Cenovus Energy Inc. Q3 FY2020 Earnings Call

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Cenovus Energy's Third Quarter Results Conference Call. 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. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Cenovus Energy. I would now like to turn the conference call over to Ms. Sherry Wendt, Director, Investor Relations. Please go ahead, Ms. Wendt.

Thank you, operator, and welcome everyone to our third quarter 2020 results conference call. Here with me is our President and Chief Executive Officer, Alex Pourbaix; our Chief Financial Officer, Jon McKenzie; our Executive Vice President, Upstream, Norrie Ramsay; and our Executive Vice President, Downstream, Keith Chiasson. 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 will provide brief comments and then we will turn to the Q&A portion of the call. Please go ahead, Alex.

Thanks, Sherry, and good morning, everybody. Did you know, on Sunday, we announced this strategic combination between Cenovus and Husky to create a resilient integrated energy leader? This transaction optimizes our cost structure, expands our market access, and strengthens our balance sheet. It positions us as a more resilient company with increased and more stable free funds flow. It also gives us opportunities to expand margins across the value chain, lowering our breakeven, and accelerating deleveraging and returns to shareholders. You've already seen us drive significant costs out of our business through corporate and operating optimizations. I'm extremely confident that we will achieve the goals we have set with the transaction and realize the potential of the combined company. But today, I'm here to talk about our third quarter results. I want to start by giving credit to our staff at Cenovus for keeping our operations running safely and reliably, as we're continuing to adapt to all the additional measures we've put in place in response to this pandemic. I continue to be impressed with the dedication of each and every one of our employees and how they continue to support each other through this time. Through all of this, our teams remain focused on delivering safe and reliable operating performance. We've had zero significant incidents across our operations to date in 2020. Our teams have successfully navigated the health and wellness challenges of the pandemic while increasing production and executing planned turnarounds at our two oil sands facilities as well as in our conventional operations. This quarter we saw some significant health and safety milestones across our operations. At Christina Lake, our drilling operations, as well as completions and well services teams achieved one year without a recordable incident, and our conventional operations marked a one-year milestone since recording a significant process safety event. This third quarter once again demonstrated our flexibility and ability to utilize our full suite of assets to maximize the price received for every barrel. It reinforced our commitment to disciplined spending, maintaining our low operating and capital cost structure, and deleveraging our balance sheet. As crude oil prices showed signs of a gradual recovery through the summer, we were able to increase our crude oil production and clear our inventory of stored barrels to capitalize on the significantly improved benchmark price for Western Canadian Select. We continue purchasing low-cost production credits from peers, so we could produce above our curtailment limit. That allowed us to produce high quarterly volumes at our Christina Lake facility. This increase was partially offset by plant turnaround and maintenance activities. Our oil sands operation this quarter averaged almost 386,000 barrels a day, up from 373,000 barrels a day in the previous quarter, and a 9% increase from the third quarter of 2019. We recorded adjusted funds flow of $414 million, which was a significant increase from the second quarter of 2020, when the unprecedented drop in oil prices resulted in adjusted funds flow of negative $462 million, and we generated free funds flow of $266 million in the third quarter and made meaningful progress on reducing our net debt. At the end of the third quarter, net debt declined to approximately $7.5 billion from $8.2 billion at the end of the second quarter of 2020. We had an operating loss of $452 million and a net loss of $194 million in the third quarter of 2020. The operating loss was largely due to an impairment charge of $450 million on the Borger refinery and negative operating margin from the refining and marketing segment. While we are pleased with our performance in this quarter, we expect commodity price volatility for the foreseeable future. That's why we look forward to the increased cash flow stability and enhanced free funds flow the transaction with Husky will provide. With that, I'm happy to take your questions.

[Operator Instructions] First question comes from Menno Hulshof with TD Securities.

I have one question and it's unrelated to the Husky transaction. Maybe you could just give us your thoughts on the outlook for your SAGD operations over the near-term, and more specifically, to the extent that WTI continues to trade in the mid-30s, and the heavy differential, call it in the $10 range? And what can we expect to operationally through year-end and maybe even early 2021? I'm assuming dynamic storage becomes a part of the conversation, but any thoughts on that front would be helpful?

Hey, Menno, it's Keith Chiasson. I'll start and maybe Norrie can talk about the operational side of things. But when we looked at the economics even in the mid-$30 WTI range and the tight differential that we see, we still see ourselves as variable cost netback positive. So, we would anticipate producing through this time at full rates. As we look forward, obviously, with curtailment ending in December, we are unconstrained and no longer have to acquire production credits to be able to do so. So, it's something that we watch really closely and monitor, and because of the low-cost nature of our production, we're able to produce and generate positive variable costs netback.

It's Norrie Ramsay from our Upstream business. If you remember, in the second quarter, we actually curtailed our production and our oil sands business by about 60,000 barrels a day, and in some days, it was actually down 80,000 barrels a day. We brought that all back on, as you can see in the third quarter, as we were 90% higher than our second quarter, overall average production, and we have full flexibility to increase that up to our higher levels. Again, curtailment is obviously limiting what we could do. Once December rolls around, we'll have a lot more flexibility. However, it's always going to be a value conversation and it's the value rather than the actual volume of production that we would be most interested in.

Next question comes from Greg Pardy with RBC Capital Markets.

A couple for you. Maybe Alex, just to pick up on the safety theme. Just wondering if there are specific actions or thoughts you have that will be taken to ensure that the combined entity here poses similar safety and reliability as noted. Is there anything you can add around that?

Yes, Greg, I'm happy to talk about that. And I think as you can tell, every quarter, I usually start out by talking about our safety performance. It is the number one focus of this company; commodity prices can come and go, but our commitment to human safety and process safety is our number one criteria at all times. As we get through this deal and the deal closes, everybody can expect that the exact same focus on human and process safety that you've seen from us over our entire history is going to continue. We're going to ensure that we put the resources towards that to ensure that we can deliver that exact same track record.

And the second one really comes back to how we should be thinking about hedging policy again. In the context of the new organization, very different integration prospects, but also tied to that question will be, if you were to continue hedging, would it remain connected with storage optimization? I'm just wondering if you can dig into that.

Sure, maybe Keith can start that and Jon may want to weigh in.

Yes, thanks for the question. When we look at hedging, there are really two different components; one is around kind of the optimization side of the business where we're trying to capture value from our storage and transportation assets. When we think about that, we are really seeing a value opportunity over a period of time or in different locations. To capture that opportunity, we lock up both sides of that transaction. From a financial side, we may lock it up, and then as that price settles, there could show pluses or minuses. But when we actually physically sell the barrels, we realize that on the netback side of things. We actually see an uptick. A key example of that was back in April, where our barrels were selling for about $4 a barrel. We could have produced and sold in Hardisty for that price too; we chose not to do that. We stored those barrels and transferred those barrels down to the Gulf Coast and stored them there. Then come June or July, we sold those barrels and realized an uplift of almost $25 to $30. In that transaction, though, we would have locked in the WTI components as well as the physical sale. Because of that, if WTI settled at $35, we may have shown a realized loss, even though our netbacks were materially higher than what they would have been in April. So when we think going forward, the combined entity has a lot less exposure to the WCS, WTI differential and Hardisty, so that becomes less of a concern for us. The combined entity still has no exposure to WTI. So maybe with that, Jon, do you want to pick up on corporate hedging?

So, Greg, I think there are three answers to your question that I would give you, and I think Keith really touched on the first. As part of this transaction, it’s about us acquiring a number of other assets to give us many more options to take our molecules to market to optimize the value that we get for them. So you should absolutely believe that we're going to continue with the type of optimization hedging that Keith has just described. For example, today we would have about 10 million barrels of storage. Going forward, we’re going to have closer to 16, as well as incremental pipes. So those opportunities are going to present themselves in increased ways for us and we intend to take full advantage of that. Secondly, I would say one of the major reasons for doing this is to reduce the volatility in our cash flows. So sort of at a corporate level, that becomes an inherent hedge, or this transaction will become an inherent hedge to manifest the cash flow streams. But finally, I would come back to something that Alex said, time and again, the under-levered balance sheet is the best way to hedge at the corporate level to rise through these commodity price fluctuations. We've been really clear since we started talking about this transaction that balance sheet deleveraging is our number one commitment, and you can expect us going forward to continue to prioritize the balance sheet on a free cash flow basis until we’re comfortable with our debt levels.

Next question comes from Prashant Rao with Citigroup.

I just wanted to talk about the hedges just a little bit more. I appreciate all the color they do. On the current program, though, and I think the communication our staff at Cenovus did a good job of communicating this to all of us in the MD&A disclosures highlighting that from 2Q. But the current program, how should we be thinking about how much volatility that might cause in FFO per share, next quarter, or I guess, this quarter and next quarter? And I guess related to that question, if we adjust for those impacts of this quarter, it seems the core sort of FFO per share was really in the mid-$0.40 per share, which I think speaks to the underlying quality, the asset base performance environment. So, just curious about that sort of thinking about how we should think about the remainder of this hedging program, the answers into going forward over the next sort of called four to six months, and also sort of what's the right takeaway there about the core reliability and performance of the assets?

Prashant, it's Jon McKenzie. I think you're thinking about the hedge program the wrong way. The hedge program that we put in place locks in additional profitability. My suspicion is you're confusing accounting treatment with straight up economics. You’ll notice in this quarter, we sold many more barrels than we produced. We took the opportunity in Q2 to start storing barrels rather than selling them into a different market. What we do is lock in that contango along the curve, so that we're locking in sort of a $4 or $5 per barrel margin by selling in Q3 versus selling in Q2. If WTI rises by more than that $4 or $5 increment that the curve was showing us back in Q2, we will show a hedging loss. The reality is, we're not speculating in the market. What we’re doing is locking in incremental margin by selling in one period versus another. So don't get confused by the hedging gains and losses; they’re really a function of how WTI is moving in the marketplace, whether it goes up through one period or down through one period. Our hedging program is designed not to speculate, but to lock in incremental margin.

I think another question I had was returning to the transaction. I appreciate that you probably can't give too much color around this right now. But when you look through asset monetization opportunities are sort of, I guess, optimizing the portfolio and post-transaction, post-merger. Could you maybe help us to think about how you evaluate that to sort of what's the construct by which you go through and balance profitability versus synergies with the overall portfolio? Specifically, I was thinking outside of the black oil production, the portfolio that you have on a consolidated basis. Any color there would be helpful?

Sure, anytime you go two companies with this kind of scale and scope together, you're going to go through a process and we have been doing and are continuing to go through a process of determining what is core to this business and what is non-core. There are a lot of criteria that kind of go into those decisions, but really at the base of them, it is about the value of those assets can generate in their strategic importance to the company. So, we will, I think people can take it as a given that we are going to proceed to look at monetizing non-core assets that are falling out of this combination. From my perspective, I think we already have a pretty good understanding of the kind of assets that we're going to take a really hard look at in that regard. We're also going to be cognizant of whether they are worth more to other people, but I think the other issue is going to be the time and can we actually transact at values that are value-creating for our shareholders. So, expect more from us on this. I think we're going to act fairly quickly, and it's just going to take us a little bit of time to reach a point where we can talk a little more freely about it.

Next question comes from Phil Gresh with JP Morgan.

I was just thinking about the rail contract that you have that you signed up a while ago. I think it goes maybe till the end of 2022. And I apologize if you addressed this on the last call. But what happens with that once we get to the end of this period, and now that you have the excess takeaway that Husky would provide?

Hey, Phil, it's Keith Chiasson. Yes, you're right, that some of those contracts fall off kind of at the back end of 2022. So we'll evaluate that at that time. What I would tell you is we quickly ramped down the program in the first part of this year when commodity prices collapsed. But we didn't sit on our hands through that time; we actually continued to negotiate around those contracts and have been able to further reduce our variable costs on those contracts. Because of some small investments that we made in the Bruderheim facility last year, we're actually able to store a bunch of unit trains at the facility, which allows us to ramp up the program relatively quickly. In the past, we've talked about this overall program not lending itself to quick ramp-up and ramp-down in the span of less than six months. But we've been able to take a portion of the program and really have agility and flexibility to ramp it up and ramp it down over a period of a couple of months now. So we will look at market opportunities to be able to do that at those reduced costs for transport to the Gulf Coast over the next couple of years, and then, you know, coming at the end of the contracts, we’ll look at egress and how it's all shaken out, whether or not we would want to extend those or not.

I guess my follow-up to that would just be with your comments about having lowered the cost. Does this mean that the new transport costs of each team this quarter, which are lower than prior quarters? Is a function of that cost reduction given rail not being utilized? And then is this the right way to think about the go forward? And if we go into it for coming out of curtailment, do you think you'd actually maybe start using that rail as we move into 2021?

Yes. So Phil, you shouldn't be surprised to see us use the rail kind of in the fourth quarter here. We are looking at starting up a portion of the program in November, which enables us to accumulate additional production credits versus having to acquire them in the market through the supplemental production allowance. Then in December, it comes down to a cost-benefit analysis and with the cost reductions we've been able to achieve on the variable costs, we can actually make this program economic to run barrels down to the Gulf Coast and realize higher netbacks. So you shouldn't be surprised to see us move some volume, obviously not the full program for the fourth quarter, but some volumes for the fourth quarter, which will help improve our overall netbacks.

Phil, it's Alex. Just maybe one thing I’d add to that. This improvement in pricing we've been able to achieve is really significant. It's a tribute to Keith's team, but also our freight partners; they have been really good to work with and making this a much more compelling opportunity going forward.

And Alex from a macro perspective, with the removal of curtailment, do you think the broader industry is going to need rail? I know that the commentary suggested not until mid-2021 as the decision point for why to remove the contaminants, but what's your view?

I mean, I suspect. I think I've been pretty consistent about this, but one of the very clear features of our industry is, I think all of us have been very successful in driving costs out of our operation. I suspect with curtailment going away, those barrels on the sidelines, be they sort of 200,000 to 400,000 barrels a day, I do expect them to come back and I would not be surprised at all to see rail. I don't think we're going to see it where it was a year and a bit ago, but as Keith said, it looks like it's making real economic sense for us. I wouldn't be at all surprised to see rail volumes moving up here over the next few months.

Next question comes from Manav Gupta with Credit Suisse.

Quarter-over-quarter, there was a lot of improvement in the netback. Obviously, the benchmarks are more supportive, but just trying to understand what was condensate pricing a big headwind for you in Q2 and as that kind of lag went away. You started closing the gap to the benchmark and that led to improvement in netbacks. If you could comment a little on the condensate pricing lag and how exactly was that from Q2 versus Q3?

Manav, it's Keith. I think this is kind of a build on what Jon talked about earlier and kind of how we are trying to improve our netbacks by moving barrels out of one period into another. So in the second quarter, we were able to store a lot of barrels; obviously, if we had sold them in that quarter, would have been at very low pricing. We stored those and moved them into Q3, and realized much higher realizations for those. If you look at our sales relative to production, you can see an increase in sales in the third quarter relative to production. That's really putting those barrels in the market in a higher price environment, which flows back into an improved netback for us.

Perfect. A quick follow-up here is, you've seen a very positive trend in transport and lending costs going down at Foster. Obviously, rail is a part of it, but if you look at from Q1 where it was 14.37 now all the way down to 8.60. Is there anything else that you're doing at Foster Creek to push the cost down in transport and lending besides rail, which is helping you out?

Manav, I think you'll see a lot of variability quarter to quarter. It all depends on the barrels that we move by rail, as you indicated, but also barrels that we move on pipeline and which production we choose to move down the pipeline. Some months and quarters, it may be Foster; others it may be Christina Lake. It all depends on how we can get the maximum value for our barrel, and that will drive some of that variability and transport costs. You're right that with rail off through the third quarter, our transportation costs are down because of that, but we will use those assets to capture incremental value for the company. So, you will see a bit of variability quarter to quarter, asset to asset.

And last question is the Enbridge Line 3 replacement, any color, anything you're hearing out there? Do you think this could be a 2021 event? Thank you.

Everything that we're hearing, Manav, is that they are marching towards 2021 startup. Obviously, some critical decisions are coming here in the November timeframe around some permits, and that will then drive the construction of that project. We'll be watching through the fourth quarter, intently. If they get their permits and start construction, then we do think that 2021 startup is realistic.

Next question comes from Chris Cox with Raymond James.

Thanks, guys, and thanks for taking my question. Maybe just the first one on the quarter, just any comments on why you didn't also record any impairments, that would revert, and just anything that may be differentiated bad asset tax versus what you conducted at quarter?

Yes, thanks, Chris. It's Jon McKenzie. One of the things we do with all our assets every quarter is assess for indicators of impairment. Obviously, with refining cracks dropping as precipitously as they have been and then not recovering as quickly as they have, we took that as an indicator of impairment in our Downstream. We evaluate both of those assets. The one thing I would say is that Wood River is a more complex refinery with much greater scale efficiency than we have at Borger. The reality is when we look at that one versus the net book value and we kind of ran it out on the discounted cash flow basis, we got to the answer that we did get to, but relative to the carrying value of Wood River, we did not have any impairment.

Okay, thanks. And then maybe circling back to the transaction with Husky here, just wanted to dig a bit deeper into some of the talk about the physical integration between FCCL and the Lloyd complex. I'm curious how much of your diluent value chain you think you could integrate there? I believe your current set of slides also ties in monitoring contracts on Wolf Lake and Polaris. How do you think those contracts on those pipelines come into play with your other contracts for the Downstream?

We're right on the front end of this. When we did our synergies and put out our targets, we were really clear that we didn't want to include any of that in our synergies. The $1.2 billion that we put out as capital and operating synergies are really those synergies that we have a really high confidence that we're going to be able to get in a very short period of time. The broader physical integration between FCCL and Lloyd through time is an exciting opportunity for us. Lloyd is going to be a very strategic asset and how we integrate that and work through the molecular integration, not just on FCCL molecules going into Lloyd, but the condensate coming back is something that we are working through today, but it’s too early in our minds to be talking about future values and the magnitude of integration that’s possible there. It’s really clear to us that Lloyd is a legacy asset and is going to give us a lot of optionality.

Many just off to the side; are there different ways to achieve that physical integration? Will it require negotiations with other parties other than just you and Husky?

Yes, it will.

Next question comes from Matt Murphy with Tudor, Pickering, Holt.

I appreciate with the acquisition release, laying out your carbon emissions over the long-term, and that it'll take some time to work through firming up plans there. Given that perception of oil sands as being more emissions insensitive than other oils around the world, and certainly appreciate that all oil sands isn't quite the same. Given those ambitions, just wondering if you guys could provide a bit of a teaser on some of the things you are thinking about, in meeting those ambitions, whether we're talking solvents, carbon sinks, or otherwise? Thanks.

When we came out with our targets and our ESG targets in the spring, I think we gave a little bit of color around that. What I would tell you is, we didn't come up with those targets until we had done a comprehensive economic and engineering analysis of sort of what options. Not just what were possible, but what options were actually achievable within our business plan. It would be pointless to come out with ESG targets that weren't grounded in the business plan. So, I would kind of say, it's a little bit all of the above: we’ve obviously been a leader in solvent technology. I expect that solvent technology will be a part of it. Carbon sinks is something we are looking at; carbon capture and sequestration. There could be an element of acquiring carbon offsets. However, one thing I would say that I think a lot of people don't appreciate is that there are a lot of projects that require capital, whether it's cogeneration, whether it is solvent technology, carbon capture, there's actually– we believe there are a great deal of benefits that we can reduce our GHG intensity by changing how we operate the assets. With Husky coming on, there's not only how we operate assets, but what assets on a go-forward basis get capital and what assets don't get capital. All of those have the ability to meaningfully improve the GHG intensity.

Yes, appreciate the thoughts there. If I may follow up on a completely unrelated note just on the approach to integration with the Husky transaction, if I go back to the 2019 Investor Day, for example, which I appreciate is rolled away at this point. But I think the strategy at the time was to take advantage of accessing a healthy amount of refining capacity in the U.S. market, rather than owning it yourselves from a sort of integration. Can you talk about what's changed there in the thinking? Was it just an opportunity with Husky that was really hard to pass up? Or did something change in how you're thinking about the value of integration given where rates are and how you're thinking about pipeline progression from Canada?

Yes, I mean, it's a whole lot of things. But I'd maybe go back to where my comments have been on integration from the start. I think I've always said, like, I love the integrated business model; I looked at our competitors and said it would be fantastic to have that kind of business model and take the volatility out of our cash flow and earnings related to our exposure to Alberta heavy oil pricing. However, when we looked at that indepthly a couple of years ago, at the time, crack spreads were $18 to $20, and every refining or processing upgrading business or asset we looked at was extraordinarily highly valued. I'm just not interested in picking off assets at the peak of the market. That’s why we came to a strategy at that time of focusing on opportunities to get our barrels to market via logistics rather than on processing. Since the pandemic, values for these assets have come down, but if you look at the valuation metrics of the Husky merger, you would see that the downstream 400,000 barrels a day of molecularly integrated upgrading and refining for our barrels. The valuation was absolutely compelling.

I would just add to that, Matt. Alex used a really important phrase there called molecular integration. That’s what this opportunity really presents for Cenovus moving forward, the ability to have processing units that are tied to our molecules that consume the molecules that we produce. This gives a whole different level of optionality as well as a reduction of volatility going forward. This isn't just about integration; it's about molecular integration going forward and tightening up our value chains.

Next question comes from Chris Tillett with Barclays.

Just a quick one for me. On the conventional side, it looks like you're resuming some activity there in the fourth quarter. My read is that it's tied to stronger seasonal pricing, but just wanted to confirm that or see if this was maybe a sign of interest to pursue some incremental opportunities on the conventional side in 2021?

Hey, Chris, it's Alex. No, I mean, you look at we’ve obviously been very disciplined over the last few years with the Deep Basin. Given gas prices where we found them over the last two or three years, the right decision was not to put material capital to that asset. This is an opportunity with gas prices, as you've mentioned. We can lock up gas prices for a few years at very attractive levels. It's a bit of a short cycle, these are very, very high IRR, kind of drill-to-fill opportunities, and it allows us to take that asset from a decline to basically keeping it at least flat to modestly growing.

And then maybe just as a follow-up, anything you can offer in terms of the role that those assets might play in the pro forma company?

I had responded to that question earlier about asset sales. I think we took a really hard look at a couple of years ago and whether there was an opportunity to monetize a portion of that conventional business for Cenovus. If you put an overseas conventional business together with Husky in a higher price environment, we're going to take a hard look at that. My observation today is even though the prices have come up, it's still a tough market for value, but I expect that will likely improve over the next little while, especially if prices stay where they are. We'll take a hard look at that.

Next question comes from Neil Mehta with Goldman Sachs.

I guess the first question here is maybe it's for you, given you know the Husky assets really well. But as you looked at the last couple of years of Husky, one of the challenges has been operational execution and excellence. That's shown up in different ways in both upstream and downstream in terms of performance. As you look at those assets, do you think there are things Cenovus can bring to the table to kind of get them up to speed? How did you, as you went through the process of valuing these assets, take that into consideration?

It's Jon, not Jeff. This was an absolute number one concern for us. Alex has mentioned right off the top of this call that safety always has been and always will be our number one concern going forward. When we look at this asset base, I would tell you that we had unfettered access to do our due diligence. We have been at this for nearly six months, and I would say the diligence that was done on all aspects of these assets is really unprecedented. When we look at the upstream assets, they are right in our wheelhouse, and we are very comfortable with the reservoirs, the conditions of the assets, and the commercial arrangements over the top. We think we can add value there, and that value can be realized in a fairly short period of time. As it relates to the downstream, we took a lot of time to look at improvements and changes that Husky has been making on all fronts, from new personnel coming into their operation to their safety process, safety systems, asset condition reports, as well as reliability and safety practices. We have two directors on our board who are very deep regarding refining assets and operations. This is something that has been top of mind, and we’re comfortable we’re on the right path going forward.

Great. The follow-up here is that I had asked about this over the weekend, but I don’t know if there’s been a subsequent update. Any conversations with either the ratings agencies or your credit investors about how they view this transaction in a pro forma way and whether this gets us the breadcrumbs to get back to investment grade?

I can't speak for the rating agencies that have all put out their comments now, and you can read into those what you will. But we expect that we are sowing seeds for a return to investment grade in short order. That would be very important to us.

Next question comes from Mike Dunn with Stifel FirstEnergy.

Thanks, good morning, everyone. Not to beat it to death, but I did have another question on the hedging strategy around timing of your sales versus your production. Maybe naively, I had thought that this was something that generally other players would do based on their outlooks for seasonal turnarounds for them and others. Just wondering, Jon or Alex, if finding sales versus production was something strategically done in the past without hedging, and the second part to that is how did you weigh the cost benefits of delaying the sales of your own equity barrels versus, you're locking in that contango by buying third-party barrels and delivering them later?

Mike, it’s Jon. This is something we've always done. What’s really important to us is maximizing the free cash flow to the organization. When we look at whether we can sell into the future, we have pipelines and about 10 million barrels of storage available to increase future cash flow. Now, we attach a cost to that, which approximates a few hundred basis points beyond our cost of capital. But we do that on a diligent and rigorous basis to ensure that we're maximizing free cash flow and returns to shareholders.

Okay, Jon, that’s it for me.

The other thing I would say is this is not something we’re speculating on. We take what the market gives us in terms of the shape of the futures curves. All we're doing is using our assets and playing along the length of that curve to maximize future cash flows for the company.

First question. Maybe talk about your intentions with the pro forma debt structure and if you had planned out treatment for the Cenovus and Husky transaction for closing and then perhaps if so, how you go about doing that?

Harry, it's Jon again. We're evaluating all the options around your question on pari passu, and that's something we'll have to get back to you on. What I would say, though, is we believe that investment grade is very important to this new company. It's one of the synergies that we believe haven’t taken any value for, but we think it's really important going forward. Expect us to do everything necessary to get back into that space. We'll come back to you with a comprehensive financial framework that will discuss capital structure and how we see that playing into things, but we want to do that comprehensively rather than give one piece of the framework incrementally over time.

And then, apologies if I missed this on the call last weekend or earlier today, but have you guys spoken about upfront costs to realize your synergy targets including our major driver of the deal? I'm just wondering how much cash you think goes out the door initially to capture those.

Hey, Harry, it's Alex. I think that if you want to think about costs of putting the two companies together, think about a one-time cost of just over about $500 million. That compares to the $1.2 billion a year of annual run-rate synergies that we expect to largely get in 2021 and the entirety in 2022.

I noticed there was a permit or something filed with the AVR about a DRU that's going to be built near your rail terminal. As you guys were looking at DRUs, what's your outlook on that? I mean, is there a plan to perhaps have one there at either of your rail terminals?

Hey, Robert, it's Keith Chiasson. We filed that regulatory application just to give us the flexibility around that project. With the transaction that's underway, we are taking another look at the DRU and the location. That was just a step in the process to make sure that we had flexibility.

Yes, Robert, it's Alex. Just to be really clear on that. We said when we were looking at the DRU that we were going to do the engineering and permitting to give us the ability to go forward on a DRU, and no one should think about that filing as anything more than just carrying through on that direction.

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

I think that's the end of our questions. So thanks, everybody for taking the time and enjoy the rest of your day.

This concludes today's conference call. You may now disconnect.