Cenovus Energy Inc. (CVE) Q3 2026 Earnings Call Transcript

Operator: Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Third Quarter 2026 Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press 1-1 on your touch-tone telephone. 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.

Patrick Read: Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2026 Third Quarter Results Conference Call. On the call this morning are CEO, Jonathan McKenzie, and CFO, Kam Sandhar, will take you through our results. Then we will open the line for John, Kam, other members of the Cenovus management team to take your questions. Before getting started, I will refer you to our advisories, located at the end of today's news release. These describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus's annual MD and A and our most recent AIF and Form 40 F. And as a reminder, all figures we reference on the call today will be in Canadian dollars unless otherwise noted. For the question-and-answer portion of the call, please keep to 1 question with a maximum of 1 follow-up. You are welcome to rejoin the queue for any other follow-up questions you may have. And for detailed modeling questions, please follow-up directly with our investor relations team after the call. I will now turn the call over to John. Jonathan, please go ahead.

Jonathan McKenzie: Great. Thank you, Patrick. And good morning, everybody. I would like to begin by recognizing our safety performance and the people across Cenovus who work diligently to keep their colleagues, communities, and our assets safe. Their commitment has been particularly evident during our turnarounds. Over the past 18 months, our teams have successfully executed 4 major turnarounds, all without a recordable injury. That track record speaks to the preparation, discipline, and safety culture our people bring to these complex events. For the most recent Christina Lake turnaround, we drew on experience from across our oil sands operations to help us manage significant and competing critical path work within a compressed window. The result was a turnaround delivered safely, ahead of schedule, and under budget. So now turning to our third quarter results. In our upstream business, production increased by more than 50 thousand barrels a day from the prior quarter to average nearly 1.025 million BOE per day, surpassing the 1 million BOE per day milestone. Oil sands was the primary driver of the increase producing more than 830 thousand barrels per day and setting a third consecutive quarterly production record. At Christina Lake, we reached another all time high of 381 thousand barrels per day with continued strength at Narrows Lake and from across the redevelopment well program at Christina Lake North. This more than offset the impacts of our planned turnaround, which was completed in September ahead of schedule and with less production impact than expected. In fact, the turnaround outperformed our updated plan, which we had already improved through the revised guidance we set out in second quarter results. Through a combination of strong planning and proactive management of the water oil ratio, we were able to shorten the timeline by 4 days which allowed us to produce more oil through the plant, reducing the production impact of the turnaround by approximately 180 thousand barrels. Reservoir performance also continues to exceed expectations with Narrows Lake production reaching as high as 82 thousand barrels per day during the quarter. The fifth Narrows Lake well pad is now being steamed and is expected to be online near the end of the year, which will help sustain these higher rates into 2027. At Christina Lake North, the facility expansion project remains ahead of plan while the redevelopment well program continues to support higher production. By the end of September, we had 22 redevelopment wells online. Contributing to production of more than 115 thousand barrels a day during the quarter. The 15 generator was brought on in early October alongside our second new well pad since acquiring Christina Lake North. Together, these additional. These additions support a 2026 exit rate of around 125 thousand barrels per day which represents an increase of about 15 thousand to 20 thousand barrels a day since we acquired this asset last year. At Foster Creek, production increased to an all time high of 148 thousand barrels per day, up more than 30 thousand barrels a day from the second quarter. We brought on 6 new well pads so far this year following the completion of the Foster Creek optimization project. The initial reservoir performance has been exceptional. In fact, both Foster Creek and Christina Lake, very strong well performance has resulted in our new projects producing well above expectations. At the same time, we have optimized our facilities in real time to handle more production than we previously thought possible enabling us to produce above capacity and accelerate recovery of the resource. Moving to Sunrise, production averaged 70 thousand barrels a day in the quarter, marking the early achievement of a production target we had originally set for 2027. That compares to production of around 45 thousand barrels a day when we acquired full ownership of the asset in 2022. An increase of around 25 thousand barrels per day. That performance reflects the work our people have done to implement our operating model development practices at Sunrise. Finding better ways to manage water, pressure, and steam to improve reservoir performance. With our second pad on the East Side of Sunrise now online, and 2 others planned for next year, we will sustain these higher production rates well into 2027 and beyond. At our Lloydminster thermal assets, production averaged over 100 thousand barrels a day in the quarter. Construction is progressing on the Spruce Lake Dilsap project. We expect that to add about 10 thousand barrels a day of incremental when it comes online in 2028. At the same time, we have optimized our production across our oil sands assets. We have maintained a relentless focus on costs. We have reduced unit operating costs by nearly $3 a barrel over the past 4 years, and our oil sands operating cost per barrel this quarter were the lowest that they have been since the acquisition of Husky in 2021. The continued volume growth we have delivered, the continued volume growth we have delivered with largely the same infrastructure in place has contributed to our lower unit costs. But just as importantly, this performance reflects the focus we bring every day to controlling costs and building on our position as the lowest cost producer in the oil sands. Moving to the offshore business at West White Rose, we have completed drilling the first production well. The reservoir section has come in as expected. And completion and tie in activities are now underway. We are excited to be close to, first oil from the project that will soon become an important contributor of free cash flow to this company. Moving to the downstream, strong financial product pricing drove benchmark cracks to historic levels in the third quarter and we are well positioned operationally and to capture that value. In the Canadian refining, crude throughput reached a record of 120 thousand barrels per day in the quarter or about 112% utilization. Both the Lloyd upgrader and refinery operated above rated capacity, reflecting the solid operating performance we have come to expect from these assets. Strong diesel pricing in the quarter coincided with record diesel production of approximately 18 thousand barrels a day at the Lloydminster upgrader. Now those same market fundamentals supported premium pricing for synthetic oil given its high distillate yield contributing to exceptional financial performance from our Canadian refining business. Turning to US refining Crude throughput was approximately 317 thousand barrels a day representing crude unit utilization of about 87% as we executed a major turnaround at Lima. The turnaround commenced in early September and was concluded at the end of October. Adjusted market capture in US refining was very strong at 88%. Supported by strong operating performance and commercial optimization including moving gasoline and jet fuel into higher value markets and drawing down inventories when pricing was attractive. In September, we began utilizing our share of 40 thousand-barrel-a-day expansion on the Laurel pipeline providing another important outlet for products from the Chicago market. In combination with our continued movements from the dock in Toledo, we have increased our ability to access higher value markets in PADD 1 and the Great Lakes region. I also want to take a moment to speak about our acquisition of Athabasca Oil. The rationale for this transaction for Cenovus is very clear. Athabasca brings a high quality oil sands resource base with decades of development potential. Adjacent to our existing lands where we have a strong understanding of the resource and its potential. Opportunities to add thermal reserves development inventory of this scale are increasingly rare. And we have a proven track record of applying our operating model to improve performance and create value from these types of assets. Athabasca shareholder meeting has been scheduled for November 27 and we anticipate the transaction will close in December subject to the remaining approvals and customary closing conditions. We have a great deal of respect for the foundation at Athabasca has built, and we are excited about the opportunity ahead of us with full confidence in the value that we can deliver on these assets over time. Across our business, we saw the benefits of strong execution translate into record operating and financial performance in the third quarter and we are carrying that momentum through to the rest of the year. I will now turn it over to Kam to walk through our financial results.

Kam S. Sandhar: Thanks, John. Good morning, everyone. In the third quarter, we generated approximately $6.3 billion of operating margin and $5 billion of adjusted funds flow both quarterly records. Upstream operating margin was over $4.5 billion slightly below the prior quarter as lower benchmark oil prices were partially offset by production that increased by more than 50 thousand BOE a day. Our oil sands nonfuel operating costs were down to $7.80 a barrel, down almost 50 cents a barrel from the second quarter reinforcing the cost performance John highlighted with unit costs across the oil sands portfolio down nearly $3 a barrel over the past 4 years. This performance reflects the disciplined way we continue to operate our oil sands assets with our technical teams optimizing existing assets to deliver record production while maintaining low industry leading SORs and strong cost control. In the downstream, the strong margin environment and solid operating performance translate into record operating margin of approximately $1.8 billion nearly double the prior quarter. Canadian refining contributed approximately $420 million of operating margins supported by record throughput and strong synthetic and diesel margins. The higher throughput also helped reduce unit costs unit operating costs by over $2.50 a barrel from the prior quarter to $9.70 a barrel. We also closed the sale of our Canadian commercial fuels business in August for approximately $260 million in cash proceeds after closing adjustments. U. S. Refining generated approximately $1.4 billion of operating margin with adjusted market capture increasing to 88% from 67% in the second quarter. Reflecting the stronger commercial and operating performance John discussed. Adjusted market capture in the third quarter, including the benefit of 1-time items such as the small refinery exemption waivers at Superior. Excluding these items, market capture was over 80% in the quarter. U. S. Refining operating costs were approximately $12.30 a barrel up from the previous quarter due to lower throughput volumes associated with the turnaround at Lima and expense projects deployed during the turnaround outage. Capital investment in the third quarter was approximately $1.5 billion primarily directed towards sustaining activity, the Lima turnaround and investment in our growth projects at Christina Lake North, and West White Rose. Record adjusted funds flow of nearly $625 million reduction in noncash working capital drove net debt down another $2.4 billion to the end of the quarter to $3 billion. The working capital movement was primarily driven by an $830 million increase in income taxes payable, reflecting timing differences between accruals and cash payments which are expected to reverse in the first quarter of 2027. We have now reduced net debt by approximately $5.1 billion over the last 2 quarters. Total royalties and taxes recognized in the quarter rose to $3 billion At the same time, we returned $1.9 billion to shareholders during the quarter, including $1.5 billion through common share purchases under the normal course issuer bid and $430 million through common share dividends. In August, alone, we deployed nearly $1 billion towards common shares when we saw an opportunity to acquire shares at what would be a compelling value. Our current NCIB expires on November 10, and we have received approval to apply for the renewal of the program for next year. The unique cash generating capacity of our business allows us to strengthen the balance sheet, invest in growth, make record royalty and tax payments to governments, while returning significant cash to shareholders, underscoring our balanced approach to capital allocation. Looking forward to the remainder of the year with our oil sands assets continue to perform above expectations and with the optimization we were able to achieve during the Christina Lake turnaround, we are now expecting full year production to come in over 1 million BOE a day closer to the high end of our guidance range of 970 thousand to 1.01 million BOE a day. We also expect capital investment to be at the top end or slightly above our guidance range of $5 billion to $5.3 billion as a result of a longer duration of capitalizing costs at West White Rose FX impacts in the downstream business as a result of the weakened Canadian dollar, and modest increases in growth capital in the upstream in the second half of the year. I will now turn the call back to John for some closing remarks.

Jonathan McKenzie: Great. Thank you, Kam. This quarter established a new level of performance across our portfolio. With the upstream production well above 1 million BOE per day and record results at Christina Lake, Foster Creek, and Sunrise. More importantly, that performance reflects the underlying strength of our assets and the ways our people continue to increase productive capacity, improve reliability, and get more from our existing infrastructure. We have also worked through significant planned maintenance with the Christina Lake and Lima turnarounds behind us, are positioned to carry this operating momentum forward. The next milestones are also close in hand. Christina Lake North is positioned to exit this year at about 125 thousand barrels a day. West White Rose is approaching first oil, and we expect to complete the Athabasca acquisition in December. Setting the stage for more opportunity and growth to come. We are continuing to build a stronger operating base with more opportunity ahead and financial capacity to pursue investments that create value for shareholders while creating a more resilient company. And with that, I am open to your questions.

Operator: Thank you. If you have a question at this time, please press star then 1 on your touch-tone telephone. We ask that you please limit yourself to 1 question and 1 follow-up. 1 moment for our questions. Our first question is from Menno Hulshof from TD Securities. Please go ahead.

Menno Hulshof: Thanks, and good morning, everyone. Good morning, John. I will start with a question on the heavy differential. it is clearly a lot wider than most were expecting. Shipping cost appears to be a big part of it. But I guess the question is, how is this impacting how you are thinking about upstream activity levels in 2027 and beyond? And I ask that knowing that you have not guided for 2027. But, how is that sort of impacting your overall thinking?

Jonathan McKenzie: You know, right now, Menno, there is not much in the commodity pricing world that is trading off fundamentals, geopolitics, you seems to be really the overriding factor. So 1 of the things we do is we really think about what is being driven by fundamentals versus what is more fleeting being driven by other factors that we expect to be temporary. So you know, the short answer is it does not affect our thinking at all. What we will continue to execute is our long term plans. And continue to execute on our strategy and operate well through this. But Jeff, maybe you might have some thoughts around what is going on and what is driving that wider differential and why it really is not affecting our longer term plans.

Jeffery G. Lawson: You know, Menno, you kind of summarized it really well. The first thing people tend to see is WCS differential at Hardisty get wider and then ask what is happened to Alberta congestion, which pipe, and that sort of thing. And that is a historical view. This is much more driven globally and what you point to in The US Gulf Coast. Is really the answer right now, which is freight, freight, freight, and freight. Which, as John pointed out, is driven by you know, geopolitics and global events. You know, I think what. Looking forward through next year, and I do not know if anybody knows exactly when everything starts to normalize, but we do anticipate through time that freight will normalize. Natural gas prices globally will normalize, and that will back into the diff, which is exactly why John pointed in our long term capital thinking it does not make a does not make a difference to what we are going to do that way. However, as we execute in and around commodity transactions, we do look to the fact that the West Coast is, is attractive right now relative to the Gulf Coast. And that just allows us to use the assets we have to, to optimize our netbacks.

Jonathan McKenzie: Yeah, it is funny, Menno. I see Eric smiling because this is actually good for his business. You know, the first 250 thousand barrels a day, of our heavy oil runs through his assets, and he kept all of that dislocation today. So I am sure a question is coming later on about 70% capture, and we will put that on Eric to kind of bake in his thinking there.

Menno Hulshof: Terrific. Yeah. No. That. that is really helpful, and it is actually a good segue into the next question. And I will not ask the market capture question, but maybe it is somewhat related. Refined product egress out of PADD 2. I know you have been working on this. A lot. You mentioned doing. In your prepared remarks, you mentioned doing more on the Laurel pipeline, getting more into the Great Lakes region. But, would you just be able to maybe elaborate on what that looks like? From a volumes perspective, the potential margin uplift? I guess market capture is part of that as well?

Jonathan McKenzie: Yeah. No. We have been doing a lot of work on that, and I will get Eric to comment on it. But we have been doing a lot of work on the dock at Toledo, and I mentioned the Laurel pipeline is now active, and we look at our terminal positions as other ways to mitigate any kind of congestion issues. And then longer term, the project of Phillips is put forward should give us some real structural decongestion of PADD 2. But Eric, why do not you talk about the work that we are doing to optimize our product margins?

Eric Zimpfer: Yeah. Thanks, John, and I appreciate the question. I think John summarized it well. I mean, we look at PADD 2 and just look at our facilities, always looking for how do we find the highest netback and how do we place our products in the right market You know, having the dock at Toledo is absolutely an advantage for us and the team did a really good job in Q3 of really optimizing the barrels in the Ohio Valley region. So that is both the Toledo and Lima refineries to make to make sure we are placing the products into the markets, that are most advantaged. And so we saw record performance, through the Toledo dock. We have a number of investments that we are looking at to just continue to strengthen that facility continue to look at how do we expand through the dock into a number of different markets, which we are pretty excited about. Yeah. The Laurel pipeline is, I think, another example of how the region and the industry is balancing product flows and seeing the opportunity to help supply positions further to the east. And so being able to get onto that pipeline and moving some barrels already and then looking forward into Q4 with more barrels flowing that way. Again, we just see a tremendous opportunity to help reduce some of the congestion in PADD 2, but really access some of the more advantaged markets that we are seeing there in PADD 1. So, you know, we will continue to look at the different markets we can access, but we have got a great team that is continually looking to optimize and really excited about, you know, being able to continue to advance our positions there.

Menno Hulshof: Thanks to you both. I will turn it back.

Operator: Thank you, Menno. Thank you. Next question is from Greg Pardy from RBC Capital Markets.

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

Jonathan McKenzie: Yeah, you know, we are we are always looking, Greg, at things that we can do both on the assets as well as what we can do commercially. In refining, you typically have 3 levers. You have got the crude feedstock, you have got product placements, and then you have got your operating cost that sit right in the middle. And you know, the value proposition or the magnitude of the value proposition is kind of in that ordering. And we certainly are looking at a number of things that we can do operationally as well as commercially to kind of optimize that. But maybe I will turn it over to you, Eric. You can tell how you are thinking about the business in terms of margin expansion through the portfolio that you have got.

Eric Zimpfer: Yep. Yeah. And thanks for the question. You know, what I would just probably reiterate, John, and Jeffery's point, I think with these heavy differentials, it really reinforces the value of the integrated model. I think the value of having a downstream in the heavy oil value chain really becomes very clear. And this quarter, I think, a great example of that. Certainly, looking at the wider heavy differentials to again reinforce why we have a downstream. As John said, I think as we have really worked to get reliability up and manage our sustaining capital has created the opportunity to look more at some of the growth opportunities. And some of that comes in a variety of forms. I just spoke to market and so continuing to invest in the Toledo dock to be able to place barrels and more barrels into more advantaged markets. We are looking at how do we improve our yields and how do we get more distillate and jet and diesel yields, how do we continue to optimize across the Ohio Valley region and really unlock some of the synergies that we see that we are pretty excited about Even in Canada, we are seeing opportunities to invest in those facilities to just grow the margin with the barrels we are running. We have done--the team has done a really good job of expanding throughput there, and we see opportunities to improve the yields, to get more advantaged products as we go. So a number of different investment opportunities we are looking at to just grow within our existing facilities, improve market access, improve yields, and just continue to make the business more robust and strengthen that integrated heavy oil value chain that we have built.

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

Jonathan McKenzie: Yeah. I would not read too much into that, Greg. You know, at the end of the day, we would view we are going to be buying those shares anyway, and we are pretty clear about how we are going to vote those shares. So it is just a bit of an insurance policy that you know, adds to deal certainty and is something we are always looking for.

Greg Pardy: Got it. Thanks very much.

Jonathan McKenzie: Thanks, Greg.

Operator: Thank you. Next question is from Neil Singhvi Mehta from Goldman Sachs. You may proceed.

Neil Mehta: Hey, John and team. Congrats on the results. A quick 1 on West White Rose. Just give us a mark to market on where we stand there. It sounds like it is getting pretty close to first oil here. And how are you thinking about the pace of start-up through 2027?

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

Andrew Dahlin: Yeah. No. And if you think about it, we did finish just TD-ing, the first production well, completing that as we speak. We will get that on production shortly. And just to reiterate and put some more color on what John just spoke to, we then go into a state of concurrent operations on the Wellhead platform. We will have production operations from the first well. And in concurrently with that, we will actually start drilling the second well. And then on an average of sort of--every 90 days or so, we will put subsequent production wells on. So, obviously, first production well on here, this year, second production, and third and fourth production wells on in 2027. And then we will just complete, continue doing that through the next 4 or 5 years. Ramping production up to. On a gross level, right, roughly 80 thousand barrels a day by 2028-2029.

Jonathan McKenzie: Yeah.

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

Jonathan McKenzie: Yeah, you know, 1 of the things I am incredibly proud of is the way that our upstream business, in particular, our heavy oil business just continues to find ways to grind costs out of our business. Doing it on, a quarter after quarter basis But I think in our oil sands business this quarter, we were down to $10 a barrel Canadian across the portfolio. And it is not just scale, Neil. Like, this is coming across all the different asset groups that we have got, whether it is Lloydminster, Sunrise. Or FCCL. So there is certainly a piece of it you know, where the volumes and working on the denominator of those unit costs is really paid dividends. But it is it is more than that. it is the operating model. it is it is getting the maintenance cost down. it is getting the chemical cost down, and it is just finding ways to continue to do things better. So 1 of the things about this business that, you know, I firmly believe is this is a commodity business and the low cost producer wins and across our oil sands base, not only the biggest producer but we are the lowest cost producer as well. So you know, I am just incredibly proud of the work that we have done. And as we kind of look into 2027, I think you are right. We are going to get some inflationary pressure. You know, across this business and across this industry. But I am pretty confident that we are going to be able to beat a lot of this back. And that is kind of been our history. it is what we expect from our people. And putting more volume through, you a fixed-cost base helps that. But we are always focused on our unit cost and keeping those very, very competitive relative to our peer group.

Neil Mehta: Thanks, John. Appreciate it.

Jonathan McKenzie: Thanks, Neil.

Operator: Thank you. I would like to remind you that you have if you are on the phone and wish to ask a question, please press star then 1. Next question. Is from Travis Wood from National Bank Financial. Please go ahead.

Jonathan McKenzie: Yeah. Good morning, Travis.

Travis Wood: Yeah. Good morning, John.

Jonathan McKenzie: Question is around the change in policy.

Travis Wood: In Alberta around the caribou lands, and I am trying to get an understanding and making sure that I understand the process in terms of what that could mean for organic opportunities within Cenovus, whether that is through parts of even Athabasca But I think I am more so thinking about Surmont from the Mag transaction. Does that change in policy significantly change the kind of near term to midterm growth plan for brownfield expansions, kind of like you did over the past 5 years? Yeah.

Jonathan McKenzie: You know what? I think--you know, there is a lot being made of the land sale, and we are obviously looking at this and looking at this, and I do not know that it changes any of our strategy, Travis. You know, I think we look at things incrementally versus something that is gonna fundamentally change the direction that we are going. So we are looking at what is become available. You know, we are doing our analysis. We are trying to think through some of the uncertainty that you referenced. With regard to the regulation in and around this. But we think about it the same way we look at everything. it is another opportunity that is gonna come across our desks, and we are gonna properly evaluate it and think through what synergies that might add, to the assets that are inside the portfolio and how we might add value from it. But there--you know, to the point you mentioned, there is still a fair amount of uncertainty around how this is actually gonna manifest itself, but do not think about it as something that changes our strategy or operating plans materially.

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

Jonathan McKenzie: I think the way to think about it is there could be oil sand leases that become available through this process. Where before they were not available because they were in areas that were designated as caribou lands. That were sterilized.

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

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

Jeffery G. Lawson: And, Travis, I think we have some incredibly nuanced bespoke agreements to hammer out. And they are tough because they are new. No 1's drafted them before. that is around carbon capture, 6 megatons, incremental 10 megatons. But what you should take away is that both levels of government, the feds and the province, have been great to deal with. They have been pragmatic. They are trying to push this ahead. So if you look at what we have got so far, we have got the mega productivity deduction. We have got changes to the impact assessment act, which really give primacy to Alberta. So we do not have a bunch of oil sands stuff locked up because the Impact Assessment Act. We have got the West Coast Oil pipeline as a project of national interest. Both levels of government and a shift to the BC government now wanting to get that done. All positive. On the Alberta side, the premier's publicly said they are going to come out with their growth incentive royalty. And they are gonna come up with some modifications to supports for the system. So it feels like all this stuff is coming together in the right place. Now we need to hammer out actually the trade off for that, which is what our 6-megaton carbon capture project looks like. All the companies are aligned in hammering that out. If we have all the support in place. So it is all coming together. You know, November 15 is a pretty tight timeline to get all this stuff done, but we are working towards that. And I guess we will play it week by week if we actually hit that timeline. But we are on a path. We are not falling off the path, and we are pushing forward on it.

Travis Wood: Okay. Thank you so much for the color, guys. I will turn it back.

Jonathan McKenzie: Great. Thanks, Travis.

Operator: Thank you. There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jonathan McKenzie.

Jonathan McKenzie: Great. Thank you, operator. So this concludes the conference call. Thank you all for joining us. We appreciate your interest in the company. Thank you very much, and have a great day.

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