Thank you, operator. Good morning, everyone, and welcome to Cenovus's 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 John, 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's annual MD&A and our most recent AIF and Form 40-F.

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'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 John. John, 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 four 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. 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 were able to shorten the timeline by four 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 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 six 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 performances 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 two 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 four years, and our oil sands operating costs 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 with largely the same infrastructure in place has contributed to our lower unit costs. 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 were 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. 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 US 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 US 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 add 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 27th, 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 Cam to walk through our financial results.

Thanks, John. 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 non-fuel operating costs were $7.80 a barrel, down almost 50 cents a barrel from the second quarter, reinforcing the cost performance John highlighted, with unit costs across the oil sands portfolio down nearly $3 a barrel over the past four 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 industry-leading SORs and strong cost control.

In the downstream, a 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 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.

US 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 John discussed. Adjusted market capture in the third quarter including the benefit of one-time items such as small refinery exemption waivers at Superior; excluding these items, market capture was over 80% in the quarter.

US refining operating costs were approximately $12.30 a barrel, up from the previous quarter due to the 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 non-cash 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 two 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 shares at what we viewed as compelling value.

Our current NCIB expires on November 10th, 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 continuing 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 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 John for some closing remarks.

Great, and thank you, Cam. This quarter established a new level of performance across our portfolio, with 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 assets 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. With that, I'm open to your questions.

Thanks, and good morning, everyone. Good morning, John.

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 in 2027 and beyond? 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.

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. 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. 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.

That's a historical view. This is much more driven globally, and what you point to in the US Gulf Coast is really the answer right now, which is freight, freight, freight, and freight, which, as John pointed out, is driven by geopolitics and global events.

I think with 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'll 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.

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. 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. No, that's really helpful, and it's actually a good segue into the next question.

I won't ask the market capture question, but maybe a somewhat related [laughs]. Refined product egress out of PADD 2, I know you've been working on this a lot.

In your prepared remarks, you mentioned doing more on the Laurel Pipeline, getting more into the Great Lakes region. Would you just be able to maybe elaborate on what that looks like from a volume's perspective, the potential margin uplift, and I guess market capture is part of that as well?

No, we've been doing a lot of work on that, and I'll get Eric to comment on it. 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.

Then longer-term, the project that Phillips is put forward should give us some real structural decongestion of PADD 2. Eric, why don't you talk about the work that we're doing to optimize our product margins?

Thanks, John, and I appreciate the question. I think John summarized it well.

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.

That's both the Toledo and Lima refineries to make sure we're placing the products into the markets that are most advantaged. 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.

Being able to get onto 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 advanced markets that we're seeing there in PADD 1. We'll continue to look at the different markets we can access, but we've got a great team that is continuing looking to optimize and really excited about being able to continue to advance our positions there.

Thanks to you both. I'll turn it back.

Great.

Thank you, Menno.

Thanks. Good morning.

My goodness, impressive top to bottom with the numbers in the quarter. I want to just stay just with the downstream, not so much necessarily on the margin capture, but 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?

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

The value proposition or the magnitude of the value proposition is kind of in that ordering. We certainly are looking at a number of things that we can do operationally as well as commercially to kind of optimize that.

Maybe I'll turn it over to you, Eric, and you can talk how you're thinking about the business in terms of margin expansion through the portfolio that you've got.

Yep. Thanks for the question.

I would just probably reiterate John and Jeff'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. This quarter I think is a great example of that, certainly looking at the wider heavy differentials to, again, reinforce why we have a downstream.

As John 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. 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 advanced 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. The 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.

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.

Very good. Thanks for that.

Then just completely switching gears, the 9.9% stake in Athabasca, is that just essentially an insurance policy ahead of the vote should an interloper emerge? Just curious on that.

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.

It's just a bit of an insurance policy that adds to deal certainty, which is something we're always looking for.

Got it. Thanks very much.

Thanks, Greg.

Hey, John, team, 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?

I'll let Andrew provide more color on it. As I mentioned in my notes, the first well has been drilled and we're well into completing that well and tying it in, we're looking forward to first oil, which is imminent.

This is a project now that it's de-risked, and the right thing for us to do is let the technical teams finish this well and bring production online. Now what you should expect going forward is the first well package is seven wells, so that's five producers and two injectors.

We should be on a pace where kind of every 90 to 100 days, you'll see the next well come on. Andrew, maybe a little bit more color on how you're seeing the project?

No, and if you think about it, we'd just TD the first production well, completing that as we speak. We'll get that on production shortly.

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.

Then on an average of sort of every 90 days or so, we will put subsequent production wells on. Obviously first production well on here this year, second production and third and fourth production wells on in 2027.

Then we'll just continue doing that through the next four or five years, ramping production up to, on a gross level, roughly 80,000 barrels a day by 2028, 2029.

Yeah.

Thank you. Then, John, 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?

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. I think in our oil sands business this quarter, we were down to $10 a barrel Canadian across the portfolio.

It's not just scale, Neil. This is coming across all the different asset groups that we've got, whether it's Lloydminster, Sunrise, or FCCL.

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 costs down. It's getting the chemical costs down, and it's just finding ways to continue to do things better.

One of the things about this business that I firmly believe is this is a commodity business, and the low-cost producer wins. Across our oil sands base, we're not only the biggest producer, but we are the lowest-cost producer as well.

I'm just incredibly proud of the work that we've done. 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. That's kind of been our history, it's what we expect from our people.

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.

Thanks, John. Appreciate it.

Thanks, Neil.

Good morning, guys. Good morning, John.

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. 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 mid-term growth plan for brownfield expansions kind of like you did over the past five years?

I think 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. 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.

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.

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.

That makes sense. Just so I understand, would there be lands 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. Yeah.

Okay. No, that makes sense.

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 weeks or maybe months?

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

Hey, Travis. 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 megatonnes, incremental 10 megatonnes.

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 this ahead.

If you look at what we've got so far, we got the MEG productivity deduction, we've got changes to the Impact Assessment Act, which really give primacy to Alberta, we don't have a bunch of oil sands stuff locked up because the Impact Assessment Act. We've got the West Coast oil pipeline as a project of national interest, both levels of government and a shift to the BC government now wanting to all get that done.

It's all positive. On the Alberta side, the premier's 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.

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 megatonne carbon capture project looks like.

All the companies are aligned and hammering that out, if we have all the supports in place. It's all coming together.

November 15th is a pretty tight timeline 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 timeline. We are on a path, we're not falling off the path, and we're pushing forward on it.

Okay. Thank you so much for the color, guys.

I'll turn it back.

Great. Thanks, Travis.

Great. Thank you, operator.

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.