Cenovus Energy Inc. Aktie

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Third Quarter 2026 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.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2026 Third 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. For the question-and-answer portion of the call, please keep to one question with a maximum of one follow-up. You are welcome to rejoin the queue for any other follow-up questions you may have. And for detailed modeling questions, please follow up directly with our Investor Relations team after the call. I will now turn the call over to Jon. Jon, please go ahead.

Great. And thank you, Patrick, and good morning, everybody. I'd like to begin by recognizing our safety performance and the people across Cenovus who work diligently to keep their colleagues, communities and our assets safe. Their commitment has been particularly evident during the execution of our turnarounds.

Over the past 18 months, our teams have successfully executed 4 major turnarounds, all without a recordable injury. That track record speaks to the preparation, discipline and safety culture our people bring to these complex events. For the most recent Christina Lake turnaround, we drew on experience from across our oil sands operations to help us manage significant and competing critical path work within a compressed window. The result was a turnaround delivered safely, ahead of schedule and under budget.

So now turning to our third quarter results. In our upstream business, production increased by more than 50,000 barrels a day from the prior quarter to average nearly 1,025,000 BOE per day, surpassing the 1 million BOE per day milestone. Oil sands was the primary driver of the increase, producing more than 830,000 barrels per day and setting a third consecutive quarterly production record.

At Christina Lake, we reached another all-time high of 381,000 barrels per day with continued strength at Narrows Lake and from across the redevelopment well program at Christina Lake North. This more than offset the impacts of our planned turnaround, which was completed in September ahead of schedule and with less production impact than expected. In fact, the turnaround outperformed our updated plan, which we had already improved through the revised guidance we set out in second quarter results. Through a combination of strong planning and proactive management of the water oil ratio, we're able to shorten the time line by 4 days, which allowed us to produce more oil through the plant, reducing the production impact of the turnaround by approximately 180,000 barrels.

Reservoir performance also continues to exceed expectations with Narrows Lake production reaching as high as 82,000 barrels per day during the quarter. The fifth Narrows Lake well pad is now being steamed and is expected to be online near the end of the year, which will help sustain these higher rates into 2027. At Christina Lake North, the facility expansion project remains ahead of plan, while the redevelopment well program continues to support higher production.

By the end of September, we had 22 redevelopment wells online, contributing to production of more than 115,000 barrels a day during the quarter. The fifth steam generator was brought on in early October, alongside our second new well pad since acquiring Christina Lake North. Together, these additional -- these additions support an expected 2026 exit rate of around 125,000 barrels per day, which represents an increase of about 15,000 to 20,000 barrels a day since we acquired this asset last year. At Foster Creek, production increased to an all-time high of 248,000 barrels per day, up more than 30,000 barrels a day from the second quarter. We brought on 6 new well pads so far this year following the completion of the Foster Creek optimization project. The initial reservoir performance has been exceptional.

In fact, both Foster Creek and Christina Lake, very strong well performance has resulted in our new projects producing well above expectations. At the same time, we've optimized our facilities in real time to handle more production than we previously thought possible, enabling us to produce above capacity and accelerate recovery of the resource. Moving to Sunrise. Production averaged 70,000 barrels a day in the quarter, marking the early achievement of a production target we had originally set for 2027.

That compares to production of around 45,000 barrels a day when we acquired full ownership of the asset in 2022, an increase of around 25,000 barrels per day. That performance reflects the work our people have done to implement our operating model and development practices at Sunrise, finding better ways to manage water, pressure and steam to improve reservoir performance. With our second pad on the east side of Sunrise now online and 2 other planned for next year, we'll sustain these higher production rates well into 2027 and beyond. At our Lloydminster thermal assets, production averaged over 100,000 barrels a day in the quarter. Construction is progressing on the Spruce Lake DilSAP project.

We expect that to add about 10,000 barrels a day of incremental production when it comes online in 2028. At the same time, we've optimized our production across our oil sands assets, we have maintained a relentless focus on costs. We have reduced unit operating costs by nearly $3 a barrel over the past 4 years and oil sands operating cost per barrel this quarter were the lowest that they've been since the acquisition of Husky in 2021.

The continued volume growth we have delivered, which -- the continued volume growth we have delivered with largely the same infrastructure in place has contributed to our lower unit costs. But just as importantly, this performance reflects the focus we bring every day to controlling costs and building on our position as the lowest cost producer in the oil sands.

Moving to the offshore business at West White Rose, we've completed drilling the first production well. The reservoir section has come in as expected and completion and tie-in activities are now underway. We are excited to be close to first oil from the project that will soon become an important contributor of free cash flow to this company.

Moving to the Downstream. Strong financial product pricing drove benchmark cracks to historic levels in the third quarter, and we are well-positioned operationally and commercially to capture that value.

In the Canadian refining, crude throughput reached a record of 121,000 barrels per day in the quarter or about 112% utilization. Both the Lloyd upgrader and refinery operated above rated capacity, reflecting the solid operating performance we have come to expect from these assets. Strong diesel pricing in the quarter coincided with record diesel production of approximately 18,000 barrels a day at the Lloydminster upgrader.

Now those same market fundamentals supported premium pricing for synthetic oil given its high distillate yield, contributing to exceptional financial performance from our Canadian refining business.

Turning to U.S. refining. Crude throughput was approximately 317,000 barrels a day, representing crude unit utilization of about 87% as we executed a major turnaround at Lima. The turnaround commenced in early September and was concluded at the end of October. Adjusted market capture in U.S. refining was very strong at 88%, supported by strong operating performance and commercial optimization, including moving gasoline and jet fuel into higher-value markets and drawing down inventories when pricing was attractive.

In September, we began utilizing our share of the 40,000 barrel a day expansion on the Laurel pipeline, providing another important outlet for products from the Chicago market. In combination with our continued movements from the dock in Toledo, we have increased our ability to access higher-value markets in PADD 1 and the Great Lakes region. I also want to take a moment to speak about our acquisition of Athabasca Oil.

The rationale for this transaction for Cenovus is very clear. Athabasca brings a high-quality oil sands resource base with decades of development potential, adjacent to our existing lands where we have strong understanding of the resource and its potential. Opportunities to have thermal reserves and development inventory of this scale are increasingly rare, and we have a proven track record of applying our operating model to improve performance and create value from these types of assets. Athabasca's shareholder meeting has been scheduled for November 27, and we anticipate the transaction will close in December, subject to the remaining approvals and customary closing conditions.

We have a great deal of respect for the foundation Athabasca has built and we're excited about the opportunity ahead of us with full confidence in the value that we can deliver on these assets over time. Across our business, we saw the benefits of strong execution translate into record operating and financial performance in the third quarter, and we're carrying that momentum through to the rest of the year. I'll now turn it over to Kam to walk through our financial results.

Thanks, Jon. Good morning, everyone. In the third quarter, we generated approximately $6.3 billion of operating margin and $5 billion of adjusted funds flow, both quarterly records. Upstream operating margin was over $4.5 billion, slightly below the prior quarter as lower benchmark oil prices were partially offset by production that increased by more than 50,000 BOE a day. Our oil sands nonfuel operating costs were down were $7.80 a barrel, down almost $0.50 a barrel from the second quarter, reinforcing the cost performance Jon highlighted with unit costs across the oil sands portfolio down nearly $3 a barrel over the past 4 years.

This performance reflects the disciplined way we continue to operate our oil sands assets with our technical teams optimizing existing infrastructure to deliver record production while maintaining low industry-leading SORs and strong cost control. In the Downstream, the strong margin environment and solid operating performance translated into record operating margin of approximately $1.8 billion, nearly double the prior quarter.

Canadian refining contributed approximately $420 million of operating margin, supported by record throughput and strong synthetic and diesel margins. The higher throughput also helped reduce unit costs -- unit operating costs by over $2.50 a barrel from the prior quarter to $9.70 a barrel. We also closed the sale of our Canadian commercial fuels business in August for approximately $260 million in cash proceeds after closing adjustments. U.S. refining generated approximately $1.4 billion of operating margin with adjusted market capture increasing to 88% from 67% in the second quarter, reflecting the stronger commercial and operating performance Jon discussed. Adjusted market capture in the third quarter, including the benefit of onetime items such as a Small Refinery Exemption waivers at Superior.

Excluding these items, market capture was over 80% in the quarter. U.S. refining operating costs were approximately $12.30 a barrel, up from the previous quarter due to lower throughput volumes associated with the turnaround at Lima and expense projects deployed during the turnaround outage.

Capital investment in the third quarter was approximately $1.5 billion, primarily directed towards sustaining activity, the Lima turnaround and investment in our growth projects at Christina Lake North and West White Rose. Record adjusted funds flow of nearly $625 million reduction in noncash working capital drove net debt down another $2.4 billion to the end of the quarter at $3 billion.

The working capital movement was primarily driven by an $830 million increase in income taxes payable, reflecting timing differences between accruals and cash payments, which are expected to reverse in the first quarter of 2027. We've now reduced net debt by approximately $5.1 billion over the last 2 quarters. Total royalties and taxes recognized in the quarter rose to $3 billion. At the same time, we returned $1.9 billion to shareholders during the quarter, including $1.5 billion through common share purchases under the normal course issuer bid and $403 million through common share dividends.

In August alone, we deployed nearly $1 billion towards common share purchases when we saw an opportunity to acquire our shares at what we viewed as compelling value. Our current NCIB expires on November 10, and we have received approval to apply for the renewal of the program for next year.

The unique cash-generating capacity of our business allows us to strengthen the balance sheet, invest in growth, make record royalty and tax payments to governments while returning significant cash to shareholders, underscoring our balanced approach to capital allocation.

Looking forward to the remainder of the year with our oil sands assets continue to perform above expectations and with the optimization we were able to achieve during the Christina Lake turnaround, we are now expecting full year production to come in over 1 million BOE a day, closer to the high end of our guidance range of 970,000 to 1,010,000 BOE a day. We also expect capital investment to be at the top end or slightly above our guidance range of $5 billion to $5.3 billion as a result of a longer duration of capitalizing costs at West White Rose, FX impacts in the downstream business as a result of the weakened Canadian dollar and modest increases in growth capital in the upstream in the second half of the year. I'll now turn the call back to Jon for some closing remarks.

Great. And thank you, Kam. This quarter established a new level of performance across our portfolio with the upstream production well above 1 million BOE per day and record results at Christina Lake, Foster Creek and Sunrise. More importantly, that performance reflects the underlying strength of our asset and the ways our people continue to increase productive capacity, improve reliability and get more from our existing infrastructure.

We've also worked through significant planned maintenance with the Christina Lake and Lima turnarounds behind us, we are positioned to carry this operating momentum forward. The next milestones are also close in hand. Christina Lake North is positioned to exit this year at about 125,000 barrels a day. West White Rose is approaching first oil, and we expect to complete the Athabasca acquisition in December, setting the stage for more opportunity and growth to come.

We're continuing to build a stronger operating base with more opportunity ahead and financial capacity to pursue investments that create value for shareholders while creating a more resilient company. And with that, I'm open to your questions.

[Operator Instructions] Our first question is from Menno Hulshof from TD Securities.

I'll start with a question on the heavy differential. It's clearly a lot wider than most were expecting. Shipping cost appears to be a big part of it. But I guess the question is, how is this impacting how you're thinking about upstream activity levels into 2027 and beyond? And I ask that knowing that you haven't guided 2027, but how is that sort of impacting your overall thinking?

Right now, Menno, there isn't much in the commodity pricing world that's trading off fundamentals. Geopolitics seems to be really the overriding factor. So one of the things we do is we really think about what is being driven by fundamentals versus what is more fleeting being driven by other factors that we expect to be temporary.

So the short answer is it doesn't affect our thinking at all. What we will continue to execute is our long-term plans and continue to execute on our strategy and operate well through this. But Geoff, maybe you might have some thoughts around what's going on and what's driving that wider differential and why it really isn't affecting our longer-term plans.

Menno, you kind of summarized it really well. The first thing people tend to see is WCS differentials at Hardisty get wider and then ask what's happened to Alberta congestion, which pipe and that sort of thing. And that's a historical view. This is much more driven globally.

And what you point to in the U.S. Gulf Coast is really the answer right now, which is freight, freight, freight and freight, which, as Jon pointed out, is driven by geopolitics and global events. I think looking forward through next year. And I don't know if anybody knows exactly when everything starts to normalize.

But we do anticipate through time that freight will normalize, natural gas prices globally will normalize, and that will back into the diff, which is exactly why John pointed in our long-term capital thinking, it doesn't make a difference to what we're going to do that way. However, as we execute in and around commodity transactions, we do look to the fact that the West Coast is attractive right now relative to the Gulf Coast, and that just allows us to use the assets we have to optimize our netbacks.

Yes. It's funny Menno. I see Eric smiling because this is actually good for his business. And the first 250,000 barrels a day of our heavy oil runs through his assets, and he captures all of that dislocation today. So I'm sure a question is coming later on about 70% market capture, and we'll put that on Eric to kind of bake in his thinking there.

Terrific. Yes. No, that's really helpful. And it's actually a good segue into the next question. And I won't ask the market capture question, but maybe it's somewhat related. Refined product egress out of PADD 2, I know you've been working on this a lot.

You mentioned doing -- in your prepared remarks, you mentioned doing more on the Laurel pipeline, getting more into the Great Lakes region. But would you just be able to maybe elaborate on what that looks like from a volumes perspective, the potential margin uplift? And I guess market capture is part of that as well.

Yes. No, we've been doing a lot of work on that, and I'll get Eric to comment on it, but we've been doing a lot of work on the dock at Toledo, and I mentioned the Laurel pipeline is now active, and we look at our terminal positions as other ways to mitigate any kind of congestion issues. And then longer term, the project that Phillips 66 is put forward should give us some real structural decongestion of PADD 2. But Eric, why don't you talk about the work that we're doing to optimize our product margins?

Yes. Thanks, Jon, and I appreciate the question. I think Jon summarized it well. I mean as we look at PADD 2 and just look at our facilities, always looking for how do we find the highest netback and how do we place our products in the right market. Having the dock at Toledo is absolutely an advantage for us.

And the team did a really good job in Q3 of really optimizing the barrels in the Ohio Valley region. So that's both the Toledo and Lima refineries to make sure we're placing the products into the markets that are most advantaged. And so we saw record performance through the Toledo dock. We have a number of investments that we're looking at to just continue to strengthen that facility and continue to look at how do we expand through the dock into a number of different markets, which we're pretty excited about.

The Laurel pipeline is, I think, another example of how the region and the industry is balancing product flows and seeing the opportunity to help supply positions further to the east. And so being able to get on to that pipeline and moving some barrels already and then looking forward into Q4 with more barrels flowing that way. Again, we just see a tremendous opportunity to help reduce some of the congestion in PADD 2, but really access some of the more advantaged markets that we're seeing there in PADD 1.

So we'll continue to look at the different markets we can access, but we've got a great team that is continually looking to optimize and really excited about being able to continue to advance our positions there.

Next question is from Greg Pardy from RBC Capital Markets.

And my goodness, impressive top to bottom with the numbers in the quarter. I wanted to stay just with the downstream, not so much necessarily on the margin capture. But I mean, there's -- when we talk about growth, right, there's typically a big focus on upstream. Are there any downstream either margin or growth projects that would begin to enhance your heavy oil processing capacity or just perhaps distillation capacity in general?

Yes. We're always looking, Greg, at things that we can do, both on the assets as well as what we can do commercially. And in refining, you typically have 3 levers. You've got the crude feedstock, you've got the product placement and then you've got your operating costs that sit right in the middle.

And the value proposition or the magnitude of the value proposition is kind of in that ordering. And we certainly are looking at a number of things that we can do operationally as well as commercially to kind of optimize that. But maybe I'll turn it over to you, Eric, you can talk how you're thinking about the business in terms of margin expansion through the portfolio that you've got.

Yes. Thanks for the question. One, I would just probably reiterate Jon and Geoff's point, I think with these heavy differentials, it really reinforces the value of the integrated model. I think the value of having a downstream in the heavy oil value chain really becomes very clear. And this quarter, I think, is a great example of that and certainly looking at the wider heavy differentials to again, reinforce why we have a downstream.

As Jon said, I think as we've really worked to get reliability up and manage our sustaining capital, it's created the opportunity to look more at some of the growth opportunities. And some of that comes in a variety of forms. I just spoke to market access and so continuing to invest in the Toledo dock to be able to place barrels and more barrels into more advantaged markets.

We're looking at how do we improve our yields and how do we get more distillate and jet and diesel yields, how do we continue to optimize across the Ohio Valley region and really unlock some of the synergies that we see that we're pretty excited about. Even in Canada, we're seeing opportunities to invest in those facilities and just grow the margin with the barrels we're running. We've done a -- team has done a really good job of expanding throughput there, and we see opportunities to improve the yields to get more advanced products as we go.

So a number of different investment opportunities we're looking at to just grow within our existing facilities, improve market access, improve yields and just continue to make the business more robust and strengthen that integrated heavy oil value chain that we've built.

Okay. Very good. And then just completely switching gears. The 9.9% stake in Athabasca, is that just essentially an insurance policy ahead of the vote, like should an interloper emerge? Just curious on that.

Yes. I wouldn't read too much into that, Greg. At the end of the day, we would view we're going to be buying those shares anyway, and we're pretty clear about how we're going to vote those shares. So it's just a bit of an insurance policy that adds to deal certainty, which is something we're always looking for.

Next question is from Neil Mehta from Goldman Sachs.

Jon, congrats on the results. A quick one on West White Rose. Just give us a mark-to-market on where we stand there. It sounds like it's getting pretty close to first oil here. And how are you thinking about the pace of start-up through 2027?

Yes. I'll let Andrew provide more color on it. But as I mentioned in my notes, the first well has been drilled, and we're well into completing that well and tying it in. So we're looking forward to first oil, which is imminent. This is a project now that is it's derisked the right thing for us to do is let the technical teams finish this well and bring production online. And what you should expect going forward is the first well package is 7 wells, and it's 5 producers and 2 injectors. And you should be -- we should be on a pace where kind of every 90 to 100 days, you'll see the next well come on. So Andrew, maybe a little bit more color on how you're seeing the project?

Yes. No, if you think about it, we did finish just TD, the first production well, completing that as we speak. We'll get that on production shortly. And just to reiterate and put some more color on what John just spoke to, we then go into a state of concurrent operations on the wellhead platform. We will have production operations from the first well. And concurrently with that, we will actually start drilling the second well.

And then on an average of sort of every 90 days or so, we will put subsequent production wells on. So obviously, first production well on here this year, second production and third and fourth production wells on in 2027. And then we'll just complete -- continue doing that through the next 4 or 5 years, ramping production up to on a gross level, roughly 80,000 barrels a day by 2028, 2029.

Yes.

And then Jon, on operating costs in oil sands continue to trend well. As you get more scale in this business, how should we think about the operating cost profile as we move into next year, especially because there are some signs of inflation in the underlying system, too?

Yes. One of the things I'm incredibly proud of is the way that our upstream business and particularly our heavy oil business just continues to find ways to grind costs out of our business, doing it on a quarter-after-quarter basis. But I think in our oil sands business this quarter, we were down to $10 a barrel across the portfolio. And it's not just scale, Neil. Like this is coming across all the different asset groups that we've got, whether it's Lloydminster, Sunrise or FCCL. So there's certainly a piece of it where the volumes and working on the denominator of those unit costs has really paid dividends. But it's more than that. It's the operating model. It's getting the maintenance cost down. It's getting the chemical cost down, and it's just finding ways to continue to do things better.

So one of the things about this business that I firmly believe is this is a commodity business and the low-cost producer wins. And across our oil sands base, we're not only the biggest producer, but we are the lowest cost producer as well. So I'm just incredibly proud of the work that we've done.

And as we kind of look into 2027, I think you're right, we are going to get some inflationary pressure across this business and across this industry, but I'm pretty confident that we're going to be able to beat a lot of this back. And that's kind of been our history. It's what we expect from our people. and putting more volume through a fixed cost base helps that. But we're always focused on our unit costs and keeping those very, very competitive relative to the peer group.

[Operator Instructions] Next question is from Travis Wood from NBCCM.

Question is around the change in policy in Alberta around the Caribou lands. And I'm trying to get an understanding and making sure that I understand the process in terms of what that could mean for organic opportunities within Cenovus, whether that's through parts of even Athabasca.

But I think I'm more so thinking about Surmont from the MEG transaction. Does that change in policy significantly change the kind of near-term to midterm growth plan for brownfield expansions kind of like you did over the past 5 years?

Yes. I think we -- there's a lot being made of the land sale, and we're obviously looking at this and looking at this actively. I don't know that it changes any of our strategy, Travis. I think we look at things incrementally versus something that's going to fundamentally change the direction that we're going. So we're looking at what's become available. We're doing our analysis. We're trying to think through some of the uncertainty that you referenced with regard to the regulation in and around this. But we think about it the same way we look at everything.

It's another opportunity that's going to come across our desks, and we're going to properly evaluate it and think through what synergies that might add to the assets that are inside the portfolio and how we might add value from it. But to the point you mentioned, there's still a fair amount of uncertainty around how this is actually going to manifest itself, but don't think about it as something that changes our strategy or operating plans materially.

Okay. That makes sense. And just so I understand, is -- would there be land within Cenovus that you own the oil sands leases to that would be sitting on Caribou lands that could potentially become open without having to participate in the sale?

I think the way to think about it is there could be oil sand leases that become available through this process, where before they weren't available because they were in areas that were designated as Caribou lands that were sterilized.

Okay. No, that makes sense. Okay. And then last question, if you can entertain us with this, just in terms of what is the MOU discussion? How is that process going? And how can we think about kind of the critical path from here over the next couple of weeks or maybe 3 months?

You know what I could give you my take on it, but Jeff Lawson is kind of right in the middle of this, and maybe he can give you a much better answer than I can on his view of how this is progressing.

Hey, Travis.

Hey, Jeff.

I think we have some incredibly nuanced bespoke agreements to hammer out, and they're tough because they're new. No one's drafted them before, and that's around carbon capture, 6 megatons, incremental 10 megatons. But what you should take away is that both levels of government, the Feds and the province have been excellent to deal with. They've been pragmatic.

They're trying to push us ahead. So if you look at what we've got so far, we've got the Mega Productivity Deduction. We've got changes to the Impact Assessment Act, which really give primacy to Alberta. So we don't have a bunch of oil sands stuff locked up because of the Impact Assessment Act. We've got the West Coast Oil Pipeline as a project of national interest, both levels of government and the shift to the BC government now wanting to all get that done. It's all positive. On the Alberta side, the premier publicly said they're going to come out with their growth incentive royalty. and they're going to come up with some modifications to supports for the system. So it feels like all this stuff is coming together in the right place. Now we need to hammer out actually the trade-off for that, which is what our 6-megaton carbon capture project looks like.

All the companies are aligned in hammering that out if we have all the supports in place. So it's all coming together. November 15 is a pretty tight time line to get all this stuff done, but we're working towards that. And I guess we'll play it week by week if we actually hit that time line. But we are on a path. We're not falling off the path, and we're pushing forward on it.

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

Thank you, operator. So this concludes the conference call. Thank you all for joining us. We appreciate your interest in the company. 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.

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Conference Call regarding the acquisition of Athabasca Oil Corporation. [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.

Thank you, operator. Good morning, everyone, and thank you for joining us to discuss Cenovus' proposed acquisition of Athabasca Oil Corporation announced earlier today.

On the call today are Cenovus' CEO, Jon McKenzie; and CFO, Kam Sandhar. In a moment, I will turn the call over to Jon and Kam to discuss the transaction. We will then open the line for questions. Along with the news release issued this morning, we have posted a presentation with additional details in the Investor Relations section of our website.

Before we begin, 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. Unless otherwise indicated, all figures discussed today are in Canadian dollars. [Operator Instructions]

I will now turn the call over to Jon. Jon, please go ahead.

Great. Thank you, Patrick, and good morning, everybody. Today, Cenovus announced that we have entered into a definitive agreement to acquire Athabasca Oil Corporation in a cash and stock transaction valued at about $5.7 billion or about $12 per share. This transaction builds on a strategy that has been at the core of Cenovus for decades. We have spent more than 20 years developing, operating and growing SAGD assets at scale. Throughout that time, our operating model has continued to evolve as we have advanced technology, refined our development practices and incorporated new learnings from across our portfolio.

The result is an approach that consistently delivers industry-leading performance that has become one of Cenovus' clearest competitive strengths. That competitive advantage is what underpins our confidence in and excitement for this transaction. The rationale for this transaction for Cenovus is clear and obvious. Athabasca brings a high-quality oil sands resource base with decades of development potential ahead of it. It adds approximately 1.3 billion barrels of 2P reserves and approximately 2.3 billion barrels of 2P plus contingent resource. That implies best-in-class reserve life index of approximately 75 years and a resource life of approximately 140 years.

These are long-life assets located in an area where Cenovus already has a deep operating experience and strong understanding of the resource. They also represent one of the only remaining large-scale opportunities to add meaningful thermal reserves, resource and future development inventory within the core of the oil sands. That combination of quality, scale and long-term growth is particularly compelling.

Our confidence in this transaction is grounded in a track record that has been built over many years. We have consistently demonstrated our ability to improve performance and unlock additional value through the application of Cenovus' operating model and through a proven track record of profitably delivering over 30 phased expansions. We have done that across the assets we have acquired, and we have done that across the assets that have been part of Cenovus since the beginning.

From Foster Creek and Christina Lake to Sunrise, Lloydminster and most recently, Christina Lake North, we have continued to improve the operating performance, enhance capital efficiency and to grow production through disciplined execution. We have also demonstrated the ability to advance major growth projects successfully, integrate acquired businesses and deliver on the commitments we make.

Let me spend a few minutes on how we think about creating value from these assets. Athabasca's thermal assets produce about 40,000 barrels a day. Through a combination of existing asset optimization, Leismer expansion and future development to Corner, we see an opportunity to increase thermal production to approximately 115,000 barrels a day by 2032. That represents one of the most significant organic growth opportunities available in Canadian oil sands today.

In the near term, we see opportunities to increase production through an expanded redevelopment well program and targeted optimization initiatives at Leismer and Hangingstone. We also see an opportunity to increase production from Leismer to more than 60,000 barrels a day through debottleneck and facility expansion. By executing on this plan, we can reduce the steam-oil ratio by about 20% and deliver brownfield growth at an attractive capital efficiency of $35,000 per flowing barrel.

Beyond Leismer, Corner represents a significant future growth opportunity that Athabasca has spent years advancing and derisking. This is where we have the ability to accelerate and execute that development plan. We bring leading SAGD operating expertise, a proven project execution capability and the experience required to advance multiple opportunities at the same time. We also have a strong balance sheet that supports our ability to fund these opportunities through all points in the cycle.

By bringing forward and consolidating multiple phases of expansion, our development plan contemplates advancing Corner to approximately 40,000 barrels a day by 2032, 3 years earlier than the current development plan. When combined with the existing asset optimization opportunities, these projects support thermal production of approximately 115,000 barrels a day by 2032.

By looking at the combined set of opportunities in the thermal business, our fully accelerated development plan would involve approximately $700 million to $800 million of annual capital investment through 2030. That includes about $200 million per year of sustaining capital plus the growth capital that would be required to advance the expansion at Leismer and advancing and accelerating the Corner project.

Another unique aspect of these assets is the proximity to some of the existing undeveloped resource we have in our portfolio, including Thornbury and May River, which together hold an estimated 550 million barrels of recoverable resource. Now when we developed Narrows Lake, we proved out our ability to move steam over long distances to more efficiently capture nearby resource.

This transaction creates the possibility in time to access those resources without building a new greenfield processing facility, opening the door for additional capital-efficient growth options in our portfolio. And we are encouraged by the pace at which the governments have recently moved to support major resource developments in Canada. Both the federal and provincial governments have made positive changes and are working to finalize arrangements to making investing in Canada and the energy business competitive again.

Recent announcements around tax policy, royalties, new pipelines and regulatory efficiency are important steps in the right direction. These steps will have a meaningful impact on our ability to advance growth projects like the ones we are contemplating at Leismer and Corner. We remain committed to working constructively with governments to reach definitive arrangements later this year, which support production growth by implementing competitive regulatory and policy reforms.

While the thermal assets are the primary driver of this transaction, Athabasca also brings the opportunity to consolidate ownership of the Duvernay Energy Corp., strengthening our position in a high-quality oil-weighted resource play. Duvernay Energy Corp. has assembled an attractive inventory within the Kaybob fairway and full ownership gives us more control over the pace of development going forward. The Duvernay asset is currently self-funding and producing about 5,000 barrels a day with the potential to grow and sustain 20,000 BOE per day with additional investment. Together, this transaction adds high-quality reserves, significant growth potential and a development runway that extends for decades.

We've also identified about $85 million of annual corporate and commercial synergies, which we expect to capture promptly following the close of the transaction. These are expected to come from reduced G&A and financing costs along with optimization of transportation and marketing arrangements. We believe that Athabasca is a natural fit with our strategy and a strong addition to the Cenovus portfolio.

I'll now turn it over to Kam to walk through the financial aspects of the transaction.

Thanks, Jon, and good morning, everyone. Before I walk through the details of the transaction, I want to briefly touch on our current financial position.

Cenovus' business performance remained stable and consistent through the third quarter with production throughput continuing to perform well through to the end of September. This strong operational performance and favorable commodity price environment put the company in a position where net debt at September -- at the end of September ended at approximately $3 billion. We continue to not only strengthen our balance sheet, but also returned $1.9 billion to shareholders through dividends and share repurchases through the third quarter.

Our continued operational performance, coupled with strong commodity prices, has resulted in significant debt reduction complemented with returning cash to shareholders while positioning us well to move forward with this transaction.

Turning to the transaction itself. We have structured the acquisition to balance 3 important priorities: first, maintaining a strong balance sheet and investment-grade credit ratings; second, minimizing dilution to our existing shareholders; and third, preserving flexibility to continue to return cash to shareholders and fund attractive growth opportunities across the combined portfolio.

The transaction is valued at approximately $5.7 billion. The consideration will be composed of up to maximum 75% in cash or a maximum of 35% in Cenovus shares with the final split determined by shareholder elections. Assuming the 75% cash consideration, this equates to approximately $4.3 billion of cash and the issuance of 32 million shares. The cash portion of the transaction will be funded through cash on hand and existing Cenovus credit facilities.

Following completion of the transaction, at current strip pricing, we would expect net debt to fall between $5 billion and $5.5 billion by the end of 2026. That equates to well under 0.5x net debt to adjusted funds flow at strip pricing. There is no change to our commitment to maintain strong liquidity and our mid-BBB investment-grade credit ratings.

And with share buybacks totaling 34 million shares during the third quarter, we've already offset the shares we expect to be issued through the transaction. We believe the structure appropriately utilizes the strength of our balance sheet while limiting dilution to existing shareholders.

The transaction is expected to be accretive to adjusted funds flow per share in 2027, including the impact of synergies. Importantly, this acquisition does not change our approach to capital allocation. We remain committed to maintaining a strong balance sheet, investing in high-return opportunities and returning excess cash to shareholders.

I'll now turn the call back to Jon for some closing remarks.

Great. Thank you, Kam. When I step back and look at this transaction, what stands out is the quality and the duration of the opportunity. Athabasca brings approximately 1.3 billion barrels of 2P reserves and a thermal asset base with a reserve life in excess of 75 years. I'm confident that we can put our people and operating model to work across this asset base, accelerate development and maximize its potential over the coming years. It adds meaningful opportunity to our long-term growth plans and expands the opportunity set available to Cenovus and our shareholders. Combined with our existing assets, it further strengthens our position as Canada's leading SAGD producer. We believe it's a natural fit with our strategy and a strong addition to the Cenovus portfolio.

And with that, we'll be happy to answer your questions.

[Operator Instructions] The first question comes from Neil Mehta with Goldman Sachs.

Congratulations on the transaction. I guess, Jon, how much of this was about getting access to existing production in PDP versus the growth initiatives here? And to the extent part of what you're paying for is the growth optionality, can you spend a little time unpacking both the opportunity at Leismer and at Corner?

Sure. And you're right. I think one of the things that I would note, not only is this a really high-quality set of assets with resource depth. But one of the things we like about both Leismer and Corner is just the quality of the asset in there. We talked about rich pay in this company, and this is a set of assets that have deep quality resource potential going forward. So it's not just about the magnitude of the resource, quality is a key differentiator.

And one of the things that we find in this basin, Neil, is you sometimes end up with these scenarios where companies own a significant resource and they've undercapitalized it over the years for a variety of reasons. And then we have the ability to come in and accelerate that growth. And when we apply our operating model, we can take advantage of some efficiencies as well.

So when we look at Leismer right now, there is a debottleneck that is largely paid for and in place that will take that asset to 40,000 barrels a day, and we expect to get there in early to mid-2027. And then beyond that, we have an opportunity to take that to 60,000 barrels a day through brownfield debottlenecking of the existing plant as well as accelerating some future well pads.

And one of the things that excites us about Leismer, as we go forward, we kind of see the SOR in those well pads being somewhere around the 2.5 range, which is kind of best-in-class. So that is a tremendous resource. We've identified 60,000 barrels of potential production over a reasonably short period of time. And again, that resource is something of the highest quality.

Corner is probably, we think, one of the most prolific undeveloped resources in the basin. We've identified a project to take it to 40,000 barrels a day, but on an accelerated time frame. And what excites us about that, again, is it's going to have a low SOR and lots of room for us to optimize as we go forward. So really, in our minds, this is about taking a piece of real estate that is strategic. It is of the highest quality, and it gives us the ability to accelerate future growth as well as apply sort of optimization based on our operating model.

We've already kind of defined about 80 redevelopment opportunities, both at Hangingstone and at Leismer. So we're very confident that in the short term, you're going to see a production bump. And then over the next 5 years or so, you're going to see a realization to the numbers that I talked about.

Yes. And then just a follow-up. This might be for Kam, but you guys have this tiered percentage of your excess free funds flow to shareholder returns. And if I remember, between $4 billion and $6 billion, you're 75% back to shareholders and below $4 billion, you're 100%. So this will get you to around $5 billion, $5.5 billion by year-end. So is it fair to say through this process and into next -- early next year, we should be thinking 75% still to shareholders and the other 25% to debt reduction?

Yes. Good question, Neil. So I think first, what I'd start with is those -- that framework obviously has been in place for a number of years. And I think one of the things we've highlighted continuously is it is it's not formulaic, it's principal-based. So any decision we make around shareholder returns, investing in the assets and buying back our stock as an example, it's going to be a value-based decision. I would say we continue to see value in buying our shares. So we'll -- as I mentioned, we've paid back about $1.9 billion through the third quarter. I think that's the highest it's been through this year.

So we'll continue to look at that as an opportunity. What you should expect from us is a balanced approach. We're going to continue to invest in our assets along with these -- the growth options that we were adding into the portfolio, but we'll continue to be balanced around returning cash. So use that 75% as a guideline. We will adjust accordingly where we see value opportunities.

Our next question comes from Travis Wood with NBC.

Question would be kind of a bit of a follow-on to Neil's there, but what would be the governors around the pace of growth? Like obviously, you're sitting with some pretty epic resource ahead of you. So what -- why is it 115 by 2032? And is this kind of building into your egress outlook as we look at egress options kind of west and south?

Yes. We have -- one of the things that this does for us as well, Travis, is it just increases our ability to be opportunistic. So we have a number of avenues with which we can add value for shareholders on a per share basis, whether that is deleveraging, whether that is buying back our stock, dividends or future resource growth. So this just increases that sense of balance that exists across our portfolio, and we're excited about the opportunity to take advantage of that.

Another piece in here that is important, that is the fiscal framework with which we exist within. And I mentioned in this that having the federal government come forward with accelerated capital cost allowance is not immaterial to this. And we also expect to see growth incentives for -- on the royalty side with the province of Alberta. So all of that kind of fits together to kind of draw capital back into the resource in the Athabasca Basin and probably accelerate growth as well.

So we're looking at a number of different things, but what we really like about what we continue to do is we just create this balanced portfolio where we have a really healthy company in terms of the resource availability in front of us. We have a bulletproof balance sheet, and we have the ability to get value back to shareholders through multiple channels as we become more and more opportunistic.

Okay. And the follow-up, kind of a follow-up but separate question, just around you've done now consolidated MEG. You have kind of best-in-class thermal assets across the basin now with this Athabasca purchase. How are you guys thinking about, especially with the Suncor news overnight? How are you guys thinking about those East Coast Canada assets fitting into the portfolio kind of over the next 5 years?

Yes. We really like West White Rose. We're invested in that and production there is imminent. So I'm sure Suncor had their own reasons for doing what they did, and we continue to see that as a profitable area of the world in which we exist. And we understand what our footprint is there. We understand what our competitive advantage is within that footprint. So I don't think it's ever going to be something that is materially bigger than what we've got today, but we are excited about bringing on West White Rose and look forward to first production there.

Thank you. At this time, we have no questions in the queue. So we will wait a minute to give you the chance to connect with us. [Operator Instructions] Thank you. There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. And thank you, operator. So this concludes our conference call. I'd like to thank everybody for participating and wish everybody a great day. Thank you.

Thank you. This does conclude the program. You may now disconnect.

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Second Quarter 2026 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.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2026 Second Quarter Results Conference Call. On the call this morning are 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 referenced on the call today will be in Canadian dollars, unless otherwise indicated. 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. For detailed modeling questions, please follow up directly with our Investor Relations team after the call.

I will now turn the call over to Jon. Jon, please go ahead.

Great. And thank you, Patrick, and good morning, everyone. As always, I'd like to begin by recognizing our safety performance and those who protect our people and our assets each and every day.

On May 19, we safely completed the Foster Creek enhanced sulfur recovery project ahead of schedule and on budget. This is the fourth major project our projects group has safely and economically delivered over the last 14 months. After 24 months and 600,000 hours of work, [indiscernible] cost unit was put into service, marketing our first application of this technology in SAGD operations. The project improves how we manage Salford Foster Creek. It lowers chemical operating costs by $0.50 to $0.75 a barrel, supports regulatory compliance and removes about 700 trucks per year from the road at site. Most importantly, though, with an established track record of consistently bringing projects online, on time and on budget with outstanding safety performance, we continue to see our projects organization as a competitive advantage for Cenovus.

So now turning to our results. This was another strong quarter for Cenovus, and we're well positioned for continued performance and growth through the remainder of 2026 and into 2027. I Market conditions were supportive and our people ran our assets very well through the quarter. The outcome was our best quarterly financial result ever. In our Upstream business, production averaged more than 970,000 BOE per day this quarter. This included oil sands production of over 786,000 barrels per day exceeding the production record we set in the first quarter. We've continued that momentum into the third quarter with July monthly production for the company well on track to average over 1 million BOE per day. This will be the first month the company has achieved this milestone, which is a testament to the quality of our people and assets as well as our resilient culture.

Our largest oil sand asset, Christina Lake, continues to be the most material contributor to our strong production performance. Production in the second quarter reached a new all-time high of 372,000 barrels per day, supported by the ramp-up of Narrows Lake and the initiation of the redevelopment well program at Christina Lake North. Narrows Lake continues to exceed its expectations and is now producing over 80,000 barrels per day, much earlier than planned. This is contributing to Christina Lake averaging about 400,000 barrels a day for the month of July. The Narrows Lake acid is one of the highest quality SAGD assets in the basin, and the growth we expected from Narrows Lake is coming much sooner than forecast. Notably, we reached that production rate we expected to get from the first 5 well pads from only the first 4 well pads and we expect to bring on the next Narrows well pad later this year.

At Christina North, the integration work is progressing seamlessly. We have delivered on all the upfront commercial and corporate synergies and remain on track to increase production to 150,000 barrels a day by 2028. We're seeing production volumes from Christina Lake North respond well with current rates reaching above rated capacity of 110,000 barrels per day. As our redevelopment program progresses and with our first new pad since the acquisition now online and performing well and with the commissioning of the fifth OTSG later this year, we expect production from this field to increase in the second half of the year. In the third quarter, we will conduct a plant turnaround on Phase F and G at Christina Lake. As always, we continue to optimize the scope and execution of these major maintenance events to reduce the duration, cost and production cost.

As a result, we've shortened the planned duration of the turnaround by 9 days and reduced the expected production loss by over 700,000 barrels, representing more than 20,000 barrels per day of increased production over the turnaround duration. The efficiency of our turnarounds in the oil sands has become a real competitive advantage for Cenovus. The redundancy, interconnectedness and isolation we have built into our plants over the past 2 decades, allows us to reduce the scope of scheduled turnarounds and optimize production inside the turnaround windows as well as under normal operating conditions. Combined with the optimization of the Foster Creek turnaround earlier this year, we are now on track to produce over 1.2 million more barrels than were budgeted during the turnarounds this year. This has been reflected in our revised annual guidance.

At Foster Creek, production in the quarter was approximately 215,000 barrels a day. The asset exited the quarter at record production levels of 245,000 to 250,000 barrels a day which continued through July. As mentioned earlier, we also brought on a sulfur recovery unit well ahead of schedule, which is expected to reduce operating costs at Foster Creek by $0.50 to $0.75 per barrel.

Moving to Sunrise. Production was nearly 66,000 barrels a day during the quarter, following the startup of the first well pad in the East development area. With continued strong performance at Sunrise, we are now regularly exceeding 70,000 barrels a day of production, a target originally planned for 2027. We're also seeing consistent contribution from our Lloydminster Thermal assets, where production averaged 103,000 barrels a day for the quarter. Strong results from the redevelopment program continues to deliver production ahead of our expectations at Spruce Lake, Pikes Peak, [indiscernible] Valley. With the continued -- with the increased productivity, we are delivering at each of Christina Lake, Foster Creek and Sunrise, we are increasing our full year production guidance for the company to the range of 970,000 BOE to 1,010,000 BOE per day with no change to our capital investment guidance. We're also reducing unit cost guidance, reflecting higher production increased utilization rates and continued cost discipline.

At West White Rose drilling of the first production well remains on track, and we expect to reach first oil in late Q3. At this point, we expect the increase in contributions from the East Coast to meaningfully support production growth and the cash flow profile. Now moving to the downstream business, strong operational availability across our assets saw us capitalize on a supportive pricing environment in the second quarter. The Canadian refining business delivered crude throughput of 102,000 barrels per day or utilization rate of roughly 94%. Operations in the quarter included scheduled maintenance on the second train of the hydrocracker at the Lloyd Upgrader, which was delivered under budget setting the stage for consistent operations in the second half of this year and all the way through 2027.

In the U.S. refining business, market conditions were highly favorable in the second quarter, supported by low Midwest inventories, robust crack spreads and wider heavy oil differentials. Crude throughput averaged 350,000 barrels per day or approximately 96% utilization. The business continues to run well generating material adjusted cash flow for the company, and we are well prepared to execute the turnaround of the [ Lyme ] integrated unit in September, October this fall. All in all, Cenovus had a very strong quarter, and we expect that trend to continue as we continue to execute against our business plans.

Now I'll turn it over to Kam to walk through our financial results.

Thanks, Jon, good morning, everyone. In the second quarter, we generated approximately $5.9 billion of operating margin and $5 billion of adjusted funds flow, both all-time highs for Cenovus. Upstream operating margin was over $4.9 billion, increasing from the prior quarter due to higher benchmark oil prices and increased oil sands production. As John mentioned, with stronger production volumes and cost performance across the business, we've updated our full year operating cost guidance with reductions to each of our oil sands, conventional and Asia Pacific costs.

Our Oil Sands nonfuel operating costs were $828 a barrel, a reduction of almost $0.65 a barrel from the prior quarter. In our Conventional gas business, costs declined by nearly $0.50 per BOE quarter-over-quarter to $9.13 per BOE, reflecting an ongoing focus on cost control. In the Downstream, strong refined product pricing, widening heavy oil differentials supported a favorable margin environment. Operating margin was approximately $1 billion in the quarter, this included $144 million inventory holding gain between our Canadian and U.S. refining segments. That performance is supported by disciplined cost control and strong operational availability across our refining network.

In the Canadian refining business, full year operating cost guidance is lowered by $1 per barrel to $11 per barrel at the midpoint, reflecting increased throughput guidance and lower repairs and maintenance. U.S. refining operating costs were $10.55 per barrel, almost $1.20 per barrel lower than the previous quarter, reflecting higher throughput volumes combined with lower energy and electricity prices. Adjusted market capture, as John mentioned, was 67% decreasing from the prior quarter with the rise in Midwest gasoline pricing and the lag in asphalt and secondary product prices. Capture is also impacted by temporary dislocations in domestic light crudes, including Bakken, Midland, WTI, which increased feedstock costs during the quarter.

Capital investment in the second quarter was approximately $1.2 billion, supporting sustaining activity across the business alongside our in-flight growth projects at Christina Lake North, Sunrise, Foster Creek and West White Rose. We expect capital spend to be higher in the second half of the year as we continue to execute our program and maintenance activity increases with the planned turnaround at our Lima Refinery. Capital guidance for 2026 remains unchanged at $5 billion to $5.3 billion. With record adjusted funds flow in a nearly $700 million reduction in noncash working capital, net debt decreased to $5.4 billion at the at quarter end, representing a $2.7 billion reduction in 1 quarter. The reduction in working capital was partly driven by a $690 million increase in income tax payable due to our strong financial results.

If commodity prices remain elevated, we expect income taxes payable to continue to increase in the second half of '26 before unwinding in the first quarter of '27. With our revised guidance, we expect cash taxes to be $2.3 billion to $2.6 billion, of which a significant portion will be paid in February of 2027. During the quarter, we fully repaid the remaining $2.2 billion outstanding on the term loan that was obtained as part of the MEG acquisition in November. Reflecting the strength of the quarter, total royalty and tax payments rose to $2.7 billion. Shareholder returns in the second quarter were $1.4 billion, including $1 billion in common share purchases through the NCIB and $411 million through common share dividends. These outcomes highlight the significant value created for all of our stakeholders, including meaningful contributions to the province and the government in Canada via royalties taxes returns to shareholders and ongoing debt reduction.

As our net debt is now below $6 billion as per our revised financial framework we set out when we announced MEG will be increasing targeted shareholder returns to 75% of excess free funds over time while continuing to progress towards our long-term net debt target of $4 billion. Our shareholder returns targets should continue to be viewed as guidelines, and we will continue to exercise judgment, and maintain flexibility in where we allocate capital in a particular quarter to maximize value and focus on returns for our shareholders.

I'll now turn the call back to Jon for some closing remarks.

Great. Thank you, Kam. So as I reflect on the quarter, what stands out is the consistency of our execution and the opportunities which our people continue to find to get more out of our assets. We would never apologize [indiscernible] credit for a higher commodity price environment, but the key is to run well at last and capitalize on the opportunity. Across the business, we delivered on our commitments, outperformed our plans and built momentum for will be a strong second half of 2026.

We're now seeing the payoff from years of disciplined investment and operational and technical focus. All of our growth projects in the oil sands are nearing or have exceeded full rates, while we continue to find ways to optimize performance. At the same time, our integrated business model continues to be an advantage. Our strong refinery availability provides reliable destination for our growing production, allowing us to capture the benefits of a robust downstream environment while minimizing our transportation costs and commitments.

Now I'd be remiss if I did not also briefly address the trilateral agreement which members of the Oil Sands Alliance have entered into with the federal and Alberta governments earlier this month. While the MOU was only a first step, the agreement represents meaningful progress towards creating a competitive investment environment for Canada's vast oil sands resource base. Although the MOU still provides provisions for an uncompetitive carbon tax that uniquely burdens Canadian industry, it creates a framework for governments and industry to work together on production growth emissions reduction and expanded market access.

Most importantly, by acknowledging and committing to the need to put a competitive policy and regulation in place to support meaningful growth in Canadian oil sands as well as appropriate fiscal frameworks to support political priorities on carbon capture, the agreement establishes an important foundation for future investment in development. Cenovus is committed to working with our partners in both the Canadian and Alberta governments to work towards definitive agreements to make this reality. What matters most is this agreement signals a willingness to work together to grow the oil and gas sector for the benefit of all Canadians. This is an important step to get our economy moving forward again, creating high-paying jobs for Canadians and generating tax and royalty revenue to support Canada's quality of life and standard of living.

And while the opportunity set for industry is expanding, our approach will be unchanged, we'll continue to responsibly develop resources, support our communities in which we do business, be disciplined to allocate the use of capital and run our business to the long-term benefit of our shareholders and stakeholders. And with that, I'll open it up to questions.

[Operator Instructions] The first question is from Greg Pardy with RBC Capital Markets.

And another really, really strong quarter. Good to see. Jon, within the release, what [indiscernible] a little bit is just the sanctioning of the solvent-aided SAGD projects. I know it's -- I mean it's not nothing, right? It's 10,000, 15,000 barrels a day. What's your thinking about broader implementation of SAGD over time?

Yes. So Greg, we believe that solvent assisted SAGD has targeted application in some of the areas that we have within our portfolio. So this will be the first commercial application of that inside our portfolio. So you're quite right earlier in this year, we sanctioned the project in Spruce Lake to bring on kind of 10,000 barrels a day in 2028 time frame.

What we expect from that is there may be broader application within the Narrows Lake portfolio and some of the other parts of our business. But as we've always been really clear about in this business, SOR is king, and this is a way to get the SOR down, get more volume for less time. And there's some applications, as I mentioned, across some of our portfolio. But Andrew, maybe you want to address a little bit or 2.

Yes. No, happy to. Greg Yes, indeed, as Jon said, this is a targeted application of solvents and we're doing it in a high-quality reservoir in Saskatchewan [indiscernible] Spruce Lake. And what we're really hoping to achieve here is actually a production increment of about 40% to 50% and an SOR reduction of about 30%. We see similar applications in high-quality reservoirs across our portfolio. But I think where our subsurface team is particularly excited is we also think that solvents could be a good fit for lower-quality resources. So for example, resources where you have thinner pay. So we're going in with this in a high confidence area. And then we're looking at how we can take that technology further into the next decade in more challenging reservoirs.

Okay. Understood. And maybe just switching gears, staying on the ops side, as you mentioned that the shorter duration under currents now is becoming a big advantage. So the national question is, how have you done that? Perhaps what are you doing now that you weren't doing before? And is it as simple as really planning or it's like what's the special sauce behind that?

Yes. I think when people see the results, everybody looks for a special sauce. But what you have to remember is this is probably 2 decades worth of work in some of these plants now we're getting into the fourth and fifth turnaround cycle the way these plants were designed in the phased application that we built them, we've had the opportunity to create interconnectiveness, bypasses isolation and the like. So the first key any turnaround is getting as much work as you can out of the turnaround window and limiting scope that comes through isolation.

And then with the jumpovers and the interconnectedness of the plants, we're able to reroute process streams to minimize the loss of production during the turnaround window. But this is not something that you do overnight. It's not something that happens overnight. One of the things that we think about, for example, is as we move to the Christina phase up, Phase G turnaround, we start thinking about what that's going to look like in 5 years, what are we going to do in this window to minimize the production impact in, I guess it would be 2031 turnaround when that scheduled turnaround comes up again. But this is something that happens through time and something you design into your plans when you build it and then you optimize it through time. I don't know if you have anything else you want to add on that?

Yes. No, happy to, it's Andrew again. Jon [indiscernible] and I were talking about that the other day. And I really think just to build on what John said, it really comes in sort of waves of things we've done. It starts off with the design of the plants, the scale of the plants and how we have multiple phases that we can leverage. Second thing is the cycle time of our turnarounds. We've done a lot of integrity management and condition-based monitoring over the years. So we now go cycle time 5-plus years of each of the turnarounds. So that's an important step, Greg.

Then on the terms of -- the third leg would be kind of the scope of the work that we execute inside of the turnarounds, and we've really been able to reduce that by actually taking the work and spreading it over 365 days. So basically sprinkling it in during the operational time rather than in a turnaround. And then finally, and here are some kudos co-star operations team. Our operations team is doing a phenomenal job during the execution of the turnarounds themselves leveraging what Jon just spoke to. Quite a bit of confidence in that now. We obviously saw it at Foster Creek, where we had minimal production impact. We just guided you to a reduced impact of the turnaround coming up at Christina Lake. And then the other thing I'd just remind you, Greg, and everyone that we've got a pretty light turnaround cycle in the upstream business over the next few years. Just the way we've not been able to spread them out, you'll see sort of 1 or 2 lighter turnarounds each year.

Next question is from Dennis Fong with CIBC.

Congrats as well on a strong quarter as well as the continued momentum you're showcasing in ops. My first question here maybe continues on from Greg's question. So Christina Lake on the back of Narrows Lake success as well as the work that you do in Christina Lake North. You previously talked potentially about interconnecting the 2 processing facilities. Can you talk towards one, maybe the strategy and how that maybe evolved just on the back that you've seen it narrows as well as where you're seeing facility limits at either Christina Lake North or Christina Lake South? And how does that also optimize maybe the well development or how that shifted the well development and like the next well pad locations that you're thinking about drilling between the 2 assets?

It's kind of funny. You're asking us to give -- to front run our Investor Day in January. But we're actually working on the interconnectedness of Christina Lake North Garth and our Christina plant today.

Andrew, maybe you're the best person to answer Dennis' question.

Yes. I'll have a go. Maybe I'll take a giant step back and then kind of talk to the evolution of both Christina Lake and Christina Lake North and then how we're going to connect them. And the evolution of Christina Lake, you'll recall, Dennis, a couple of years ago, we were at 230,000, 235,000 barrels a day. We sanctioned the expansion and as well the tieback to Narrows Lake. And we've now taken Christina Lake production to close to 265,000, 270,000 barrels a day with Narrows Lake at 80,000 barrels a day plus. So we're seeing good performance there.

Christina Lake still treating them separately at Q1, Q2 performance was in that sort of 105,000, 110,000 barrels a day. We're seeing that ramp up to probably towards 125,000 barrels a day by year-end, and that's a function of the redevelopment wells and as well the fifth OTSG coming on stream in Q4. And then we'll continue to grow Christina Lake up towards 150,000 barrels a day and beyond in 2028.

Now that's kind of the status. Now when we did the deal, we spoke to our investors and yourselves about the opportunity we had to optimize the subsurface and even between the 2 areas. We're really going now, not wanting to front run too much, Dennis, but we're really looking at how can we also physically connect the plants. So back to my answer earlier to Greg on the turnaround performance and how we're utilizing the scale and the phases of the plant. We actually see an opportunity here to optimize and get more juice out of the surface facility by actually connecting all the various pieces between the 2 plants.

So again, I complemented the ops group earlier. Here, it's the projects group and the technical expertise that just amazes me every day. And quite frankly, the plan, Dennis is Investor Day in January. That's where we're really going to showcase not only what we're going to do to drive further value in the subsurface, but also utilizing the surface infrastructure better.

Yes, Dennis, your question on plant constraints is kind of interesting as well because when we kind of look at Christina North, we've been feel limited for so long. And now with Narrows Lake coming on at these elevated rates, we've actually seen production rates this month at Christina Lake, not Christina Lake North, but just Christina Lake over 300,000 barrels a day. So what you will see is much higher Christina Lake production in July, and we expect for that to continue. But we're really just kind of evaluating right now what are the plant limitations that we have inside these facilities. And I think we're going to be surprised to the upside of it, and that's going to form part of our thinking as we start to integrate these plants and work towards one Christina Lake that has 2 interconnected plants as we work through the latter part of this decade.

Definitely, definitely. I really appreciate that context from both of you. I wanted to shift to Sunrise and maybe carrying along with that thought around facility constraints. From the last quarter, you kind of suggested that one of the 2 trains was able to run at a very high capacity at Sunrise during some planned maintenance there. How do you think about, we'll call it, the go-forward development strategy around Sunrise. It seems like the facility, again, has a fair amount of ample capacity? Is it just how do you kind of maybe drive the cadence of well drilling to kind of further ramp that beyond the 70,000 barrel a day level, which you highlighted you just hit ahead of schedule?

Yes. We've done a lot of work on the Sunrise facility since we acquired 100% of it back in 2022. In the original design basis was 2 trains, A and B, each 30,000 barrels a day of capacity. We've had one train during turnaround conditions up to 52,000, 53,000 barrels a day, and we've done a lot of capacity testing through the last 4 years, a lot of debottlenecking and creating sort of that interconnectedness between the 2 to facilitate higher production rates. But we haven't really found the facility constraints there because we are, again, production constrained or feel constrained.

So the only challenge for us is to continue to work that up. As I mentioned in my notes, we're regularly over 70,000 barrels a day today with the first of the Eastern well pads now online. We expect to bring on the second later this year. But that is something that we are going to continue to work through, continue to debottleneck and continue to kind of push the limits of where those constraints might manifest themselves today. But I think the short answer to your question is it's something higher than where we are today, but we're not really sure exactly where that's going to lie.

Yes, I probably I can add one more color comment too is so indeed, we haven't pushed the boundary. So proud of the team for how to push the boundaries at FCCL. There's more to come here at Sunrise. So the subsurface team are doing it now by going out east and looking to develop a reservoir that's up to 50 meters thick. What we look at in the facility is how can we expand it and how can we expand it relatively efficiently from a capital point of view. And it looks to us at this stage that we have enough water treatment and oil treatment. And so what we need is more steam. So again, at Investor Day, we'll talk a bit more to kind of what our plans are there.

Yes. So again, in all these things, it's about getting the SOR down and getting your production up and finding out where those debottleneck opportunities might land. But we've got room to go there.

Next question is from Menno Hulshof with TD Cowen.

I'll start with a question on the new production guidance range of [indiscernible], just over 1 million BOE. Given that we're halfway through the year, what's the scenario where you hit the top end of the range or even eclipse it? And similarly, what would need to happen to only hit the bottom given you averaged 970 in the second quarter?

Yes. So maybe I'll start this and somebody else can kind of fill in some of my thinking on this. But what we try and give you, Menno, is a view to where we think P50 lies in terms of the future production guidance that we're giving you. And what's really clear to us is through a combination of the redevelopment programs better reservoir performance and better production coming from the well pads that we are bringing on. Production took a pretty significant jump in the month of July in particular at Christina Lake and in particular, at Foster Creek. So we would expect to be somewhere around 245 at Foster Creek and somewhere around 285 at Christina Lake. And as I mentioned, we've had days at Christina Lake, where we're over 300. So we think that the kind of 50,000 barrels a day increment that we've given is largely attributable to those 2 assets.

Over and above that, we still expect to have increasing production from Sunrise. We mentioned it's up over 70,000 barrels a day pretty regularly right now, and we still expect to have increased production from the East Coast as we get to first oil as well as incremental production from Lloydminster and conventional. So in thinking through this, we want to give you sort of that P50 number where we've got sort of that equal chance of being above or below it, but it gives you I think, a balanced view of where we are inside the portfolio today and a balanced view of what we expect for the rest of this year and moving into 2027.

That all sounds very promising. I'll follow up with a question on basin condensate supply, given how topical it's become with the recent positive messaging on thermal growth from pretty much everybody. Can you remind us of how much condo you can really produce versus consume? And then more broadly, does future [indiscernible] supply concern you at all? And are you hearing of any industry initiatives to boost it over the next, call it, 3 to 5 years?

Yes. So maybe I'll start this, and then Jeff can finish it. But we consume far more than we produce. I think we -- not including the Lloyd upgrader, I guess, in our conventional business, we're about 20,000 barrels a day, and we would consume about 240, 000, 240,000 barrels a day, much of which we bring from the U.S. So condensate supply is something that we think about a lot, and we think about where does it come from, but we have to remember as well as pricing really determines a lot of the availability of condensate. There are other light hydrocarbons we can use over and above the formal condensate supply. But going forward, as we grow, our condensate strategy actually figures into everything that we do in terms of allocating more capital to our heavy oil business. But Jeff?

So Matt, I think it's a great question, particularly with some of the things John touched on around the MOU and the future potential growth. So to take your question in sort of 2 parts in sort of the short and medium term, there's lots of shock absorbers in the system to be able to bring diluent to bear that's through blending, bringing light into the condensate pool at upgraders throughout the province choosing to bring a product that is diluent rather than having it blended into synthetics. And there's a number of ways that this just resolves itself on a short-term basis month to month and week to week.

I think you're speaking more to a longer-term structural thing. And the first on that is if growth is orderly and measured, I think we would expect to see price to drive the choice to produce condensate in Alberta. We've seen that over time with both ourselves and many other producers throughout the province being very price responsive and targeting rich grass when it's the right time to and targeting dry gas when it's the right time, too. So we'd see that being a price-based response. And then there has been pipeline creep through time where import pipelines have found new capacity, and that is an opportunity for the future. In the past, we've seen things like the development of the DRU, which recycles condensate in Alberta, and that's a potential for the future. And deeper into the past, we've seen things like structural rail bringing condensate in, and I don't know that we'll need to get there. I think we would try to see the market to resolve itself in advance. However, as we point out, if there is pretty significant growth in a more expedited basis, you'll see those sorts of projects be brought to bear sooner to be able to meet the demand.

Next question is from Neil Mehta with Goldman Sachs.

Jon, just love your perspective on this trilateral memorandum of understanding. I think -- when I think about some of your comments earlier this year to the comments on the call today, definitely feels like -- you feel like you've made a lot of progress on this. And so just practically from a Cenovus perspective, if you blue-sky this thing, what could it mean for the business in the early 2030s?

Well, I think one of the things that we've argued, Neil, is that we have to have a competitive regulatory and policy environment to attract capital into this industry going forward. I think with some of the impediments that came through policy and regulation, it became really difficult to attract capital into the oil sands business. I think that where we are today and what's been discussed and agreed on unlocks this business in terms of its investability. And I think that's something that's pretty exciting for Canada.

This is probably the largest investment opportunity that we have as a country and to make it investable again and start to attract capital into this business without getting into specifics because I'm not at liberty for that, but it does it is pretty exciting for this industry.

We'll look for more [indiscernible]. West White Rose. It's finally here. It's been a journey Obviously, again, the top side on was a big deal last year, but it sounds like you're tracking for first oil by the end of the third quarter. What's left?

That's it. We're drilling the first production well now. So that well needs to be drilled and completed and get to first oil. And then what you'll see from us in the first well packages, a series of 6 other wells that we'll drill. But we're really excited about this, too. You're quite right. It's been a journey that predates us even buying Husky. It goes back a number of years before that. So to get this completely derisked and beyond the cusp of first production is something that we're pretty excited about and we've been waiting for, for quite a while.

Congrats.

Next question is from Patrick O'Rourke with ATB Cormark Capital Markets.

Congratulations on the record quarter here. Just wondering, with respect to the downstream and the Lima turnaround that's going to happen in the second half year, maybe if you could outline the sort of key activities and scopes there. And I'm just curious with where cracks have been and are today? And it sounds like the plan is to go forward as initially design, but would there be any thought to a reduction in scope or timing there?

Thanks, Patrick. This is Eric. I appreciate the question. I think just thinking about the line of turnaround, Yes, it is something we've been focused quite a bit on. The team has worked very hard to be prepared for it. I really getting after the crude unit, the VAC unit, the isocracker the hydrocracker reformer and then a couple of the units. So it's a big chunk of work. And as I said, the team has been working really hard at it. I think you've been just building on some of the themes around getting after reliability and getting after isolation and making the facility and the units more accessible online to get after certain things as part of the scope.

There's quite a bit inside the back tower that we're going to do and really look to make sure that we can maximize heavy crude through Lima by getting that back tower cleaned up, turned around and ready to go. I think as you said, it's obviously a very strong crack environment. We've done a good job, I think, across the downstream really in 2Q around trying to be as flexible as we can with some of our non-cycle lending outages and moving them where we can to really support the supply disruption and get our products to the market when the market needs it. Yes. It's something we'll continue to look at for Lima, but I see it's a big turnaround. We're ready for it, and our focus is on executing it safely and executing it well, and that's really where we are right now.

Okay. Great. And then we all sort of saw the license activity that came through in the Montney in the quarter here. Just curious about the strategy there. Could it become a bigger piece of the puzzle in the conventional unit? Or is this more so about filling up sort of unused facility capacity that you have right now?

Yes. I think the way to think about it, Patrick, is more of our capital this year has been directed towards our Montney positions vis-a-vis the Deep Basin. So we are -- we have some areas there that we're investing in largely in the liquids-rich portion as well as in the top area. But I think that's a progression that you'll see through time is continue to invest more or direct more of our conventional capital into the Montney area vis-a-vis the Deep Basin, and that's really just driven by economics and strategy.

[Operator Instructions] Next question is from Manav Gupta with UBS.

I wanted to ask a broader question. With the Strait of Hormuz, and we don't exactly know the status of when it will open, and whether it be a perpetual block there or some kind of derisk risking over there, do you think there is a need for U.S. refining system to pull a little harder from the Canadian upstream operations. I mean we are seeing U.S. utilization of 97% right now. And globally, the utilizations are much lower because they're unable to source that crude. And what's making this happen is the crude coming down from Canada. And I understand there are some political tensions right now between the 2 countries. But going ahead, do you see U.S. refining system even more dependent on the Canadian crude, given what we are seeing in the geopolitical tensions out there.

I'm going to turn that question over to Jeff to answer.

Well, that's pretty broad. What I would say is that aging crude has a really natural home in the U.S., and it's been finding its way there. There's the pipeline, there's a physical constraints that are what they are. and we see those pipelines running full and that pull continues to be there. Prices have been really interesting in the U.S. Gulf Coast. We've seen a high degree of variability as the straight is impacted it. I mean, we all watch benchmarks in WTI and Brent, something that's less observable is the -- where the physical barrel prices and where we see that is in the WCS differential at the Gulf. And that has been really variable as of late in the quarter, it was between minus 2 and minus 12.

The reason I go to prices is that's the market telling us what the pull is. And when you see times of belief where there's more constraint in the straight you see prices get stronger, minus 2, when it seems to be that maybe tensions are easing, that comes off minus 12. And that is just the market telling us what to do. Through all of those times, however, we have seen a very similar locational differential between Canada and the Gulf Coast. And that just means there's been a steady constant pull. I'd actually go to a different place to answer your question, which is more around the structural egress opportunities that continue to come to market because that's going to be the governor on exactly how much Canadian crude goes to the south. We've seen a number of pipeline proposals come, a number of open seasons continue to be run. And that just is really what's telling me more about the interconnectivity between the 2 countries rather than purely something out of the straight.

So I'm not sure if I dodged your question or answered it. but I do think it has a lot more to do with physical interconnections, and we continue to see that opportunity to expand looking into the future.

And my quick follow-up is, I think last year, you did a very trip to Toledo refinery. And you laid out certain goals in terms of for the downstream business, we are seeing much stronger utilization. I'm just trying to understand from the point where you had set those goals for a further improvement in downstream. How are you tracking against your own goals? And where else could we see further improvement in your downstream business?

Yes. Yes, thanks for the question. I think as you said, the discussion we had last year at Toledo outlined where we saw the business moving to. And I think we've made really, really good progress. Really proud of what the team has done safety performance is really strong. I think reliability has really started to improve. And you're starting to see some of that optimization come through with a more reliable kit. And I think we're just really starting to get into some really exciting opportunities as we look at some of the growth potential of the portfolio. And so those are things like really getting after -- great Lakes expansion in terms of moving products to different markets and out of PADD 2, which is really seasonally congested. We're looking at how do you further optimize the value chain and I'm talking to both the oil value chain as well as the Ohio Valley system.

And so getting the right crude blends into our refineries and really making sure that we're fully optimized on the upgrader, looking at the Ohio Valley and figuring out where there are opportunities within our naphtha systems to really get after the right cuts and really monetize that system the way we can seen, just low capital constraint opportunities, constrained busting opportunities really across the portfolio as we're identifying some of these reliability improvements. the team has done really, really well at placing more jet into the market. So we're seeing strength in Jet.

So how do we pull more jet, how do we place more jet into the market? How do we find new market opportunities for that jet fuel I can go on and on, but I would say there's just a number of opportunities that once you start to unlock the reliability, it really unleashes what I believe is a really outstanding commercial team that has quite a bit of savviness that can find more and more opportunities to get additional dollars per barrel as we continue to take this kit forward.

Thank you. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. And thank you, operator. So this concludes our conference call. I'd just like to thank everybody for joining us. We obviously appreciate your interest in the company. So thank you very much, and have a great day.

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

Good morning, and welcome, everyone, to Cenovus' Virtual Annual Meeting of Shareholders. I'm Kim Guttormson, Director of Communications.

I'd first like to acknowledge that in our many operating areas, we work on the traditional lands of multiple indigenous peoples. In Canada, this includes First Nations, Metis and Inuit. And in the United States, this includes tribal nations. We extend our most sincere thanks and respect to the members of these nations. Today, we're holding our annual meeting in a virtual format, which allows a broader base of shareholders to participate regardless of your location.

Before turning the meeting over to Alex Pourbaix, Chair of Cenovus' Board, I'll take a minute to explain how the meeting will work. If you are a registered shareholder or duly appointed proxy holder, your information screen displays instructions on how to participate in the meeting, including voting and submitting questions. The ability to vote or ask a question is available for registered shareholders and duly appointed proxy holders only. All other guests are in listen-only mode.

Polling is now open, and voting details are displayed on your information screen. If you've already voted, you don't need to take any further action unless you'd like to change your vote. We'll close the polls following the final voting matter. If you are a registered shareholder or a duly appointed proxy holder, you may submit questions at any time during the meeting. Select the Questions tab found at the left or bottom of the screen and type in your question. Please note that questions related to voting matters will be addressed during the formal portion of the meeting.

To ensure questions related to voting matters are addressed before we close the polls, we may need to return to earlier agenda items. We may also aggregate questions that are similar. Questions that aren't related to voting matters will either be addressed during the Q&A session, which follows the formal portion of the meeting and remarks from our CEO, or they will be posted to our website, cenovus.com, in the coming days, and these will include management's response.

I'll now ask Alex Pourbaix, Chair of the Board, to call the meeting to order. Mr. Pourbaix?

Thank you, Kim, and welcome, everyone, to Cenovus' Annual Meeting of Shareholders. Before we start the formal portion of the meeting, I'd like to take a moment to thank you, our shareholders. We appreciate your continued support and confidence in our strategy and execution. As you'll hear from our CEO, Jon McKenzie, we are positioned to further build on our momentum in 2026 and beyond, focusing on our strategic priorities and continuing to deliver value across the business. I would like to thank all of our directors for their continued commitment to our success.

Now on to the business of the day. In accordance with Cenovus' bylaws, I will chair the meeting. Colin Ritchie, Assistant Corporate Secretary, will act as Secretary, and Stephen Bandola from Computershare will act as scrutineer. The record date for determining shareholders who are entitled to receive notice of and vote at this meeting was fixed at March 10, 2026.

I've been advised by the Secretary that notice of this meeting was properly given and a quorum is present. Accordingly, I declare the meeting properly called and constituted for the transaction of business. The reading of the notice of meeting will be dispensed with, and I direct the Secretary to include with the minutes, a copy of the meeting materials, confirmation of mailing to shareholders and the report on attendance. I now call the meeting to order.

Jon McKenzie, President and Chief Executive Officer, is here today, along with members of Cenovus' executive team, including: Andrew Dahlin, Executive Vice President and Chief Operating Officer; Kam Sandhar, Executive Vice President and Chief Financial Officer; Jeff Lawson, Executive Vice President, Corporate Development and Chief Sustainability Officer; Susan Anderson, Senior Vice President, Legal and General Counsel; Candace Newman, Senior Vice President, People Services; Eric Zimpfer, Head of Downstream; and Geoff Murray, Executive Vice President, Commercial. They are all available to answer your questions following the formal portion of this meeting. Also with us today and available to answer questions are Ryan Lundeen and Ali Arnell, partners at our auditor, PwC. The rest of the Cenovus leadership team and our Board members are also joining the meeting but are in listen-only mode.

The business of today's meeting is described in the notice of meeting and management information circular dated March 10, 2026, which were delivered and filed in advance of this meeting. You can find a link to the circular and annual report by clicking on the Document icon found at the left or on the bottom of your screen, and they can also be found on Cenovus' website and on SEDAR+.

The business of today's meeting is to receive the audited financial statements for the year ended December 31, 2025, and to consider and vote on 3 items as set forth on Pages 12 to 14 of the circular. First, the appointment of our auditor; second, the election of directors; and third, the nonbinding advisory vote on the corporation's approach to executive compensation. For efficiency, we have prearranged for Andrew Dahlin and Kam Sandhar, both Cenovus shareholders, to move and second the formal business motions. We will now proceed with the formal business of the meeting.

The first item of business is to receive the consolidated financial statements and the auditor's report for the year ended December 31, 2025. The 2025 annual report containing these audited financial statements was delivered to shareholders in advance of the meeting, and a link can be found at the left or bottom of your screen, as well as on Cenovus' website and on SEDAR+.

We will now move on to the voting items. A reminder, the polls are still open for voting on the items of business. As mentioned earlier, voting will be conducted by online polling, and voting options will be visible on your screen if you are a registered shareholder or duly appointed proxy holder. If you have already voted, you don't need to take any further action unless you would like to change your vote.

Item 1 on the agenda is the appointment of our auditor as set forth on Page 12 of the circular. Could I have a motion?

Mr. Chair, my name is Andrew Dahlin, and I move for a vote on Item 1 to appoint our auditor.

Thank you, Mr. Dahlin. Is there a seconder for the motion?

Mr. Chair, my name is Kam Sandhar, and I second the motion.

Thank you, Mr. Sandhar. Are there any questions on the motion?

There are no questions on the motion.

[Voting]

Okay. We will now move to Item 2 on the agenda, the election of each of the director nominees as set forth on Page 13 of the circular, being: Stephen Bradley; Keith Casey; Michael Crothers; James Girgulis; Jane Kinney; Eva Kwok; Melanie Little; Richard Marcogliese; Chana Martineau; Jon McKenzie; Claude Mongeau; myself, Alex Pourbaix; Frank Sixt; and Rhonda Zygocki. There having been no further nominations received in advance of the meeting in accordance with Cenovus' bylaw #1, I declare the nominations closed. Could I have a motion?

Mr. Chair, my name is Kam Sandhar, and I nominate each of the individuals you've listed, and I move that each nominee be elected a director of Cenovus.

Thank you, Mr. Sandhar. Is there a seconder for the motion?

Mr. Chair, my name is Andrew Dahlin, and I second the motion.

Thank you, Mr. Dahlin. Are there any questions on the motion?

There are no questions on the motion.

[Voting]

We will now move on to Item 3, a nonbinding advisory resolution to approve the corporation's approach to executive compensation as set forth on Page 14 of the circular. Could I have a motion?

Mr. Chair, my name is Andrew Dahlin, and I move for a vote on Item 3, a nonbinding advisory resolution to approve the corporation's approach to executive compensation.

Thank you, Mr. Dahlin. Is there a seconder for the motion?

Mr. Chair, my name is Kam Sandhar, and I second the motion.

Thank you, Mr. Sandhar. Are there any questions on the motion?

There are no questions on the motion.

[Voting]

Online polling is now closed. In order for today's resolutions to be passed, the approval by a simple majority of the votes cast by shareholders who voted online or by proxy at this meeting must be received. I have received the scrutineer's report and confirm as follows: PwC is appointed as auditor of Cenovus, as approved by 99.67% of the votes cast by shareholders. Each director nominee is elected to the Board. The nonbinding [ advisory resolution ] to accept the approach to executive compensation was approved by 97.39% of the votes cast by shareholders.

I direct the Secretary to file the final scrutineer's report with the minutes of the meeting. Details of the voting results will be filed with securities regulators and included in the news release which will be issued later today.

The formal business of the meeting is now complete. May I have a motion to conclude the meeting?

Mr. Chair, my name is Kam Sandhar, and I move that this meeting conclude.

Thank you, Mr. Sandhar. I declare the formal business of this meeting is concluded. I now invite Mr. Jon McKenzie, Cenovus' President and Chief Executive Officer, to give his remarks, which will be followed by a question-and-answer session.

Thank you, Alex. On behalf of Cenovus, our employees and our shareholders, I'd like to thank you for your continued leadership, stewardship and as Chair of the Board. I'm looking forward to another year of close collaboration in 2026.

Now I'd like to first bring your attention to the advisory on the screen, which refers to some of the information I'm about to discuss. Additional information about forward-looking statements and financial information can be found in our first quarter news release, first quarter management's discussion and analysis and our 2025 annual report. These are all available on cenovus.com under Investors.

I will begin with safety, the cornerstone of everything we do. The safety of each of our employees and contractors is our top priority, supported by a safety culture that is deeply embedded across all our operating sites. Our strong performance in 2025 includes top-quartile process safety performance for the third consecutive year. We remain committed to continuous improvement to ensure our people go home safe every day.

In 2025, we executed a long list of priorities across the company. Operationally, our teams delivered exceptional performance, setting multiple Upstream production records across our assets and demonstrating top quartile downstream reliability. Our Upstream production of 834,000 BOE per day was the highest ever for Cenovus, up 3% from 2024, and that doesn't include the impact of acquiring MEG Energy and its Christina Lake asset. We exited the year producing over 970,000 BOE per day.

In the Downstream, our refineries ran reliably through the year with a combined utilization rate of 95% across the Canadian and U.S. segments while enhancing the competitiveness of their margins and unit costs. We also executed major milestones on our highly efficient growth projects, completing the Narrows Lake tieback to Christina Lake, a first of its kind extended steam reach pipeline, facilities work on the Foster Creek optimization project, which delivered production growth well ahead of schedule, and construction, installation and tie-ins of the West White Rose platform.

2025 also saw us complete two significant transactions. We closed the acquisition of MEG on November 13, adding 110,000 barrels a day of top-tier resource located next to our largest producing SAGD asset. Consolidating the Christina Lake area will generate a projected $400 million of annual operating and corporate synergies by 2028, with work already underway. We also sold our [indiscernible] and now have full operational, commercial and strategic control of our Downstream business, which is a critical component of our heavy oil value chain. Together, these transactions position the company for continued growth and value creation over the long term.

From a financial perspective, our balance sheet remains robust, and we continue to prioritize the flexibility that comes with a $4 billion net debt level, which represents an underlevered balance sheet. Following the MEG acquisition, our capital allocation framework was adjusted to balance deleveraging and shareholder returns while we maintain a long-term net debt target of $4 billion.

In 2025, we returned about $3.8 billion to shareholders through dividends, share repurchases and the redemption of preferred shares. Strong operational performance, meaningful progress capturing MEG synergies and a robust balance sheet positions us well to continue to deliver value from our portfolio of assets. With the completion of our 3-year investment cycle this past year, we have delivered incremental production increases while reducing the amount of growth capital we plan to spend year-over-year.

At Narrows Lake, we used extended steam reach to unlock some of the best resource in our portfolio. Production rates at Christina Lake continue to rise as we bring down our steam-oil ratio and allocate more steam to the newest pads at Narrows Lake. At Foster Creek, we delivered the optimization project ahead of schedule, increasing capacity of one of our largest and highest quality assets by approximately 30,000 barrels per day.

Drilling at West White Rose has now commenced, and we expect first oil in the third quarter of this year. This asset is expected to reach peak production of about 45,000 barrels a day net to Cenovus by 2028, and its high netback production and decreasing capital spend position it to generate considerable free cash flow. Looking forward, our Christina Lake North expansion project will drive production growth of about 40,000 barrels per day by the end of 2028 as we head 2 new steam generators and debottleneck the water and oil handling capacity. We plan to exit 2026 at a production rate of about 1 million BOE per day, a significant and exciting milestone for our company. It is a testament to all the talented people that work for us. With these key growth projects online, we will continue to grow to around 1.1 million BOE per day by 2028.

We remain financially disciplined and do not expect to change our capital plans in response to short-term volatility and commodity prices. Our opportunity-rich portfolio gives us optionality for investment in the long term, and you should expect us to continue to find and invest in high-return growth projects across our business going forward. When looking at investments, we test economics to meet our return thresholds at USD 45 WTI and expect to maintain our overall capital spending in and around the $5 billion mark in both 2026 and 2027.

As we enter 2026, our business has never been stronger. We remain focused on protecting and extending our competitive advantages: a low-cost, long-life resource base; a conservative capital structure; disciplined cycle-resistant investment and continued commitment to increasing returns to our shareholders.

With these foundations in place, we are well positioned to navigate the year ahead. We know the geopolitical unrest has put more attention than ever on energy security. We will continue to focus on competitiveness and advocate for regulatory and policy environment that allows us to produce the resources North America and the world need. I want to thank our shareholders, our Board and our employees and contractors for your ongoing support, and I'm looking forward to the exciting year ahead.

Thanks, Mr. McKenzie. We will now answer questions that were submitted online. Please click on the Questions tab found at the left or bottom of your screen to submit your question. We may group questions that are similar for a single response. All questions and our answers will be posted on Cenovus' website within 5 business days. If we run out of time today and don't get to your submitted question, it will be posted there as well.

We have the following question from Jessica Carradine with Investors for Paris Compliance, representing shareholder Solal Foundation. The question. We have withheld our vote for the reappointment of the auditor due to ongoing gaps in the portrayal of decommissioning liability in Cenovus' financials.

My question is for PwC. Auditing standards require the disclosure of critical audit matters which communicate highly material areas that involve significant estimation uncertainty. In the 2025 financial statements, Cenovus lists decommissioning costs as a key area for estimation uncertainty. In your audit of Cenovus, how did you determine that decommissioning liabilities did not meet the threshold to be included as a critical audit matter? And what procedures did you perform to assess the sensitivity of these liabilities to core assumptions such as asset lives or the discount rate?

Hello, it's Ryan Lundeen, Assurance Partner from PwC, and thank you for the question. I'd like to address both parts. First, how critical audit matters are determined under PCAOB standards, and second, our work over decommissioning liabilities in the Cenovus audit.

First, on the CAM determination framework. Under PCAOB auditing standards 3101, a critical audit matter is not simply any material or complex area of the financial statements. It is specifically defined as a matter that was communicated or required to be communicated to the Audit Committee, relates to accounts or disclosures that are material to the financial statements and involved especially challenging subjective or complex auditor judgment.

It is important to emphasize that the CAM threshold is about the nature of the auditor's judgment, not solely about the significance of management's estimate or the materiality of the account. Many financial statement areas are material and involve estimation uncertainty, but do not rise to the CAM threshold because the auditor's work, while rigorous, did not involve especially challenging subjective or complex judgment relative to other areas of the audit.

On the second part, on decommissioning liabilities specifically, we do not opine on individual balances. The fact that decommissioning liabilities were not identified as a CAM in our audit report does not mean they receive less audit attention than necessary. It means that in the specific facts and circumstances of the audit, our procedures over this balance did not involve the degree of especially challenging, subjective or complex auditor judgment that distinguishes a CAM from other significant audit areas.

On that note, we did perform our audit in accordance with standards of the Public Company Accounting Oversight Board. Our responsibility as set out in our auditor's report indicates that we provide an opinion on the consolidated financial statements taken as a whole in accordance with IFRS. We provided an unqualified opinion in relation to those statements based on the applicable accounting and auditing standards. If there had been material deviations from such standards, we would not have been able to issue an unqualified audit opinion. Thank you.

Thank you, Mr. Lundeen. We have a second question for -- from [indiscernible]. Given the scale of Cenovus' decommissioning liabilities and the number of judgments required to estimate them, what specific steps did the committee take to scrutinize the assumptions applied by management, such as the asset lives and the discount rate, and to satisfy itself that this area receives sufficient audit scrutiny, particularly in light of the absence of any critical audit matter relating to decommissioning liabilities?

It's Alex Pourbaix. The Chair of the Audit Committee is in listen-only mode, so I will respond to this question. And I would state that Cenovus provides disclosure relating to our decommissioning liabilities, including the undiscounted amount of estimated future cash flows to settle all our decommissioning liabilities. We exercise reasonable judgment to assess liabilities and estimate future values. All of our disclosures are made in accordance with IFRS accounting standards.

With respect to timing, it is important to note that oil and natural gas currently make up over 50% of total energy demand, and that demand continues to grow. For example, the International Energy Agency expects oil demand to remain above 100 million barrels per day by 2050, and upstream oil production will require about $540 billion in annual investments through 2050 to maintain global supply. And I think it is important to note that recent global events have only reinforced that oil and gas remain critical strategic commodities for continued economic development. This points to an incredible opportunity for Canada to deliver our oil and natural gas to a growing world for decades to come.

Thank you, Mr. Pourbaix. We have a question from Jeff Carlson. Using share buybacks as a way to create value for shareholders is a coin flip at best. Further, using company earnings to repurchase its own shares is not in keeping with a vision of long-term growth. Doesn't it make more sense to deploy this capital in ways that will actually grow the company or to return these earnings directly to shareholders who have risked their own money in the form of higher or special dividends? With this in mind, my question is, why has the Board adopted this policy of repurchasing its own shares?

It's Alex again. I will also take this question. And I would say that our framework very intentionally delivers a balance of shareholder returns and deleveraging, targeting to return approximately 50% of excess free funds flow to shareholders while net debt is above $6 billion, with the remainder allocated to deleveraging. As we have said before, our capital allocation framework is not formulaic, but guidelines, and shouldn't be viewed as something we manage quarter-to-quarter, but over longer time frames.

To the extent that oil prices remain elevated, you could see us having more bias towards deleveraging to bring the debt down faster. Paying debt down faster allows us to protect our equity holders if we do see weaker commodity prices in the future. While returns on buybacks aren't as attractive at high prices, we continue to see value in repurchasing our shares, and we'll continue to do so.

Our track record has been strong. We have repurchased 337 million shares for an average price of $23.25 a share, an attractive price in relation to our view of intrinsic value.

Thank you, Mr. Pourbaix. There are no further questions.

Great. So on behalf of your Board of Directors and leadership team, thank you for attending our Annual Meeting of Shareholders.

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's First Quarter 2026 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.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2026 First Quarter Results Conference Call. On the call this morning are 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 Cenovous 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 referenced on the call today will be in Canadian dollars, unless otherwise indicated. 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. As always, I'm going to start with our top priority, which is safety. At our Toledo Refinery, we recently celebrated 12 consecutive months and over 3.3 million man hours without a recordable injury. This milestone was delivered during a period which included a major turnaround on the east side of the plant, work that carries additional risk given the elevated activity and nonroutine work.

And the business delivered consistent execution, bringing that asset back online safely and 11 days ahead of schedule. The performance reflects the commitment and dedication of the Toledo team supported by the strength of our safety systems, which focus on leadership engagement, a stop work culture and recognizing strong safety behaviors. So congratulations to the Toledo refinery, they continue to reinforce the belief core to Cenovus. Strong operational performance starts with doing the work safely every day.

So now turning to our results. Our priorities this quarter remain unchanged. We've stayed focused on executing our business plan, delivering exceptional operating performance and advancing our growth projects. The focus on execution translated into strong first quarter results with upstream production exceeding 972,000 BOE per day, supported by record oil sands volumes in our first full quarter following the MEG acquisition. While geopolitical events late in the quarter resulted in increased price volatility and heightened uncertainty, our approach to operating our business remains the same. Our results reflect the strength of our business model. We are a reliable supplier of crude oil, natural gas and refined products to both North American and global markets.

Now starting with oil sands, the Christina Lake production averaged 359,000 barrels per day in the first quarter, supported by strong well performance at Narrows Lake. Narrows Lake is now producing over 65,000 barrels a day from the first 4 well pads with a steam oil ratio below 2%. Individual well performance has been exceptionally strong and exceeds our internal expectations. Our best wells at Narrows Lake are now producing over 5,000 barrels a day. Bringing on a project of this complexity and scale to 65,000 barrels a day in just over 9 months is a testament to the quality of the asset and the capability of our technical project and operating people.

Production from Narrows Lake will continue to ramp up as we bring on additional well pads and we expect to reach 80,000 barrels a day later this summer. Now integration work at Christina Lake North is also progressing well. We've completed a delineation and seismic program in the quarter and initiated the redevelopment program ahead of schedule. The first of the 42 redevelopment wells was spud in March and began producing in April. Initial production results are exceeding our internal forecasts. And as we execute our redevelopment program, we will see increased production from Christina Lake North throughout the remainder of 2026.

At the same time, installation of the first new steam generators progressing ahead of schedule with startup expected before the end of the year. And with the acceleration of the redevelopment well program we will exceed the $150 million synergy target we set for ourselves in 2026. Not to be outdone at Foster Creek, we set another quarterly production record of 223,000 barrels per day, with peak rates exceeding 230,000 barrels a day in March. These production rates were driven by the optimization project, which was delivered ahead of schedule and strong operating performance from our new well pads. We plan to start up an additional 4 well pads in 2026.

The turnaround of Foster Creek phase began in April has progressed well to date with limited production impact. We continue to optimize our turnaround activity across our Oil Sands portfolio which will result in more efficient and lower impact turnarounds. At Sunrise, production in the first quarter was just over 59,000 barrels per day. During the quarter, we successfully started up the first of the 4 new well pads on the East side development area of Sunrise. These pads are some of the largest Cenovus ever drilled targeting high-quality rich pay of up to 50 meters thick. Now early indications from the first pad have met and exceeded expectations. We've seen recent daily rates to reach as high as 68,000 barrels per day, and with another 3 pads to come on in this area, we expect to continue to grow production from Sunrise all the way through to 2028.

The Lloydminster Thermals delivered another strong quarter, averaging 102,000 barrels per day supported by the continued outperformance of the redevelopment well program. Recent redevelopment wells have surpassed our expectations in some of our longer laterals, nearly doubling our initial forecast. Of note, now this performance excludes any contribution from Vaughan, which we sold in December and with limited initial volumes coming from Rush Lake which continues to ramp up following the 2025 outage. At our Asia Pacific assets, production was over 57,000 BOE per day in the quarter, and production from the region continues to impress, delivering consistent and robust free cash flow to Cenovus. In the Atlantic, production was over 18,000 barrels a day in the quarter, with strong performance from Terra Nova and the base White Rose field. Of note, we continue to benefit from the high netbacks and Brent plus pricing in that region. At West White Rose, we have now completed all the elements of construction and commissioning and have commenced drilling from the offshore platform, marking another important milestone for the project.

I just couldn't be more proud of what this team has been able to deliver through an extreme challenging winter and challenging weather conditions, which really extended into the early spring. With drilling operations underway. We now expect first oil from the project later in Q3. In the Downstream, first quarter results were once again very strong. The Canadian refining business delivered throughput of 115,000 barrels a day in the quarter, or utilization rate of about 107%. During the quarter, we entered into agreements to sell our Canadian commercial fuels business, which includes cardlock and travel center locations, for expected cash proceeds of $275 million.

Now this transaction is expected to close in the second half of 2026, pending approval from the Competition Bureau and other customary closing conditions. In U.S. refining business, crude throughput averaged 343,000 barrels a day or approximately 94% utilization. Our PADD II refineries continue to deliver strong operational availability, allowing us to optimize margins as the opportunities arise. Adjusted market capture was 114% for the quarter, reflecting a market environment that continued to favor our configuration, including our ability to process heavy crude and our low gasoline to distillate yield ratio.

So now I'll turn it over to Kam to walk through some of our financial results.

Thanks, Jon, and good morning, everyone. In the first quarter, we generated approximately $4.4 billion of operating margin and $3.4 billion of adjusted funds flow. Operating margin in the upstream was over $3.7 billion, exceeding the prior quarter due to the higher production in the oil sands, rising benchmark oil prices in late February and March. Our first quarter results included over $1.5 billion of taxes and royalties, which rose alongside commodity prices. Oil sands nonfuel operating costs were $8.92 a barrel in the first quarter about $0.50 per barrel higher than the prior quarter due to planned maintenance and workover activities as well as higher GHG compliance costs. Downstream operating margin was $734 million, which was -- which included $504 million of inventory holding gains with results in the quarter benefiting from competitive and reliable operations and improved product pricing.

In U.S. refining, operating costs were $11.74 a barrel or $0.20 per barrel lower than the previous quarter, reflecting lower planned maintenance offset in part by modestly lower throughput and higher energy and electricity costs. Adjusted market capture, as Jon mentioned, was 114% with economic conditions continuing to favor the configuration of our refineries, widening heavy crude differentials, strong diesel and jet fuel margins and the relative strength of secondary products versus gasoline were all tailwinds in our results.

Looking forward, capture rates are expected to normalize through the spring and summer. However, we are seeing significantly higher volatility in product prices in the current environment and how these prices settle relative to each other over the coming months may impact our capture rates. Capital investment in the first quarter was approximately $1.2 billion, supporting sustaining activity across the business, along with investment in growth and optimization projects at Christina Lake North, Sunrise, Foster Creek and West White Rose. Our capital guidance for 2026 remains unchanged at $5 billion to $5.3 billion.

Turning to net debt. At the end of the quarter, our balance was approximately $8.1 billion, a modest decrease from the prior quarter with higher adjusted funds flow, partially offset by a $1.1 billion increase in noncash working capital. This increase in working capital is typical of periods where commodity prices rise to the extent we saw through the latter part of the quarter. As current commodity prices -- at current commodity prices, we would expect the pace of deleveraging to accelerate significantly in the coming quarters. Shareholder returns in the first quarter were $1 billion, including $356 million in common share purchases $379 million through dividends and $300 million through the redemption of our Series 1 and 2 preferred shares. These were the last outstanding series of preferred shares of the original $900 million which we have redeemed over the past 2 years, resulting in a lower cost and a simplified capital structure going forward.

Consistent with our commitment to grow shareholder returns, our Board of Directors has approved a 10% increase to the annual base dividend to $0.88 per share. This increase reflects the growth of our business and the strength of our operations, which both fund the dividend and our sustaining capital requirements at a $45 WTI oil price.

I'll now turn the call back to Jon for some closing remarks.

Great. Thanks, Kam. Now as we close the book on the first quarter, it's worth reiterating that volatility and geopolitical uncertainty are not new to our industry. We've seen many cycles over the decades. It's why we constructed our capital structure, financial framework and operating model to perform through a wide range of market conditions. While higher benchmark prices underscore the operating leverage and the cash flow generating capability of our business, they do not change our strategy.

Our focus remains on executing the business plan that we laid out in December. Our company responded accordingly this quarter, delivering consistently strong operational performance across both upstream and downstream. We increased our production rates, ran our refineries with high availability and utilization, completed the West White Rose project and accelerated the integration of Christina Lake North. With our unique high-quality long reserve life assets, coupled with our disciplined capital allocation framework, and dedicated and highly competent people, our business performance continues to press our competitive advantages.

Now before we open the line for questions, I want to talk about an opportunity that we as Canadians have, if we choose to seize it. The events of the last few weeks have clearly shown in the world that energy security is national security and energy security is economic security. The reality is the world needs affordable, abundant, reliable energy from all sources, regardless of how we label them. The world will require hydrocarbons to form a material component of the energy supply mix for decades to come. And there are no examples of first world nations that don't also have access to affordable, abundant, reliable energy. It is essential and irreplaceable for a high-quality standard of living. In Canada, we are blessed with some of the highest quality, longest life resources in the world, including the Canadian oil sands.

These resources not only supply Canada with affordable, reliable, abundant energy we use and take for granted every day in our modern lives, but they also fund our social benefit network, schools, hospitals, roads, pensions through the payment of taxes and royalties and the creation of high-paying jobs. And yet the national dialogue on further development of the oil sands has been myopically focused on the climate agenda and climate policy, which have ignored a multitude of benefits that responsible oil sands development is brought to this country. Of the top 10 global producing oil nations, Canada is recognized as the most responsible producer across a broad range of metrics.

The result of this myopic dialogue, however, is that we have created a set of national policies and regulations that make resource development and investment in Canada uncompetitive for the rest of the world. Only one greenfield oil sands project has been approved and built since 2013. And Capital has left candidates to plan more competitive jurisdictions and Canada has ceded high-paying jobs, taxes and royalties to countries like Russia, Iran, Iraq in the United States. Our uncompetitive national climate policies and regulations have not reduced global demand for oil by 1 barrel. It just means that the oil, the world demands and the associated benefits are not coming from or to Canada. It does the country no service to negligibly reduce the impact of climate change over the next century if we materially erode our social benefit network over the next 15 years.

And yet, we have an opportunity to course correct. If we recognize that we are in a global competition for investment and we choose to compete, we have the opportunity to become the energy superpower that our Prime Minister has advocated for, but continuing to add incremental costs and protracted expensive regulatory processes to the energy industry drives investment in Canada. For example, the industrial carbon tax is unique to Canada. No other major oil producing in the nation in the world has one.

The result is this tax does not incent decarbonization of the Canadian industry, but instead incents industry to invest outside of Canada. This is our time. We should be an energy superpower and we need to take the right decisions to unlock investment and growth to the benefit of our economy and all Canadians.

And with that, I'll open it up to your questions.

[Operator Instructions]. Our first question comes from Dennis Fong with CIBC World Markets.

Congrats on a great quarter as well as the higher synergy capture.

Nothing is going on in the market this morning.

My first question is related to a lot of the geotechnical work that you alluded to in your prepared remarks, especially on the Christina Lake North or MEG legacy assets. I was just curious, as you start to see some of the results of the redevelopment wells roll in, how does that maybe change the way you're either thinking about the development across the asset or even maybe looking at the facility expansion project or the optimization of that expansion project as you go forward?

Yes. As I mentioned, Dennis, I'll let Andrew fill in some of the blanks that I'm going to miss. But we really took the opportunity over this winter to really start to develop our own model for the Christina Lake North asset based on the geotechnical work that we had done. So we drilled about 40 delineation drill -- or wells, shot 3D seismic and 4D seismic across the asset. And it's really confirmed, I think, what we knew before in that this is a Tier 1 expandable resource that's got a reserve life that's measured in decades, not in years.

So as we kind of go forward and think about development to that, the first step for us is to go after some of these redevelopment wells because this is oil that really comes back to the plant and doesn't consume any teams. So it really drives down the SOR and allows us to optimize the facilities as they are in place today. So what you'll see from us through the rest of this year as we finish that program is the well today, production today is 110,000 barrels a day, and that's going to grow through the rest of the year. You'll see kind of month-over-month improvements as we bring on more and more development wells. The other thing that I mentioned is we put in our base case additional steam capacity, a fifth and a sixth OTSG. The fifth is ahead of schedule. That's going to add additional steam capacity.

We'll bring that on before the end of the year, and you'll see the results of that come through in 2027. But long story short is we're well ahead of what we put in our base case in terms of the FID case for MEG. And it really, to your point, gets us thinking about what is the further expansion beyond the $150 million that we've put into the public domain today. Andrew, I don't know if you've got anything else you want to add to this.

Yes, maybe add a couple of things, Dennis. Yes, obviously, just to add a couple of sort of factoids on the redevelopment program. We target drilling 40 wells this year, 5 are drilled, 3 are on stream. And I think as Jon mentioned in his opening comments, those 3 -- first 3 wells are delivering above expectation. I think as we look broader and further out, as a function of that delineation program, we executed here in Q1, we've identified something like 250 redev opportunities. So we've got a rich portfolio for years ahead of us there. And then on the facility optimization, just to add one more detail there. We actually got 3 waves of facility projects that are all in on the go at the moment. First one is indeed the fifth OTSG coming on later this year.

Second one is an expansion of the water and oil treating facility. We call that the facility expansion project. But what we're also looking at is actually looking at an opportunity to connect the 2 facilities, CLN to the CL facility. And that's really where the next big wave of synergies comes. And yes, frankly, probably a great opportunity at the Investor Day here in Q1 2027 to provide you a good update on that. And I'd say with some confidence we're going to deliver this year's synergy target of $150 million. In fact, we're going to exceed that. I'm equally very confident that we're going to deliver and exceed the $400 million per year synergy target for 2028.

Yes. Dennis, this has just been a great acquisition for us. For us to be able to get such a huge Tier 1 resource that sits right next to what we do and it's right in the wheelhouse of what we do and is going to provide decades of returns to investors. It's just been a terrific acquisition, and we're really happy with what we got in that acquisition.

Definitely. I really appreciate that color from both of you in terms of the opportunity set going forward. Staying in the -- for my second question and staying the upstream, I wanted to focus in on Sunrise. Again, from your prepared comments, it sounds like you're getting close to that 70,000-plus barrel a day level at that asset and you don't even have all of these kind of new well pad or well pads online. Can you talk towards where maybe the next phase of maybe bottleneck situations happen to be at the Sunrise asset? Is it more facility driven? How do we think about a, we'll call it, exceeding the opportunity that you've highlighted in the 2028 time frame? And what does that kind of involver look like on a go-forward basis?

Yes. Dennis, oe of the things that we haven't been sitting on our hands at Sunrise and you haven't necessarily seen the production growth until this quarter. But we've always taken the opportunity to debottleneck the plant in preparation for where we're going with this. So we've done a lot of work on the steam systems, a lot of work on the cooling systems, a lot of work on water handling as well as cooling in that plant.

And one of the things that may be somewhat invisible to you in the last quarter, we took the opportunity to take 1 of the 2 trains down to do some overhead steam work, and we ran 1 train at 51,000 to 55,000 barrels a day. So there's lots of capacity inside this plant to continue to ramp up production as we go forward. And I think you're kind of quite right to note that with even just the first few wells from the first of the V pads coming on, we're kind of 68,000 barrels a day. So we think there's lots of opportunity before we hit the next constraint inside this plant. And it's something that we're going to take a hard look at going forward is how do we go beyond 75,000 barrels a day at Sunrise because it's an immense resource. And a lot of good work has already happened in terms of debottlenecking those facilities in preparation for going higher.

Next question is from Menno Hulshof with TD Cowen.

I'll start with a question on market capture, if that's okay. You mentioned -- I believe you mentioned potential normalization of the 114% that you achieved in Q1 in the coming months and quarters. And I know there's a lot of moving parts here, but what do you think market capture normalizes to? And more specifically, can we expect a higher floor on that measure going forward relative to what you were talking about in late 2025?

Well, I think we continue to push you towards 70% metal, but I'll let Eric speak to this in a little bit more detail.

Yes, it's a great question. I would say, certainly, a very good quarter and very proud of what the team delivered. I would say it's certainly built on the back of strong operations and strong commercial optimization, and we expect that to continue, absolutely no change in that performance. I think when I look at the market environment in the first quarter, there were a number of things that I think very much favored or supported, I think, our configuration.

And so you look at the heavy diff widening that plays certainly into our portfolio and how we're built to process heavy crude. I think the strength of diesel as well as Jet, again, I think, reinforced our configuration and gave us an opportunity there for a higher market capture. And I would also point to the relative pricing of secondary products relative to gasoline. And so with those secondary products pricing strongly relative to gasoline, it gives us a higher market capture potential. So you put all those things together in the first quarter and you come up with a pretty strong number that we're proud of. As I look forward into the second quarter, and as Jon talked about it normalizing to 70%, there's a couple of factors I'd maybe call your attention to.

One on the feedstock side, I would say when you look at some of the pricing around domestic light sweet crudes relative to TI, so crudes that we do run that is becoming increasingly expensive and a widening relative to that TI marker. And so that impacts the market capture available to us to the negative I would also point to, as I mentioned, benefiting us in the first quarter, as the gasoline crack strengthens and it widens against that secondary product pricing, that also impacts the market capture available to us. So while our performance, we expect to stay the same, expect to have really good reliability, really good operations and really good commercial optimization.

The market environment as it evolves into the second and third quarter. And it's frankly seasonal, you see it every year. These factors show us that our market capture potential will be lower as we get into 2Q and 3Q. And again, that's back into that kind of 70% range that we've talked about previously.

That was very helpful. Maybe the follow-up question is on -- because it's getting a lot of airtime, the Christina Lake North development program, you mentioned, I believe, another 250 locations. And so my question is, is 40 wells per year a reasonable cadence? Or would you consider accelerating that a little bit in 2027 and 2028. I'm just asking that because I'm assuming that would be close to the top of your opportunity set in terms of full cycle returns.

No, I'm going to let Andrew answer this more fully, and you're absolutely right that the opportunity set continues to grow and the 250 locations that we had are not all equal. But you also have to remember to Menno, we've got 2 well pads that we're starting up this year as well. And so the pacing and staging of your redevelopment really is limited by the internal constraints that you have inside your plant and your oil and water handling systems.

But as we go forward, what you should expect from us at Christina Lake North, as we talked about, is steadily increasing production, steadily decreasing SOR. And then with the additional more steam, you're going to see a material movement in the production. But the pacing and staging of redevelopments and redrills, to your point, is not yet optimized, and that's something that we'll lay out when we get into Investor Day in January.

I don't have a lot to add actually, Jon. It's really not -- it's Andrew speaking. It's really an optimization of a fully integrated system between the subsurface and the facilities. And obviously, we're going to -- we lean towards the readers because they come on with such -- with instantaneous oil and such low SORs.

Next question is from Alexa Petrick from Goldman Sachs.

Our first one is just around capital allocation priorities. I mean as we think about the elevated commodity price environment and incremental cash flow generation, any updated thoughts on how you're balancing pay down and capital returns?

Good morning, Alexa, it's Kam. I think at the highest level, I would say not a lot has changed. Our framework, I would say, we've kind of had intact now for the last few years. I think, first, what I would start with is we've set our capital program this year. We've got our plan with our growth projects continue to progress. We've got embedded growth in our business going into the fourth quarter of this year into next year.

So that $5 billion to $5.3 billion of capital spending, you shouldn't expect any change. That is -- even though we are seeing higher prices than what we budgeted for at the beginning of the year. I think our plan as it relates to organic capital is unchanged. I think beyond that, obviously, you saw we also increased our dividend. And again, that's kind of normal course, I would say, too, that, that dividend needs to be sustained and fully funded in a lower price world. And that's really anchored to the growth that you're seeing in the portfolio, not just this year, but even as we think about where we're going to be in 2027 and 2028.

And then beyond that, really, it comes down to what is our kind of driver between deleveraging and share repurchases. And I think what we've outlined before is that we've got a guideline in place where as the debt moves from what was around $8 billion down to $6 billion, we're going to kind of be 50-50 and they will move to a higher proportion of buybacks as we get the debt down further.

But one of the things I would say is, clearly, this price environment we're in today, it is not what we expected when we started the year. I think we are really viewing it as something that's more short term in nature. So with that in mind, I think we're probably taking a bit of an opportunity to probably have a bit of a bias towards more debt reduction versus buybacks, not to say that we don't see a return on the buyback. I think we continue to see a return, and you'll see us stay in market. But when you think about proportions of our free cash flow, I think nobody should be surprised to see us have a little bit higher proportion to deleveraging in the short term.

Okay. That's very helpful. And then our follow-up is really just around West White Rose. I mean any color there around what the gating items are for first oil and timing around the cash flow inflection?

Sure. Andrew, why don't you take that one and maybe just kind of draw a path between where we are today and first oil.

No, sure. Absolutely. Yes. So West White Rose, as Jon talked in his opening comments, project's completed. We've got the operating authority from the regulator, and we -- and drilling has commenced. So over the next -- the first well there kind of comes in 3 phases. Phase 1 is obviously drilling the well. So this is roughly 6,000 meter long well, it's a horizontal well. We'll do that. Then we go into the completion phase and then the tie-in phase. So drilling completion and tie in, that's what we're saying we should be complete have completed by late Q3 of this year and then, hence, get the first production on stream. Having done that, we immediately go to the second well. And then we just continue through a repeat of that program through roughly 30 to 35 wells, which will take us through the next 4 years. So we'll see first production here late Q3 this year and then a steady ramp-up of production from West White Rose from current 0 up to a plateau of 85,000 barrels a day by late 2028, noting that's the gross volume.

Yes. It's a pretty exciting day for us. This has been a long time coming. And going through the commissioning process and the work that was done on SIT really confirmed that the construction was first rate, high quality, and we really got this to a point now where we're in operations. And so the project is now behind us, really happy with how it's functioning technically. Everything is kind of all systems go as we kind of drill the first of 7 wells in the first well package. So a very exciting day for us.

Actually, Jon, can I just add one thing. I think it's an exciting day for many people. For us as an organization for our partners, but also for the province of Newfoundland. This is a world-class project that's come on stream that's going to benefit the companies but also in Newfoundland for decades to come.

Our next question is from Greg Pardy from RBC Capital Markets.

Thanks for the detailed rundown. Jon, I couldn't help, but think a little bit about your comments on the regulatory framework and carbon taxes and so forth. And I'm trying to get at the root of that a little bit in terms of -- has there been any change perhaps in your thinking maybe over the last year or so. As it relates to regulatory reform, decarbonization, export market diversification and so forth? Like how are you and perhaps -- well, you can only speak for yourself, I you realized. But how -- are you thinking about that differently now than you might have a year ago? Has anything changed that way?

No, Greg, I think we're -- we've been entirely consistent through time. What we have to do, and I think this was part of where the MOU was going is we have to have a view where pathways production and pipelines all come together. And the reality is that with comprehensive policy reform that allows for our significant investment in this base and the production piece is lacking.

And so we need a set of policies that are consistent with investment. We need a set of policies that recognize that we, as Canadians, compete for capital, and we have to compete in a different way. We have not grown oil sands on a greenfield basis for over 10 years. And if we are going to fill 1 million-barrel a day pipeline to the West Coast, it's got to come with growth, and that growth has to come capital and that capital has to be competitively advanced vis-a-vis, where else it can go?

Okay. Okay. All right. I think that's clear. And then, Jon, in the past, even back at the refinery tour in Ohio back in the fall. I mean, part of the strategic role that your U.S. downstream plays is just the potential for congestion in Western Canada. Now there have been -- there's debottlenecking underway. There's various initiatives on the mainline and so on. But what's the in-house view at Cenovus in terms of what maybe the egress picture is looking like out of Western Canada is the concern around congestion maybe as much as it was before?

Yes. No, it's -- I'm going to let Jeff answer the back part of your question, but you're absolutely right. Our refineries provide us with the most economic egress out of this province versus any other opportunities we have -- what is kind of interesting right now is we have a number of opportunities to a number of different locations by a number of different midstreamers that potentially could offer additionally aggress to producers going forward. .

But Jeff, maybe you can talk a little bit about how you're seeing the environment for egress and midstream participation in ex-Alberta egress.

For sure, Jon. And Greg, I think Jon hit the high level on it really well, which is through some pretty hard work over the past couple of years by Cenovus and by industry and a number of midstream partners we are seeing a nice steady flow of creative egress alternatives come to market.

I would say, we've seen what's come to pass already, so only speak of things that are being worked on or looking to the future. You can quickly name at least 3 different projects, bringing north of 1 million barrels a day of egress to diverse locations, all potentially in service by the end of this decade. And that's a big change from 2024 right when Trans Mountain came on, and there was maybe a large feeling that this might be the last I think industry has proven creative and responsive to need. And as we said last quarter, don't be surprised to see Cenovus continue to support these initiatives.

Next question is from Travis Wood from NBC National Bank.

Question is kind of back to what Menno was talking about in terms of market capture. But rather than the market capture, would you guys be able to share some thoughts around how you're able to capture some of the physical flow disconnects and global pricing, whether that's shifting how you're moving the crude itself or maybe shifting and optimizing the refined product sales into other markets and on the refined product side. I'm kind of thinking more jet fuel or diesel opportunities that you see kind of as an ad hoc basis through the marketing and trading team as well.

Yes. So Travis, we're kind of doing this in 2 places. I mean one of the places that we have opportunity is on the crude side. and particularly on the East Coast of Canada, where we're seeing the physical and financial markets disconnect. I'll let Jeff talk a little bit about that, and then Eric can kind of fill you in on how we're thinking about the product market and our ability to capture premiums there?

Great. So Travis, just in terms of crude side, we all watch and have seen benchmarks do what they do and move around. But when you get into the physical market, there's a lot of things that are less seen. I would say off the East Coast, we've managed to find some attractive pricing both dated Brent versus Brent, when you get into the more physical nature of things dated Brent sets that price. And you can look for lots of headlines on it, but those prices have been anywhere from $20 to $40 plus greater than Brent. So pretty significant. In addition, as you look to grade and location differentials across all of like crude, we've seen opportunity to sell at increased differentials of things would normally be $1 a premium moving to $6, $7 and $8 premium . So we continue to extract that. And then we have a number of assets on the pipeline side that allow us to move crude around and there's opportunities to move between grades to gather incremental value. It really has shown up really significantly in the physical market. which is less observable than the benchmark. So we just continue to optimize in that range. And I think Eric will go on the refined product side.

Yes. Yes. And maybe just a little more on the feedstock side, building on Jeff's point. I think you've been able to see some really good optimization as we look at standing up the network. So whether that's understanding how do we really find the optimization opportunities from the upgrader, how do we actually optimize across our entire network with Superior and Toledo and down into Lima number of opportunities we see and have been able to capture. I think I would also point to being able to optimize and bus through some constraints inside the refinery to maximize our heavy crude and actually maximize the high 10 portion of the heavy crude, which becomes quite advantage for us.

So a lot of good work even on the feedstock side. optimizing within the network. I think turning to the product side, continuing to find ways, again, as a network to really optimize across the portfolio. I'd point to, as I've spoken before around the marine facility at Toledo and using that to find new means of egress continue to work to figure out how do we monetize our octane length and find different outlets for octane products as opposed to just finished products. I think it's been a huge opportunity, really optimizing within our jet and diesel make and making sure the right molecules are going to the right places to get the most advantaged products into the market.

And so our jet make is something that I think was really strong as we looked ahead, we optimized the kit in the first quarter, and as I spoke to some of the market capture performance, that spoke to seeing the opportunity in the market and then within the physical refinery being able to do that. So I think a lot of different moving pieces that all add up to strong performance in the quarter.

Okay. No, that makes sense. And I know, Jon, you've kind of been continuing to talk about 70% market capture. But if the team continues to optimize both organic feedstock for the refiners optimize global sales from the upstream side and then capture much more robust product pricing downstream. Is there a scenario where you could -- you think you could continue to outperform that 70% given the initiatives the team seems to be working on?

There's always a scenario where you capture more than 70%, and there's always a scenario where you capture less. And to the point you're making, Travis, we recognize that this is somewhat of a clumsy marker in terms of trying to gauge performance. And what we've committed to do is come to you at our Investor Day in January and provide a lot more fidelity into how this works. But I don't want to front run that -- and I don't want to get out over my skis in terms of promising something well above 70%.

But suffice it to say, we're really pleased. We're really happy really proud of the work that Eric and the downstream have done to achieve the kind of market capture rates that we've got, and we look forward for more to come. We're obviously not finished but we owe you a better explanation going forward as to how you can gauge and forecast a refining business and that's to come.

Okay. We'll wait for January and keep asking you on the quarterly call. So I appreciate the color.

I'd be disappointed if you didn't, Travis.

Next question is from Manav Gupta from UBS.

A quick question. Your weighted average tax spread for the first quarter net of RINs was almost down $5 versus the last quarter. I know it's been only probably half a quarter, but can you give us some idea where this number is trending quarter-to-date? I would assume it's materially higher, but if you could give us some idea where that number is trending quarter-to-date for you guys.

Yes, this is Eric. I don't have the specific number, but I can certainly speak to a few things. I think as we saw in the first quarter, January and February were pretty lean. That's expected that is pretty typical in PADD II particularly, where you just have some really tough margin environment. We saw the strength start to return in March and operated into that environment where there's a supply disruption and working to place our products into that market. We've continued to see that strength into the second quarter here. There's a couple of things I think about. Obviously, we've got quite a bit going on in the world. But I think we look at the supply-demand balance really being pretty tight. I think you've seen a number of folks move inventory into the market. So inventories at relatively low positions.

There's been seasonal maintenance going on as well as some unplanned maintenance throughout the pad. And so that makes a tight supply-demand balance even tighter and that really starts to strengthen the cracks. And so we've seen some really, really strong cracks and continue to put our good operations to work to make sure we're putting our products into that market. But the supply-demand balance that we see, I think, continues to show some strong cracks here in the second quarter.

Perfect. And my quick follow-up here is international crude prices are high. International gas prices are super high. Can you talk a little bit about how your international gas assets could be kicking some tailwind maybe for a couple of quarters from what's going on? If you could talk about your international gas asset exposure over there.

Yes. And remember, Manav, that our international gas assets are really on a fixed price basis. So those are low volatility cash flows that we get out of Asia, China and Indonesia. So they don't necessarily see the exposure to the international gas price, but what tends to happen when LNG prices go up is the demand for our gas goes up as well. It's the first gas into Guangdong when LNG prices elevate the way that they have. Now where we do see some benefit is on the associated liquids, those trade at a Brent plus basis. And we do capture additional margin on that. But 1 thing I say about our Asian gas business, and we love that business because of its low volatility and certainty that everybody kind of loves it when the international prices of gas are low and then they always wonder why we're not getting a bigger margin when international gas prices are high, but it's been a fantastic business for us. but we don't necessarily participate in LNG prices as they go up and down.

[Operator Instructions] Next question is from Patrick O'Rourke from ATB Cormark Capital Markets.

Congratulations on another strong operational performance here, especially in the upstream. Hopefully, this isn't redundant because you've covered a lot of ground so far. But just taking a look at the downstream here and heavy throughput in the U.S. segment was up in the quarter. Still, if you were to look at nameplate a little bit of potential upside to that. Was the driver of that, as you spoke to network optimization? Or was this being driven by the heavy crude differential there? And what sort of impact does this have on your market capture going forward?

So I'm going to let Eric answer this question, but there's a couple of things that are bubbling beneath the surf. As Eric mentioned, the cracks were relatively low in January and February, and we obviously optimize our throughput based on commercial considerations. And then on the asphalt side, asphalt prices haven't necessarily kept pace with feedstock and so we've adjusted there.

So when you kind of look at that utilization rate, you've also got to think through all the commercial considerations that go in and around that. It's not entirely a mechanical reliability story. But Eric, maybe you can provide some color.

Yes, I think you hit it really well. Yes. Look, we're built and configured to run the heavy crude, and that's what we do. I think, as Jon alluded to, though, when we looked at the market environment and then certainly as the market started to strengthen, the asphalt prices did not follow the crude prices. And so there are some choices we needed to make around how do we position the kit economically in that environment. And so I think in terms of overall reliability, really, really strong quarter. But looking at market factors and understanding again some of that secondary pricing I talked to earlier, how is that pricing in relative to the price of crude? And then how does that show how you optimize your network.

That said, I will highlight a number of things we've been able to do to unlock heavy crude capacity. A lot of that comes down to reliability of our coking units. A lot of really good work to get after the reliability there, get cycle times down, get throughput up and that really does enable the ability to process more heavy crude, essentially the same total throughput, which is a big advantage for us, again, optimizing within just constraints in the refinery. And just having a mindset to how do we continue to safely and reliably push our constraints to unlock incremental value.

And I think really seeing some of the the talent of the team come through and the ability to unlock those constraints and continue to push the business forward, I think is pretty exciting.

Okay. Great. And this may be a bit more of a broader philosophical question, but I really appreciate the advocacy for the industry that are to start the call. I'm wondering, you've gone through a substantial growth phase here. Growth is in a sense, tailing off a little bit. What would the sort of specific market conditions and regulatory parameters be that enormous opportunity set within the portfolio where we would see Cenovus start to think about upticking the growth profile again here where it makes sense?

Yes. And thanks for the question, Patrick. And you're quite right. We have seen some modest growth in the industry, and you've seen some growth of Cenovus over the past number of years. But the way I would describe that growth is a lot of it comes from acquisition and mergers, and a lot of it comes from brownfield and debottlenecking projects. I think the issue that we have to wrestle with is if we do want material growth in the provinces has suggested that it's looking to actually double production, we have to have a competitive market that allows for greenfield development and greenfield development comes at a higher cost and a higher breakeven than the growth that you've seen to date.

So things like what we've done at Narrows Lake or what we've done at Foster Creek, I would just describe those as optimizations versus fundamental greenfield growth. So without providing for a competitive set of policies that attract capital into this basin and allow us to meet those hurdle rates. I think we're at a point where we have to be pretty thoughtful about a set of policy environments that really do allow us to grow and fill a pipeline that's desirous of moving another 1 million barrels a day to the West Coast.

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

Great. And thank you, operator. Obviously, this concludes our conference call. And I'd like to thank everybody for joining. We certainly appreciate your interest in the company and wish you all a great day. Thank you.

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

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.

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. 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.

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.

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.

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

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.

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.

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.

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. 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?

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, 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.

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. 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.

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 the line of 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 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.

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.

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 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?

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.

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.

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

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?

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.

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- 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.

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

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

Apologize. You came up because Chris Hebert [ we're wondering ] really well.

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.

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.

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?

That will include turnarounds.

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?

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.

Our next question comes from the line of 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 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?

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.

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 Instructions] 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.

Good morning, everyone. Thank you for standing by, and welcome to the Cenovus Energy's Third Quarter 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.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2025 Third Quarter Results Conference Call. On the call this morning are CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. Then we'll open the line for John, Kam and other members of 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 on Cenovus' annual MD&A and our most recent AIF and Form 40-F.

And as a reminder, all figures we referenced on the call today will be in Canadian dollars, unless otherwise indicated. You can view our results at cenovus.com. For the question-and-answer portion of the call, please keep the 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. And thank you, Patrick, and good morning to everybody. To begin the call, I'd like to recognize some of our employees for safely achieving a number of critical accomplishments and milestones over the quarter. Coming into this year, we set some very ambitious goals for the company in 2025 and our execution has been near flawless.

What make these achievements even more satisfying is that we have remained focused on the safety of our people, the communities in which we operate in the environment. Now for example, at the West White Rose project, we completed some intricate and critical work in the third quarter that included installing the top sides on the gravity-based structure, making subsea connections at 120 meters below the ocean surface and completing a turnaround of the SeaRose FPSO.

These operations require thousands of offshore hours and were completed in one of the most hostile operating environments, the North Atlantic and I'm incredibly proud of our people and their continued commitment to our core values as we meet our goals and milestones.

Now before I get to the results, I'd also like to take a moment to speak about the MEG acquisition. As many of you are aware, MEG shareholder vote, which was scheduled to take place yesterday has been postponed to next Thursday, November 6. The delay is to give time for MEG to respond to a regulatory inquiry related to MEG's consideration of the amended terms of the transaction-related matters.

The inquiries associated with a complaint raised by a former employee of MEG, who holds approximately 4,000 shares. We do not expect this inquiry to have any impact on the transaction. There continues to be very strong support for the transaction for MEG shareholders with 86% of the shares voted in favor of the transaction. We expect the vote to proceed as planned next week.

Cenovus remains resolute in our commitment to this transaction. When completed, this acquisition combined with the organic growth we are already delivering across our business is transformational to this company. Subject to shareholder and court approval, we anticipate closing this transaction in November and welcoming the MEG team and moving quickly to capture the identified synergies and beyond.

Now turning to the quarter. We've spoken about 2025 as being an inflection point for our company, where the investments we've made in our people, our assets and in the growth of our business start to come through. The third quarter results are a proof point of more to come. We achieved the highest ever upstream production of 833,000 BOE per day, highlighted by the best ever performance of our oil sands assets which contributed 643,000 barrels per day.

At Christina Lake, production was 252,000 barrels a day in the third quarter, supported by the ramp-up of volumes from Narrows Lake. In the quarter, we brought on 3 well pads at Narrows Lake, which are continuing to ramp up as expected. We expect Christina Lake to sustain or exceed its current production rates in the coming quarters.

At Foster Creek, we achieved a production record of 215,000 barrels per day in the quarter. As part of the Foster Creek optimization project, we brought on 4 new steam generators online in July and they've already supporting consistently higher production from the asset, well ahead of schedule.

Commissioning of the water treatment and deoiling facilities is underway and approaching completion. New pads will be brought online in the first quarter of 2026. We have effectively brought forward a portion of the growth from this optimization project that was really not expected until 2026. We expect to build on the high level of production in the coming quarters as we fully utilize the steam capacity and complete the project.

At Sunrise, we executed a turnaround in September and production was 52,000 barrels a day in the quarter, with turnarounds at both sides of the plant completed in the year and followed by an efficient ramp-up, we expect Sunrise to exit the year around 60,000 barrels a day. The first of the new well pads from the East development area at Sunrise is planned for start-up in early 2026.

Development of the high-quality reservoir in this region will deliver the next phase of growth from the asset over the next 2 years. The Lloydminster Thermals produced 96,000 barrels per day in the quarter, the assets have performed very well despite 18,000 barrels of production from Rush Lake facilities remaining shut in as strong performance from the other assets in the region offset some of the lost volumes.

At Rush Lake, we have confirmed the integrity of the asset and are working towards a phased restart of production prior to the end of the year, subject to approval by the regulator. We expect to safely ramp up production through 2026.

At West White Rose, I'm pleased to say the commissioning is nearly complete and there has been an extraordinary achievement by everybody involved, and we will be drilling from the platform prior to year-end and seeing first oil in the second quarter of next year.

Now moving to the Downstream. We had an excellent third quarter. The Canadian refining business continues to run well with crude throughput of 105,000 barrels a day and utilization rate of about 98%. In U.S. refining, we delivered record production with crude throughput of 605,000 barrels per day and utilization rate of 99%.

Our assets ran as expected during the quarter with high rates of utilization and availability. And this in conjunction with seasonally higher -- or seasonally stronger crack spreads generated positive refunds flow for the business. Cost control in the downstream has been a focus area for the business, and we continue to see unit cost trend downward towards competitive benchmarks and with the sale of WRB, which closed at the end of the quarter, our downstream business is now fully owned, operated and within our control.

Now I'll turn it over to Kam to walk through some of the financial results.

Thanks, Jon, and good morning, everyone. In the third quarter, we generated $3 billion of operating margin and approximately $2.5 billion of adjusted funds flow. Operating margin in the Upstream was approximately $2.6 billion, an increase of around $450 million from the second quarter, driven by our strong operating performance and higher realized pricing in the oil sands.

Oil sands non-fuel operating costs of $9.65 per barrel decreased quarter-over-quarter due to lower turnaround activities and higher production volumes. We continue to make progress on reducing operating costs across the upstream business and expect to see further reductions as we bring on the West White Rose project, realize a full benefit the Foster Creek optimization project and continue to see steady ramp-up at Sunrise.

Our downstream business demonstrated strong performance in the quarter with operating margin of $364 million. This included $88 million of inventory holding losses and $38 million of turnaround expenses partially offset by a $67 million benefit related to the receipt of the small refinery exemption at Superior.

In the U.S. refining per unit operating costs, excluding turnaround expenses were $9.67 a barrel, a decrease of $0.85 a barrel from the second quarter and over $3 a barrel relative to the same quarter last year. The reduction in OpEx was largely driven by performance from our operated assets which delivered operating cost of approximately $9.90 per barrel in the third quarter.

Adjusted market capture for the U.S. refining business was 65% in the quarter, this was supported by a capture rate of 69% from our operated assets, which benefited from the small refinery exemption at Superior and increased refined product exports from the dock at Toledo. The sale of our 50% interest in WRB refining closed at the end of the third quarter.

In addition to the cash proceeds of $1.8 billion received on October 1, the transaction eliminated Cenovus' share of drawn credit facilities associated with the joint venture of $313 million, resulting in a total value received at $2.1 billion based on preliminary closing adjustments. Results from our U.S. refining business will only include our operating assets beginning in the fourth quarter, and we have updated our 2025 guidance to reflect the sale of Wood River and Borger.

Capital investment of $1.2 billion was driven by a consistent level of sustaining activity across the business in addition to the continued advancement of our key growth projects. With the West White Rose project now substantially complete, we continue to expect our growth capital to come down significantly in 2026.

At the end of the third quarter, our net debt was approximately $5.3 billion prior to the receipt of the $1.8 billion of cash proceeds from the sale of WRB. We returned $1.3 billion to shareholders in the quarter through dividends and share buybacks. We took the opportunity to allocate more capital to share repurchases in the third quarter following the announced sale of WRB.

This included the purchase of about 40 million shares at an average price of $22.75 per share. The total value of the share repurchase in the quarter was $918 million which is approximately $175 million higher than our excess free funds flow in the quarter. Subsequent to the quarter and through October 27, the company purchased another $409 million worth of shares or about 17 million shares.

And as Jon noted, following the approval by MEG shareholders, we expect the acquisition of MEG Energy to close in November. Total consideration for the transaction is expected to be a split of 50% cash and 50% Cenovus shares. This equates to a maximum of approximately $3.8 billion in cash and the issuance of $160 million Cenovus shares on a fully pro rata basis.

Pro forma, our balance sheet remains strong with less than 1x net debt to cash flow. And going forward, we'll continue to be opportunistic with our share buybacks while living within the guidelines of our financial framework. As we head into 2026, our major projects are nearing completion and our growth capital is coming down.

Combined with the strength in our balance sheet, the business is positioned well to support our near-term growth plans and remain resilient even at the bottom of the cycle commodity price.

I'll now turn the call back to Jon for some closing remarks.

Great. Thank you, Kam. As I mentioned earlier, we set some ambitious goals for ourselves and the company for this year, and I couldn't be more proud of the way our people have taken up the challenge. We've largely completed our growth projects and are seeing the benefits of higher production with more to come over the future quarters.

Our downstream business has been relentless in driving performance across the portfolio of assets and the sale of WRB gives us full operational, commercial and strategic control of our downstream business while monetizing our non-operated business at an attractive price. Our business is blessed with a deep inventory of development opportunities at low supply costs below $45 WTI and underpinned by a fortress balance sheet.

We are focused on aligning our strategy, business plans and priorities and look forward to building on a quarter-over-quarter growth and value for the foreseeable future. And with that, I'm happy to answer your questions.

[Operator Instructions] Our first question comes from the line of Menno Hulshof from TD Cowen.

Just a question on portfolio streamlining. If we assume that the MEG deal closes towards the middle of November, like you've talked about, how should we be thinking about asset sales potential in the context of what would be a more levered balance sheet? I know you get this question a lot, but any updated thoughts there would be helpful.

One of the things that we are always very cognizant of Menno is the amount of leverage we keep on our balance sheet, and we've always run with an underlevered balance sheet, which allows us to do transactions like this very comfortably.

So there is no burning platform to need to delever after doing this transaction. We're very comfortable with the level of debt that we're going to be taking on to get this deal done and through time, we'll get back to the $4 billion of net debt, but there is no urgency to do asset sales or something like that in an effort to get there.

And that being said, we always look at the portfolio. We always should think about how we want to position ourselves and if opportunities arise. We're always live to those, but certainly, there's nothing that would say that we need to do something tomorrow. We would never do a transaction like this if we felt it was going to corrupt the balance sheet and put our equity holders in harm's way.

Great. And then maybe moving on to the downstream, we're sort of moving into November now, sort of 1/3 of the way through the quarter. How would you frame the setup for U.S. Downstream for Q4. And then maybe on a related note, how much should we expect market capture to be impacted with the Wood River border assets no longer in the mix? I'm guessing it's no more than, call it, 1 to 2 percentage points, but any thoughts there would help.

Well, in Q3, our market capture was actually higher in our operated assets than they were in the non-operated assets. But I've got Eric Zimpfer with us this morning. So maybe I'll turn that question over to him to see how he's thinking about Q4 and market capture.

Yes. Thanks, Jon, and thanks for the question, Menno. Yes, I'd say I certainly think the third quarter is a testament to the work that the team has done, and I think has been something that has really been a focus area for the year. And really proud of the results of what we're seeing in the third quarter.

As we look at the fourth quarter, I think there's a couple of things I think about in terms of the underlying performance, continue to be encouraged by the trajectory. So reliability improvements that we've made have really give us a foundation.

I think the cost focus that we've had throughout the year and the results that we're seeing with the lower cost base is something that, again, we continue to focus on and will continue to be something that we emphasize going forward.

Yes, any time you get into the fourth quarter, you expect margins to start to come off, cracks start to weaken. We're already seeing some of that. There's some strength right now. But I think having a strong business and strong underlying performance gives us the ability to kind of weather through some of the market challenges that you inevitably expect in fourth quarter and then also in the first quarter as well with the PADD II region specifically.

In terms of the market capture, I'd just maybe emphasize. Reemphasize what Jon shared, that has been a continued area of focus for us. A number of things that we've worked to really help strengthen our market capture. The U.S. operated portfolio really outperformed the collective portfolio in terms of what we saw in market capture.

So continue to be encouraged, but it's something we are continuing to focus on and try to figure and look for opportunities to grow that market capture even more through our synergy opportunities as well as accessing some markets where we can have some higher netbacks and better product placement.

One moment for our next question. Our next question comes from the line of Patrick O'Rourke from ATB Capital Markets.

Maybe just to sort of continue on the downstream theme there from Menno. Just wondering, now with the fully operated portfolio with the integration in the kits, sort of what the flexibility is going forward in terms of the product slate. It's a little bit lower on, call it, diesel distillate yield and maybe some of your Canadian peers, is there an ability to raise those things, capture premium products?

And then you've spoken to pushing product in the more premium markets, Eastern Canada, et cetera. What progress you've made on that so far.

Yes. Thanks, Patrick. It's a great question. In terms of the portfolio, I think one of the things I'm really excited about is with the opportunities of the U.S. portfolio, I think, particularly around the synergies each refinery has its unique configuration that allows us to maximize the value. But one of the things we've really started to lean into is how do we optimize across the entire portfolio? And how do we get the best product yield across portfolio and not just asset by asset, but really thinking about it at a portfolio level. I think that gives us a tremendous opportunity.

And I can think particularly in the Ohio Valley area, where we're able to optimize, whether it's our premium production, premium gasoline production whether it's balancing our distillate feedstocks and maximize their distillate production truly an area where we're continuing to explore and we see -- we certainly see some potential benefits and also the opportunities to do some investments in the future to look at how do we continue to make the best products from our kit.

In terms of kind of the second part of your question on accessing the markets, continues to be an area of focus. PADD II is, we think, a really good region for us, but the opportunity to place products outside of PADD II and find more advantaged markets is really important to our strategy.

I would point to -- we've made significant progress in how we're managing the Toledo marine facility. And that has given us the ability to put products into a number of different regions outside of PADD II whether it's in the Canadian markets, whether it's into Upstate New York or whether it's into other regions on the Great Lakes.

But tons of opportunities there. We're really excited about the opportunity to further explore that. And see great upside there.

Okay. Great. And then just in terms of free cash flow allocation priorities, I know with the initial MEG transaction, you came out with sort of a formula in terms of allocation of balance sheet versus shareholder returns, 50% than 75% finally 100%. Today's updated deck just really speaks to the 100. And I know you said it wouldn't necessarily be formulaic on a month-by-month, quarter-by-quarter basis.

But maybe if you could comment sort of on the game plan in terms of allocation today between delevering and share buybacks.

Sure. Kam, you've done a lot of work on this. Why don't you take this one?

Yes. So Patrick, I would kind of separate sort of from the MEG transaction what we're doing today. Obviously, we spent the last year to -- even longer than that, getting the balance sheet to where we are today, which is at that $4 billion target. So putting MEG aside for a second, I would say the plan would be to return 100% of our excess free cash flow because we are at our long-term debt level.

And we'll be -- we continue to see that as a really good opportunity today, and we'll continue to utilize our free cash flow to return that cash back to shareholders. And I'd say for now, given where the share price is, and we continue to see it as an attractive place to deploy capital, you should expect that excess free cash flow to go towards share repurchases.

Obviously, as we get to the point where MEG does close, which we still expect here in November, we will adjust that framework to be a bit more balanced with deleveraging and shareholder returns. So the plan would be as we bring the debt back down to around that $6 billion, we'll be kind of around 50-50.

But as you pointed out, it's not going to be so prescriptive in formulaic. We'll be thoughtful about how much we put on the balance sheet and how much we repurchase shares. And some of that will depend on commodity prices and free cash flow. But think of those as guidelines versus formulas going forward. But I think overall, the goal would be to get back down to the $4 billion, that is still our ultimate target.

We have an approach where we want to make sure we get the balance sheet back to that $4 billion. Obviously, our cash flow base, our growth we've got plus the plan with the MEG assets, we'll put the company in a really good position from a leverage point of view. But we view our balance sheet as being something that's going to stay pristine, and it allows us flexibility and opportunity like we've been able to pursue on the MEG transaction.

Our next question comes from the line of Alexa Petrick from Goldman Sachs.

I wanted to ask maybe switching gears. As we think about West White Rose, you've made a lot of progress there. What are some of the gating items and then any early thoughts on what that production path could look like for 1H 2026 versus 2H?

Yes. We haven't given guidance for 2026, '27 and '28 yet. But what we have said publicly about West White Rose is that we are largely through commissioning that project now and we'll be drilling well prior to year-end with first production expected in early second quarter 2026. That still remains the direction of travel.

But Andrew, maybe you could just provide a little bit more detail on where we are and what that path may look like.

Yes. No. Thank you, Alexa. Yes, maybe to go a little bit back in time and just catch up too. So obviously, in July, we placed the top sides on top of the CGS. We deep -- as Jon said, we're deep into the commissioning and start-up activities, and that actually included the -- all the subsea so we connected the West White Rose platform to the Sea Rose in terms of all the pipeline work, et cetera.

We'll be drilling by year-end and then indeed, first production in Q2 of 2026. In terms of production ramp-up, it's not -- we're going to drill roughly 5 wells per year. It's roughly a straight line from 2026 through to 2028. And what we've said is in 2028, gross volume should be around 80,000 barrels a day, which net Cenovus share is roughly 45,000 barrels a day, Alexa.

Okay. That's helpful. And then I recognize it's still a bit early, but you've talked about significant amount of growth CapEx coming off next year. Any early thoughts on what that magnitude could look like? And what are some maybe other offsetting considerations we should be keeping in mind?

Yes. So where we've really guided the market, and we'll formalize this when we come out with our budget in December. But if you look at spending the last couple of years, we've been around CAD 5 billion, which would include somewhere around [ 1.5, 1.7 ] worth of growth capital. And what we've been guiding to is 2026 will look different with all of these growth projects kind of rolling off the agenda.

So what you should be thinking about is on an unaffected basis, not including MEG, we would be around $4.2 billion. Take out WRB from that kind of brings you to around $4 billion And that's kind of where we think the budget pre-MEG is going to sit. And then we've also suggested that in 2026 when you add in MEG assets, we would probably be adding about another $800 million for sustaining and growth capital on the MEG assets in 2026.

So maybe I've really just already given you the budget for 2026 capital. But that's kind of what we've been saying, and I think it's very consistent with where we've been taking the market over the last few months and years.

[Operator Instructions] Our next question comes from the line of Manav Gupta from UBS.

I am so sorry about this for UBS IT issues. I wanted to ask you, there are a number of organic growth projects, which you are pursuing, which could deliver over 100,000 barrels of organic volume growth on top of MEG and so can you update us what's the progress over there? How are those projects progressing?

Yes. I'm not sure where the 400,000 barrels came from Manav.

No. 100,000. 100,000.

Sorry, I think you said 4, you kind of worried me I thought maybe our messaging had been confused.

No. 100,000, sir.

Yes. What we've been guiding the market to is about 150,000 barrels of growth. And it really comes from heavy oil, conventional and offshore so right across our portfolio. So on the East Coast, as Andrew mentioned, we look to ramp up the West White Rose project, about 45,000 to 50,000 barrels a day by 2028.

That growth starts in '26 and progresses linearly through '26, '27 and into '28. And that's kind of the biggest piece of the growth profile. What we're seeing in Narrows Lake with the tieback to Christina Lake, is the 20,000 to 30,000 barrels a day starting to materialize there, and you'll see Christina Lake in that 250 to 260 range.

We talked about adding 80,000 barrels a day of steam capacity at Foster Creek, which would add about 30,000 barrels a day to that asset. Today, we're already seeing about [ 20 ] of that with the early steam that we brought on. in Q3. But you should see that continue to ramp up in 2026 as we bring on well pads as well finished, the water handling and deoiling sections of that growth.

In Sunrise we're just getting into what we call the V PADD, and these are in the Eastern region of Sunrise. These are some of the most prolific PADDS that we've got in our inventory, and we expect to see production grow from 55,000 barrels a day to close to 75% over the next couple of years at Sunrise.

And then the other growth comes from our conventional and cold heavy businesses. But what you'll see from us as we progress through time and get through '26, '27 and in '28 is production will increase into that kind of 950,000 barrel a day range.

Very helpful. My quick follow-up here is, during the quarter, the buyback was very strong. The buyback went up materially did the net debt? I'm just trying to understand, was this just a timing issue where the PSX deal had been announced and those cash proceeds are probably coming in somewhere in the fourth quarter. That's why the buyback and the net debt went up at the same time, if you could clarify on that.

Sure, Manav, it's Kam. So I think one thing just to keep in mind is our reported net debt at the end of September was $5.25 billion. That did not give consideration to the $1.8 billion that we brought in for the sale of Wood River and Borger. So after -- shortly after quarter end, we dropped back down to $4 billion but what I would say is we announced the sale back in early September.

We very intentionally obviously knew the timing of closing and when we get the cash. So we actually accelerated some of our buyback program through September and in October. So I think what I would tell you is I think we're going to continue to steward towards that $4 billion going forward. Obviously, MEG transaction when that closes, we'll change that.

But I think to the extent that we can, we'll continue to use 100% of excess free cash flow to buy back shares. But the debt -- the goal is to kind of hold the debt in and around that $4 billion. But obviously, the reported debt number at the end of September did not have or did not reflect the proceeds we received from the sale.

That's exactly what I thought. So it was just a timing issue. The buybacks are in 3Q and the proceeds coming in a little later.

Our next question comes from the line of Patrick O'Rourke from ATB Capital Markets.

Welcome back, Patrick.

Just wanted to kind of build on the comments there with respect to narrows. In the public data, we're seeing that sort of in the 15,000 to 16,000 in September, so getting close to the low end of that range. a bit of differentiation on well performance. We're only working with September here. You guys have the hindsight of more recent data.

I would assume, through -- close to through the month of October. Just wondering how well performance is trending relative to type curve and any time frame around when you get to the bottom of that 20,000 range.

Yes. So I'm going to turn this over to Andrew to give some detail, but we started steaming 2 well PADDS back in July and brought on about 18 wells on the X5 and 6 PADDS. We're currently steaming the third PADD, and we brought on, I think, 6 of 8 of those well pairs. And these are ramping up as expected. But Andrew, you're all over this every day. So why don't you add some good color.

Patrick, we were totally on top of this, and we're seeing exactly what we expected from those wells and that they are strong without giving too many numbers. I can tell you here that production in October is now up into the 20-something thousand barrels a day, 22,000, 23,000 barrels a day.

Indeed, we're producing from 3 PADDS pads, we're ensuring that we've got great conforms across all of those PADDS. And then here in early Q1 of next year, we'll bring the fourth pad on. So no, we're very comfortable and very confident in the performance we're seeing at Narrows Lake and ultimately in the delivery of that growth of the Christina Lake asset.

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

Great. And thank you, operator. And I think we're grateful and surprised. There were no questions about MEG but be that as it may, this concludes our conference call, and thank you for joining us. As always, we really appreciate the interest in the company. And thank you to all, 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.