Canadian Natural Resources Limited (CNQ) Q2 2020 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Canadian Natural Resources earnings results conference call webcast. [Operator Instructions]. Please note that this call is being recorded today, August 6, 2020, at 9:00 a.m. Mountain Time. I would now like to turn the meeting over to your host for today's call, Corey Bieber, Executive Advisor. Please go ahead, Mr. Bieber.

Thank you, operator, and good morning, everyone, and thank you for joining our second quarter 2020 conference call. With me this morning are Tim McKay, our President; and Mark Stainthorpe, our Chief Financial Officer. Before we begin, I would refer you to the special note regarding non-GAAP measures contained in our press release. These measures used to evaluate the company's performance should not be considered to be more meaningful than those determined in accordance with IFRS. I would also like to refer you to the comments regarding forward-looking statements contained in our press release and also note that all amounts are in Canadian dollars and production and reserves are expressed as before royalties, unless otherwise noted. With that, I will now pass the call over to Tim McKay.

Thank you, Corey. Good morning, everyone. Canadian Natural delivered top-tier operational results in the second quarter, as we have robust, long-life, low-decline assets, operational excellence, capital discipline and the ability to enhance our margins, which delivers sustainable cash flow. The strengths of Canadian Natural's business model were also implied to environmental, social and governance, to deliver industry-leading performance across the board, a significant factor in our long-term sustainability. And when it comes to environmental performance, Canada leads the world. Canadian Natural, and indeed, the Canadian oil and gas sector has delivered game-changing environmental performance. For instance, Canadian Natural has already reduced our overall corporate commission intensity by 30% since 2012. And at Horizon, our intensity is down 38%. And with our leading -- we are a leading capture and sequester of CO2 in the oil and gas sector worldwide. In just these areas, Canadian Natural has taken the equivalent of over 2 million cars off the road, equivalent to 5% of the entire vehicles in Canada, and that is just what Canadian Natural has done. The entire industry has achieved similar, equally impressive results. In our oil sands operation, we can develop technologies and by using Canadian ingenuity, we can even do better, moving closer to Canadian Natural's aspirational goal of reaching net-zero emissions. Canadian Natural has multiple pathways to achieve net zero. With the actions identified in the near, mid and long-term and the strength of the Canadian Oil Sands Mining asset with its long life, low decline and its manufacturing like operations, it can have one of the clearest, if not the clearest route, to net zero of any global oil asset. Canadian Natural had a very strong operational results as we achieved quarterly production of 1.165 million BOEs per day, with natural gas production of 1.46 Bcf per day and liquids production of 922,000 barrels per day. During the quarter, we effectively and efficiently reacted to temporary curtail production, complete maintenance due to low prices while prioritizing high-margin production. Then, as prices improved, we quickly reinstated production cost effectively. Starting with natural gas. Overall, Q2 production was 1.462 Bcf per day, an increase from our Q1 production of 1.44, with North American Q2 natural gas at 1.431 Bcf per day, up from Q1 of 1.407 Bcf per day as we started to execute our plan to add 60 million cubic feet per day of natural gas volumes at less than $3,000 per BOE/d. We continue to focus on operational excellence and our Q2 North American natural gas operating cost was very strong at $1.11 per Mcf versus Q1 of $1.24 per Mcf. In the second quarter, Canadian natural realized corporate natural gas price of $2.03 per Mcf as a result of our diversified natural gas sales portfolio, of which 49% is used within operations, 32% exported and 19% is exposed to AECO pricing. Our Q2 North American light oil and NGL production was 82,422 barrels a day, down approximately 7%, primarily due to the company's decision to temporarily curtail production and reduce well servicing activities in the second quarter. Q2 operating costs decreased to $14.41 per barrel versus Q1 operating costs of $15.99 per barrel. Overall, our international assets had a strong Q2 with oil production approximately 44,000 barrels a day, which is comparable to Q1. Offshore Africa production was 17,444 barrels, up when compared to Q1 of approximately 16,000, as expected, due to the planned maintenance program completed in Q1, offset by natural field declines. CDI operating costs in Q2 were strong at $7.67 per barrel versus Q1 of $8.83 per barrel. In the North Sea, production averaged 26,627 barrels a day in Q2, down from Q1 of 27,755, primarily due to natural field declines with strong operating costs of $28.47 per barrel, a reduction compared to our Q1 operating costs of $29.73 per barrel. In South Africa, the operator is moving the rig and is targeted at the exploration well in Q3 of 2020. And contingent on results, an additional exploration well could be drilled on the block. Q2 heavy oil production was reduced to approximately 62,500 barrels per day in the quarter versus 88,100 in Q1 as we temporarily curtailed production and reduced well servicing activities related to the low pricing in the quarter. Q2 operating costs decreased to $17.97 per barrel from the Q1 operating cost of $18.68 per barrel, reflecting the company's focus on cost control. A key component of our long-life, low-decline assets is our world-class Pelican pool, where leading edge polymer flood continues to deliver significant value. Second quarter production was 55,731 barrels a day, down from the first quarter of 57,986, primarily as a result of reduced well servicing activities in the quarter. Operating costs continue to be very strong at $6.31 per barrel versus Q1 operating costs of $6.18 per barrel. At Pelican, our team continues to drive operational excellence. And with our low decline and very low operating costs, Pelican continues to have an excellent netback. Our second quarter Thermal production was 212,807 barrels per day, down from the Q1 of approximately 228,000. Operating costs in Q2 were $10.13 per barrel versus Q1 operating costs of $11.02. During the quarter, planned maintenance was conducted at Jackfish as well in our Thermal production areas, we temporarily curtailed production in the quarter as a result of the low prices in May. In the second quarter, in the Kirby area, production was approximately 56,000 barrels a day, which includes both Kirby North and Kirby South. The Kirby North ramp-up is ahead of schedule and for the month of July, averaging approximately 43,200 barrels a day, approximately 8% higher than the nameplate capacity of 40,000 barrels a day, a great result by our team. At our Oil Sands Mining operations, we had an outstanding second quarter with record production of 464,318 barrels a day, inclusive of the Horizon maintenance in May, with record low quarterly operating costs of $17.74 per barrel of SCO. Our teams continue to capture synergies between the 2 sites leveraging technical expertise, services, operating efficiencies, driving our costs down with consistency, with year-over-year hard dollar costs, excluding fuel, down approximately $96 million in the first 6 months on an unadjusted basis as compared to 2019. Our teams are very focused on driving operational excellence. As well, as part of the company's overall strategy to maximize value and enhance margins, during June, we were able to test the Albian mine capability in which we had an average test rate of approximately 339,000 barrels a day in that period. With the Scotford upgrader targeting to increase capacity to approximately 320,000 barrels a day in Q3 of this year, we are confident we can fill the extra capacity. This additional capacity at AOSP will allow us increased flexibility, margin improvements and will be managed through the company's curtailment optimization strategy. Work on the commercial engineering for IPEP continues, while the field pilot testing is temporarily delayed as we reduced people on our sites due to COVID-19, and we only will continue to pilot when it's safe to do so. I will now turn it over to Mark for the financial review.

Thanks, Tim. The second quarter demonstrated the advantages of having a low-cost structure and a unique portfolio of assets with low decline when navigating the low commodity price cycle. Adjusted funds flow was $415 million in the quarter, effectively covering capital expenditures, which were 50% below Q1 '20 levels at $421 million in the second quarter. In addition, we stored a higher portion of our Oil Sands Mining SCO and international light crude oil in the low commodity price quarter. The estimated increase in adjusted funds flow would have been approximately $60 million in the quarter had those barrels been sold in June. Liquidity remains strong at the end of Q2, with total availability on our bank lines and cash of $4.1 billion. In the quarter, we increased our $750 million term facility to $1 billion and extended the maturity to 2022. And we retired as scheduled $163 million of our $3.25 billion facility and a $900 million Canadian medium-term note. Because of our operational excellence and solid financial position, we were able to be patient and prudent and obtained attractive pricing when raising a total of $1.1 billion of notes in the quarter, consisting of $600 million of 5-year, 2.05 coupon and $500 million of 10-year 2.95 coupon bonds. Net debt at the end of the quarter was $22.8 billion with debt to book capital of just over 41%, well below our bank covenant and within the company target range of 25% to 45%. With our low maintenance capital program of $2.7 billion and the ability to keep production flat, we target significant free cash flow in the second half of the year at current strip pricing, which result -- which would result in ending 2020 debt being flat to down from ending 2019 levels. Our long-life, low-decline assets and effective and efficient operations gives us the ability to sustain returns to shareholders over the long term. In March, we increased the dividend 13%, which is the 20th consecutive year of dividend increases. And due to our ability to generate sustainable cash flow, we maintain the dividend through the low commodity price cycle. Our culture of continuous improvement, our ability to be effective and efficient and the relentless focus at Canadian Natural in controlling our costs led to the solid financial results in a very challenging and volatile commodity price environment. With that, I'll turn it back to you, Tim.

Thank you, Mark. Canadian Natural's ability to deliver sustainable cash flow is driven by our effective and efficient operations, our high-quality, long-life, low-decline assets that have low maintenance capital and significant reserves that are resilient in a volatile pricing environment. As WTI prices improve, there is even more upside for our shareholders. At strip pricing, we are targeting significant free cash in the second half of 2020. Canadian Natural is focused on continuous improvement, and we continue to find opportunities to drive our costs down and are working with our service providers, and for 2020, are targeting significant savings of approximately $745 million. As a result of our effective and efficient operations, the quality of our assets, we have a low free cash breakeven, including all capital expenditures plus current dividend of approximately $30 to $31 per barrel. Canadian Natural continues to take proactive and effective steps to ensure the health and safety of the people working for us, and we will continue to enhance our COVID-19 program across the company as well as our safety performance. As I talked earlier, Canadian Natural is on track to achieve our environmental targets, lowering our GHG intensity. And as we achieve that target, we will set our next target and will continue to lower intensity as we work towards our aspirational goal of net zero in the Oil Sands. In summary, we will continue to focus on safe, reliable operations, reducing our GHG intensity and enhancing our top-tier operations. Canadian Natural is delivering top-tier cash flow generation. And with our $2.7 billion capital forecast, we are keeping production stable. We are unique, sustainable, robust and clearly demonstrate ability to deliver returns to shareholders by balancing our 4 pillars. That concludes our Q2 call. I will now open the line for questions.

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

Yes. A couple of questions, but maybe the first one is just on Horizon AOSP. You mentioned 320,000 of the upgrader in the third quarter. Is that capacity? So should we be -- sorry, how should we be thinking maybe of the ongoing capacity on the upgrader? And then just the mirror image of that is, are we now talking maybe a $17, $18 kind of OpEx run rate at Horizon AOSP?

Yes. So the first question with the ASOP. So the expansion is really for the front end. Obviously, we're not the operator of the upgrader. But when they're completing their -- complete their turnaround, the capacity is going to be at the 320,000 range. So what we'll do is ramp it up and see how well it runs in terms of that 320,000. So the good part is we have excess capacity to be able to fill it and keep it full. On Horizon, I would say sub '19 is not a bad number. Our teams are really doing an excellent job in terms of both finding enhancements to the operation so that we can increase reliability, get a little extra capacity from time to time as well as defining operating cost improvements.

Okay. And just related to that, a lot of turnaround activity in the Oil Sands this year. Does that really negate a big turnaround next year?

No. Actually, a part of it, we have the East Tank expansion that we are doing at Horizon. It's still on track. So when we do that work, we will be taking an outage in early spring to complete that work. So we're doing what I would call a relatively small one this year with a little bit bigger one into next year when the expansion piece is ready.

Okay. And last one for me, just shifting gears is a pretty large working capital draw over about $1 billion. I'm just wondering, Mark, can you give us an idea maybe of the components of that? And then reversal and/or how much does that really figure into the debt calc as you're thinking about it?

Yes, sure, Greg. And as you know, the working capital generally is a timing thing. There's 2 kind of bigger components. One, of course, is the receivables. When you come out of March and into June, you had certainly different forecast pricing. So when you get paid the next month, you have that draw or that increase in receivables. The other notable one, though, is the draw on payables. So that, I think, reflects a little bit about how the costs are coming down and the capital has come down. So you may not see that reversal there as we continue to control costs. I guess the last thing to consider going into Q3, though, is turnaround, so we are doing turnaround, so there will be more capital and things like that, that go along with that.

Your next question comes from Neil Mehta from Goldman Sachs.

And strong operational quarter here. I just wanted you guys to expand a little bit more on the comments in the release where you said your net debt will be flat at 2019 year-end levels by the end of the year at the forward strip. Can you talk a little bit about sort of the assumptions that are going into that pricing thoughts on capital? And I think you talked a little bit about the working capital side because it would imply a very robust free cash flow ramp-up in the back half of the year.

Yes. I mean, that's kind of a forecast at strip pricing, so taking strip WTI. And it's hard to do strip differentials, so we're taking a sort of normalized differential over time just because it's so illiquid in the back half to really get a strip differential. And same with strip FX. So you do actually have an FX draw on that compared to 2019 ending levels. But I think it really, Neil, just speaks to the sustainability, the free cash flow capability of the assets because of that low decline and low capital requirements. And as Tim mentioned, we're on track for the $2.7 billion of capital in 2020. So that makes its way through in the second half. But really, it's about prices here stabilizing a little bit higher at WTI in sort of $41 range. That gives us that free cash flow in the second half.

Very clear. The follow-up is just on 2021 capital spending. I think on the last call, you indicated in early look, if prices stay depressed, it would be plus/minus $3 billion. Obviously, the curve has firmed up nicely here for '21. So any flavor for how we should think about spend? And what do you define as sustaining CapEx now that we've gone through a couple more months of this down cycle?

Yes, Neil, it's Tim McKay here. Really, what we're seeing this last year is that there's a huge volatility, a huge change, shall we say, with the demand. And so I think right now, it's really too early to really speculate in the fall here. We'll go through our process of going through all the different projects we have as well as decide kind of what our CapEx is. Do I see it changing significantly based on the strip pricing today? Maybe not, but it's really too early. I think we'll go through our process. We'll make that decision later on with the Board.

Tim, as a clarification, when you say, see it changing significantly, you mean changing significantly from 2020 levels?

Yes, exactly. Like if we're in the $3 billion range, that would probably be about a number in there, but it's just really too early to say. It's -- we'll just go through our process and look at it here. Because it's -- as we've seen this last year, obviously, we started off with a $4 billion budget and that reduced to $2.7 billion very quickly, and we're able to do that, keeping our production flat. And so when we look into next year, we'll go through our normal process and evaluate what opportunities we have ahead of us and what makes best for the company at that time.

Will you be doing an open house in November? Again, I guess that will be -- have to be virtual to the extent you are...

Yes. We really haven't talked about that at this time, but I would suspect we would.

Your next question comes from Asit Sen from Bank of America.

It looks like you have committed 10,000 barrels a day of the targeted 50,000 barrels a day Keystone optimization expansion that becomes available in 2021. Just wondering if you could talk about similar opportunities that might become available. It looks like Keystone has received U.S. permits to increase exports. Just wondering if you could talk about your thoughts on that.

Well, all I can say is that approximately the 10,000 barrels a day, obviously, we're looking forward to getting access to that as soon as possible. Our understanding is that they are trying to do that as quickly and prudently as possible. The incremental barrels, I suspect, they'll go to some kind of open season but really, that would be a question for TC to answer.

Got it. And Tim, just a follow-up on that. Pipelines have been in the news lately, running into all kinds of regulatory issues. How are you thinking about broadly your risk -- takeaway in risk mitigation strategy? Any thoughts on that given the new environment?

Well, Canadian Natural has been very supportive to all different pipeline projects. So whether it's a Keystone base expansion, a Keystone expansion, we've committed 200,000 barrels a day there. TMX, we've got 94,000 barrels a day there. So we have a numerous -- or a number of opportunities there for diversifying, our pipeline piece. My understanding with Trans Mountain is that the construction is going very well, and they're on track for that December 2022. So today, I feel pretty positive. TMX will be a good stepping stone. It looks like very strong to be completed and completed essentially on time. So that part, I feel very comfortable about. On the keystone, it's obviously a very interesting in that it is changing almost daily. So I really couldn't comment really on the Keystone one.

Great. And Mark, just a follow-up on your earlier answer. Net debt year-end 2020 being flat year-over-year is unique among global energy peers. You've always talked about the 4 pillars. Is this now a new strategic goal in this environment, not let net debt rise in any scenario?

Well, I think when we look at the 4 pillars, those are still sort of fundamental to how we allocate capital and cash flow. What you have seen in 2020, of course, is the suspension of the buyback program for now as the free cash flow is going to the balance sheet. And that has been sort of the case. Also, of course, when you look at the return to shareholder pillar, we've been able to maintain our dividend through the price cycle. We increased it here in March, 13%. And again, I think that's a reflection of the low-cost structure of the asset base, the low-decline nature that is able to sustain cash flow and free cash flow through the commodity price cycles.

Your next question comes from Joe Gemino from Morningstar.

How are you thinking about DAPL and the east leg of Line 5 as it may relate to sort of the EPS capacity for your production?

Yes. The pipelines are always interesting in the news. Obviously, DAPL and the Line 5 are changing very rapidly day-to-day, month-to-month. Obviously, they are in service. They are very reliable. So we feel comfortable. We don't believe there will be -- well, the DAPL has very little impact on us. When you look at the declines that are happening in the basin, whether it's in North Dakota or in Canada, I don't think the DAPL will be really of any significance by the time if something was to go there. But Line 5, again, we feel very comfortable with what Enbridge is doing there. And everything we've heard from Enbridge is always very positive.

Your next question comes from Phil Gresh from JPMorgan.

A couple of very quick follow-up questions for you. First is just on the Oil Sands Mining segment. I know it's already asked about AOSP, but just overall, the Oil Sands Mining business had 464,000 barrels a day of production this quarter. So taking into account that performance and the capacity increase at AOSP, just in general, as you look ahead to say 2021 on an annualized basis, how do you think about the total capacity or production potential across both assets with that kind of performance?

Yes. I think it is increasing incrementally. But it -- before I look at -- looking ahead into next year, we got a bigger outage on Horizon. So that piece could be relatively flat year-over-year in terms of volume. AOSP, with the work they're doing this year, they've delayed the further piece to the plant until 2022. So I suspect ASOP will actually be up year-over-year. But these are great assets. Our teams are very focused on finding those opportunities to do small incremental gains across there. So our capability is increasing and reliability, I think, is quite high and very top tier. So there is a little bit of opportunity there, but our teams are really doing a great job in terms of finding those opportunities.

Yes. I guess, if I were to think of 2Q as a new run rate, when there's not maintenance, is that a reasonable way to look at things?

Yes. When you really look at the Q2, what it really showed is how well our teams can run the facilities. We did do the pigging maintenance at Horizon in May. So when you account for that, it was a fantastic quarter. Obviously, once you do it once, you'll do it again, and that's what our goal would be is to make it closer to that when we don't have maintenance every quarter.

Right. Okay. Just one more debt question. Sometimes you guys will give a leverage ratio target as well for year-end. And obviously, you gave the net debt aspect of that. Just curious if there's a specific ratio you're thinking that, that would imply?

Well, I think we -- it would imply a higher leverage ratio than 2019 just based on commodity prices in 2020. So I'll leave it at that.

Yes. I mean, it seems like sub 4x, but -- yes, I was just curious.

Yes, for sure, it will be sub 4x.

Our next question comes from Manav Gupta from Crédit Suisse.

I wanted an outlook from the WCS differential. It's been widening a little here. Just wanted your thoughts on -- into year-end. And I think on last conference call, you talked about apportionments being very low and you were spot on. So if you could tag that and give us your near-term outlook on the apportionments on the pipelines also?

Sure. It's Tim McKay here. So apportionment when we look ahead here between the maintenance and what's come off the market here, we believe that apportionment will be relatively low going into the third quarter. Fourth quarter, again, it will probably depend mostly on the pricing situation at that time. But Q4 could be similar, maybe a little higher in terms of apportionment as the turnarounds are completed in the various areas. As far as WCS, I mean, it's 22% today. It's always -- it's an illiquid market. We think that anywhere from that 22% to 30% is probably the right range for the third and fourth quarter. But again, part of it's going to really depend on the pricing and what comes back on in the market here. But we feel very confident that apportionment at least for the third quarter will be quite low and towards the end of the year, might increase a bit.

And a quick follow-up. You are doing some turnaround on the Horizon and AOSP side. Should we assume that third quarter, we should see an increase from Jackfish and some of your other heavy production to offset the turnaround at Horizon and AOSP?

Yes, exactly. You'll see that we'll flex our thermal muscle in terms of increasing that production and wrapping up the Primrose and Jackfish and then obviously, as we come off the turnarounds at both AOSP and Horizon, they will decrease.

Your next question comes from Amir Arif from Cormark Securities.

Sorry, can you hear me?

Yes, we can.

Okay. Just a couple of quick questions for you. Just on the gas side, just given the strength we're seeing in the '21 strip, just curious how much more productive adds you could -- you have in your inventory in terms of low capital efficiencies that you're talking about in terms of $3,000 per flowing?

Well, obviously, the $3,000 per BOE/d were the kind of the cream opportunity. So obviously, we have more opportunities, probably between that $3,000 and $5,000 per BOE/d. And we always find other opportunities within our portfolio that our teams, when they look through the properties, buying those other opportunities. So it's kind of a continuous improvement process. There will be more. We always find more. I wouldn't want to say how much more today, but they are always working and improving. So all I can say is it's always more, if not less.

Okay. Sounds good. And then could you give us an update on the Septimus gas flood that you had initiated?

Yes, legs? So legs, we finished off last year. We moved the compressor into an Alberta area where we were looking to do that pilot in there. Right now, we've just got it on hold. Right now, with the stronger gas pricing and lower liquids prices, it just didn't make sense to carry on with that pilot in that area at this time, as well as we were preserving capital. So part of our budget process, we'll look ahead on that one. In terms of Septimus, it worked exactly as we felt it would. And so it is another lever we can pull in our -- for our company here in the future.

Okay. And then just a quick question on the AOSP side. Just with the expansion, is there any meaningful change or any change on the quality of the upgraded product coming out with the one expansion volumes?

Yes. So it's actually in 2 steps. So the first step is just increasing the front end. So there will be a little more heavy oil coming out of the upgrader after the expansion. And then in 2022, they do another part of expansion on the, I would say, the backside of the plant, which will give you more SCO. So it's just a 2-step process. Of course, we're not the operator. And -- but we'll get the first step, the front end up and see what -- where we can take that end. And then when they do the next piece in 2022, we'll get more quality SCO.

Okay. And then just a final question on the international side. Just -- if you look at the 5-year strip, just if you think of about a $45 to $50 environment, how does the international segment, just given that it's sort of spread around 3 different areas, how does that fit into the corporate profile?

Well, very well. It's a free cash generator. We've got exploration opportunities in CDI where we could increase production. So I look at it as just another opportunity that sits in our portfolio, that we can exercise when the timing is right. And if you look at the international operations, I believe the number I last saw was almost $5 billion of free cash flow from those properties over time here since owning it. So I look at it, it's just a nice adder to our company.

Okay. Sounds great. And just finally, when can we expect the results from that South African exploration well that you're spudding next quarter?

While the operator is moving the rig, and I would expect maybe in Q4 sometime year-end, yes.

[Operator Instructions]. Your next question comes from Mike Dunn from Stifel FirstEnergy.

Just wondering, gentlemen, I didn't see any 2020 production guidance in your disclosures today. Is it -- I'm assuming it's still the case that as of your press release 3 months ago, you still would be expecting to meet at least the low end of your original 2020 production guidance. And I just wanted to clarify if that included specifically for the oil and NGLs guidance as well and not just the total BOEs.

Yes. When we did our annual guidance back in December, it just included all production, so liquids production and gas production. So on the liquid production at that time, we had 910,000 to 970,000 barrels a day as a range, and the gas is 1,360 MMcf/d to 1,420 MMcf/d. So there's really -- the way today, with the stability of everything, I would say, yes, we'll be within guidance, probably maybe a little over guidance -- over on the gas side. But it's -- as we've seen here over the last few months with May minus -- negative pricing to where we are today, which looks pretty stable, it looks fairly on track.

Your next question comes from Menno Hulshof from TD Securities.

I just have one follow-up question on next year's Horizon turnaround. Can you just remind us of the scope of the expansion work that the outage is tied to?

Sure. There's a couple of items being done. But the biggest piece is the East Tank farm. So what this does is, it just gives us extra tankage so that when we go into an outage or have an outage in one of the plants that we're able to store product and then make that product back up. So that's probably the biggest scope that's happening out there. There is additional work that we're doing on some piping. Obviously, we have a very proactive integrity program. And we see some piping that we'd like to replace and really, that's really the major scope of it.

And what is the capacity of the new tankage?

Well, I don't have that number off hand there, sorry.

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

Thank you, operator, and thank you, everyone, for attending our conference call this morning. Canadian Natural's large, well diverse asset base continues to drive significant shareholder value. The ability of our teams to deliver effective and efficient operations with top-tier performance is contributing to substantial and sustainable free cash flow throughout the business cycle. This, together with effective capital allocation, contributes to achieving our goal of maximizing shareholder value. If you do have any further questions, please don't hesitate to give us a call. Thanks, and goodbye.