Veren Q3 2024 Earnings Call Transcript

Quartr
Provided by Quartr
October 31, 2024

There are 9 speakers on the call.

Operator

Good morning, ladies and gentlemen. My name is Jenny, and I will be your operator for Verint'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 Verint'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.

Operator

Dollars. 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. 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 of the press release issued earlier today.

Operator

I will now turn the call over to Craig Britza, President and Chief Executive Officer at Barron. Please go ahead, Mr. Gritzia.

Speaker 1

Thank you, operator. Welcome everyone to our Q3 2024 conference call. With me today are Ken Lamont, our Chief Financial Officer and Ryan Gritzfeld, our Chief Operating Officer. Our 3rd quarter results were highlighted by generating excess cash flow of $114,000,000 returning $85,000,000 to shareholders through dividends and share repurchases announcing our strategic infrastructure transaction for proceeds of $400,000,000 which closed in the Q4 and further net debt reduction with total expected repayment of $1,300,000,000 in 2024. We will continue to prioritize operational execution, optimizing and strengthening our balance sheet and increasing our return of capital to shareholders.

Speaker 1

In the Q3, we produced 185,000 BOE per day comprised of 65 percent oil and liquids. Our Q3 production was impacted by 3rd 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.

Speaker 1

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 1st 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 3 years. These wells have already accumulated 440,000 BOE per well in just 9 months and are currently producing at a rate of 1800 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.

Speaker 1

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.

Speaker 1

Although the wells completed with plug in 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 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.

Speaker 1

We have achieved substantial efficiency gains in KBOB 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 twenty twenty three. 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 percent to oil and liquids with development capital expenditures of $1,450,000,000 to $1,500,000,000 We also announced our 2025 budget today where we expect to produce 188 Boe to 196,000 Boe per day weighted 65 percent to oil and liquids with development capital expenditures of $1,480,000,000 to $1,580,000,000 Year over year, our 2025 production growth based on 4th quarter is still expected to be 10,000 Boe per day, which is in line with our prior plan. 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.

Speaker 1

However, should commodity prices weaken, we will use our discipline and flexibility to lower our capital budget. We expect to generate $575,000,000 to $775,000,000 of full year excess cash flow in 2025 at $70 to $75 per barrel WTI price. We've allocated 85 percent 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.

Speaker 1

Consistent with our capital allocation framework, we have also allocated a small portion of our budget to 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 $4,000,000,000 of cumulative after tax excess cash flow over the life of this plan at $70 per barrel WTI pricing and $3 per Mcf AECO price. 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.

Speaker 1

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 and A. Operator, please open the lines.

Operator

Thank you. Your first question comes from the line of Michael Harvey from RBC Capital Markets. Your line is now open.

Speaker 2

Yes, sure. Good morning. Thanks for taking the question. I guess just a couple for me. Just kind of getting close to year end, do you expect to see any of these recent well results having an impact on the reserves you're carrying or McDaniels is carrying for these areas?

Speaker 2

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?

Speaker 1

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 update.

Speaker 1

So, 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 well 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.

Speaker 1

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 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 Q3 in 2015 to 2016 Phase 3. 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 very rapid time, including some of the wells down in Carth.

Speaker 1

There's some of the pads down in Carth 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 to 7 Phase 3 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 car sales acreage where it hasn't been done before and really what this is going to end up doing for us in that area.

Speaker 1

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, say in the reserve book looks pretty solid. And then when you look into well results kind of December and then into Q1.

Speaker 2

Got you. Thanks for that, Craig.

Speaker 1

Yes. Thanks for the question, Mike.

Operator

Thank you. Your next question is from Jeremy MacRae from BMO Capital Markets. Your line is now open.

Speaker 3

Sure. Hey, Craig. I've got a couple of 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?

Speaker 3

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 wait I'll ask second question after here in a sec.

Speaker 1

Yes. 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.

Speaker 1

I think when you look at where we are on an overall guidance cut for 2025 relative to where we were, you're basically off 10,000 barrels a day or 5%. Of that 10,000 BOE a day, so of that 10 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 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.

Speaker 1

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 $1,000,000 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.

Speaker 1

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 and then as we entered into 2024 on 3rd 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 car acreage as well too. So that's where I start to get pretty jazzed. So I'll look again fairly long on your question, Jeremy, sorry.

Speaker 3

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? Like I know it probably has things to do with like your pumping rates in that, but just is it almost 100% completion design and is there a risk of geology or is this really just because you got to go back to the old completion design?

Speaker 1

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.

Speaker 1

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 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.

Speaker 1

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 2. 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.

Speaker 1

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 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 were stepping out and doing anything any different. We in fact, we're trying to drive the cost structure on a proven technology.

Speaker 1

But with our area of 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 all that I learning experience and we're going to take this and run this and grow from it going forward.

Speaker 3

Just on the old NCS systems versus the new, what you're going to try, like it looks like you're using about 6.5 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?

Speaker 1

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.

Speaker 1

But the other thing do 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?

Speaker 3

Yes. Okay. That's good for me. Thanks, Craig.

Speaker 1

Okay. Thanks,

Operator

Jeremy. Thank you. Your next question is from Dennis Komp from CIBC World Markets. Your line is now open.

Speaker 4

Hi, good morning and thanks for taking my questions. I guess my first one follows along, I guess a little bit of the prior 2. 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 your revised completion design. Can you talk towards how that might have evolved a little bit?

Speaker 4

How that may impact inventory? Just again depending on how you think about completion design going forward as you rotate back towards single point entry for some of your fields?

Speaker 1

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, call it, couple of months. So that design is what is necessary for us to capture that entire portion of the reservoir.

Speaker 1

So keep that in mind. But as far as well, density 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 is a fairly conservative well density. And then when you move down south into the Carr and Carr South areas, our well spacing there is generally 8 on a per DSU basis and that's between the 2 benches.

Speaker 1

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.

Speaker 1

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 look for us to take that technology and apply it across that part of the field as well too.

Speaker 1

And that's what's got us excited as we go.

Speaker 4

No, I appreciate that incremental. Sorry, go ahead, Craig.

Speaker 1

Yes. 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 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 volumes, right, not oil volumes. We're only off, call it, at $2,000 on oil.

Speaker 4

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?

Speaker 4

Is it pipelines? Is it combination of all 3, I guess? Just a little bit more color on that side would be great. Thanks.

Speaker 1

Yes. And so the one thing you'll note in the 2025 budget is we bumped up our Montney facilities capital spend by about $70,000,000 year over year from 2024 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.

Speaker 1

We actually reallocated $30,000,000 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 be in more of call it a more steady state facility spend going forward as we get these issues addressed. But like Dennis, it's what you mentioned. It's a combination of everything.

Speaker 1

It's some line looping to make sure that we have flexibility to move beyond the or between the batteries. It's adding incremental tankage, free water knockouts. 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 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.

Speaker 1

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 and expansion that was supposed to happen in February of next year, 2025. We've accelerated that into 2024. So that as those phases of 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.

Speaker 1

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.

Speaker 4

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.

Speaker 1

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 too. And then we do have, we are working on a new Gold Creek battery that would be online in 2020 6 too in the background.

Speaker 4

Perfect. Thank you.

Operator

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

Speaker 5

Hey, good morning guys. Just had a couple of questions related to the guidance that you put

Speaker 3

out this morning. So on 2025,

Speaker 5

I'm just wondering within that base budget that you've outlined, if

Speaker 4

you can just speak a little bit

Speaker 5

to some of the contingency that you put in there both for planned and unplanned downtime? Just trying to get

Speaker 4

a sense for how conservative you guys are you looking at that at this?

Speaker 1

Yes. So, hey 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.

Speaker 1

We have built in some incremental downtime into the budget for 2025. So we have layered in an incremental couple of 1,000 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 1,000 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 much more robust number on that in 2025 than we had in 2024.

Speaker 1

Does that help you?

Speaker 5

Yes. No, that is helpful. And then I guess just a follow-up to that related to

Speaker 4

the budget. I'm just wondering if

Speaker 5

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, dollars 25 is backwardated, so even lower than that. So from what I'm sitting now, let's say 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.

Speaker 1

Yes. So what I can assure you of, Luke, is that we are not adding capital. Oil can rip to $150 we will not be adding capital. So know that. And I think with the way the program is set right now is a good apples to apples comparison of what the market had saw from us previously.

Speaker 1

So it gives you a good data point as far as the benchmark. I think if commodity 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 $250,000 to $300 ish million out of that. That would probably pair your overall production down in the range of call it 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 cutting some of the other operations as well as how we've been thinking through that.

Speaker 1

Just to give you a bit of a flavor. So if commodity 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 2024 and 2025 and then what that means into our 5 year plan as you look to go forward on that. But absolutely, if the commodity slide, we will react and we will react in the right fashion.

Speaker 5

Got it. That's helpful. I guess just final one for me related to the infrastructure, it looks like you got about an incremental $75,000,000 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, over the next 3 to 5?

Speaker 1

Yes. So when you look at our 5 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 2026 and 2027, 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.

Speaker 1

And in the back part of the 5 year plan, we start to get in that kind of 8% to 10% -ish 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.

Speaker 6

Great. Appreciate that. Thanks, Greg.

Speaker 1

Thanks for the questions.

Operator

Thank you. Your next question is from Michael Spiecher from HCM. Your line is now open.

Speaker 7

Good morning, guys.

Speaker 1

Good morning, Michael. I

Speaker 7

would love to say, how's it going? It must be a tough morning at Verint, 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 KaBOB. Have you guys seen any wins from the tighter spacing on the 2 35 pad and going forward kind of any learnings on inventory and completions there in the KaBOB oil window?

Speaker 7

So I know that's one of your stronger assets. So I'll start with that.

Speaker 1

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 in through the oil window, we run-in that about 400 ish meter spacing.

Speaker 1

We crept in from the 600 meters and in some of the areas you're going to see us tighten in 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.

Speaker 1

So as opposed to call it 400 meter spacing, somewhere in that 3 20 meter spacing. But we'll see how the long term performance is on those before we start to layer an incremental inventory.

Speaker 7

Awesome. Thank you. 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 pay column as much as you kind of would expect. And then at 6 to 7 East and the new 8 of 31, you guys are kind of thinking single point entry NCS on those.

Speaker 7

And what would be the kind of the boundary to the south where you'd 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?

Speaker 1

So you're 100% right as far as the rate and the high growth and you're not 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.

Speaker 1

And if you remember, we did the original Phase 2 pad there, 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 helped them. So we have made those changes.

Speaker 1

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 Carr 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 car and that area. That has been under the plug and perf system.

Speaker 1

So let's now see what single point will 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 though, Michael, if you look in 64 of 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 a absolute outstanding pad. So you can use that one for reference point when you're digging into the details a little bit.

Speaker 7

Yes. So just one last one for me. I think that's a 6 to 10 pad. And so I think you guys have said earlier that Carr West in 60 four-three is behaving like Carr East. When you guys go into single point entry in 60 four-three, how do you expect those well results to change?

Speaker 7

Is that a lower IP at a lower decline?

Speaker 1

I think we might have lost you there. You've got a little bit 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 CAR when 64.2 has that is that behaving or 64.3 behaving like 64.2. So I can tell you that the type wells in there now built off what we see in the offsetting production.

Speaker 1

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. Sure.

Speaker 1

All right.

Speaker 7

I appreciate it. I'll turn it back. Thanks, guys. Happy Halloween. Yes.

Speaker 1

Thank you.

Speaker 3

Thank

Operator

you. Your next question is from AmirAli from KB Capital. Your line is now open.

Speaker 8

Thanks. Good morning, guys. I just wanted to get a little bit of clarification on a couple of previous questions here. So on in Carr 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 at Carr North because I think you've got some Carr North wells in Q1?

Speaker 1

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

Speaker 8

Sounds good. And then on the 'twenty five guidance CapEx relative to WTI move, I think you were talking about a $250,000,000 to $300,000,000 potentially lower capital spend. Is that so was that closer to $60,000,000 WTI or just in the

Speaker 1

way? 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 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.

Speaker 1

It certainly would not be, like I said, the same before, it's not adding any incremental capital. Yes. So in those numbers like I mentioned,

Speaker 8

A. Got it. That makes sense. And so the focus remains on generating free cash above delivering on the production growth that you're looking out for 2025. Is that

Speaker 1

a fair way to think about it

Speaker 8

then?

Speaker 1

Yes. 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 other remaining 60% goes back to the shareholders in the base dividend and then the top up obviously Tula Choice especially on days like today is share repurchases.

Speaker 8

Makes sense. And then just one 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 then 1 rig at Montney?

Speaker 1

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 the 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 of the type wells in areas.

Speaker 1

So all that is baked in. So we get there in 2029 and then at a $70 price deck and call it $3 ish or $3 aECL that generates the $4,000,000,000 of excess cash flow, cum after tax excess cash flow at that level. And that's at $70 And it's a sorry, it's Ken's point to me here. It's a 2 rig Duvernay program. So Kaybob Duvernay runs 2 rigs.

Speaker 1

The Alberta Montney runs 3 rigs in that program. And then we bob and weave in the Saskatchewan asset base somewhere between 13 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.

Speaker 8

Okay, sounds good. Thanks for the color.

Speaker 1

Yes. Thanks, Sameer.

Operator

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

Speaker 1

Okay. I'll pass it over to Sarfaraz Samani. He's our Manager of Investor Relations and he's just going to moderate a couple of questions from the web. Yes. Thanks.

Speaker 1

So there's just couple coming here

Speaker 6

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?

Speaker 1

Based on the program we've laid out or it was?

Speaker 7

Fully funded. Yes.

Speaker 1

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 $1,100,000,000 of or $1,100,000,000 to $1,100,000,000 of capital. And that would fund the dividend and then the capital program.

Speaker 6

And 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?

Speaker 1

Yes. So right now we're going to exit the year somewhere around $2,500,000,000 of absolute debt. Keep in mind that's going to be about a $1,300,000,000 debt repayment over 2024. That'll put us in and around the debt to 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 $1,500,000,000 of debt.

Speaker 1

So that would equate to somewhere around 1 times debt to cash flow in that 40 $5 to $50 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 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 2,200,000,000 dollars And at that point in time is how we look to grow our return to capital.

Speaker 1

And I think I mean it depends on the strip and how this plays out, but that would occur at some point in 2025.

Speaker 6

Okay. 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.

Speaker 1

Thanks, everybody.

Operator

Thank you. Verint's Investor Relations department can be reached at 1-eight fifty five-seven sixty seven-six thousand nine hundred and twenty three. The conference has ended. Thank you and have a good day.

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Earnings Conference Call
Veren Q3 2024
00:00 / 00:00