Veren Inc. (NYSE:VRN) Q4 2024 Earnings Call Transcript

Veren Inc. (NYSE:VRN) Q4 2024 Earnings Call Transcript February 27, 2025

Veren Inc. beats earnings expectations. Reported EPS is $0.24, expectations were $0.21.

Operator: Good morning, ladies and gentlemen. My name is John, and I’ll be your operator for Veren’s 2024 Q4 and Full Year Results Conference Call. This call is being recorded today and will be webcast along 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, the management may make projections or other forward-looking statements regarding the future events or future financial performance. Any such statements are made subject to the forward-looking information and non-GAAP measure 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: Thank you, operator. Welcome, everyone to our Q4 2024 and full year results conference call. With me today are Ken Lamont, our Chief Financial Officer; and Justin Foraie, our Senior Vice President, Operations and Marketing. Veren was successful in 2024 in many fronts. We safely integrated our Alberta Montney assets into our corporate portfolio. We generated over CAD640 million of excess cash flow, realizing nearly 1/3 in Q4. We returned 60% of our excess cash flow to shareholders through the base dividend and share repurchases. We reduced our net debt by 35% or CAD1.3 billion. We delivered strong reserve additions across all categories. We successfully disposed of noncore assets and entered into a strategic long-term infrastructure partnership.

And we achieved an investment-grade credit rating, which allowed us to diversify our capital structure and improve our overall cost of capital. In 2024, we generated annual average production of 191,000 BOE per day, including fourth quarter production of 189,000 BOE per day. Our Montney and Duvernay assets in Alberta accounted for nearly 80% of our Q4 production, equating to 10% growth compared to Q1. Our 2024 independent reserves report demonstrates why we continue to be excited about the quality of our asset base. We organically replaced 173% of our 2024 production on a 2P basis and achieved positive technical revisions. The majority of our 2P additions came from the Alberta Montney with the remainder coming from the Kaybob Duvernay. We replaced our production efficiently, generating a strong recycle ratio of 2.1x based on our 2P F&D costs, including change in FDC.

We continue to believe in the long-term sustainability and the future potential of our asset base, with over 65% of our premium drilling locations in the Alberta Montney and Kaybob Duvernay remaining un-booked. In the Alberta Montney, we continue to test the single-point entry completions designs in car. We are pleased with the initial results from the 2 multi-well pads we brought on stream in late fourth quarter using this design. These pads generated an average peak 30-day rate of 1,270 BOE per day per well, which is 30% above the area type well. These wells also featured a high oil cut of 80%. We continued to invest in our gas egress infrastructure and infield optimization projects to increase our operational flexibility, minimize future downtime and enhance our ability to grow.

We anticipate realizing future operational efficiencies through both this investment and our previously announced strategic long-term partnership with Pembina Gas Infrastructure. In the Kaybob Duvernay, we are pleased by the consistent results we are generating. We brought on stream 2 multi-well pads in the fourth quarter that generated an average peak 30-day rate of 1,000 BOE per day per well, which is 25% above the area type well. These wells also featured a high condensate rate of 70%. We drilled several successful delineation wells in 2024 on both the east and west boundaries of our lands in Kaybob, de-risking future drilling inventory in the area. Our 2025 program includes additional delineation in the liquids-rich and lean gas windows.

We have built an asset portfolio that is a strategic combination of quick-payout short-cycle assets in Alberta with our long-cycle Saskatchewan properties that provide dependable excess cash flow. Our annual production guidance for 2025 is 188,000 to 196,000 BOE per day. We’ve had a strong start to the year, delivering January production of 191,000 BOE per day. Our production growth is weighted to the second half of the year. This is driven by planned facilities downtime in the early part of the year and the timing of bringing on our multi-well pads. Our capital expenditures guidance of $1.48 billion to $1.58 billion is weighted to the first half of the year and includes $240 million or 15% directed to facilities as discussed earlier. This investment further solidifies our infrastructure needs to support our long-term growth plans.

We anticipate generating significant excess cash flow of $625 million to $825 million this year based on $70 to $75 per barrel WTI pricing and $2.25 per Mcf AECO. We continue to return 60% of our excess cash flow through our base dividend and share repurchases with the goal of increasing our returns over time. We are confident about our 2025 outlook and remain focused on operational execution, strengthening our balance sheet and returning capital back to 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.

Q&A Session

Operator: [Operator Instructions] And we will now take the first question and this comes from the line of Amir Arif from ATB Capital.

Amir Arif: Just a few quick questions for you, Craig. Just first of all, just on the sliding sleeve test, the car south pad results again are encouraging. Is there any additional color you can share for us in terms of how those wells are holding up and if you feel that this has cracked the code in terms of how you want to do completions going forward in the area?

Craig Bryksa: Thanks for the question. So I can give you some color and I do have Justin here as well, too, so he could provide you some color. But obviously, like we talked, the rates — and you know me, Amir, I’m a bit of a rounder, so let’s say 1,300-ish BOE per day for the average of the 6 wells. We’re very excited about that. We’ll continue to optimize completions as we go forward, both using single-point entry and plug and perf as we look across the field. But certainly, with what we’ve seen from initial results on these, very strong. The other thing about it, Amir, is keep in mind the oil cuts on these have been significant, too, when you’re in that realm of 80%-ish. So really big oil wells and it’s been positive on that front.

When you look at the assets — or sorry, these first couple of pads here over, call it, a 45-, 60-day, we’re certainly happy with how they’ve been hanging in and how the decline performance has been on that. And as you and I have discussed in the past, one of the other potentials about the single-point entry is not only some of that initial results but also what does it do for the shallowing of the decline over the long term. So to date, excited, couldn’t be really happier about how the 2 pads have come online.

Amir Arif: I appreciate that color. And then just second question on the operating cost, they dropped nicely just quarter-over-quarter. Just curious how much of that is just due to the higher volumes and how much of that is due to some of the plant debottlenecks and facility upgrades you were doing? Or I’m just curious if that’s still coming in terms of further operating cost reduction from some of the facility optimization work.

Craig Bryksa: Yes. So a lot of that, Amir is, obviously, you’ve got a big component of the field costs that we have are fixed, right? So as those volumes are coming where you expect them to be, that does bring down the OpEx on a per BOE basis, so happy with that. The other thing that you alluded to is the debottlenecking work that we really started. It really started last year in about August, September, and we’ve been working diligently at that. We are starting to see some of the benefits of that on those — that base level performance. As you bleed off the pressures across the field, you can now flow more into not only into the facilities but also into those pipelines that take it into the facility. So that’s starting to show through and then that starts to show through in that OpEx as it comes through on the dollars per BOE.

So we’ll continue to do that here. We’ve got big plans for Q1 and then into Q2 on debottlenecking. So ideally, we start to see some consistent performance on that.

Amir Arif: Sounds good. And then just 1 final question, if I can, on just the capacity expansion at Gold Creek West. Is that progressing on time for the 6 to 7 pad to be tied in into March? Or is that 6 to 7 pad going to be into a new facility? Because I thought you were also building a new facility in that area or maybe I’m mistaken about that.

Craig Bryksa: No. You’ve got some of the color right there for sure, Amir. So the 6 to 7 pad itself, so Phase 3, we’re talking about here, will be coming on, call it, mid-March, that flows into our 326 facility, Gold Creek West facility, and that expansion work has been going on through Q4 and into Q1. And happy to tell you that things from that standpoint look good as far as timing. So we’ll be in good shape as far as processing capacity for that pad so I don’t expect any delays. And you know what really helped us, Amir? I mean, let’s be honest, not very often you get a January where a cold day is minus 20, right? So that certainly helped as far as some of that work going. But no, everything looks good as far as on time. And there is a little — a bit more facilities work that we’re going to continue to do through Gold through the front half of the year.

Extremely excited about that area, Amir, with the potential of some of those wells. So we’ve got a bit more work to do but the facility itself is on time.

Operator: And the next question comes from the line of Jeremy McCrea from BMO Capital Markets.

Jeremy McCrea: Just relates to just some of the recent wells here coming on with the single-point entry. So these wells are coming on 30% better on the BOE, 50% better on an oil basis. At what point do you look at your guidance and say, if all of our wells start to come perform like that, do we need to potentially look at revising our numbers up? How many wells would you like to see before you see that? Or what are some of the metrics you’re looking for on that there?

Craig Bryksa: Yes. So thanks for the question, Jeremy. So it’s Craig here, and again, Justin is with me if he wants to provide any color. But again, Jeremy, we’re really into February in the year. Extremely happy with how we entered the year and then how January looked on a production basis and really happy with the performance of these first 2 pads. And we’ll see how things play out for the remainder of the year and what that means. We’re very comfortable with the market guidance that we have out now, the 188,000 to 196,000. Things look certainly on track to be at those levels. So we’ll see how things play out. We’ve got a couple of pads coming up here, and I know you’re aware of, over the next little bit, in March, we have the 6 to 7 Phase 3 pad, which we’re excited about.

We also have a 12 to 36 pad that is — it’s kind of a north car area, Jeremy, if you’re familiar with that one on the map. So that one will be coming on in April, and that’s a blend, mainly single-point entry but we do have a couple plug and perfs in there, too. So it’s a good data set for us on a go-forward basis. And then in the Duvernay, we’ve got a couple of pads here coming on just over the next month or so. So let’s see how things go. But so far, so good, both on a well results basis as well as just overall production levels from the field. So, so far, so good.

Jeremy McCrea: Okay. And maybe just a bit of a catch-all just in terms of different M&A going on throughout the Montney. Is this something you guys are still interested in or just very happy with your current Montney, Duvernay positions and maybe you’re more likely at finalizing some of this main dispositions?

Craig Bryksa: Jeremy, our stance really hasn’t changed on that over the last 12 months. If you remember, we’ve been letting everybody know that we’re going to take a good solid pause as far as acquisitions and divestitures. We’re extremely excited about the asset base that we were able to put together. Love the Duvernay, love the Montney. Love how it pairs with the long-cycle assets in Saskatchewan. Lots of opportunity in front of us. We’ve got a good 5-year plan that we feel really good about. So I think what we really need to do is to continue to demonstrate to the market the quality of the assets and the quality of our execution. So that’s my way of saying, don’t look for us to be doing anything on that front in the near term. Very happy with how things have been moving here into the New Year.

Jeremy McCrea: Okay, perfect. And nice to see the stock moving here today this morning as well.

Craig Bryksa: Thanks, Jeremy.

Operator: And the next question comes from the line of Michael Spyker from HTM Research.

Michael Spyker: Good quarter. A little more pep in the step this morning. It’s good to see. I’ve got 1 question. I guess I got a few so you can tell me if I’m getting too into the weeds. But looking at some of the gas oil ratios in the Gold Creek 7 to 17 and 15 to 16 pads, they’ve been lower initially and during early time production. So is that a function of shorter frac growth not penetrating the upper part of the gassier sequence since you get less gas drive? Or how do you rationalize that kind of difference in early time gas oil ratios? And just generally, is there anything kind of notable you guys have noticed over the past few months producing these pads that have furthered the NCS sleeve single-point entry thesis? Because the declines are a lot shallower than you would have expected. So I’m just kind of curious what the learnings have been over the last 3 months or so.

Craig Bryksa: Thanks for the question, Michael. And so you noted 2 of those pads from Q4 where we did the plug and perf trials. One thing I would tell you that we’re really encouraged about is how those wells or how those pads have continued to increase in production. And have recently been running fairly flat in that 500 to 600-ish BOE per day range and at a much higher oil cut. So we’ve been excited to see how those things have performed. And I think at some point in time, they’ll — when you think of a time plot, these wells will end up probably cuming where they should be again relative or initial type well. So we’re excited about how they’ve played out. As far as the GOR, you’re right, the GOR is a little bit lower. We do think where the wells were landed and that style of completion may not aid it in the height growth and really penetrated into a little bit of that gas.

But these are early time results and we continue to analyze that, but certainly have been encouraged with how they have performed. All that said, our next batch in that area, we will try or we will move back to the single-point entry system in there and see how those do on a relative basis. But certainly, with 70 of those in the area, we feel pretty good about the results that we’ll expect from that under the single-point system.

Justin Foraie: I’m Justin, I’ll add a little color here, too. Yes. Sorry, Michael, just on your question on GORs being a little bit lower. One thing we have noticed with those 7 to 17 wells is actually our flowing bottom hole pressure or the percent drought, the percent drawdown on those wells has been quite low. So those wells, we are looking at optimizing and looking at different ways to be able to get that drawdown much lower in the well to help encourage that reservoir gas to come out. So again, look forward here in the next few months, next quarter or 2 for us to get those wells optimized and try to get that gas to come out.

Craig Bryksa: And then the last thing I would say, Michael, even though you do those plug and perf trials, we use — we still use basically 3 tons a meter and similar fluid rates. So that fluid and proppant went into that reservoir. It’s just maybe it didn’t maximize the height growth what we needed. But that certainly has obviously got a good stimulation on those wells and they are performing better than we had hoped or thought.

Michael Spyker: Okay. That’s super helpful. I guess kind of just a follow-up on that. I’m getting a little ahead of time lines here, but would there be an opportunity in the future possibly to replicate that NCS sleeve with extreme limited entry plug and perf? I mean, Shell did some of those kind of a few years ago and get the cost savings and maybe kind of try to pump harder with higher tier equipment. Has that been a discussion down the road or kind of just focused on getting NCS back on track and proving those results first?

Craig Bryksa: Yes, no. I mean, absolutely, you’re thinking the same way we are. We always want to continue to optimize our completions design, and it’s going to end up being different, I’m sure, for different areas. We also always want to continue to optimize our cost structure and pound that down. And if you — one of the learnings that we did have early on there, Michael, was in that quarter, as we could see the completions on that particular 7 to 17 pad, the performance wasn’t what we had hoped. We did make that change on the 12 to 36 pad where we ended up going to 3 perf clusters per stage. So we’re already starting to get a little bit more of a limited entry and getting that fluid rate per entry point a little bit higher.

Now certainly, you can go down to where you have 1 perf per — sorry, 1 perf cluster per stage but that’s where you start to get a little bit dilutive on your cost structure, right? So at that point in time, it doesn’t make sense to do that. It makes a lot more sense to use the single-point system. So these are things that we need to continue to work through. It’s going to continue to evolve for us. We’re going to continue to get better from a production standpoint and a cost structure standpoint. So that’s why we’re excited about how things have really started to play out here for us in January and how this is coming into the New Year.

Michael Spyker: Okay, that’s awesome. I appreciate that. I got 1 more and it might be a little gritty, but just on sourcing. I guess no pun intended on the grittiness, but it seems an evolution of the proppant mix, 30-50 heavy on the [5,023] and then 30-50 on 100 mesh or I guess, [50140] on the [2010]. Is that a function of just sand sourcing or are you guys seeing different results with different kind of proppant blends?

Justin Foraie: It’s Justin here again. So we have transitioned and, in some cases, to using some smaller sand to see if we can more effectively place that sand and more effectively get that prop type growth that we want — that we think we need to get. So still an evolution there on sand proppant sizing as well, Michael.

Michael Spyker: Okay, guys. I appreciate that so much. Very excited for the rest of the year. Good job on the quarter that was well done.

Operator: And the next question comes from the line of Dennis Fong from CIBC World Markets.

Dennis Fong: Congrats on a great quarter there, Craig and team. My first question here is just related a little bit, which was kind of a similar line of questioning. So given the incremental liquids content that you’re seeing coming from the single-point entry design, and I think Justin maybe partially alluded to it, how do you think that maybe plays into or maybe how you think about adjusting the build-out or utilization of gas lift in your operations as well as how you think about the development of the field or optimization of the field as you progress development, especially with the higher liquids content?

Justin Foraie: Dennis, it’s Justin again here. So yes, I mean, through the acquisition process and with Spartan Delta and Hammerhead, we acquired a couple of different theories on their gas lift and how they set up their pads. We’re looking to push gas lift, first of all, out to the pad level. And then secondly, where we can utilize it transition to high-pressure gas lift to be able to draw these wells down quicker. Now when we do get even higher on the liquids content, we will be looking at possibly using ESPs. There are a couple in the field that are running and have run effectively over the years in the past in our predecessor companies that we’re operating these fields. So again, I think it’s instead of a standard operation or a standard fit for artificial lift, it’s definitely something that’s going to evolve and be a pad-by-pad evaluation for us going forward.

Dennis Fong: Great. Really appreciate that incremental color there, Justin. My second question maybe shifting towards net debt. You’ve obviously made a lot of progress through 2024. I guess this might be also addressed to Ken. Can you talk towards maybe your comfort level with your balance sheet today? And if kind of the — like, obviously, organic deleveraging is kind of the primary way of lowering outstanding debt. But are there any other options that you’re looking at to maybe accelerate that process? And how should we be thinking about kind of your comfort level with where it stands today? Obviously, I understand you’ve made a lot of progress thus far.

Craig Bryksa: Yes. It’s Craig here, Dennis. So thanks for the question. I’m going to — I’ll pass it to Ken. But the one thing I would note is we did make significant progress on our overall debt reduction last year. We did manage to get our balance sheet down to that, call it, that $2.5-ish billion of absolute debt, which is down 35% year-over-year. And as we’ve noted in the past, our near-term debt target on an absolute level is about $2.2 billion, and we see ourselves getting there here over the next, call it, 12-ish months when you think of just the excess cash flow generation from our organization and that retained amount that we keep. But ideally, and Dennis, you know us well, and I mean, you talk to Ken and I. When you think of the business for the long term, we’d like to be somewhere in that neighborhood of about $1.5 billion or $1.6 billion-ish of absolute debt.

So we’ll continue to work towards that. And Ken is here and give you some color just as how we’re thinking to.

Ken Lamont: Yes. I echo the same comments as Craig. And then obviously, what we’re really excited about here when we look at ’25 and then you look at the 5-year plan, it’s just the amount of excess cash generation. And then obviously, as a function of that, how much we’re able to retain. So if I look forward into 2025 here, I mean, we’ve got organic deleveraging of $250 million at a US$70 WTI. So obviously, these are good numbers and we’re able to bring that debt to cash flow or that leverage down. I mean, how comfortable we are today, we’re very comfortable at basically a 1x debt to cash flow. To Craig’s comments, obviously, we want to drive that lower. And so yes, I think the real setup here as we look at this year and then look beyond, not only are we growing our production on a 7% CAGR, but we’re growing our excess cash by 15%.

And so year-over-year, even with the growth program that we’ve got, we’re building our excess cash generation, and that’s just going to accelerate the debt reduction and deleveraging. So happy with the setup. Obviously, we’re going to remain committed to it. We’ll have our base dividend there, which is sustainable here at lower oil prices. Every dollar on a return of capital and above that is going to go to share repurchases. And then obviously, keeping that 40% for the balance sheet and strengthening that. So like the setup, and that’s how we’re going to go forward.

Operator: And the next question comes from the line of Luke Davis from Raymond James.

Luke Davis: Wondering if you can just expand a little bit on some of the prior questions, first being related to your guidance. Looking a little bit conservative, given how strong volumes have come on year-to-date and some of the improvements we’re seeing across the portfolio. So just wondering if you can provide a little more detail around the parameters on the low end and the high end of the range and what’s currently baked in there.

Craig Bryksa: Yes. So thanks, Luke. So again, our guidance is 188,000 to 196,000. I think if you break it into halves on the year, we’ll be in the neighborhood of 187,000 on the front half of the year and around 197,000 in the back half of the year on average. So if you think of it from a quarter’s perspective, we’re going to be somewhere in the neighborhood of we’re saying 183,000 in Q1 and about 200,000-ish to a little bit over 200,000 in the back half of the year. Keep in mind, Luke, we’ve got a couple of things going on here in the backdrop. One, with the capital program being a little bit more heavily weighted to the front half of the year and then with pad timing, you’re spending all this money up front here in the front, drilling these wells and getting these pads on.

But we don’t see a lot of that production coming to the back half of the year. So that puts a little bit of a downward pressure on the front. And then the other thing we do know is, as we alluded to a little bit earlier, we’ve got quite a bit of facilities work going on here in the backdrop. So even if you look into February for an example, we did have some facilities that we had shut down to do some work on and all that plays into your numbers. So I guess it’s my way of saying we are comfortable with the range that we put out. Happy with the start we’ve had in January. And keep in mind, it’s only February so let’s see how things continue to progress, but the setup is so far so good on that front.

Luke Davis: I appreciate that. Just…

Craig Bryksa: Did that help?

Luke Davis: Yes, super helpful. Just 1 follow-up. A lot of focus obviously in the Montney and Duvernay. But I’m wondering if you could just speak a little bit to the Saskatchewan side of the portfolio. Speak to some of the changes you’re making down there, things you like. And related to M&A, prior question was asked on the Montney specifically, but anything you can do there to kind of bulk that up or generally just how you’re thinking about that side of the business?

Craig Bryksa: Yes. Luke, again on that, I mean, super happy with how the portfolio has come together, especially when you think of where we were, call it, 5 years ago and the portfolio, what it looks like today, the inventory of the short-cycle assets in front of us, between the Montney and the Duvernay, which we love both of them. And the other thing to keep in mind is the liquids in our play or in our assets relative to some of the other ones out there, we’re in that phase envelope in that 75% to 85%, whether it’s condensate or oil. So love the inventory setup in front of us between those 2. And then we really like that pairing of the long-cycle assets in Saskatchewan. So I wouldn’t look for us to do anything on the M&A front.

Obviously, Luke, there’s always a little, what I would call, base business things that you do around your swaps and small little tuck-ins and that thing that you always look to build out on the assets. But anything big, I wouldn’t say is going to occur. And then when you look at Saskatchewan, what we love about Saskatchewan is it’s a little bit longer stage of its life cycle. It’s now shifted really into that EOR phase and whether it’s the water-flood or the polymer floods, we continue to advance that. And things on that front have looked good. It’s just a nice low-decline excess cash flow asset that pairs well with the short cycles that we have. And so with that in mind, we do have a little bit of a drilling program going on out there now.

And we bob and weave between — somewhere between 1 and, call it, 3-ish drilling rigs not only throughout the year but also throughout the 5-year plan. And some of that is just the timing of breakup, where you’re familiar with those — they’re generally single well pads. It’s not like you can get on a big pad and run through breakup. So Saskatchewan as a whole has been performing really well. And I think far aside from polymer and the water-floods, the other thing that we’ve been doing is the open-hole multilaterals and mainly in the Butte Field area, and that’s been exciting for us. So it’s in a good, steady, consistent production base, and it’s been just a good, steady, consistent execution on that program. So no real surprises there, Luke.

Operator: Thank you. And there are no further questions on the line. Thank you for joining today’s Veren’s call. Veren’s Investor Relations department can be reached at 1-855-767-6923. Thank you, and have a good day.