Canadian Natural Resources Limited (NYSE:CNQ) Q2 2024 Earnings Call Transcript

Canadian Natural Resources Limited (NYSE:CNQ) Q2 2024 Earnings Call Transcript August 1, 2024

Operator: Good morning. We would like to welcome everyone to Canadian Natural’s 2024 second quarter earnings conference call and webcast. After the presentation, we will conduct a question-and-answer session. [Operator Instructions]. Please note, this call is being recorded today, August 1, 2024 at 9 A.M. Mountain Time. I would now like to turn the meeting over to your host for today’s call, Lance Casson, Manager of Investor Relations.

Lance Casson: Thank you. Good morning, everyone, and thank you for joining Canadian Natural’s Second Quarter 2024 Earnings Conference Call. As always, I’d like to remind you of our forward-looking statements. It should be noted that in our reporting disclosures everything is in Canadian dollars, unless otherwise stated, and we reported reserves and production before royalties. Additionally, I would suggest to review our advisory section in our financial statements that include comments on non-GAAP disclosures. Speaking on today’s call, Scott Stauth, our President; and Mark Stainthorpe, our Chief Financial Officer. Scott will provide highlights on strong operational quarter that included completion of planned turnarounds, setting us off a robust target of production in the second half of the year.

Mark will then summarize our excellent financial results, including significant liquidity and returns to shareholders. To close, Scott will summarize prior to open up the line for questions. With that, I’ll pass it to you, Scott.

Scott Stauth: Thank you, Lance, and good morning, everyone. The strength of our well-balanced and diverse portfolio, combined with our ability to execute safe, effective and efficient operations delivered an excellent second quarter for Canadian Natural. Our team managed our planned maintenance activities very well, and optimized production resulting in a strong second quarter with production of 1.29 million BOEs per day, which is an increase of 8% compared to Q2 of 2023. Our thermal assets delivered strong production during the second quarter, primarily due to better-than-expected performance from the new pad combined with early completion of planned turnarounds at Jackfish and Kirby. At Horizon, we successfully completed the final tie-ins related to the reliability and happen project as well as planned turnaround activities.

Through optimization efforts, our team completed the turnaround at Horizon in 28 days, 2 days earlier than budgeted. Subsequent to the quarter end, we achieved significant milestone at Horizon in July 2024 with production of the 1 billion-barrel of bitumen since operations began in 2009. Supporting this milestone is the company’s significant total proved SCO reserves of approximately 6.9 billion barrels with a reserve life index of 44 years as at year-end 2023. Also during July, SCO production of approximately 500,000 barrels per day was achieved, driven by strong production at Horizon benefiting from the final tie-ins and commissioning of the reliability enhancement project. The commissioning of TMX pipeline during the second quarter and the positive impact of this incremental egress has had on the Canadian economy represents a significant achievement for Canada.

The impact on the energy industry has been and will continue to be positive through the narrowing differential — differentials, improved realized pricing along with the development of more diverse market for Western Canadian crude oil. TMX is a significant accomplishment, adding much needed egress capacity and increasing exposure to global market pricing for crude oil products. Canadian Natural’s strong execution, effective and efficient operations, combined with stronger realized prices drove significant free cash flow during the quarter despite planned turnarounds. I will now run through our Q2 operational results. Liquids production in the second quarter averaged approximately 934,000 barrels per day, and natural gas production averaged approximately 2.1 bcf per day.

On the conventional side of the business, primary heavy oil production averaged approximately 79,100 barrels per day in the second quarter which is a 3% increase compared to the production volumes in the second quarter of 2023, reflecting strong results from multilateral wells on our extensive heavy oil land base which is the largest in Canada and includes the Mannville and Clearwater fairways. Primary heavy oil operating costs averaged $17.59 per barrel in the second quarter, which is down 12% from the second quarter of 2023, primarily reflecting lower energy costs. We are seeing excellent results on our multilateral wells, driven by our culture of continuous improvement and strong execution from the team. In 2024, we increased the average length of our multilateral heavy oil wells by 16% to approximately 9,900 meters compared to an average budgeted well length of approximately 8,500 meters.

This has lowered our cost per meter and increased our reservoir capture. As a result of our optimized longer well designs and the technical expertise of our teams average initial peak rigs of multilateral onstream in the first half of 2024, have increased 30% to 230 barrels per day per well compared to our average initial peak rates of 175 barrels per day per well. Our Pelican Lake production averaged approximately 45,000 barrels per day in the second quarter, which is down 5% from the second quarter of 2023, reflecting low natural field declines from this long life world-class asset. Operating costs at Pelican Lake were $8.92 per barrel in the second quarter, an increase of 4% compared to the second quarter of 2023, which was primarily due to lower production volumes partially offset by lower energy.

North American light crude oil and natural gas production averaged 108,000 barrels per day in the second quarter, which is up 5% from the second quarter of ’23. The increase was a result of strong drilling results over the past year and lower production in the second quarter of 2023 caused by wildfires and third-party pipeline outage. Operating costs in our alloy crude oil NGL operations averaged $13.75 per barrel in the second quarter, a decrease of 24% compared to the second quarter of 2023 due to higher production and lower energy costs. North American natural gas production averaged 2.1 Bcf during the second quarter, which is comparable to the second quarter of 2023, reflecting strong results from our Montney and Deep Basin wells, offset by natural field declines.

Operating costs in our North American natural gas averaged $1.19 per Mcf in the second quarter, which is down 12% compared to the second quarter of 2023, primarily a result of lower energy costs. As we outlined in our first quarter, we shifted certain natural gas development activity in 2024 to high-return multilateral heavy oil wells due to lower natural gas prices. Concurrently, approximately 20% of our remaining 2024 planned natural gas wells will be drilled with production curtailed until the trend in natural gas prices improve. We maintain optionality to bring these natural gas wells on production in late 2024 or early 2025 to align with improved natural gas prices, maximizing value for our shareholders. Our 2024 corporate natural gas production guidance of 2.12 Bcf to 2.23 Bcf remains unchanged.

In our thermal and situ operations, we achieved — we achieved strong thermal production in the second quarter, averaging just over 260,000 barrels per day. This is up 12% from the second quarter of 2023, driven by strong results from Jackfish, Kirby North and Primrose pad developments. Second quarter thermal and situ operating costs averaged $10.95 per barrel, which is down 25% compared to the second quarter of 2023, primarily reflecting higher production volumes and lower energy costs. Planned turnaround to Jackfish and Kirby North facilities were successfully completed ahead of schedule in Q2 of ’24. At Jackfish, the first of 2 SAGD pads drilled in 2023, which full production capacity in Q2 of 2024, which is ahead of schedule. The second pad is currently producing at full production capacity and is also ahead of schedule originally budgeted for Q4 of 2024.

The teams executed both of these Jackfish pads very well from drilling to onstream and both exceeded our previous production type curves. Additionally, we are targeting to drill one SAGD pad at Jackfish in the second half of 2024 with production from this pad targeted to come on in Q3 for 2025. At Primrose, we finished drilling one CSS pad, which is targeted to come on production ahead of schedule in late Q4 2024. This pad was originally targeted for Q2 of 2025. Again, the teams have done a good job of optimizing execution, advancing the first path through decoupling construction schedules. The second pad is currently being drilled and is targeted to come on in production in Q2 of 2025. At Wolf Lake, we currently — we recently drilled one SAGD pad, which is targeted to come on full production in Q1 of 2025.

At Kirby North, we started injecting solvent in late June 2024. Currently, all 8 wells at our commercial scale solvent SAGD pad are receiving solvent, and we target to increase solvent injection with subsequent reduction in steam injection over the coming months. We will monitor solved recoveries and production trends as we evaluate ongoing results. In our oil sands mining and upgrading operations, second quarter SCO production averaged approximately 411,000 barrels per day, an increase of 16% compared to the second quarter of 2023. The increase in production reflected planned maintenance at Horizon that was successfully completed ahead of schedule compared to Q2 of 2023, which included planned turnarounds at both Horizon and AOSP. Operating costs on our oil sands mining and upgrading assets are top tier, averaging $25.95 per barrel in the second quarter, a 17% decrease compared to the second quarter of 2023.

This reflects higher production volumes from produced planned maintenance activities and lower energy costs. At AOSP, due to the schedule optimization of the Scotford Upgrader in Q2, the planned September turnaround is now targeted the last 39 days compared to the previous 49-day schedule. During this turnaround, Scotford Upgrader is expected to run at reduced rates with the impact to annual production targeted to be approximately 9,000 barrels per day, a 2,000 barrel per day improvement compared to budget. Our significant SCO reserves are world-class. We are executing near- and medium-term projects evaluate longer-term projects to potentially bring value forward, including near-term production growth at Scotford Upgrader includes debottlenecking project, which is targeted to be completed during the plan and targets to add incremental capacity at AOSP of approximately 5,600 barrels per day net to Canadian Natural.

Medium-term production growth includes other oil sands mining and upgrading optimization projects such as the naphtha recover tailings treatment project, which targeted to add approximately 6,300 barrels per day of production in late 2027. Longer term, combining our IPEP technology with Paraffinic Froth Treatment has the potential to add approximately 195,000 barrels per day of annual bitumen production. Our world-class assets are strategically balanced across commodity types so we can be flexible and capture opportunities throughout the commodity cycle to maximize value for shareholders. Our unique and diverse portfolio of assets is supported by long-life, low-decline assets, which have large low-risk, high-value reserves with low maintenance capital, making Canadian Natural truly a unique and resilient energy company.

The strategic weighting of our capital program this year adding growth in the second half of the year and exiting 2024 with strong production rates positions us well moving into 2025, while we target strong production and free cash flow in the last 6 months of this year. Now with that, I’ll turn it over to Mark for a financial review.

Mark Stainthorpe: Thanks, Scott, and good morning, everyone. In second quarter of 2024, we achieved excellent financial results driven by strong operational execution and our relentless focus on continuous improvement initiatives across the company. We generated adjusted funds flow of $3.6 billion and adjusted net earnings from operations of $1.9 billion. This drove significant returns to shareholders in the quarter totaling $1.9 billion, with $1.1 billion in dividends and $800 million in share buybacks through our NCIB program. Our capital program for 2024 remains on track and with increasing production volumes forecasted in the second half of 2024, we target to generate significant free cash flow and additional returns to shareholders as we continue to allocate 100% of free cash flow to shareholders in 2024.

Our commitment to increasing share returns is clear in our sustainable and growing quarterly dividend, which on a post-split basis was increased to $0.525 per share in March 2024 from $0.50 per share, marking 2024 as the 24th consecutive year of dividend increases. Subsequent to quarter end, the Board has declared a quarterly dividend of $0.525 per share payable on October 4, 2024. Our financial position is very strong with net debt at $9.2 billion and debt-to-EBITDA at 0.6x at the end of Q2 ’24. And during the quarter, we repaid at maturity a USD 500 million bond and a $320 million medium-term note. Liquidity remains strong and including revolving bank facilities and cash liquidity at the end of the quarter was approximately $6.4 billion. Our culture of continuous improvement, employee ownership alignment with shareholders and our operational expertise drives our teams to create significant value across all areas of the company.

With that, I’ll turn it back to Scott for some final comments.

Scott Stauth: Thanks, Mark. And again, in summary here at Canadian Natural. Our disciplined focus is the core of what we do. Our culture of continuous improvement focused on cost control, effective and efficient operations and disciplined capital allocations continue to drive strong results while maintaining financial flexibility, maximizing value for our shareholders. With that, I will turn it over for questions.

Q&A Session

Operator: [Operator Instructions]. Your first question comes from Menno Hulshof of TD Cowen.

Menno Hulshof: I’ll start with a question on SCO given the 50,000 barrel per day net combined rate you achieved in July. You talked about the Scotford Upgrader turnaround, and then you also have the — I guess, in 2025, there is no planned turnaround at Horizon given completion of the reliability enhancement project. So can you just give us a sense of what the trajectory is going to look like for synthetic through the end of the year and into 2025?

Scott Stauth: I think our volumes are going to look pretty strong. I mean the only thing that you’ll see is our planned turnaround, which we reduced at Scotford from 49 days down to 39 days. No further production interruptions or planned maintenance activities at risen. So you would expect strong SCO volumes for the remainder of the year with the exception of that planned turnaround.

Menno Hulshof: And then for 2025, is there anything that you can say there? I mean it should be a pretty clean year across the board, presumably.

Mark Stainthorpe: Yes. As you know, there will be no turnaround on horizon next year. There will be a turnaround at Scotford next year, but not at Horizon. So it should be another strong year with production rates at Horizon being approximately 28,000 barrels a day higher for the next year.

Menno Hulshof: Perfect. And then maybe the second question would be on solvent, the solvent enhanced oil recovery pilots at Kirby North and Primrose. Can you just give us a rundown on what you’re currently seeing in terms of results, including solvent recovery? And when do you think you’ll be in a position to make a decision on whether to commit to that on a more commercial scale?

Mark Stainthorpe: Yes. So as you know, we’ve recently placed the KN06 pad on solvent injection at the end of July. We are seeing some early reduction results in and around the 20% range. So that’s very positive this early in the game. Other than that, nothing significant to report out to you at this point in time. Over the following quarters, we’ll continue to update everyone here in terms of where we’re at. I would suspect by mid next year, this time next year, we should be able to come out and report out in terms of how we see us taking the good results from this pad and extrapolating that out on future pads.

Operator: Your next question is from Greg Pardy of RBC Capital Markets.

Greg Pardy: Thanks for the rundown, Scott. We don’t see too many flawless quarters, but this sure looks like it. I’m kind of intrigued a little bit with what you’re doing differently with the turnaround activity and the optimization. I know you referenced just in your comments where there have been some decoupling of construction activities. But — what when you start to kind of break down optimization and planning and so on, what maybe — what has changed? And what are you doing differently than in the past?

Mark Stainthorpe: Sure. Yes. Good question, Greg. So if you looked at — take a look at Jackfish, essentially rate from strong drilling results to the team is doing a really good job of building the facilities and getting the pads on stream. That’s our [indiscernible] and our SPADs. Both of those pads, the execution was strong, but what really stood out on both of those pads was the production profile. The ramp-up of production exceeded our previous type curves. So we’re very pleased with those results as they came in stronger than we had expected. And then over at Primrose, we have decoupled the 2 pads, 71c 162. We brought forward 71c because we were able to decouple the execution plans from the facility construction perspective, focus on bringing on volumes sooner than we would have otherwise.

So it was really coming through good planning of the teams with the focus being on optimizing the production opportunity as soon as possible. So just working through the schedules from a continuous improvement perspective, Greg.

Greg Pardy: Okay. And then this is, I mean, the longer-dated stuff and so on. But in terms of IPEP and PFT, I mean, there’s conceivably quite a big prize there, $195,000 in total, as you mentioned. What are the pieces that would need to be in place in order for the company to start to move towards that?

Mark Stainthorpe: Yes. So for that project, what’s really important for Canadian Natural and for industry from that perspective for that matter is that we need to see a strong fiscal regime for our pathways project so that we can capture our CO2 emissions. So that is key for us. We’ve got concepts and ideas in terms of working through the engineering stages of that project. But the fiscal regime for pathways is very important. The second piece is the egress out of the basin here. And so — we’re looking forward to additional Enbridge debottleneck as well as TMX to look at capturing those volumes that we bring on in the future.

Operator: Your next question is from Dennis Fong of CIBC.

Dennis Fong: My first one is a bit of a follow-on to Menno’s question on Horizon and the cadence of production. As we think about, again, further optimization of the asset itself. How do you think your teams could potentially drive outperformance versus what you think is currently, you will call it stated capacity? And then secondarily, what do you think the implications of that happened to be for driving cost structure lower just from that project in general?

Mark Stainthorpe: Yes, good question, Dennis. I think if you look forward over the next few quarters here, where we’ll have the opportunity to see what the impacts of the debottleneck project have truly been in terms of a day run rate and subsequent production that we’ll report out. I think it’s early for us to estimate what that might look like in terms of the capacity — total capacity. At early stages, I can tell you, it does look positive. But again, we need to see the components throughout the upgrader running at the maximum rates here, and then we’ll have a better idea. But we’ll be able to report it out a little bit better on that in the next quarter, Dennis.

Dennis Fong: Great. I appreciate that context. Shifting over to the Mannville heavy oil and just your heavy oil — your cold heavy oil production in aggregate, I appreciate the incremental update in terms of length of multilaterals that you’ve been drilling. When we look historically through time that CNQ has produced up to, I think, about 145,000 barrels a day from just the conventional heavy oil assets in aggregate. Now I understand that’s a long time ago. But understanding that there’s a large kind of resource prize here. How do you think about developing the asset from kind of the current levels today and ongoing, especially given the large acreage position that you have both in the Clearwater and in kind of the Lloydminster Mannville heavy oil stack?

Mark Stainthorpe: Yes. Good question, Dennis. I think you’d look at it just from an overall corporate capital allocation strategy and we’ll direct our capital towards the projects that do create the best returns for us based on cost and pricing received. If you look specifically at heavy oil and the introduction of the multi-lats in those areas, we’ll continue to optimize the technology to put it to best use. We also continue to use our slot well drilling and targeting certain zones. And again, it just really boils back to how we allocate our capital within our corporate portfolio. So I can’t tell you exactly how that’s going to look like over the next year. But with oil prices remaining in the range that they’re currently at, looking at the forward strip, I’d say — I think you could consider that the current activity levels and the levels that we have budgeted for 2024 would likely continue on into 2025.

Operator: Your next question is from Manav Gupta of UBS.

Manav Gupta: Congrats on a strong quarter. Just trying to understand, you have a very informed view on the differential there. We have seen a little bit of widening here. And also, what we are seeing on the U.S. side is a number of U.S. refiners are pulling backgrounds in 3Q because of the weaker product margin. So your near-term outlook on the differentials would be very helpful.

Mark Stainthorpe: Sure. Yes. And it’s a very good question. And I think you mentioned one of the impacts, which is the wider crack spreads that the refineries are seeing. So that has an impact on the differential. The second thing that we’re seeing is the drawdown on Alberta inventory stock. So over the last 104 days for us looking at the numbers, we can see a drawdown of approximately 150,000 barrels per day. So that’s in excess of existing Western Canadian Basin production. So that’s also having an impact and I think you’re also seeing additions of Mexican crude into the U.S. Gulf Coast. So that is also having an impact. So those 3 things combined, we’re seeing, you saw June at $11. And so now you’re seeing $15, $15.5 right now. So I think those 3 things combined are having an impact.

Operator: Your next question is from Neil Mehta of Goldman Sachs.

Neil Mehta: Yes. Thanks, team, and solid results here. I just want to stay on the differential theme this time talking about the gas side of the equation. Remind us again how you’re thinking about natural gas in your portfolio, while it’s obviously very weak right now. From a pricing standpoint, it’s also a cost. So how do you think about the net impacts? And just as we think about AECO specifically, how does pricing evolve from here as we think about the next couple of years?

Mark Stainthorpe: Yes. I think you’re — obviously, we’re seeing the softer pricing right now. We have gone back to review with our teams and our management, and we elected to take approximately half of the wells remain planned for the rest of the year. So that will be about 20 wells out of a total of 40 that we’re going to basically drill, complete, but not put on production until we see those prices improve. And I think we’re looking at timing of that in — late in the fourth quarter or early in Q1, I think we should see the benefits of LNG Canada starting to commission and come online. So I think we’ll see the prices start to turn around from there. And that’s our view on where we see things going at this point in time.

Neil Mehta: And then the follow-up is — and I know it’s a little trickier to talk about some of the ESG-related stuff these days. But how are we tracking on the Pathways project? What are gating items here? How does political uncertainty fit into that as well? And I would just trying to get a sense of how this is evolving.

Mark Stainthorpe: Yes. I’d say the 3 parties, the federal government, provincial government and the Pathways organization is still working very diligently to try to come up with that financial regime package that will work for the investment to move forward. And again, it’s a collaboration of those 3 parties. It takes time to work through all of the parameters that they’re working with in terms of the cost structure. I’m still positive at this time that we’re going to see something come together here. And I can tell you that there’s a lot of effort and a lot of focus on part of the CEOs and the representatives from the government to try to bring this forward and make it happen.

Operator: Your next question is from John Royall of JPMorgan.

John Royall: So my first question is you’re pretty meaningfully below $10 billion in net debt as of the end of the quarter, which I think was largely due to the working capital release and the sale of the PSK shares, understanding cash flows are volatile, and it’s difficult to be right to $10 billion on any given day. But should we expect that maybe you can return in excess of 100% in the second half, given you have this buffer right now at $9.2 million?

Mark Stainthorpe: John, it’s Mark here. And yes, I mean, you’re correct. There’s the working capital that we’ve talked about from quarter-to-quarter will fluctuate us around that $10 billion level. And then the sale of the PrairieSky share is obviously going to reduce debt. But right now and since the beginning of 2024, we’ve been at that sort of 100% of free cash flow allocation to shareholders’ framework. So you can see that — you’ll see that continue through the rest of ’24.

John Royall: Okay. Great. And then can you speak about your current thinking on the M&A side. We spoke about the small divestiture. Just anything else you might look at on the divestiture side obviously, your balance sheet is where you want it to be, but anything else you might look to sort of prune there? And then just on the other side, how you’re thinking about acquisitions from here?

Mark Stainthorpe: Yes. I don’t — I think we expect activity to be pretty quiet going forward here. And there isn’t anything that comes to mind in terms of from that perspective. So I would think that like as you know, we have the — with the asset base that we have, the amount of reserves that we have and the opportunities they have within those various areas. We’re really confident and confident about not having to do any acquisitions and having that strong internal growth here. So yes, it’s — I don’t have any other comments in terms of the M&A activity at this point.

Operator: Your next question is from Patrick O’Rourke of ATB Capital Markets.

Patrick O’Rourke: Pretty comprehensive rundown. A few things that’s going to actually just get asked. But I want to walk back to the gap. You talked — you spoke to the macro here. Over the last couple of years, you’ve reallocated capital from what was going to be directed to gassier assets over the oilier assets. Just kind of curious in terms of sort of the price range for AECO or however you’re looking at it right now. What would sort of be the price where we would see capital swing back to those gassier assets?

Mark Stainthorpe: Yes. It’s a good question, Patrick. I think though, how you got to look at it is that in terms of the Montney, you’ve got significant liquids production, which really drive the economics there. So it doesn’t take much of a gas price from that perspective to have the economics go around to drill and complete those wells. Where you get into the lower liquids production wells, I think we definitely need to see a little bit stronger activity, the stronger pricing that we’re seeing right now. I can’t give you exact price, but it has to be better than it is now. If you look at the forward pricing we can make it work at what we’re seeing in the strip.

Patrick O’Rourke: Okay. And then just maybe to kind of build upon what John Royall was asking earlier. You did take the net debt down meaningfully below the $10 billion. Can you just clarify in terms of free cash flow, do you consider those previous guided the funds from that to be free cash flow that you would distribute to shareholders when we’re running our calculation here? And then I don’t know if you can speak to what kind of the motivation for the timing of the sale of that asset was.

Mark Stainthorpe: Yes. No, you should think of the PrairieSky share sale is outside of the free cash flow because when you look at the free cash flow policy, it’s adjusted funds flow from operations less our capital less our dividend. So it will — we continue down that path of that 100% free cash flow return to shareholders, but the PrairieSky shares were outside of that. And then as far as for us, it was just a good time to sell the right time to sell and capture that good value we have here from an investment over the period here.

Operator: There are no further questions at this time. I will now turn the call over to the presenters for closing remarks.

Lance Casson: Thank you, operator, and thanks to everyone for joining us this morning. If you have any questions, please give us a call. Thanks, and have a great day.

Operator: This concludes today’s presentation. Thank you for your participation. You may now disconnect.