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

Thank you, Operator. Good morning, everyone, and welcome to Cenovus' 2025 Second Quarter Results Conference Call. On the call this morning, our CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. We'll then 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. You can view our results at cenovus.com. I will now turn the call over to Jon. Jon, please go ahead.

Great. Thank you, Patrick, and good morning, everyone. As always, I'll start with our top priority, health and safety. This quarter posed some unique challenges, and I couldn't be more proud of the way our people responded. In late May, the Caribou Lake wildfire forced the evacuation of over 2,000 workers from our Foster Creek and Christina Lake operations. The fire came within a couple of kilometers of Christina Lake. As a result, the facility underwent an orderly shutdown as per our protocol. After a brief outage and thanks to the tireless and determined work of our people, we safely ramped production back up to 250,000 barrels a day and returned to normal operations over the course of the week. This effort included draining and restarting over 50 kilometers of steam pipelines, bringing 26 boilers back online, returning the cogeneration facility back to service, and remobilizing all 2,000 people back to the site. It was an incredible effort, all safely done and without damage to our assets. It's a privilege to witness how our people step up when it matters most, and I'd like to thank our staff for their resilience, continued commitment, and dedication. Now turning to the quarter, this was a terrific quarter for the company. A lot of important work got done, and many important milestones were achieved. We underwent a heavy maintenance period completing large turnarounds in both the upstream and the downstream, which came in ahead of schedule and under budget. We achieved some very significant milestones on our major projects, bringing us closer to delivering on our production growth targets and completing our three-year cycle of higher capital investment. Through all that activity, we delivered exceptional operating performance across the company. Together, these achievements set the stage for the second half of the year and beyond, and they were accomplished thanks again to the hard work and determination of our people. Now I want to speak to some of the details. Beginning with the Upstream, production in the quarter was 766,000 BOE per day as we completed turnarounds at Foster Creek and Sunrise, and managed the production impacts from the wildfire activity at Christina Lake and the steam release at Rush Lake. The turnarounds of Foster Creek and Sunrise both went very well. We completed the work and restored production well ahead of schedule, minimizing volumes lost over the quarter. At Christina Lake, production came back strongly following the brief wildfire-related shut-in. Production was 218,000 barrels a day in the quarter and has averaged over 250,000 barrels a day in July. We achieved an important milestone with the Narrows Lake tieback to Christina Lake. Narrows Lake produced first oil earlier this month in July. This is a huge accomplishment and a testament to the technical and operations team who made this first-of-a-kind tieback possible. We'll ramp up the first pads at Narrows Lake over the remainder of the year, and this means a lower steam-oil ratio and sustained higher production rates as we maximize the value from this asset. Now, the second quarter was also a very busy quarter at the West White Rose Project. During the quarter, both the concrete gravity structure and the topsides were transported out to the offshore field location. In June, the CGS was placed on the seabed, and in mid-July, the topsides were lifted and set atop the CGS well ahead of schedule. This feat of engineering included the world's first-ever direct ship-to-ship transfer of a topside to the Pioneering Spirit crane vessel. With both the CGS and the topsides work complete and set in place, hookup and commissioning activities have now begun. This will include the connection to the SeaRose FPSO, which began producing oil earlier in the year following the successful completion of the asset life extension. During the quarter, it reliably produced over 7,000 barrels per day. We plan to commence drilling from the West White Rose platform before the end of the year and achieved first oil in the second quarter of 2026. At Foster Creek, we tied in four new steam generators during the turnaround and turned them over to operations in July. These steam generators will collectively add about 80,000 barrels per day of new steam capacity as part of the optimization project. We will complete work on the de-oiling and water treatment facilities later this year, and we're on track to bring on first oil from the project in early 2026. During the quarter, we also responded to a casing failure in an injector well at Rush Lake, which resulted in a steam release to the surface. The release was a localized incident impacting one well at the Rush Lake 2 asset. In response to the release, both Rush Lake 1 and Rush Lake 2 facilities were shut in. Prior to the shut-in, the facilities had been producing about 18,000 barrels a day. The well has been brought under control, and we will work together with the regulator to complete a full investigation and put together a plan to safely restart production. As a result and out of caution, we have removed Rush Lake volumes from our production guidance for the remainder of this year. The production impact has been partially offset by strong performance from the other Lloyd thermal assets driven by new development wells and optimization work. Overall, it's been a very active and productive period for our Upstream business, and we continue to deliver on our growth plans. In the Downstream, we had strong results in the second quarter. Excluding inventory holding losses and expense turnaround costs, the Downstream business generated about $220 million in operating margin. The Canadian refining had another exceptional quarter. Crude throughput reached a new quarterly high of 112,000 barrels per day with a utilization rate of 104%. The reliability improvements made to the upgrader during last year's turnaround have enabled us to test the facility's capacity with crude rates reaching as high as 87,000 barrels a day versus an operable capacity of 75,000 barrels per day. The Lloydminster Refinery also performed exceptionally well, with rates reaching 33,000 barrels per day and record asphalt production in the quarter as we took advantage of strong seasonal demand. In U.S. refining, we delivered crude throughput of 553,000 barrels per day while also executing a major turnaround at the Toledo Refinery. Our execution at the Toledo Refinery is exemplary. We took down eight major refinery units on the east side of the plant and similar to Lima last year, took a targeted approach to address the issues that we expect to improve reliability going forward. The turnaround was completed 11 days ahead of schedule, and costs came in at the low end of the guidance range. Importantly, this marks the end of a heavy maintenance period across our downstream business where we have expensed nearly $900 million in turnaround costs over the last six quarters. With our full network up and running and our major maintenance behind us, we have a clear runway to demonstrate the capability of the refining network through the rest of the year and into the second half of 2026. I will now turn it over to Kam to walk us through our financial results.

Thanks, Jon, and good morning, everyone. In the second quarter, we generated $2.1 billion of operating margin and approximately $1.5 billion of adjusted funds flow. Operating margin in the Upstream was approximately $2.1 billion. Relative to last quarter, benchmark oil prices were lower, and the Canadian dollar strengthened. This was partially offset by the WCS Differential narrowing by more than $2 a barrel in the quarter. Oil sands non-fuel operating costs of $10.73 per barrel increased quarter-over-quarter due to turnaround activities and lower volumes in the second quarter. We expect operating costs to come down in the second half of the year and into next year as we return from maintenance and begin to bring on additional volumes from our growth projects. In the Downstream, we generated an operating margin shortfall of $71 million. Excluding $50 million of inventory holding losses and $239 million of turnaround expenses, operating margin in the Downstream was about $220 million in the quarter. In the Canadian Refining business, operating costs of $10.63 per barrel decreased by about $0.20 a barrel from the first quarter, coming in below our full year guidance range for the second consecutive quarter. In the U.S. refining business, per unit operating costs of $10.52 per barrel decreased by about $1.60 per barrel from the first quarter and over $1 a barrel relative to the same quarter last year. We continue to make progress in driving down costs in our operated refineries as we increase reliability and structurally remove costs across our network. Capital investment of $1.2 billion included sustaining activity across the business, as well as growth and optimization capital in the oil sands, where we advanced our key projects and in the Atlantic region with the progression of the West White Rose project. At the end of the second quarter, our net debt was approximately $4.9 billion, a reduction of about $150 million from $5.1 billion at the end of the first quarter. In addition to reducing our debt, we returned $819 million to shareholders through dividends, share buybacks and the redemption of $150 million of preferred shares. We purchased approximately $300 million worth of shares through our NCIB in the quarter or about 17 million shares at an average price of about $17.50 per share. Non-cash working capital decreased by $923 million in the quarter, a significant contributor to our ability to continue to return cash to shareholders while further reducing our debt. We will continue to steward net debt towards our $4 billion target while remaining active with our NCIB. With the value we see in our shares today and with our growth projects on track to start up in the coming quarters, we continue to see a significant opportunity to increase our returns to shareholders going forward through share repurchases. To this end, the company purchased another $129 million worth of shares subsequent to the end of the quarter through July 28, which amounts to about 6.6 million shares. With that, I'll now turn the call back to Jon for some closing remarks.

Great. And thank you, Kam. As I touched on before, we had a terrific quarter and have successfully delivered on a number of key initiatives. We completed the turnarounds of Foster Creek, Sunrise, and Toledo well ahead of schedule and under budget. We achieved first oil at Narrows Lake and are now bringing on new production from some of the best quality resource in the basin. We have begun hookup and commissioning of the West White Rose project ahead of schedule after successfully completing critical work to position the concrete gravity structure with the topsides in July. We tied in four new steam generators at Foster Creek, bringing us one step closer to completing the optimization project and adding over 30,000 barrels a day of production at Foster Creek. Our growth projects are approaching completion. Our major maintenance activities for the year are largely behind us, and we are focused on driving value from our operations. This is a pivotal moment for the company as we execute on our plan to deliver higher production and lower capital into 2026 and increased free funds flow. We have a clear view on the work in front of us and remain focused on creating long-term value for our shareholders. With that, we're happy to answer any of your questions.

Our first question will come from the line of Menno Hulshof from TD Cowen.

I'll start with a question on U.S. downstream. And with the understanding that you don't disclose utilization by refinery, and you did touch on this to some degree in your opening remarks, but can we just get a rundown on the status of your PADD 2 operated refineries? And given that the little bit of downstream turnaround activity that was planned for Q3 looks to have been pushed to Q4, how would you frame the bookends for Q3 utilization in market capture?

Yes. So the way I would frame it is we've always talked about being competitive in the downstream, and we've defined that as kind of a Q1, Q2 cutoff point, and we measure it using Solomon. So what we're driving towards is kind of that 98% availability right across the refining network that we have in the U.S. Today, all those refineries are kind of wide open. We're out of turnaround at Toledo. Everything is operating as we would expect it to, and we expect to see that through the third quarter. I think we have some scheduled maintenance, which is relatively small at Toledo, and we think that's probably the confusion with additional turnaround work, but as in any refinery, you have regular scheduled maintenance that you undertake during the course of time. But if I look out from now, the only big turnaround we have happens in 2026 at Lima, and that looks like that's going to be in the back half of the year, Q3, Q4, and then 2027 at Toledo. So we are through this major maintenance cycle that we've been in over the last six quarters, and we're really looking forward to seeing what we can do over the next 12 months and then more broadly with much less maintenance going forward through '26, '27.

And then maybe just flipping over to Rush Lake. It's good to hear that you've already developed a plan to restart the well. I'm not going to ask for background on the root cause because I know there's an ongoing investigation. But given that it looks to have been a casing failure on an injection well, can we assume there's minimal risk to Rush Lake design capacity and operating protocols? Are there any read-throughs at all for your other Lloyd projects?

Yes. I think out of an abundance of caution and conservatism, we've removed Rush Lake production for the rest of this year. So you're quite right. We're just finishing our root cause analysis and the investigation right now. We're confident that this is a casing failure on one well. As I said in my call notes, we've got control of the site, and we're moving to the recovery phase of this, where we'll work with the regulator and convince ourselves that we've got a good safe start-up plan for this. Both of those things need to come together, and we need to finish the investigation, but suffice it to say we're in the recovery portion of this incident.

Our next question will come from the line of Dennis Fong from CIBC.

I guess, first off, congrats on a really strong quarter. My first question here is just around next steps for some of these up-and-coming projects and ones that you're working on next. I know you've highlighted Sunrise, Lloyd thermal, and Conventional Lloyd heavy oil, including multi-labs as kind of potential next projects. Can you discuss around sizing of CapEx and how you would think about the cadence of growth as well as cadence of spending over the next few years as you look towards these projects? How do you rightsize them given the obviously volatile commodity price environment we're sitting in?

Yes. As we've kind of signaled to the market, we're really coming to the end of an investment cycle that we've had in this business that started in '23 and really concludes this year. So we've been pretty clear that 2026 capital will be much reduced from where we were in '23, '24, and '25, and we've kind of used a low $4 billion as a good marker for you to build into your models. One of the things that we think about as it relates to some of the shorter cycle assets that we've got, particularly in Lloydminster, we just feel like we've got some tremendous structural advantages there and that we own a huge block of land. It's full of oil. We own all the infrastructure. We've got all the pipelines and then we have many of the royalty rights there as well. So as with any investment, we kind of rightsize it and we make sure that it returns capital and return on capital at $45. We think about what's the right pacing and staging to use in terms of how big that investment needs to be. I think when you think about 2026, it might be somewhere around the $150 million to $200 million range that we would put into that cold heavy oil business in Lloyd that kind of supports growth in the kind of 10% range as we move towards 40,000 barrels a day. But like any investment, it's got to make money at $45.

Great. Thanks, Jon. Really appreciate that color. My second question here, and maybe a bit of a follow-on to Menno's first question, now that you've completed major maintenance on Toledo and Lima last year, can you talk about what your team saw or changed during those turnarounds that provide your team with incremental confidence in this runway for stronger operations going forward?

Yes. We have now had a chance to get inside every asset except for Superior, which we rebuilt and restarted in 2023, '24, but at Superior, in Toledo, we had a chance to take the east side of the plant down. The big units and the big money-making units that we had a chance to get into for the first time were the isocracker, the crude unit, the reformer. I got inside the sulfur systems, the back tower, small cokers, the hydrogen plants, and the flare. Those are pretty significant assets, and when we got inside them, we didn't find a significant amount of fund work, which is always a good thing. The improvements that we make on those and getting everything cleaned and dusted gives us much better confidence that we can continue to run those assets for the reliability rates that we're looking for. We were pleasantly surprised in the turnaround by what we didn't find, and we look forward to a good clean run in Toledo.

Our next question will come from the line of Greg Pardy from RBC Capital Markets.

Jon, maybe just to switch into Asia for a minute. Liwan, Indonesia, as I think about those assets. Liwan is not oil price driven. It's a good field, reduces your breakeven, but just curious how you think about those two assets and how they fit in the portfolio long term.

The way I think of both of them, Greg, is we have real competency inside our footprint, both in Asia and Indonesia. In Indonesia, we're a non-operated party with 40%. In the South China Sea, we operate the deepwater. I think as you pointed out, these assets throw out a significant amount of free cash flow. It's fixed price gas plus we get liquids. We produce that gas where we get about a $12 realization, and we produce the gas for about $1. It has very minimal capital requirements, sustaining capital requirements, and the fiscal terms are actually quite good in terms of royalties and taxes. Our strategic approach on those has really been to operate well and harvest cash from them. As you know, they generate about $1 billion of free cash flow every year. Our goal is really to try and extend the contractual terms around the gas sales and get as much free cash flow as we can out of those assets going forward. It's a harvest strategy today with an idea that we've got some contractual optimization to do over time.

And just a quick one for Kam. The working capital tailwind was huge in the quarter. Should we expect much of that to reverse in Q3, Q4? You think?

Greg, it's Kam. I would say, number one, I think working capital is something we're always going to focus on, making sure we minimize it to the best we can. I think the tailwinds you saw in the second quarter, a big chunk of it was driven by just the price movement we saw in the quarter. There was probably about a $400 million or $500 million impact on working capital release we had as it relates to commodity price changes on our inventory balances. The second piece is that there were some tax refunds that we were expecting that we were able to bring in through the second quarter that amounted to a couple of hundred million dollars. The goal for us is to continue to minimize any builds in working capital. The timing of production to sales and those types of things will always move around quarter-to-quarter, but I think the aim is to minimize and keep working capital as low as possible. I wouldn't expect you'll see fluctuations because of commodity prices, but we're going to try to minimize that as much as we can. This quarter, that release really helped us not just deleverage but also continue on a fairly robust shareholder return program through the quarter.

Next question will come from the line of Neil Mehta from Goldman Sachs.

You've been very transparent about your perspective around M&A and have a long history of doing really good M&A, including the Husky deal. That's been a lot of the investor focus and attention around certain assets. What's your perspective on M&A strategy and how do you think about a potential bolt-on deal?

I don't think anything has changed in the way that we look at M&A. We have a portfolio that we quite like. We don't see any holes inside that portfolio. In terms of capital allocation, inorganic and organic opportunities need to compete. Nothing has changed over the course of our tenure in terms of the way we look at M&A. If you're thinking about a particular M&A piece, we're not going to comment on that.

Okay. Moving on to operations here, let's talk about West White Rose, the concrete gravity structure was a big deal, getting that in place. What are the gating items? What does that translate to from a free cash flow perspective?

Yes. Over the last couple of years, we've been investing about $800-plus million a year into that project. That will flip over and generate about $800 million of free cash flow using kind of a $60 WTI, $63 Brent pricing when we reach full production in '27 or '28. It's a huge change in terms of cash flow generation versus cash flow consumption that we're really excited about. You're absolutely right; it's a huge step for us to get this CGS on the seabed floor, and it was done with precision. It was done really, really well. As I mentioned in my call notes, it was well ahead of schedule. I'm always amazed at our technical people. Whether in oil sands, offshore, or in the projects group, what they're able to do. If you're looking at the critical path now, the piece of commissioning that's on the critical path is getting the topsides welded to the gravity-based structure. That will get underway in short order. We anticipate the entire commissioning and hookup schedule to be about three months. Prior to the end of the year, we will start drilling our first well at the West White Rose project, with first oil expected in early Q2 2026.

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

Just looking here, you're able to improve the outlook for the operating costs in the Canadian downstream unit with this update to guidance. Wondering what the key drivers are here? Is that utilization? Is it reliability enhancement and margin capture? How much of that came down to lower than anticipated gas prices in the Western Canadian Sedimentary Basin?

It's all of the above, Patrick. Any time you're trying to take costs out of our refining business and get unit costs down, obviously, you're looking at the denominator as well as the numerator of the equation, and getting good production on the top line is a big help. When we ran the upgrader and the refinery at the levels we did, you're going to see a consequence on your unit cost on the output of that equation. One of the things I would tell you is I think Eric and his team, and I couldn't be more proud of these guys, have been grinding out costs over the last several quarters. They're getting after this in a very tactical way. What we've seen over the quarters is a continued reduction in not just the absolute spend but as you get that better reliability, and you're not spending as much on maintenance while getting volumes through, it shows up in the numerator and the denominator of that equation. This has been blocking and tackling, and our team has been all over this for some time, and we're now seeing the results.

And then I was going to ask about West White Rose, but I hope it was pretty comprehensive there. I just want to switch back to the U.S. downstream and maybe as it relates to my last question. How low do you think you could get the operating costs there? Can you quantify the opportunity on a per-unit basis? What's really going to drive incremental margin as we roll into the next 12 months where you don't have the same level of major turnaround activity that you've had through this quarter?

There are always three drivers of margin in a refinery. One is you have to get the crude slate right, and I think we do a pretty good job of that. Differentials have been very tight; as they widen, we would capture more of that in our Downstream, particularly in the upgrader. At Toledo and Superior, we do have a high diet of heavy oil, so as the differentials widen, you'll see margin capture in those four assets, especially in the Lloyd refinery. We have a lot of work we're doing on the product side. Product placement is another area where you can drive additional value and margin capture. We've opened up the dock at Toledo, which we think is a very strategic asset. We continue to increase our terminal positions, not just in PADD 2, but we recently opened an asphalt refinery in PADD 4. We work on this constantly. As for unit costs, we’ve been clear that we’re not competitive on unit cost, and we need to get them down over time. The trajectory you've seen in that business should continue through time, but I think there's probably another $2 per barrel that we can get out of our U.S. refining assets over time. It's going to be a journey, and we will be very deliberate about it, prioritizing reliability and safety, which are always job one in running our refineries.

Our next question will come from the line of Manav Gupta from UBS.

I just wanted to understand this a little bit. You were down for about a week because of the fire and then you probably took a week to ramp back up. What would a good number in terms of the volume that would be higher for the quarter versus what you lost due to these fires?

Yes. On Christina, I think that's the asset you're talking about. We were down for about four days and then ramped up to full production over the coming weeks. So about 11 days in total to go from a standing start to 250,000 barrels a day. Adding up the barrels that we lost, it's about 2 million barrels. So if that were the number that you were going to use for lost profit opportunity, I think that would be a good number to put in your model.

That's exactly what I was looking for. My second question to you was you generally have a very informed view on the differential, especially on the heavy side. Multiple things are going on here: OPEC raising some volumes, Chevron getting to drill back, and very high U.S. utilization and desire for heavy barrels. What's your outlook for the heavy-light differential into the year-end?

Well, Geoff Murray gets paid to provide insights on these kinds of questions. Maybe I'll turn it over to him.

Sure thing, Jon. Manav, there's sort of two parts to that. What is the differential in Alberta, and what is the differential in the U.S. Gulf Coast? A lot of global factors impact that U.S. Gulf Coast differential. We've seen that be quite narrow compared to history, around minus $2 to minus $3 to WTI. That seems appropriate given the current conditions. Looking forward, I think you need to consider when OPEC raises some volumes and how much. Much of that volume would be medium sour, which tends to impact the Gulf. I wouldn't expect that to go anywhere further past the normal long-run average of maybe $2 wider, which tends to percolate back into Alberta. On Alberta, I think TMX is here, it's working, and doing what it's supposed to do, which is to maintain the Alberta differential quite tight to the Gulf Coast. I expect that to persist through the fourth quarter.

At this time, we have no questions in the queue. Our next question will come from the line of Emma Graney from The Globe and Mail.

I'm just curious to get your take on the new policy environment that we're seeing from Ottawa with Bill C-5 and that kind of thing. Where do you think this might set Canada going forward, particularly with Cenovus and opportunities?

Thanks for your question. I'll turn this over to Jeff Lawson to give you an answer.

I'll give you a bit of an answer. I think the federal liberal government has been the most constructive with us and our industry than we've seen in the past decade. They visit us often and make an effort to improve the Canadian economy by bringing on major projects. I think they're well-intentioned. They have much work to do with industry and the provinces to get things done. We love the notion of new projects and strengthening the Canadian economy, but we need to step back and understand what's preventing us from proceeding. There's a lot of regulatory hurdles present. We talk about energy corridors or a new pipeline to the coast, yet we still have a tanker ban, emissions cap, methane regulations, and an industrial carbon tax that isn't competitive with other jurisdictions. We hope to see changes in these areas for major projects. Thankfully, the governments are engaging in these discussions and being thoughtful about our proposals. I'm cautiously optimistic we're moving in the right direction, but we have a long way to go.

Does this broader policy change shift anything in the energy and infrastructure environment regarding mergers and acquisitions?

I think it shifts everything positively. Over the past decade, we’ve seen a flight of foreign direct investment from all sectors due to regulatory uncertainty. If we become more competitive, we’ll be more attractive to foreign capital, which will improve valuations across industries. This will enable us to pursue organic and inorganic growth rather than simply returning capital to shareholders. I believe this can create a virtuous cycle and drive more M&A.

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, everybody, for your questions today, and for those of you online, we absolutely appreciate your interest in the company. Please enjoy 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.