Granite Ridge Resources, Inc (NYSE:GRNT) Q1 2025 Earnings Call Transcript

Granite Ridge Resources, Inc (NYSE:GRNT) Q1 2025 Earnings Call Transcript May 9, 2025

Operator: Good morning, and welcome to the Granite Ridge Resources First Quarter 2025 Earnings Conference Call. Currently, all participants are in a listen-only mode. After the question and answer session, will follow the formal presentation. To ask a question, simply press star followed by the number one on your telephone keypad. To withdraw your question, I will now turn the call over to James Masters, Investor Relations representative for Granite Ridge.

James Masters: Thank you, operator, and 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 the quarter’s results and company strategy. 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 Resources 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 will now turn the call over to Luke.

Luke Brandenberg: Thank you, James. Thank you all for joining us today. This morning, I plan to cover the key highlights from the first quarter, discuss the recent market volatility, and review our current 2025 budget, along with the flexibility we have within it. I will then share thoughts on the outlook for the rest of 2025 before passing it over to Tyler. Kicking off with the quarter, I’m pleased to share that Granite Ridge Resources had an outstanding first quarter in 2025. We achieved a production rate of over 29,000 barrels of oil equivalent per day, reflecting a 23% increase compared to the same period last year. Additionally, we generated $91 million of adjusted EBITDAX, surpassing our internal projections. These impressive results highlight the success of our strategic focus on geographic and hydrocarbon diversity, currently a balanced fifty-fifty split between oil and gas, and our partnership with top-tier operators.

Our outperformance in the first quarter was primarily driven by traditional non-op wells that came online earlier than anticipated or outperformed their expected type curves throughout the quarter. A standout performer continues to be our operated partnership program, where we are excited to see substantial growth in volumes over the past year. Our partner in the Delaware Basin has increased gross daily operated oil by 400%, from 2,500 barrels of oil per day to approximately 10,000 barrels of oil per day with interest in over 50 producing wells. For every dollar we invest in this business, we are targeting full cycle returns of greater than 25%, and we are pleased that the results to date align with those expectations. For the quarter, we turned 13.7 net wells to sales, increased oil volumes by 39%, and natural gas volumes by 10%, with robust initial production from new wells primarily in the Permian Basin.

One area I am particularly proud of is our cost structure, which continues to improve on a per-unit basis as we scale the business. As the denominator grows, our efficiency improves. In the first quarter, we reported LOE of $6.17 per BOE, 13% lower than last year. On an operating margin basis, we improved from 83% in the first quarter of last year to 87% this year. These are not one-time savings. They’re repeatable cost structure improvements thanks to increased scale, that will continue to drive enhanced cash flow and shareholder returns. Turning to the macro environment, while volatility has been a prevailing theme lately, Granite Ridge Resources remains well-positioned with a diversified asset base. Our production is approximately 75% hedged through 2026, and we maintain a leverage ratio of just 0.7x net debt to adjusted EBITDA.

This combination preserves our expected cash flows and provides significant optionality as we look to capitalize on opportunities in this environment. Our diversification, in particular, proves incredibly valuable during times of volatility. After two years in the doldrums, it is great to see the macro picture improve for natural gas, and we are pleased with both the production and operating margin growth of our natural gas assets. Year over year, while gas volumes grew by 10%, our revenue from gas more than doubled to $31 million thanks to realized prices of $3.97 per mcf compared to just $1.84 per mcf a year ago. We continue to evaluate opportunities to accelerate capital deployment in response to today’s improved gas pricing, particularly in the Haynesville and dry gas Eagle Ford.

Moving to our 2025 budget, during our last call, I mentioned the possibility of an accelerated CapEx scenario of approximately $380 million. However, due to recent market volatility, we’ve decided to proceed with our base case of $310 million. This approach is projected to achieve a 16% production growth at the midpoint. Let’s take a quick look at our sources and uses for 2025. Using round numbers, the uses include a $300 million budget for CapEx, about $60 million for dividends, and $25 million for interest and other costs, totaling $395 million. On the sources side, while production growth does not directly translate to cash flow, with gas prices up, oil prices down, and hedges in place, it serves as a reasonable proxy. Starting with $291 million of 2024 EBITDA and applying a 16% increase at the production guidance midpoint, we estimate about $335 million.

This leaves us with $60 million in incremental debt. I walked through this for a couple of reasons. First, to assist those of you who model Granite Ridge Resources. We appreciate you. Second, to highlight in the current hydrocarbon price environment, our plan puts us roughly cash flow neutral excluding the dividend. I recognize that excluding the dividend is a lightning rod for some. In this environment, where oil and gas stocks trade more like assets from businesses, people often take the negative and criticize us for borrowing to pay the dividend. I would like to offer a different perspective. We believe we can fund our dividend and achieve mid to high single-digit production growth out of cash flow. As we continue to find accretive opportunities even in this price environment, we are taking on conservative leverage to generate mid-teens production growth and accelerate cash flows.

As we consider budget flexibility, our focus on full cycle returns and efficient operating cost management has enabled us to maintain a low leverage profile while achieving significant asset growth. In the face of an uncertain market, these priorities remain crucial. We are confident in our assets and balance sheet’s ability to withstand fluctuations in hydrocarbon prices, and our capital program is designed to adapt to various price scenarios. Like our peers in the oil and gas industry, we’re closely monitoring hydrocarbon prices and will continue to adjust our budget accordingly if oil remains below $60 per barrel. As recently as this week, we have non-consented well proposals that do not meet our return threshold and identified approximately $30 million in CapEx within our operated partnerships that we can swiftly cut or defer with additional flexibility if market conditions require.

Our guiding principle for capital allocation remains a focus on full cycle returns combined with conservative leverage. Production growth is merely a result of this strategy. With estimated maintenance capital accounting for less than two-thirds of our 2025 budget, we have substantial flexibility to make decisions that enhance long-term shareholder value. To review, we’ve had an outstanding quarter with performance exceeding expectations across the board. Our balance sheet remains in great shape at just 0.7 times leverage, and our hedging program is solid, covering roughly 75% of current production through 2026. We are growing responsibly with increased margins and a lower capital reinvestment rate than ever before. Strategically, where are we?

After a decade of building a significant non-op portfolio, with diversified interest across six premier oil and gas basins in the United States, our current focus on operated partnerships brings balance to the portfolio. This focus adds control over the timing of CapEx and cash flows while partnering with some of the highest quality operating teams in the country. We have built Granite Ridge Resources on the principles of diversification and strict underwriting standards to generate steady returns for our shareholders. Our approach remains rooted in capital stewardship, with disciplined allocation following close behind. Over the past two and a half years as a public company, we have ensured that our intent to grow and add scale has not come at the expense of financial prudence.

I’m proud of our efforts. The growth we have experienced is due to sound capital allocation strategies always with good rocks and outstanding partners. Looking ahead to the rest of 2025, we are focused on three key priorities. First, developing our operated partnership program. We currently have two operating partners and have agreed to terms with a third, all targeting the Permian Basin. Earlier this year, we were running two rigs in the Delaware Basin, but have since scaled back to one rig. We are pleased with the results we have achieved so far and maintain total control and flexibility to adjust the program according to the hydrocarbon environment. This program will account for about 60% of our capital this year, up from 50% in 2024. Second, maintaining a careful balance between growth and returns.

We continue to guide to a 16% production growth while maintaining our $0.11 per share quarterly dividend, which at current prices offers almost a 9% dividend yield. And finally, preserving our financial flexibility. With the support of our banking partners, we successfully increased our borrowing base in April by $50 million to $375 million, providing enhanced pro forma liquidity of $141 million as of March 31. Leverage stands at just 0.7x net debt to EBITDAX. This conservative approach has served us well through multiple cycles. With that, let me turn it over to Tyler to walk through the numbers in more detail. Tyler?

Tyler Farquharson: Thanks, Luke, and good morning, everyone. I’ll begin with an overview of our income statement. We generated $122.9 million in total revenue this quarter, that’s up nearly $34 million from the same period last year, with realized prices of $69.18 per barrel and $3.97 per Mcf. Our adjusted net income was $28.9 million, or 22¢ per share, an 89% increase year over year. That strong performance translated into $86.7 million of operating cash flow before working capital changes. On costs, I want to highlight two items. First, as Luke mentioned, reduced LOE to $6.17 per BOE. Second, G&A came in at $2.94 per BOE, down 5% from last year as we continue to benefit from scale. Turning to capital allocation, we invested $71 million in drilling and completions capital with the majority directed toward our Permian operated partnerships.

In addition, we deployed $34 million on acquisitions securing 12 net high-quality locations at an average cost of $2.1 million each. Total capital for the quarter was $101 million compared to consensus expectations of $87 million. The difference primarily reflects the timing of a $14 million opportunistic acquisition completed during the quarter, reflecting our ability to remain flexible and capitalize on attractive assets when they arise. Our balance sheet remains a real strength. We ended the quarter with $250 million of debt outstanding, just 0.7 net debt to EBITDAX, and with our recent borrowing base increase, we now have $140.8 million in total liquidity which positions us well to capitalize on future opportunities. Our hedge book also provides significant protection.

For oil in 2025, we have 2.4 million barrels hedged with floors at $61.86 and ceilings at $77.89. On the gas side, we protected 7.3 BCF at floors of $3.43, and ceilings of $4.23 and have swapped an additional eight BCF at $3.67. These hedges lock in substantial cash flow through 2025. Based on this strong start to the year, we’re reaffirming all aspects of our 2025 guidance. We continue to expect production between 58,000 BOE per day with oil making up 52% of volumes. On costs, we’re now tracking toward the low end of our LOE guidance range of $6.25 to $7.25 per BOE. Looking ahead, we anticipate Q2 production will remain consistent with Q1 levels followed by a modest increase in the second half of the year. Capital spending in Q2 is expected to be broadly in line with Q1 levels, with a more measured pace of investment planned for the second half as we maintain our focus on capital efficiency.

Back to you, Luke.

Luke Brandenberg: Thank you, Tyler. I have the privilege of working daily with some of the most talented, driven, and creative professionals in the industry. My partners built this business from the ground up, and over the past dozen years, we have established a remarkable track record of consistently achieving the goals that great oil and gas companies strive for. We have prudently allocated capital to grow asset value, while maintaining conservative leverage, continuously reduced our cost structure, and replaced and increased inventory with an intense focus on quality. Our commitment to delivering value for shareholders is evident through both cash returns and asset appreciation. Our journey has not been without challenges, as we have navigated several significant downturns.

However, through discipline, teamwork, and an unwavering focus on our investors, we have continually demonstrated our ability to adapt and drive value across cycles. While macroeconomic conditions may fluctuate, our commitment remains steadfast. We focus on what we can control, building a resilient business capable of adapting to any environment, and maintaining a laser focus on delivering returns for our investors. Over the long term, the market will ultimately reward consistent earnings. We invite you to join us on this journey. With that, operator, please open the line for questions.

Q&A Session

Operator: At this time, I would like to remind everyone, if you would like to ask a question, simply press star followed by the number one on your telephone keypad and we will pause for just a moment to compile the roster. Our first question comes from the line of Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston: Hey, guys. Thanks for the time. Can you maybe give us some color as to how much production came in the door from the 10 acquisitions that you closed in Q1? And maybe what the split is in terms of Delaware versus Utica and what the oil and gas mix kinda looks like.

Luke Brandenberg: Yeah. You got it. Good morning, Phillips. That acquisition, so we closed that earlier this year. We think it’s about 450 barrels for the year. Twenty-five. You know? $9 million if I had to put a number to it, but about 450 is how I would look at it. That’s all Delaware production. In fact, that asset acquisition that Tyler mentioned, that was the only thing that we bought that had any production associated with it.

Phillips Johnston: Okay. And was there any material contribution to Q1 volumes, or was the close kinda late in the quarter and it’s kind of Q2 through Q4 impact?

Luke Brandenberg: Yeah. I call it the latter. It was later in the quarter, and so I think you’ll see that show later. Not necessarily much of an impact in Q1.

Phillips Johnston: Perfect. Tyler, I touched on LOE in your prepared comments. Nice to see Q1 was below the low end of the range. It sounded like we should be steering towards the low end of the range for the year. Is that what I heard?

Tyler Farquharson: Yeah. Correct. Morning, Phillips. Yeah. As production is starting to scale on those operating partnerships, we’re starting to see those LOE per unit move down towards the lower end of our guidance. So that’s our current expectation is to be at that low end.

Phillips Johnston: Okay. Great. Thanks, guys.

Luke Brandenberg: Awesome. Thank you, Phillips. Have a good weekend.

Phillips Johnston: You too.

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

John Abbott: For my first one, maybe following up on your prepared remarks on the strong well performance from your non-op wells. Can you elaborate on which specific basins are outperforming? And are there any factors that you would attribute this outperformance to?

Luke Brandenberg: Yeah. Hey. Good morning, Johnny. Great question. I appreciate that. Probably should have given some more color on that in the prepared remarks. So if I think about really, our, you know, quote, beat compared to internal I’d group into two buckets. So one is from acceleration, so wells that came on sooner than we thought. And then the existing wells that outperformed. And so I’ll hit each of those separate. Acceleration was probably a third of the beat. You know, that’s just one of those games where on the traditional non-op space, we don’t know exactly when those are gonna come online. And so we’re generally a bit conservative on it, and we like to be pleasantly surprised. So the wells that I’d say really had an impact was one pad in particular in the Delaware Basin.

That came online sooner than we thought, and that made a big impact. We had a couple pads in the Utica. And see no operator pads that came online earlier, and we’ve been real pleased with what those guys are doing up there. And then, you know, cats and dogs here and there. Just small working interest in the DJ in Midland Basin that were a bit sooner than we thought. So that’s called a third of it. The other two-thirds was really existing wells. And so this is one as well where I love how we underwrite. We’ve got a great team over here on the underwriting side. And they take a very practical approach to these. And so one thing that we saw on some existing wells, are some wells that were shut in for offset frac. And so, again, we don’t really benefit by being aggressive on when they come back online.

We like to see a bit conservative. And so we had some wells come online sooner than we thought. That had a pretty significant contribution. The biggest point that I’ll mention that I’m encouraged about, now we’ll see how this changes in the current market environment, but we had a pretty big pad for us in the Delaware Basin. That had been constricted, primarily because of gas prices late last year. And as gas prices ramp, it’s a, again, a Delaware pad, but it has a strong gas contribution. They started opening the chokes a little bit as prices improved. Not just at Hub, but also at Waha. And so we had some increased production as they increased the chokes and bumped production a bit. I’m curious to see if that continues now that the oil prices have been a little bit tougher over the past month or so.

But I think that was certainly exciting to see at the time. And, we’ll see if that trend continues.

John Abbott: Terrific. I appreciate all that color. For my maybe leaning into your comments on natural gas, how do you evaluate the relative attractiveness of each basin just given the softening in oil and strengthening in gas? And does this dynamic change your appetite for increasing or decreasing exposure in certain basins either from a non-op or operated partnership basis?

Luke Brandenberg: Yeah. That’s a great question too because look, you’re talking capital allocation. At the end of the day, and that’s our primary role is capital allocation. What we always say is that every opportunity has to compete for capital, so we’re in six basins. Deals in each of the six basins have to compete. It’s, you know, as we know, oil, you know, wells aren’t just oil or just gas in a lot of places. They certainly are. And say, the Haynesville or South Texas Eagle Ford. But take the Delaware Basin. You know, that’s been such an interesting one where oil prices have come down, but gas has come up. And so we have to look at just a full cycle basis across both hydrocarbons. So what really it’s led us to do right now on our traditional non-op side, we have some inventory in some gas-weighted basins, primarily the Haynesville and dry gas Eagle Ford.

A lot of the operators we’re talking to there are either looking at wells that have been duct. Some cases for a year or more, that they’re looking to turn online. Some have at least hinted that they may accelerate development on some of those. You know, in that case, it’s less of us making a decision. It’s more of the wealth proposal comes in, and we determine if we’re gonna participate, but we continue to make that compete for capital. I really like the diversification we have. In these environments. I just think that’s a big one. And with 50% gas production, we really are seeing the benefit of that right now. In spite of challenges on the oil side. So I’m not really hitting your questions head-on, John, and it’s not intentional. I’m not trying to evade it.

It’s more of everything competes for capital. We see what comes in the door. As I mentioned, you know, we had wells just this week that we were non-consenting because they didn’t hit the return hurdle. So we’re going to stay disciplined and we’ll see where it goes. Our operator partnerships are all currently in the Permian. And so they’re that blend of oil and gas. We don’t have any in like, pure gas basin that we can really push right now. But we got some great partners, and we’re excited to see what they do this year.

John Abbott: Makes sense. Thanks, guys.

Luke Brandenberg: Hey. Thank you. Hope you have a good weekend.

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

Noah Hungness: Morning, Noah. You may be muted. I can’t hear you if you’re talking.

Noah Hungness: Oh, can you hear me now?

Luke Brandenberg: I can hear you now.

Noah Hungness: Okay. Sorry about that. Could you give us an idea of how we should think about oil cut kind of trending through the rest of the year? Just kinda noting maybe 1Q was a little lower than what we were expecting.

Luke Brandenberg: Yeah. It’s a good question. I’d say that, we were actually just talking about that this morning. You know, it’s a dynamic where we’re basically in line with what we thought. On oil production, but gas production was higher than we thought. And so you end up in the scenario where, you know, oil cut is a bit lower, but it you know, oil production was darn near spot on, and gas was just higher. So gas outperformed. This is one we battle a lot, Noah, and I’m glad you hit on it because as these wells get older, right, they get gassier. GOR is increasing, but it’s challenging to make a curve on an increasing GOR, you know, what you really wanna assume. And so generally speaking, I found that we’ve been pretty darn consistent on oil.

And slightly outperform on the gas side just due to that rising GOR. So right now, we’re leaving guidance intact at the 51 to 53. I think that if we were to quote miss, I would say that it’s a miss because gas production was better than we thought. So a weird way, it’s a positive miss. But that’s one that we a lot of these wells, especially the entire working interest wells, and some of these wells in deeper zones. Right? We’re drilling some Wolfcamp B and C’s, that have a higher gas content as they continue to outperform makes it a bit tougher to model the gas side. But we view that oddly as a positive given that oil production was pretty darn close. And gas production was just a beat.

Noah Hungness: Yeah. No. That’s very helpful color. And then for my second question, how can we think about the or maybe you could add a little bit of color around the non-op versus partnership capital split. I think you guys are allocating more capital to the partnership. Could you maybe talk about the moving parts there and your decision behind that?

Luke Brandenberg: Yeah. You got it. So right now, I think our operated partnership capital will be roughly 60% of our total CapEx for the year. And the neat thing is we have full control over that. And so we have the ability to defer some of that if the price environment doesn’t make sense. A really neat thing about that model is we have some great partners that we’re just absolutely thrilled to have. They mean a lot to us. And we’ve created structures that we really are aligned there. And so this isn’t a, you know, us dictating down from an ivory tower. We gotta cut back. It’s a conversation, and we’ve created real financial alignment there. So while it’s 60% of the capital, that’s an easy one to move. And we can do that. Fortunately, we are aligned with our partners in that case.

You know, the traditional non-op side is we have a well-by-well election. Right? We can always elect not to participate in a well. But we have less control over driving activity there. But, again, we non-consented some wells this year that just didn’t hit the return hurdle. So the sixty-forty is, I’d say, more of an output than an input. In the sense that we didn’t start the year saying, I wanna allocate 60% of capital to operate a partnership. We just let the deals compete for capital. And we’ve really been pleased with what we’ve been able to capture on the operated partnership side. Again, we’ve got just some just great groups that are continuing to surprise us, in what they’re able to capture. And, you know, even in this environment, we are continuing to find accretive opportunities.

Now you know, there may not be it may not be as easy to find, but we’ve been in Midland for over a decade with capital. Right? There are deals that we see that I’m confident that, you know, the whole world doesn’t see. It may not be the only one, but one of the small few, which demonstrated that we’re a trustworthy counterparty. And so that adds value on both the operated partnership side and the traditional non-op side. So again, similar to John’s question, I’m not sure that I hit it dead on because it is more of an output than an input. But we do have full control over both. I mentioned in the prepared remarks that we will we’re watching hydrocarbon prices like a hawk. And, you know, we are quick to say, hey. We need to slow down CapEx or quick say, hey.

We’re not gonna participate in that. It may be a burden in the hand, but it’s not returning, you know, meeting our return thresholds. And we’re gonna lay off on that for now.

Noah Hungness: Oh, that all makes sense. Good stuff, guys. Thank you.

Luke Brandenberg: Thank you, Noah. Have a good one.

Operator: And our final question comes from the line of Michael Scialla with Stephens. Please go ahead.

Michael Scialla: It’s okay, Tyler. Wanna see if you could talk a little bit more on the partnership wells, how those are performing. And you said you scaled back to one rig. Is that the plan for the remainder of the year? And maybe just in terms of production, you talked about the 10,000 BOE a day of gross production from the partnership. Where do you see that going for the remainder of the year?

Luke Brandenberg: Yeah. Good question, Mike. You know, that’s the biggest piece of what we’re doing. So I’m glad you asked about it. I’ll hit those and maybe varying orders. You know, on the production side, you know, the 10,000 is a gross number. I’d say we expect our operator partnerships to be roughly a quarter of our production this year. Right now, it’s probably a bit less than that as they’re continuing to grow. But I think about a quarter for the year where production will be from our operated partners. As I think about well performance, we continue to be really pleased with what we’re seeing. I’ll tell you one of the most impressive things is just the DNC side of things. They continue to do an incredible job executing.

I think that’s something that is often misunderstood. And I’m glad you asked because it gives me a chance to hit it. You know, the DNC side of things and the drilling days that we’re seeing, I mean, they’re competitive with the best operators in the basin. I think there’s a view out there potentially that smaller operator, you know, smaller scale is just gonna cost a lot more. And that’s just not necessarily true. We’ve continued to hang with some of the best operators in the basin in terms of performance. You know, in an inflationary environment, sure. You’re gonna pay more for pipe and that sort of thing if you don’t have a yard full of it. But, fortunately, in the relatively stable price environment we’ve seen over the past six, twelve months, we’ve really done a great job on the DNC side.

Continuing to beat expectations. On the performance side, prices are always a play, but productivity has been good. While oil prices have been less than they were when we drilled these wells or made the decision to drill, the gas prices have really helped, so that’s keeping the return intact. We talked on the last call. I think we looked at our first five projects with these guys. And, you know, we’re targeting a 25% rate of return. We were, you know, right about that 24% rate of return as of the last call. They continue to execute, and we continue to want to deploy capital now. As I did mention, we are watching the markets like a hawk, and we will be quick to react. That was a part of the going from, you know, two rigs to one. It’s just a conversation of hey.

Should we be thoughtful? Should we maybe defer some of this inventory? We’re having conversations about where we should duck wells waiting for a better price environment. What did I miss? You had a couple of good pieces in there. I want to make sure I hit them all.

Michael Scialla: I think you got them all. Appreciate that. I want to follow-up on the other part of the Midland Basin partnership. I think you had been kinda back and forth on whether to start drilling that around midyear. I guess, where does that stand now? You and maybe some of the industry results up in that part of the Midland Basin, how those are impacting maybe your plans there and is that impacting the ability to add acreage in that area as well?

Luke Brandenberg: I’m laughing because you hit the nail on the head with that one. The price of poker is going up as the results in the Northern Midland Basin, you know, it seems like every month oil and gas investor has another article about strong results up there, which is great. We’d love to see it. It doesn’t necessarily help on the ability to capture additional inventory side. But I think all in, we’d be we’re happy to see that. But from our operating perspective, we’re still looking at probably this summer starting now. I’d say that’s a real-time conversation based on what we’ve seen over the past month. But the plan has been, you know, this summer, to start development. We’re looking at essentially a four-well pad up there.

It’s a smaller working interest initially based on our deal that we structured. But that’s the plan that we’re looking at now. But that is one of the easiest to defer. And so in a scenario where we decide, hey. If it makes sense, it’d be more prudent to hold off on this. That’s an easy one to look at is Northern Midland Basin project.

Michael Scialla: Got it. Appreciate it, Luke.

Luke Brandenberg: Absolutely. Thank you.

Operator: This concludes today’s conference call. Thank you all for joining. You may now disconnect.