Gulfport Energy Corporation (NYSE:GPOR) Q3 2025 Earnings Call Transcript

Gulfport Energy Corporation (NYSE:GPOR) Q3 2025 Earnings Call Transcript November 6, 2025

Operator: Greetings, and welcome to the Gulfport Energy Corporation Third Quarter 2025 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce Jessica Antle, Vice President of Investor Relations. Please go ahead.

Jessica Wills: Thank you, and good morning. Welcome to Gulfport Energy’s Third Quarter 2025 Earnings Conference Call. I am Jessica Antle, Vice President of Investor Relations. Speakers on today’s call include John Reinhart, President and Chief Executive Officer; Michael Hodges, Executive Vice President and Chief Financial Officer. In addition, Matthew Rucker, Executive Vice President and Chief Operating Officer, will be available for the Q&A portion of today’s call. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, plans, objectives, future performance and business. We caution you that these actual results could differ materially from those that are indicated in the forward-looking statements due to a variety of factors.

Information concerning these factors can be found in the company’s filings with the SEC. In addition, we may reference non-GAAP measures. Reconciliations to the comparable GAAP measures will be posted on our website. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. At this time, I would like to turn the call over to John Reinhart, President and CEO.

John Reinhart: Thank you, Jessica, and thank you for joining our call today. Last night, we announced meaningful progress on key inventory additions that strengthen the company’s core asset value and support sustainable long-term value creation for shareholders. Since 2023, we have consistently communicated our commitment to adding high-quality, low breakeven locations. And during the third quarter, we made meaningful strides in expanding our drillable inventory. First, driven by Gulfport’s development and recent peer activity, resource viability of the Ohio Marcellus has expanded to the north, demonstrating the significant incremental value in Gulfport’s inventory portfolio overlying our existing Ohio Utica development in Northern Belmont and Southern Jefferson County.

These high-quality locations are being added to the existing portfolio at no incremental land cost, effectively doubling our net drillable Marcellus inventory in Ohio. Second, the successful appraisal drilling of our first 2 U-development wells in the Utica validates the feasibility of U-development across our acreage position, adding economic low breakeven inventory on otherwise underutilized acreage, which previously only accommodated subeconomic short lateral development. Third, we have continued our disciplined discretionary acreage acquisitions into the third quarter and since mid-2023 have invested over $100 million towards high-quality, low breakeven locations that enhance optionality across our portfolio. Collectively, these initiatives have increased our gross undeveloped inventory by more than 40% since year-end 2022, and we now estimate Gulfport holds approximately 700 gross locations across our asset base.

These inventory additions facilitate substantial fundamental value enhancements for the company by increasing our net economic inventory by approximately 3 years and brings our total net inventory to roughly 15 years, with peer-leading breakevens below $2.50 per MMBtu. Finally, we also achieved a significant milestone on the financial front during the quarter by completing the redemption of our preferred equity. This transaction simplified our capital structure and complements our ongoing equity repurchase program. Inclusive of the preferred redemption as of September 30th, Gulfport has returned $785 million to shareholders since March 2022, and we intend to continue to opportunistically repurchase our undervalued common stock, announcing plans to allocate an incremental $125 million towards repurchases during the fourth quarter of 2025, all while maintaining an attractive leverage ratio forecasted to be at or below 1x at year-end 2025.

Moving to our third quarter results. Our average daily production totaled 1.12 billion cubic feet equivalent per day, an increase of 11% over the second quarter of 2025 and keeping us on track to deliver full year production of approximately 1.04 billion cubic feet equivalent per day, which includes unplanned third-party midstream occurrences that were previously disclosed alongside our second quarter results in August. On the capital front, we remain committed to allocating capital to the highest value opportunities across our asset base. We announced 2 targeted initiatives where we plan to invest incremental discretionary capital expenditures during 2025. First, as part of our technical team’s ongoing focus to optimize development and unlock additional value within our existing portfolio, we have elected to invest approximately $30 million towards discretionary appraisal development during 2025.

This program predominantly targets the drilling and completion of our first 2 U-development wells in the Utica, which, as mentioned, were recently successfully drilled and are scheduled for completion late in the fourth quarter. These wells validate the technical feasibility of U-development across our acreage and enable us to optimally develop areas of our acreage footprint that were either not prioritized for future development due to acreage configuration or only contemplated for shorter lateral development that did not clear our current economic hurdles. This discretionary investment allowed us to unlock roughly 20 gross locations, nearly 1 year of high-quality dry gas inventory and enhances our long-term development optionality. In addition, our team identified and executed several other appraisal opportunities during the second and third quarters of 2025, including DUC completions of laterals that were drilled several years ago, infilling 2,000-foot spaced laterals as well as refrac opportunities from under stimulated wells in the Utica.

These activities were designed to supplement base production with limited incremental capital, and we will assess performance from these initiatives and apply the learnings to pursue additional value-enhancing opportunities that may exist elsewhere in the company’s portfolio. Second, in response to known forecasted production impacts from simultaneous operations of an offsetting operator as well as planned third-party midstream maintenance production downtime in the first quarter of 2026, we are planning to invest approximately $35 million towards discretionary development activity during 2025. This proactive spend is expected to mitigate the forecasted upcoming production impact and position the company to deliver offsetting volumes into a favorably — into a favorable economic commodity price environment.

While we continue to optimize our 2026 development program amongst our attractive development areas and plan to announce our formal capital and production guidance in February, the discretionary capital investments made in 2025 will benefit the 2026 program. Along with these incremental capital investments, the company reiterates our commitment to return capital to shareholders through our ongoing common share repurchases. And this incremental capital spending will not reduce the amount we previously planned to allocate towards share buybacks during 2025. In total, we expect to allocate approximately $325 million to common stock repurchases during the year, while maintaining financial leverage at or below an attractive 1x. On the land front, through September 30, 2025, we have invested roughly $23.4 million on maintenance, leasehold and land investment, focused on bolstering our near-term drilling programs with increases of working interest and lateral footage in units we plan to drill near term.

In addition, we continue to pursue discretionary acreage acquisitions, primarily in the dry gas and wet gas windows of the Utica, and we have invested approximately $15.7 million during the first 9 months of 2025. We reiterate our plans and remain on track to allocate $75 million to $100 million in total before the end of the first quarter of 2026 and currently forecast approximately $60 million of cumulative spend by year-end 2025. Upon successful completion of our planned expenditures, this is planned to add over 2 years of core drilling inventory, further bolstering our undeveloped well counts and development optionality beyond the additions we announced earlier today. Specific to our Marcellus activity, we continue to be very encouraged by our Hendershot pad results in our first multi-well development, the 4-well Yankee pad brought online late in the second quarter and located in the Marcellus core development area.

The Yankee pad is exhibiting attractive performance compared to its direct offset, the Hendershot 5-well, and when normalized to 15,000-foot laterals, tracking in line on a 2-stream equivalent comparison. Notably, the Yankee pad represents our first Marcellus pad to be gathered and processed under our new midstream agreement, which enhances development economics by enabling the extraction and sales of valuable NGLs, especially considering the favorable ethane treatment that the contract provides. In addition to our Marcellus core inventory, as I noted, recent peer development activity has expanded our Ohio resource liability into Northern Belmont and Southern Jefferson Counties, where we hold a meaningful amount of acreage, as depicted on Slide 8 of our investor presentation.

We estimate approximately 120 to 130 gross locations across the defined Marcellus North development area, expanding Gulfport’s gross Marcellus inventory by approximately 200%. We plan to drill our first Marcellus North development in early 2026 and look forward to discussing the development results once the wells come online and we gain production history. In summary, we remain focused on expanding and responsibly developing Gulfport’s high-quality, low breakeven inventory while prioritizing shareholder returns and maintaining our strong financial position. The expansion of our Ohio Marcellus inventory, validation of new development and targeted discretionary acreage acquisitions have increased our total net inventory to roughly 15 years with breakevens below $2.50 per MMBtu, and we remain committed to returning capital to shareholders through common share repurchases, including the planned incremental repurchases in the fourth quarter of 2025, again, all while preserving a strong balance sheet.

Now I will turn the call over to Michael to discuss our financial results.

Michael Hodges: Thank you, John, and good morning, everyone. From a financial perspective, Gulfport delivered a strong quarter with robust quarterly production growth and solid cash operating costs, which resulted in attractive adjusted EBITDA and free cash flow generation. Net cash provided by operating activities before changes in working capital totaled approximately $198 million during the third quarter, more than funding our capital expenditures and common share repurchases, while maintaining our balance sheet strength at just over [ 8/10 ] of a turn of financial leverage. We reported adjusted EBITDA of approximately $213 million during the quarter and generated adjusted free cash flow of approximately $103 million, which includes the impact of approximately $12.4 million of discretionary capital expenditures.

Our all-in realized price for the third quarter was $3.37 per Mcfe, including the impact of cash settled derivatives, resulting in a premium of $0.30 above the NYMEX Henry Hub index price. This outperformance reflects Gulfport’s differentiated hedge position, the pricing uplift from our liquids portfolio and the impact of our diverse marketing portfolio for our natural gas. As many of our peers have discussed, we are entering an exciting time for the natural gas market, fueled by LNG expansion and the increase in demand for natural gas power generation that is accelerating from the build-out of new data centers. This evolving landscape presents exciting opportunities and while on a smaller scale than some industry peers, Gulfport has been able to benefit from our firm transportation portfolio to secure targeted arrangements with larger gas marketers that deliver incremental value to the company.

We continue to evaluate additional opportunities to supply gas to meet this growing demand and Ohio appears to be fertile ground for future development in this area. This market trend also pairs well with our direct exposure to the growing LNG corridor near the Gulf Coast through our firm transportation agreements that access the TGP 500 and Transco 85 sales points, markets which averaged more than $0.50 above the NYMEX Henry Hub index price during the third quarter. Together, these marketing and takeaway arrangements improve our realized prices, increase our all-in netbacks and ultimately lead to enhanced durability in our free cash flows. Turning to the balance sheet. Our financial position remains strong with 12-month net leverage exiting the quarter at approximately 0.81x, down from the prior quarter and benefiting from the increasing EBITDA our business has delivered over the past year.

As of September 30, 2025, our liquidity totaled $903 million, comprised of $3.4 million of cash plus $900.3 million of borrowing base availability. And we recently completed our fall borrowing base redetermination with our lenders, unanimously reaffirming our borrowing base at $1.1 billion, with elected lender commitments remaining at $1 billion. Our strong liquidity and financial position today is more than sufficient to fund any development needs we might have for the foreseeable future and provides tremendous flexibility from a financial perspective as we are positioned to be opportunistic should situations arise that allow us to capture value for our stakeholders. As demonstrated through our discretionary acreage acquisitions, proactive capital initiatives and planned share repurchases announced alongside our earnings.

As John mentioned previously, we completed the opportunistic redemption of all outstanding shares of Gulfport’s preferred stock during the third quarter. The company redeemed a total of 2,449 shares of preferred stock at an aggregate redemption value of approximately $31.3 million. This is a milestone financial accomplishment for Gulfport as the completion of this transaction simplifies our capital structure and underscores our belief in the attractive value proposition that Gulfport’s equity represents. Inclusive of the preferred redemption, during the third quarter, we repurchased 438,000 shares of common stock for approximately $76.3 million. And since the inception of the program, we have repurchased approximately 6.7 million shares of common stock at an average price of $117.45 per share, approximately 40% below the current share price.

Our consistent approach to share repurchases over the last 2 years has delivered tremendous value to our shareholders. That said, we also remain opportunistic, utilizing our financial flexibility to allocate capital when we believe the current valuation does not reflect the strength of our underlying fundamentals. And as such, repurchasing shares at today’s level represents a highly attractive use of capital. As John mentioned, we expect the incremental discretionary capital expenditures announced today to be funded without impacting our planned share buyback program and alongside earnings announced plans to allocate approximately $125 million to common stock repurchases in the fourth quarter of 2025 to be funded from adjusted free cash flow and available revolver capacity, all while maintaining leverage at or below 1x.

In closing, we remain committed to allocating capital strategically, recognizing the highest value opportunities across our assets while maintaining our return of capital framework, all anchored by a strong financial position that provides substantial flexibility. Our recent inventory expansion delivers meaningful asset accretion and long-term shareholder value, and our low breakeven inventory positions the company to benefit from improving natural gas fundamentals and deliver meaningful free cash flow growth going forward. With that, I will turn the call back over to the operator to open up the call for questions.

Q&A Session

Operator: [Operator Instructions] And the first question comes from the line of Neal Dingmann with William Blair.

Neal Dingmann: Great update. John, my question is, you’ve talked a lot on the release and this morning about just seems like well results when I look at versus type curve. They continue to improve. And I’m just wondering, I guess, 2 questions around that. Is it just you’re targeting the rock better? Or maybe just talk about what you think is really driving that certainly notable upside? And then is it fair to say, I mean, if there was even pressure and takeaway wasn’t an issue that could we even see materially bigger wells than we’re already seeing?

John Reinhart: Thanks for the question. I think one of the things that we’re pretty proud of here is the team’s constant focus on operational execution and their ability to test and optimize the completions and drilling, quite frankly, and drill out phases of our development. The teams — what I’ll point you to, the teams have progressed, especially in the different windows of the Utica with cluster spacing, with sand. So for instance, there’s been a pretty material change in the way we allocate sand, whether it’s 40/70 or 100 mesh, the cluster spacing, the stage sizes. So the teams are constantly evolving, assessing and testing as we move through our development program in both the Marcellus and the Utica and the condensate, and the well results showed that.

So pretty pleased with how the teams are focused on that, that optimization and certainly look for more to come. I think on the upside question you asked about, there’s certainly no doubt with some of the occurrences that we experienced that the throughput could have been well over what our actual production results went up in ’25, and we communicated that earlier in the year. I think on a per well basis, we do follow restricted choke management. And while there may be some upside there, generally speaking, although we’ve had some modifications to some of these restricted rates being a little bit lower because of some of the occurrences, I’ll tell you that the teams and the execution of the production results out there are following in trend and what we expect.

So limited upside on the pressure managed results. What I’ll tell you is any restrictions we’ll see near term will just kind of pan out and prolong the plateau period and shallow the decline later on. But I mean, overall, great well results. It’s a great asset base and the teams are constantly looking to optimize value.

Neal Dingmann: Great. Great. And then just a follow-up, maybe on capital allocation, I don’t know either for you or Michael. I mean is it simply — I mean, again, we know you focused on the, I think, very smartly on the stock buyback. But again, when you’re looking at M&A — and you have little debt, so I understand that. But when you guys are looking at sort of M&A prospects, does it just — is it — I don’t know, maybe I’m making it too simple, simply, are we better to buy — continue buying back a ton of our shares? Or what is the value when we see some assets out in the market? I mean, does that factor in, and maybe just discuss that around the capital allocation?

Michael Hodges: Yes. Neal, this is Michael, and John can certainly jump in. But I think you’re hitting the nail on the head. I think when we look at kind of the opportunities that are already in front of us, kind of I’ll call them these organic opportunities with the acreage acquisitions we’ve been able to execute on over the last few years and then with the equity, I think those are extremely attractive. I mean, again, I won’t get into specific rates of return and then there’s always intangible factors we consider as well. But I would just tell you the rates of return on some of those investments are quite high. And so you think about other opportunities outside of the portfolio and the need for those to compete. There certainly are those opportunities out there.

And we do know that the market has seemed to value some scale. But I think for us, the way that we’ve been able to consistently add at those high rates of return has made a lot of sense. And I think the equity value has reflected that so far. We think there’s still some underappreciated aspect to it there. But I think, again, we’re constantly measuring those opportunities against what we already have and at least in our view, trying to be very disciplined about the way we think about those things.

Operator: The next question comes from the line of Brian Velie with Capital One Securities.

Brian Velie: Just a couple here real quick. I wondered if you could walk me through kind of your line of thinking for adding those appraisal U-development wells this year rather than waiting until ’26? Was it just the gas pricing getting better recently? It certainly looks like it was the right time to do it. But I just wondered what that does for you or what this does for you in setting up ’26? Maybe just kind of put you a little bit leaning forward into next year? Were there other time line considerations or things that encouraged you or convinced you to pull this into this year?

John Reinhart: Yes. Brian, I appreciate the question. I think as we looked at the company’s portfolio, I mean, it should be no surprise to anybody that we’ve been very focused on expanding the high-quality inventory over the past 3 years. We probably sound like a broken record whenever we say it, but that is a key focus for us. And as we looked at the fourth quarter, there’s robust cash flow. The company has a healthy balance sheet. And almost every investor meeting that we have wants to see us kind of grow that inventory. And I think we agree, having sustainable long-term low breakeven inventory is very important for the company. It just provides durability, that’s very important. So as we looked at all that, it was the right time to take a look at this appraisal bucket, which was primarily allocated towards these U-development.

And this is a real opportunity for the company to take what was — what I would call shorter lateral type development that were subeconomic to the right side of the skyline and really pull forward some really good, high-quality return 20 gross wells, that also adds, by the way, some dry gas into ’26. So, I think the company was positioned very well overall financially. The commodity environment really looks constructive, and it was just the right time to continue to expand on our inventory through the Marcellus delineation efforts and all the technical work there as well as the U-development.

Michael Hodges: Yes. And I just think maybe I’d add to that, Brian. I think the timing certainly helps, right? I mean I think the gas environment is strong. And I think we’re certainly conscious of that as we make these decisions. But John hit on the point. I think it’s really about unlocking the inventory. And we’ll see what the results look like. We’ll get these things completed near the end of the year, get the production online. Some of this appraisal capital, I think John mentioned in his remarks, was also related to some legacy DUCs and some refracs. And so, we’ll kind of see what the productivity of these projects are. And so I think as far as thinking about next year at this point, probably a little early to guide you on kind of how much incremental there is there, but we’ll certainly be following up.

And I think John mentioned this in his prepared remarks, looking for other opportunities within the portfolio where we can apply some of these learnings that we’ve had.

Brian Velie: Great. That’s very helpful. And then maybe one quick follow-up. I just want to make sure that I’m thinking about this correctly and see if any shifts in the way that you guys are thinking about it. But we’re working on 2 back-to-back years, returning more than 90% of free cash flow to shareholders. This year is probably going to be in the low 90%, the way I model it with fourth quarter free cash flow and your $325 million of buybacks, plus the discretionary capital number, you’re going to be right there again. This year it’s a little bit more of the total on acquisitions of land versus buybacks than maybe it has been in the past few years. Should we think about that the same way for 2026? At least as it stands now where the mix or the balance between the 2 choices that you have is going to depend on kind of acquisition availability or deal flow and then the other piece, you have share price performance. Is that the right way to continue thinking about it?

Michael Hodges: Yes, Brian, I think that’s a great way to think about it. I think the framework that we’ve laid out hasn’t changed, right? I mean I think we feel like we’re going to generate a lot of free cash flow next year, and we are going to continue to look for these highly accretive locations that we’ve been able to add. This year, we had line of sight to a little bit bigger number than the last 2 years, but this is 3 years in a row that we’ve been able to add those locations. So as we think about next year and what the opportunity set might be, certainly not ready to size that just yet. But whatever that size comes in at, I think our strategy would remain with buying back the equity, assuming that the value continues to be a proposition that we think makes a lot of sense.

And so as I sit here today, that’s the way we think about it and certainly able to adjust that as we move forward. But we think that, that’s the highest and best use of our free cash flow right now.

Operator: The next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

Timothy Rezvan: I know you all don’t have 2026 guidance out yet, but we’re trying to understand sort of the puts and takes of your recent comments. You’re accelerating some activity in 4Q, and you mentioned some constraints that you’ve seen in 1Q from midstream and offset fracs. We saw a pretty dramatic kind of [ SKU ] to the production in 2025 with first quarter down a lot. How should we think about sort of the shape of production? I know you don’t have guidance. But just trying to understand kind of the impact of your 4Q acceleration and how that’s going to shape the next couple of quarters? Can you give any context on that?

Michael Hodges: Yes. Tim, this is Michael. I’ll take the first shot and John can certainly jump in. I think if you look back at Gulfport over the past at least few years when our management team has been involved, we’ve had a fairly front-loaded capital program, and that was true in ’25 as well. So if you think about the timing of the turn-in lines for some of that activity, you’re going to see that a lot of that coming online, call it, second, third, early fourth quarter, which leads you to flush production kind of late in the year and a little bit lower production as you get into the first part of the year. Now to your point, we’ve got some projects here later in the year that will help the first quarter production, but we also have some midstream issues.

So all that to say, I think the general shape will be similar to years in the past. I think that some of these projects might help a little bit. So maybe on a year-to-year comparison, there might be a little bit of a benefit there. But I think overall, that cadence is going to be very similar. And you’ll see strong production from Gulfport kind of Q3, Q4 with a little bit lighter as you go into first quarter, second quarter.

Timothy Rezvan: Okay. That’s helpful. I appreciate that. And then I want to talk on ops real quick. Slide 8 showed sort of this outperformance of the Yankee wells versus the Hendershot pad, and you talked about that a little bit. Is there something specifically you can kind of point to, that drove that outperformance? I know that no rock is identical. But is there something you feel that like has kind of emboldened you for this resource acquisition from that pad when you think about sort of optimizing production? Just curious any insights on that?

Matthew Rucker: Yes. This is Matt. Happy to take that one. Certainly, from that Hendershot pad, first 2 wells that we performed here in Ohio, lots of lessons learned, core data taken, things like that. So when we came back in for the full development opportunity here at the Yankee, certainly applied those lessons. I can’t necessarily attribute it to one specific thing, but we did change our completion design techniques based on what we saw in the first 2 wells, as well as some different targeting within the formation there based on our core data and our production results. So all of those things combined and understanding the reservoir fluid system a little better after the first 2 allowed us to really hone in on what those are based on just learnings in other plays and basins. And so, I think that’s the result we’re seeing here and certainly applicable to the rest of our position, which has kind of given us the support here to continue to add to our inventory.

Operator: The next question comes from the line of David Deckelbaum with TD Cowen.

David Deckelbaum: Just — curious just on the Marcellus delineation. First activity, I guess, up in Belmont. One, I guess, when are you thinking about doing some of your own work in Jefferson? And I guess, as you look at delineated activity in Belmont, what percentage do you think that, that would incrementally derisk of Marcellus prospectivity in Belmont? And I suppose as well, like would the intention be to design wells that would be similar to what you would see in development mode? Or is there going to be a little bit more science on these?

John Reinhart: Yes. I think to your first question on activity and just our general inventory add there. There are several well points to the east of us. And I think even Michael, Matt and I in our prior lives down in Monroe County, there’s been several Marcellus. And then here, we were, of course, up in that Belmont area. I think there’s a lot of data points. What really kind of triggered the timing for us here is that northern data point that kind of shored up the structural features and structural mapping as you go from south to north, which really kind of put a pin in it for us and that offset operator who drilled that well. It’s got substantial production that’s public now. And I’d reference you to Enverus as well on some of their inventory data.

It really facilitated us recognizing what we believe is a materially derisked footprint here. I will tell you that we’re pretty conservative, and we took a conservative approach on this inventory adds in the Marcellus. If you reference Slide 8 in the investor deck, it kind of shows ongoing assessment. And I think that’s maybe what you’re referring to. We wanted to make sure that we stayed structurally and honored to structural and honored the data that we saw for these 50 or 60 net inventory wells, but there is meaningful upside. I think to your point, as we think about development, we’re going to drill this first pad in Northern Belmont, which kind of ties along to the same structure and features is that Southern Jefferson. So for us, it’s — we’re agnostic to it.

What we’re looking for is what well mix that’s going to provide. So by the end of this year — or sorry, the end of next year, we’ll have a pretty good understanding of the production mix. And so, to your question about development opportunities, we’ll then take that information and start looking at midstream contracts, processing agreements. So we’re probably 2 to 3 years out from actually full developing that northern core, but we are going to drill our first well up there to get a good idea of production mix. On the South ongoing assessments, what I’ll tell you is we’re not an exploration company. We like to really derisk what we do operationally. So as we work from the east to the west, that will naturally start to delineate that ongoing assessment area where we feel like there’s some real upside there potentially for the company because the actual play moves to the west as you go farther south, just that’s the way the structure works.

So there’s a little bit — we feel positive about the opportunities to potentially add some locations in the future, but we won’t have any kind of real well set data or anything to compare to at least over the next 1.5 years. So that — there’s more to come there in the future.

David Deckelbaum: I appreciate all the details there. I wanted to just ask on the buyback in the context of flexibility going forward. You guys highlighted the $35 million of spend that would accelerate the pad into 4Q ’25 to really, I guess, offset impacts that would have happened in the first quarter. And you guys announced you’re going to buyback about $125 million of shares in the fourth quarter. It was 3.5% of your cap, [ that was ] pretty notable. Do you see an intention, I guess, to start building excess activity so that you have flexibility around issues in sort of peak periods as you get sort of beyond ’26?

Michael Hodges: Yes, I’ll take the first part, and then John or Matt can talk about kind of excess operational activity. I think on the buyback side, I think we’ve remained pretty consistently committed to it, David. So I think the announcement around earnings with the extra $125 million, I think it was maybe a little bit of an extension of what we’ve been doing anyway. I do think as we thought about the additional capital investment that we talked about earlier, the appraisal capital and then the proactive development capital, I think we wanted to show that the buyback is not kind of the offset to that, right? So I think that was the intention there. And I think there was a question earlier in the call about the intention going forward, and I think we’ll remain pretty consistent there.

But I don’t think that on the buyback side, kind of the inventory of operational opportunities is changing our approach. In fact, I think what we did here in the fourth quarter kind of indicates that the buyback will remain consistent despite any kind of additional activity we consider going forward. So I don’t know if, John or Matt, do you have anything you want to add to that?

John Reinhart: Yes. I’ll touch on the preparedness and kind of contingencies. We’ve really been focused, as we talked about on adding additional inventory. And these inventories kind of scour different landscape areas. So we’ve been focused on dry gas, wet gas. We’ve developed — and certainly some Marcellus. We’ve developed some condensate wells. So as you think about kind of preparations for future occurrences and incidents, these all are in different footprints in different areas. So, by default of just adding this low breakeven, high-quality blocky acreage we can develop, it does set us up for contingent options as we move forward for any kind of unforeseen or unplanned incidents that we might have in the future. So, by default, we’re actually focused on doing that by these inventory adds, and we feel like that’s a very prudent action for us to take just considering what’s happened over the last year.

Operator: The next question comes from the line of Jacob Roberts with Tudor, Pickering, Holt & Company.

Jacob Roberts: I wanted to ask on the 20 U-development locations. Is that largely a function of just the previous wells drilled? Or is that a function of that footnoted price? I’m just wondering over a multiple year period, how many of these do you think you could actually identify as feasible?

John Reinhart: Yes, it’s a great question. I’ll tell you that the general first review over our portfolio and acreage footprint, these are more geared towards looking at land configurations that would limit lateral lengths. Otherwise, there would be longer lateral development. So, for instance, when the teams went through and scoured in these highly productive, high-quality acreage positions, we had 20 gross locations that we could actually form through basically combining, let’s just call it, double that amount of shorter laterals. And what that did was it took a very subeconomic short lateral even at 350, 375 gas, let’s just call it 20% IRRs. These are still attractive returns, but they just — they don’t compete for capital with our current portfolio.

And they raised those up to somewhere along the lines of 60% plus returns. So what we’re effectively doing is combining some of these subeconomic shorter laterals and moving them to the left in the skyline chart. So, it’s really a function of the acreage position and maximizing our utilization of our current footprint. That’s how I would characterize it.

Jacob Roberts: Great. As a follow-up, I’ll echo the sentiment that it’s great to see the inventory additions to the portfolio. I’m wondering if that longer-dated inventory and as you guys continue to add to that, does that open up the conversation more to potential power agreements, data centers and all those types of conversations? I understand there’s an absolute volumes component to those conversations as well. But just wondering if that’s making those conversations more feasible?

Michael Hodges: Yes. Jacob, this is Michael. I think not necessarily. Like so, if you think about our position in the area, we’re having kind of ongoing discussions. We are a bit on the smaller side. And so I think in general, you’re going to see most of those announcements go with folks that are investment grade or just bigger producers of gas. I think having the inventory certainly matters when you have those discussions. I mean there’s certainly kind of a desire to be able to demonstrate the durability. I would tell you that our motivation has really been more on our business and certainly shoring up our own views of kind of duration of inventory, which, again, we felt very strongly about over the past few years, and we’re continuing to execute on that.

So just kind of demonstrating that out. But I don’t think that in the past, those have been issues that have limited those discussions. We’re in discussions on some of those projects. But certainly doesn’t hurt to have kind of that additional runway to be able to demonstrate.

Operator: The next question comes from the line of Peyton Dorne with UBS.

Peyton Dorne: Just one question on my end. NGL stepped up nicely in the period. I believe it was from the new Marcellus pad and maybe also from the [ Cadiz ] pad. I just wonder if you could touch on how the NGL recoveries have gone so far with that development mode that you entered into and how you see NGL marketing shaping up as you’ve obviously added a bit more to that Marcellus opportunity set?

Michael Hodges: Yes. Peyton, this is Michael. It’s a great question, actually. You’re right. We did see a nice uplift in our NGL volumes this quarter. A combination of things there, right? So you had mentioned our Marcellus pad, our Yankee pad and the 4-well pad in the Marcellus. We had some strong recoveries there. I think the liquids yield on those wells, that look very attractive to us. And our new midstream agreement that we actually signed earlier this year, this is the first 4-well pad where we’ve been able to process the liquids over there. So good recoveries. There’s some strong economics over there as well. John mentioned in his prepared remarks, we don’t talk a lot about it, but actually have some really good pricing around some components of the barrel of that NGL barrel over there.

So that was a positive. The other area that you didn’t mention is we have our wet gas development that’s come on this year. And I would tell you that the yields there have actually been very strong as well. So that’s in our kind of — we called it our wet gas Utica. It’s part of our discretionary acreage budget that we spent over the last couple of years. We put those wells on earlier this year. And we saw, I would tell you, kind of outperformance on the NGL side. So again, we’ve got favorable contracts up there. Not a lot has changed in our legacy Ohio Utica contracts, but that Marcellus contract on the marketing side is very strong from an economic perspective. And so, we feel really good that our netbacks have been strong even when I would tell you that some others in the basin have seen some weakness in NGLs.

Operator: The next question comes from the line of Noah Hungness with Bank of America.

Noah Hungness: First question here. Last week, Governor DeWine announced the energy opportunity initiative, $100 million fund for power developments in Ohio. And I guess I was just wondering, how do you think that changes the playing field for data center development and ultimately, just regional natural gas demand?

Michael Hodges: Yes. Noah, this is Michael. Great question. I think we’ve seen increasing levels of interest. I was just going to — I mentioned that maybe a little bit earlier in my prepared remarks that there’s a lot of activity going on in Ohio right now. I think — Ohio, I think I called it fertile ground, but it certainly seems like there’s a favorable regulatory environment. There’s favorable political environment, and there’s just a lot of interest in projects in that area. So again, from our perspective, we’re a bit smaller than some of the other guys out there. So, more likely for us to participate in kind of some aggregation strategy of marketing firms that put together volumes of gas come to us looking for volumes.

We can get some uplift in our value when we do that. I think you’re aware that we like to keep things fairly flexible in our business. So we’re always kind of balancing the long-term commitment element of that with the pricing opportunity that we have. So, to your point, I think it’s very favorable, I call it positive momentum in the area right now. And ultimately, we’ve got gas, a lot of gas that’s still uncommitted to any of those projects. And so to the extent there’s further opportunities, we can certainly consider those.

Noah Hungness: That’s really helpful. And then for my second question here, going over to Slide 8, I see that you guys gave an average lateral length for your core Marcellus and North Marcellus positions. And it is long laterals 3, 3.5 miles. But given the undeveloped nature of the bench, why do you think the lateral lengths aren’t longer, something like 4 miles or 4.5 miles?

Matthew Rucker: Yes. Noah, this is Matt. I mean this is really just a representation of our current development plan on our footprint. We’ll always be looking for opportunities to find more efficient longer laterals. I think there’s some land constraints in certain parts, but these are pretty long and pretty attractive economics. So for us, this is kind of in that wheelhouse of where we like to be, with minimal risk on the operations side. And so, that may change over time as we continue to develop out the footprint, but this is a pretty comfortable position for us to be in right now.

Operator: The next question comes from the line of Carlos Escalante with Wolfe Research.

Carlos Andres E. Escalante: Look, I think the inventory disclosure is very helpful for the market. So I can appreciate your efforts to — across multiple horizons to deepen your portfolio bench and the value add that it has. But I wonder what kind of conversations are taking place aiming at larger opportunities, in particular around what your role is in broader consolidation? And this goes for both of your operated basins. I mean we’ve seen a lot of activity on a relative scale in the Anadarko in general. So just wondering where your head is at with that?

Michael Hodges: Yes, I’ll start, and then John can jump in. Carlos, thanks for the question. I think Neal asked a little bit earlier a similar question where I think our view on those opportunities is that we have pretty compelling opportunities within our existing portfolio, and we’re measuring anything outside our portfolio against those opportunities. So I think there — likely, you’re aware that there’s been some activity up in Appalachia. I think for the company, we’ve been disciplined over the last few years and feel like the strategy has really been effective for us. So I think that will continue. And I think to your point on the Anadarko Basin, I think there was another operator last night that announced a potential transaction.

There is growing activity in that area. We’ve seen a number of transactions. Our position is very, very strong in that area. I would tell you that it’s desirable, but we really like it. We allocate capital there every year. I think if you look at it on a rate of return basis, the well results are very competitive with our Appalachian position. So, from our perspective, the growing interest down there is positive. But I think, again, we like what we have, and we think we create value through the drill bit. And so, for us to develop that asset still makes a lot of sense.

Operator: The next question comes from the line of Nicholas Pope with ROTH MKM.

Nicholas Pope: I was hoping we could talk a little bit more about the U-development kind of reached total depth on these wells. Curious what risks you’re looking at remaining as you kind of move to completion and bringing these wells online, I guess, compared to the wells that you have existing of similar lateral length, but I guess, obviously, a different geometry on these wells?

Matthew Rucker: Yes, Nick, this is Matt. Thanks for the question. We did get both wells, TD and Kage starting to move into the completion phase here in the fourth quarter. I would just tell you the risk like in most horizontal well developments really on your pump down of tools and getting all the way to TD to start your perforating and your frac and then ultimately, your drill out. So when you talk about U-shaped development wells, it’s really important on the front end to get your well design planning accurately. And so, the teams have done a really good job of running our torque and drag modeling and appropriately using the proper build rates to ensure that we’re able to get those things down. So I see that as a minimal risk based on the well design planning that the teams have done over the last several months preparing for this development.

Nicholas Pope: Got it. That makes sense. And as you look at like the kind of mile markers that we should look for, as you kind of move into production and kind of getting a sense of how these things produce, should we expect similar production rates from these wells to comparable kind of straight lateral length wells in the same region? Is that kind of how we should be comparing things as these wells start to be developed?

Matthew Rucker: Yes. I think that’s a good way of thinking about it, Nick. I think when you think about the perforated lateral footage on both of those essentially doubling for the footprint there, it will be very similar to the dry gas development on a straight lateral where we kind of target a capped rate per foot on our IP rates from a choke management perspective and very similar EUR per foot over the life of the well. So I would expect that to look very similar. So in our type curves on a 15,000-foot lateral, we’re in that 30 million a day range. So adjusting around that for us in the choke management situation, that’s what that would look like.

Operator: This concludes the question-and-answer session. I’d like to turn the call back to John Reinhart for closing remarks.

John Reinhart: Thank you for taking the time to join our call today. Should you have any questions, please don’t hesitate to reach out to our Investor Relations team. Have a great day.

Operator: This concludes today’s conference. You may disconnect your lines at this time. Thank you for your participation.