Crescent Point Energy Corp

TSX:CPG

Earnings Call Analysis

Veren's Q3 2024: Strong Cash Flow, Key Production Adjustments

In Q3 2024, Veren generated $114 million in excess cash flow and returned $85 million to shareholders, moving to reduce debt by $1.3 billion in 2024. Despite production challenges, they expect to average 191,000 BOE per day in 2024. However, they revised 2025 guidance to 188,000-196,000 BOE per day due to recent well performance issues. A larger capital allocation of $1.45-$1.5 billion for 2024 aims at enhancing facilities. They anticipate cumulative after-tax cash flow of $4 billion by 2029, assuming a $70 per barrel WTI price【4:2†source】.

Solid Cash Flow and Capital Returns

In the third quarter of 2024, Veren generated an impressive $114 million in excess cash flow. This strong performance allowed the company to return $85 million to shareholders through dividends and share repurchases. Moreover, Veren completed a strategic infrastructure transaction, yielding $400 million, which is anticipated to enhance their financial stability and flexibility moving forward.

Production Performance and Challenges

Veren's production reached 185,000 barrels of oil equivalent (BOE) per day, with oil and liquids comprising 65% of that total. However, production levels were somewhat hampered by both third-party facility downtime and infrastructure limitations. In response, the company plans to invest in the expansion of their facilities' capacities to better accommodate increasing production demands. Notably, they have also identified 300 net drilling locations within their Alberta Montney assets, signifying potential for growth.

Optimizing Production Methods

The company's recent focus has been on optimizing completion designs in their Alberta Montney region. The switch from plug-and-perf to single point entry completion systems is set to enhance production efficiency significantly. Although initial results from plug-and-perf completions were economically sound, they failed to meet productivity expectations. Therefore, Veren is shifting back to their previously successful single point entry methods, which they believe will yield improved results.

Guidance Adjustments for Future Production

For 2024, Veren has adjusted its production guidance to an annual average of 191,000 BOE per day, with capital expenditures estimated between $1.45 billion and $1.5 billion. Looking ahead to 2025, the company anticipates production between 188,000 to 196,000 BOE per day, with capital expenditures set between $1.48 billion and $1.58 billion. This marks a reduction from earlier expectations, but the company remains bullish about the long-term potential of its assets.

Long-Term Financial Strategy

Veren’s updated five-year plan projects a production ramp-up to 250,000 BOE per day by 2029 and plans to generate approximately $4 billion in cumulative after-tax excess cash flow at $70 per barrel WTI pricing. Furthermore, the company aims to maintain a disciplined approach to capital expenditure; should commodity prices fall, they plan to scale back investments appropriately. The firm is positioning itself to return 60% of excess cash flow to shareholders while using the remainder for debt reduction.

Debt Management and Future Outlook

The company is on track to exit 2024 with approximately $2.5 billion in total debt, following a $1.3 billion repayment plan. Long-term, Veren aims to operate with a debt level around $1.5 billion, leveraging strong cash flow to maintain a low debt-to-cash flow ratio. As the financial landscape improves, further capital returns to shareholders are expected.

Market Reactions and Strategic Positioning

Recent market responses to Veren's adjustments suggest some overreaction, with a perceived impact of 10,000 BOE per day on production guidance. However, this is largely attributed to natural gas rather than oil output, minimizing the impact on financial performance. With targeted strategies in place, including operational changes and facility optimization, Veren is well-positioned for future growth and value creation for its shareholders.

Earnings Call Transcript 2024-Q3

[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 and non-GAAP measures sections of the 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, executive]

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 $114 million, returning $85 million to shareholders through dividends and share repurchases, announcing our strategic infrastructure transaction for proceeds of $400 million, which closed in the fourth quarter and further net debt reduction with total expected repayment of $1.3 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 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 is 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 among the top 1% and of all oil and liquids wells in North America over the last 3 years.

These wells have already accumulated 440,000 BOE per well in just 9 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 7-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 meet ups 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 5-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 $1.45 billion to $1.5 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 $1.48 billion to $1.58 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 $575 million to $775 million of full year excess cash flow in 2025 at $70 to $75 per barrel WTI pricing.

We've allocated 85% of our 2025 budget to our short-cycle Kaybob Duvernay and Alberta Montney assets that provide top quartile returns, scalability and quick plays. 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 5-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 $4 billion of cumulative after-tax excess cash flow over the life of this plan at $70 per barrel WTI pricing and $3 per Mcf AECO 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 capital back to our 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.

[Operator]

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

[Michael Harvey, analyst]

Yes. 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? 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, executive]

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 a mid-year reserve update with the independents as well as the full year-end reserve update. 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 2 of these pads, keep in mind, Mike, they just came on here in October between our 10 and 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 III.

So keep in mind, Mike, all 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 a very rapid time. including some of the wells down in Karr, 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 2 pads that are used in 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 to 7 Phase III offset, that 7-well pad will be coming on sometime in around February. But again, we have made that 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 to see if it even improves that even more. So it's a long-winded answer, say, in the reserve book looks pretty solid. And then when you look into well results kind of December and then into Q1.

[Operator]

Your next question is from Jeremy McCrea from BMO Capital Markets.

[Jeremy McCrea, analyst]

Kind of a couple of questions here. Maybe I'll just start with the elephant in the room. Can you comment on your stock price here this morning in just in 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 well results? And then I'll just -- I'll ask the second question after here in a sec.

[Craig Bryksa, executive]

Yes. 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, our you're basically off 10,000 barrels a day or 5% of that -- 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 only 2,000 of that is oil with the rest being made up as NGLs.

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. 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 prize 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 in the number of sleeves you're using in these. They can be -- it could be upwards of $1 million 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 of days. I think people are -- or 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. Again, fairly long winded on your question, Jeremy, sorry.

[Jeremy McCrea, analyst]

I think it's just -- it's 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? I know what probably has things to do with like your pumping rates and that but just -- is it almost 100% completion design? And is there a risk of geology? Or is this really just -- you guys just went to go back to the old completion design?

[Craig Bryksa, executive]

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 how 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-in perf.

So one thing I would note, Jeremy, is on the 10 to 28 pad that came on last there in this Gold Creek area. One of the things that we did do as we were learning this and catching up to this we did change the perf intervals in that stage. So instead of going to 5 clusters, we pulled back into 3 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 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 would note for you, Jeremy, is when you look at when you look at the competitors and you move to the south and the west across the play, the majority of the play is developed using plug and perf, right? So it's not that we are stepping out and doing anything any different. We, in fact, we're 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 Paul, a learning experience, and we're going to take this and run this and grow going forward.

[Jeremy McCrea, analyst]

Just on the old NCS systems versus the new what you're going to trial, like it looks like you're using about 6.5 tubes a minute for pumping. Is that going to increase at all going forward here? Or is there anything different with NCS that you want to use differently than higher wells?

[Craig Bryksa, executive]

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 to know is as we do our reservoir diagnostics, the real tipping point for the rock is in and around 5. So if you're over that 5, you start to get that better effective frac and at 6.5, you're certainly getting there. Well above that, right?

[Jeremy McCrea, analyst]

Yes. Okay. That's good for me.

[Operator]

Your next question is from Dennis Fong from CIBC World Markets.

[Dennis Fong, analyst]

I guess my first one follows along, I guess, a little bit of the prior two. And so obviously, as you 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 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, executive]

Yes. 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, call it, 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 spaced 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, is 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 8 on a per DSU basis and that's between the 2 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 a 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 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, analyst]

I appreciate that incremental -- sorry, go ahead, Craig.

[Craig Bryksa, executive]

Well, I was going to say it's really this production performance that we've seen out of this latest couple of pads, called 11 wells with them not coming on a type well that has 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 volumes, right, not the oil volumes. We're only off, call it, that 2,000 on oil.

[Dennis Fong, analyst]

No, I appreciate the 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 the combination of all 3, I guess? Just a little bit more color on that side would be great.

[Craig Bryksa, executive]

Yes. And so the one thing you'll note in the 2025 budget is we bumped up our Montney facilities capital spend by about $70 million year-over-year from '24 into 2025. And that's the big component of that change in the capital guidance is that. And 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 that 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 $30 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, call it, a more steady-state facility spend going forward as we get these issues addressed.

But 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 or between the batteries. It's adding incremental tankage, free water knockout. It's 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'm talking Gold Creek Quest now, if you think of that 6 to 7 pad, which has just been an incredible pad, and we're following up that pad-up now with Phase III. And we're just super excited about what Gold Creek West means and what the materiality it is for this company, we have accelerated that battery turnaround and expansion that was supposed to happen in February of next year '25. We've accelerated that into 2024. And 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 that I don't know if that helps you or not.

[Dennis Fong, analyst]

No, 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.

[Craig Bryksa, executive]

So, 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 2. And then we do have -- we are working on a new Gold Creek battery that would be online in 2026 too, in the background.

[Operator]

Your next question is from Luke Davis from Raymond James.

[Luke Davis, analyst]

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 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, executive]

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 of 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, call it, an incremental couple of thousand a day on an annualized basis, again, forecasted monthly, and then that will show through the quarter. So we have -- I would say we have a very a much more robust number on that in '25 than we had in '24. Does that help you?

[Luke Davis, analyst]

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 $65 to $70 world? I know spots below the budget that you put out this morning, '25 is backward dated so even lower than that. So from what I'm sitting now, it 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, executive]

Yes. So what I can assure you of, Luke, is that we are not adding capital. Oil can rip to $150 and 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 of commodities slide into that is 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 $250 million to $300-ish million out of that.

That would probably pair your overall production down in the range of at 3,000 to 5,000-ish BOE per day on the annualized basis, and that would be basically looking at peeling out 1 of the Montney rigs and then cut in some of the other operations as well as how we've been thinking through that. just to give you a bit of a flavor. So if commodities slide, we are going to be disciplined. We are absolutely not toned up 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 to 25 and then what that means into our 5-year plan as you look to go forward on that. But absolutely, the commodity slide, we will react and we will react in the right fashion.

[Luke Davis, analyst]

Got it. That's helpful. I guess just a 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 the infrastructure spend to sort of shape up, say, over the next 3 to 5?

[Craig Bryksa, executive]

Yes. So when you look at our 5-year plan and the detail in there, 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 2 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 5-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.

[Operator]

Your next question is from [ Michael Spiker from HTM ].

[Unknown Analyst]

I would love to see -- 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 the reprieve for you guys at Kaybob. Have you guys seen any wins from the tighter spacing on the 2 to 35 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, executive]

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 our well spacing on what we've been doing in the area. Now typically, through the oil window, we run in that out 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 as far as well density and well spacing looks pretty good.

I would also say though, Michael, as you -- 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, somewhere in that 320-meter spacing. But we'll see how the long-term performance is on those before we start to layer in the incremental inventory.

[Unknown Analyst]

Awesome. So just to confirm, that the plug and perf has kind of seen soft results, and that's mostly due to lesser frac high growth. So you're not stimulating the [ Peak columns ] as much as you kind of would expect. And then at 6 to 7 East, and the new 8 to 31, you guys are kind of thinking single-point of 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 [ Alamo's ] 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, executive]

So you're 100% right as far as the rate and the high growth, and you're not -- on these last plug and perfs in the Gold Creek area, we didn't get that call. 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 to 7 Phase III we made the call to switch all of those to the single point entry system as we are 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 II pad. There are 2 of them were plug and perf and 2 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 2 wells was aided by the single point entry systems in the offsetting wells. 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 cars as we move from Township 66 down and ultimately, if the wells are just put the production results dictate, 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. But keep in mind, we've had some good results in Karr in that area. That has been under the plug and perf system. So let's now see what single point we'll do in there. And that's where we -- like I mentioned a couple of minutes ago, that's where a person starts to get excited.

And then do know that, Michael, if you look in 64, 2, so Township 64 range 2, there's a 5-well pad in there. that was originally completed by the Spartan Delta team actually using single point entry, and it is an absolute outstanding path. So you can use that one for a reference point when you're digging into the details a little bit.

[Unknown Analyst]

Yes. So just one last one for me. I think that's a 6 to 10 pack. And so I think you guys had 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, executive]

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 642. So I can tell you that the type is in there 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 front. So I guess we'll see how these ones play out. I hate to speculate on that, Michael.

[Operator]

Our next question is from Amir Arif from ATB Capital.

[Laique Ahmad Amir Arif, analyst]

I just wanted to get a little bit of a clarification on a couple of previous questions here. So on Karr South, I guess 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, executive]

We're doing it across the play. And thanks for the question. But yes, we're going to we move it across the play based on what we've been seeing.

[Laique Ahmad Amir Arif, analyst]

Sounds good. And then on the 25% guidance CapEx relative to WTI move, I think you were talking about a $250 million to $300 million potentially lower capital spend. Is that -- so was that closer to $60 WTI? Or just in the...

[Craig Bryksa, executive]

I don't think we're married to a price point at that, Amir. It's more how is the market and how the 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. And then we'll look to react to that, but that reaction will be to remove capital. It certainly would not be, like I said, the saying before, it's not adding any incremental capital in those numbers like I mentioned.

[Laique Ahmad Amir Arif, analyst]

Got it. That makes sense. And so the focus remains on generating free cash above delivering on the production growth that you look out for '25. Is that a fair -- when you think about it then?

[Craig Bryksa, executive]

That's 100% fair. And then the idea is to continue to strengthen the balance sheet with that share that we keep for ourselves that the 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 repurchases.

[Laique Ahmad Amir Arif, analyst]

Makes sense. And then just 1 final question on the 5-year plan, what WTI pricing assumption have you made in that 5-year plan? And is that like a 2-rig program at Duvernay and one rig at Montney?

[Craig Bryksa, executive]

No. So the 5-year plan has us growing over that time period. So instead of the real difference between us in the old 5-year plan relative to the new 5-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 by wells and understanding the types 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, $3 AECO. That generates the -- just under $4 billion of excess cash flow after tax excess cash flow at that level. And that's at $70.

Sorry, Ken's pointing it me here. It's a 2-rig Duvernay program. So Kaybob Duvernay runs 2 rigs. The Alberta Montney runs 3 rigs in that program. And then we Bobade 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.

[Operator]

There are no further questions at this time. Please proceed.

[Craig Bryksa, executive]

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 of questions from the web.

[Sarfraz Somani, executive]

Yes. Thanks. So this just a couple come in here right now. So one is what WTI prices needed for us to fully fund capital and base dividend right now based on our program?

[Craig Bryksa, executive]

Based on the program we've laid out? Yes. So in that event, I mean, if commodities slide, we'd look to pull back the capital program so that we are fully funded in that $50 range and then that would equate to somewhere in the neighborhood of about $1.1 billion of $1 billion to $1.1 billion of capital. And that would fund the dividend and then the capital program.

[Sarfraz Somani, executive]

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 -- and then where do we hit the short-term target? And what happens to the return of capital at that time?

[Craig Bryksa, executive]

Yes. So right now, we're going to exit the year somewhere around $2.5 billion of absolute debt Keep in mind, that's going to be about a $1.3 billion debt repayment over 2024. That will put us in and around the commodities we are today in and around 1x debt to cash flow. In the long term, we'd like to run the business at about $1.5 billion. of debt. So that would equate to somewhere around 1x debt to cash flow in that $45 to $50 price environment. And at that point in time, I think our balance sheet is, 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 and 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 $2.2 billion. And at that point in time is how we look to grow our return of capital. And I think -- I mean it depends on the strip and how this plays out, but that would occur at some point in 2025.

[Sarfraz Somani, executive]

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

[Craig Bryksa, executive]

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.