Camden Property Trust (CPT) Q3 2026 Earnings Call Transcript

Operator: Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp Third Quarter 2026 Financial and Operating Results Conference Call. After today's presentation, there will be the lower section of the webcast frame. I would now like to turn the conference over to Chad Kalmakoff, Vice President, Finance and Treasurer. Please go ahead.

Kimberly A. Callahan: Thank you, operator. Good morning, and welcome to Baytex's third quarter 2026 Results Conference Call. Joining me today are Chad Lundberg, our President and Chief Executive Officer Kendall Arthur, our Chief Operating Officer and Chad Kalmakoff, our Chief Financial Officer. Please note that our discussion today contains forward-looking statements within the meaning of applicable securities laws, I refer you to the advisories regarding forward-looking statements oil and gas information, and non-GAAP financial and capital management measures in yesterday's press release. All dollar amounts referenced in our remarks are in Canadian dollars unless otherwise specified. We will open the call for questions after our prepared remarks. Webcast participants are able to submit questions online. With that, let me turn the call over to Chad Lundberg.

Alexander J. K. Jessett: Good morning. We continue to execute our strategy with strong performance across our portfolio unlocking an opportunity rich set of growth options driving long term value for shareholders. In 2026, we have improved our capital efficiency, reduced operating costs, and lowered our decline rate and breakevens. Most importantly, safety performance has been strong. I want to thank our teams across the operations for their continued commitment to safety. The improvements we have made have translated into an accelerated growth plan. Improved capital efficiency, lower costs, and execution across the Duvernay and Heavy Oil portfolio enable an increase to our 2026 capital program and are the foundation of a higher growth plan for 2027 through 2029. This acceleration is driven by efficiency gains. Not a change in our commitment to capital discipline. Execution of our strategy once again illustrated by our Q3 results. Production averaged 71.6 thousand BOE per day up 5% from third quarter 2025 and in line with our full year plan. We delivered record Duvernay production of 12.8 thousand BOE per day continued to perform across the heavy oil portfolio and generated a $139 million of free cash flow. We also returned a $165 million to shareholders during the quarter through share repurchases and our base dividend. While exiting with a net cash position of $522 million For 2027, we expect production of 76 thousand to 79 thousand BOE per day. Representing 7% to 11% annual growth with exploration and development expenditures of $7.75 to $850 million This is the first year of full Duvernay commercialization which drives Q4 to Q4 growth of 15%. This program achieves a sustaining capital breakeven of $50 per barrel in 2027. Down from $52 in 2026. Which allows us to continue returning capital to shareholders. Our updated 3 year outlook has improved and now targets 8% to 10% annual production growth. Supported by capital expenditures of approximately $800 million This plan is built to deliver having exceeded our 15% total shareholder return target through the third quarter of 2026, we expect to achieve it again in 2027. At a mid cycle WTI price of $70 per barrel, we expect to maintain a net cash financial position throughout the 3 year plan. Funding production growth continued share repurchases and the base dividend. Kendall will take you through the operating performance. Chad Kalmakoff will cover off our financial position and capital allocation in more detail. Kendall, over to you.

Laurie A. Baker: Thanks, Chad. Third quarter production averaged 71.6 thousand BOE per day, and exploration and development expenditures were $186 million both in line with our full year plan. Beginning with the Duvernay, our second pad of 2026, a 5 well pad on our Northern Pembina acreage was brought on stream in late August. The wells generated average 30 day initial production rates of 1.49 thousand BOE per day per well including 973 barrels per day of oil. Drilling and completion performance continues to improve. Full length 2026 wells achieved drilling completion costs of $930 per foot of completed lateral. Better than budget and 11% lower than 2025. The shorter cycle times allow us to add 2 drills in the fourth quarter. Taking 2026 program to 19 wells drilled. 13 wells are expected on stream in 2026 with the remaining 6 brought on stream in 2027. Our third Duvernay pad of 2026 a 4 well pad in Northern Pembina, is completed and now on stream. Tuck in acquisitions completed during the year increased our Duvernay land by 16% to 106 thousand net acres. With efficiency gains and expanded inventory, could now grow the Duvernay to 25 thousand BOE per day, 1.5 years faster than our previous plan that retains over 15 years of hold-flat inventory at that level. Turning to heavy oil. 5 rigs were active during the third quarter across Peavine, Peace River, Lloydminster and Moranville. With strong well performance and efficiency gains realized in 2026 we now expect to bring approximately 109 heavy oil wells on stream in 2026. Including 5 additional clear water wells at Peavine, and 4 additional wells at Peace River. We are also advancing enhanced oil recovery. The expanded fourth quarter program includes $13 million for additional polymer flood development at Lloydminster, with production expected in the second quarter of 2027. Looking to 2027, our operating plan advances each of the core businesses. Roughly 40% of our 2027 capital investment goes to the Duvernay, with the balance directed to heavy oil and Viking. In the Duvernay, we plan to bring 21 wells on stream and grow average production to approximately 18 thousand BOE per day targeting a fourth quarter exit rate of 22 thousand to 23 thousand BOE per day. The Viking will run an efficient 1 rig drilling program with plans for 66 net wells on stream in 2027. In heavy oil, we plan to bring approximately 130 wells on stream. Including 32 at Peavine, 78 in Lloydminster, and approximately 20 at Peace River. We expect heavy oil production to grow modestly to approximately 48 thousand per day. Our updated 3 year outlook maintains this pace of development. Annual growth at 8% to 10% takes corporate production to approximately 92 thousand BOE per day by 2029, Annual capital expenditures are expected to average $800 million through the plan Production in the Duvernay will grow approximately 35% per year through this plan. Achieving the target of 25 thousand BOE per day level in the second half of 2028. We are targeting further improvements in drilling and completion costs to further improve free cash flow generation from the Duvernay. Heavy oil production is expected to grow modestly while contributing significant free cash flow through the plan. Our deep inventory of primary development opportunities supported by continued delineation in Northeast Alberta and expanded enhanced oil recovery provides a strong foundation for the business. Notably, this plan could be enhanced with water flood in the Clearwater and Gemini modular SAGD development. At Peavine, waterflood patterns are currently injected. And expected rates with 6 expected to begin in the fourth quarter. We expect to see a response on these pilots by mid-2027. We have also completed drilling a REX waterflood pilot at Moranville with injection scheduled to begin in the fourth quarter. In 2027, we are advancing technical characterization engineering and design for Gemini modular SAGD project with a target FID in the second half of the year. Gemini has approximately 300 million barrels of oil in place a successful pilot completed in 2014 and regulatory approval for a 5 thousand-barrel-per-day first phase. Waterside and thermal development can strengthen our business by increasing recovery from our existing resource base while adding sustainable production and free cash flow generation. Our 3 year outlook is about building stronger, more profitable business. Disciplined capital allocation directs investment towards opportunities that improve returns and strengthen free cash flow. Advancing enhanced oil recovery at Thermal is expected to moderate declines and reduce sustaining capital requirements. While continued delineation of our existing land base can deepen our development inventory. These priorities position us to create lasting value from the assets we already own The operating organization continues to execute safely and efficiently. I want to thank our field and office teams and our service partners for their focus and performance. With that, over to Chad Kalmakoff to discuss the financial results and capital allocation.

Benjamin D. Fraker: Thanks, Kendall. Strong operating performance and commodity prices supported another solid financial quarter. We generated adjusted funds flow of $332 million or $0.48 per basic share. Free cash flow was $139 million or $0.20 per basic share, after exploration and development expenditures of $186 million During the quarter, we returned $165 million to shareholders, We repurchased 24 million common shares for $149 million, and paid a quarterly dividend of $0.025 per share. Our balance sheet remains a significant strength and we exited the quarter with net cash of $522 million. This financial position supports the accelerated development Kendall outlined and provides resilience across commodity price cycles. Improved efficiencies and shorter cycle times have allowed us to accelerate the Duvernay, heavy oil, and advanced enhanced oil recovery development. As a result, our 2026 exploration and development expenditures are now expected to be $665 million up from $625 million previously. Higher benchmark prices have also increased our royalty rate guidance to approximately 16%. Operating costs are now expected to be approximately $13.30 per BOE improved from our previous guidance range of $13.75 to $14.25 per BOE. Transportation costs are expected to be approximately $3.75 per BOE from $3.40 to $3.60 per BOE previously. For 2027, we have initially allocated a $150 million to share repurchases under the normal course issuer bid. With flexibility to adjust depending on market conditions. We expect to maintain the quarterly dividend at $0.25 per share. At a mid cycle WTI price of US$70 per barrel, we expect to maintain a net cash position through the 3 year plan. Sustaining capital is also expected to decline reflecting our improved capital efficiency. That financial strength gives us the capacity to fund continued production growth share repurchases, and the base dividend. Allowing us to keep growing value for our shareholders on a per share basis as we grow the business. With that, I will turn the call back to Chad Lundberg.

Alexander J. K. Jessett: Baytex is delivering on its strategy. Consistent execution, is accelerating our growth plan while our discipline remains unchanged. What has changed is the pace. Stronger operating performance, improved capital efficiency, and lower costs give us the opportunity to accelerate development. We now expect the Duvernay to reach 25 thousand BOE per day in the second half of 2028. 1.5 years earlier than our previous plan with the option to generate further growth or hold flat with an improved 15 years of inventory from that point Heavy Oil continues to provide the foundation of the company with a deep inventory and enhanced oil recovery projects that extend the value of the resource. We are investing in high return organic opportunities. Advancing long term projects in a measured way and continuing to return capital to shareholders. The result is a business that is growing faster, and generating more free cash flow. We exceeded our 15% total shareholder return target in 2026 and expect to achieve it again in 2027 while maintaining balance sheet strength to deliver through the cycle. I would like to thank our employees and service providers for their continued focus and safe execution. With that, we are ready for questions.

Operator: We will now begin the analyst question and answer session. You will hear a tone acknowledging your request. Submit your question in writing, please use the form in the lower right section of the webcast frame. If you are using a speakerphone, The first question comes from Menno Hulshof with TD Securities. Please go ahead.

Menno Hulshof: Thanks, and good morning, everyone. I will start with Peavine Waterflood. it is a bigger question, but can you just remind us of what you need to see to scale up activity? And if you decide to move forward with commercial development, how quickly could that occur and how would it fit into the 3 year plan Or I guess the other option is that it displaces activity that is already in the plan. How are you thinking about that?

Alexander J. K. Jessett: Hi, Menno. I think similar to messaging in the past, it takes time to understand waterflood performance. What are the key measures we are looking for as 1, just injectability check We have got that. 2 is we should see GOR suppression. 3 is offsetting production response. Through decline as we take these wells out. I think we expect to see it by mid 2027. I mean, we are going to see markers and tells ahead of that time. So it does take a little bit of time, but it is coming soon. Just in terms of the broader build out, we are developing the acreage today leaving gaps for future water flood injectors. If we saw the tells and indicators that we were expecting to see we could layer in additional capital, half of 2027. We think that would be in the $20 million to $30 million range. Again, that would be a first step to start backfilling some of the gaps we left with the injectors. So I do not know if that gives you the snapshot you are after, but like, that is how we are thinking about it near term. Just in terms of longer term and how does it fit into the 3 year plan, if it works, we should start to see it pick up production performance inside the 3 years. How much is yet to be determined? I will leave it at that.

Menno Hulshof: Okay. Great. Thanks for that, Chad. And then maybe just a second question on land acquisitions. How competitive was the process to secure the additional 15 thousand acres in the Duvernay? And are you seeing opportunities to do more? Is it now fairly picked over? And then I guess on the other side of the ledger, what is the sort of the latest messaging on keeping versus monetizing the Viking? Thank you.

Alexander J. K. Jessett: Well, I think, the simple answer is it is very competitive. I mean, what we are doing with the asset as we have you know, held it since 2018, worked it through a delineation phase and really learning and developing what we call this ecosystem of developing an unconventional. Improving the characterization, reducing capital costs, bringing the stakeholders along with building out the infrastructure position to be able to handle these growth targets that we are ultimately achieving. And now here we are excited to step in the first year of full commercialization, hitting our production ramp a year and a half early, seeing the reduction in capital costs to $930 a foot it is ultimately flowing right through the top line breakeven reductions I mean to say it is not competitive with what I just rattled off, I would be remiss. it is-- it is extremely competitive. it is great land. We hold a great position, and, you know, we are going to try for more of it. I think the message is sections, not townships from this point forward. It is largely held. On the Viking, it is-- it is a similar message. You know, it is not core to the business. At the right time, we would look to try to potentially monetize the asset. The right time would be just how we think through the commodity cycle and acting contracyclically which would point us into higher prices, ultimately triggering us into potentially looking at it. Nothing further other than that, though, Menno.

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

Operator: The next question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

Greg Pardy: Yes. Thanks. Good morning. Thanks for the rundown. So you have got a huge land position lot of legacy stuff, Peace River Arch, etcetera. Is there another Gemini in there somewhere?

Alexander J. K. Jessett: We do have a large land position, 750 thousand-acres across basically the entirety of Central To Northern Alberta. I mean, what is in the plan? And we revealed a little bit more in our IR pack is, you know, 1.1 thousand of what we call risked locations We have expanded that to now include the full inventory set of 2.3 thousand unrisked locations. So that those inventory, wells are in the plan. Today. Second is we have the Gemini position, which sits on top of basically our Northeast Alberta acreage, that you touched on. Do we have further to go in terms of modular SAGD properties inside that 750 thousand-acres? Look. it is what we are doing. it is what our heavy teams are scouring every day is just looking for opportunities. Part of the exploration programs is not only derisking and advancing that 1.1 thousand risk well set to try and improve, the 2.3 thousand unrest, but it is looking for other opportunity within that within that set of land.

Greg Pardy: Chad, I do not think you want to answer my question. Okay. Well, hey. I tried to answer it by saying we have lots of opportunity. Without being specific about that. Okay. Okay. No. No. That sounds good.

Alexander J. K. Jessett: And, like, if I would. Yeah. Let me just expand on that. We are always working up new initiatives And there are things we are working on today you know, beyond modular safety, beyond what we have outlined in detail, beyond these primary well sets that we are we are just not talking about. They are not ready to talk about for various reasons, not technically far enough along the pathway, could be competitive to Menno's question from a landfill perspective and tipping our hats further would put us in a compromised position strategically. So just so I hesitate to go further.

Greg Pardy: No. No. That. Look, that. that is extremely good context. Okay. Completely shifting gears then. Some of the recent Duvernay wells, I mean, you know, a, great rates, number 1. Number 2 is the oil slash condi component very high in those. When you achieve the 25 thousand BOE a day in 2028. What is the modeled product split between oil versus gas versus NGLs? And then just related to your capital program because the Gemini is a big piece. Have you factored in inflation in to that into that outlook and then that is it for me.

Alexander J. K. Jessett: Okay. So when these wells come on, they have a higher liquids component. So 65% oil, 25% liquids, and 10% gas would be a general rule of thumb. And, actually, if you look at that was released in Q2 and then this 1 that we are talking about in Q3. I think they are 87, 88% liquids ultimately. So that is kind of where they come on. As we depressurize the reservoir, move through bubble point, we start to break out more gas in situ. And so that gets us to ultimately where we take these out at a 40% oil, 40% liquids, and 20% gas. 2028, we would be, as we model it out, basically, right in the middle of that. So it is the mix of base that is maybe drifting a little bit lower, and these new wells that are coming online that just have a little bit more pressure bottom hole. With respect to inflation, we have built, I would say, lower single digits into the plan. that is to account for what we are seeing on things like steel, things like diesel fuel. So we have built some into the plan. We have offset it to some extent, though, by all of the efficiency gains that we are talking about. We profiled the Duvernay efficiency gains. We have achieved some gains to our heavy oil program, most notably up in Peace River with, motor size, hole size, style selection of how we are actually executing on the drills. So we think we have struck the right balance of honoring what we are seeing and kind of benching that against the efficiencies.

Greg Pardy: Very good. Very good. Thanks very much. Thank you.

Operator: The next question comes from Amir Arif with ATB Capital. Please go ahead.

Amir Arif: Congrats on a really good update here. A couple of quick questions. For you. Just on the operating cost improvement, I was surprised at how much you were able to improve your operating cost structure. Is it more just driven by volume growth or do you or is there other factors behind pure operating cost improvement given the inflation that we are seeing in the industry?

Alexander J. K. Jessett: No doubt volume growth is helping us as we put more barrels across fixed costs, we can amortize those fixed costs. Offering just a higher volume set. That is 1 of the benefits of growth, Ami. Second, though, we would absolutely want to profile is just I would call it the proactive nature of our operating teams as they rethink and challenge each other operating in all of the different areas. So, for example, instead of taking a piece of equipment to closer to failure or where it starts to break down at an increased frequency, we are really challenging, can we put incremental costs into that equipment ahead of time that ultimately nets improved run life but then also, lower operating costs ultimately through the entirety of the lifespan span of that piece of equipment. So that is 1. That proactive nature. 2 is just when we look at operating these wells, again, being proactive on how we are operating them. So just with respect to maybe some of the lower producers as an example where we would in the past, pump them at a 3 or 4 strokes per minute on a continual basis. We are electing to put them on a timer or even a Porvory timer where we shut them down for a week. Turn them on for a day, produce the same amount of oil, but we greatly reduce the run time on that equipment and prevent it from wearing out further. I think we are ultimately seeing it flow through in a much bigger way through our repair and maintenance line item in the OpEx expense part of the ledger. 2 fold, pretty excited about what the teams are driving.

Amir Arif: Got it. No. that is good color. And then just a second question. You have improved your corporate decline rate to about 30%. But under the 3 year outlook, if you start growing organically around 9%, where does your corporate decline sort of get to by 2029? Under your modeling for your plans?

Alexander J. K. Jessett: I think this is 1 of the strengths of the 3 year plan. I am glad you asked because it is a bit of a hidden gem Traditionally, if you were to go and grow an existential position as we are talking about it, it does ultimately have a little bit higher decline than our corporate average. But when you balance it across the entirety of our portfolio heavy oil by the Duvernay, actually see the decline moderate modestly. I will say that we do not see the big improvements until we get into Clearwater water floods or if we do get into an FID on our modular SAGD in the second half of 2027, that would also materially improve base decline The point is though it is it does not go up It ticks down moderately through the plan. Even without the Waterflood success? Correct. So without the Clearwater waterflood success. I would say though you do see in this plan that we are capitalizing more of our EOR projects throughout the Lloydminster region of this particular instance. Noted that we have 400 million barrels of oil in place resource that and projects ahead of us to go after. So that will start to pay and improve the decline through the through the base plan. And we have been capitalized. that is not new. We have been these style projects for quite a while. I mean, we have got 10% of our heavy oil production that is under flood influenced by flood. Most of that is polymer flood. This is a continuation of an investment in more of those great EOR projects in the portfolio.

Amir Arif: Okay. I appreciate that. And then just 1 final question, just to clarification on the Gemini SAGD, you will be in a position to potentially go to FID in the second half of 2027. I am assuming production would not come on until 2010. Under that time frame, but is the if you do an FID, is the capital for that project included in the $800 million for 28-29?

Alexander J. K. Jessett: Targeted yeah. So our target is second half 2027 FID. There are a couple more items that we are just trying to get our heads around to really come to that conclusion. So characterization, I think we have got a really good handle on it. Capital cost, we have come a long ways on. I think by the end of the year, you will see us have a design selection, so size, mostly of first phase that we would intend to execute on. We are still waiting on royalty framework notionally to be announced from the, province. And then some of the auxiliary items that we need to ultimately make a facility of this size go. So water source, water disposal, and then gas supply. So we are working through all those measures. We have $10 million in the plan today. For Gemini budget, 800 million total. That is for further delineation of what we would call phase 3 or pods 3 and 4 of the project. So 3D seismic and then some stratigraphic test wells to just further define the steam chamber. If, we do reach FID H2 2027, there is another $50 million roughly that we would look to and think about adding to the plan in the back end of 2027. And then, obviously, that would come with the step up on the capital expenditures through 2028 as we point to first oil in 2029.

Amir Arif: Sounds good. Thanks.

Operator: The next question comes from Sam Burwell with Jefferies. Please go ahead.

Sam Burwell: Hey, guys. Good morning. This dovetails on the last 1. Curious about how you think about CapEx and free cash flow in late 27 and then 2028 assuming an FID of Gemini. Do you guys feel you have enough flexibility just with regard to the net cash position and the free cash flow you should be generating? But just curious if like there is flexibility in the plan to maybe scale down if commodity prices are lower or WCS dips are wider or anything like that. I am just curious how you are thinking about flexibility with Gemini potentially on the come?

Alexander J. K. Jessett: I mean, we study this intensely as we think about capital allocation, as we think about a fortified balance sheet that continues through the 3 year plan. As we sit today, we exit 2026. Again, we are in a bit of a choppy environment with respect to macro right now. To say the least. We do expect to exit the year at close to $400 million of net cash as we stress test the capital plan for 2027, $800 million with the commitment for $150 million to the buyback it would still leave us ample capacity to handle capital expenditures on Gemini. In the future and still leave us with that rock solid ironclad balance sheet Okay.

Sam Burwell: Awesome. And then just a little bit more of a housekeeping question, but the incremental 27 CapEx versus the prior plan, how does that break down or bucket between the Duvernay heavy oil and then anything earmarked for EOR slash Gemini?

Alexander J. K. Jessett: So here's how we think about that. If you take $625 million and that is kind of where we were yesterday before we released this press release, I will just build you to 800 from there. there is an extra $90 million, basically, of Duvernay capital that is really stepping again into this first year, full commercialization, 21 wells on stream. it is basically an extra 3 drills and 8 completions. The second is incremental heavy activities. So that is about $40 million to jump to that 130 well heavy oil pace from, call it, a 110. So an incremental 20 drills Layer in $35 million of EOR. So that is the Lloydminster polymer project. That we are excited about to the previous question. Helping to reduce base decline and that longer term sustainability. And then last is $10 million going to Gemini by way of 3D seismic and stratigraphic test wells. So I think that gets you to $800 million that drives the 8% to 10% enhanced growth rate on an annualized basis and really important to flag 15% on a Q4 on Q4 basis. That first year step into Duvernay commercialization, you see the barrels come, they come later in the year. It is all and that is what is driving that large Q4 on Q4 growth rate. So I guess would look at it this way. We have got some shorter cycle capital mid cycle capital, so the ER projects, and some longer term sustainability style capital by way of Gemini.

Sam Burwell: Alright. That math squares perfectly. Thank you, Chad. Thanks.

Operator: This concludes the question and answer session from the phone lines. Like to turn the conference back over to Chris Lesoway for any questions received online.

Kimberly A. Callahan: Thanks, operator. A handful of questions submitted through the webcast. So question for Chad Kalmakoff to start. Surround shareholder returns, maybe just reinforce our plans for 2027 in terms of the dividend and the share buyback and whether there is flexibility or plans to adjust those amounts?

Benjamin D. Fraker: Sure. Thanks, Chris. So on the dividend to start, plans to remain the $0.09 per year dividend No plans to increase that yet. I think, generally, when we think about that, we want to further reduce the fixed cost or further reduce the breakeven. So it is sitting at $50 today. You know, if we can increase that further, that could be an opportunity on the dividend, but not today. On the share buyback, we have initially set that at a $150 million. As we have kind of outlined in the plans, we have an efficient capital program in hand for 2027. There are opportunities potentially within the plan to advance further projects that are very valuable to us Peavine waterflood, Gemini, etcetera. So we maintain the flexibility around that buyback. Opportunity to adjust that, should market and the business give us that availability. So initial $150 million we will assess that as we kind of go through the year. Under the same conditions we always look at is kind of relative value our intrinsic value, and where we sit in the commodity cycle along with the kind of capital opportunities available to us.

Kimberly A. Callahan: Great. Thanks, Chad. This 1's for Chad Lundberg. I see some news out there about the Caribou land sale that is forthcoming. Maybe just comment on any opportunities that we see may see there?

Alexander J. K. Jessett: A potential opportunity? No different than all of the other non Caribou Lands. that we are Actively Pursuing, Exploring, Testing, And, Ultimately, If We Like The Thesis, Are Bidding on at a land sale. Caribou Lands, I guess, the only difference is it could stand to be a larger land sale. We do not know yet. We will see, in November here what the postings look like. It could just be a little bit larger, and we are working up our plans to potentially be at the sale.

Kimberly A. Callahan: Great. Thanks, Chad. Last question here for Chad Kay around hedging. Maybe just describe our philosophy around hedging in general and then in terms of WCS for next year.

Benjamin D. Fraker: Sure. Thanks, Chris. So, we would kind of anchor our hedging program to our balance sheet. We obviously have a fairly fortified balance sheet to live through commodity cycles. So not looking to put on WTI hedges. We do have WCS hedges here till the end of the end of this year. Nothing on for 2027 at this point. Obviously, in a pretty high differential environment today, not looking to add anything at these prices because if things do tighten, there could be an opportunity there on the WCS side.

Kimberly A. Callahan: Great. Thanks, Chad. So that is all the questions we have. So thanks again to everybody who joined the call today. For those of you who submitted questions, we did not get to, please reach out and I will follow-up directly. Thanks again for your time today and have a great day.

Operator: This brings a close to today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.