Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Fourth Quarter and Full Year 2025 Results Conference Call. 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.

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.

Great. Thank you, Patrick, and good morning, everyone. I want to start by acknowledging our safety performance. Safety is essential to everything we do and informs every decision we make. At our Sunrise Oil Sands asset, our teams have now completed two full calendar years and more than 1.8 million hours worked without a reportable incident. This is particularly significant since 2025 saw the highest activity level at Sunrise in the last six years, with nearly 950,000 hours worked while completing two turnarounds and advancing the asset's growth program. This achievement is a reflection of our strong commitment to safety, even during busy periods. The personal safety of our employees and contractors remains a top priority that drives our actions. We are dedicated to building on our strong performance and continuously improving to ensure our team's safety every day. Now to our results. 2025 was a pivotal year for Cenovus as we executed a wide range of priorities across the company. Our performance in 2025 highlights the dedication and quality of our people and assets. I am thoroughly impressed with how our teams tackled the challenges we faced. We set a high bar and successfully delivered on our ambitious agenda. Operationally, our teams excelled, achieving multiple upstream production records and executing consecutive quarters of top-tier downstream reliability and profitability. Our upstream production reached 834,000 BOE per day in 2025, the highest in Cenovus's history and a 3% increase from 2024, excluding the MEG Energy acquisition impact. We also managed to cut total upstream non-fuel operating costs by about 4% compared to the previous year. In the Downstream, our refineries operated effectively throughout the year, maintaining a combined utilization rate of 95% across our Canadian and U.S. segments. This included completing a major 59-day turnaround at Toledo, which finished 11 days ahead of schedule. Simultaneously, we managed to lower costs, with operating costs reducing by about $4 per barrel in the Canadian Refining segment and $2 per barrel in our U.S. refineries. We recognize that there is still work to be done as we continue to reduce costs and leverage our commercial strengths to enhance our market presence. We also marked significant achievements across our growth projects in 2025, including completing the Narrows Lake tieback to Christina Lake, a pioneering extended steam reach pipeline. We finished the facilities work on the Foster Creek optimization project, which resulted in production growth ahead of schedule, and completed the construction and installation of tie-ins on the West White Rose platform. These projects reflect a tremendous amount of effort and creativity from all areas of our organization, and I am extremely proud of our accomplishments. In 2025, we also concluded two major transactions, starting with MEG Energy. We have long understood the quality of the resource and the synergy potential from consolidating the Christina Lake area. When MEG became available, we acted swiftly. The acquisition was finalized on November 13, adding over 100,000 barrels a day of premium resource directly within our largest producing SAGD asset. The inclusion of MEG's assets and personnel has bolstered our leading heavy oil portfolio, establishing our position as a top heavy oil producer, both in the Western Canadian Sedimentary Basin and globally. Additionally, we divested our interest in the WRB refining joint venture at the end of the third quarter. Consequently, we now maintain full operational, commercial, and strategic control of our Downstream business, which is critical to our heavy oil value chain. Collectively, these transactions set the stage for ongoing significant value growth in the long term. Now, regarding our fourth quarter results. Upstream production in the fourth quarter was 918,000 BOE per day, featuring oil sands production of 727,000 BOE per day, both records for the company. After accounting for the complete benefits of the MEG acquisition, which closed in mid-November, we exited the year with production exceeding 970,000 BOE per day in December, which included nearly 786,000 BOE per day from the oil sands. We are optimistic about our recent performance and anticipate sustaining our operational momentum into 2026 and beyond. During the fourth quarter, production at Christina Lake averaged 309,000 barrels a day. This incorporates approximately six weeks of production from the newly acquired Christina Lake North asset, which achieved record-high production rates of over 110,000 barrels a day in the quarter. Combined, Christina Lake represents the largest and highest quality thermal asset in the industry, with reserves lasting decades. The integration of systems and personnel is largely complete, and we have already realized most expected corporate synergies. Work is progressing swiftly to take advantage of operational synergies. We have initiated a delineation and seismic program at Christina Lake North to optimize our future development plans for this resource. Our technical teams are utilizing our scale and operational practices to achieve immediate production and cost efficiencies. We have also kicked off a redevelopment program involving 42 wells, which will support increased production volumes in 2026 and 2027. We are confident in our ability to realize $150 million in annual synergies in 2026 and 2027 and over $400 million in annual synergies by the end of 2028. We are identifying additional synergy opportunities as we fully integrate our development plans for the broader Christina Lake region. At Foster Creek, we achieved a quarter production record of 220,000 barrels per day, thanks to the Foster Creek optimization project. We brought online incremental steam capacity of about 80,000 barrels a day in mid-2025, and in the fourth quarter, we commissioned and serviced the water treatment and deoiling facilities. With these milestones achieved and production ramping up, we have successfully delivered approximately 30,000 barrels a day of growth at Foster Creek well ahead of schedule. In the upcoming year, new well pads associated with the optimization project will come online at Foster Creek, further supporting the increased production levels we are experiencing. We are also advancing our enhanced sulfur recovery project, which will decrease operating costs by about $0.50 to $0.75 per barrel when it begins mid-year. At Sunrise, following the turnarounds completed in Q2 and Q3, production increased to over 60,000 barrels a day in the fourth quarter. The first of the new well pads in the East development area, using our newly designed well pad approach, is currently steaming and projected to start production in early 2026. We plan to initiate a total of three well pads in this high-quality reservoir in 2026 and at least one more in 2027, allowing us to drive production growth to over 70,000 barrels a day by 2028. With the extensive work completed earlier this year, we have also extended the turnaround cycle at Sunrise from four to five years, meaning there won’t be significant turnarounds at Sunrise until 2030, which provides an extended runway for growing volumes and optimizing the asset. The Lloydminster thermals enjoyed an exceptional fourth quarter, partly due to a successful redevelopment well program that greatly outperformed our expectations. Combined with strong base well optimization, production averaged over 107,000 barrels per day in the quarter, which is over 10,000 barrels higher than the previous quarter. This includes the impact of the Vawn sale that occurred at the start of December. Building on our successful 2025, we will implement an even larger redevelopment program in Lloydminster in 2026. Turning to the Atlantic, at West White Rose, we are currently conducting systems integration testing and are in the final commissioning phase. Our teams have performed admirably in advancing the project despite challenging weather conditions in the North Atlantic. This winter has featured particularly severe storms, with waves reaching 17 meters and winds up to 170 kilometers per hour. Despite these challenges, our teams have made consistent 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 before the year-end, transitioning staff from a vessel to fully staffing the platform. We have indicated that we expect first oil in the second quarter; however, given the weather-related disruptions, this timeline is tight, but our team is motivated and performs excellently as we push this forward. In the offshore sector, in collaboration with our partners in Asia, we successfully extended the gas sales agreements in China for both Liwan 34-2 and Liwan 29-1 after the quarter. These extensions will facilitate sales through the end of the field’s production periods in 2034 and 2040, respectively, increasing sales volumes within our five-year plan and adding nearly $2 billion in incremental free cash flow over the life of these assets. Now transitioning to the Downstream, fourth quarter results affirm the profitability and competitiveness of our assets even in a weaker crack environment. In the quarter, our Canadian Refining business operated at its highest production rates throughout the year, processing 113,000 barrels per day, representing about 105% utilization. In U.S. Refining, our fourth quarter results only represent our operated assets since we divested our interest in WRB refining effective September 30. Our U.S. refining operations processed 353,000 barrels per day, or approximately 97% utilization. Despite significant deterioration in market crack spreads in the Chicago area in early December, which is typical for this time of year, we managed to capture a larger share of the available margin. Excluding a one-time pipeline settlement, our adjusted market capture was around 95% in the quarter. This reflects seasonal product mix impacts related to our configuration and our ability to seize commercial opportunities during the quarter. Now, I'll pause and turn this over to Kam to discuss our financial results.

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 non-fuel 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 one-time 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 three major capital projects at Narrows Lake, Foster Creek, and West White Rose. As we look forward, growth spend 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.

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.

Our first question will come from Dennis Fong from CIBC World Markets.

First and foremost, congrats on a really strong quarter and year. My first one here focuses 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.

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 three months now. And I'd say that particularly during the first six 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.

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 later 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 three 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.

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.

Fantastic. I really appreciate the depth of that context, both Jon and Andrew. For my second question, I want to shift my focus to Lloyd. In your slide deck, you highlighted development from both thermal and conventional assets, targeting over 145,000 barrels a day in the next couple of years. I noticed the mention of solvent enhanced oil recovery techniques. Can you provide more details on that opportunity and its potential impact on the field?

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.

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. 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 two to three decades. So that's where we are on that.

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

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.

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?

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.

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?

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.

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?

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.

Menno, it's Andrew speaking. I'll provide an update on the project status. Major construction is complete, and the platform is now operational and livable. All the subsurface work connecting the platform to the SeaRose has been finished. As Jon mentioned, we're in the final stages of commissioning and testing. Looking ahead, we will soon begin drilling. Regarding production and capital expenditures for the year, we are on track with our guidance. Our production target is between 20,000 and 25,000 barrels per day, and while I don’t have the specific capital expenditures available right now, we are also within that guidance. As the first and second wells come online, you will see production from SeaRose and Terra Nova contributing throughout the year. Our uptime and availability for production from both facilities have been strong in Q1, and you can expect a production increase in the second half of the year as each new well is added.

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.

Our next question will come from Neil Mehta from Goldman Sachs.

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?

Yes. No, it's something we obviously think about, Neil. Since I came to this company, the two things that we obviously highlighted were egress and having a strong balance sheet. And when you think about this company growing from a standing start to 1 million barrels a day over 20 years, those two 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.

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.

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.

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 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?

We really don't think about the commodity price of the day, Neil. We are kind of more value oriented 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.

Yes, Neil, I would like to add that when we examine our philosophy regarding capital allocation and the growth projects in our portfolio, it's important to note that our growth spending has actually decreased year-over-year. We have completed or are nearing completion on projects like Narrows, the Foster optimization, and West White Rose, and we’ve also included the FEP expansion. Overall, our growth expenditure is down compared to the previous year. We aim to ensure that our capital spending remains stable regardless of commodity price fluctuations. We can fully fund our growth plan even in a low $50 environment, so we don't plan to react abruptly to changes in commodity prices, whether they decrease by $5 to $10 or increase. In terms of our priorities concerning excess free cash flow, there has been no change. Our approach remains balanced between deleveraging and share repurchases. While the share price has performed well, it has not reached a level that would prompt us to reduce buybacks. We have made significant improvements in our business regarding costs, growth, and free cash flow, making it increasingly resilient and allowing us to continue buying back stock.

Our next question will come from Travis Wood from NBCCM.

I wanted to dive deeper into that topic because I find it quite interesting in terms of the rate of change. Can you discuss some of the anomalies you observed during Q4 that led to the adjusted 95%? Do the marketing and trading team have the ability to capture similar opportunities going forward? Additionally, how much does refinery downtime impact that market capture? If Whiting goes offline again in the future, can we increase our market capture during those unique quarters with other refineries undergoing maintenance?

Yes, that's a great question, Travis. I appreciate it. To start, I believe that the reliability improvements we've made in our portfolio position us well to seize market opportunities as they arise. Whenever there's a market disruption, our reliability allows us to take advantage of it, which was evident in the fourth quarter. We observed some strength in the crack until early December before it naturally declined with the winter season. I anticipate that we will remain focused on capitalizing on market opportunities as they present themselves, as it's essential to our strategy. Regarding the market, each refinery and downstream operation has its distinct configuration, and when market fundamentals align with those configurations, it leads to greater market capture. For us, having a higher consumption of heavy crude positively impacts our portfolio, particularly when the heavy differential is in our favor. Additionally, when the gas crack decreases, our diesel and jet length enables us to optimize our refinery cut points and maximize distillate production. Superior has substantial asphalt production, and when the asphalt market strengthens, it benefits our portfolio as well. This is the seasonality I referred to earlier—depending on market conditions and pricing, these factors can either favor or hinder us. In the fourth quarter, we were able to take advantage of both market opportunities and our configuration's alignment with available crack spreads.

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?

Yes. No, that's a good question, Travis. So what we've done on 34-2, 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 the 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.

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

So I think we may have got our wires crossed on our end.

I apologize for the confusion. You came up because Chris Hebert was really well.

I did indeed. So, a couple of things. I want to return to Neil's question. You completed the 3-year growth plan. Is there another growth plan, possibly more modest than the current offering? Also, related to what Kam mentioned about not significantly restricting your spending, how should we consider your capital spending over the next two or three years? This clearly connects to the level of balance sheet deleveraging, other factors being equal.

Yes. What I would say is that we do not intend to engage in large major projects again. The West White Rose is the last of those significant projects. We have a relatively low sustaining capital around the 3.6 to 3.7 range, providing us with ample capital for growth projects that meet the $45 threshold. The growth you will see from us over the next couple of years, aside from the work already outlined at the MEG asset, will focus on brownfield development, debottlenecking, and similar initiatives. For example, we have the SAGD project underway at Spruce Lake, which could add 5,000 to 10,000 barrels a day but does not qualify as a major project. You can expect to see more of these initiatives. We aim to increase production for $45 or to achieve a return on capital around that figure, potentially in the range of $10,000 to $20,000 per flowing barrel. I would suggest modeling our capital spending close to the $5 billion we've previously discussed as the upper limit, and then projecting a growth rate of about 3% to 5%.

Okay, that's helpful. Regarding the $5 billion, let's consider another $350 million. I appreciate that you are capitalizing your turnarounds, which provides good transparency. Just to clarify, would that amount include turnarounds or not?

That will include turnarounds.

Okay, terrific. Travis's question was good. I'm really interested in your Asian business. It doesn't get a lot of attention, but what does that business look like over the next two to five years? How much time are you spending there? Do you want to grow it, harvest it, or are you considering selling it?

I believe the way I view that business is that it is indeed a strong operation that generates a substantial amount of free cash flow, averaging around $1 billion annually over the past five years since we acquired it. We appreciate that it operates on a fixed price for gas while also capturing the value of liquids based on Brent prices. The operating costs are approximately $1 per M, and the fiscal take is relatively low, with minimal requirements for sustaining capital. Our approach is not about harvesting the asset but rather optimizing it, focusing on the Block 29/26, where we believe we have a competitive edge. We assess the opportunities within the block, collaborate effectively with our partner CNOOC, and value that relationship. It's an asset that we continually draw free cash flow from and reinvest wisely.

Our next question will come from Manav Gupta from UBS.

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 at 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, 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?

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 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.

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.

And there are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon 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.

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