Good morning. We would like to welcome everyone to the Canadian Natural Resources 2023 First Quarter Earnings Conference Call and Webcast. After the presentation, we’ll conduct a question-and-answer session, and instruction will be given at that time. Please note that this call is being recorded today May 4, 2023 at 8:00 a.m. Mountain Time. I would like to turn your meeting over to your host for today's call, Lance Casson, Manager of Investor Relations. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to Canadian Natural's first quarter 2023 earnings conference call. As always, 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 our reserves and production before royalties. Additionally, I would suggest you review our comments on non-GAAP disclosures in our financial statements. With me this morning is Tim McKay, our President; and Mark Stainthorpe, our Chief Financial Officer. Tim will first speak to how Canadian Natural is a leader on environmental, social and governance, followed by specifics on our safe, reliable, world-class operations, including details on targeted production growth from our long life low decline assets to generate strong returns on capital and maximize shareholder value. Mark will then summarize our solid financial results, including significant returns to shareholders so far this year and our strong finance position. To close, Tim will summarize our call prior to opening up the call for questions. With that, I'll turn it over to you, Tim.

Good morning, everyone. In the first quarter, we achieved strong quarterly production of approximately 1.32 million BOEs per day including record natural gas production at approximately 2.14 Bcf per day and liquids productions of approximately 963,000 barrels a day, reflecting strong operational performance across our assets, including our long life, zero-decline well and mining upgrading assets, comprising approximately 50% of the total company's liquids production this quarter. Our high-value SCO captured approximately a $2 premium to WTI in the quarter, driving strong SCO pricing and generating significant free cash for the company. Canadian Natural is the leader in environmental, social governance and has made it a priority to our collaborative with industry peers and governments to achieve meaningful GHG emission reduction in support of both Alberta and Canada's chronicles. The Alberta government's recently announced emission reduction and energy development plan built upon the province long-standing climate leadership and achievements and emissions reduction. We look forward to supporting the province and continuing to provide affordable, reliable, responsibly produced energy, while reducing emissions and aspiring towards a net-zero economy in 2050. Canadian Natural's current GHG goals support Alberta's client plan where large-scale carbon capture and storage projects like pathways have a significant role in reducing GHG emissions. Moving to the assets. I'll now do a brief overview. Overall, in Q1 2023, natural gas production was approximately 2.14 Bcf, which was a record for the company, a 7% increase over Q1 2022. For North American operations, Q1 2023, natural gas production was strong at approximately 2.13 Bcf per day, an increase of approximately 139 million cubic feet over Q1 2022, primarily as a result of the company's strategic decision to invest in our drill-to-fill strategy, adding low-cost, high-value liquids-rich natural gas production volumes. During the quarter, the company drilled 21 net wells, of which 19 were brought on in the quarter, meeting targeted rates. As well during the quarter, our third party pipeline impacted both natural gas by about 33 million a day and associated liquids of approximately 3,500 barrels per day. For Q1, North American natural gas operating cost was $1.43, which is up 12% compared to Q1 2022 of $1.28. Our teams continue to focus on operational excellence and cost control. Our North American light oil and NGLs Q1 production was 108,531 barrels per day, comparable to Q1 2022, primarily a result of strong drilling results. Q1 operating costs were $18.62 per barrel, up from Q1 2022 operating cost of $15.24 per barrel, primarily due to increased power and service costs in the quarter. During the quarter, we drilled 16 net wells as part of our light oil development plan, which targeted to come on production in both Q2 and Q3 of this year. At Wembley, the company finished drilling a five well light oil -- a 5-well light oil pad late in Q1, which is targeted to come on May 15, with initial production rates of approximately 4,000 barrels a day of liquids and 14 million cubic feet per day of natural gas. This pad is part of the company's budgeted 11 well program in the greater Wembley area. Our international assets in Q1 2023 had oil production of 27,331 barrels a day, which is down from Q1 2022 levels of approximately 31,000 barrels a day, primarily due to the decline in maintenance in North Sea and Offshore Africa. International assets continue to generate good free cash flow and value for the company. Moving to heavy oil, production was 77,690 barrels a day in Q1 2023, up 23% from Q1 2022, primarily due to strong drilling results in 2022. Operating costs in Q1 2023 were $21.47 per barrel comparable to our Q1 2022 operating cost of $22 per barrel. During the quarter, the company drilled 42 net heavy oil wells, of which 26 wells were multilateral wells across our land base from Bonnyville, Lloydminster to the Clearwater area with production results on target and budget. A key component of our long-life, low-decline assets is our world-class Pelican pool, where our leading-edge polymer flood continues to deliver significant value. Q1 production was 48,244 barrels a day, down 7% and Q1 2022 average of 51,991 barrels a day, reflecting the decline nature of the property. Polymer injection rates were reinstated in February 2023, and the field is targeted to return to its historical decline rate of approximately 5% in the second half of 2023. The team continues to focus on mitigating cost pressures and we had a good Q1 2023 operating cost of $9.63 per barrel, an increase from our Q2 2022 operating cost of $748 per barrel, primarily due to high power costs in the quarter. With our low decline and very low operating cost, Pelican Lake continues to have excellent netbacks. In our thermal in situ operations in Q1, we continue to leverage our continuous improvement culture and our expertise to deliver effective and efficient operations. Q1 2023 production was 242,884 barrels a day, down from Q1 production -- Q1 2022 production of 261,743 barrels as forecasted as a result of natural decline. Q1 2023 operating costs were $15.94 per barrel upwards comparing to Q1 2022 operating costs of $14.35 per barrel, primarily a result of higher power costs and service costs, offset by lower natural gas costs. I'll now update on our thermal growth plan. At Primrose, the company is targeting to grow production by approximately 25,000 barrels a day from Q4 2022 to Q4 2023 levels, primarily from its results of the two CCS pads drilled in 2022. The first production cycle from these pads is targeted to begin in Q3 2023, which targets strong quarterly production at Primrose of approximately 100,000 barrels a day in the fourth quarter of this year. At Kirby, the company is targeting to grow production by approximately 15,000 barrels a day from Q4 2022 levels to approximately 65,000 barrels a day in Q4 2023 as the company progressed its development of four SAGD paths in 2023. Production from the first pad drilled in 2022 as targeted ramp-up full production capacity in Q3 2023. The three remaining pads are targeted to round up to full production cuts over the first nine months of 2024 at a pace of one pad per quarter. At Jackfish, the production has been very strong, averaging approximately 115,000 barrels a day with minimal capital since acquiring the asset, representing its long-life motto decline nature. The company is currently drilling two SAGD pads. Production from these pads is targeted to ramp up to full production capacities in Q3 of 2024 and Q4 of 2024, respectively supporting our continued high utilization at that facility. Subsequent to the quarter end, the company commenced planned turnarounds of Primrose East and Wolf Lake, which targets to impact Q2 2023 production from by approximately 15,000 barrels a day and are reflected in the company's previous announced annual production guidance. The thermal and so production is targeted to increase in the second half of 2023 into 2024 and with new pads that were drilled in 2022 and pads targeted to finish drilling in the first half of 2023. Production is targeted to grow by approximately 30,000 barrels a day from Q4 to -- Q4 2022 to Q4 2023, averaging approximately 280,000 barrels a day. And with the strip of WCS differential tightening this could add incremental cash flow. In the company's world-class oil sands mining and upgrading assets, we had a Q1 production of approximately exactly 4,228 barrels a day of SCO with Q1 2023 operating costs that were $25.06 per barrel. During the quarter, SCO prices were strong, resulting in premium pricing for SCO at approximately US$2 per barrel above WTI adding additional cash flows. Subsequent to Q1 2023, as previously announced, the planned turnaround activities on the non-operated stocker began April 10, with the mines targeted to operate at reduced rates for approximately 73 days impacting the 2023 annual production by approximately 8,300 barrels a day. For Horizon, the plant turnaround is targeted to begin May 16 with a full plant outage, targeting for approximately 28 days impacting the 2023 annual production by approximately 21,600 barrels a day. At Horizon, the 14.4 [ph] reliability enhancement project is progressing as planned and tie-ins are targeted to be complete during the turnaround. This project targets to extend major turnaround maintenance cycles from one per year to one every second year, increasing SCO production capacity by approximately 5,000 barrels a day in 2023, increasing to approximately 14,000 barrels a day in 2025. I will now turn it over to Mark for a financial review.

Thanks, Tim. In the first quarter of 2023, we generated solid financial results with adjusted funds flow of CAD 3.4 billion and adjusted net earnings from operations of CAD 1.9 billion. This drove material free cash flow in the quarter of CAD 1.4 billion after dividends and base capital. Balanced allocation to our four pillars continues, including significant returns to shareholders in the quarter and year-to-date up to including May 3, 2023, year-to-date returns to shareholders totaled CAD 2.8 billion, including CAD 1.9 billion in dividends and CAD 0.9 billion in share repurchases. Our commitment to increasing shareholder returns is evident in our sustainable and growing quarterly dividend, which was increased to CAD 0.90 per share from CAD 0.85 per share in March 2023 and marking 2023 as the 23rd consecutive year of dividend increases. Subsequent to quarter end, the Board has declared a quarterly dividend of CAD 0.90 per share payable on July 5, 2023. As debt levels have decreased significantly over the last few years, returns to shareholders are targeted to increase in the near term as our free cash flow allocation policy states that once net debt reaches that CAD 10 billion level, a 100% of free cash flow will be allocated to shareholder returns. We are in a very strong financial position with debt to EBITDA at 0.5 times at the end of Q1 2023, and we continue to maintain strong liquidity. Including revolving bank facilities, cash and short-term investments, liquidity at the end of Q1 2023 was approximately CAD 6.1 billion. At Canadian Natural, we have several competitive advantages, including our diverse long-life low decline production, supported by our large high-value reserves and effective and efficient operations. This, combined with our people, culture, and commitment to continuous improvement targets to continue to drive material free cash flow and strong returns on capital going forward. With that, I'll turn it back to you, Tim, for some final comments.

Canadian Natural's advantage is our ability to effectively allocate cash flow to our four pillars, and we have a well-balanced, diverse, large asset base with a significant portion long-life, low-decline assets, which require less maintenance capital to maintain volumes. We will continue to allocate cash flow to our four pillars in a disciplined manner to maximize value for our shareholders which all is driven by effective capital allocation, effective and efficient operations and by our teams who deliver top-tier run. We have a robust, sustainable free cash flow. And through our free cash flow allocation policy returns to shareholders are significant. Our dividend was increased by 13% in March marking 2023 as the 23rd year of consecutive increases and has a CAGR of approximately 21% over that time. In summary, we will continue to focus on safe, reliable operations, enhancing our top-tier operations and will continue to drive environmental performance. We're in a strong position and being nimble enhances our capacity to create value for our shareholders. We will continue to apply the same drive to ESG governance social and environment, a significant factor in our long-term sustainability. As we move forward to lower our carbon emissions, with our first target to reduce our absolute Scope 1 and Scope 2 emissions by 40% by 2035 from our 2020 baseline on our journey to achieve our goal of net GHG in the oil sands by 2050. Canadian Natural is delivering top-tier free cash flow generation, which is unique, sustainable, robust and clearly demonstrates our ability to both economically grow the business and deliver returns to shareholders by balancing our four pillars. With that, I will open the call to questions.

Thank you. [Operator Instructions] Your first question comes from Greg Pardy from RBC Capital Markets. Please go ahead.

Yes, thanks. Good morning. Thanks for the run down. Tim, how does the -- how does your D&C program look in the second half, just given the movement in commodity prices beyond the all the thermal that feels like it's very much in motion right now. And I'm thinking more about just generally shorter cycle time heavies versus drilling gas?

Yes. Good question, Greg. During this period here, we started to just relook at the forward pricing on both gas and oil. And in the original plan, we had a very balanced program, approximately 10 rigs for -- really for the rest of the year. So to me, it will be a question of the value that each commodity can create here over the next kind of short cycle. So intuitively, I would suspect that from a capital allocation point of view, gas will not compete relative to oil in the short-term. And so we may end up doing a few less gas wells and then doing a few more oil wells. But that's still to be determined. But just looking at the commodity prices today, that would -- that could be what we'll end up doing.

Okay. Understood. And then maybe just shifting gears, just for Mark, I mean, we're just getting the question, do you expect to get to the CAD10 billion net debt this year or just given the choppiness we're seeing in commodity prices, maybe that's more of a 2024 event?

Yes. I mean, Greg, as you know, it's going to depend on where commodity prices settle out here. So I don't think it's unrealistic to get there at the end of this year still. But if prices continue to decrease or stay low, then it may push out early. I think the message though early into 2024. I think the message though is to just remember that we're generating a lot of free cash flow now. So we're executing on the balanced approach to our four pillars, and then that does include, of course, some significant returns to shareholders today, just increasing as we get there, and it is in the near-term.

Okay. Thanks very much to both.

Thanks, Greg.

Your next question comes from Dennis Fong from CIBC. Please go ahead.

Hi, good morning and thanks for taking my questions. The first one, really, as you see Egress issues out of Western Canada alleviate including additional potential access to the West Coast, how do you look at your portfolio of assets and maybe even the geographic diversification of the production that you have, especially obviously, giving evolving fiscal frameworks as well as some of the focused capital allocation within Canada?

Well, if you're specifically talking to just the Egress, in the short-term, I would say it's very constructive for oil. So I believe that the tightening in the WCS differentials is in part a result of the Egress not having any Egress issue on the oil side. And then with TMX coming on, I believe that you'll keep it tight because those barrels have options to go off the West Coast or down to the Gulf Coast in the US. In terms of natural gas, with the maintenance that we see with TC Energy here over the summer here, it may be a little choppy and then strengthening towards the fourth quarter. Obviously, with the incremental drilling that's happened in Western Canada, it is putting some pressure on the Egress and as such, will put some pressure on the local pricing in the short-term.

Great. Great. Thanks. Maybe if we could shift a little bit more to Primrose and Wolf Lake. I appreciate the incremental color you gave in your prepared remarks. When we think about the ramp-up of production eventually from that region, how should we be thinking about operating costs, similar small ratio, GHG emission impact? And then I've got a second follow-up there on Primrose around solvent. Thanks.

Sure. So with the incremental production that we have, obviously, with the newer pads, your SORs will decrease. In a lot of these areas, we haven't drilled any SAGD pads or CCS wells for a number of years. So we'll see the SORs reduce. Obviously, production go up. And then intuitively, with lower SOR, you'll have lower operating costs. So that's usually the case. The one thing is the SAGD, when you start steaming, it takes some time to ramp-up and then plateaus giving you the lowest SOR at full ramp up. Whereas the see the cyclic types, your first cycle is your lowest SOR followed by second and third and fourth cycle progressively has a higher SOR. But in the short-term, when you're -- these wells were on stream, the SORs are very low and the operating costs are very good.

Great. Thanks. And my follow-up is just around potential deployment of solvent within Primrose as well. You're obviously seeing some encouraging results. How quickly could you convert some of the pilot information and some of the design there into kind of a broader, more commercial development at Primrose? Thanks.

Yes. That's a good question to Dennis. The -- so we are doing a commercial development at Kirby North, which is on the SAGD side. And so we're really actually just stepping into it. To me, it's all about making sure that our designs and the economics are there that support the solids. So SAGD side, we feel very comfortable. And what we would do is as we progressed that development. We do one pad at a time. So you can't -- because of the nature of the area, you can't do all or nothing in terms of development or your inflationary cost would be astronomical. Down at Primrose, once the pilot is complete, we'll make that assessment and then look to do – to expand that there. But it really is about stepping in making sure that we achieve the goals that we want to maximize returns.

Great. Thanks. I'll turn it back

Thank you.

Your next question comes from Neil Mehta from Goldman Sachs. Please go ahead.

Yes. Thanks so much. The first question is just, sort of, the M&A environment. To the extent the market choppiness continues. You guys have done a great job being countercyclical in picking up assets and recognizing you have no gaps in your portfolio, but do you see an opportunity to be proactive in countercyclical to the extent these conditions worsen?

Yeah. It's a really good question, Neil. And if you look at our track record, it's really been all about when we do an M&A, it's about how much value -- long-term value does that acquisition had. So, it's really not even about countercyclical. It's really about what value can we achieved through that acquisition. So that's really all I can say is, we're not in the market, but any acquisition we do. And you've seen it in the past is, how much incremental value? Does it create long-term for our shareholders?

Okay. That makes sense. The follow-up is just on some of the pipeline movements here and updates that have been pretty active in the last couple of weeks. So, the first one would be around the mainline. And do you think that the pending agreement has the potential to tighten up WCS differentials. And then, as it relates to TMX, any of the cost of runs here, how much of it do you see as being potentially pushed through on to the suppliers? Thank you.

Okay. Thanks, Neil. Two very good questions, first, on the Enbridge one, it's difficult to say. I think, what's positive is the parties have put together and agreed on a fair tolling agreement. So we'll see what that does. I think in just general, having more egress available is really the driving force before differentials. In terms of TMX, we're a committed shipper on there for 94,000 barrels a day and no different than Enbridge. You go through the process to make sure the cost and the toll piece is correct for that service. So it's to me, it's just no different than Enbridge, you have to step through that process to understand the cost and what is allocated to lead into the goals.

Make sense.

[Operator Instructions] Your next question comes from Menno Hulshof from TD Securities. Please go ahead.

Thanks and good morning everyone. I just have one question on IPEP, especially given some of the negative press on tailings ponds of late. Can we get an update on the time line for getting the demonstration plant up and running? And then realistically, when can we expect it to be deployed commercially? And then maybe you could also speak to whether you're fully committed to moving IPEP and PFT forward together at this stage.

Yeah. Those are good questions. Those are for IPEP, we'd still have to do another more commercial size demonstration path. So IPEP is a great opportunity. But from the work that we've been doing in the background, our engineers believe that if you were to do IPEP, then you would need to do really something else like paraffinic and actually do two items at the same time because it is a large cost to go that way. In terms of tailings, I mean, -- we have a very good program. We have a very robust group out there, making sure that our trialing are compliant. So, to me, it's -- as always, I mean, we're always looking for opportunities to continually improve our environmental performance, whether it's in water, tailings, GHG. And we have a great team of engineers and people working in our Technology Innovation group that are looking at all the opportunities that we can do to reduce our environmental footprint everywhere in the company. :: Thanks, Tim. That's all I had.

Presenters, there are no further questions at this time. Please proceed with your closing remarks.

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

Ladies and gentlemen, this concludes your conference call for today. We thank you for joining and ask that you may disconnect your lines. Thank you.