Gulfport Energy Corp Q3 FY2025 Earnings Call

Greetings, and welcome to the Gulfport Energy Corporation Third Quarter 2025 Earnings Call. 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.

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.

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 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.

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 0.8 turns 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.

And the first question comes from Neal Dingmann with William Blair.

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?

Thank you for the question. One of the things we take pride in is our team's continuous commitment to operational execution and their ability to test and optimize completions and drilling as we progress through our development phases. The teams have made significant advancements, especially in different sections of the Utica, focusing on cluster spacing and sand usage. For example, we've seen material changes in how we allocate sand, whether it's 40/70 or 100 mesh, as well as in cluster spacing and stage sizes. The teams are always evolving, assessing, and testing as we develop the Marcellus and Utica. The well results reflect this progress. We are pleased with the team's focus on optimization and anticipate more improvements ahead. Regarding the potential upside you mentioned, it's clear that due to certain events we've encountered, the throughput could have exceeded our actual production results for 2025, which we communicated earlier this year. On a per well basis, we manage restricted choke operations. While there may be some potential upside, overall, we have made some adjustments to the restricted rates, which are slightly lower due to certain occurrences. However, the execution of our production results is in line with our expectations. Any near-term restrictions will likely extend the plateau period and reduce the decline later on. Overall, we are seeing great well results, and our asset base is strong, with the teams continually striving to maximize value.

Great. And just a follow-up on capital allocation, I’m curious about your approach. We know you have been wisely focusing on stock buybacks, but when considering M&A opportunities, especially with your low debt levels, how do you evaluate the balance? Is it preferable to continue repurchasing shares heavily, or do potential market assets play a significant role in your decision-making? Could you elaborate on how this influences your capital allocation strategy?

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.

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

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?

Yes, Brian, thank you for the question. As we've reviewed the company's portfolio, it's clear we've been dedicated to expanding our high-quality inventory for the last three years. This focus is critical for us. In the fourth quarter, we saw strong cash flow and a healthy balance sheet, and almost every investor meeting highlights the importance of growing our inventory. We recognize that having sustainable long-term low breakeven inventory is essential for the company as it ensures durability. Given this context, we found it was the right moment to evaluate the appraisal bucket, mainly designated for U-development. This presents a significant chance for the company to enhance what were previously shorter lateral developments that were not economically viable, thereby generating attractive returns from 20 gross wells, which will also contribute some dry gas into 2026. Overall, the company is financially well-positioned, the commodity environment appears favorable, and it was timely to further expand our inventory through the Marcellus delineation efforts and the associated technical work.

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 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.

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?

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.

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

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 decline 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?

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.

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?

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.

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

I'm curious about the Marcellus delineation, particularly regarding the activity in Belmont. When are you planning to conduct work in Jefferson? Looking at the activity in Belmont, how much do you believe it will reduce the risk associated with prospective wells in that area? Additionally, will you design these wells similarly to those in development mode, or will there be a greater focus on scientific approaches?

Yes, regarding your first question about activity and our general inventory, there are several well sites to the east of us. In our previous roles in Monroe County, we noted multiple Marcellus wells, and here we've been focusing on the Belmont area. We have a lot of data points. The key factor for us has been some northern data that clarified the structural features as you move from south to north, confirming our findings about the offset operator's well, which is now public and shows substantial production. We believe this has significantly reduced the risk associated with our footprint. We approach our inventory additions in the Marcellus conservatively, as shown on Slide 8 in our investor deck, reflecting our ongoing assessment. We are careful to respect the structural data we have for these 50 or 60 net inventory wells, and there is meaningful upside potential. As for development, we plan to drill our first pad in Northern Belmont, aligning with the same structures and features seen in Southern Jefferson. Our primary focus is on the well mix that this will provide. By the end of next year, we should have a clear understanding of our production mix. Regarding further development opportunities, we'll use this data to explore midstream contracts and processing agreements. We're likely 2 to 3 years away from fully developing that northern region, but we'll start by drilling our first well to assess production mix. In the south, we want to reiterate that we're not an exploration company; our goal is to derisk operationally. As we assess from east to west, we'll identify ongoing areas that show real upside potential, as the play extends westward with depth to the south. While we remain optimistic about adding more locations down the line, we won't have concrete well data for at least the next 1.5 years. More information will become available in the future.

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?

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?

I'll discuss our preparedness and contingencies. We've been focused on increasing our inventory across various landscape areas. Specifically, we've targeted both dry gas and wet gas, and we've developed some condensate wells in the Marcellus region. As we consider future events and incidents, we have options across different locations due to this inventory expansion. By acquiring this low breakeven, high-quality acreage, we are positioning ourselves for any unforeseen or unplanned situations that may arise in the future. Overall, our emphasis on adding to our inventory is a prudent decision in light of the events of the past year.

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

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?

It's a great question. In our initial review of our portfolio and acreage footprint, we focused on land configurations that would restrict lateral lengths. This approach enables longer lateral development. For example, our teams examined highly productive, high-quality acreage and identified 20 gross locations that can be effectively formed by combining approximately double that number of shorter laterals. This adjustment improved our returns significantly. Although these shorter laterals had lower economic viability even at gas prices of 350 or 375, offering around 20% IRRs, they were still attractive. However, they didn't compete effectively for capital within our current portfolio. By optimizing our approach, we were able to elevate those returns to over 60%. Essentially, we are transforming some of these less economically viable shorter laterals and enhancing their potential within our strategy. This is fundamentally about maximizing the utilization of our existing acreage.

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?

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.

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

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?

Yes, Peyton, this is Michael. It's a great question. You're right; we did see a nice increase in our NGL volumes this quarter. There are several factors contributing to this. You mentioned our Marcellus pad, our Yankee pad, and the 4-well pad in the Marcellus, where we experienced strong recoveries. The liquids yield from those wells looks very promising to us. Additionally, our new midstream agreement signed earlier this year allows us to process liquids from this first 4-well pad. The recoveries have been good, and the economics are strong as well. John mentioned in his prepared remarks that we don't often highlight it, but we actually have favorable pricing on some components of that NGL barrel. That’s a positive aspect. Another area you didn't address is our wet gas development that launched this year, which has also shown strong yields. We refer to it as our wet gas Utica, and it falls within our discretionary acreage budget invested over the last couple of years. We initiated those wells earlier this year and have seen outperformance on the NGL side. We have favorable contracts in that area. While not much has changed in our legacy Ohio Utica contracts, the Marcellus contract from a marketing perspective is quite strong economically. Therefore, we are quite satisfied that our netbacks remain robust, even as some others in the basin have experienced weakness in NGLs.

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

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?

Yes, Noah, this is Michael. That's a great question. We've observed a growing interest in the region. I mentioned earlier that there's significant activity occurring in Ohio, which I consider a promising area. The regulatory and political environments are favorable, and there is considerable interest in projects happening there. From our standpoint, we're smaller compared to some others in the market, so we are more likely to engage in an aggregation strategy with marketing firms that consolidate gas volumes to approach us. This approach can enhance our value. We prefer to maintain flexibility in our business, so we're continuously balancing long-term commitments with pricing opportunities. I believe there's positive momentum in the area currently. Moreover, we have a substantial amount of uncommitted gas related to those projects. Therefore, if additional opportunities arise, we will definitely consider them.

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?

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.

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

I believe the inventory disclosure is very beneficial for the market. I appreciate your efforts to enhance your portfolio and the added value it brings. However, I'm curious about the discussions happening regarding larger opportunities, specifically related to your role in broader consolidation, especially in both of your operated basins. We've observed significant activity in the Anadarko region, so I'm interested in your perspective on that.

I'll start, and then John can join in. Thank you for the question, Carlos. I think earlier Neal raised a similar point regarding our opportunities. We believe that we have strong options within our current portfolio and evaluate any outside opportunities against those. You're likely aware of some recent developments in Appalachia. We've maintained a disciplined approach in recent years, and our strategy has proven effective. I expect this will continue. Regarding the Anadarko Basin, another operator announced a potential transaction last night, indicating increased activity in that area. Our position there is very strong, and we find it desirable. We allocate capital to that region every year, and on a rate of return basis, the well results are very competitive with our operations in Appalachia. From our view, the rising interest in that area is a positive sign, but we believe in the value of what we currently have and that we can create value through continued development. So, further developing that asset still makes a lot of sense for us.

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

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?

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.

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?

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.

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

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.

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