming back to your – or I guess, kind of just thinking about your investigation of the DRU. So there were some pieces that were outstanding there, and I'm just curious where you're at in terms of determining what the price uplift might be on dry bit versus dilbit in the Gulf, conceivably backhauling that into Alberta? And then separate, but related is, is if you do go ahead with the DRU, would you contemplate something where you're using third-party funding or what have you?

Thanks, Greg. It's Keith here. We're still in the investigation stages of the DRU. We’ve talked about trying to get this decision to a point where we could make an FID at the back half of this year. And I would say we're still on that path. Everything that we've been doing with regards to the research around this project and discussions with the refineries and the rail companies is lining up that we do actually think there's a potential project here. When we look at it, obviously removing the condensate in Alberta is very helpful when you consider the amount of condensate we consume. When we look at the valuation of neatbit relative to dilbit, and the fact that heavy barrels have really disappeared from the market down in the U.S. Gulf Coast and additional light barrels have come into production through shale plays, we do think that certain refineries are seeing or would see kind of that value uplift from that neatbit. And those conversations are progressing, and I would say, they’re progressing pretty well. I think the other component that that's going to be critical to making this project economic though is around the freight and transport costs, and we are working with our rail partners. Obviously, we built our rail program over the past year and a bit and have good partnerships with those service providers and working with them, because this structurally changes that business model for them and drives to a multi-year, multi-decade type business model. So they're very interested in this model, but it would take all those pieces kind of coming together to kind of drive an economic decision. And like I said, we'd be looking at that at the back end of the year. With regards to the backhaul of condensate, that is something that we will evaluate. We don't see it as critical for this decision. Really what we're looking for on the FID decision. In a congested market, where pipelines don't progress, this project makes a lot of sense. And then in a market where it's unconstrained, you have all the pipeline access and egress out of the province. We're really trying to make sure that this project is sustainable through that type of environment as well.

Greg, it's Alex. I was just going to add one other comment, and I think a lot of people have heard me say this, but we are very much intending to bring the same kind of capital discipline to this decision is I think we're trying to show on all of our other decisions. But I do think it's important to remember that we don't tend to think of this as growth capital. I look at it as risk reduction capital. We're going to be very, very cognizant of what market access, where it's going. And in a world if market access were in our view to be remained constrained, and we had an opportunity to execute on a project that could take basically a quarter of our production and remove it from the vagaries of the Alberta market and differentials. That's something we're just going to be thoughtful about. Anyway with that, I'll turn it back.

Okay. And last quick one for me is, you had a $70 million exploration expense, I think in the fourth quarter. Was that just a write-down in the Deep Basin? Or where would that have been?

Yes. Hi, Greg. It's Jon again. The vast majority of that was in the Deep Basin, and it's in the E&E accounts. So as part of every year, we reevaluate all of our plans in each of the different businesses. And it really reflects our new development plan, our continued development plan in the Deep Basin, and then how we think about those opportunities.

Okay, terrific. Thanks very much.

Next question comes from Emily Chieng with Goldman Sachs.

Hi, good morning. First question I have here is just around the cost component that we saw in the quarter, in particular with respect to transportation costs, blending and fuel costs. How that changed quarter-over-quarter? And aside from the impact of higher volumes in 2020, where if any, do you see the trajectory of those three components trending?

Hi, Emily. It's Jon again. There's really two components to that. One is the condensate costs and the other is the transportation costs to get our oil out of Alberta and down into the marketing hubs in Chicago and the Gulf Coast. And what we saw on an annual basis is actually the price of condensate or the cost of condensate came down year-over-year. But in the fourth quarter, it did increase. And what we have seen again through the year as we move more and more of our volumes to the Gulf Coast from Alberta, that unit cost is going up. So if you were thinking about modeling this, Q4 is probably a good run rate going forward.

Got it. Thank you. And then my second question is just around Christina Lake phase H and Foster Creek phase H. What sort of work here needs to be completed before we can start thinking about whether or not these get sanctioned in the second half of the year? Thank you.

Hi. It's Norrie Ramsay here. We obviously will retain our capital discipline and ultimately the decision will be driven by egress access. We've been working over this last year. There's very little capital required for both phases in preparation for sanction, but it will be a later in the year decision and it will be subject to confidence in our egress.

Great. Thanks.

Next question comes from Phil Gresh with JPMorgan.

My first question is I think somewhat similar to the last question. In the sense that if you are to move forward with the DRU, and you're still thinking about future phases of FCCL from a capital spending perspective. Is there a way you're thinking about balancing multiple projects at once and would there be a some kind of constraints, I guess, or limit on the amount of capital that you want to spend if you move forward with that scenario? Just going back to the Analyst Day and the questions around that, there are a lot of nuances to the plan. So any additional color would be helpful.

Yes. Hi, Phil. It's Jon again, and thanks for the question. And you're right, and nothing's really changed since Investor Day. If you look at the capital plan that we gave you, we didn't have any capital for the DRU in that plan, and we will come to that, as Keith said in the fourth quarter. What we're really trying to balance is the capital program to the balance sheet to market access with a forward view of the market that's going to overlay that. So as all of those things come together, what I would say is once we do FID these projects, it would be our intention to finish them. We don't want to put ourselves in a position where we're moving them up and down, but we've been really clear that any kind of growth that we would see at FCCL is contingent on our view of transportation as well as where we are with our balance sheet.

Hey, Phil. It's Alex. I mean, maybe this doesn't need saying, but it's probably worth saying. When we came up with that five-year plan, it wasn't coincidental that the number one focus we said was balance sheet improvement. And that continues to be a priority for us. And we're always going to assess these other initiatives in the context of making sure we deliver on that aspect of the plan.

Sure. Okay. And then I guess just to follow-up on that, I mean is there a scenario where you would do multiple phases of FCCL at the same time as the DRU?

Hey Phil. It's Drew here. So maybe another piece of context here is that, when we think about the DRU and we think about that project itself, it really doesn't look that materially different than an oil sands phase as far as the actual kit and whatnot, actually. And I would argue it might even look a little simpler. But when we come to a decision around DRU and the capital, I mean there's a number of different financing options to consider that. And so as we laid out in the five-year plan at Investor Day, we didn't have the DRU capital explicitly because we have different options in order to do that. But as we think about the two FCCL phases, we still have the internal capability to do those. Foster Creek is not as intense from a man-loading standpoint as Christina H would be. There's about a two-year gap of when each of them would come on in 2023 or 2025. So we can spread our manpower quite effectively over that. And if we think about a timing of when and if the DRU went, we don't have a lot of concern there either as far as being able to manage that out of the major projects team that we still have in the company. So I think there's still a lot of flexibility to Jon and Alex's point about how we consider balancing that in a timing standpoint with the balance sheet. But as far as the risk of executing and looking at what these different projects are, we don't see that as a significant risk or strain to the company.

Phil, it's Jon again. Just to add to that, and I take Drew’s point on organizational capability being one restriction that we think. We obviously consider, but we think we've got well in hand. The other thing I would say is we're not going to put ourselves in a position where we go cash flow negative to get these things done or free cash flow negative. We've talked at length about the value of having free cash flow and options and liquidity in this market and those priorities still stand.

Okay. My follow-up was just on the rail situation. I presume you would have made some comments if you had signed up for any of the recent government contracts. But maybe you could just confirm that or give your stance on it? Thanks.

Yes, Phil, it's Keith here. In January, we were able to move about 120,000 barrels a day. I just want to reiterate that was on our existing contracts that we had through that time. We're pleased with the government's policy announcement around the supplemental production and allowance, that basically allows us to unconstrain our program. But we're also happy with the current size of our rail program. So we obviously had a look, but we're happy with where we're at right now.

Okay. Thank you.

Next question comes from Phil Skolnick with Eight Capital.

Yes, thanks. A couple of questions. Just first, just back on the DRU unit. I guess what's the ultimate deciding factor there, because there was a comment that was made earlier, just you first started off saying if we're in a pipe, a situation where the egress is still not completely there on pipe, this thing makes a lot of sense. But then it sounded like as if you're in a situation where we do have enough pipe capacity, the project still is what you want to make sense. Is that how you're looking at that? You're trying to make this thing work all around?

No, I mean – Phil, it’s Alex. Maybe I should have made myself a little clearer. We think of the DRU as a strategy related to alleviating market access issues. And we're not looking to spend unnecessary capital. So if we're in a world where we see some subset of the development pipelines going ahead and we can achieve those kinds of – we can achieve pipeline differentials in getting our oil to market, then I would see relatively a little need for a DRU. If on the other hand, we look to be in an era where we're going to be continuously or largely constrained getting out of the province and that is driving wide dips and we can lock up pipeline type differentials through a combination of DRU and rail, then that would be a very important milestone for us and how we think about this. But we're not looking to build a DRU for the purpose of building a DRU.

Okay. That sounds good. And just my other question is, you railed 106,000 barrels a day in December, and you have 100,000 capacity right now. Is that that extra six, is that due to efficiencies or did you use third-party rail? And if it was due to efficiencies, then what does that mean in terms of your overall rail cost per barrel?

Yes, Phil. It's Keith here. So 106,000 barrels in December, 120,000 barrels a day in January, so we spent a lot of time in 2019 building the program, getting all the cars. We now have all of the capacity. And what you're seeing is, is basically cycle time reduction. When we put our plan together, we had forecasted that it would take us 24 days down and back on a cycle time for a unit train. We've optimized that program. We're now down below 20 days where we're sitting right around 18 days. We've extended the length of the trains, added more cars to the train. So we are seeing those efficiencies that allow our program to flex up and down and 2020 will really be a year of optimizing. So as we see value from moving additional barrels down to the Gulf Coast, we can flex up. If we see a value in slowing down the program a bit, we can do that as well. So we're really working to optimize the program through 2020 and some of that is exactly the back end of your question with regards to maximizing the value and keeping our costs as low as possible.

All right. Thanks. That's it for me.

Next question comes from Matt Murphy with Tudor, Pickering.

Good morning. Just wondering, Keith, if you could address the extent to which you see the recent announcements by some other rail operators to create, I guess a bit more of a process around handling hazardous products such as crude as well as speed reduction limits, slowing your ability to move barrels where it seems like obviously – differentials have tightened up versus WCS Houston quite recently? Thanks.

Yes. Matt, it's Keith here again. Obviously during situations like this, we're in almost daily contact with the railroads. The railroads have demonstrated a very good capability of moving product and commodities over the years safely. And obviously they're very focused on looking at these recent incidents and learning from them. I would tell you that the recent embargoes put in for us moving unit trains has limited impact. We've seen a little bit of a slow down, but not material to this point. What I would say is some of the blockades could potentially jeopardize some of the movements across Canada. So we are obviously very active in monitoring the situation, currently limited impact to our business.

Got it. Helpful, thanks. On unrelated note, I'm just wondering if you could offer your thoughts on the potential for disclosures and targets on emissions to one-day approach, Scope 3 for example versus your currently laid out targets. You've seen a number of your larger peers in Europe, for example, laying out some targets through that lens. Certainly don't want to downplay the targets that you've laid out there. Just curious, any thoughts on Scope 3?

Yes. Matt, it's Al Reid. That's not something that we're looking at doing today. What we put out was targets that really look to reduce the emissions that we manage and we control. And that's where we're comfortable today. Certainly some other operators have put out Scope 3 targets, but they have emissions that they manage over a larger scope of the whole value chain. And for us, it's really limited to what we manage and that's what we're comfortable with today.

Okay. Helpful. Thanks very much.

Next question comes from Asit Sen with Bank of America.

Thanks. Good morning. Two quick ones. First on Slide 7. Oil sands sustaining CapEx increase in 2020 due to deferral of sustaining CapEx in 2019. Could you remind us how big that component was?

Hey, Asit. It's Drew here. So you're right. I mean, when we looked at 2019 due to some of the curtailment, obviously, but also just the team really kind of optimizing how we're managing both the production, but also just the recovery of the well, current well pairs in the assets. We've been able to bring that down substantially. And obviously, it's about $4 – just under $4 a barrel last year. So as Norrie talked earlier, we're looking at the H phases, which we have to take into account over a two, three-year period. The different in each asset, how much capital is required and bringing pads on at a certain time to obviously maintain the production and even allow phase G to ramp up as this year kind of goes. So this year it's up a little bit. As you look at our budget, it's about 70% of our capital budget is to sustain in the organization. So our level right now in oil sands is in the $600 million to $700 million range of that, I mean, we're still in that $4 to $5 range to maintain our production, which is still extremely low. And the teams continue to find good synergy and the cost savings as they keep looking at our sustaining capital. So you have to remember though that the timing of when we need pads on any given year is going to slightly fluctuate on any given calendar year. So how you should really continue to look at it is just what we've done on a per barrel basis in that $4 to $5. And you might even have a year where it goes to $6 per barrel, but that's just purely because of timing and sequencing of when pads are needed so.

Got it. That's very helpful. Thanks for the color. And then not to deliver this point, but as you look further to increase your exposure to the U.S. Gulf Coast and the options being rail, DRU, and let's say, Enbridge Mainline. When you're evaluating that and thinking about the macro, is it fair to say at a low bottom of the cycle of price of $45 a barrel that you stress test your outlook, pipelines become more favorable.

Asit, the way we kind of look at this today is, yes, when you look at the pipeline costs and transport costs of U.S. Gulf Coast, we're really looking at a portfolio of options. What we're trying to do with the DRU though is make it competitive against that pipeline option, so that it can compete in that world. But what I would offer up is that with regards to the Supplemental Production Allowance program, the SPA program and rail economics, we really look at it at differently. So we think that the government could actually manage [Audio Gap] and manage that differential to U.S. Gulf Coast pricing plus a $10 transport costs. And then they have the rail barrels that would move under the supplemental production allowance, which make up somewhere in the 400,000 to 550,000 barrels a day that people, the way they would look at those economics would be, can I produce the barrel? Can I transport it at rail costs and my netback that I get from selling it in the Gulf Coast? So we really see them as separate economic decisions because with the SPA program, it's basically a barrel that you can produce that you weren't able to produce without the rail program in place.

Thank you.

Next question comes from Fai Lee with Odlum Brown.

Hi, Fai here. Just a question for Alex. With respect to your greenhouse gas emission target, I'm just wondering, if you comment a bit about your confidence around achieving the target and the key milestones that have yet – you have to reach in order to reach the targets. Also related to that question, I'm just wondering what your sustainable targets mean with respect to your production beyond the 2% to 3% production growth that you have in your five-year plan? Thanks.

Sure, Fai. I mean, right off the bat, talking about that 30% reduction in GHG intensity over 10 years, I mean this is, I think it's really important to remind people that this is just a continuation of what Cenovus' has been doing for many, many years. And as I'm sure you're aware, over the past – over the past 12 or 15 years, we've already reduced our emission intensity by around 30%. So we see this as just sort of a further movement along that path of improving our environmental footprint. And about a year – well, probably over a year ago, we realized that this was something we wanted to take a real hard look at committing to. We put in a solid year of work with our – both our internal experts and a number of leading global experts outside of the company. And the plan that we came up with, and obviously there's going to be more to come about the specific levers that we intend to pull, but we’re quite confident that we have levers in the business that will allow us to reach those targets over 10 years. We think we can do that largely if not entirely within that five-year plan we delivered to the market towards the end of the year. But to give you an idea, I mean, I'll just think of a few things that are in our sort of plan, continuously improving our production processes. And as I said, there'll be more to come about that, but I think that's an area that we actually see it at relatively little to no capital costs. We can actually drive quite meaningful GHG intensity improvements. We already have cogens in our facilities. Nobody should be surprised to potentially see more cogens in the plan going forward. We've been working on solvent technology for many, many years and was probably something that we were planning on rolling out. That would obviously be a big component of the strategy. And then there's a bunch of other things like, we've been working on reducing our methane emissions out of the Deep Basin. That’s going to be a part of it. I would just say there's a broad suite of other things. Even things like increased use of data analytics. We think there's actually a significant price there in terms of improving our GHG efficiency. So kind of just to put it in a nutshell, we're highly confident that we do have a set of tools that can get us there and can get us in there within the realm of the capital programs that we've been considering and have communicated to the market. And our plan is over the next year or so, as we formalize those, we'll be coming out to the market and giving more color on them.

And in terms of the production, are there any assumptions about production growth beyond the five-year plan like to hold production flat, continue to grow at 2% to 3%? Or are there any assumptions built around the targets?

Yes. I mean like right now, the targets that we would be – that we have set are contemplating just that growth that we have right now that we've communicated in that plan. But – and we would obviously have to take a look at that. And as you also saw, we've committed to a 30% intensity reduction and also keeping our absolute emissions flat. And that is predicated on a view of the opportunities in the projects we communicated at our Investor Day.

Okay. Thank you.

Yep. No worries.

Next question comes from Dan Healing with The Canadian Press.

Thanks for taking my question. It sounds as though Cenovus did not take part in the Alberta government's sale of its rail contract. Can you verify that? And also, I'm curious why you wouldn't have taken part in it since it sounds like the government is taking a bit of a loss on it, which suggests there might have been some good deals?

Hey, Dan. It's Alex. As Keith said, we look at everything and given our involvement in the rail business in the province. I think it's a safe bet to consider that we took a pretty hard look at it. But I think as Keith also said, we're pretty comfortable with the rail program that we have right now. So in order for us to look at something, it would have to be pretty compelling. So I mean, we were very happy to see that those contracts are in the hands of industry. I think that's better long-term for everybody. And I think we just go on from here.

Okay, thanks.

Next question comes from Jon Morrison with CIBC Capital Markets.

Good morning, all. Just a point of clarification, if you get to a point where the DRU makes economic sense, but you aren't overly comfortable with a margin of error and your cash flow coverage to: one, continue the deleveraging plan that you guys have laid out; and two, fund the development program that you put out at the Investor Day. Is it entirely logical to assume that it probably goes forward, but maybe you look at third-party partnership or ownership models at that stage as kind of any potential concerns of the market of flying too close to the sun just aren't in any playbook on the horizon within the company?

Hi Jon. It's Jon. I think that's reasonable to assume. We have a lot of options if we chose to go ahead with the DRU as to how we might choose to finance it. What I would say is we've put a lot of work into getting our balance sheet into the condition that it's in and we're not going to jeopardize it for growth projects. That all being said, we think that when we get to the end of the year, the DRU looks compelling in terms of its economics. We'll work hard to make sure we have financial capacity to do that if that's the direction we choose to go.

And if the feed were continues in the DRU, is there anything shaking kind of the original goalposts that you put out there of $800 million to $1 billion of 180 inlet volumes and 120 neatbit?

Yes. None of that is changed. That's still the scope and cost estimates that we're looking at.

Okay. Maybe just a final clarification point. Keith, you talked about the increased throughput in both December and January, but just a point of clarification is, did you need to use any other companies loading slots at the export terminals to achieve that throughput? Or hypothetically you could achieve a similar number go-forward if there is a downstream bottlenecks on the system?

Yes, Jon, as people maybe aware, we own rail loading facility, we've spent some capital through 2019 to debottleneck that facility. We have the capacity to load two-plus unit trains a day out of that facility. So the combination of kind of efficiencies in utilizing our fleet of cars as well as working with the freight contractors and the other operator of the loading facility, we're able to kind of flex up and down that program.

Okay. Appreciate the color. I'll turn it back.

And at this time, I'll turn the call over to Mr. Pourbaix.

Well, I think that's all the questions. I just want to thank everybody for joining us today, and the call is complete and everybody enjoy their day. Thanks.

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