Canadian Natural Resources Limited (CNQ) Q4 2022 Earnings Report, Transcript and Summary

Good morning. We would like to welcome everyone to the Canadian Natural Resources' 2022 Fourth Quarter and Year-End Earnings Conference Call and Webcast. [Operator Instructions] Please note that this call is being recorded today, March 2, 2023 at 9 AM 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.

Thank you, operator. Good morning, everyone, and welcome to Canadian Natural's fourth quarter and year-end 2022 earnings conference call. Before we begin, I'd like to remind you our forward-looking statements, and it should be noted that on our reporting disclosures everything is in Canadian dollars, unless otherwise stated and we 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, President; Trevor Cassidy, Chief Operating Officer, Commercial; and Mark Stainthorpe, our Chief Financial Officer. Tim will start off by speaking to the specifics of our safe, reliable, world-class operations that continue to drive long-term shareholder value. Next, Trevor will provide highlights of our growing high-value reserves. Then Mark will provide an update on our strong financial results, including our robust financial position, substantial shareholder returns and our free cash flow policy that we are enhancing today. To close, Tim 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. Canadian Natural delivered strong operational results in 2022, as we achieved record annual production of approximately 1.28 million BOEs per day, an increase of 4% over 2021 levels, which included approximately 933,000 barrels a day of liquid production and record annual natural gas production of approximately 2.1 Bcf per day. As a result of our diverse portfolio, which is supported by our robust long-life, low-decline assets, primarily in the Oil Sands Mining and thermal in situ combined with our capital discipline, we generated significant free cash flow. And as we continued balancing free cash flow to our four pillars of capital allocation maximizing value for our shareholders. In 2022, we exited with a net debt of approximately $10.5 billion. We returned approximately $10.5 billion to our shareholders, $5.6 billion in share repurchases and $4.9 billion in dividends. And today, we announced a further 6% increase in our dividend. In 2022, the company's total proved reserves increased by 6% to nearly 13.6 billion BOEs, this resulted in a 265% replacement of 2022 production, at an FD&A metric of $8.39 per BOE, including changes in further development costs. Notably, greater than 50% of the company's total proved reserves are high-value, zero-decline SCO. As we continue to progress our ESG initiative, deliver industry leading performance across the board, a significant factor in our long-term sustainability. In November 2022, we announced our new environmental GHG target to reduce Scope 1 and Scope 2 absolute emissions by 40% by 2035, as we leverage technology, innovation to reduce our environmental footprint while ensuring safe, reliable, effective and efficient operations. We are working collaborative through the Pathways Alliance to achieve our goal of net zero in the Oil Sands, equally as important is that we work together with both Federal and provincial governments to achieve climate goals in an economically sustainable manner. As well, Canadian Natural is an industry leader in abandonment and reclamation as we have abandoned over 3,000 wells in the last two years, each in the last two years. And at this pace, we could have abandon our current inventory of inactive wells in just 10 years. I will now do a brief overview of our assets, starting with natural gas. Overall, 2022 annual natural gas production was approximately 2.1 Bcf per day, which is a 23% increase over 2021 production levels. For North American operations, 2022 annual natural gas production was approximately 2.08 Bcf per day versus the 1.68 Bcf for 2021, up almost approximately 395 million cubic feet per day, primarily as a result of the company's strategic decision to invest in liquid-rich natural gas areas through our drill-to-fill strategy, adding low-cost, high-value, liquid-rich gas production as well as opportunistic acquisitions completed late 2021 and early 2022. On an annual basis, our 2022 North American natural gas operating cost was $1.19 per Mcf, an increase of 3% from 2021 of $1.15 per Mcf, primarily due to increased energy costs. For the fourth quarter of 2021, North American natural gas production was approximately 2.1 Bcf versus 1.84 for Q4 2021, with operating cost of $1.22 per Mcf versus $1.08 in 2021, once again, reflecting the higher cost of energy. Our teams continue to focus on operational excellence, and we had a successful natural gas drilling program, which included 50 net wells in Q4 2022, bringing the total natural gas wells drilled in the year to 72 net wells. For North American light oil and NGL the 2022 annual production was approximately 110,000 barrels a day, up 16% from 2021, primarily as a result of strong drilling results. Annual operating costs were strong at $15.91 per barrel versus 2021 operating costs of $15.28. Q4 production was 112,989 barrels per day, again, up 16% when comparing to Q4 2021, with quarterly operating costs of $16.47 per barrel as compared to Q4 '21 costs of $14.61 per barrel, again, primarily a result of higher energy costs. The company delivered strong execution and results in the high-value Montney light crude oil and Deep Basin developments in 2022. And as budgeted, a total of 32 net wells were brought on stream. For international assets in 2022 had an annual production of 27,233 barrels a day, a 14% decrease versus 2021 levels, primarily due to maintenance activities in the North Sea and natural field declines. Offshore annual production was 14,343 barrels per day versus 2021 of approximately 14,000 barrels with annual operating costs in 2022 of $17.25 per barrel versus 2021 at $14.73. In the North Sea, annual production averaged 12,890 barrels in 2022, down from the 2021 level of 17,633 barrels per day and an annual cost of approximately $89 per barrel. As a result, of the North Sea regulatory and economic conditions, including the impact of higher natural gas and carbon prices going forward, we're accelerating our plan for the COP and abandonment of the 2 Ninian platforms by four to five years earlier than originally envisioned. This follows the company's successful abandonment to the Ninian North platform using the single lift technology in 2022. Moving to heavy oil, the 2022 annual production was approximately 67,700 barrels a day in 2022, an increase of 5% versus 2021, reflecting strong drilling results, increased development activity offset by natural field decline. Annual operating costs were $21.84 per barrel versus the 2021 operating cost of $19.37 per barrel. Fourth quarter 2022 production was 72,161 barrels per day, primarily a result of strong drilling activity versus the Q4 2021 production of 64,866 barrels a day. Operating costs were $21.28 per barrel versus Q4 operating costs in 2021 of $19.72 per barrel, again impacted by higher energy costs. In 2022, the company drilled a total of 127 net horizontal multi-lat heavy oil wells, including 52 net wells at Smith in the Clearwater. The company's Clearwater production averaged approximately 13,000 BOEs per day in Q4 2022, up approximately 9,100 BOEs per day from the start of the year. A key component of our long life, low decline assets is a world-class Pelican Lake pool, where our leading-edge polymer flood continues to deliver significant value. The 2022 annual production was 50,333 barrels per day versus the 2021 average of 54,390 barrels per day, a 7% decline. The team continues to focus on operating costs with the annual operating costs of $8.36 per barrel, an increase from our 2021 operating cost of $6.75 per barrel, again, primarily a result of increased energy costs incurred during the year. Fourth quarter 2022 production was approximately 48,000 barrels a day, down 9% from the fourth quarter of 2021 of approximately 53,000 barrels a day. This primarily is a reflection of the temporary injection reduction in Q4 2022 and natural field declines. In February, injection rates have been fully restated and the polymer flood is expected to return to its historical low decline rate of approximately 5% in the second half of 2023. Operating costs in Q4 2022 were $9.14 per barrel versus Q4 2021 of $6.78 per barrel. With our low decline, low operating costs, Pelican Lake continues to have excellent netbacks. We had a good year in our thermal in situ operations in 2022 as we continued to leverage our continuous improvement culture and our expertise to deliver effective and efficient operations. In 2022, we had annual production of approximately 252,000 barrels a day versus 2021 levels of approximately 259,000 barrels a day. Thermal annual operating costs were $16.50 per barrel, up from 2021 levels of $12.14 per barrel, primarily as a result of increased energy costs. Q4 2022 production was strong at 253,188 barrels per day, down 4% from Q4 2021 levels, with operating costs of $17.20 per barrel, reflecting higher energy costs when compared to Q4 2021 of $13.08 per barrel. At Primrose, we finished drilling at two CSS pads in Q4 and we target to bring these pads on in early Q3 2023. At Kirby, the development of the four SAGD pads is on track. The first pad began steaming late December 2022 and targets to wrap up the full production capacity in Q3 2023, with the remaining three pads targeted for full ramp-up in 2024. At Jackfish, the company is currently drilling a SAGD pad, which is targeted to be its steam in early Q4 2023 with the ramp-up of full production capacity in 2024. As well, we are continuing to progress our engineering design of the commercial scale solvent SAGD development at Kirby North and target to commence solvent injection in early 2024. At Canadian Natural's world-class Oil Sands Mining and upgrading assets, we had an annual production averaging 425,945 barrels a day of SCO, a decrease of 5% from 2021 levels, primarily as a result of unplanned downtime at both Scotford and Horizon during the year. We had annual 2022 operating costs averaging $26.04 per barrel versus 2021 operating costs of $20.91 per barrel. The company continues to focus on high reliability, cost control as well as operational enhancements. At our Oil Sands Mining operations, we had production of 428,784 in the fourth quarter of 2022, with a fourth quarter operating costs of $25.48 per barrel of SCO. Our quarterly production was impacted as a result of the October unplanned maintenance at both Scotford and Horizon, which we talked to in our November Q3 2022 results. Then with the extreme cold weather in December, we had to complete multiple mining equipment repairs, resulting in the reduced rate at Horizon for both December 2022 and January 2023. This event is targeted to impact Q1 production by approximately 25,000 barrels a day. Production from the Oil Sands Mining and upgrading assets averaged approximately 483,000 barrels a day in February 2023. The reliability enhancement project at Horizon continues to progress well and is now targeted to be 45 days ahead, increasing SCO production capacity earlier than originally budgeted. The impact of this project was approximately 5,000 barrels a day on an annual basis for 2023, increasing to approximately 14,000 barrels a day in 2025. As a result of the advancement of the reliability project, and the reduced rates in Q1 and the thermal and Oil Sands Mining and upgrading 2023 production guidance remains unchanged. For the second quarter, both Scotford and Horizon will start their planned 2023 turnaround. Scotford targeted to start in April at reduced rates for 73 days and Horizon is targeted for a full shutdown in May for 28 days. I will now turn it over to Trevor for our 2022 reserves review.

Thank you, Tim, and good morning. Consistent with previous years, 100% of Canadian Natural's reserves are externally evaluated and reviewed by independent, qualified reserve evaluators. Our 2022 reserve disclosure is presented in accordance with Canadian reporting requirements, using forecasted commodity pricing and escalated costs. Canadian standards also require disclosure of reserves on a company working interest before royalty basis. As you just heard from Tim, Canadian Natural had another strong year, and the results are also demonstrated in Canadian Natural's reserves. Total proved and total proved plus probable reserves increased 6% to 13.6 billion BOE and 18 billion BOE, respectively. Of the 13.6 billion BOE of total proved reserves, 65% or 8.8 billion BOE are proved developed producing reserves. The strength and depth of Canadian Natural assets are evident as approximately 77% of total proved reserves are long-life, low-decline reserves. Again, it's also important to note that approximately half of Canadian Natural's total proved reserves are high value, no decline synthetic crude oil at 6.9 billion BOE. Also worth noting is that the company's total proved plus probable natural gas reserves increased 10% to 22.3 Tcf, the largest natural gas reserves in Canada. This provides Canadian Natural with top-tier, long, reserve life index of 32 years for total proved and 42 years for total proved plus probable. Findings and development costs and reserve replacements are key indicators of the strength of our assets. In 2022, Canadian Natural continued to achieve strong performance as reflected in our finding and development costs and reserve replacement metrics. The corporate finding, development and acquisition costs, including changes in future development costs, are $8.39 per BOE for total proved and $7.62 per BOE for total proved plus probable reserves. Canadian Natural replaced 2022 production by 265% for total proved and 334% for total proved plus probable reserves. The net present value of future net revenues before income taxes using a 10% discount rate and including the full company ARO, is approximately $151 billion for total proved reserves and approximately $184 billion for total proved plus probable reserves. In summary, these strong results reflect the strength and depth of Canadian Natural's asset base, the value of the company's long-life, low-decline reserves and our ability to execute and maximize value from our reserve base. Thank you. I'll now hand it over to Mark for financial highlights.

Thanks, Trevor, and good morning, everyone. Our fourth quarter financial results were strong and adjusted funds flow of $4.2 billion and adjusted net earnings from operations of $2.2 billion, driving full year 2022 adjusted funds flow of $19.8 billion and annual adjusted net earnings of $12.9 billion. Net earnings for 2022 were $10.9 billion, including a onetime noncash charge in Q4 of $651 million related to the acceleration of abandonment on two platforms in the North Sea. These strong financial results drove material free cash flow in 2022 as we balance our four pillars, including returns to shareholders. We returned a total of approximately $10.5 billion to shareholders through $4.9 billion in dividends and $5.6 billion through share repurchases, equaling about 77 million shares repurchased in 2022; while at the same time, reducing our net debt level by $3.4 billion. Subsequent to quarter end, the Board of Directors has approved a 6% increase to our quarterly dividend to $0.90 per common share from $0.85 per common share. This follows the two dividend increases totaling 45% 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 assets and high-value reserve 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. Our strong financial position continues to get stronger. Debt-to-adjusted EBITDA is up 0.5x at the end of 2022. We've reduced net debt by approximately $10.7 billion since the beginning of 2021, and we continue to maintain strong liquidity. Including revolving bank facilities, cash and short-term investments, liquidity at the end of 2022 was approximately $6.9 billion. As a result of this strong financial position and having a sustainable cash flow profile, particularly when you compare our debt levels to the size, diversity and long life, low decline nature of our high-value reserves, we have enhanced our free cash flow allocation policy. As the Board of Directors has confidence in the sustainability and resilience of the company to support accelerating incremental shareholder returns to a 100% of free cash flow when the company's net debt reaches $10 billion instead of the previous $8 billion net debt level. Once the company's net debt reaches $10 billion, the free cash flow allocation will be adjusted to define free cash flow as adjusted funds flow less dividends, less total capital expenditures. Based on strip prices today and taking into account the final 2022 tax installment in Q1, capital profile and our current shareholder return framework, including dividends and a significant share buyback program, we target to reach the $10 billion net debt level late this year. Our disciplined approach to capital allocation, our focus on a strong financial position and our effective and efficient business model is unique and drives material free cash flow. This provides significant returns to shareholders and long-term shareholder value. With that, I'll turn it over to you, Tim, for some final comments.

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, which require less capital to maintain volumes. We are balanced in our commodities. In 2022, approximately 44% of our BOEs, light crude oil and SCO; 29% heavy oil and 27% natural gas, which lessens our exposure to the volatility in any one commodity as we move through 2023. 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 by our teams who deliver top-tier results. We have a robust, sustainable free cash flow; and through our free cash flow allocation, returns to shareholders have been significant. For 2022, $4.9 billion in dividend and $5.6 billion in share repurchases for a total of $10.5 billion. And today, our dividend was increased by 6% for the 23rd consecutive year and has a CAGR of 21% -- approximately 21% over that time. In summary, we will continue to focus on safe, reliable operations, enhancing our top-tier operations and we'll continue to drive our environmental performance. We are in a strong position and being nimble enhances our capacity to create value for our shareholders. 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 and deliver returns to shareholders by balancing our four pillars. With that, I will now open the call for questions.

[Operator Instructions] Your first question comes from Greg Pardy with RBC Capital Markets.

Thanks for the rundown, guys. A couple of questions, maybe just on net debt and then unlocking the 100%. Does the broadened free cash flow definition include acquisitions and then, I guess, related to that, I'm just curious as to how close you are to the $10 billion, just given that, I think you've got just a little over $2 billion of cash taxes due this quarter?

Yes. Thanks, Greg. First off, M&A wouldn't impact the formula. So that answers your first question. And yes, I mentioned in my prepared remarks there that you're right, we have the final tax installment of course due in Q1 and then when you look at the capital profile and of course, our dividends and current share buyback program, which is significant based on the current free cash flow allocation, we target that net debt somewhere late this year.

Okay. Late '23?

Yes, correct.

Okay. Okay. Great. And then maybe just shifting gears a little bit related to Pathways, but we're certainly hearing a lot more from you guys as it relates to IPEP and solvents and so forth. Are those initiatives now being prioritized just given the Pathways initiative going on as well? I'm just curious.

Greg, it's Tim here. It's a good question. So really, for IPEP and that to go forward, you really need that gas conservation or the CO2 conservation or Pathways to be up and running. So at this time, the main focus is delivering on the Phase I program. So currently, we're drilling a couple of wells today, testing the formation, doing all that work. We're continuing with the engineering of the pipeline and as well as the gas collection system. So it's really a lot of work being done to that piece.

Your next question comes from Menno Hulshof from TD Securities.

I'll start with the Clearwater. It looks like production averaged 13,000 barrels a day in Q4 and just eyeballing things, you're targeting 17,000 to 18,000 barrels a day for 2023. Does that guidance still sound about right? Are there any interesting trends that are jumping out at Smith at the moment? And what could the Clearwater look like in 2024 with the uplift on market access through TMX?

Yes. I think you might be a little aggressive on the Smith piece there. What we're seeing is that we're -- as most times, you always find opportunities and challenges in terms of the development. And of course, we've always said that these developments are smaller in nature. You have to be very methodical in the development piece. And so while Smith is great, it's doing very well. As we move to the other Clearwater items, we'll have to take a wait and see on those results. So that's really all I can say. We're seeing that you need a fairly thick reservoir probably in the 5 meters to really make the economics. And -- but what we're seeing is on the heavy oil side towards Bonnyville, those ones are actually pretty well -- pretty competitive with Smith and some of the Clearwater plays just due to the access piece.

I'll just move on to the North Sea. It's clearly a very small part of the portfolio. Now you wrote off and citing an increasingly challenging commercial outlook, I think as I described it. In light of that and with one of your Canadian peers exiting the region entirely, how are you thinking about your remaining North Sea and Côte d'Ivoire assets within the portfolio longer term?

Yes. I mean the North Sea, I mean, we've always planned for COP and the abandonment to those platforms. If you recall, we have abandoned Murchison, we did Ninian North last year. So we're quite good at handling those -- that abandonment of these platforms. And so to me, it's just all part of managing your portfolio. Every field asset does have a life -- shelf life. So to me, we just continue on in the North Sea with that program. And really, it just gets smaller into there. Côte d'Ivoire and Baobab, Espoir, I mean they still have lots of opportunity here. We are planning another phase at both Espoir and Baobab. We're just doing the work there, and they will probably be executed into the next year. But no, those assets, they still got lots of life left and it's just a matter of doing it right.

Your next question comes from John Royall with JPMorgan.

So can you talk about your thought process of getting a little more aggressive on the returns of capital here and moving to the $10 billion floor versus the $8 billion before, and then also removing the lower down on the 80% to 100%? And then on timing, I think Mark had said twice that it would be late this year on achieving $10 billion. I think in the 3Q call, you had said late '23 to get to $8 billion. So I assume that's more just about the scrip coming down, but just sort of if there are any other moving pieces in that bridge.

John, it's Mark. I'll answer the second question first. It's largely related to commodity prices, so there's really nothing else that's going on there. But second, on your question just around the change in the policy and kind of timing of that today. Every quarter, our Board reviews our free cash flow policy, and we look at our financial position, we look at it against a lot of metrics to ensure we're doing the right things. With our debt level decreasing over $10 billion in the last couple of years, at the same time, we've been able to grow production and as Trevor talked about, increase our reserves. And Trevor mentioned it, remember that over 50% of the total proved reserves are high value, zero decline synthetic crude oil reserves, so a much more sustainable environment for free cash flow. So when you put all that together, the Board determined that now $10 billion remains a very conservative debt level and provides that sort of ample flexibility and liquidity. And you can couple that in with why it migrates now to just 100% of the free cash flow.

Great. And then sort of staying on the same lines, maybe you could speak a little bit about the definitional change for free cash flow available to distribute. And how -- and maybe just -- I'm trying to sort of understand how it -- recognizing we have some other moving pieces that we just talked about, how it might affect kind of future returns to shareholders if you just sort of isolated it. So how much gross CapEx do you expect to be in this business once you get sort of one over the other side of your current growth program?

In terms of capital?

I'm just -- I believe that's the major moving pieces between the definition before and today.

Yes, John, let me just -- like when you look at the change in the definition, you really have to think about it, it's really just a natural progression of the formula. If you're going to have net debt at $10 billion and 100% of free cash flow being returned to shareholders, then capital needs to be funded from the free cash flow distributions. Otherwise, you would always fluctuate up and down from the $10 billion. So it's really just a natural progression of how the formula needs to work.

Your next question comes from Doug Leggate from Bank of America.

John Abbott on for Doug Leggate. Our first question is, what are you seeing on gas? And will you maintain your gas growth projections? Or is there anything that would cause you to slow down growth?

Yes. There is -- as you're aware, there is a little bit of pressure on natural gas prices coming into the summer and maybe partly into next year. So we constantly continue to high-grade our opportunities. So while I don't see anything materially different, I do see that at the end of this year, we could end up doing a few less gas wells and a few more oil wells. So I would suspect that as we get into breakup here, we will view our go-forward plans and adjust accordingly to always continue to high-grade our opportunities.

Very helpful. And then for our second question is, what are you thinking about as far as how you see the potential acquisition and divestiture market at this period of time?

M&A, in my opinion, is there's a little bit disconnect between the buyer and sellers I think. I look too expensive in my opinion, to be in the market. And that's why we're focused on just organically growing on a dollar per BOE, we've been quite successful. And we have lots of running room in our inventory of assets. So therefore, it's a good time to sit back, work through our assets and develop our opportunities production cost effectively.

Your next question comes from Dennis Fong with CIBC World Markets.

The first one is just around leverage and term debt. I know the company obviously has a lot of available liquidity and the maturities have frankly already been pushed out given your, I guess, campaign of repurchasing kind of near-term notes. How should we be thinking about some of the medium- to longer-term term note structures as we go forward? And what do you think is maybe the appropriate capital mix or capital structure mix as we think about things going forward?

Dennis, it's Mark. Good question. It's -- when you look at our bonds outstanding today, we've got about $11.4 billion of Canadian equivalent bonds outstanding. And we build a maturity profile to make sure we have the opportunity to pay down absolute debt as we knew the free cash flow was coming. So you've seen that over the last couple of years, we've been able to pay down bonds and sometimes pay them early, as you pointed out. So we do have some maturities here at the end of this year. There's about $400 million remaining on our one Canadian bond and somewhere in the neighborhood of just over $800 million after the first half of next year. So that gives us the opportunity to potentially pay down that debt and get to a place where your bonds are in that $10 billion sort of neighborhood. So given the net debt sort of level that we're looking to achieve here, that kind of all goes around to make sense on how you build that capital structure.

Great. Great. I appreciate that answer. My next question is shifting gears more to the upside is at Primrose. I know at your Investor Day, you highlighted, we'll call it, the productive capability at that asset. How should we be thinking about the ability to get to those higher production levels? And how does that interrelate potentially to, we'll call it, positive data that you receive from your initial pilot on the solvent side of things? And then maybe what are the next steps after you kind of feel more comfortable with the data that you have?

Sure, yes. In the steam flood area of Primrose, as you're aware, we are doing that solvent pilot there. And yes, it does look encouraging. And so what it does for us is by lowering our steam demand, and let's just say our steam demand is roughly reduced by 50%, it frees up capacity to expand into more areas. So you can do more areas at the same time. So what that does, because we have the excess capacity available at Primrose, but we don't have the excess steam capacity, you can actually use that extra steam capacity that you make available to increase production. So it's just -- it's an opportunity, but we've got, I guess, a little more time before we go forward on it, but it does look very encouraging. And so hopefully, that answered your question, Dennis?

Your next question comes from Mike Dunn with Stifel FirstEnergy.

Just had a question about your operating costs, specifically with related to electricity in Western Canada here. Can you -- one of you gentlemen, maybe frame for me, maybe, Mark, maybe what the year-over-year impact was either 2022 versus 2021 on your electricity costs in Western Canada or even second half '22 versus first half '22?

Yes, Mike, I don't have those numbers in front of me. What I can say is -- as you're aware, it significantly changed over the year. And -- but I don't have those numbers available. I think you can follow up with Lance to get those, but I don't have our power prices in front of me today.

Okay. Maybe just a follow-up, but I know lots have come off here year-to-date versus Q4. Is that looking material to your OpEx in terms of a quarter-over-quarter change?

Yes. I wouldn't say it's all material, but similar to last year, as natural gas and power prices increased, we're seeing that same effect coming down in the first quarter. So power prices, to your point, have come off as well as natural gas. And they're somewhat interrelated, right? It will help us on the operating cost side going in so far this year.

Okay. Great. Yes. I think I have a good handle on your natural gas impact on OpEx, but I'll follow-up with Lance.

Your next question comes from Roger Read with Wells Fargo.

Maybe come back to the question about capital structure and maybe thinking about it from a standpoint of maybe a mid-cycle pricing. What's the right way to think about the capital structure and cash returns to shareholders? So what I'm trying to get at is, how did you really determine $10 billion is the right number, what are your base assumptions on commodity prices and the WCS differential? And how should we think about this on a not just sort of the immediate of '23, but maybe in a little longer time frame?

Roger, it's Mark. We think of it on a lot of different cases and make sure that we're evaluating it on different price points. And we do that to make sure things like our dividend is sustainable through all cycles. So when you look at a debt level of $10 billion, again with the company our size and the type of reserve base, and then you can look at history of like 2020, again, we talked about it today, but we were call it, $10.7 billion higher in debt and could manage through those lower commodity price cycles. So when you continue to evaluate what your debt levels look like against those metrics, as we continue to grow, you're able to actually sustain higher debt levels, but we feel it's the right place to be in a conservative spot like we are at about $10 billion. So we look at and evaluate capital structure and free cash flow and sustainability of things like our dividend at all different price points. As you recall, we have a very low breakeven given the low decline in age of our assets and low-cost structure.

Yes. I follow that. I guess I understand Tim's conservative when we look at certainly the history of the company and the industry, but what defines $10 billion is conservative in your mind? And I'll just say, as opposed to, say, $5 billion or $15 billion, like what -- what is -- is it strictly the dependability of the dividend in kind of all price scenarios? Or is there some other component involved?

Well, I think there's several components involved. Again, one is making sure that the dividend is sustainable through those cycles. So your debt level needs to be able to be managed through those cycles. And as I've mentioned before, I think this is just a very conservative approach at this time. And we've come out of lower commodity prices in 2020 and to be conservative is, I think, the right place to be at this stage. And it still generates significant free cash flow returns to shareholders right now on the 50-50 split. And obviously, that's getting enhanced and augmented as we come into late 2023.

Okay. And then just a final follow-up. I'm fine with share repurchases as a use of cash, but when you look at base dividend, share repurchases, other alternatives, variable dividends, something like that, what's the evaluation process there that leads you more towards, I'm going to assume, share repurchases over other options?

Well, we look at a lot of factors, and Trevor mentioned it in his prepared remarks. If you look at net asset value, intrinsic value, you can look at it on a historical multiple basis, we feel buying back shares as a very good opportunity right now.

Your next question comes from Greg Pardy with RBC Capital Markets.

Mark, at the risk of frustrating with my question, I just want to make sure I understand things that a few other people ask me at the same time. So should we think about once you hit that $10 billion level of net debt that effectively thereafter, it's kind of a new world where you're at this 100% payout? And the reason I ask is that if acquisitions aren't included in the free cash flow generation definition, but they include net debt, then I'm just wondering how do you avoid hip hopping back and forth between that level? How should I think about that?

Well, you should think about it is that we're driving down to $10 billion in net debt, so we'll go to 100% free cash flow going to shareholders. I suppose down the line if there's an acquisition, and Tim mentioned that that's not really something right now, but if there is, then your net debt goes up, then you will revert back to the 50-50 threshold until you get back to $10 billion, that's how you should think of it.

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

I had a couple of macro follow-up questions. The first is around Pathways. I know you've got a lot of people dedicated to this project. Just give us a lay of the land, what are the gating factors to get to FID? And what's your best guess on when we get the project at final investment decision?

Yes. That's a good question. Obviously, we need to make sure it all makes sense. And part of that is making sure that we have the provincial government and federal government and industry working together in terms of a structure for carbon capture. Obviously, it's a big undertaking. It's a big cost. And with the big cost, you want certainty on the rules and -- as well as the financial structure of how to do it. And so I think that's probably the #1 item going forward. In the meantime, we're drilling the wells. We're doing the engineering. We're doing all the land work, the EIAs to progress that project. So there's -- to date, there's been no showstoppers. But obviously, as you saw in the U.S. with the Inflation Reduction Act, they moved ahead of Canada. And part of it is, you have to have a competitive financial structure here in Canada that competes against other jurisdictions. So it's -- to me, I am encouraged with the developments that we're seeing federally and provincially, that we'll be able to have something that works for industries in terms of carbon capture going forward.

Okay. All right. We'll look for more clarity there. And then on WCS differentials, they blew out at the beginning of the year, late last year, and they've come in. I'd be curious on your view on the trajectory of WCS from here. And maybe talk -- and tie in your views on TMX because that will matter for '24 in theory?

Sure. I mean with the WCS differentials, I think in our last call there, we said that there is pressure on the WCS widening in the short term. Part of it was seasonal. Part of it was natural gas prices and part of it was the [SBR] reserve piece coming to market. Since that time, as we also indicated then, we had seen tightening coming into 2023. We -- that has proved to be correct. Obviously, natural gas prices have reduced. The [SBRs] are looking and stopped and potentially go back into injection. And the product is on demand. You're going to see some oil, let's say, Mexico, go to its own refineries. So I feel it's very constructive for the WCS piece. Obviously, there's so many factors, gas price, reliability, refineries that will impact -- that could impact it. But I'm very encouraged by that for here in 2023. At TMX, I have not heard any new updates other than it's progressing, coming on late this year or starting to mechanically be complete late this year, which, again, to me, is a positive piece for both the WCS and in general, egress out of Western Canada, because it gives you optionality. As you saw with the -- when there is a pipeline issue today, on the egress side, whether it's Line 3 or another line, it does put some pressure on the pricing here in Alberta. And so with TMX, I would think that what it will do is stabilize those pricing, so that they're more a reflection of the true market.

There are no further questions at this time. Please 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.

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