Canadian Natural Resources Ltd Q3 FY2022 Earnings Call

Good morning. We would like to welcome everyone to the Canadian Natural Resources 2022 Third 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 that this call is being recorded today, November 3, 2022 at 9:00 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, operator, good morning everyone, and welcome to Canadian Natural's Third Quarter 2022 Results Conference Call. Before we begin, I would 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 reported 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 highlights on our safe reliable operations that continue to drive long-term shareholder value. This will include an overview of activities in the quarter, including specifics on our world-class assets and operations. Mark will then provide an update on our strong financial results, including our robust financial position, free cash flow generation, and increasing shareholder returns. To close, Jim will summarize our call prior to opening up the line for questions. With that, I'll turn it over to you, Tim.

Thank you, Lance. Good morning, everyone. Our emphasis on cost management, our culture of continuous improvement, and our disciplined approach to capital allocation are yielding strong operational and financial outcomes. The capital program for 2022 remains at $4.9 billion, excluding acquisitions. In the third quarter, we achieved record production of approximately 1.34 million barrels of oil equivalent per day, with natural gas production reaching an all-time high of about 2.13 billion cubic feet per day, all benefiting from strong pricing that averaged $6.57 per thousand cubic feet due to our diversified sales strategy. We also recorded liquids production of about 983,700 barrels per day, showcasing excellent operational performance across our assets, particularly from our long-life oil sands mining and upgrading assets, which produced 487,553 barrels per day of synthetic crude oil, making up nearly 50% of our total liquids production for the quarter. Our higher-valued synthetic crude oil achieved a price premium of US$8.87 over West Texas Intermediate this quarter, leading to favorable pricing and significant free cash flow for the company. After the quarter ended, we reached a significant milestone with the Pathways Alliance on October 4, obtaining the right to further explore our CO2 injection hub, which allows us to move forward in our evaluation process. We are also advancing engagement with stakeholders and detailed engineering on our 400-kilometer trunk line designed to transport captured CO2 from the oil sands to the storage hub. We appreciate the ongoing support from the Alberta government as we collaborate on this ambitious greenhouse gas emissions reduction project. We also thank the federal government for its recent supportive statements regarding the role of the Canadian oil and gas sector in global energy security and its commitment to a competitive fiscal framework for carbon capture. These developments are crucial as we strive to meet the oil sands industry's goal of net zero greenhouse gas emissions by 2050, which will necessitate approximately $24 billion in investments from the industry and governments by 2030 for foundational carbon capture and other emission reduction initiatives. Moreover, due to Canadian Natural's effective operations and a favorable royalty and tax system in Canada, our payments to government are projected to be about $11 billion in 2022, an increase of around $6 billion or 120% compared to 2021. Our forecast for 2022 capital expenditures, at about $4.9 billion excluding acquisitions, signifies an increase of approximately $1.4 billion or 41% from last year as we responsively supply energy to meet global demand. Additionally, we have returned around $4.9 billion to shareholders through base and special dividends, reflecting a 127% increase or $2.8 billion over 2021. I will now provide a brief overview of our assets, beginning with natural gas. Overall, our Q3 natural gas production was approximately 2.13 billion cubic feet, which sets a record for the company, showing a slight rise compared to Q2. For our North American operations, Q3 natural gas production reached approximately 2.12 billion cubic feet, an improvement from Q2's 2.09 billion cubic feet, thanks to our strategic investments in our drill-to-fill strategy and opportunistic acquisitions. In Q3, operating costs for North American natural gas averaged $1.13 per thousand cubic feet, down 2% from Q2’s $15, reflecting effective operational performance. Highlights from our operations include a six-well pad at Nig which came online in Q3, achieving strong capital efficiency of around $2,700 per barrel of oil equivalent per day, with October's production averaging 55 million cubic feet of natural gas and 3,200 barrels of liquids, surpassing budgeted rates. Additionally, a two-well pad at Townsend started production in July, also showing strong output with October production averaging 20 million cubic feet of natural gas. In terms of North American light oil and NGL, Q3 production averaged 109,255 barrels a day, consistent with Q2, largely due to robust drilling results and prior acquisitions. Q3 operating costs were $16.68 per barrel, which is a 10% increase from Q2’s $15.19 due to rising power costs. Our drilling initiatives continue to yield promising results; for example, a three-well pad at Wembley began production in July at a capital efficiency of approximately $6,000 per barrel of oil equivalent per day, with October production averaging over 2,000 barrels a day of liquids and 7 million cubic feet of natural gas. At Gold Creek, a two-well pad that came online in September demonstrated strong performance as well, with October production averaging about 2,100 barrels a day of liquids and 16 million cubic feet of natural gas. In our international operations, we had oil production of 24,493 barrels a day in Q3, down from Q2's 25,907 barrels primarily due to maintenance activities in the North Sea and offshore Africa. Our international assets continue to produce valuable free cash flow. Regarding heavy oil, Q3 production climbed to 68,933 barrels a day, a 4% increase from Q2, driven by strong drilling outcomes. Operating costs eased to $21.30 per barrel compared to $22.86 in Q2, mainly due to reduced natural gas fuel costs, even as trucking costs rose. Canadian Natural holds a significant land position in Clearwater with approximately 940,000 net acres, having drilled 14 net multilateral Clearwater wells in the Smith area during Q3, bringing the total for 2022 to 33 net wells. Our Clearwater production averaged about 12,300 barrels a day in September, reflecting an increase of 8,400 barrels since the beginning of the year. A vital component of our low-decline assets is the Pelican Lake pool, where advanced polymer flooding is generating substantial value; Q3 production was 50,051 barrels, slightly down from Q2's average of 51,112 barrels, illustrating the pool's low decline characteristics. The team is focused on managing cost pressures, achieving strong Q3 operating costs of $8.89 per barrel, up from $7.99 in Q2, mainly due to higher pilot costs. In our thermal in situ operations, we leveraged our continuous improvement culture to maintain efficient performance. Q3 production was 243,393 barrels a day, down from Q2's 249,938 barrels, largely due to planned maintenance at Jackfish. Q3 operating costs improved to $15.63 per barrel from Q2’s $18.93 mainly because of lower natural gas costs, despite higher power costs. At Kirby, we are on track with the three SAGD well development, aiming to initiate steaming of the first pad by Q1 2023 and ramping up to full production capacity by Q3 2023. At Primrose, the two CCS pads were drilled on schedule and within budget, and we anticipate initiating steaming and production in Q3 of 2023. In our world-class oil sands mining and upgrading operations, Q3 production averaged 487,553 barrels of synthetic crude oil, with operating costs remaining strong at $22.35 per barrel. Variations in production and operating costs compared to Q2 arose primarily from planned maintenance turnarounds at the Scotford and Horizon facilities. During this quarter, strong SCO prices resulted in premium pricing of $8.87 per barrel over WTI, contributing to additional free cash flow. After Q3, we experienced unplanned outages at both Horizon and Scotford in October, leading to a Q4 production target range of 450,000 to 460,000 barrels of SCO. Both facilities have since been restored to full capacity, and we are enhancing piping integrity and maintenance routines at Horizon for safe operations. The reliability enhancement project at Horizon is progressing well, aiming to extend major maintenance from once a year to every two years, which will boost SCO production capacity by about 5,000 barrels a day in 2023, increasing to around 14,000 barrels a day by 2025. Now, I will turn it over to Mark for a financial review.

Thanks, Tim and good morning everyone. Our third quarter financial results were very strong with effective and efficient operations driving adjusted funds flow of $5.2 billion and adjusted net earnings from operations of $3.5 billion, while our capital program for 2022 remains on track. Returns to shareholders have been significant and increasing throughout 2022, as we have returned year-to-date a total of approximately $10 billion to shareholders through $4.9 billion in dividends and $5 billion through share repurchases, equaling about 71 million shares repurchased year-to-date up to including November 2nd. Our dividend is growing and sustainable and is supported by our long life low decline assets, which deliver significant and sustainable free cash flow. Subsequent to quarter end, the Board of Directors has approved a 13% increase to our quarterly dividend to $0.85 per common share from $0.75 per common share. This represents the second dividend increase in 2022 and demonstrates the confidence that the Board has in the sustainability of our business model, the strength of our balance sheet, and the nature of our diverse long life low decline asset base. This continues the company's leading track record now with 23 consecutive years of dividend increases with a significant compound annual growth rate of 21% over that period of time. When compared to the beginning of 2021, our dividend has doubled to the current rate of $3.40 per share annually and has been sustainable through all cycles. This, of course, is in addition to the special dividend of $1.50 per share we paid in Q3. Our strong financial position continues to get stronger. Debt to EBITDA is at 0.5 times at Q3 with debt targeted to decline further throughout the year. As part of our financial strength, we continue to maintain strong liquidity including revolving bank facilities, cash, and short-term investments, liquidity at the end of Q3 was approximately $6.5 billion. Our disciplined approach to capital allocation maximizes shareholder value and our free cash flow allocation policy is unique and balanced, providing significant returns to shareholders and a strengthening balance sheet, all while continuing to grow our business. With that, I'll turn it back to you, Tim.

Thank you, Mark. Canadian Natural's advantage is our ability to effectively allocate cash flow to our four pillars. We have a well-balanced, diverse, large asset base, which a significant portion is long life, low decline assets, will require less maintenance capital to maintain volumes. We continue to allocate cash flow to our four pillars in a disciplined manner to maximize value for our shareholders, which is all driven by effective capital allocation, effective and efficient operations and by our teams who deliver top-tier results. We have a robust, sustainable free cash flow and through our free cash flow allocation policy returns to its shareholders are significant. Our dividend will increase by 13%, marking 2023 as our 23rd year of consecutive increases and has a CAGR of approximately 21% over that time. Year-to-date, Canadian Natural has returned approximately $10 billion to shareholders through approximately $4.9 billion in dividends and $5.1 million through share repurchases. In summary, we'll continue to focus on safe, reliable operations and enhancing our top-tier operations, and we will continue to drive our environmental performance. We were in a strong position and being nimble enhances our capacity to create value for our shareholders. We will continue to apply that same drive, GSG, environmental, social, and governance, a significant factor in our long-term sustainability. As we move forward to lower our carbon emissions across the asset base and our journey to achieve our goal of net zero GHG emissions in the oil sands by 2050. Canadian Natural is delivering top-tier free cash flow generation, which is unique, sustainable, and robust and clearly demonstrates our ability to both economically grow the business, deliver returns to shareholders by balancing our four pillars. With that, I will now open the call to questions.

Thank you. We will now begin the question-and-answer session. Your first question comes from Greg Pardy with RBC. Please go ahead.

Thanks for the update, everyone. Tim, could we discuss the two outages a bit more? It's reassuring that both plants are operating again, but it’s unusual for your company to experience two issues in a single quarter. Was there anything specific about these outages?

The primary issue we encountered was with Horizon, where the drain line of a coker charge pump experienced corrosion and erosion. Although we regularly change out these pumps, this particular risk wasn't identified beforehand, leading to a minor outage. Moving forward, we will enhance our preventive maintenance program by thoroughly inspecting the integrity of the drain lines to ensure reliable operations. Regarding the Scotford facility, which we do not operate, there was also a corrosion issue on a water line, but they managed to successfully implement a solution to stop the leak. The insights we gain from these experiences will not only benefit our operations at Horizon but also at Scotford. While it's unusual for us to experience such outages, we excel at learning from these situations to improve our processes. This instance was indeed rare and unique for us.

Understood. Thank you for that. My second question is about the pathways. What does the timeline look like for increasing spending in this area? There are obviously credits and potential additional incentives, but is the actual spending and installation of hardware expected to really happen between 2025 and 2030?

While the spending actually starts this year, there's a lot of environmental work involved. We aim to submit the regulatory pieces as soon as possible, ideally in 2023. Alongside this, we would want to place an order for the trunk line. Approximately 200 individuals across various companies are currently working on the project. Since we received everything just a month ago, there's a significant amount of work underway. As we begin to outline our plan, we will communicate it further. There is a lot of activity taking place right now, and we are striving to proceed as quickly and effectively as we can.

Okay. Thanks very much, Tim.

Thank you. Your next question comes from Dennis Fong with CIBC World Market. Please, go ahead.

Hi. Good morning and thanks for taking my questions. The first one is just on the solvent project that you have in your thermal in situ assets. The 50% or 40% to 45% depending on what timeline, I guess, reduction in GHG emission intensity is quite impressive. I was just curious as to what maybe some of the milestones or benchmarks you might have to further roll out the solvent program to other areas of Primrose, especially just given kind of some of the initial success that you're seeing there?

Yes. At Primrose, it's really just a matter of time. Everything is on track, and we believe it's functioning very well. We expect that by the fall of next year, we will have enough information to increase our operational scale commercially. This looks very promising, although it is still early in the process. Additionally, as you may remember, at Kirby, we will soon be implementing a commercial scale pad at Kirby North. There are currently no significant obstacles we can identify, but we need to ensure we fully understand the process, and as we transition to commercial scale operations, it continues to meet our expectations.

Just as a quick follow-up to that, are some of the build-outs for the deployment at a commercial scale already included in your existing sustaining or strategic capital, or would that require additional investment beyond what we have planned for this year?

The Kirby North is in our plan today. Obviously, if the PRIMROSE 1 works very well, then we'd look to modify our plan in the future. But, obviously, it isn't into our capital next year because we don't have the results of the pilot.

Great. Great. And then if you wouldn't mind, just a quick question on the Clearwater. You've seen frankly, very strong ramp-up of production there. I was just curious as to how we should be thinking about the production and infrastructure as well as the processing capabilities that you have within the region, obviously, being able to leverage off of Pelican is helpful. But just if you wouldn't mind providing a little bit more color on that side. Thanks.

Yes. There's really no showstoppers. Obviously, Pelican, we have ample capacity to handle the production and the gas handling is being directed to our calling gas plant, which has been in existing for many years. So there is no showstoppers to me, it's more about just following through with our development plans and delivering the production growth in the Clearwater.

Great. Thanks.

Yes. Thank you, Dennis.

Thank you. Your next question comes from Menno Hulshof with TD Securities. Please go ahead.

Thank you and good morning, everyone. Maybe I'll start with a follow-up to Dennis' Clearwater question. Would you be in a position to walk us through some of the details on well design, cost and IP rates based on the 33 wells you've drilled to date? And more generally, how is that play currently competing for capital?

It competes well from a capital perspective, with wells typically producing around 275 to 300 barrels per day. The drilling costs are favorable due to the tight multi-lateral area, allowing for cost control and learning as we continue drilling. Economically, it performs very well. It's crucial to manage the business in this area to prevent rising costs. Historically, during our heavy oil projects, we saw costs escalate quickly. Therefore, maintaining a steady pace of development is essential to avoid increasing expenses. Currently, the costs are relatively low, estimated at around $2,000 to $2,500 per BOE. Overall, it competes extremely well within our portfolio.

Thanks for the detail, Tim. And then just moving on to the Horizon reliability enhancement project. And the goal there is, as you talked about, is to move that major turnaround interval from one to two years. It looks like you're getting at least some of the benefit of that next year since you're guiding to a 5,000 barrel per day capacity on synthetic, but maybe you can confirm whether that correct and how Horizon’s turnarounds are going to get staged from here on in. And then the final piece, a lot of questions, my apologies. But the final piece is whether or not the plan is to get the AOSP on that every second year track as well?

Okay. So the first question related to Horizon. So what's actually happening at Horizon is some of the equipment we installed this last year during the turnaround. And so that gives us a little bit of bump in terms of reliability and capacity into next year. And then what happens is when we do the second turnaround here at Horizon in 2023, additional equipment gets installed, and then basically commissioned and everything else there next year. So it's just doing it in a methodical way so that we see these increments happen. And then obviously, the reason why you see it in 2025, because that is when the year you actually would not do that turnaround. So it's just basically as we install the equipment, certain pieces are commissioned, and which get that benefit over time. As far as AOSP in terms of the upgraded there, what they do is similar, but different. What they do is they have two different pieces of equipment. They take one down one year. And then the second piece of the next year. And then I believe the third year, they have a full big outage. So we don't operate it. But historically, that's what we've kind of seen is that they do certain pieces every second year followed by a bigger turnaround outage.

Thanks, Tim. I'll turn it back.

Okay. Thank you.

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

Hi. Thanks for taking the time. This is Nicolette Slusser on for Neil Mehta. So just first on CapEx, is there any sort of additional commentary you can provide around next year's spend as we think about the higher cost environment and with incremental production growth? And then if we should be thinking about any upward revisions to maintenance capital?

Yes. For 2023, we're still going through our budgeting process. And so it's a little early there. But to your point, we are seeing still cost pressures productivity pressures. And so we're walking through that today. But I don't see any big showstoppers. I just think that as we get busier into next year and companies start to have a little more activity. There's pressures on productivity and pressures on costs. So – it's a little early to say, but I don't see any major differences from this year to next year, just those two items.

Okay. Thank you for that. And then on the gas side, I understand close to 40%, I think, is exported to markets outside of AECO. As you ramp gas volumes in the 2023 and 2025 time frame, how should we be thinking about the marketing side relative to the current sales mix?

Yeah. Our marketing team, obviously, we have longer-term plans of what we can do in terms of the natural gas market. So I would be at very similar to that going forward. Obviously, we are looking ahead. And I think you see it in our gas pricing that we are looking ahead in terms of whether it's outages, whether it's export capacity that's needed, we're always looking ahead for opportunities to diversify our sales portfolio. So I would potentially look at it along the same lines of what we have today, which is roughly 37%. But yeah, we're always looking ahead and we're always diversifying, and we're always looking ahead and we're always diversifying, and we're always making sure that we have a strategy for our natural gas.

Great. Thanks so much.

Yes.

Thank you. Your next question comes from John Royall with JPMorgan. Please go ahead.

Hey, guys. Good morning. Thanks for taking my question. Do you have any thoughts at this point on when you would expect to hit your $8 billion net debt for? I think you did kind of mathematically push it out this quarter just with the payment of the special dividend. How do you think about that decision between doing further incremental returns like you did with the special versus kind of working your way down to towards that floor level?

Hey, John, it's Mark here. Thanks for the question. Yes, when you think about the capital allocation, it's really a function of being balanced. And I think you've seen that with significant debt repayment, of course, dividends increasing on a base dividend as well as the special you mentioned. And then, of course, we have our significant share buyback program ongoing. So it's really more of a balanced approach on how we do that. And you're right, you push out the debt balance. So now when we were looking before, it was kind of Q4, Q1. But now, of course, with the special in Q3, that will push out later into next year. It really depends, of course, on your price forecasting. There's significant sensitivity some of those items. So it really depends on what you're thinking on price forecast.

Okay. Thank you. And then just another one on gas as such a large producer. Maybe you can speak to your view on the fundamentals in Canadian gas and prices going into 4Q and next year. Just any outlook you can share there?

We've noticed that some of the export capacity pieces have taken longer to come online. There is a lot of activity in the natural gas sector, and our results have been very positive. I believe other companies are experiencing similar success as well. This situation may exert some pressure depending on when certain expansion projects happen. I haven't yet seen the planned maintenance outages for next year, but increased gas supply—and the type of maintenance on the lines—could create some pressure on the AECO price for the upcoming year. It's hard to predict, but it seems that more gas will increase pressure on the system. Therefore, the timing of these expansions and additional volume increases is crucial.

That's very helpful. Thank you.

Okay.

Thank you. There are no further questions at this time. You may proceed.

Thank you, operator, and thank you to those who joined 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 participating. And ask that you please disconnect your lines.