Good morning. We would like to welcome everyone to Canadian Natural's 2024 First Quarter Earnings Conference Call and Webcast. After the presentation, we will conduct a question-and-answer session. Instructions will be given at that time. 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 you 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 how, through our defined plan, effective and efficient operations, and strong execution, we're targeting 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. 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 pads, 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 the conventional, more shorter cycle growth activity rounds up in the second half of the year. We continue to find ways to be more effective and efficient, including optimizing our turnaround schedules. 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, when we skip a turnaround. Through early turnaround work in Q1 during the unplanned maintenance activities, we reduced the outage duration of the planned turnaround in Q2 from 30 - 28 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 de bottleneck project at 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, upgrading, optimization projects, including the Naphtha Recovery Treatment Project, which is targeted to add approximately 6,300 barrels per day, late 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, produced 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 first 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 CAD 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 2023, reflecting low natural field declines from this long life asset. Operating costs at Pelican were CAD 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 2023. Operating costs in our light crude oil and NGLs operations averaged CAD 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 about $1.27 per 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 CAD 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 2024. Due to the early completion of the turnaround at 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 two 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 two 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 to full production capacity in Q4 of 2024. This will support continued high utilization rates at the Jackfish facilities. 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 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%-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 target for the first quarter, reflecting both planned and unplanned maintenance activities, including the advancement of the Scotford Upgrader planned turnaround from April to March. Through improved turnaround and commissioning, scheduling, as well as optimization efforts, we are targeting to recover these daily production volumes in the last three quarters of the year. Our operating costs in our oil sands mining and upgrading assets are top tier, averaging CAD 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. 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 nine months of this year. Now, I will turn it over to Mark for a financial review. Thanks, Scott, and good morning, everyone. In the first quarter of 2024, we generated solid financial results with adjusted funds flow of CAD 3.1 billion and adjusted net earnings from operations of CAD 1.5 billion. This drove significant returns to shareholders in the quarter, totaling CAD 1.7 billion, with CAD 1.1 billion in dividends and CAD 600 million in share buybacks through our NCIB program. As we reached net debt of CAD 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 will continue to manage the allocation on a forward-looking annual basis. Our commitment to increasing shareholder returns is evident and our sustainable and growing quarterly dividend, which was previously increased to CAD 1.05 per share from CAD 1.00 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 CAD 1.05 per share, payable on July 5, 2024. Our financial position is very strong, with debt to EBITDA at 0.6 times at the end of Q1 2024, 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 CAD 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 results in increasing share 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. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. If you have a question, please press the star followed by the one on your telephone. You will hear a prompt that your hand has been raised. Questions will be taken in the order received. If you wish to cancel your request, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question is from Menno Hulshof from TD Cowen. Please ask your question. Thanks, and good morning, everyone. I'll start with a question on the 55,000 barrels per day of additional commitments that you made on Flanagan South in the quarter. Can you elaborate on how that became available and 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 other companies have done? Thank you. Good question. And thanks for that. Yeah, the opportunity on Flanagan to gain the additional 55,000 barrels just came through an open season process. We participated in that process. Yeah, 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 expanding markets and, you know. 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 gonna create optional additional egress opportunities. Terrific. Thanks for that, Scott. And then my second question relates to the shift from natural gas activity into, into heavies onto your end. You talked about 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. Yeah. On the oil side, it's a reduction of about six 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, you know, some of the net backs we're gonna be seeing in the second half of the year on our oil side. Thanks again. I'll turn it back. Thank you. Your next question is from Greg Pardy, from RBC Capital Markets. Please ask your question. Yeah, thanks. Good morning. Thanks for the rundown, guys. Really two very different questions, but Scott, I'm, I'm continue to be kind of intrigued on what you're doing with, with solvents, and I'm wondering if you could perhaps frame the commercial scale project you have now. How are you-- I don't really know what the size of it is ultimately gonna look like, but is it possible to-- for you to speak maybe to what, you know, the capital efficiency and/or operating costs might look like with that project, or is that really to come? Yeah, Greg, good question. And for sure, some of that is still to come as this project is set up on a, 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 field facilities, and really, once we start injecting solvent here in July, we're gonna monitor the process. We wanna 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 it enough runtime to fully understand the cycle from a solvent perspective. But essentially, what it does allow you to do is, as I mentioned before, is reduce 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. Yeah, good, good... It'll be good to follow up on that, I guess, later in the year and I guess even into next year. And then the second one, obviously, TMX is, you know, is in focus. Could you maybe just comment on, on how your-- well, to the extent you want to, just on how your marketing will look, whether you've, you know, already secured tankers? I mean, I, I'd be very interested as to whether those are, you know, are destined for California or they're going to Asia or what have you. There was some press sounding, suggesting, you know, limitations on pilots and so forth in the area, but just any, any color there would be great. ... Sure. Yeah, 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, you know, some of that, Greg, as you pointed out, may end up going marine side still onto the West Coast, or it could move to Asian markets. Okay, thanks again. Thank you once again. If you wish to ask a question, please press star one. Your next question is from Dennis Fong from CIBC World Markets. Please ask your question. Hi, good morning, and thanks for taking my questions. 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 have 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? Yeah, 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. You know, leverage that towards, you know, understanding the processability on the solvent side at Primrose. And yeah, as you noted out, there's certainly steam limit constraints on the cyclic side. You know, 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 gonna 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 for to gain greater confidence in making a decision around that project? Yeah. So a couple things with that, Dennis. Our teams have been working on, you know, 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. Great, thanks. Appreciate that color as well. I'll turn it back. Thank you. Your next question is from Mike Dunn from Stifel. Please ask your question. Good morning. Thanks for taking my question. Just following up on that, on the longer-term expansions at Horizon. Perhaps I've missed it previously, but it's looking back through 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 further north? Thanks. Yeah. So your research is 100% correct, Mike, and this is the first time we've talked about the 195,000. Previously, it was 75,000. Really, what's evolved out of this as the teams continue to work through this is the scalability side of it. And you know, working through engineering enhancements on the IPEP project for extraction and just increasing the scalability of the froth treatment. That's what's led us towards the 195,000 barrels per day. And yeah, it's primarily related to the Horizon operations piece of it there, so yeah. Okay, that's all for me. I appreciate the answer. Thank you. Once again, please press star one should you wish to ask a question. Your next question is from Neil Mehta from Goldman Sachs. Please ask your question. Hello, Neil, your line is now open. Anyone there? Yes, go ahead. Oh, okay, great. Terrific. I'm not sure what happened there. Okay, 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 you know, the startup of LNG Canada, which would hopefully improve local netbacks? Yeah, you bet. A great question. So as you pointed out, we are a large consumer of natural gas in our oil sands operations, so we've got about a third of it, AECO pricing, a third export, and about a third is for our oil sands operations. In terms of looking forward and 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, you know, a lot of the economics are on the Montney side, are driven by the 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, team, one of the hallmarks of CNQ over the last ten 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? 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 gonna come forward simply through our continuous improvement plans that we've 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. 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, you know, go running up into 2019. 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 of continuous improvement through. So I'm confident our teams are gonna be able to continue to dig through and find opportunities to both decrease the cost and optimize the production, which obviously helps 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 they come. I mean, if you think about the vastness of our operations and all the teams that we have working on these in these areas, there's 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 level, the teams, they're small, incremental cost savings opportunities, but of course, they, they all add up. We have our teams focused on saving dollars everywhere in our operations, so it adds up everywhere. Perfect. Thanks, team. Thank you. There are no further questions at this time. Please proceed. Thank you, operator. 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.