管理層發言
Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Second Quarter 2026 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' 2026 Second Quarter Results Conference Call. On the call this morning are CEO, Jon McKenzie; and CFO, Kam Sandhar, who will take you through our results. Then we'll open the line for Jon, Kam and other members of the Cenovus management team to take your questions. Before getting started, I'll refer you to our advisories located at the end of today's news release. These describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus' annual MD&A and our most recent AIF and Form 40-F. And as a reminder, all figures we reference on the call today will be in Canadian dollars, unless otherwise indicated. For the question-and-answer portion of the call, please keep to one question with a maximum of one follow-up. You're welcome to rejoin the queue for any other follow-up questions you may have. For detailed modeling questions, please follow up directly with our Investor Relations team after the call. I will now turn the call over to Jon. Jon, please go ahead.
Great. And thank you, Patrick, and good morning, everyone. As always, I'd like to begin by recognizing our safety performance and those who protect our people and our assets each and every day. On May 19, we safely completed the Foster Creek enhanced sulfur recovery project ahead of schedule and on budget. This is the fourth major project our projects group has safely and economically delivered over the last 14 months. After 24 months and 600,000 hours of work, the sulfur recovery unit was put into service, marking our first application of this technology in SAGD operations. The project improves how we manage Foster Creek. It lowers chemical operating costs by $0.50 to $0.75 a barrel, supports regulatory compliance and removes about 700 trucks per year from the road at site. Most importantly, though, with an established track record of consistently bringing projects online on time and on budget with outstanding safety performance, we continue to see our projects organization as a competitive advantage for Cenovus. So now turning to our results. This was another strong quarter for Cenovus, and we're well positioned for continued performance and growth through the remainder of 2026 and into 2027. 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 sands 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 SAGD assets in the basin, and the growth we expected from Narrows Lake is coming much sooner than forecast. Notably, we reached the 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 Lake North, the integration work is progressing seamlessly. We have delivered on all the upfront commercial and corporate synergies and remain on track to increase production to 150,000 barrels a day by 2028. We're seeing production volumes from Christina Lake North respond well with current rates reaching above rated capacity of 110,000 barrels per day. As our redevelopment program progresses and with our first new pad since the acquisition now online and performing well and with the commissioning of the fifth OTSG later this year, we expect production from this field to increase in the second half of the year. In the third quarter, we will conduct a plant turnaround on Phase F and G at Christina Lake. As always, we continue to optimize the scope and execution of these major maintenance events to reduce the duration, cost and production 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 Creek turnaround earlier this year, we are now on track to produce over 1.2 million more barrels than were budgeted during the turnarounds this year. This has been reflected in our revised annual guidance. At Foster Creek, production in the quarter was approximately 215,000 barrels a day. The asset exited the quarter at record production levels of 245,000 to 250,000 barrels a day which continued through July. As mentioned earlier, we also brought on a sulfur recovery unit well ahead of schedule, which is expected to reduce operating costs at Foster Creek by $0.50 to $0.75 per barrel. Moving to Sunrise, production was nearly 66,000 barrels a day during the quarter, following the startup of the first well pad in the East development area. With continued strong performance at Sunrise, we are now regularly exceeding 70,000 barrels a day of production, a target originally planned for 2027. We're also seeing consistent contribution from our Lloydminster Thermal assets, where production averaged 103,000 barrels a day for the quarter. Strong results from the redevelopment program continues to deliver production ahead of our expectations at Spruce Lake, Pikes Peak and 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 increase in contributions from the East Coast to meaningfully support production growth and the cash flow profile. Now moving to the downstream business, strong operational availability across our assets saw us capitalize on a supportive pricing environment in the second quarter. The Canadian refining business delivered crude throughput of 102,000 barrels per day or utilization rate of roughly 94%. Operations in the quarter included scheduled maintenance on the second train of the hydrocracker at the Lloyd Upgrader, which was delivered under budget, setting the stage for consistent operations in the second half of this year and all the way through 2027. In the U.S. refining business, market conditions were highly favorable in the second quarter, supported by low Midwest inventories, robust crack spreads and wider heavy oil differentials. Crude throughput averaged 350,000 barrels per day or approximately 96% utilization. The business continues to run well generating material adjusted cash flow for the company, and we are well prepared to execute the turnaround of the integrated unit in September and October this fall. All in all, Cenovus had a very strong quarter, and we expect that trend to continue as we continue to execute against our business plans. Now I'll turn it over to Kam to walk through our financial results.
Thanks, Jon, good morning, everyone. In the second quarter, we generated approximately $5.9 billion of operating margin and $5 billion of adjusted funds flow, both all-time highs for Cenovus. Upstream operating margin was over $4.9 billion, increasing from the prior quarter due to higher benchmark oil prices and increased oil sands production. As Jon mentioned, with stronger production volumes and cost performance across the business, we've updated our full year operating cost guidance with reductions to each of our oil sands, conventional and Asia Pacific costs. Our Oil Sands nonfuel operating costs were $8.28 a barrel, a reduction of almost $0.65 a barrel from the prior quarter. In our Conventional gas business, costs declined by nearly $0.50 per BOE quarter-over-quarter to $9.13 per BOE, reflecting an ongoing focus on cost control. In the Downstream, strong refined product pricing and widening heavy oil differentials supported a favorable margin environment. Operating margin was approximately $1 billion in the quarter; this included $144 million inventory holding gain between our Canadian and U.S. refining segments. That performance is supported by disciplined cost control and strong operational availability across our refining network. In the Canadian refining business, full year operating cost guidance is lowered by $1 per barrel to $11 per barrel at the midpoint, reflecting increased throughput guidance and lower repairs and maintenance. U.S. refining operating costs were $10.55 per barrel, almost $1.20 per barrel lower than the previous quarter, reflecting higher throughput volumes combined with lower energy and electricity prices. Adjusted market capture, as Jon mentioned, was 67% decreasing from the prior quarter with the rise in Midwest gasoline pricing and the lag in asphalt and secondary product prices. Capture is also impacted by temporary dislocations in domestic light crudes, including Bakken, Midland and WTI, which increased feedstock costs during the quarter. Capital investment in the second quarter was approximately $1.2 billion, supporting sustaining activity across the business alongside our in-flight growth projects at Christina Lake North, Sunrise, Foster Creek and West White Rose. We expect capital spend to be higher in the second half of the year as we continue to execute our program and maintenance activity increases with the planned turnaround at our Lima Refinery. Capital guidance for 2026 remains unchanged at $5 billion to $5.3 billion. With record adjusted funds flow and a nearly $700 million reduction in noncash 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 2026 before unwinding in the first quarter of 2027. With our revised guidance, we expect cash taxes to be $2.3 billion to $2.6 billion, of which a significant portion will be paid in February of 2027. During the quarter, we fully repaid the remaining $2.2 billion outstanding on the term loan that was obtained as part of the MEG acquisition in November. Reflecting the strength of the quarter, total royalty and tax payments rose to $2.7 billion. Shareholder returns in the second quarter were $1.4 billion, including $1 billion in common share purchases through the NCIB and $411 million through common share dividends. These outcomes highlight the significant value created for all of our stakeholders, including meaningful contributions to the province and the government in Canada via royalties, taxes, returns to shareholders and ongoing debt reduction. As our net debt is now below $6 billion, as per our revised financial framework we set out when we announced MEG, we will be increasing targeted shareholder returns to 75% of excess free funds over time while continuing to progress towards our long-term net debt target of $4 billion. Our shareholder returns targets should continue to be viewed as guidelines, and we will continue to exercise judgment, and maintain flexibility in where we allocate capital in a particular quarter to maximize value and focus on returns for our shareholders. I'll now turn the call back to Jon for some closing remarks.
Great. Thank you, Kam. So as I reflect on the quarter, what stands out is the consistency of our execution and the opportunities which our people continue to find to get more out of our assets. We would never apologize for a higher commodity price environment, but the key is to run well at all times 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're now seeing the payoff from years of disciplined investment and operational and technical focus. All of our growth projects in the oil sands are nearing or have exceeded full rates, while we continue to find ways to optimize performance. At the same time, our integrated business model continues to be an advantage. Our strong refinery availability provides reliable destination for our growing production, allowing us to capture the benefits of a robust downstream environment while minimizing our transportation costs and commitments. Now I'd be remiss if I did not also briefly address the trilateral agreement which members of the Oil Sands Alliance have entered into with the federal and Alberta governments earlier this month. While the MOU was only a first step, the agreement represents meaningful progress towards creating a competitive investment environment for Canada's vast oil sands resource base. Although the MOU still provides provisions for an uncompetitive carbon tax that uniquely burdens Canadian industry, it creates a framework for governments and industry to work together on production growth, emissions reduction and expanded market access. Most importantly, by acknowledging and committing to the need to put a competitive policy and regulation in place to support meaningful growth in Canadian oil sands as well as appropriate fiscal frameworks to support political priorities on carbon capture, the agreement establishes an important foundation for future investment and development. Cenovus is committed to working with our partners in both the Canadian and Alberta governments to work towards definitive agreements to make this reality. What matters most is this agreement signals a willingness to work together to grow the oil and gas sector for the benefit of all Canadians. This is an important step to get our economy moving forward again, creating high-paying jobs for Canadians and generating tax and royalty revenue to support Canada's quality of life and standard of living. And while the opportunity set for industry is expanding, our approach will be unchanged. We'll continue to responsibly develop resources, support the communities in which we do business, be disciplined in allocating 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.
分析師問答
The first question is from Greg Pardy with RBC Capital Markets.
And another really, really strong quarter. Good to see. Jon, within the release, a little bit is the sanctioning of the solvent-aided SAGD projects. I know it's not nothing, right? It's 10,000, 15,000 barrels a day. What's your thinking about broader implementation of solvent-aided SAGD over time?
Yes. So Greg, we believe that solvent-assisted SAGD has targeted application in some of the areas that we have within our portfolio. So this will be the first commercial application of that inside our portfolio. So you're quite right earlier in this year, we sanctioned the project in Spruce Lake to bring on kind of 10,000 barrels a day in the 2028 time frame. What we expect from that is there may be broader application within the Narrows Lake portfolio and some of the other parts of our business. But as we've always been really clear about in this business, SOR is king, and this is a way to get the SOR down, get more volume for less time. And there's some applications, as I mentioned, across some of our portfolio. Andrew, maybe you want to address a little bit or two.
Yes. No, happy to. Greg. Yes, indeed, as Jon said, this is a targeted application of solvents and we're doing it in a high-quality reservoir at Spruce Lake. And what we're really hoping to achieve here is actually a production increment of about 40% to 50% and an SOR reduction of about 30%. We see similar applications in high-quality reservoirs across our portfolio. But I think where our subsurface team is particularly excited is we also think that solvents could be a good fit for lower-quality resources. So for example, resources where you have thinner pay. So we're going in with this in a high-confidence area, and then we're looking at how we can take that technology further into the next decade in more challenging reservoirs.
Okay. Understood. And maybe just switching gears, staying on the ops side, as you mentioned that the shorter duration turnarounds now is becoming a big advantage. So the natural question is, how have you done that? Perhaps what are you doing now that you weren't doing before? Is it as simple as really planning or what's the special sauce behind that?
Yes. I think when people see the results, everybody looks for a special sauce. But what you have to remember is this is probably two decades worth of work in some of these plants. Now we're getting into the fourth and fifth turnaround cycle. The way these plants were designed in the phased application that we built them, we've had the opportunity to create interconnectedness, bypasses, isolation and the like. So the first key of any turnaround is getting as much work as you can out of the turnaround window and limiting scope that comes through isolation. And then with the jumpovers and the interconnectedness of the plants, we're able to reroute process streams to minimize the loss of production during the turnaround window. But this is not something that you do overnight. It's something that happens through time and something you design into your plans when you build it and then you optimize it through time. One of the things that we think about, for example, is as we move to the Christina phase F and G turnaround, we start thinking about what that's going to look like in five years, what are we going to do in this window to minimize the production impact in the 2031 turnaround when that scheduled turnaround comes up again. But this is something that happens through time and something you design into your plans when you build it and then you optimize it through time. I don't know if you have anything else you want to add on that?
Yes. No, happy to, it's Andrew again. Jon and I were talking about that the other day. I really think just to build on what Jon said, it really comes in sort of waves of things we've done. It starts off with the design of the plants, the scale of the plants and how we have multiple phases that we can leverage. Second thing is the cycle time of our turnarounds. We've done a lot of integrity management and condition-based monitoring over the years. So we now go cycle times of five-plus years for each of the turnarounds. So that's an important step, Greg. Then on the third leg would be 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 operational time rather than in a turnaround. And then finally, and here are some kudos to our operations team. Our operations team is doing a phenomenal job during the execution of the turnarounds themselves leveraging what Jon just spoke to. Quite a bit of confidence in that now. We obviously saw it at Foster Creek, where we had minimal production impact. We just guided you to a reduced impact of the turnaround coming up at Christina Lake. And then the other thing I'd just remind you, Greg, and everyone, is 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.
Next question is from Dennis Fong with CIBC.
Congrats as well on a strong quarter as well as the continued momentum you're showcasing in ops. My first question here maybe continues on from Greg's question. So Christina Lake on the back of Narrows Lake success as well as the work that you do in Christina Lake North. You previously talked potentially about interconnecting the two processing facilities. Can you talk towards one, maybe the strategy and how that maybe evolved just on the back that you've seen in Narrows as well as where you're seeing facility limits at either Christina Lake North or Christina Lake South? And how does that also optimize maybe the well development or how that shifted the well development and the next well pad locations that you're thinking about drilling between the two assets?
It's kind of funny. 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. Andrew, maybe you're the best person to answer Dennis' question.
Yes. I'll have a go. Maybe I'll take a giant step back and then kind of talk to the evolution of both Christina Lake and Christina Lake North and then how we're going to connect them. And the evolution of Christina Lake, you'll recall, Dennis, a couple of years ago, we were at 230,000, 235,000 barrels a day. We sanctioned the expansion and as well the tieback to Narrows Lake. And we've now taken Christina Lake production to close to 265,000, 270,000 barrels a day with Narrows Lake at 80,000 barrels a day plus. So we're seeing good performance there. Christina Lake still treated them separately at Q1, Q2 performance was in that sort of 105,000, 110,000 barrels a day. We're seeing that ramp up to probably towards 125,000 barrels a day by year-end, and that's a function of the redevelopment wells and as well the fifth OTSG coming on stream in Q4. And then we'll continue to grow Christina Lake up towards 150,000 barrels a day and beyond in 2028. Now, when we did the deal, we spoke to our investors and yourselves about the opportunity we had to optimize the subsurface and even between the two areas. We're really going now, not wanting to front run too much, Dennis, but we're really looking at how can we also physically connect the plants. So back to my answer earlier to Greg on the turnaround performance and how we're utilizing the scale and the phases of the plant. We actually see an opportunity here to optimize and get more juice out of the surface facility by actually connecting all the various pieces between the two plants. So again, I compliment the ops group earlier. Here, it's the projects group and the technical expertise that just amazes me every day. And quite frankly, the plan, Dennis, is Investor Day in January. That's where we're really going to showcase not only what we're going to do to drive further value in the subsurface, but also utilizing the surface infrastructure better.
Dennis, your question on plant constraints is kind of interesting as well because when we look at Christina Lake, we've been feeling 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 over 300,000 barrels a day. So what you will see is much higher Christina Lake production in July, and we expect that to continue. But we're really just kind of evaluating right now what are the plant limitations that we have inside these facilities. And I think we're going to be surprised to the upside on that, and that's going to form part of our thinking as we start to integrate these plants and work towards one Christina Lake that has two interconnected plants as we work through the latter part of this decade.
Definitely, definitely. I really appreciate that context from both of you. I wanted to shift to Sunrise and maybe carry along with that thought around facility constraints. From the last quarter, you kind of suggested that one of the two trains was able to run at a very high capacity at Sunrise during some planned maintenance there. How do you think about the go-forward development strategy around Sunrise? It seems like the facility, again, has a fair amount of ample capacity. Is it just how do you kind of drive the cadence of well drilling to further ramp that beyond the 70,000 barrel a day level, which you highlighted you just hit ahead of schedule?
Yes. We've done a lot of work on the Sunrise facility since we acquired 100% of it back in 2022. In the original design basis it 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, a lot of debottlenecking and creating 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. So the only challenge for us is to continue to work that up. As I mentioned in my notes, we're regularly over 70,000 barrels a day today with the first of the Eastern well pads now online. We expect to bring on the second later this year. But that is something that we are going to continue to work through, continue to debottleneck and continue to push the limits of where those constraints might manifest themselves today. But I think the short answer to your question is it's something higher than where we are today, but we're not really sure exactly where that's going to lie.
Yes, I can add one more color comment too. Indeed, we haven't pushed the boundary fully at Sunrise. So proud of the team for how they pushed the boundaries at FCCL. There's more to come here at Sunrise. The subsurface team are doing it now by going out east and looking to develop a reservoir that's up to 50 meters thick. What we look at in the facility is how can we expand it and how can we expand it relatively efficiently from a capital point of view. It looks to us at this stage that we have enough water treatment and oil treatment. And so what we need is more steam. Again, at Investor Day, we'll talk a bit more about what our plans are there.
So again, in all these things, it's about getting the SOR down and getting your production up and finding out where those debottleneck opportunities might land. But we've got room to go there.
Next question is from Menno Hulshof with TD Cowen.
I'll start with a question on the new production guidance range of just over 1 million BOE. Given that we're halfway through the year, what's the scenario where you hit the top end of the range or even eclipse it? And similarly, what would need to happen to only hit the bottom given you averaged 970 in the second quarter?
Yes. Maybe I'll start this and somebody else can kind of fill in some of my thinking on this. But what we try and give you, Menno, is a view to where we think P50 lies in terms of the future production guidance that we're giving you. And what's really clear to us is through a combination of the redevelopment programs, better reservoir performance and better production coming from the well pads that we are bringing on, production took a pretty significant jump in the month of July in particular at Christina Lake and in particular at Foster Creek. So we would expect to be somewhere around 245 at Foster Creek and somewhere around 285 at Christina Lake. And as I mentioned, we've had days at Christina Lake where we're over 300. So we think that the kind of 50,000 barrels a day increment that we've given is largely attributable to those two assets. Over and above that, we still expect to have increasing production from Sunrise. We mentioned it's up over 70,000 barrels a day pretty regularly right now, and we still expect to have increased production from the East Coast as we get to first oil as well as incremental production from Lloydminster and conventional. So in thinking through this, we want to give you sort of that P50 number where we've got an equal chance of being above or below it, but it gives you a balanced view of where we are inside the portfolio today and a balanced view of what we expect for the rest of this year and moving into 2027.
That all sounds very promising. I'll follow up with a question on basin condensate supply, given how topical it's become with the recent positive messaging on thermal growth from pretty much everybody. Can you remind us of how much condensate you can really produce versus consume? And then more broadly, does future supply concern you at all? And are you hearing of any industry initiatives to boost it over the next, call it, three to five years?
Yes. Maybe I'll start this, and then Jeff can finish it. But we consume far more than we produce. I think not including the Lloyd upgrader, in our conventional business, we're about 20,000 barrels a day of condensate production, and we would consume about 240,000 barrels a day, much of which we bring from the U.S. So condensate supply is something that we think about a lot, and we think about where it comes 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?
So I think it's a great question, particularly with some of the things Jon touched on around the MOU and the future potential growth. To take your question in sort of two parts in 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 are a number of ways that this resolves itself on a short-term basis month to month and week to week. I think you're speaking more to a longer-term structural thing. The first is if growth is orderly and measured, we would expect to see price 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 gas when it's the right time to and targeting dry gas when it's the right time too. So we'd see that being a price-based response. Then there has been pipeline creep through time where import pipelines have found new capacity, and that is an opportunity for the future. In the past, we've seen things like the development of the DRU, which recycles condensate in Alberta, and that's a potential for the future. And deeper into the past, we've seen things like structural rail bringing condensate in, and I don't know that we'll need to get there. I think we would try to see the market resolve itself in advance. However, as we point out, if there is significant growth in a more expedited basis, you'll see those sorts of projects be brought to bear sooner to be able to meet the demand.
Next question is from Neil Mehta with Goldman Sachs.
Jon, just love your perspective on this trilateral memorandum of understanding. I think when I think about some of your comments earlier this year to the comments on the call today, it definitely feels like you've made a lot of progress on this. So just practically from a Cenovus perspective, if you blue-sky this thing, what could it mean for the business in the early 2030s?
Well, I think one of the things that we've argued, Neil, is that we have to have a competitive regulatory and policy environment to attract capital into this industry going forward. I think with some of the impediments that came through policy and regulation, it became really difficult to attract capital into the oil sands business. I think that where we are today and what's been discussed and agreed on unlocks this business in terms of its investability. And I think that's something that's pretty exciting for Canada. This is probably the largest investment opportunity that we have as a country and to make it investable again and start to attract capital into this business without getting into specifics because I'm not at liberty to, but it is pretty exciting for this industry.
We'll look for more. West White Rose. It's finally here. It's been a journey obviously, and the topside on was a big deal last year, but it sounds like you're tracking for first oil by the end of the third quarter. What's left?
That's it. We're drilling the first production well now. So that well needs to be drilled and completed and get to first oil. And then what you'll see from us in the first well packages 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 derisked and beyond the cusp of first production is something that we're pretty excited about and we've been waiting for for quite a while.
Next question is from Patrick O'Rourke with ATB Cormark Capital Markets.
Congratulations on the record quarter here. Just wondering, with respect to the downstream and the Lima turnaround that's going to happen in the second half of the year, maybe if you could outline the sort of key activities and scope there. And I'm just curious with where cracks have been and are today? And it sounds like the plan is to go forward as initially designed, but would there be any thought to a reduction in scope or timing there?
Thanks, Patrick. This is Eric. I appreciate the question. I think just thinking about the Lima turnaround, yes, it is something we've been focused on quite a bit. The team has worked very hard to be prepared for it. We're really getting after the crude unit, the vacuum unit, the isocracker, the hydrocracker, the reformer and then a couple of 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 building on some of the themes around getting after reliability and getting after isolation and making the facility and the units more accessible online to get after certain things as part of the scope. There's quite a bit inside the back tower that we're going to do and really look to make sure that we can maximize heavy crude through Lima by getting that back tower cleaned up, turned around and ready to go. It's obviously a very strong crack environment. We've done a good job across the downstream in 2Q around trying to be as flexible as we can with some of our non-critical outages and moving them where we can to really support the supply disruption and get our products to the market when the market needs it. Yes, it's something we'll continue to look at for Lima, but I see it's a big turnaround. We're ready for it, and our focus is on executing it safely and executing it well, and that's really where we are right now.
Okay. Great. And then we all sort of saw the license activity that came through in the Montney in the quarter here. Just curious about the strategy there. Could it become a bigger piece of the puzzle in the conventional unit? Or is this more about filling up sort of unused facility capacity that you have right now?
Yes. I think the way to think about it, Patrick, is more of our capital this year has been directed towards our Montney positions vis-a-vis the Deep Basin. So we are investing in some areas there that are largely in the liquids-rich portion as well as in the top area. But I think that's a progression that you'll see through time: continue to invest more or direct more of our conventional capital into the Montney area vis-a-vis the Deep Basin, and that's really just driven by economics and strategy.
Next question is from Manav Gupta with UBS.
I wanted to ask a broader question. With the Strait of Hormuz, and we don't exactly know the status of when it will open, and whether it be a perpetual block there or some kind of de-risking over there, do you think there is a need for the U.S. refining system to pull a little harder from the Canadian upstream operations? I mean we are seeing U.S. utilization of 97% right now. And globally, the utilizations are much lower because they're unable to source that crude. And what's making this happen is the crude coming down from Canada. I understand there are some political tensions right now between the two countries. But going ahead, do you see the U.S. refining system even more dependent on the Canadian crude, given the geopolitical tensions out there?
That's pretty broad. What I would say is that heavy crude has a really natural home in the U.S., and it's been finding its way there. There's the pipeline, there are 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 Strait is impacted. We all watch benchmarks in WTI and Brent, but something that's less observable is where the physical barrel prices are and where we see that is in the WCS differential at the Gulf. 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. When you see times where there's more constraint in the Strait you see prices get stronger, minus $2; when tensions ease, that comes off toward minus $12. 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 go to a different place to answer your question, which is 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. That is really what's telling me more about the interconnectivity between the two countries rather than purely something out of the Strait. So I hope that helps. We continue to see the opportunity to expand in the future.
And my quick follow-up is, I think last year, you did a trip to the Lima refinery. You laid out certain goals in terms of the downstream business; we are seeing much stronger utilization. I'm just trying to understand from the point where you had set those goals for further improvement in downstream, how are you tracking against your own goals? And where else could we see further improvement in your downstream business?
Thanks for the question. The discussion we had last year outlined where we saw the business moving to. I think we've made really good progress. I'm really proud of what the team has done: safety performance is strong, and reliability has really started to improve. You're starting to see some of that optimization come through with a more reliable kit. I think we're just starting to get into some exciting opportunities as we look at some of the growth potential of the portfolio. Those are things like getting after Great Lakes expansion in terms of moving products to different markets and out of PADD 2, which is seasonally congested. We're looking at how to further optimize the value chain; I'm talking about both the oil value chain as well as the Ohio Valley system. Getting the right crude blends into our refineries and making sure that we're fully optimized on the upgrader, looking at the Ohio Valley and figuring out where there are opportunities within our naphtha systems to really get after the right cuts and monetize that system. Low-capital, constraint-busting opportunities exist across the portfolio as we're identifying some reliability improvements. The team has done well at placing more jet into the market. We're seeing strength in jet. So how do we pull more jet, how do we place more jet into the market? How do we find new market opportunities for that jet fuel? I could go on, but there are a number of opportunities that once you start to unlock reliability, it really unleashes a strong commercial team that can find more opportunities to get additional dollars per barrel as we continue to take this kit forward. Great. And thank you, operator. So this concludes our conference call. I'd just like to thank everybody for joining us. We obviously appreciate your interest in the company. So thank you very much, and have a great day.
Thank you. This concludes today's program. You may all disconnect. Thank you for participating in today's conference, and have a great day.