Veren Inc. (NYSE:VRN) Q3 2024 Earnings Call Transcript

Veren Inc. (NYSE:VRN) Q3 2024 Earnings Call Transcript October 31, 2024

Operator: Good morning, ladies and gentlemen. My name is Jenny and I will be your operator for Veren’s Third 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 Veren’s website homepage. All amounts discussed today are in Canadian dollars, with the exception of West Texas Intermediate or WTI pricing which is quoted in U.S. dollars. [Operator Instructions] During the call, management may make projections or other forward-looking statements regarding future events or future financial performance. Any such statements were made subject to the forward-looking information in the non-GAAP Measures section with press release issued earlier today. I will now turn the call over to Craig Bryksa, President and Chief Executive Officer at Veren. Please go ahead Mr. Bryksa.

Craig Bryksa: Thank you, operator. Welcome everyone to our Q3 2024 conference call. With me today are Ken Lamont, our Chief Financial Officer; and Ryan Gritzfeldt, our Chief Operating Officer. Our third quarter results were highlighted by generating excess cash flow of CAD114 million, returning 85 million to shareholders through dividends and share repurchases, announcing our strategic infrastructure transaction for proceeds of CAD400 million which closed in the fourth quarter, and further net debt reduction with total expected repayment of CAD1.3 billion in 2024. We will continue to prioritize operational execution, optimizing and strengthening our balance sheet and increasing our return of capital to shareholders. In the third quarter, we produced 185,000 BOE per day comprised of 65% oil and liquids.

Our third-quarter production was impacted by third-party facility downtime and our own infrastructure constraints. To address these challenges, we are investing incremental capital to improve and increase our facilities capacities. Our teams have gained a better understanding of our Alberta Montney assets and we are implementing some changes to enhance our execution. We believe implementing these changes will positively address recent under — recent well underperformance in some of our Montney wells that have contributed to adjusting our overall outlook for the remainder of 2024, which will also impact 2025. Overall, we remain very excited by the quality and depth of our corporate inventory and believe it is one of our biggest strengths to supporting our long-term sustainability and our future value creation.

The quality of our Alberta Montney asset is evident when looking at our results. Wells on the first Gold Creek West pad that were drilled, completed and brought on stream earlier this year rank amongst the top 1% of all oil and liquids wells in North America over the last three years. These wells have already accumulated 440,000 BOE per well in just nine months and are currently producing at a rate of 1,800 BOE per day per well. This pad includes a recently optimized well that is showing higher productivity than its IP30 rate of 2,000 BOE per day. In early 2025, we expect to bring on stream an adjacent seven-well pad in the Gold Creek West area and are currently expanding our facilities capacity to accommodate increasing production from future development and well optimization in the area.

In total, we have over 300 net internally identified drilling locations in this area alone. Since entering the Alberta Montney, we have focused on identifying efficiencies in the play to further improve our area economics. To that end, we trialed the use of plug and perf completions design in our Gold Creek area at the beginning of 2024 instead of single point entry design. We believe this change could generate similar production results at a lower cost. Although the wells completed with plug and perf are economic and lowered our costs, production results have not met our expectations. Our own findings have been confirmed through the additional data review including adjacent well logs, reservoir diagnostics and microseismic analysis. Results seen in early October made us finally conclude that we will continue to use the single-point entry design in the Gold Creek area going forward.

This update is now reflected in our 2024 guidance, 2025 budget, and our five-year plan. We will always seek to maximize efficiencies and returns and we will continue to fine-tune our drilling and completions design when data warrants it. We have achieved substantial efficiency gains in Kaybob since entering the play in 2021 including lowering our average drilling days per 1,000-meter lateral length by approximately 30%. We continue to benefit from knowledge transfer between our plays and have applied the same strategy of optimizing our approach in the Alberta Montney where we have lowered our drilling days by approximately 20% since entering the play in the first half of 2023. Based on the production impacts I discussed earlier, we now expect to generate annual average production of 191,000 BOE per day in 2024 weighted 65% to oil and liquids with development capital expenditures of CAD1.45 billion to CAD1.5 billion.

We also announced our 2025 budget today, where we expect to produce 188,000 to 196,000 BOE per day weighted 65% to oil and liquids with development capital expenditures of CAD1.48 billion to CAD1.58 billion. Year-over-year, our 2025 production growth based on fourth quarter is still expected to be 10,000 BOE per day, which is in line with our prior plan. Our 2025 budget reflects a $70 per barrel WTI price assumption that is backstopped by our diversified hedge book to protect our 2025 cash flow. However, should commodity prices weaken, we will use our discipline and flexibility to lower our capital budget. We expect to generate CAD575 million to CAD775 million of full year excess cash flow in 2025 at $70 to $75 per barrel WTI pricing. We have allocated 85% of our 2025 budget to our short-cycle Kaybob Duvernay and Alberta Montney assets that provide top-quartile returns, scalability, and quick payouts.

As mentioned, this includes incremental capital in the Alberta Montney to increase facilities capacity. The remainder of our capital budget is allocated to our long-cycle, low-decline Saskatchewan assets which generate our highest operating netback and significant excess cash flow. Consistent with our capital allocation framework, we have also allocated a small portion of our budget through long-term projects such as decline mitigation and various environmental initiatives. Under our updated five-year plan, our annual average production grows to 250,000 BOE per day in 2029, driven by our Alberta Montney and Kaybob Duvernay assets. We expect to generate CAD4 billion of cumulative after-tax excess cash flow over the life of this plan at $70 per barrel WTI pricing and CAD3 per MCF equal pricing.

On a compounded annual basis, our excess cash flow per share growth works out to be over 10% which is similar to our prior plan. We will continue to return 60% of our excess cash flow back to shareholders while retaining the remainder for debt reduction. As our balance sheet strength improves, we will look to increase the percentage of excess cash flow we return. We remain excited about the quality of our assets and our overall potential to generate significant excess cash flow and create future long-term value for our shareholders. I’d like to thank everyone for their ongoing support and I look forward to taking any questions. I’ll now turn the call back to the operator to begin the Q&A. Operator, please open the lines.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Michael Harvey from RBC Capital Markets. Your line is now open.

Michael Harvey: Yes, sure. Good morning. Thanks for taking the question. I guess just a couple for me. Just kind of getting closer to year end, do you expect to see any of these recent well results having an impact on the reserves you’re carrying or McDaniel is carrying for these areas and — or is it kind of too early to make an assertion on that? And then second one is just timing. When would you expect to see or be able to provide the market with some updated well results with the new completion strategies?

Craig Bryksa: Good morning, Mike, thanks for the question. So it’s Craig here. As far as reserves, we’re making our way through that process. I can tell you we do mid-year reserve update with the independents as well as the full year-end reserve updates. But so far as we go through the process, our reserve book looks really good. Keep in mind when we entered into the play, we took the approach of wider well density right from the get-go. So we had our wells spaced quite a bit wider than what had been booked in the past. So overall when you look through the field, the reserve book looks really good and really strong. Some ups and downs, but overall I would say it looks good on that standpoint, Mike, and we’ll have that finalized here obviously for year end and we’ll get some color on that as that gets done.

As far as your next question on recent well results, as we were going through the quarter here and starting to see the production and two of these pads, keep in mind Mike, they just came on here in October between our 10 to 28 pad and our 7 to 17 pad where we had went to the plug and perf design relative to the single point entry design. Those pads had just recently came on, but they did confirm what we had suspected based on a pad that we had on kind of later in the third quarter in our 15 to 16 Phase 3. So keep in mind, Mike, all of these pads sit in a great area of the reservoir where you’ve got a number of producing wells. All have been developed in the past using the single-point entry design. As we were seeing these results play out, we had quickly started to change any further completion designs on any of the pads that we were moving on forward to the single point entry.

So the completions and drilling teams were actually, they did a great job on switching that out in very rapid time, including some of the wells down in Karr — some of the — some of the pads down in Karr South which we’re drilling right now too. So I’d expect to have you some color late December as far as the next two pads that are using the single point entry. And then as we get into the new year, you’re going to start to see more pads coming online throughout the new year, with the biggest one being the 6 or 7 Phase 3 offset that seven well pad will be coming on sometime in around February, but again we have made that and switch to the single point entry design, which I’m excited about, especially when you think of the Hammerhead acreage or that Karr South acreage where it hasn’t been done before and really what this is going to end up doing for us in that area.

We’ve had good results in that area. I think with the new system, ideally, this even improves that even more. So it’s a long-winded answer to say and reserve book looks pretty solid and then when you look into well results kind of December and then into Q1.

Michael Harvey: Gotcha. Thanks for that, Craig.

Craig Bryksa: Yes. Thanks for the question, Mike.

Operator: Thank you. Your next question is from Jeremy McCrea from BMO Capital Markets. Your line is now open.

Jeremy McCrea: Sure. Hi Craig, got a couple questions here. Maybe we’ll just start with the elephant in the room. Can you comment on your stock price here this morning in just terms of do you think this is an overreaction? Do you think this is just anything what you think on the market’s reaction to the guidance here in some of these wall results? And then I’ll just wait, I’ll ask second question after here in a sec.

Craig Bryksa: Yes, that I — obviously, Jeremy — well, first of all, Jeremy, thanks for the questions. I think it’s obviously tough for me to comment on the market. Do I think it’s an overreaction? I do, I think when you look at where we are on an overall guidance cut for 2025 relative to where we were, it’s — you’re basically off 10,000 barrels a day or 5% of that 10 — sorry, 10,000 BOE a day. So of that 10,000 BOE per day revision that we’ve made to our guidance, about 6,000 of that is gas and, and only 2,000 of that is oil with the rest being made up as NGL. So as far as the streams that drive the revenue in this business, it’s really driven by oil. And that overall impact to our oil production next year is only 2,000 BOE per day out of that small 5% revision to our guidance.

So I think that plays into it. But then the other thing too, Jeremy, I think like any company that has went through a transformation, you’re always going to have questions on your wells and your well performance in the near term until you’re demonstrating that like we are in Kaybob where we took that and have really put that into the market where they have all that confidence. And I think maybe the market just got a little bit spooked on a few pads here that have underperformed relative to what we’ve seen in that area over the past. And keep in mind on that too, Jeremy, the size of the price on us moving forward with the plug and perf design was fairly significant when you think at an all-in cost. Now, depending on what exactly type of completion and the number of sleeves you’re using in these, they can be — it could be upwards of a million dollars per well we were able to save by going to plug and perf.

But ultimately the performance of the wells hasn’t been what we’ve expected. So I think this will filter through over the next couple days. I think people who are in the market will start to see the opportunity in front of them and I’m excited when we start to look into 2025 knowing that we’re so much smarter going into that year than as we entered into 2024 on third parties and the infrastructure around them, on our own existing infrastructure, on the different mitigation components that we put into that and then, most importantly, on what we’ve learned as a team as far as landing and completions design in this area and then how we translate that into the Karr acreage as well too. So that’s where I start to get pretty jazzed. So again, fairly long–

Jeremy McCrea: Yes, go ahead.

Craig Bryksa: …on your question, Jeremy. Sorry.

Jeremy McCrea: I think it’s just a bit of confidence here and I think the market did have some high expectations coming into the year. And just with these latest wells here, can you give like some more specific details on why the single point entry is going to be better than the plug and perf? Like I know it probably has things to do with pumping rates in that, but just is it almost 100% completion design and is there risk of geology or is this really just because it’s got to go back to the old completion design?

Craig Bryksa: Yes. So if you look at where these pads are and where they sit relative on the map, they are right in Gold Creek, right in the core of that area. And in fact the wells that we, the pads that just came online should be better than the offsetting wells based on the geology and how that improves as you’re moving a little bit to the south and the west in this area. So that part is where I would say maybe a bit of the disappointment is when you think through with the plug and perf. But as far as the plug and perf relative to the single point entry, the biggest difference is when you are pumping your frac down hole, a single point entry system only has one entry point into the reservoir. And the biggest difference within this reservoir is the rate at which you enter that reservoir is going to really dictate how far and high you can crack that rock vertically.

And on the single point entry system, we’re basically — we’re over double the rate at the entry point. So it allows us to do a much better stimulation into the reservoir than it did relative to the plug and perf. So one thing I would note, Jeremy, is on the 10-28 pad that came on last there in this Gold Creek area. One of the things that we did do as we were, as we were learning this and catching up to this, we did change the perf intervals in that stage. So instead of going to five clusters, we pulled back into three clusters. So we got more rate per entry point and that pad is significantly better than the other two. So never mind just how much better that would have been using the single point entry system. So it’s all that data and all that learnings and you take that.

We’ve done the reservoir modeling, we’ve done the diagnostics, we’ve went through and looked at the microseismic and you can see all this data on there. So yes, you’ll see us move fully here to that single point entry system and then we’ll deploy that down into the other areas of the play as well. And that’s why we’re excited. So the other thing I will note for you Jeremy is when you look at the competitors and you move to the south and the west across the plate, the majority of the play is developed using plug and perf. Right? So it’s not that we were stepping out and doing anything any different. We, in fact, were trying to drive the cost structure on a proven technology. But with our area, the reservoir and that our reservoir is oil, you have a little bit higher viscosity, and all those things come into play on these types of things.

So call it a learning experience. And we’re going to take this and run this and grow from it going forward.

Jeremy McCrea: Just on the old NCS systems versus the new, what you’re going to try, like it looks like you’re using about six and a half cubes a minute for pumping. Is that going to increase at all going forward here or is there anything different with NCS that you wanted to use differently than prior wells?

Craig Bryksa: Yes. So you’re always experimenting on things but as far as pump rate, going to the full-on single point entry systems, Jeremy, you’re limited by your coil as you’re pumping down coil. That rate is kind of, it’s at those pressures and velocities that you can inject that. So we’ll go with that 6.5 just based on mechanical limitations. But the other thing you know is as we do our reservoir diagnostics, the real tipping point for the rock is in and around five. So if you’re over that five, we start to get that better effective frac and at 6.5, you’re certainly getting there. Well above that, right?

Jeremy McCrea: Yes. Okay. That’s good for me. Thanks, Craig.

Craig Bryksa: Okay. Thanks, Jeremy.

Operator: Thank you. Your next question is from Dennis Fong from CIBC World Markets. Your line is now open.

Dennis Fong: Hi, good morning and thanks for taking my questions. I guess my first one follows along, I guess a little bit of the prior two. And so obviously as you’ve kind of been editing your completions design, can you talk towards a little bit more and I think you alluded it to Harvey’s — or your answer to Harvey’s question is really just around drilling density. Obviously, there’s a lot of focus around elevator fracs, accessing other areas of the reservoir. Given kind of a — kind of your revised completion design, can you talk towards how that might have evolved a little bit, how that may impact inventory just again, depending on how you think about the completion design going forward as you rotate back towards single point entry for some of your fields.

Craig Bryksa: Yes, and I — so thanks, Dennis. And what I would say to that is in order for us to get that proper elevator frac, we need to use the single point entry. And that is what has become abundantly clear to us here over the last couple of months. So that design is what is necessary for us to capture that entire portion of the reservoir. So keep that in mind. But as far as well densing and well spacing, we’re fairly conservative on that already. Like if you remember, when you think through Gold Creek and Gold Creek West, we space our wells in the 5 to 7 is the tightest we would go on a per DSU basis, mostly in that 5 range. But certainly there are some areas where we’re a little bit tighter at 7, which again when you look at industry over the long term, this is, I would say, it’s a fairly conservative well density.

And then when you move down south into the Karr and Karr south areas, our well spacing there is generally eight on a per DSU basis and that’s between the two benches. But again that’s a significant widening of spacing, when you think of what Hammerhead and the prior operator had been doing in the past, their well density was in that 10 to 11 wells. And we certainly believe that is too tight. I think you can see that on inter-well interference, you can see that on decline rates of those wells. So we’ve taken a little bit more of a conservative approach and now the next step for us is single point entry has never been tried down there. Actually, there’s, I shouldn’t say that, sorry, there’s one pad in the far end of the south field that is single point entry.

And in fact Dennis, if you look at that pad, it’s one of the best pads in that area. So this is where, you know, look for us to take that technology and apply it across that part of the field as well, too. And that’s what’s got us excited as we go.

Dennis Fong: No, appreciate that. That’s incremental. Sorry. Go ahead, Craig.

Craig Bryksa: Yes, well, I was going to say it’s really this production performance that we’ve seen out of this latest couple pads called 11 wells with them not coming on a type well. That is played into Q4 — into our Q4 numbers. And that really is what flows through into 2025. And that’s where you see that setback on the production. But again, the bulk of that volume is the gas volume, right? Not the oil volumes. We’re only off, call that 2,000 on oil.

Dennis Fong: No, I appreciate that incremental color on and the details around kind of the next steps on the development side. Switching gears a little bit, you also mentioned it in your prepared remarks. You talked a little bit around optimizing facilities. Can you discuss maybe a little bit more in depth as to what that entails? Is it compression? Is it incremental capacity at your batteries? Is it pipelines? Is it a combination of all three? I guess just a little bit more color on that side would be great. Thanks.

Craig Bryksa: Yes. And so the one thing you’ll note in the 2025 budget is we bumped up our Montney facilities capital spend by about CAD70 million year-over-year from ’24 into 2025. And that’s the big component of that change in the capital guidance is that, and you know, Dennis, as we got into these areas and you’re working through things, we started to realize that as you’re bringing fluid volumes in, the capacity of some of these batteries is not at nameplate capacity. So we’ve been doing a significant amount of work in 2024. We actually reallocated CAD30 million out of production and drilling spends in Saskatchewan into facilities in the Alberta Montney this year to get after that as soon as we could. And then we’re applying more capital into it in 2025.

And I think by the end of next year, you’ll see us being more of called a more steady state facility spend going forward as we get these issues addressed. But it, like Dennis, it’s what you mentioned, it’s a combination of everything. It’s some line looping to make sure that we have flexibility to move beyond — between the batteries. It’s adding incremental tankage free water knockout. It certainly is some incremental gas lift compression and making sure all that is in place and on site. So it’s kind of, for lack of better terms, a mixed bag of everything that you’d see in facilities that we have identified and are now addressing across the field top to bottom. The other thing to note, Dennis, like with 6 to 7, so I talk in Gold Creek West now, if you think of that 6 to 7 pad which is, it’s just been an incredible pad.

And we’re following up that pad up now with Phase 3 and we’re — that — just super excited about what Gold Creek West means and what the materiality it is for this company. We have accelerated that battery turnaround, an expansion that was supposed to happen in February of next year, ’25. We’ve accelerated that into 2024 so that as those phases, the next phases of those pads come on, we’re all ready for that. So that has been going on here in the background, too and actually that shutdown is on right now. So it’s a little bit of everything there, Dennis, as far as — I don’t know if that helps you or not.

Dennis Fong: No, that — I appreciate that context. I was just wondering if there were kind of a couple, we’ll call it, key areas that needed to be kind of improved upon or optimized. But it sounds like it’s a little bit of everything, so, no, I appreciate that color as well there, Craig. I’ll turn it back.

Craig Bryksa: Dennis, one thing I would say is Gold Creek is where we’re spending a lot of that, which is where some of these newer pads come into, too. And then we do have — we are working on a new Gold Creek battery that would be online in 2026, too, in the background.

Dennis Fong: Perfect. Thank you.

Operator: Thank you. Your next question is from Luke Davis from Raymond James. Your line is now open.

Luke Davis: Hi, good morning, guys. Just had a couple of questions related to the guidance that you put out this morning. So on 2025, I’m just wondering, within that base budget that you’ve outlined, if you can just speak a little bit to some of the contingency that you’ve put in there, both for planned and unplanned downtime. Just trying to get a sense for how conservative you guys you’re looking at this?

Craig Bryksa: Yes, so, hi, Luke, it’s Craig. That’s a — it’s a good question. I would say after experiencing what we experienced in Q3 of this year and just unplanned downtime, some planned downtime as well as some of the facility constraints that we’ve seen. And then, as well, you get smarter on how some of these facilities run through different weather conditions. We have built in some incremental downtime into the budget for 2025. So we have layered in an incremental couple thousand barrels a day beyond what we had already, just to ensure that as we make our way through the year, that some of these unexpected things can be absorbed within our overall numbers. So we had a layer in there on an annualized basis, and obviously, you forecast that monthly, but we’ve layered on called an incremental couple thousand a day on an annualized basis, again forecasted monthly.

And then that’ll show through the quarter. So we have, I would say — we have a very, much more robust number on that in ’25 than we had in ’24. Does that help you?

Luke Davis: Yes, no, that is helpful. And then I guess just a follow-up to that, related to the budget, I’m just wondering if you can outline what a potential program would look like in sort of a CAD65 to CAD70 world. I know spots below the budget that you put out this morning, 25 is backward rated, so even lower than that. So from where I’m sitting now, looks like it presents a little bit more downside risk in terms of when you firm that up in December. So just trying to understand sort of what the bookends might look like?

Craig Bryksa: Yes. So what I can assure you of, Luke, is that we are not adding capital. Oil can rip to 150 bucks. We will not be adding capital. So know that. And I think with the way the program is set right now, it was a good apples-to-apples comparison of what the market had saw from us previously. So it gives you a good data point as far as a benchmark. I think if commodities slide into that 60-ish dollar range for a while, we would look to be disciplined on that and we’d look to pull back on that. And at that point in time, we’d likely look at cutting, I don’t know, I would say somewhere in the neighborhood of CAD250 million to CAD300-ish million out of that. That would probably pare your overall production down in the range of call it 3,000 BOE to 5000-ish BOE per day on the annualized basis.

And that would be basically looking at peeling out one of the Montney rigs and then cutting some of the other operations as well as how we’ve been thinking through that, just to give you a bit of a flavor. And so if commodities slide, we are going to be disciplined. We are absolutely not tone-deaf to the market and how things have been playing out there. All that being said, we do like the plan, especially for the learnings from ’24 and ’25 and then what that means into our five-year plan as you look to go forward on that. But absolutely, if the commodities slide, we will react and we will react in the right fashion.

Luke Davis: Got it. That’s helpful, I guess. Just final one for me related to the infrastructure, looks like you got about an incremental 75 million or so into 2025. How does that cascade into future years and how should we expect that infrastructure spend to sort of shape up, say it over the next three to five?

Craig Bryksa: Yes. So when you look at our five-year plan and the detail in there, Luke, this year is the biggest spend on that front. And then when you start to look into ’26 and ’27, it pulls back by roughly the amount we added this year into those next two years, and then beyond that it starts to get even a little bit lower. So this year, we’re about 15% of our budget. And in the back part of the five-year plan, we start to get in that kind of 8- to 10-ish percent of the total budget as we start to have some of these issues behind us. But this 2025 is the biggest year as far as the facility spend from that standpoint.

Luke Davis: Great. Appreciate that. Thanks, Craig.

Craig Bryksa: Thanks for the questions.

Operator: Thank you. Your next question is from Michael Spyker from HTM. Your line is now open.

Michael Spyker: Good morning, guys.

Craig Bryksa: Good morning, Michael.

Michael Spyker: Would love to say how’s it going It must be a tough morning at Veren, but we move forward. So I guess my questions this morning come mostly from the plug and perf completions like everybody else has been touching on. But I’ll start with a reprieve for you guys at Kaybob. Have you guys seen any wins from the tighter spacing on the 235 pad and going forward, kind of any learnings on inventory and completions there in the Kaybob oil window? So I know that’s one of your stronger assets, so I’ll start with that.

Craig Bryksa: Yes. So Michael, thanks for the questions and obviously we love Kaybob and we love the consistency and the repeatability of Kaybob and you’ve seen us slowly over time creep in in our well spacing on what we’ve been doing in the area. Now typically in through the oil window, we run in that about 400-ish-meter spacing. We crept in from the 600 meters and in some of the areas you’re going to see us tightening a little bit more. As far as the individual pads and how they play out in the areas, we’ll see how the long-term performance looks and what that does before we start to shift inventory on any of those fronts. But so far, things on — as far as well density and well spacing looks pretty good. I would also say though Michael, as we move through 2025 and we start pushing into the more condensate-rich fairway as opposed to the volatile oil window where you get a little bit higher pressure, we might even creep in a little bit tighter there as well too.

So as opposed to, call it, 400-meter spacing, you know, somewhere in that 320-meter spacing. But we’ll see how the long-term performance is on those before we start to layer an incremental inventory.

Michael Spyker: Awesome. Thank you. So just to confirm the plug and perf has kind of seen soft results and that’s mostly due to lesser frac height growth. So you’re not stimulating the pay column as much as you kind of would expect. And then at 6-7 East and the new 8-31 you guys are kind of thinking single point entry NCS on those. And what would be the kind of the boundary to the south where you think about adding back plug and perf, is that kind of Elmore Township 66 kind of area or how do you think about the windows of the asset where you’d start to bring back some of that plug and perf completion?

Craig Bryksa: So you’re a 100% right as far as the rate and the high growth. And you’re not — you’re — we on these last plug and perfs in the Gold Creek area, we didn’t get that column. We didn’t get all the way to the top and the results have shown that. So you’re right on that. And it is driven by the rate and the entry points into the reservoir. As far as 6 or 7 Phase 3, we made the call to switch all of those to the single point entry system as we were drilling those. All that being said Michael, keep in mind one of them already had its liner run in so it will be plug and perf. And if you remember, we did the original Phase 2 pad there. Two of them were plug and perf and two of them were single point entry. And the results are good from that pad.

They’re actually phenomenal. But we do believe, now knowing what we know, we believe that the plug and perf systems in the two wells was aided by the single point entry systems in the offsetting well. So we believe there is some frac carryover into those wells that help them. So we have made those changes. But as far as moving down south, I think we want to understand what the upside is to all this single point entry systems in Karr as we move from Township 66 down. And ultimately if the wells are just the production – or the production results dictate it, then we would look to stay with a single point entry system in those if things look great. So we’ll see how that ends up playing out. Like, keep in mind we’ve had some good results in Karr and that area that has been under the plug and perf system.

So let’s now see what single point will do in there. And I — that’s where we, you know, like I mentioned a couple minutes ago, that’s where a person starts to get excited and then do know Michael, if you look in — if you look in 64 at 2, so Township 64, range 2, there’s a five well pad in there that was originally completed by the Spartan Delta team actually using single point entry. And it is an absolute outstanding pad. So you can use that one for a reference point when you’re digging into the details a little bit.

Michael Spyker: Yes, so just one last one for me. I think that’s a 6-10 pad. And so I think you guys have said earlier that Karr West in 64-3 is behaving like Karr East. When you guys go into single point entry in 64-3, how do you expect those well results to change? Is that a lower IP and a lower decline?

Craig Bryksa: I think we might have lost you there a minute. Michael, but yes we can. But I think your question was on how do we expect the well performance on the single point entries in Karr when 64-2 has that, is that behaving or 64-3 behaving like 64-2. So I can tell you that the typos in there are now built off what we see on the offsetting production. Anything that benefits us through single point entry would be upside to that. But what we are seeing is less gas in that area and more liquids. Like the liquids rates have been strong, but they’re not a very sharp decline. A little bit more steady on that oil front. So I guess we’ll see how these ones play out. I hate to speculate on that, Michael.

Michael Spyker: Sure. All right, I appreciate it. I’ll turn it back. Thanks, guys. Happy Halloween.

Craig Bryksa: Yes, thank you.

Operator: Thank you. The next question is from Amir Arif from ATB Capital. Your line is now open.

Amir Arif: Thanks. Good morning, guys. I just wanted to get a little bit of a clarification on a couple previous questions here. So in Karr South, again you’ve been historically doing plug and perf. You’re going to test these sliding sleeve. Are you also going to be doing that a Karr North because I think you’ve got some Karr North wells in Q1?

Craig Bryksa: We’re doing it across the play and thanks for the question. But yes, we’re going to move it across the play based on what we’ve been seeing.

Amir Arif: Sounds good. And then on the ’25 guidance CapEx relative to WTI move, I think we’re talking about a 250 million to 300 million dollar potentially lower capital spend. Is that — so was that closer to 60 WTI or just in the low?

Craig Bryksa: Yes, I mean, — Amir, yes, I don’t think we’re married to a price point at that, Amir. It’s more how’s the market and how’s market moving and how do you see things playing out? And obviously, we’ve got some data points coming out here this year that follow into next year with OPEC, the election, what all these things mean to our commodity? Yes. And then we’ll look to react to that. But that reaction will be to remove capital. It certainly would not be like I was saying before, it’s not adding any incremental capital – in those numbers like I mentioned.

Amir Arif: Okay. Got it, got it. That makes sense. And so the focus remains on generating free cash above delivering on the production growth that you’re looking at for ’25. Is that a fair way to think about it then?

Craig Bryksa: That’s a 100% fair. And then the idea is to continue to strengthen the balance sheet with that share that we keep for ourselves. That other remaining 60% goes back to the shareholders and in the base dividend and then the top-up obviously tool of choice, especially on days like today is share purchases.

Amir Arif: Makes sense. And just one final question on the five-year plan, what WTI pricing assumption have you made in that five-year plan? And is that like a two-rig program at Duvernay and then one rig at Montney?

Craig Bryksa: No, so the five-year plan has us growing over that time period. So instead of the real difference between us in the old five-year Plan relative to the new five-year plan is that we basically lost a year here with what we learned. So now instead of 250,000 BOE per day in 2028, we get there in 2029. And keep in mind that incorporates everything that I’ve been talking about here today as far as type wells and understanding the type wells in areas. So all that is baked in. So we get there in 2029 and then at a 70 price deck and call it 3-ish. Well, CAD3 AECO that generates the 4, just under CAD4 billion of excess cash flow cum after-tax excess cash flow at that level and that’s at 70 bucks. And it’s a, sorry, it’s — Ken’s pointing to me here, it’s a two-rig Duvernay program.

So Kaybob Duvernay runs two rigs. The Alberta Montney runs three rigs in that program. And then we bob and weave in the Saskatchewan asset base somewhere between 1 and 3 depending on the seasonality with breakup and that sort of thing in that asset base. So it’s very achievable from a cadence of operations standpoint.

Amir Arif: Okay. Sounds good. Thanks for the color.

Craig Bryksa: Yes. Thanks, Amir.

Operator: Thank you. There are no further questions at this time. Please proceed.

Craig Bryksa: Okay, I’ll pass it over to Sarfraz Somani, he’s our Manager of Investor Relations and he’s just going to moderate a couple questions from the web.

Sarfraz Somani: Yes, thanks. So this couple come in here right now. So one is what WTI price is needed for us to fully fund capital and base dividend right now based on our program?

Craig Bryksa: Based on the program we’ve laid out or — and what?

Sarfraz Somani: Fully funded.

Craig Bryksa: Yes, so in that event, I mean if commodities slide, we’d look to pull back the capital program so that we were fully funded in that CAD50 range. And then that would equate to somewhere in the neighborhood of about CAD1.1 billion or CAD1 billion to CAD1.1 billion of capital. And that would fund the dividend and then the capital program.

Sarfraz Somani: Okay and the second question is just on the long-term debt, could you remind what the long-term debt target is and at what point — in the interim where do we hit the short-term target and what happens to the return of capital at that time?

Craig Bryksa: Yes, so right now we’re going to exit the year somewhere around CAD2.5 billion of absolute debt. Keep in mind that’s going to be about a CAD1.3 billion debt repayment over 2024. That’ll put us in and around the commodities we are today in and around 1 times debt to cash flow. In the long term, we’d like to run the business at about CAD1.5 billion of debt. So that would equate to somewhere around 1x debt to cash flow in that CAD45 to CAD50 price environment. And that point in time, I think our balance sheets call it bulletproof. And there’ll be points in time where we have less debt than that. But as you look at it, that’s just kind of a guide to give you on how, if you ask the executive team in the board on how we’d like to run the business, it’s in those levels.

We do have a bit of a near-term debt target where we’d like to be around CAD2.2 billion. And at that point in time is how we look to grow our return of capital. And I think it depends on the strip and how this plays out, but that would occur at some point in 2025.

Operator: Yes. Thanks, Craig. There are no more questions online right now, so just wanted to close the call here and thank everyone for joining us today.

Craig Bryksa: Thanks, everybody.

Operator: Thank you. Veren’s Investor Relations department can be reached at 1-855-767-6923. The conference has ended. Thank you and have a good day.