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. 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.

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 reviewing our advisory section in our financial statements that include comments on non-GAAP disclosures. Speaking on today's call are Scott Stauth, our President; and Mark Stainthorpe, our Chief Financial Officer. Scott will provide highlights on a strong operational quarter that included completion of planned turnarounds, setting us up for 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 opening up the line for questions. With that, I'll pass it to you, Scott.

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 the early completion of planned turnarounds at Jackfish and Kirby. At Horizon, we successfully completed the final tie-ins related to the reliability enhancement 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 a significant milestone at Horizon in July 2024 with the production of the 1 billionth 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 of 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 the 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 differentials, improved realized pricing, along with the development of a 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, the 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 outages. 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 improves. 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 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 turnarounds at 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 achieved full production capacity in Q2 of 2024, which is ahead of schedule. The second pad is currently producing at full 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 online 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 pad through decoupling construction schedules. The second pad is currently being drilled and is targeted to come on production in Q2 of 2025. At Wolf Lake, 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 solvent 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 for 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 to evaluate longer-term projects to potentially bring value forward, including near-term production growth at Scotford Upgrader, which includes the debottlenecking project, targeted to be completed during the plan and aims 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 recovery tailings treatment project, which is 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 adds growth in the second half of the year and positions us well moving into 2025 as we target strong production and free cash flow in the last 6 months of this year.

Thanks, Scott, and good morning, everyone. In the 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 the 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. 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.

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.

Your first question comes from Menno Hulshof of TD Cowen.

I'll start with a question on SCO given the 50,000 barrel per day net combined rate you achieved in July. You mentioned the Scotford Upgrader turnaround, and there won't be a planned turnaround at Horizon in 2025 due to the completion of the reliability enhancement project. Can you provide insight into what the trajectory will look like for synthetic through the end of the year and into 2025?

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 Horizon. So you would expect strong SCO volumes for the remainder of the year with the exception of that planned turnaround.

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.

Yes. As you know, there will be no turnaround at 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.

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?

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 in terms of how we see ourselves taking the good results from this pad and extrapolating that out to future pads.

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

Thanks for the overview, Scott. We don't often see perfect quarters, but this one appears to be just that. I'm curious about your new approach to the turnaround activity and optimization. You mentioned some separation in construction activities. However, as we begin to dissect optimization and planning, what has changed? What are you doing differently compared to the past?

Sure. Good question, Greg. If you look at Jackfish, the drilling results have been strong, and the team is doing an excellent job of building the facilities and getting the pads operational. Both pads executed well, but what really stood out was the production profile. The production ramp-up surpassed our previous expectations. We are very pleased with these results as they came in stronger than anticipated. At Primrose, we have decoupled the two pads, 71c and 162. We expedited 71c by separating the execution plans from the facility construction, allowing us to bring on volumes sooner. This success can be attributed to good planning by the teams, with a focus on optimizing production opportunities as quickly as possible. We are continuously working through schedules from a perspective of improvement, Greg.

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?

Yes. For the pathways project, it is essential for Canadian Natural and the industry to have a strong fiscal regime in place to effectively capture our CO2 emissions. This is crucial for us. We are exploring concepts and ideas as we advance through the engineering stages of the project, but the fiscal regime is very important. Additionally, we are anticipating further debottlenecks from Enbridge and TMX to help us capture the volumes we aim to bring on in the future.

Your next question is from Dennis Fong of CIBC.

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 have been for driving the cost structure lower just from that project in general?

Yes, that's a good question, Dennis. Looking ahead over the next few quarters, we will have the chance to evaluate the impact of the debottleneck project on our daily run rate and the subsequent production we will report. It’s too early for us to estimate what this might mean for total capacity. In these early stages, I can say that the outlook appears positive. However, we need to see the components of the upgrader operating at maximum rates to get a clearer picture. We will be able to provide a more detailed update on this in the next quarter, Dennis.

Great, I appreciate that context. Shifting over to the Mannville heavy oil and your cold heavy oil production overall, I appreciate the update regarding the length of the multilaterals that you've been drilling. Historically, CNQ has produced around 145,000 barrels a day from its conventional heavy oil assets, though I know that was some time ago. Given the substantial resource potential here, how do you plan to develop the asset from its current levels moving forward, especially considering the large acreage you control in both the Clearwater and the Lloydminster Mannville heavy oil stack?

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-laterals 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 target 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 over the next year. But with oil prices remaining in the range that they're currently at, looking at the forward strip, 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.

Your next question is from Manav Gupta of UBS.

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 back in 3Q because of the weaker product margin. So your near-term outlook on the differentials would be very helpful.

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.

Your next question is from Neil Mehta of Goldman Sachs.

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?

Yes, we are currently experiencing softer pricing. We have reviewed our plans with the teams and management, and we decided to postpone about half of the wells we had scheduled for this year. This means we will drill and complete around 20 out of 40 wells, but we won’t bring them into production until we see an improvement in prices. We anticipate that we might begin to see those benefits late in the fourth quarter or early in the first quarter, especially with LNG Canada starting to come online. Therefore, we expect prices to begin to recover from that point. This represents our perspective on the current situation.

I know it’s a bit challenging to discuss some of the ESG-related matters these days. How are we progressing on the Pathways project? What are the key issues we need to address? Additionally, how does political uncertainty play into the situation? I’m trying to get a clearer understanding of how this is developing.

Yes. I'd say the 3 parties, the federal government, provincial government and the Pathways organization are still working very diligently to try to come up with that financial regime package that will work for the investment to move forward. 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. I can tell you that there's a lot of effort and a lot of focus on the part of the CEOs and the representatives from the government to try to bring this forward and make it happen.

Your next question is from John Royall of JPMorgan.

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?

John, it's Mark here. You're right that the working capital we've discussed will fluctuate around the $10 billion level each quarter. The sale of the PrairieSky shares will help reduce debt. Since the beginning of 2024, we’ve been allocating 100% of our free cash flow to shareholders, and you will see that continue throughout 2024.

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?

Yes, I think we expect activity to be quite low going forward. There isn't anything specific that comes to mind regarding that. Given our asset base, the reserves we hold, and the opportunities available in those areas, we are very confident that we won't need to pursue acquisitions and can focus on strong internal growth instead. So, I don't have any additional comments regarding M&A activity at this time.

Your next question is from Patrick O'Rourke of ATB Capital Markets.

That's a thorough overview. I have a couple of questions, but I want to revisit the gap. You mentioned the macro situation. Over the past few years, you've shifted capital from gassier assets to oilier ones. I'm curious about the price range for AECO or whatever you're currently considering. At what price point would we see a return of capital to those gassier assets?

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 an 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.

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 previously guided 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.

You should consider the PrairieSky share sale as separate from free cash flow. When evaluating free cash flow policy, it involves adjusted funds flow from operations minus our capital expenditures and dividends. We remain committed to our goal of returning 100% of free cash flow to shareholders, but the PrairieSky shares fall outside that framework. It was simply an opportune time to sell and to realize the value we have gained from that investment over the years.

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

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.

This concludes today's presentation. Thank you for your participation. You may now disconnect.