Cenovus Energy (CVE) Q2 2026 earnings call transcript

Thank you, Operator. Good morning, everyone, and welcome to CENOVUS' 2026 Second Quarter Results Conference Call. On the call this morning, our CEO, John McKenzie, and CFO, Cam Santar, will take you through our results. Then we'll open the line for John, Cam, 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 40F.

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 John. John, 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 19th, 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, the aiming cost unit was put into service, marking our first application of this technology in SAGD operations.

The project improves how we manage sulfur at Foster Creek. It lowers chemical operating costs by 50 to 75 cents 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. 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 asset is one of the highest quality sagde 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 five well pads from only the first four 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 planned turnaround on Phases 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 loss. As a result, we've shortened the planned duration of the turnaround by nine 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 two 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 Crink 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 the sulfur recovery unit well ahead of schedule, which is expected to reduce operating costs at Foster Creek by 50 to 75 cents per barrel.

Moving to Sunrise, production was nearly 66,000 barrels a day during the quarter, following the start-up 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 are 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, and Deed Valley.

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 increasing 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 Hydra Cracker at Deloitte 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 Lima 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 Cam to walk through our financial results.

Thanks, John. 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 and on-fuel operating costs were $8.28 a barrel, a reduction of almost $0.65 a barrel from the prior quarter. And 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 was supported by disciplined cost control and strong operational availability across our refining network. In the Canadian refining business, full-year operating cost guidance was 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 lake crudes including Bakken Midland WTI which increased feedstock costs during the quarter Capital investment in the second quarter was approximately billion supporting sustaining activity across the business alongside our in 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 Limer refinery.

Capital guidance for 2026 remains unchanged at $5 to $5.3 billion. With record adjusted funds flow and nearly $700 million reduction in non-cash working capital, net debt decreased to $5.4 billion at quarter end, representing a $2.7 billion reduction in one 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 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 of 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, we'll be increasing targeted shareholder returns to 75% of excess free funds flow 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, maintain flexibility in where we allocate capital in any particular quarter to maximize value and focus on returns for our shareholders.

I will now turn the call back to John for some closing remarks.

Great, and thank you, Cam. 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 nor take credit for a higher commodity price environment, but the key is to run well, well at last, and capitalize on the opportunity. Across the business, we delivered on our commitments, outperformed our plans, and built momentum for what will be a strong second half of 2026.

We are now seeing the payoff from years of discipline and 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 a 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 is 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 and development.

CENOVUS is committed to working with our partners and both the Canadian and Alberta governments to work towards definitive agreements to make this a 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 getting 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 will continue to responsibly develop resources, support our communities in which we do business, be disciplined allocators or 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.

Yeah, so, you know, Greg, we believe that, you know, solvent-assisted, you know, SAGD, you know, 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 a project in Spruce Lake to bring on, you know, kind of 10,000 barrels a day in the 2028 timeframe.

You know, 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, you know, as we've always been really clear about, you know, in this business, SOR is king, and this is a way to get the SOR down, get more volume for less steam. And there's, you know, some application, as I mentioned, across some of our portfolio. But, Andrew, maybe you want to address a little bit there, too.

Yeah, no, happy to. Morning, Greg. Yeah, indeed. As John said, this is a targeted application of solvents, and we're doing it in a high-quality reservoir in Saskatchewan at an area called Spruce Lake. And what we're really hoping to achieve here is actually a production increment of about 40 to 50 percent and an SOR reduction of about 30 percent. 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, 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 next decade in more challenging reservoirs.

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

Then with the jump overs and the interconnectedness of the plants, we're able to reroute process streams to minimize the loss of production during the turnaround window. 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 F, phase G turnaround, we start thinking about what that's going to look like in five years and what are we going to do in this window to minimize the production impact in the 20, I guess it would be 2031 turnaround when that scheduled turnaround comes up again. This is something that happens through time. It's something you design into your plants 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.

Yeah, no, I'm happy to. It's Andrew again. John, Sonia, 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 four 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. You know, we've done a lot of integrity management and condition-based monitoring over the years, so we now go cycle time at five-plus years of each of the turnarounds. So that's an important step, Greg.

Then on the terms of the scope, 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's some kudos goes to our operations team. Our operations team is doing a phenomenal job during the execution of the turnarounds themselves, leveraging what John 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 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 been able to spread them out, you'll see sort of one or two lighter turnarounds each year.

That's right.

Thanks, Greg.

You're asking us to front run our investor day in January, but we're actually working on the interconnectedness of Christina Lake North and our Christina plant today. Okay. Andrew, maybe you're the best person to answer Dennis's question.

Yeah, 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 record, 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, 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. Similarly, 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 in even between the two areas. We were 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 two plants. So again, you know, 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 invested in January. That's where we're really going to showcase not only what we're going to do to try further value in the subsurface, but also utilizing the surface infrastructure better.

Dennis, your question on plant constraints is kind of interesting as well, because when we kind of look at Christina North, we've been field 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, you know, 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, you know, I think we're going to be surprised to the upside of it. And that's going to, you know, form part of our thinking as we start to integrate these plants and work towards, you know, one Christina Lake that has two interconnected plants. You know, as we work through the latter part of this decade.

Yes, we've done a lot of work on the Sunrise facility since we acquired 100% of it back in 2022. And the original design basis was two 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 four years and a lot of de-bottlenecking and creating sort of that interconnectedness between the two to facilitate higher production rates. But we haven't really found the facility constraints there because we are, again, production constrained or field constrained.

So the 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. That is something that we are going to continue to work through, continue to de-bottleneck, and continue to push the limits of where those constraints might manifest themselves today. 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 line out.

Yeah, I could probably add one more color commentary too. So indeed, we haven't pushed the boundary yet. I'm so proud of the team for how they pushed 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. I think what we're looking 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 Invest Today, we'll talk a bit more to kind of what our plans are there.

Great. Thanks, Dennis.

Yeah, 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, you know, 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, you know, 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, you know, days at Christina Lake where we're over 300. So we think that, you know, the kind of 50,000 barrels a day increment that we've given you is largely attributable to those two assets. Over and above that, we still expect to have increasing production from Sunrise. We mentioned that'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, you know, in thinking through this, you know, we want to give you sort of that P50 number where, you know, 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.

Yeah, so maybe I'll start this and then, you know, Jeff can finish it. But, you know, we consume far more than we produce. Well, not including the Lloyd Upgrader, I guess. You know, in our conventional business, we're about 20,000 barrels a day. We would consume about 240,000 barrels a day, much of which we bring from the U. S. 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 that 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.

Jeff? 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 we have to take your question in sort of two 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 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, you know, 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 to. So we'd see that being a price-based response. And then, you know, 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 a DRU, which recycles condensate in Alberta, and that's a potential for the future. I will now turn the call over to management for the CENOVUS ENERGY INC However as we point out if there is pretty significant growth in a more expedited basis you see those sorts of projects be brought to bear sooner to be able to meet the demand Thanks to you both.

Great. Thanks, Mano.

Well, you know, 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. You know, 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 is pretty exciting for this industry.

You know, that's it. We're drilling, you know, 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 package is a series of six 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 de-rest and be on the cusp of first production is something that we're pretty excited about, and we've been waiting for it for quite a while.

Thanks, Neil.

Yeah, thanks, Patrick. This is Eric. I appreciate the question. I think, yeah, just thinking about the Lima turnaround, you know, it is something we've been focused quite a bit on. The team has worked very hard to be prepared for it. You know, it really is getting after the crude unit, the vac unit, the isocracer, the hydrocracker, reformer, and then a couple other units. So it's a big chunk of work. And as I said, the team has been working really hard at it. I think even 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 is 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. So, you know, I think, as you said, you know, it's obviously a very strong crack environment. You know, 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, you know, get our products to the market when the market needs it. Yeah, it's something we'll continue to look at for Lima, but I see it's a big turnaround.

We are ready for it, and our focus is on executing it safely and executing it well. That is really where we are right now.

Yeah, I think the way to think about it, Patrick, is more of our capital this year has been directed towards our montany positions vis-a-vis the deep basin. So we have some areas there that we're investing in, largely in the liquids-rich portion, as well as up in the Tupper area. But I think that's a progression that you'll see through time, is continuing 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.

You know, I'm going to turn that question over to Jeff to answer. That's pretty broad.

What I would say is that Canadian crude has a really natural home in the U. S. , and it's been finding its way there. There's the pipelines, there's the 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 has impacted it. I mean, we all watch benchmarks in WTI and Brent. Something that's less observable is 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 two. 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 two 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 expand looking into the future.

Yeah, 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, you know, really getting after, you know, Great Lakes expansion in terms of moving products to different markets and out of pad two, which is, you know, really seasonally congested.

And we're looking at how do you further optimize the value chain, and I'm talking both the heavy 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 are there opportunities within our NAFTA systems to really get after the right cuts and really monetize that system the way we can. And seeing just low capital constraint opportunities, constraint 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? So, you know, I can go on and on, but I would say there's just a number of opportunities that, you know, 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, you know, find more and more opportunities to get additional dollars per barrel as we continue to take this kit forward.

Great. Thanks, Manav.

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.