Granite Ridge Resources, Inc (NYSE:GRNT) Q4 2024 Earnings Call Transcript

Granite Ridge Resources, Inc (NYSE:GRNT) Q4 2024 Earnings Call Transcript March 7, 2025

Operator: Good morning, and welcome everyone to Granite Ridge Resources Fourth Quarter and Full Year 2024 Earnings Conference Call. Currently, all participants are in listen-only mode. A question and answer session will follow the formal presentation. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. I will now turn the call over to James Masters, Investor Relations Representative for Granite Ridge.

James Masters: Thank you, operator. Good morning, everyone. We appreciate your interest in Granite Ridge Resources. We will begin our call with comments from Luke Brandenberg, our President and Chief Executive Officer, who will review company strategy, discuss 2024 results, and provide an outlook for 2025. We will then turn the call over to Tyler Farquharson, our Chief Financial Officer, who will review our financial results in greater detail. Luke will then return to provide some closing comments before we open the call up for questions. Today’s conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements.

We would ask that you also review the cautionary statement in our earnings release. Granite Ridge disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday’s press release and our filings with the Securities and Exchange Commission. This conference call also includes references to certain non-GAAP financial measures. Information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures is available in our earnings release that is posted on our website. Finally, as a reminder, this conference call is being recorded.

A replay and transcript will be made available on our website following today’s call. With that, I’ll now turn the call over to Luke.

Luke Brandenberg: Thank you, James, and good morning, everyone. I appreciate you joining us today. This is an exciting call for us at Granite Ridge. Our fourth quarter 2024 results exceeded our expectations and contributed to a strong full year 2024. I look forward to discussing that in more detail shortly. Even more exciting than our accomplishments in 2024 are our plans for 2025. Since going public, we’ve been laying the groundwork for the significant progress we anticipate this year. We have an exceptional team of professionals and partners in place. Now is the time to execute. As this is a year-end call, I will begin with an update on the Granite Ridge business and why we believe it offers a unique value proposition within the oil and gas sector.

Q&A Session

Next, I will share the results of the capital we’ve invested in operated partnerships, which is rapidly transforming the company into one that controls its capital expenditures and cash flow timing, similar to an operator. Finally, I will highlight the results we have achieved this year and outline what you can expect from us in 2025 before turning the call over to Tyler for the details. Going public in 2022, we have been viewed as a non-operated oil and gas company. However, our roots go back to 2014 as an oil and gas private equity firm, and our business model has always represented a blend of both non-control and controlled. We are less an oil and gas company than we are a publicly traded private equity firm, with career oil and gas investors and a technical team applying an investment-driven approach to oil and gas development.

Over the past decade, we built interest in over 3,100 wells across six of the premier unconventional basins in the United States. We offer our investors a diversified portfolio targeting best-in-class full-cycle returns by investing in oil and gas projects with proven public and private operators. The opportunity set has evolved in the past few years, and Granite Ridge is doing what we do best, identifying dislocations in the market. In 2014, non-operated inventory with near-term development traded at a substantial discount to operated inventory, roughly 50%. By 2023, the volume of non-operated oil and gas deals had surged, but the discount began to compress as mineral buyers expanded into non-operated interests and family offices increased their allocations, often seeking the tax benefits associated with oil and gas.

As the non-operated space became more competitive, smaller operated deals offered higher returns. This shift occurred due to an exodus of private capital, leaving a void in the market. From 2018 to 2023, private equity fundraising for US natural resources plummeted by nearly 90%. Although more robust lately, those firms that have been successful in raising capital are generally allocating larger commitments to fewer teams. Recognizing this evolution, we’re once again partnering with highly talented, proven value creators who have successfully built companies for private equity. In 2024, we’ve invested approximately $120 million in what we previously referred to as strategic partnerships and controlled capital. By partnering with proven operators, the majority working interest owner, we gained control over capital and development timing, leading to higher returns and enhancing our ability to generate shareholder value.

As our controlled investments have grown in scale and importance, we are simplifying how we describe our opportunity set to better reflect our forward-looking strategy. Going forward, our investments will fall into two categories: operated partnerships and traditional non-op. Operated partnerships are controlled investments with proven value creators in their areas of expertise where we hold the majority working interest. These deals give us full control over capital allocation, development timing, and well design, allowing us to optimize returns. Traditional non-op remains an important part of our strategy, where we own minority interests in core areas managed by experienced operators. This provides exposure to high-quality assets without the need for direct operational control.

This shift is not just about terminology; it’s about how we’re positioning Granite Ridge for the future. In 2024, just under half our capital was allocated to operated partnerships, but the success of our early investments gives us confidence to lean in further. In 2025, the strategy will account for nearly 60% of our capex. For our investors, this means more control, higher returns, and increased optionality in a competitive market. We are targeting full-cycle returns of greater than 25% and have been pleased with our results to date. To add some color, our first six projects in our operated partnership program included 38 wells, all in the Delaware Basin. We invested $148 million, and based on realized and projected cash flows at current strip pricing, we estimate a full-cycle internal rate of return of 24%, fully accounting for inventory costs as well as drilling and completion expenses.

We are currently running two rigs and have 92 gross or 42.9 net locations in hand or under definitive agreements across two operating partners in the Permian Basin. The operated partnership strategy continues to gain momentum, and we are in active discussion with several additional management teams. We have built a great mousetrap that provides public investors with private equity-like exposure and offers proven value creators a differentiated capital structure that does not rely on an exit but offers the flexibility to build a company rather than an asset to flip. As I mentioned on the last call, it is different and is working. As usual, Tyler will provide a detailed overview of the fourth quarter. I would like to highlight a few key points.

In our last call, I mentioned we expected roughly a 10% decline in gas production, offset by a modest increase in oil production. I was pleasantly surprised to be wrong, but for the right reasons. In the fourth quarter of 2024 compared to the third, gas production actually increased by 4%, complemented by a 16% increase in oil production. The primary driver of this outperformance was acceleration in our traditional non-op business, specifically chunky interests in wells operated by Newburn, EOG, and Silver Hill that came online earlier than expected. Additionally, early outperformance in a couple of our operated partnership units contributed to the beat. We are looking ahead to an exciting year for Granite Ridge, with robust production growth of 16% or 29,000 barrels of oil equivalent per day at the midpoint with an oil weighting of 52%.

This is largely driven by our Permian operated partnerships and a few high working interest Permian units in our traditional non-op business. We expect gas production to remain steady through the first three quarters, followed by an increase in the fourth quarter as about a dozen wells come online across the Haynesville, dry gas Eagle Ford, and traditional non-op Permian. Oil production is expected to decline by about 5% in the first quarter, increase slightly in the second quarter, and accelerate in the second half of the year as our second Delaware-focused operated partnership rig stood up this mid-February begins to contribute in earnest. We are guiding to a total capex range of $300 million to $320 million, with 56% allocated to Operative Partnership and the remainder to traditional non-op.

As is our norm, this range only includes deals and developments that are either in hand or under contract. Absent a significant negative change in hydrocarbon prices, we’re confident that we can fund this capital plan as well as our fixed dividend from internally generated cash flow and existing liquidity. We have a substantial amount of oil-weighted inventory in our operated partnership program, and current economics are incentivizing us to drill sooner rather than later. While honoring the conservatism towards leverage that is in our DNA, I could see a path towards an additional $60 million to $80 million in development CapEx this year. This additional CapEx would be weighted towards the fourth quarter and would likely have a negligible impact on 2025 production but would significantly contribute to early 2026.

We continue to evaluate various debt financing opportunities which we believe offer attractive options for our capital plans. We plan to continue to monitor market conditions and our strategy remains focused on non-dilutive capital to expedite the development of our existing inventory. On that note, I’ll hand it over to Tyler to provide more insights into our results.

Tyler Farquharson: Thanks, Luke, and good morning, everyone. As Luke mentioned, we are happy to report fourth quarter results that exceeded expectations. Production for the quarter was a record 27,000 BOE per day, up 10% sequentially with an increase in oil cut from 50% to 53%. For the year, total production increased to 25,000 BOE per day and finished near the high end of our guidance range. For 2025, we expect our growth trend to continue with the midpoint of our production guidance range representing a 16% annual increase. Our net loss for the fourth quarter was $11.6 million or $0.09 per diluted share. Excluding non-cash and non-recurring items, adjusted net income for the quarter was $22.7 million or $0.17 per diluted share.

Adjusted EBITDAX in the fourth quarter was $82.6 million, which was a slight increase year over year from $81.8 million and a 10% increase from the prior quarter. In 2024, we achieved adjusted EBITDAX of $290.8 million, down from $305.4 million in 2023 due to lower realized commodity prices and the impact of the best assets in December of 2023. Moving on to cost, I want to highlight our per unit lease operating expenses which have continued the trend of year-over-year improvement. In the fourth quarter, we reported per unit lease operating expense of $5.99 per BOE, which is 7% lower than the fourth quarter a year ago. We reported full-year LOE of $6.29 per BOE, an 8% improvement over 2023. The decrease in lease operating expenses is primarily due to lower gathering and transportation expenses, and decreased workover, repair, and maintenance costs versus 2023.

Production and ad valorem tax for 2024 were 6.8% of sales, a slight reduction from the prior year. Both our LOE and production tax metrics ended below the low end of our guidance, and we’ve lowered our 2025 initial cost guidance ranges to reflect our continued strong performance. Our per unit cash G&A expense was $2.09 per BOE for the quarter, down 14% from the same quarter last year. For the full year, $2.45 per BOE was 16% lower than the year before. This metric continues to improve as our business grows and highlights the scalability of our business model. Operating partners completed and placed on production 299 gross or 23.4 net wells for the year, with activity primarily focused in the Permian Basin. As of year-end, we had an additional 202 gross or 14.9 net wells in process.

In the fourth quarter, we successfully closed nearly two dozen transactions, primarily involving Utica Condensate Window Leasing, and consolidating existing operated partnership units in the Permian Basin. We invested approximately $9 million, including future drilling carries. Excluding Utica leases that are not yet unitized, we added 1.2 net locations at a cost of $2.9 million per net location. Most of these 1.2 net locations are either in the drilling phase or already online, including an in-process three-and-a-half-mile Utica condensate unit. We anticipate $12 million in future development CapEx, aligning with our typical ratio of $1 of entry capital to roughly $3 to $4 in the ground. Finally, we have consistently returned capital to shareholders, and the fourth quarter was no exception, as we paid out our regular quarterly dividend of $0.11 per share.

Subsequent to quarter-end, our board declared another $0.11 per share cash dividend payable on March 14, 2025, to shareholders of record as of February 28, 2025. I’ll now hand it back to Luke to discuss our outlook for 2025.

Luke Brandenberg: Thank you, Tyler. Granite Ridge combines the control of an experienced operator with the investment acumen of a private equity firm. We provide access to a diversified portfolio of oil and natural gas interests, situated in some of the world’s most productive basins. Our extensive proprietary data set gives us a competitive edge in selecting higher return projects, partnering with some of the industry’s most successful operators. We maintain a target leverage of less than 1.25 times net debt to adjusted EBITDAX and continuously optimize our portfolio with near-term development opportunities. Additionally, we actively manage risk through a systematic hedging strategy, protecting our investments with 90% of our current production hedged through 2026.

For 2025, we project a 15% growth in production per share, coupled with robust cash returns to shareholders through our fixed dividend, which implies a current yield of over 7.5%. Since 2023, our fixed dividend has consistently yielded between 5% and 9%, while production growth per share was over 20% in 2023 and 13% in 2024. As a management team and board, we find this performance highly compelling. As our Form 4s show, we continue to put our money where our mouth is by investing alongside our shareholders. Thank you again for joining us this morning. We are excited about the year ahead and appreciate your interest in Granite Ridge. With that, I’ll turn the call back over to the operator for questions. Operator, please open the floor for questions.

Operator: At this time, I would like to remind everyone in order to ask a question, please press star one on your telephone keypad. We will pause for just a moment to compile the Q&A roster.

Mike: Hi. Good morning, guys. I want to see if I can get a little bit more color on the contingent $60 to $80 million that, Luke, you mentioned you could spend toward the fourth quarter. I guess, what factors will really determine whether or not that gets spent? Is it strictly market conditions or something beyond that? And maybe if you could address how that might impact the first half of 2026 if that does get spent and if it doesn’t.

Luke Brandenberg: Yeah. You got it. Thanks for the question, Mike, and good morning. The way that we look at the world right now, our CapEx is pretty weighted towards the first half of 2025. Probably about two-thirds of the CapEx for the year we’re currently modeling in the first half. Really, that’s first-quarter weighted. We’re looking at first-quarter CapEx. It’s probably a third higher than what we saw in the fourth quarter. So that’s currently what we’re modeling out, but you hit the nail on the head. It’s really market-driven. We look at our inventory on the operator partnership side, and we’re excited about what the economics look like of those projects. And so if the market conditions hang in there, you know, it certainly seems some volatility on pricing lately, and I’ll hit on that in a second.

But if the market conditions hang in from a hydrocarbon price perspective, that could be pretty darn interesting. The other piece I mentioned, you know, our current capital budget we’re certain or I’d say highly confident, again, absent some material market condition change, that we can fund that out of cash flow and existing liquidity. But we’re always looking at ways to better capitalize this business for the long term. And, you know, we’re specifically focused on anti-dilutive ways. We’re always canvassing the market. We’re always talking and looking at different opportunities. And so if we were to have an opportunity to access additional liquidity in a way that was not dilutive, then we would seriously consider that. So that’s the high level.

I would say pricing is one on the market conditions that I would like to hit on. So I really appreciate you opening that door for me. Oil’s been a bit volatile lately, but we’ve certainly seen that in the past few months. The reason I want to hit that is it’s a great example of why our diversification is really a strength for us. You know, oil being a more international commodity has gotten a lot of international attention. It’s really only down about 6% year to date. We see a lot of volatility. What gets less attention is the gas side. Given that it’s just a more localized market, but gas is up about 24% year to date. And so we really want to hit that as a highlight because that’s really going to benefit us. We have a significant amount of gas production, approximately half our reserves are gas, and we feel good that we have alignment with our partners on the traditional non-op side in the gas basins that are going to put some of those wells out of sales this year.

So that’s a real long-winded way of answering your question, but the net-net is that $60 to $80 million that would be inventory in hand on our operated partnership side. We see it. We’re excited about the economics, and if market conditions are there, both on the hydrocarbon pricing side, but then also the capitalization side, then we would really look to accelerate that from what’s currently modeled in 2025 to be developed and have that CapEx hit in 2025, but the production would really start to show up in 2026.

Mike: I appreciate that detail. And if that does get spent, it’s fair to assume that the momentum continues to grow in the, you know, first half of 2026.

Luke Brandenberg: Yes, sir. You nailed it. I don’t think that would have a lot of impact on 2025 production. It may have a little bit, but it will be negligible. It would really help to continue the growth profile that we’re showing into 2026.

Mike: Got it. And then one more if I could. You mentioned the two rigs that you’re running inside the partnerships. I think you had said those are both in the Delaware. Is that correct? And if so, your thoughts on adding a rig in the Midland, what needs to be done before you could do that?

Luke Brandenberg: Yeah. That’s right. So they’re both in the Delaware Basin right now, primarily Loving County. That’s where most of the development has been to date and what’s projected right now. We do look forward to starting a drill in the Midland Basin probably middle of this year. We’ve got an asset in hand. We have another deal that we’re working on getting closed that we’re excited about. There’s a few ducks that we have to get in a row just from, like, an operational perspective, getting some other interest owners lined up. But we do hope to spud those wells middle of this year in the Northern Midland Basin as well.

Mike: Sounds good. Thanks, Luke.

Luke Brandenberg: Thank you, Mike.

Operator: Your next question comes from the line of Derek Whitfield with Texas Capital. Please go ahead.

Derek Whitfield: Good morning, Allen. Thanks for taking my questions. Also, congrats on a strong close to 2024.

Luke Brandenberg: Awesome. Thanks, Derek. Appreciate you reaching out, and thanks for picking us up. It means a lot.

Derek Whitfield: Absolutely. Well, Luke, I’ll step into the door that you open on natural gas. When you look at the environment, I mean, it’s arguably the most supportive macro environment we’ve seen in well over a decade. But very few are seemingly leaning into it. How are you thinking about the opportunity for both the controlled capital and traditional non-op basis?

Luke Brandenberg: Yeah. Thanks for asking that. You know, we don’t currently have any just pure natural gas-focused partners on the operated partnership side. We’ve explored some opportunities there, and we will continue to. We don’t have any right now. A couple of points, though, I would say that we look forward to benefiting from a lot of our Delaware production is pretty darn gassy, and so we are seeing a benefit there. It’s nice to get some positive realizations at Waha after some rough periods last year. But on the traditional non-op side, we do have some compelling inventory right now. We’re looking at, you know, at least a net well in process in the Haynesville. And we expect that to come online. That’s across several gross wells, but they come online probably late third quarter or early fourth quarter.

We also have some inventory in the dry gas Eagle Ford that we expect to come online probably in the third quarter. What I’m optimistic of, we’re real careful when we pick our partners on the traditional non-op side. We want to make sure that if we’re going to be in the non-op position, we want to be under folks that we have real alignment with. And there’s one group in particular that’s been a great partner to us. We know them well. They’ve got a wonderful position in the Haynesville that we were able to get a little piece of. I’m optimistic that if these prices hang in there, they’ll accelerate development there. And so there’s a scenario where we do have additional CapEx and development going to the dry gas Haynesville this year, with some of these traditional non-op groups that are, let’s say, quick to adapt.

So we’re excited about that. You know, if I look at the Haynesville, we have, you know, probably 16, a little more than that, net locations that could be developed. Again, we’re only looking at a little over one on the back half of this year, but I would love to see that number accelerate.

Derek Whitfield: Terrific. And then referencing your deal sourcing funnel on slide nine, are there any generalizations you can offer on the deals won or lost other than price? And if you could also add maybe where you’re seeing the greatest opportunities in the marketplace.

Luke Brandenberg: Yeah. So it’s funny on gas. Just to stay on that topic, gas deals, we’ve seen a lot of. If you look at 2014, we saw a lot of gas-weighted deals. We weren’t really competitive on them in 2014 because the fact is a lot of folks were wanting you to pay, you know, then strip pricing. It was kind of 2025 pricing that was in the fours when gas was trading, you know, more on the high twos. And then we struggled to get there. So we lost the vast majority of the gas deals that we looked at in 2024. So that was definitely a driver. Where we continue to see most opportunity, it’s in the Permian, and a lot of that’s just driven by, you know, non-op deals that are generated where the rigs are. And so that’s where we see most of the opportunity.

But, yeah, we struggle to win gas deals because we weren’t willing to, you know, pay for four-dollar gas when it was trading, you know, in the high twos or low threes. In hindsight, maybe I wish I had some of those, but that’s alright. Another place that we had actually had some success is small, but it’s in the, you know, condensate window of the Utica. Tyler mentioned that we’ve done a few deals there. It’s not necessarily large in dollar quantity, although into additional drilling that’ll make that more impactful. But it’s actually pretty high in just count. We’ve been excited about what we’ve seen there. We’ve got a great partner that we’re working with up there in the Dell Resources guys, Dale Operating. So that’s been a neat area for us.

But I’ll tell you the one neat thing is we talk about diversification. And if you look at our portfolio, I think we do have a neat diversification. That’s an output. You know, whenever we set our budget for 2025, we don’t say, hey, I want to allocate 50% of the Permian and 10% of the Haynesville. That’s not the case. We just let every deal compete on economics. But where we are intentional is, we’re intentional to make sure that our deal flow, so the 650 plus deals, that those are diversified because we want to make sure that if you see any themes and basins, that we’re quick to recognize them and that we have quick ability to move. So again, a long-winded way, I think, in answering your question, but hopefully, give you a little more color to what we’re seeing.

Derek Whitfield: Okay. Great update.

Luke Brandenberg: Alright. Thank you, Derek.

Operator: Your next question comes from the line of Noah Hungness with Bank of America. Please go ahead.

Noah Hungness: Morning, guys. For my first question, I was just I wanted to ask on your CapEx guide. Is that all D&C spend, or is there any deal or acquisition CapEx in there?

Luke Brandenberg: There’s deal and acquisition CapEx in there as well. Thanks for asking. That’s a good point. So there is a combination of those two things. It’s certainly D&C heavy, I would say. But it’s primarily D&C. If I had to break it out, Tyler, what would you say? Because there’s a little acquisition we did earlier this year that had some PDP. What would you think? Maybe I had to guess, probably three-quarters is development. You know, if I think about it, Noah, we typically say that a dollar of inventory drives three to four dollars of development. And so, you know, any quarter, that number may change. But if you look at it over the long term, I think you’re generally going to be 20, 25% inventory and, you know, 75, 80% development.

Noah Hungness: Gotcha. And then for my second question, I had noticed there was an impairment that you guys had in 4Q24. Could you just add any color on that?

Tyler Farquharson: Yeah. I think so. This is Tyler. Yeah. So that was in our Williston Basin assets. You know, we haven’t invested a lot of capital up there over the past handful of years. That’s been one of our areas that we’ve seen less deal flow and less investment opportunity. So that’s really a maturing asset, PDP heavy asset. I think, you know, we’ve had a lot of little things on some cost and other items that have just, you know, gone up as those properties mature. So that’s really what was driving that impairment is just the lack of additional CapEx investment up there. And then the maturing of those assets.

Luke Brandenberg: And, you know, if I can add something there too, and this may be a little hand wavy, but it’s the truth. One thing I want to point out there, nobody likes to see these write-downs, but that was actually a really good deal for us. So that was a deal that we bought, oh, several years back. But we basically bought it for PDP value. And so that deal has worked out for us, but it’s one of those few deals where you actually buy for PDP. And you get the inventory for, I’ll use air quotes, you know, free. And so what a lot that we wrote down in that specific instance was inventory that we booked but we didn’t necessarily pay for but we booked it. And then, you know, it was honestly marginal, which is why we didn’t have to pay a lot for it.

But that’s what ultimately drove the write-down to Tyler’s point. So again, nobody likes to see write-downs, but I would say the write-down was not the result of a bad investment decision. It was just the result of we were able to book some inventory that was probably marginal, but we got for nothing. And then, ultimately, I have to write that down. But in a higher price environment, I could come back.

Noah Hungness: Yeah. I mean, that was going to be, I think, my follow-up question if I could. Just as we’ve seen, you know, the Bakken, I feel like people would consider the boundaries of the Bakken expand. And your laterals have continued to extend. You guys have gotten more creative with your development. I mean, do you see, like, a pathway potentially where those locations that have been written off could come back into the money?

Luke Brandenberg: I do. I would say it’s probably more price-driven than it is, you know, CapEx driven in the areas that we’re at anyways. That’s a bigger piece for us if hydrocarbon prices increase and if you’re looking at $80 oil, like that, some of that does come back. The CapEx piece certainly matters. But the bigger driver for us in those areas, again, it was stuff that primarily we got without paying a lot of value for. It was more of a production buy. But, yes, I think it could come back. I don’t know that it’s ever going to. Never say never. In the near term, I don’t see it being a big growth area for us. So the land side up there, we’re just seeing fewer opportunities. Other people may be on a real small scale, but it’s been tougher for us to capture opportunities up there at a compelling price lately. So I don’t think it’ll be a growth area. But I do think there’s a scenario where that comes back if prices get a little better for us.

Noah Hungness: Appreciate the color, guys. Thanks.

Luke Brandenberg: Yeah. Thanks, Noah.

Operator: Your next question comes from the line of John Abbott with Roth Capital. Please go ahead.

John Abbott: Good morning, and congratulations on the nice results all the way around.

Luke Brandenberg: Appreciate it. Thanks, John.

John Abbott: Yeah. You were pretty confident in talking about 2025’s guidance, and as also mentioned, crude has been volatile primarily to the downside this year. In preparing your guidance, did you get the impression from many of your partners that some of their planned wells might be, quote, on the bubble or subject to being rescheduled or canceled?

Luke Brandenberg: Yeah. That’s a great question, John. So I’ll hit that from two approaches. You know, right now, if we look at our expected turn to sales for the year 2025, probably 60% of that is through the Operative Partnership Program. So on that side of the equation, we control that. Right? And so where we are right now and where prices are right now, we still think that’s an attractive economic decision to develop that. Again, this is called 60% of the turn to sale wells. You know, if prices do continue to degrade, particularly on the oil side, we could change that. That’s a neat thing about these operating partnerships. We do have control over that. Right now, it’s still good. But we are keeping a close eye on it. We’re keeping a close eye on the economics and when it makes sense to drill.

Or if it makes sense just to slow down the pace. That’s a big piece on the non-op side. So call it 40% of the wells that we expect to turn to sales this year. You know, one thing we’re always pretty careful to do is only guide the wells where we see a real line of sight to those wells happening. And so for most of those, you know, some maybe you’ve got a permit on, but a decent number of those already, frankly, are either been spud or at least you’ve got some capital being spent, building pads, etcetera. So those, it could always change, but, you know, it’s harder to move it harder to stop and move and train. And a lot of those are already in process. So I don’t anticipate a big change. But, again, if there was a significant move, that could happen.

But right now, we feel pretty good about that $310 million. Certainly, the traditional non-op side, again, a lot of it’s moving. But the operated side, we’re going to adapt quickly if the market does continue to degrade.

John Abbott: Well, thanks very much for the additional detail. I’ll turn it back to the operator.

Luke Brandenberg: Great. Thank you, John. Have a good weekend.

Operator: Before going to the next question, again, if you would like to ask a question, press star one on your telephone keypad. Your next question comes from the line of Chris Baker with Evercore ISI. Please go ahead.

Chris Baker: Hey, guys. Hey, Mark. I wanted to go back to the Operative Partnership. You know, I think as we kind of frame up the next few years, you know, it seems like there’s a coming free cash flow inflection as those stabilize. You know, an inflection that you’re arguably not getting much of any credit for in the market. Could you just kind of frame up in the scenario where that maybe continues, you know, how should we think about the longer-term strategic direction? Are there, you know, levers to pull in terms of forcing the market’s hand a little bit or just any sort of thoughts around that longer-term outlook and what we’re likely to see as some of these initial partnerships kind of start to stabilize, that’d be great. Thanks.

Luke Brandenberg: Yeah. Thanks for the question, Chris. I appreciate it. And thanks for picking up the rebrand to Operative Partnership so quickly too. You know, on that side, what we really like about the operator partnerships is, as you mentioned, you know, if you just pick up a rig, you’re going to have this big cash flow outspend, and then eventually you get to a cash flow positive place. And so you’re really hitting the nail on the head, and we anticipate that, you know, especially with our first partnership that’s running two rigs, you know, we’re still in a cash flow outspend, but that’ll start to resolve itself, you know, in the next year or so, I anticipate. We do think that’s a big delta. One thing that just in the market, this is just a fight that we’ve had to fight since going public.

I think I’ve said it before. In fact, I know I have, but, you know, we went public in October 2022 with no debt. And we were hoping the market would reward us and, you know, cheer us for our financial discipline, and we were just met with a resounding yawn, as we say. It seems that, you know, the market is more focused on leverage than it was, you know, in the pre-COVID era certainly. But, you know, it seems like if you’re less than one and a half times levered, the market is, you know, gives you a pass. That’s not really a risk factor. So in a weird way, because the opportunity sits there and we’re excited about it, we just continue to grow, continue to add rigs, or continue to add partners. In fact, I mentioned that we’re in advanced discussions with a couple of other teams.

We’re real close with another one that’s pretty exciting. Your point is spot on as we have accelerated development, based on the opportunity set and based on the inventory we have that we’re excited about. We’ve gone to that cash flow negative piece, but that’s not going to happen forever. We actually added a slide in the investor deck that wanted to put in there because investors, I could say, alright. If you guys have an increase in debt, when do we stop? But just to show that if you look over the company’s history, at least over the past seven, eight years, you know, we’ve never been above one times levered. And part of that is just conservatism in our DNA. But as we look forward, a big part is exactly what you hit. These guys are going to outspend cash flow, and you pick up a rig, and then eventually that becomes a self-sustaining program that we’re excited about.

So our first partnership is running two rigs. Hopefully, sometime next year, that gets to being, you know, about cash flow positive. To be totally transparent though, you know, we’re going to pick up a rig hopefully middle of this year with our second partner. We have a third partner we’re really fired up about. They wouldn’t be drilling anytime soon, maybe late this year, but they’ll be in that cash to outspend as well. But the goal is to get those guys cash flow positive. You’re living within cash flow. They can actually put a positive print on a, you know, free cash flow basis. It’s definitely kind of anything else we can hit there for you, Chris? I really appreciate the question. And you dialing in.

Chris Baker: Oh, sorry, guys. I was on mute. Thanks for the answer. Super helpful. Congrats on the quarter.

Luke Brandenberg: Hey. Thank you, Chris. Have a great weekend.

Operator: You too. Ladies and gentlemen, that concludes today’s call. Thank you all for joining. You may now disconnect.