Crescent Point Energy Corp. (NYSE:CPG) Q1 2024 Earnings Call Transcript

Crescent Point Energy Corp. (NYSE:CPG) Q1 2024 Earnings Call Transcript May 10, 2024

Crescent Point Energy Corp. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning, ladies and gentlemen. My name is Annes, and I will be your operator for Crescent Point Energy’s First Quarter 2024 Conference Call. This conference call is being recorded today and will be webcast along with a slide deck which can be found on Crescent Point’s website home page. The webcast may not be recorded or rebroadcast without the expressed consent of Crescent Point Energy. All amounts discussed today in Canadian dollars with the exception of West Texas Intermediate or WTI, pricing, which is quoted in U.S. dollars. The complete financial statements and Management’s Discussion & Analysis for the period ending March 31, 2024, were announced this morning and are available on the Crescent Point, SEDAR+, and EDGAR websites.

All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session for members of the investment community. [Operator Instructions]. During the call, management may make projections or other forward-looking statements regarding future events or future financial performance. Actual performance, events, or results may differ materially. Additional information or factors that could affect Crescent Point’s operation or financial results are included in Crescent Point’s most recent annual information form, which may be accessed through Crescent Point, SEDAR+ or EDGAR websites, or by contacting Crescent Point Energy. Management also calls your attention to the forward-looking information and non-GAAP measures sections of the press release issued early today.

I will now turn the call over to Craig Bryksa, President and Chief Executive Officer of Crescent Point. Please go ahead, Mr. Bryksa.

Craig Bryksa: Thank you, Operator. Welcome, everyone to our Q1 2024 conference call. With me today are Ken Lamont, our Chief Financial Officer, and Ryan Gritzfeldt, our Chief Operating Officer. We’re off to a great start in 2024. As recently stated, our strategic priorities are focused on operational execution, optimizing our balance sheet, and increasing our return to capital. Our first quarter results showcased how our operational execution and capital discipline led to solid results across our business. In the first quarter, we produced over 198,000 BOE per day. We generated $130 million of excess cash flow, returning 60% of that to our shareholders through our base dividend and share repurchases. And on the balance sheet front, we reduced our net debt by over $150 million.

Earlier this week, we entered into an agreement to dispose of non-core assets in Saskatchewan for $600 million. We plan to direct the net proceeds from this disposition towards debt repayment further strengthening our financial position. As a result, we forecast our net debt at the end of 2024 to be $2.8 billion or 1.1x debt to cash flow. This would mark significant net debt reduction of $1 billion since year-end 2023. All these highlights serve as examples of how we are executing on our strategic plan and maintaining our commitment to enhance shareholder value. I’d like to focus today on our operational excellence across our entire portfolio because that is what ultimately drives the effectiveness of our strategic priorities. In the Alberta Montney, we continue to demonstrate the quality of our asset base and our technical strength.

Our recent well results show that we are drilling some of the top wells, oil and liquids producing wells not just in the area, but across the entire Western Canadian Cemetery Basin. We have also seamlessly integrated our recently acquired Alberta Montney assets and brought on stream 18 wells year-to-date with strong results. In Karr West, we brought on stream three multi-well pads since closing our acquisition in late 2023. These wells were drilled by the prior operator using their frac design including tighter well space. The peak 30-day well rates from these first two pads have ranged from 400 to 1,400 BOE per day with 85% liquids. The third pad recently came on stream with strong initial results. We will be bringing on stream our first fully operated pad in this area early second half of the year, which will utilize our drilling and completions design, including wider well space.

At our recent multi-well pad in Gold Creek West, we tested different completions designs. We used a plug and perf technique on two of the four wells instead of sliding sleeves and have seen promising results to-date. This pad had an average peak 30-day rate of 1,800 BOE per day per well with 85% liquid weighting. As good as these results are we believe that we can do more to unlock future value by further optimizing our drilling and completion designs. Consistent with previous quarters, our Kaybob Duvernay results also feature strong IP30 rates with high liquids weighting, most of which is condensate. This leads to generating prolific returns in the area. In the first quarter, I’m proud to say that our operating team achieved a remarkable milestone by successfully drilling the longest onshore well in Canadian history.

Our record well had a total measured depth of over 9,000 meters, which included a lateral length of over 5,400 meters. It was drilled as part of a multi-well pad in the volatile oil window to access portions of the reservoir that otherwise would not have been recovered. We will bring this pad on stream in the second half of the year and we are excited to see the results. Our most recent pad in this area, which came on stream in the first quarter had an average peak 30-day rate of over 1,500 BOE per day per well, comprised of 75% liquids. I’d like to congratulate our Kaybob Duvernay team for their tremendous accomplishment in drilling this record setting well. This is yet another example of our technical bench strength and overall operating expertise.

In Southeast Saskatchewan, we continue to advance our open hole multi-lateral well development program and are seeing encouraging results from these wells. We plan to drill 10 2 mile, 8 legged wells during 2024. With the recently announced government of Saskatchewan royalty incentive, the net present value and payout of our program improves by 10%. With our recently announced non-core asset disposition in Saskatchewan, we revised our 2024 annual production guidance to 191,000 to 199,000 BOE per day. Our capital expenditures guidance of $1.4 billion to $1.5 billion remains unchanged due to the minimal spending we had allocated to the disposed assets for the remainder of the year. On a pro forma basis, we expect to generate $875 million of excess cash flow in 2024, at $80 per barrel WTI.

The majority of this excess cash flow is weighted to the second half of the year based on the cadence of our capital program. We will continue to allocate 60% of our excess cash flow to shareholders and the remaining 40% to the balance sheet. As I step back and look at where our company is headed, I’ve never been more excited. We will continue to focus on our strategic priorities of operational execution, optimizing our balance sheet, and increasing our return of capital to our shareholders. Our priorities are supported by an asset portfolio with 20 years of premium drilling inventory to provide disciplined per share growth and significant excess cash flow. Our corporate transformation improvements that we’ve made to get to this point are truly exceptional.

Our first quarter results clearly show how positive the start of the year has been for us. Before wrapping up, I’d like to invite everyone listening in on this call to our AGM later this morning, which will be held virtually. Please visit our website for further details. I’ll now open the call to questions from the investment community, followed by questions from the webcast. Operator, please open the line to questions.

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Q&A Session

Operator: Thank you, sir. Ladies and gentlemen, we now begin the question-and-answer session. [Operator Instructions]. Your first question comes from Dennis Fong with CIBC World Markets. Dennis, please go ahead.

Dennis Fong: Hi, good morning, and congrats on the strong results this morning, and thanks for taking my questions. My first one is maybe focused around the strong type curve results that you guys have showcased. I was just curious as to how would you think about or what level of improved confidence would you need to start applying these stronger results to your plan? And how would that potentially affect either the cadence of production growth or CapEx or free cash flow generated over both the next 12 months and the five-year program?

Craig Bryksa: Hey Dennis thanks for the question. It’s Craig here. I’ll take some of this and then I’ll pass it to Ryan as he’s with me here too. And he can talk to you a lot about how the operations have been going. But Dennis, off to a great start to the year. Happy to be with where we are just over that 198,000 BOE per day. Got a good cadence of operations running, as you’re well aware. We have the two rigs running in the Duvernay, we have the three rigs running in the Montney, and then we bought between call it two to three rigs in Saskatchewan, depending on the timing of the program. But operationally, things have been going very well. Well results have been coming in very well. We’re excited to see when you think to the back half of the year with our spacing in particular in the Montney not only our spacing, but our well designs as those pads start to come online.

We’re certainly encouraged for that. Your question around well results and maybe more pointing towards some outperformance relative to type curves. I think we spoke a little bit about this at the Analyst Day. We’d like to see, call it two to three to four pads in an area with consistent results that are in and around those numbers as we slowly creep that up within our type well. So we take a little bit more of a measured or balanced approach. So ideally you start to see this flow in over time, but really happy with where we are to-date, happy with the performance, encouraged with the performance of the operations team. And Ryan, I don’t know if you’d have any other comments on wells [ph].

Ryan Gritzfeldt: Yes, I think Craig answered it well, and it is a good question. We’ve been getting that question a lot, specifically in Gold Creek West, where like Craig mentioned, we’re getting really strong results. 1,800 BOE a day, 85% liquids IP30s versus our type curve closer to 1,300 BOE a day. We do need more — we need more production history. How are those wells going to decline before we up our type well across the area in our five and 10-year plans. We have 300 locations in that area, and we’re going to actually test probably tighter spacing to seven wells a section, which would add another 100 locations. But I think it’s not proven to just apply that 1,800 BOE a day result across the whole area. So I think that kind of shows the how we’ve adequately risked our production in our 2024 budget and five-year plan.

And as we continue to get more results, more pads, more production history to fully understand the declines, that’s when we’ll look at bumping our assumptions in the current year and go-forward.

Dennis Fong: Great, great. Appreciate that color and context. My second question is shifting maybe more towards the balance sheet. You’ve obviously completed some non-core asset sales in the first quarter and recently announced further non-core asset sales. When I think about we’ll call it the billion dollars of potential debt or deleveraging that you see over the next 12 months both organically and inorganically. How comfortable are you with that pace of deleveraging? And obviously, there’s a further debt target behind that, but I just wanted to understand about the pace of that versus where any commodities are your current capital plans, and what that might afford you for flexibility in terms of capital allocation. Thanks.

Craig Bryksa: Yes. Thanks, Dennis. So Ken is with us here too, as well, so he can give you some color on this in a second. But for us, when you look at where we were at the end of last year, after we did that big strategic Montney acquisition with Hammerhead, we had our balance sheet at about call it just under $3.7-ish billion of absolute debt. So for us to chew up basically $1 billion in a 12-month period, I would say is a good pace of debt reduction. We’re happy with that and happy with projections on that both through the non-core dispositions in Southern Alberta and Northern Alberta, which we closed in the first quarter, and now that the most recent one here in Saskatchewan that we just had announced. So when you combine the proceeds from that plus what we see for excess cash flow generation and the share that the company keeps, that’s in and around $1 billion, so it’s a good significant move or strengthening of our balance sheet.

Look for us, as we talked Dennis and you and I have talked in the past, we’d like to be here a near-term debt target. I’m seeing near-term of around $2.2 billion of absolute debt that’s about one times debt to cash flow. And that, call it $60 to $70 price environment — sorry, $60 to $65 WTI price environment, that would be about one-time. So we want to move quickly towards that. So look for us to try and accelerate into that as we go, but very happy with the progress we’ve made to-date. And we’ll continue towards that, strengthening towards it that, like you say, $2.2 billion. And then as we get to that level, look for us to start to talk about increasing our return of capital to shareholders. So right now we return 60% of our excess cash flow to our shareholders.

As we get closer to that number or in and around that number, look for us to grow that profile as well. And then further beyond that, when you look at the business moving forward, Dennis, we’d like to be in the neighborhood of about $1.7 billion of absolute debt is how we’d like to run the business for the long-term. And that would equate to 1x debt to cash flow at $50 WTI. And when you’re in that type of level, you’re pretty much bulletproof from a balance sheet standpoint. So when we talk balance sheet optimization, that’s what we’re gearing towards is that type of level. And I can tell you I’m pretty pumped myself on a billion dollar net reduction here over, call it a 12-month period ideally, Dennis, next time we’re talking, we can say we’re doing even more than that, but certainly a good start.

And Ken, I don’t know.

Ken Lamont: Yes. The only thing I’ll add to that Dennis is we’re obviously very highly hedged here the back half of this year. So 45% fixed price hedged on oil, 30% on gas, and that extends in oil into 2025 as well in the first half about 20%. So as far as our ability to harvest that retained excess cash feels very comfortable, just given the level of the hedge books as well too. So that’ll provide a little more certainty in bringing that in and bringing that debt down.

Dennis Fong: Great. I appreciate the context there. I’ll turn it back. Thanks.

Craig Bryksa: Thanks, Dennis.

Operator: Thank you. Your next question comes from Amir Arif with ATB Capital. Please go ahead.

Amir Arif: Thanks. Good morning, guys. Just a few quick questions. Just on those Karr West wells, I know it was previous completion approach, but just the variability between the 400 to 1,400. Can you just give us a sense of what was causing that and if there were any lower Montney wells included in those pads?

Craig Bryksa: Yes. I think it’s best for Ryan to grab that one.

Ryan Gritzfeldt: Yes, good question. So the 5 of 11 pad, it did have three lower, or it does have three lower Montney wells. We spoke a little bit at our Investor Day at how the previous operator drilled through a fault on that pad. And so there are a handful of wells that have shortened lateral lengths because of that. And we also think that the lowers were drilled a little bit too low, close to the bottom, the very bottom of the Montney zone. So we think that definitely some of the wells have been impacted by that. Some of the B and the C Montney wells are strong at that 1,400 BOE a day. What we’re excited about here go-forward. So we’re bringing a pad on right now. It’s our 2 to 10 pad. We’ll have IP30 results in the next quarter.

Still at the previous operator well spacing, but with our fluid system in our frac design. So look for those results. And then we’re also right now drilling a pad down in that Karr South, Karr West area, the 5 of 23 pad, where we’re testing the lower Montney again. But we didn’t drill those as low as on that 5 of 11 pad. So look for that pad, the 5 of 23 pad, where it’s our well spacing. So a little bit wider well spacing and our fluid system for our frac. So look for those results in the summer.

Amir Arif: And I don’t believe you booked too many lower Montney wells like, it could be inventory at B from that zone or the two or three.

Ryan Gritzfeldt: Yes, I think — yes, there’s a very small amount of lower Montney booked, but, yes, if you apply a fairly conservative well spacing, there’s probably conservatively 150 and 200 lower Montney locations in that area.

Amir Arif: Okay. Sounds good.

Craig Bryksa: But just a handful booked.

Amir Arif: Yes, yes. And then just a question on the different completion approach of the sliding sleeve versus plug and perf. Doesn’t seem to be making much of a difference on the performance, but obviously lower well costs. Can you just give us a sense of how much you could reduce your well cost and when you’d be comfortable enough, potentially shifting more to plug and perf and what the magnitude of the well cost saving would be?

Craig Bryksa: Yes. So this is Craig. Extremely excited about how those wells have came in. Do know that the plug and perf, the IP wasn’t quite as high as the sliding sleeves. So the sliding, which makes sense when you think of that single entry point. Extremely excited, though, with how the operations team went through on the plug and perf and the success we had. And really, your point there, the big win on that is twofold. One, ideally, the decline rate is a little bit shallower. And then two, the cost of those wells was about 500,000-ish less than what we are seeing on the sliding sleeve. So it’s a significant win operationally for the team, and then as well on the cost structure moving forward. So we do have a few more of those wells that we’re going to be doing this year. And we built in that, that, call it cost savings into those wells as we see it in our 2024 program. Ryan, I don’t know.

Ryan Gritzfeldt: Yes, no, that’s good.

Amir Arif: I appreciate that color.

Craig Bryksa: Did that help you?

Amir Arif: Yes, absolutely. I appreciate the color. And just one final question, just on the open hole multilateral over in Saskatchewan, I believe the economics for your open holes are significantly better than your frac well. Is this an area where eventually, should we be thinking about you switching over to open holes for the full development eventually, over time, or does open hole only work over certain parts of that play?

Craig Bryksa: Yes, good question. For the most part, the open hole multi-laterals work as we’re pushing the edges of the play, specifically where we kind of lose the frac barrier to the overlying water bearing lodge pole formation. So in our core, the conventionally frac wells, I think will still give us the best results. But it’s when we start pushing the boundaries specifically to the North and to the Northeast, that’s where we’re getting these really good results. The last open hole multi-lateral we brought on into March, it’s been two months now in and around that 225, 250 barrels a day. So continuing to get great results, it’s increased our inventory in the plate, and like we said in the Investor Day, this is an inventory that we’re going to rush out and add rigs, but it definitely will help us maintain our production levels in the play and extend our drilling inventory life.

Operator: Thank you. Your next question comes from Aaron Bilkoski with TD Cowen. Please go ahead.

Aaron Bilkoski: Hi, good morning, guys. My question is on the CapEx associated with the assets that you had sold. I guess, am I correct to assume that you were planning to spend roughly $50 million there?

Craig Bryksa: Good morning, Aaron. When you look into the five-year plan, so beyond 2024, we had about $50 million allocated to those assets. So from 2025 to 2028, it was about $50 million a year. When you look at 2024 with us going through the disposition process, we had a very minimal amount of capital allocated to that. I want to say had the assets still been with us this year, we would have spent a minimal amount somewhere in that neighborhood of $15-ish million, I want to say. I think in and around there in the back half of the year, and mainly most of that was allocated to flatly. But no, your assumption is right. Moving forward, it would have been around 50 in the five-year plan per year. This year was only about 50-ish.

Aaron Bilkoski: Got you. So as I look ahead to 2025, you have seems like roughly $50 million in unallocated capital. Where do you see that going? It’s not enough to obviously add another rig, but do you use that to squeeze out a few more Montney and Duvernay wells, your pace of drilling and completion may be running a little bit faster than you had budgeted.

Craig Bryksa: Yes. And we’ll see how that goes. And Aaron, like mentioned earlier on the call, the cadence of operations has been good. Our team is just off and running, in particular with Montney. And I’m excited, and I know Ryan is excited with how the performance has been. We actually — we just ended up clipping a pace setter well for us here about a month or two ago, that was basically 11 days. So it certainly tightened the timeframe on how fast that we’re drilling the wells, which is good because that drives your capital structure. When you look within the five-year plan, we’ll spend some time here over with now having the disposition done, and through the summer on looking at capital allocation across the portfolio, and then we’ll look to see how that plays within the five-year plan.

And I would expect more detail in and around the five-year plan Aaron later on this year. Right now, we’ve basically did it. I don’t want to say mechanical update, but basically we’ve removed the assets that have been sold out of that plan and haven’t really put any real work into the reallocation of that capital if it even happens. I mean, we’re pretty happy with how to-date. So just because the — we had that in there doesn’t mean we’ll end up doing that or spending that. Got you?

Aaron Bilkoski: Thanks very much, Craig. I appreciate that.

Craig Bryksa: Yes.

Operator: Thank you. Your next question comes from Jeremy McCrea with BMO Capital Markets. Please go ahead.

Jeremy McCrea: Hi, guys. You talked about well improvements, well cost savings. How much of this have you built into 2024 and 2025? Like I know you said there’s some of it built in, but what could we potentially see for revisions if these wells continue to come above expectations or the well costs continue to come below expectations? I’ll leave it at that for now.

Ryan Gritzfeldt: Hey Jeremy, it’s Ryan here. Yes, I mean, as you go, you build a little bit in rates, but again, what I’ve been saying is these things take time. So we said our Montney drills depending where you are $9 million to $10 million per well, and we have line of sight to sub $9 million over the next 12 months to 24 months. So it takes time. We want to see it repeatably before we build more in. Like Craig mentioned, we brought in a different walking double rig into the play. It’s taken a few pads to finally find its stride. It’s drilled as quick as well at just under 11 days. But these things take time, right? So we’ve built a little bit in, but as we go, obviously, we’ll build in more kind of similar to the production results question. We need to see the results being repeated consistently and we’ll build it in over time.

Craig Bryksa: The one thing I would add too, Jeremy, so as you’re well aware, one of the things or one of the things that really drives your cost structure is time and location, and Ryan alluded to that. So as we get our rigs running and we get smarter and we’re doing things better and the team is really learning off each other, then ideally you drive that time and location down. That’s both on the drilling and the completion side as we follow along the three rigs in the Montney in particular with one frac spread. But the other thing that works in our favor is our internal procurement division, and we’ve had some success recently here with working with a new service provider to pump our fracs, and that ended up saving us a material amount of money here on a per well basis too.

So Ryan’s team is working that into the budget, but all that works in our favor as well too. So we’ll see how that ends up playing out. But very happy with both the ops team on what they’ve been doing to-date and then as well the procurement division on what they’ve been working with our service providers on, so.

Jeremy McCrea: Okay. And maybe just a quick follow-up there too. Is there any new concepts that you haven’t talked about here today? Like I said, we talked about trying to plug and perf versus the NCS. Is there any other new concepts that you’re going to test over the rest of the year that you’ll talk about coming Q2, Q3, and say, hey, actually, that actually kind of worked here.

Craig Bryksa: Go ahead.

Ryan Gritzfeldt: Yes, I don’t think so, Jeremy. I think what we’re doing right now keeps us busy with new things. Craig mentioned we just drilled the longest onshore well in Canada in the Duvernay. We’ve had questions. Well, what did you do differently? And honestly, not a lot different. It’s just taking the learnings. We’ve been in the play now for what three years? It’s taking the learnings and applying them, and that’s why I say some of these things take time. And — but with all the things we do have going on right now, it’s exciting to see where we can bring our cost to, like Craig mentioned with supply chain management, with our operations team continuing to push the limits. But in terms of, like, new things like plug and perf and Gold Creek East that we’re trying. There really isn’t anything new that I can speak of.

Craig Bryksa: And Jeremy, I’d add to that in our teams, as you get in here, they learn from each other, and the Duvernay team learns from the Montney team, and away they go. And we apply different things as we go. So it’s a consistent evolution and always being innovative around that. So you’re always looking at different muds and bid systems and how that works. So ideally that drives your cost structure. The other thing is, we’re typically a little bit more conservative on our well spacing, as you’re well aware. We like to be. We’d rather be a little bit wider and creep our way in, as opposed to being too tight and have to creep our way out and revise inventory to the negative. So one thing you will see us do this year, Ryan said it earlier on the call is with the success we’ve been having in Gold Creek West these like that last pad is called 1,800 BOE per day on average per well at 85% oil or liquids.

Look for us to tighten in that spacing on an offsetting pad to the pad’s going to go directly to the West. We’re going to tighten in that spacing. We’re going to go from five wells to seven wells per DSU. Ideally, we get some very good strong results like we’ve been seeing, and then that opens up inventory in that entire airway or area. So it’s going to be a lot more of that. And then obviously, when you think of the geos and how our landing zones and how they’re steering the wells, they learn as we go. Let’s see, optimal landing position. How do you want to stagger your zones between the different areas? So it’s going to be more of that, just getting smarter and then look for us over the years to get even better. And like Ryan mentioned, that Duvernay well, we’ve been running in the Duvernay now for three years, but over three years, so that well is 19 or basically 9,017 meters, that horizontal leg was 5,400 meters long.

And Jeremy, we did that in one bit run. So not only is it the longest well in Canada, it’s also drilled half a day faster than the peer who had that title in front of us. So the team, they did an incredible job on that. But — so we’ll see how it plays out with us in the Montney.

Operator: Thank you. Your next question comes from Travis Wood with National Bank Financial. Please go ahead.

Travis Wood: Yes, thanks, and good morning. The question’s probably for Ken. I just wanted to take it back to what Dennis was getting at around debt; I guess a couple questions to get here. First, any more assets to be sold, smaller, non-core stuff, the scraps that are left in the portfolio? And then how should we — is debt to cash the right way to think about where leverage sits? Or as you think about accelerating debt repayment? Could we start to think this on a debt to cap base or what’s the right way to think about that? And how low should the absolute debt number get to? So a lot of questions in there, but kind of just driving at one. And then any way to accelerate some of the repayment of the senior notes and the bonds that are coming due over the next couple of years.

Craig Bryksa: Hey Travis, thanks for the question. I’ll maybe grab the first one as far as A&D, and then I can pass it to Ken on the debt and the debt structure and how we’re looking at optimizing the balance sheet. As far as A&D, Travis, you’ve watched Crescent Point over the last six years, but in the last maybe three years in particular on the movement within the portfolio, and I did mention to you that we’re going to take a good long pause as far as the acquisitions. We’re happy with how things have come together here, so don’t look for us this year to do anything on the acquisitions front. I would also tell you too as far as the upstream dispositions, when you look at now with us having moved off — what we just moved off recently here both in Alberta and Saskatchewan.

We’re pretty — we’re excited with how the portfolio fits and stands today. So I wouldn’t look for any near-term dispositions, further dispositions, upstream dispositions either. So again, happy with that as far as that movement on the portfolio. And then we’ll look to execute here over the next call to 12-ish months, and then I’ll maybe pass to Ken as far as the debt structure and balance sheet optimization.

Ken Lamont: Yes. So on the debt side, Travis, I think the way we’re approaching it is a bit of a leverage at a lower oil price is kind of where we set what I’ll call our targets, or more optimal debt level. And so if you think about, we’ve been signaling here on the back of the deal, we open the year at $3.7 billion of debt. We talked about reducing that by about $1.5 billion to get to $2.2 billion. That’s kind of a debt to cash flow of around 1x at between $60 and $65 U.S. WTI. And so that’s really an initial level where you think, if we can deleverage down to that, that gives us kind of our first level of comfort, and where we can kind of reflect on potential return increasing in the return of capital proposition of the shareholders.

In the longer run, we’d like to run our business at a one-time debt to cash flow at a $50 U.S. WTI. And so that’s to Craig’s earlier comment on this call, about $1.7 billion of absolute debt. And so that’s really what we would like to manage the business at. Now, obviously, there’ll be period of times where we’ll have — we’ll be well below that. There could be period times going forward. We’ll be slightly above that. I think that’s kind of where we’re shooting to manage the business on average. And so that’s really how we’re thinking about debt levels and where we’d like to get to. With respect to the bonds, absolutely, there are early repayment provisions within those bonds where interest rates sit today. There wouldn’t really be any penalties at all to repay them early.

However, outside of just having some covenants associated with those bonds, which were well inside of obviously, they’re carrying an interest rate of 4%. So I’m not really motivated right now to repay those things early. And so I think we’ll probably look to leave those outstanding for a bit more period of time here. And then, obviously, to Craig’s point, we’re focusing on kind of getting to that $2.2 billion of debt retaining some excess cash, and just driving that balance sheet down this year a little bit further.

Travis Wood: Okay. Perfect. And then so is that $1.7 billion? Is that the threshold on absolute debt where we could start to think about 100% of excess cash be returned? Is that the optimal level for that scenario to unplay?

Craig Bryksa: So Travis, like we’ve mentioned, as we get to $2.2 billion, look for us to grow the allocation that we’re returning. So right now, we return 60% of our excess cash flow goes back to the shareholders in the form of base level dividends. And then the top up is all happening right now through share repurchases. And we certainly believe that that makes sense with how we trade on our intrinsic value. So look for us to continue that. As we get to $2.2 billion, look for us to grow that percentage upwards and call it somewhere in that 70%, 75%-ish ranges as we get there. And we’ll see how that plays out as we work through that with both the management team and the Board. As we get to $1.7 billion, I wouldn’t expect that to grow any further, Travis.

I mean, for us, there’s always going to be a component of that excess cash flow that we maintain in the business. So to continue to strengthen either a, the balance sheet or if you want to allocate a little bit more to some organic growth or that sort of thing, but we certainly believe in always maintaining a certain level of excess cash flow for us to stay in the business and quite happy to drive the balance sheet down well below that $1.7 billion of absolute debt that is our target. So don’t look for us at any point in time to go to that 100. And I would also say too, Travis, when you look at us relative to our peers, with our asset base and our netback both operating netback and then cash flow net back, I think Crescent Point punch is well above its weight as far as excess cash flow per share generation.

So our 75% certainly be competitive with what some of those other peers would be doing at a little bit higher level.

Operator: Thank you. There are no further questions on the phone line. Please proceed.

Craig Bryksa: Thanks, operator. I’ll pass it over to Sarfraz Somani, our Manager, Investor Relations to moderate a couple questions here from the webcast.

Sarfraz Somani: Yes. Thanks, Craig. So there’s just a couple of questions on tax, and I’m just going to group them here into one. The question would be, when do we expect to pay cash taxes. And does this timing get impacted by the recent known courses cash and disposition?

Craig Bryksa: Yes. So the non-core cash and disposition didn’t have a real material impact, really on our production excess cash generation and/or tax profile. Right now, as we sit on strip, we will not be taxable until the year 2026. In 2026, I would expect to be on strip taxable at kind of a 9% of the — of our cash flow would be the effective tax rate, and that kind of holds steady going forward at strip over the following year. So no cash taxes in 2024 or in 2025.

Sarfraz Somani: Okay. And so there are no more questions right now on the line. So just want to thank everybody for joining us — joining our call today.

Craig Bryksa: Thanks, everyone.

Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your line.