Cenovus Energy Inc. (NYSE:CVE) Q4 2025 Earnings Call Transcript

Cenovus Energy Inc. (NYSE:CVE) Q4 2025 Earnings Call Transcript February 19, 2026

Cenovus Energy Inc. beats earnings expectations. Reported EPS is $0.3641, expectations were $0.28.

Operator: Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy’s Fourth Quarter and Full Year 2025 Results Conference Call. [Operator Instructions] As a reminder, this call is being recorded. I would now like to turn the meeting over to Mr. Patrick Read, Vice President, Investor Relations and Internal Audit. Please go ahead, Mr. Read.

Patrick Read: Thank you, operator. Good morning, everyone, and welcome to Cenovus’ 2025 Year-End and Fourth Quarter Results Conference Call. On the call this morning, our CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. Then we’ll open the line for Jon, Kam, and other members of the Cenovus management team to take your questions. Before getting started, I’ll refer you to our advisories located at the end of today’s news release. These describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus’ annual MD&A and our most recent AIF and Form 40-F.

And as a reminder, all figures we reference on the call today will be in Canadian dollars, unless otherwise noted. You can view our results at cenovus.com. For the question-and-answer portion of the call, please keep to one question with a maximum of one follow-up. You’re welcome to rejoin the queue for any other follow-up questions you may have. We also ask that you hold off on any detailed modeling questions. You can follow up on these directly with our Investor Relations team after the call. I will now turn the call over to Jon. Jon, please go ahead.

Jonathan McKenzie: Great. And thank you, Patrick, and good morning, everyone. I want to begin by recognizing our safety performance. Safety remains the cornerstone of everything we do at this company and every decision we make. At our Sunrise Oil Sands asset, our teams have now gone through 2 full calendar years and more than 1.8 million hours worked without a reportable incident. Now this is particularly notable because 2025 represented the highest activity level at Sunrise in the past 6 years with close to 950,000 hours worked as they completed 2 turnarounds and advanced the asset’s growth program. This outcome reflects our deep commitment to safety even during periods of elevated activity. Personal safety for each of our employees and contractors remains a critical priority, which must underpin everything we do.

We are working to build on our strong performance and continuously improve to ensure that our people come home safely each and every day. So now to our results. 2025 was a very important year for Cenovus in which we executed a long list of priorities across the company. Our performance in 2025 is a testament to the great people and assets we have at Cenovus. When I look at all the things that we accomplished this year, I couldn’t be more impressed by the way our people met the challenges we faced. We had a very ambitious agenda, and we collectively delivered against it. Operationally, our teams delivered exceptional performance, including setting multiple upstream production records across our assets and executing consecutive quarters of top quartile downstream reliability and profitability.

Our upstream production of 834,000 BOE per day in 2025 was the highest ever for Cenovus and up 3% from 2024, excluding the impact of the MEG Energy acquisition. We also reduced total upstream nonfuel operating costs by approximately 4% from the year before. In the Downstream, our refineries ran well through the year with a combined utilization rate of 95% across the Canadian and U.S. segments. This included the impact of a major 59-day turnaround at Toledo, which was completed 11 days ahead of schedule. Now at the same time, we lowered costs, delivering a reduction in operating costs of around $4 per barrel in the Canadian Refining segment and $2 per barrel in our U.S. operated refineries. We recognize there’s more work to do as we continue to drive down costs and leverage our commercial capabilities to enhance our market capture.

We also achieved major milestones across our growth projects in 2025. This included completing the Narrows Lake tieback to Christina Lake, a first of its kind extended steam reach pipeline. Completing the facilities work on the Foster Creek optimization project, which delivered production growth well ahead of schedule and completing the construction and installation of the tie-ins on the West White Rose platform. These projects reflect an enormous amount of effort, determination, and ingenuity from all parts of our organization that I couldn’t be — and I couldn’t be more proud of what we’ve delivered. Now 2025 also saw us complete 2 significant transactions. Starting with MEG Energy. We have long recognized the quality of the resource and the synergy opportunity available if we consolidated the Christina Lake area.

When MEG became available, we responded accordingly. The acquisition was successfully closed on November 13, adding over 100,000 barrels a day of top-tier resource located directly within our largest producing SAGD asset. The addition of MEG’s assets and people have strengthened our industry-leading heavy oil portfolio and solidified our position as the preeminent heavy oil producer, not just in the Western Canadian Sedimentary Basin but globally. We also sold our interest in the WRB refining joint venture at the end of the third quarter. As a result, we now have full operational, commercial, and strategic control of our Downstream business, which remains critical — which remains a critical component to our heavy oil value chain. Together, these transactions position the company for continued material value growth over the long term.

So now turning to our fourth quarter results. Upstream production in the fourth quarter was 918,000 BOE per day, headlined by oil sands production of 727,000 BOE per day, both records for the company. Including the full benefit of the MEG acquisition, which closed in mid-November, we exited the year with production over 970,000 BOE per day in December, including nearly 786,000 BOE per day from the oil sands. We are encouraged by the recent performance and expect our operating momentum to continue into 2026 and beyond. At Christina Lake, production averaged 309,000 barrels a day in the fourth quarter. That includes roughly 6 weeks of production from the newly acquired Christina Lake North asset, which achieved its highest ever production rates of over 110,000 barrels a day in the quarter.

The combined Christina Lake is the largest and highest quality thermal asset in the industry with a reserve life measured in decades. The integrations of systems and people is largely complete, and we have delivered a majority of the expected corporate synergies already. Work is now progressing at pace to capture operational synergies. We have begun a delineation and seismic program at the Christina Lake North asset, which will allow us to optimize our go-forward development plans for this resource. Our technical groups have begun leveraging our scale and operating practices to deliver near-term production and cost savings. We have also begun drilling a 42-well redevelopment program, which will support additional production volumes in 2026 and 2027.

We are very comfortable in our ability to deliver the $150 million of annual synergies in 2026 and ’27, and over $400 million of annual synergies by the end of 2028. We are delineating additional synergy opportunities as we fully integrate our future development plans for the broader Christina Lake region. Now at Foster Creek, we achieved a production record of 220,000 barrels per day in the quarter, reflecting the impact of the Foster Creek optimization project. Incremental steam capacity of approximately 80,000 barrels a day was brought online in mid-2025. And in the fourth quarter, the water treatment and deoiling facilities were commissioned and put into service. With these milestones behind us and production largely ramped up, we have successfully delivered around 30,000 barrels a day of growth at Foster Creek well ahead of schedule.

Looking forward, new well pads associated with the optimization project will be brought online at Foster Creek this year, which will support increased production levels or support the increased production levels we have seen. We also continue to progress our enhanced sulfur recovery project that will reduce operating costs by about $0.50 to $0.75 per barrel when it comes online midyear. At Sunrise, following the turnarounds executed in Q2 and Q3, production rose to over 60,000 barrels a day in the fourth quarter. The first of the new well pads from the East development area, incorporating Cenovus well pad design for the first time at Sunrise is currently steaming and expected to start up in early 2026. We will bring on a total of 3 well pads in this high-quality reservoir in 2026 and at least one more in 2027.

This development will deliver the next phase of growth as we progress our plans to increase production to over 70,000 barrels a day by 2028. Now with the work we completed earlier this year, we have also extended the turnaround cycle from 4 to 5 years at Sunrise. That means there is no major cycle ending turnarounds at Sunrise until 2030, providing an extended runway while we grow volumes and optimize the asset. The Lloydminster thermals had an exceptional fourth quarter, partly as a result of the highly successful redevelopment well program that significantly exceeded our expectations. In tandem with strong base well optimization, production averaged over 107,000 barrels per day in the quarter, more than 10,000 barrels higher than the previous quarter.

This includes the impact of the sale of Vawn at the beginning of December. And building off the success we had in 2025, we’ll be deploying an even larger redevelopment program in Lloydminster in 2026. Now turning to the Atlantic. At West White Rose, we’re currently conducting systems integration testing, and we’re in the final phase of commissioning. Our teams have done a fantastic job of safely progressing the scope in spite of particularly challenging weather in the North Atlantic. We’ve seen an abnormally severe winter storm season with waves as high as 17 meters and winds up to 170 kilometers per hour. Through this, our people have continued to make steady progress. We have completed the welding and coating of the platform legs and the main power generators are fully commissioned.

We also opened the living quarters on the top side prior to year-end, transitioning staff from using a flotel vessel to fully manning the platform. Now we’ve guided you to expect first oil in the second quarter. With the weather disruptions we’ve seen, that timeline will be tight but our people are determined and do incredible work as we push this forward at pace. Also in the offshore, in conjunction with our partners in Asia, we successfully extended the gas sales agreements in China for both Liwan 34-2 and Liwan 29-1 subsequent to the quarter. The extensions will enable sales through the end of the field’s production periods in 2034 and ’40, respectively. This increases sales volumes within our 5-year plan and add nearly $2 billion of incremental free cash flow to these assets over the life of the fields.

Now moving to the Downstream. Fourth quarter results underpin the profitability and competitiveness of our assets in a relatively weak crack environment. In the quarter, the Canadian Refining business ran at its highest rates of production through the year with crude throughput of 113,000 barrels per day or utilization rate of about 105%. in U.S. Refining, our results in the fourth quarter reflect not only our operated — sorry, reflect only our operated assets as our interest in the WRB refining was divested effective September 30. Our U.S. refining business delivered crude throughput of 353,000 barrels per day or approximately 97% utilization. While the market crack spreads in Chicago area deteriorated significantly in early December, which is typical for this time of year, we’re able to capture a larger share of the margin available.

Excluding the receipt of onetime pipeline settlement, our adjusted market capture was around 95% in the quarter. This reflects both seasonal product mix impacts related to our configuration as well as our ability to capitalize on commercial opportunities we saw in the market during the quarter. Now I’m going to pause for a minute, and I will turn this over to Kam to walk through our financial results.

Kam Sandhar: Thanks, Jon. Good morning, everyone. In the fourth quarter, we generated approximately $2.8 billion of operating margin and $2.7 billion of adjusted funds flow. Operating margin in the Upstream was over $2.6 billion, in line with the prior quarter with record production in the oil sands more than offsetting declining benchmark oil prices. Oil sands nonfuel operating costs decreased to $8.39 a barrel in the fourth quarter, over $1.25 lower than the prior quarter due to higher production volumes and reduced maintenance activity. As Jon mentioned, our Downstream business continued to demonstrate strong performance in the quarter. Downstream operating margin was $149 million despite deteriorating regional crack spreads in the U.S. towards the end of the year.

This included $138 million of inventory holding losses and $15 million of turnaround expenses, partially offset by a onetime pipeline settlement receipt. Excluding these impacts, downstream operating margin would have been approximately $235 million in the quarter. In the U.S. Refining, operating costs, excluding turnaround expenses, were $11.57 a barrel, reflecting higher fuel and electricity prices, planned maintenance activity and modestly lower throughput quarter-over-quarter. The fourth quarter environment was particularly favorable to our configuration with heavy crude differentials widening, diesel and jet fuel advantage relative to gasoline and lower benchmark crude prices benefiting asphalt and other product margins. Our marketing teams were able to capitalize on market opportunities in the quarter, while at our Lima and Toledo refineries, we continue to leverage and enhance the interconnectivity of the sites.

On a sustained basis, we continue to guide to adjusted market capture of around 70% at a $14 WCS heavy oil differential with opportunities to improve this over time. Capital investment in the fourth quarter was nearly $1.4 billion, resulting in full year capital spending of $4.9 billion. This spend supported sustaining activity across the business, along with investment in growth and optimization, including capital directed to our 3 of our major capital projects at Narrows Lake, Foster Creek and West White Rose. As we look forward, growth spend in 2026 — in the 2026 plan is approximately $300 million lower at the midpoint year-over-year. This growth spend includes commencing the drilling at West White Rose, advancing the Christina North expansion project, which will support growth at Christina Lake to around 400,000 barrels a day.

Net debt was approximately $8.3 billion at the end of the fourth quarter, an increase of approximately $3 billion due to the MEG transaction, partly offset by the receipt of $1.9 billion of cash proceeds from the sale of WRB. Shareholder returns in the fourth quarter were $1.1 billion, including $714 million through share buybacks and $380 million through dividends. After closing the MEG transaction, we’ve adjusted our framework to balance deleveraging and shareholder returns while we move towards our long-term net debt target of $4 billion. When net debt reaches $6 billion, we will aim to increase shareholder returns to around 75% of excess free funds flow. Also in the fourth quarter, we recognized a current tax recovery of $189 million, primarily driven by the integration of MEG’s business with Cenovus.

Full year 2025 current taxes were approximately $780 million, well below our original guidance of $1.2 billion to $1.3 billion. Our cash tax guidance for 2026 remains unchanged at $1 billion to $1.3 billion at around a USD 60 WTI price. With the strong operational performance, meaningful progress towards capturing MEG synergies and a robust balance sheet, we are well positioned to continue to deliver value from our opportunity-rich portfolio. I’ll now turn it back to Jon with some closing remarks.

Jonathan McKenzie: Great. And thank you, Kam. 2025 was a great year for this company by any measure and a testament to the dedication and determination of the people that we have in this organization, including those who most recently joined us from MEG. Our disciplined execution and focus on operational excellence enabled us to deliver significant milestones across the major projects this year while setting numerous production records at all our oil sands assets. In our Downstream business, we’ve continued to demonstrate the potential of the assets as evidenced by consecutive quarters of top-tier reliability and meaningful cash flow contribution. Completing the strategic acquisition of MEG has materially extended our industry-leading low-cost, long-life resource base.

Through the integration of our highly complementary assets and the focus on the ingenuity of our combined teams, we expect to create significant value from this business for years and decades to come. Anchored by our strong financial framework and balance sheet, and the many opportunities ahead of us, Cenovus is more resilient, competitive and durable than ever before. And with that, we’re happy to answer any questions you might have.

Q&A Session

Operator: [Operator Instructions] Our first question will come from the line of Dennis Fong from CIBC World Markets.

Dennis Fong: First and foremost, congrats on a really strong quarter and year. My first one here focuses really on the MEG assets that you’ve now taken over. I was hoping to find out what some of the next steps happen to be in terms of obviously turning the asset over to your teams? And then how are you looking at applying, we’ll call it, Cenovus’ best practices and technical understanding on the asset to really drive stronger performance and realize the synergies that you outlined or more with the initial presentation.

Jonathan McKenzie: Sure. So maybe I’ll take a crack at it, and then I’ll turn it over to Andrew Dahlin to give you some of the details on the production side. But I think we’ve had this asset now for, I guess, it’s about 3 months now. And I’d say that particularly during the first 6 weeks since we acquired this, we moved really, really quickly on getting after all the corporate synergies that we had outlined in our investment case. So everything from the HR synergies through the commercial synergies, the finance synergies, getting the amalgamation done to realize some of the tax synergies. That was all done before year-end. And so we kind of look at that run rate of [ $150 million ], and we’re very, very comfortable that the [ $120 million ] that is sort of the corporate component of that is very realizable and has largely been captured now.

So as we kind of move into 2026, we’re really focused on the operations proper. We have started a lot of work on delineating the reservoir in advance of doing our redevelopment program, which will kick off next month and really looking at the well pad development and seeing where we can insert ourselves to impose some of our operating practices and well design on that. And Andrew will give you a bit more detail. But we haven’t lost sight, Dennis, of the bigger picture and the view of how do we bring more synergy forward and how do we go beyond the $400 million that we had articulated in the business case. And we’re comfortable there’s a lot more there, and that’s what we’re working on now. But Andrew, maybe you can talk a little bit about some of the things you’re doing in the field to get additional production synergy out of those operations.

That’s right.

Andrew Dahlin: Yes, it’s Andrew Dahlin speaking. Yes, maybe just focusing on production itself. So the first thing we’re going after here in the first half of this year is the start of the redevelopment campaign. So the plan is to drill 40 redevelopment wells that ultimately get after heated bitumen zone that sits below our current production wells. We will get production from our first redevs here in Q2 of this year. And I think as Jon has spoken to, that would benefit and see a production uplift both here in 2026 and into 2027. So that’s the kind of the first production lever we’re pulling. Second one would be our development methodology. So those of you that came to our teach-in, you’ll know that our focus or our sort of way of developing it is the field is with wider well spacing and longer wells.

So we are moving to implement that already here latter part of 2026. We’ll be steaming the first pad in 2027 and seeing a production ramp-up and actually much lower development costs starting in ’26 into ’27. And then the team is working really hard on facility debottlenecking and expansion. So there’s a debottlenecking program, actually 3 MOCs taking place right as we speak to be able to push more volume through the plant. And then, of course, we have a facility expansion project that will see the facility expanded and production taken to an excess of 150,000 barrels a day by 2027, 2028. So that was kind of the immediate production focus. And then on top of that, of course, if I look further out, we have things like boundary land, so the boundary land that existed between ourselves and MEG.

As Jon alluded to, we’re delineating that opportunity and then putting that into an optimized long-term development plan for the asset. So I’ll stop there.

Jonathan McKenzie: If I were to sum it up, Dennis, I’d say there’s really no surprises in what we put out as our investment case on this. And I think we’ll be bringing forward additional upside as we go through the coming quarters and months.

Andrew Dahlin: Fantastic. No, I really appreciate that — the depth of that context there, both Jon and Andrew. Shifting my focus towards Lloyd for my second question. In your slide deck, you showcased development, both from the thermal as well as the, we’ll call it, conventional assets towards over 145,000 barrels a day over the next couple of years. But I did draw a little bit of notice to the use of solvent enhanced oil recovery techniques. Can you elaborate a little bit more on that opportunity and what that could mean for the field?

Jonathan McKenzie: Yes. So we’ve got a solvent project going on at what we call Spruce Lake North, which we think is an ideal reservoir for the application of solvent. And I think you know that we’ve been kind of leaders in this and kind of developing that technology. So it’s not a, I’d say, a step change from our strategy but it is something that we think is an opportunity for us, and this is kind of an ideal place to do this. I think, Andrew, maybe you can talk a little bit about the development of that and when we can expect to see that project come online.

Andrew Dahlin: Yes. No, happy to. So indeed, Spruce Lake project, we’ve taken FID on the project. Its spend is in the order of $250 million. We’ll spend that here in 2026 and through into 2027 when the project will come on stream, I know. Essentially, what we do is we inject condensate along with the steam but less steam. And what it does is it lowers our SOR, it drives higher production and it drives higher ultimate recovery. So we see an immediate benefit to Spruce Lake. And frankly, we see the future application of this in the rest of our oil sands assets. and potentially also in some of our lower quality reservoirs. So we very much have a view of how could we deploy this technology into the next 2 to 3 decades. So that’s where we are on that.

Operator: Our next question will come from the line of Menno Hoshoff from TD Cowen.

Menno Hulshof: I’ll start with maybe just on the Downstream side of things. One big thing that jumped out for a lot of people in the quarter was the big uptick on a quarter-on-quarter basis for U.S. market capture. Yes, just a big increase. And you did touch on this to some degree in your opening remarks, but can you just elaborate on what drove that because nobody was even close to that in their models, I don’t think. And maybe your expectation for market capture through the middle of the year, especially given limited planned turnaround activity.

Jonathan McKenzie: Well, I’ll tell you what I’m going to turn it over to Eric to give you a view on that. Eric rarely smiles but he is smiling this morning. So I think we’re really pleased and happy with the work that he and his team have done. But Eric, why don’t you talk a little bit about how you got the market capture you did?

Eric Zimpfer: Yes. Thanks, Jon, and thanks, Menno, for the question. Yes, really pleased with the performance. I would say it’s a combination of a number of things. I think certainly, fundamentally, just having the reliability in place that gives you the ability to capture the market when it presents itself. And so what we saw in the fourth quarter was some market opportunities where there were some supply disruptions in the region and our reliability allowed us to capture that. I think you put on top of that some of the real commercial optimization work that we’ve been doing between finding the synergies between Lima and Toledo, using dock access to find new markets for our products, just really helped underpin the improvement that we’ve been driving, and you got to see that in the fourth quarter.

The other nuance to market capture that I would highlight is there is seasonality to it. So what happens in the fourth quarter when you see the gasoline cracks start to fall off as you expect in PADD 2, there is some benefit to our portfolio where we have some GDD flexibility. It also helps relative to some of the other secondary products that we make, so asphalt and some of those products are able to kind of price better relative to the crack, which shows a higher market capture. What I would say going forward is we’ll continue to guide to that 70%, but we do see seasonality in it but I would continue to steer towards that 70% at the $14 dip that we’ve talked about.

Menno Hulshof: So we are starting to see a bit of an impact from the PADD 2 egress initiatives, that you’ve talked about in the past?

Eric Zimpfer: Yes, absolutely. We’ve seen some real good improvements around our ability to utilize the Toledo dock. We set an annual record in the volumes we’ve been able to move. And that just really helps us find new markets and be able to really get after some better opportunities for us, and we’ll continue to explore all sorts of options to continue to take advantage of that.

Menno Hulshof: Okay. That’s helpful. And I’m going to assume that’s part of the first question, cutting off if it’s not. But just on West White Rose, really good to see that the Q2 timeline is still intact. But can you just give us an update on the status of drilling? And what should we be modeling for an exit rate for 2026 if everything goes according to plan?

Jonathan McKenzie: Yes. No, you’re quite right, Menno, we’re still guiding to Q2. I did mention in my notes that it’s tight. So we had hoped to be drilling by this time. We are in the final stages right now of commissioning, and that will make the time frame, again, tight for the end of Q2. But Andrew, maybe you can talk a little bit about exactly where you are and how you’re seeing production through the end of the year.

Andrew Dahlin: Menno, it’s Andrew speaking. Yes, indeed, maybe I’ll just sort of make sure that we all sort of level on where we are in terms of status of the project. So major construction is complete. The platform is commissioned and inhabitable. All the subsurface work connecting the platform to the SeaRose is completed. And as Jon talked about, we’re in the final throes of commissioning and sit testing. So that’s where we are today, and then we move into drilling. I think in terms of how do I look at it from a production and the CapEx for the year, we absolutely to guidance, both for production. Our production guidance was 20,000 to 25,000 barrels a day and actually don’t have CapEx handy but we’re also within that CapEx guidance.

And so what you’ll naturally see is as the first and the second well come on stream, you’ll see a — sorry, I’ll start again. You’ll have a base production from SeaRose and from Terra Nova, and that will continue through the year. I tell you that we’re seeing good uptime and availability on production from both of those facilities here in Q1. And then obviously, in the second half of the year, you’ll get a production ramp-up as each new well comes on.

Jonathan McKenzie: So the final push is on, Menno, and we’ve increased the number of people on the platform, and we look to be drilling very, very shortly.

Operator: Our next question will come from the line of Neil Mehta from Goldman Sachs.

Neil Mehta: And Jon, you addressed this in a couple of different ways, but maybe you can dig a little deeper, which is you’re getting to be a 1 million barrel a day producer, and you’ve got a lot of growth here coming in the next couple of years. I think there’s a lot more questions about egress coming out of Canada and apportionment is a factor and you have a little bit less WRB as a hedge. And so just maybe you can address this concern head on. Is Cenovus a lot more exposed to potential volatility in WCS? Or do you feel confident about your ability to navigate that potential risk?

Jonathan McKenzie: Yes. No, it’s something we obviously think about Menno or Menno — Neil. Since I came to this company, the 2 things that we obviously highlighted were egress and having a strong balance sheet. And when you kind of think about this company growing from a standing start to 1 million barrels a day over 20 years, those 2 things have really been front and center for us. So Geoff Murray , who’s our EVP of Commercial, he deals with this every day. But Geoff, maybe talk about some of the egress options that we have and where we sit as a company in terms of our balances.

Menno Hulshof: No, it sounds great, Jon. Neil, great question. If we wind the clock way back when to 2018, we sold 80% of what we made in Alberta. Where we stand now is maybe 40% of the crude oil we make is sold in Alberta and exposed to that diff. So we’ve moved a very long way, as you point also the growth on that front. So that’s a really big shift over the past 7, 8 years. Probably more importantly is looking forward in the near term. We’ve been saying for a while, Trans Mountain is here. It’s working. It’s performing as expected, and you will see that through the stability of the Alberta diff as compared to global points, and that’s proven to be true. We’ve also said we’re not going to rest on our laurels. And we and the industry at large haven’t.

I think we’ve disclosed entering into opportunities for 150,000 barrels a day of export over the next 2 years under contract. And even more importantly than that, I would say Cenovus has been pressing hard across the industry for what’s next, although the diff is in the right place and stable, we know that we need to take action to continue that. And I think you can probably scour the market and find a number of publicly discussed projects, and we’re really quite supportive of all of them, both in philosophy but also through contracting mechanisms, and we’ll continue to do that.

Jonathan McKenzie: Yes. I’d say just adding to that, Neil, I would say that we probably see more proposed projects today than I’ve seen in the last 10 years. and more projects that are doable in a shorter time frame than we’ve had in a long period of time. So as Geoff mentioned, heavy oil egress is a really important part of our strategy, and we are actively evaluating and looking at all of those options that are available to us. And you shouldn’t be surprised if we take action on some of those.

Neil Mehta: And the follow-up is around return of capital versus growth. We’re probably in a firmer commodity price environment, Jon, than you and I would have thought a couple of months ago. Certainly, geopolitics is part of that. But if we are — if we do go into a period of time where we’re above, let’s say, a mid-cycle price that you outlined, does that dollar go back to deleveraging/return of capital? Or could you accelerate the growth lever? How do you think about that?

Jonathan McKenzie: We really don’t think about the commodity price of the day, Neil. We are kind of more value orientated in terms of how we allocate capital over the long term. And I think we’ve been pretty clear that in the short term, until we get down to $6 billion of net debt, 50% of the free cash flow is going to be used for deleveraging, and then we’ll return 50% to the shareholders in the form of buybacks. But Kam, maybe you have some more thoughts on that.

Kam Sandhar: Yes, Neil, I would just add, I think when you look at our philosophy around just capital allocation, the growth projects we’ve got in the portfolio, and I mentioned this in my remarks, our growth spend actually has come down year-over-year when you look at the projects we’ve got. We’ve obviously finished or close to being done things like Narrows, the Foster optimization, West White Rose. We obviously added the FEP expansion. But when you look at the portfolio as a whole, our growth spend is down year-over-year. So — and one of the things we do try to do is we try to ensure that capital spend doesn’t really change with commodity prices to Jon’s point, in that we can fully fund that growth plan with our dividend and probably in a low $50 world.

And so don’t expect us to make any sort of knee-jerk reactions to capital spending if commodity prices flex down $5 to $10. And similarly, you’re not going to see us move it in the other direction if oil prices go up. When you look at the priorities we have today in terms of our excess free cash flow, I don’t think anything has changed. Neil, we — obviously, our philosophy has been that we’re going to continue to be balanced on deleveraging and share repurchases with our excess cash, and that’s something we’ll continue to do. I think I would say that obviously, the share price has continued to perform very well but we’re nowhere near a price level that I would suggest is a level where we would move away from things like buybacks. We’ve made a lot of improvements to the business, both on costs, on growth and free cash flow improvements.

And our business continues to get more and more resilient. And I think that affords us the opportunity to continue to buy back stock.

Operator: Our next question will come from the line of Travis Wood from NBCCM.

Travis Wood: I wanted to — Menno kind of stole my question there but I wanted to dig into that a little bit more because I think it’s quite interesting in terms of the rate of change. So could you talk about some of those anomalies that you saw through Q4 in order to capture that adjusted 95%? And does the marketing and trading team have that ability to capture those go forward? And I guess, in the same breath, how much does other refinery downtime have to do with that market capture? So if we see in the future, Whiting go down again, can we ramp up that market capture in those one-off quarters with other refineries going into turnaround?

Eric Zimpfer: Yes. Again, great question, Travis. I appreciate the question. Yes, I think maybe just working backwards, I think certainly, with the reliability improvements we’ve been able to deliver in our portfolio, it positions us to be able to capture market opportunities when they present itself. And so any time there’s a disruption in the market, that reliability lets you take advantage of it. And that’s what we saw in the fourth quarter. And so you saw some strength in the crack really into early December before it started to fall off as you would expect it to in the winter season. And so I fully expect that is something we will continue to stay laser-focused on that when the market presents opportunities for us, we want to be able to take advantage of that.

So that is absolutely core to what we want to be able to do. In terms of the market, I think every refinery and every downstream has its own unique configuration. And I think when the market fundamentals favor that configuration, you see the opportunity to have a higher market capture. So for us, where we have a high — heavy differential — sorry, where we have a higher heavy crude consumption where we see that heavy diff, that favors our portfolio. Where you see the gas crack come off, we have some diesel — some distillate length, some diesel and jet length, we’re able to take advantage of that by optimizing our cut points inside the refinery and really maximizing that distillate production. Superior has significant asphalt production, right?

When you see the asphalt market have some strength and carry that forward, that favors that portfolio. And so that really is that seasonality I spoke to earlier that depending on what the market is favoring and how it’s priced in, that can favor or that can work against you. And what we saw in the fourth quarter was really the opportunity, both from the market opportunities with some of the disruptions as well as our configuration fitting better into what the crack available was for us.

Travis Wood: Okay. That’s fantastic color. Switching gears for my second, just in terms of Liwan contracting on the gas sales, does that include any kind of contracted pricing as well? Is there any material change to the pricing as we look out through ’26 and beyond?

Jonathan McKenzie: Yes. No, that’s a good question, Travis. So what we’ve done on 34- it’s taken the last couple of years to really work on delineating those reservoirs. And what we’re finding is those reservoirs are getting bigger than what we had originally booked for reserves, not smaller. And that’s given us the opportunity to increase the gas sales right to the end of life of the PSCs. And that’s a big deal for us. And so the gas contracts themselves are roughly the same as what they are today, although slightly higher as well. So we’re very pleased with the pricing, very pleased with the volumes. And as I mentioned in my notes, it gives us about $2 billion of incremental free cash flow over the life of those fields. So it’s a very significant piece of work and something that the team there has been working on for the last couple of years. So it’s good to see it come to fruition at year-end.

Operator: Our next question will come from the line of Chris Hebert from RBC Capital Markets.

Greg Pardy: Jon, it’s Greg. So I think we may have got our wires crossed on our end.

Jonathan McKenzie: Apologize. You came up because Chris Hebert [ we’re wondering ] really well.

Greg Pardy: I did indeed. And yes, so listen, a couple of things. I want to come back to Neil’s question. So you finished the 3-year plan, the 3-year growth plan and so forth. Is there another growth plan, albeit perhaps more modest than the offering right now? And then kind of related to that, I wanted to go back to what Kam was talking about in terms of not really throttling your spending too much. But like how generally should we — I hate to ask it this way but how should we think about sort of your capital spend maybe over the next 2, 3 years? And that obviously ties into the degree of balance sheet deleveraging, other things being equal.

Jonathan McKenzie: Yes. So what I would say, Greg, is one of the things we don’t want to get into is big major projects again. So West White Rose is the last of the big major projects. But we have fairly low sustaining capital in and around sort of the 3.6, 3.7 level. And so we have plenty of capital available to us at growth projects that chin the bar at $45. But the growth that you’re going to see from us over the next couple of years outside of the work that we’ve already delineated at the Mega asset is really around brownfield development, debottlenecking and those kind of things. So we mentioned the [indiscernible] SAGD project that we’ve got going on at Spruce Lake, which is kind of another example of something that kind of adds 5,000 to 10,000 barrels a day, but isn’t — probably doesn’t chin the bar in terms of major project status.

But you’re going to continue to see those kind of things. So where we have opportunities to add production for $45 or sort of add production that has a return of and return on capital of $45, and we can kind of do in $10,000, $15,000, $20,000 a flowing barrel range, you’re going to continue to see those things come out of us. And so I would kind of — if I were you, I would kind of model us being close to that $5 billion that we’ve talked about in the past as kind of being the ceiling for our capital spending and then incorporate from that kind of 3% to 5% growth.

Greg Pardy: Okay. Okay. That’s helpful. And then that [ $5 billion ], let’s just assume another $350 million, like I like the fact you guys are capitalizing your turnarounds, gives good transparency. So another — I’m splitting hairs here, Jon, but that would include turnarounds or wouldn’t include turnarounds?

Jonathan McKenzie: That will include turnarounds.

Greg Pardy: Okay. Okay. Terrific. And Travis’s question was good. I mean, kind of interested in — like I love your Asian business. I mean it doesn’t get a whole lot of airtime. But what does that business look like over 2, 3, 4, 5 years? How much time are you spending there? Do you want to grow it? Do you want to harvest it? Are you going to sell it?

Jonathan McKenzie: I don’t think — the way I think about that business, Greg, you’re quite right. It’s a really good business, and it spits out a lot of free cash flow. I think it’s averaged about $1 billion a year for the last 5 years that we’ve owned it on a free cash flow basis. And what we really like about it is it’s fixed price gas plus we get the value of the liquids on a Brent basis. Your operating costs are about $1 an M. The fiscal take is relatively modest, and there’s really not much of a requirement for sustaining capital. So the way we kind of think about it is not harvesting the asset but definitely sweating the asset and staying true to the Block 29/26, where we think we have a competitive advantage. But we kind of look at it under those terms.

We evaluate the opportunities within the block. We work well with the partner there that we have in CNOOC, and we’re really grateful for that relationship. And it’s just an asset that we just continue to take free cash flow from and invest appropriately in.

Operator: Our next question comes from the line of Manav Gupta from UBS.

Manav Gupta: I just wanted to quickly focus a little bit on egress. We know Enbridge has announced MLO 1 on their call, they are very close to announcing MLO 2 could happen before year-end. And then they also threw out the prospect of an MLO 3. And then there are a bunch of projects that ET and Enbridge are looking where they could even reverse the Bakken pipeline, get more Canadian crude onto DAPL. So I’m just trying to understand, as all these Egress projects are taking shape place, does this give Cenovus a little more confidence that we are not going back to the days where WTI, WCS could be $25 or so. Those days are behind the Alberta oil sands. Can you talk a little bit about that?

Geoff Murray: Manav, it’s Geoff Murray. It sounds like between my last comment and this one you scoured the world and found a number of the pipelines. There’s — there are more out there as well under development. And I’d point to a few other developments and other companies that are working away on things in the same sort of time frame. The projects you referenced, I think, are all intended to be in service late ’27, ’28, ’29. There’s projects that push ’29, ’30, ’31 as well. And I think, as Jon pointed out, there’s a number of these opportunities out there. Very few of them look like the big challenging mega projects we saw of a decade ago, and there was a certain level of probability around those things. These things are smaller.

They’re more easily permitted. There is less development to be done. And I would say we’re well connected with all of them, broadly supportive of egress. The key will be industry and Cenovus being prepared to stand by and stand behind and take long-term contracts around these assets. And as Jon pointed out, don’t be surprised to see us do that. That is a way of saying we have impact and influence to drive the outcome you referenced, which is to continue to bring egress to market to keep the differential in Alberta where we see it now. And it does feel fairly comforting that, that is something we can take action to drive for at least the next 5 to 10 years.

Jonathan McKenzie: Yes. I think, Manav, we don’t take any of this for granted. So we would never be of the view that we’re never going back to where we are. But our challenge as a company is to make sure that we take advantage of these opportunities as they arise. We’re kind of in a world right now where we’re opportunity-rich in terms of egress. And so we’re looking at everything. But we also understand that egress is something that’s very important to this company on a long-term basis. But with everything that’s out there today, it’s very positive for this company and this industry. And as I said before, you should look for us to lead this and take advantage of it.

Operator: [Operator Instructions] And there are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Jonathan McKenzie: Great. Thank you, operator. So this concludes our conference call. I’d just like to thank everybody for joining us. We definitely appreciate your interest in the company. So thank you very much, and have a great day.

Operator: This concludes today’s program. You may all disconnect. Thank you for participating in today’s conference, and have a great day.