Good morning. We would like to welcome everyone to Canadian Natural's 2024 First Quarter Earnings Conference Call and Webcast. [Operator Instructions] Please note, this call is being recorded today, May 2, 2024, at 7 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. Please go ahead.

Good morning, everyone, and thank you for joining Canadian Natural's First Quarter 2024 Earnings Conference Call. Before we begin, I'd like to remind you of our forward-looking statements, and it should be noted that in our reporting disclosures everything is in Canadian dollars, unless otherwise stated, and we report reserves and production before royalties. Additionally, I would suggest to review our comments on non-GAAP disclosures in our financial statements. Speaking on today's call will be Scott Stauth, our President; and Mark Stainthorpe, our Chief Financial Officer. Scott will first provide highlights on our safe, reliable and world-class operations and help through our defined plan, effective efficient operations and strong execution. We're targeting a robust production in the second half of 2024. Mark will then summarize our financial results, including strong shareholder returns. To close, Scott will summarize prior to opening up the line for questions. With that, over to you, Scott.

Thank you, Lance, and good morning, everyone. Canadian Natural has been in operation for 35 years and has always been focused on returns on capital and creating value for shareholders. 2024 marks an important milestone as we are delivering 100% of free cash flow to shareholders this year. And with strong crude oil strip pricing for the remainder of the year, we are targeting to generate significant free cash flow. With our large diverse assets, we have plenty of growth opportunities to continue to create long-term shareholder value and have the flexibility to manage the pace and timing of these development opportunities. As we outlined with our 2024 budget, we have significant strategically weighted development in the first half of the year to our longer-cycle assets, primarily on thermal pad and back-end weighted with our conventional growth development, as this aligns with increased market access as well as improved forward strip pricing. As a result, we are targeting to finish the year with strong exit rates as a conventional more shorter cycle growth activity ramps up in the second half of the year. We continue to find ways to be more effective and efficient, including optimizing our turnaround schedule. For example, we are well prepared for the upcoming turnaround at Horizon, where we will be tying in the final components of the reliability enhancement project, which sets us up for strong utilization and production in the second half of the year and add 28,000 barrels a day in 2025 when we skip a turnaround. Through early turnaround work in Q1 during the unplanned maintenance activities, we reduced the outage duration of the plant due to Horizon turnaround from -- to 28 from 30 days. Additionally, we have optimized the commissioning schedule of the reliability enhancement project, which will be brought online in June following the turnaround. We have a debottleneck project at the Scotford Upgrader that will be implemented during the turnaround this fall, which will add approximately 5,600 barrels per day net to Canadian Natural. It's the small incremental movements that add up and create additional value for our shareholders, as these targeted improvements will help drive stronger production in the second half of this year. Longer term, we have our other Oil Sands Mining and Upgrading optimization projects, including the Naphtha Recovery treatment project, which is targeted to add approximately 6,300 barrels per day late to 2027. And beyond that, combining our IPEP technology with Paraffinic Froth Treatment has the potential to add approximately 195,000 barrels per day of additional annual bitumen production while improving environmental performance. Along with growth, we have a defined path to reduce our environmental footprint and continue delivering sustainable, responsible produce energy that the world needs. We are committed to supporting Canada's and Alberta's climate goals and have robust environmental targets, including zero greenhouse gas emissions in the oil sands by 2050. We are uniquely positioned with diverse long-life, low-decline assets, which are ideal for applying greenhouse gas reduction technologies and providing industry-leading environmental performance. It is important to continue working together with the Canadian and Alberta governments to make sure the Pathways Alliance is a transformative industry collaboration and achieve meaningful greenhouse gas reductions in Canada. We believe Canadian Energy is one of the most responsibly produced sources of energy in the world and should be the preferred energy choice. I will now run through our Q1 operational results. Total production in Q1 averaged approximately 1.33 million BOEs per day, including total liquid production of approximately 976,000 barrels per day and natural gas production of approximately 2.15 Bcf per day. On the conventional side of the business, primary heavy oil production averaged approximately 78,400 barrels per day in the quarter, which is comparable to production volumes in the first quarter of 2023, reflecting strong results from our multilateral wells in the Mannville and Clearwater fairways, which offsets natural field declines. Primary heavy oil operating costs averaged $19.16 in the first quarter, which is down 11% from the first quarter of 2023, reflecting lower energy costs. Our Pelican production averaged just over 45,000 barrels per day in the first quarter, which is down 6% from first quarter of '23, reflecting low natural field declines from this long-life asset. Operating costs at Pelican were $9.75 a barrel in the first quarter comparable with costs in the first quarter of 2023. North American crude oil and natural gas production averaged approximately 114,000 barrels a day in the first quarter, which is up 5% from the first quarter of '23. Operating costs in our light crude oil and NGLs operations averaged $15.25 in the first quarter, a decrease of 18% compared to the first quarter of 2023, reflecting higher production and lower energy costs. North American natural gas production averaged 2.14 Bcf during the first quarter, which is comparable to the first quarter of 2023. Operating costs on our North American natural gas averaged $1.27 Mcf in the first quarter which is down 11% compared to the first quarter of 2023, primarily related to lower energy costs. In our thermal in situ operations, we achieved strong thermal production in the first quarter, averaging just over 268,000 barrels per day. This is up 10% from the first quarter of 2023 as a result of strong execution on CSS and SAGD pad developments during 2023. First quarter thermal in situ operating costs averaged $14.05 a barrel, which is down 12% compared to the first quarter of 2023, primarily reflecting higher production volumes and lower energy costs. In April, we successfully completed the planned turnaround at Jackfish a few days ahead of schedule, and we have upcoming turnarounds at Kirby North in May of '24. Due to the early completion of the turn on Jackfish, the total impact to Q2 2024 average production is now targeted to be approximately 15,300 barrels per day, an improvement of 1,800 barrels per day from the previous impact target of 17,100 barrels per day. At Primrose, we are currently drilling 2 CSS pads, which are targeted to come on production in Q2 of 2025. We're also drilling a SAGD pad at Wolf Lake, which is targeted to come on production in Q1 of 2025. At Jackfish, we drilled 2 SAGD pads in 2023, the first of which ramped up to its full production capacity in April of this year, which is ahead of budget. The second pad is targeted to ramp up the full production capacity in Q4 of 2024. This will support continued high utilization rates at the Jackfish facilities. Additionally, we are targeting to drill 1 SAGD pad at Jackfish in the second half of 2024, with production from this pad targeted to come on in Q3 of 2025. The commercial scale solvent SAGD pad development at Kirby North is approximately 90% complete, and we are targeting to begin solvent injection in July of 2024. The use of solvents is targeted to reduce our SORs and our greenhouse gas emissions intensities by 40% to 50%. In our Oil Sands Mining and Upgrading operations, the first quarter SCO production averaged just over 445,000 barrels per day, 45,000 barrels per day lower than our targeted -- target for the first quarter, reflecting both planned and unplanned maintenance activities, including the advancement of the Scotford Upgrader planned turnaround from March to April -- to March from April. Through improved turnaround and commissioning scheduling as well as optimization efforts, we are targeting to recover these daily production volumes in the last 3 quarters of the year. Our operating costs in our Oil Sands Mining and Upgrading assets are top tier, averaging $24.85 a barrel in the first quarter comparable with the first quarter of 2023. Canadian Natural has a proven effective capital allocation strategy. We have a balance of near-, medium- and long-term growth opportunities, as I mentioned at the beginning of my call, not only on our Oil Sands Mining assets but across our entire asset base. And with the strategic weighting of our capital program this year to add growth in the second half of the year and exit 2024 with strong rates, we are targeting strong free cash flow in the last 9 months of this year. Now I will turn it over to Mark for our financial review.

Thanks, Scott, and good morning, everyone. In the first quarter of 2024, we generated solid financial results with adjusted funds flow of $3.1 billion and adjusted net earnings from operations of $1.5 billion. This drove significant returns to shareholders in the quarter, totaling $1.7 billion, with $1.1 billion in dividends and $600 million in share buybacks through our NCIB program. As we reached net debt of $10 billion at the end of 2023, we are targeting 100% of free cash flow to shareholders in 2024 as per our free cash flow allocation policy. And we'll continue to manage the allocation on a forward-looking annual basis. Our commitment to increasing shareholder returns is evident in our sustainable and growing quarterly dividend, which was previously increased to $1.05 per share from $1 per share in March 2024, marking 2024 as the 24th consecutive year of dividend increases. Subsequent to quarter end, the Board has declared a quarterly dividend of $1.05 per share payable on July 5, 2024. Our financial position is very strong with debt to EBITDA at 0.6x at the end of Q1 '24, and we continue to maintain strong liquidity. Including revolving bank lines, cash and short-term investments, liquidity at the end of the quarter was approximately $6.8 billion. As Scott has already laid out, when you combine our strategic plan in 2024, our continuous improvement initiatives and optimized production with strong commodity prices, specifically for WCS and high-value SCO, we are targeting significant free cash flow through the remainder of the year. This resulted increasing shareholder returns through our 100% of free cash flow allocation policy. With that, I'll turn it back to you, Scott, for some final comments.

Thanks, Mark. In summary, here at Canadian Natural, our culture of continuous improvement and ownership alignment with shareholders drives our team to create significant value across all areas of the company. Our effective and efficient operations combined with flexible capital allocation drives strong returns on capital and maximizes value for our shareholders. With that, I will turn it over for questions.

[Operator Instructions] Your first question is from Menno Hulshof from TD Cowen.

I'll start with a question on the 55,000 barrels per day of additional commitments that you made on Flanagan South within the quarter. Can you elaborate on how that became available in the terms if you're willing to go there, and I'm guessing you're not? And then I guess the follow-up to that is, what's the longer-term vision for building a U.S. Gulf Coast access? And would you consider building out export capability like some of -- some other companies have done?

Good question, and thanks for that. Yes, the opportunity on Flanagan to gain the additional 55,000 barrels just came through an open season process. We participated in that process, yes. And you're right, I won't be able to disclose the terms, but we just view it as a good deal. It allows us the opportunity to go to expand in markets. And then from that, your additional question just in terms of further expansions, I think we'd look towards other expansion opportunities on the Mainline system, potentially on the TMX system, which we think over time is going to create optional additional egress opportunities.

Terrific. And then my second question relates to the shift from natural gas activity into heavy into year-end. You talked about the heavy well additions. But can you quantify how much things are getting dialed back on the natural gas side of things? And I'm thinking along the lines of locations, rigs and capital.

Yes. On the oil side, it's a reduction of about half a dozen gas wells and a pickup of about 12 multilateral wells. So it's about neutral on the capital piece. So we looked at it as a good opportunity to enhance some of the netbacks we're going to be seeing in the second half of the year on our oil side.

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

Really two very different questions. But Scott, I continue to be kind of intrigued on what you're doing with solvents. And I'm wondering if you could perhaps frame the commercial scale project you have now, how are you -- a, I don't really know what the size of it is ultimately going to look like. But is it possible for you to speak maybe to what capital efficiency and/or operating costs might look like with that project? Or is that really to come?

Yes, great, good question. And for sure, some of that is still to come. As this project is set up on, I'll say, a pad scale basis, we call it a commercial project because effectively, we would be able to assimilate that on future pads, as we go forward. So we constructed the injection facilities and the recovery facilities. And really once we start injecting solvent here in July, we're going to monitor the process. We want to make sure we understand how well the recoveries are of the solvent. It's a key component in terms of the economics. And we want to ensure that we give enough run time to fully understand the cycle from a solvent perspective. But essentially, what it does allow you to do, as I mentioned before, is reduced the SORs by roughly half as well as the greenhouse gas emissions by roughly half. And we can scale it up as we add more pads going forward in the future in our SAGD operations.

Okay. Okay. Terrific. Yes, it will be good to follow up with that, I guess, later in the year end, I guess even into next year. And then the second one, obviously, TMX is in focus. Could you maybe just comment on how you're -- well, to the extent you want to, just on how you're marketing will look, whether you've already secured tankers? I mean, I'd be very interested as to whether those are destined for California or there's going to Asia or what have you? There was some press sounding suggesting limitations and pilots and so forth in the area, but just any color there would be great.

Sure. Yes, it's a good question, Greg. And so we do have a mixture of both land-based sales and marine sales. We'll continue to develop those marine sales. We have secured some marine sales so far. We'll continue to evolve that market as we go forward here. But really, it's a bit of a balance of both land and marine side. And some of that, Greg, as you pointed out, may end up going marine side still on to the West Coast or it could move to Asian markets.

[Operator Instructions] Your next question is from Dennis Fong from CIBC World Market.

The first one is maybe just following along with Greg's question just on solvents, but more specifically at Primrose. When I take a look at facility capacity, there is an abundance of oil handling capacity, but the limitation may be a little bit more on the steam side. I know you've an ongoing pilot in the region. At what point would you feel more comfortable providing a broader deployment to solvent within the region? And what do you view as being the potential upside from a productivity side for Primrose and Wolf Lake?

Yes, good question, Dennis. And we're going to be able to leverage some of the learnings even from our SAGD commercial solvent project that we're doing in Kirby North. We leverage that towards understanding the processability on the solid side at Primrose. And yes, as you know, there's certainly steam limit constraints on the cyclic side. I think we just want to make sure that we've fully understood the pilot results. They do look good on the steam flood. I would say, at this time, we just want to make sure we're focused on the SAGD solvent side of things. We'll continue to run this pilot at Primrose. We'll continue to add pads at Primrose. And we would look at it as an opportunity for sure. It's going to lag behind the SAGD side a bit though, Dennis, just in terms of really where we believe our focus should be.

Great. I appreciate that color. Maybe switching gears towards the mining side of things. You've moved forward with -- or you're now completing the more recent kind of strategic capital deployment for Horizon, and you've kind of talked towards kind of this medium opportunity in terms of the [ Naphtha ] Recovery Unit. And I know you're in the middle of the IPEP and kind of scale up opportunity here as well. At what point would you feel more comfortable moving forward with kind of the longer-term potential expansions around Horizon? We do have a little bit more egress, but what are some of the other, we'll call it, key metrics or items that you're looking forward to gain greater confidence in maybe making a decision around that project?

Yes. So a couple of things with that, Dennis. Our teams have been working on expansion opportunities for the long term. We're looking in and around that 195,000 barrels a day opportunity. What's key to all of it is two fronts. One is we need to ensure that we have a carbon policy in place. And with that, we're looking towards the Pathways project and having the alignment on a fiscal policy that works for the Pathways company in collaboration with Alberta and the Canadian government. So that fiscal policy is absolutely key for us to be able to move any additional expansion volumes forward. And also what's important in terms of that would be securing and working on enhancing egress capacity as well out of the basin.

Your next question is from Mike Dunn from Stifel.

Just following up on that on the longer-term expansions at Horizon. Perhaps I've missed it previously, but looking back to your prior disclosures, is this the first time you've outlined 195,000 barrels a day as the potential expansion at Horizon from PFT and IPEP? I believe the last number you guys were giving for a while anyway was 75,000. So just wondering what's changed there and whether or not to move forward with such an expansion, you'd be just using your Horizon barrels or some of the AOSP leases furthermore?

So your research is 100% correct, Mike. And this is the first time we talked about the 195,000. Previously, it was 75,000. Really, what's evolved out of this is the teams continue to work through this is the scalability side of it and working with -- through engineering enhancements on the IPEP project for extraction and just increasing the sizability of the Froth Treatment. That's what's led us towards the 195,000 barrels a day. And yes, it's primarily related to the Horizon operations piece of it there. So yes...

[Operator Instructions] Your next question is from Neil Mehta from Goldman Sachs.

My first question is just on the natural gas environment. Obviously, it's very soft right now in Western Canada and throughout North America. But I just love your perspective as you think about the natural gas side of the portfolio, recognizing that you're also a large consumer of it. But how do you see local prices playing out over time, especially as we work through the start-up of LNG Canada, which would hopefully improve local netbacks?

Yes, you bet. Great question. So as you pointed out, we are a large consumer of natural gas in our Oil Sands operation. So we've got about 1/3 of it AECO pricing, a 1/3 export and about 1/3 is for our Oil Sands operations. In terms of looking forward on the price side of things, of course, yes, with LNG Canada coming online, we're seeing strip movements in the $3 range. And I think what's also important to remember here as well is that a lot of the economics are on the Montney side, driven by liquids production. So that carries the strong most weight in terms of the economics there. So we do see price improvements as LNG Canada goes forward, and we'll look to capitalize on those opportunities as much as we possibly can with our balanced portfolio, ensuring that we are directing our capital towards the highest return projects.

And then [indiscernible] over the last 10 years has been systematically driving down your cost structure. And the question we often get asked is what's the low-hanging fruit at this point? I just love your perspective as you guys think about the next couple of years, what are structural cost reductions that you still see within the business? And can you help bucket them for us?

I think I would just say in general that for the most part, the cost reduction opportunities are going to come forward simply through our continuous improvement plans that we put in place with our teams. We challenge our teams to bring forward ideas, concepts and execute on those concepts on an annual basis, and we continue to do that year-over-year. And so really, I think that's all we've always looked at doing our business. It's making sure that we're focused on continuous improvement piece. You saw over time what we were able to achieve at Horizon with cost reduction running up into 2019. And so it's that same type of mentality across all of our business assets, whether it's on the natural gas side, heavy oil side, oil sands mining and thermal. We carry that concept to continuous improvement through. So I'm confident our teams are going to be able to continue to dig through and find opportunities to both decrease the cost, and optimize production was obviously helps the cost per barrel as well.

Are there any specific initiatives you're willing to speak to at this point? Or we'll see them as they come?

I think we'll see them as we come. I mean, if you think about the vastness of our operations and all the teams that we have working on in these areas, there is significant amount of work activity that they're looking at for continuous improvement. But I would say that when it gets down to the [ ground or low ] over the teams, they're small incremental cost savings opportunities. But of course, they all add up. We have our teams focused on saving dollars everywhere in operation. So it adds up everywhere.

There are no further questions at this time. Please proceed.

Thank you, operator, and thanks, everyone, for joining us this morning. If you have any follow-up questions, please give us a call. Have a great day.

Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect.