Gulfport Energy - Earnings Call - Q3 2025

Executive Summary

• EPS beat despite revenue shortfall versus Street: Q3 2025 Primary EPS came in at $4.93 vs $4.67 consensus (beat), while revenue (ex-derivatives, S&P definition) was $307.6M vs $344.7M consensus (miss). Year-over-year sales rose sharply as commodity pricing and liquids uplift improved mix. The revenue delta vs GAAP “Total revenues” reflects derivative mark-to-market accounting in company reporting.*
• Strong operations and mix: Total net production rose 11% QoQ to 1,119.7 MMcfe/d; liquids volumes increased 15% QoQ to 22.0 MBbl/d, helping realized pricing (3.37 $/Mcfe incl. hedges).
• Inventory and technical catalysts: ~125 gross Ohio Marcellus locations added (≈200% increase), validation of Utica U‑development (2 wells TD) unlocking ~20 gross dry gas locations; total undeveloped inventory now ~700 gross locations (~15 years) with breakevens below $2.50/MMBtu. These are key medium-term stock catalysts.
• Capital returns and balance sheet: Company plans ~$125M of Q4 buybacks (targeting ~$325M for 2025) and completed redemption of remaining preferreds ($31.3M), with liquidity of ~$904M and borrowing base reaffirmed at $1.1B.

What Went Well and What Went Wrong

• What Went Well

  • Inventory depth and quality improved: “effectively doubling our net drillable Marcellus inventory in Ohio” and validating U‑development across Utica; total undeveloped inventory ~700 gross locations, ~15 years at sub‑$2.50/MMBtu breakevens.
  • Liquids uplift and realized price premium: All-in realized price was $3.37/Mcfe, a ~$0.30 premium to Henry Hub, supported by hedges, liquids pricing, and marketing optionality to TGP 500/Transco 85.
  • Solid cash generation and returns: Adjusted EBITDA of $213.1M and adjusted FCF of $103.4M funded capex and buybacks; plan to allocate ~$125M to Q4 repurchases while keeping leverage ≤1x.

• What Went Wrong

  • Top-line versus Street: S&P “Revenue” missed consensus ($307.6M vs $344.7M), despite YoY sales growth; GAAP “Total revenues” include derivative gains not in Street models.*
  • Ongoing infrastructure headwinds: Known midstream constraints and offset-operator simultaneous ops pressured cadence; company is investing ~$35M in 2025 to mitigate anticipated Q1’26 downtime.
  • QoQ GAAP revenue compression: Total revenues fell QoQ ($379.7M vs $447.6M) largely due to smaller derivative gains ($66.8M in Q3 vs $136.1M in Q2).

Transcript

Operator (participant)

Greetings and welcome to the Gulfport Energy Corporation third quarter 2025 earnings call. At this time all participants are in the listen only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance, please press Star zero on your telephone keypad. 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 Antle (VP of Investor Relations)

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 and 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 their earnings announcement. At this time I would like to turn the call over to John Reinhart, President and CEO.

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 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 Counties. 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 two 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. 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. 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 structure and complements our ongoing equity repurchase program inclusive of the preferred redemption. As of September 30, 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 ATT leverage ratio forecasted to be at or below 1 times 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 two 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 2U 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 2U 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 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 one 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 and filling 2,000 foot spaced laterals as well as refrac opportunities from understimulated 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 a 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 and primarily in the dry gas and wet gas windows of the Utica, and we have invested approximately $15.7 million during the first nine months of 2025.

We reiterate our plans and remain on track to allocate $75 million-$100 million in total before the end of the first quarter of 2026 and currently forecast approximately $60 million of cumulative spend on by year end 2025. Upon successful completion of our planned expenditures, this is planned to add over two years of core drilling inventory, farther 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 two 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 viability 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 120-130 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 U 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 (EVP and CFO)

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 opportunity 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 0.81 times, 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 for 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 plan to 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 few 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.

Operator (participant)

Thank you ladies and gentlemen. If you would like to ask a question, please press Star one on your telephone keypad and a confirmation tone will indicate your line is in the question queue. You can press Star Q if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. The first question comes from the line of Neil Dingman with William Blair. Please proceed.

Neal Dingmann (Energy Research Analyst)

Morning guys. 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. I'm just wondering, I guess two questions around that. Is it just you're targeting the rock better or maybe just talk about what do you think is really driving that certainly notable upside. Is it fair to say, I mean if there was, even if pressure and takeaway wasn't an issue, that could we even see materially bigger wells than we're already seeing?

John Reinhart (President and CEO)

Hey, good morning Neil. 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, you know, what I'll point you to. The teams have progressed especially in the different windows of the Utica with cluster spacing with sand. 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. 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 show that.

Pretty pleased with how the teams are focused on that optimization and certainly look forward 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 2025 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.

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. I mean overall great well results, it's a great asset base and the teams are constantly looking to optimize value.

Neal Dingmann (Energy Research Analyst)

Great, great points.

Just to follow up, maybe.

On capital, on capital allocation, I don't know, either for you or Michael, I mean, is it, is it simply. I mean, again, we know you focused on the, you know, I think very smartly on, on the stock buyback. Again, when you're looking at M and A and you have little, little debt, so understand that. When you guys are looking at sort of M and A prospects, does it just, is it, you know, I don't know, madam. 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? Does that factor in. Maybe just discuss that around the capital allocation?

Michael Hodges (EVP and CFO)

Yeah. Hey, Neil, 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. Again, I won't get into specific rates of return, and there's always intangible factors we consider as well. I would just tell you the rates of return on some of those investments are quite high. You think about other opportunities outside of the portfolio and the need for those to compete. There certainly are those opportunities out there. We do know that the market has seemed to value some scale.

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. 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.

Neal Dingmann (Energy Research Analyst)

Great details. Thanks, guys.

John Reinhart (President and CEO)

Thanks, Neil.

Operator (participant)

The next question comes from the line of Brian Velley with Capital One Securities. Please proceed.

Brian Velie (Equity Analyst)

Good morning, everybody. Thanks for taking my questions. Just a couple here. Real quick, I wondered if you could walk me through kind of your line of thinking for adding those appraisal view development wells this year rather than waiting until 2026. Was it just, you know, the gas price 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 2026 maybe just kind of puts you a little bit leaning forward into next year. Were there other timeline considerations or things that encouraged you or convinced you to pull this into this year?

John Reinhart (President and CEO)

Yeah. Good morning, Brian. 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 three years. You know, we probably sound like a broken record whenever we say it.

That is a key focus for us.

As we looked at the fourth quarter, there is robust cash flow, the company has a healthy balance sheet and, you know, almost every investor meeting that we have, you know, wants to see us kind of grow that inventory. I think we agree having sustainable long term, low breakeven inventory is very important for the company. It just provides durability. That is very important. 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. This is, you know, this is a real opportunity for the company to take what was what I would call shorter lateral type development that were sub economic to the right side of the skyline and really pull forward some really good, you know, high quality return 20 gross wells.

That also adds, by the way, you know, some dry gas into 2026. So you know, I think the company was positioned very well overall financially. The commodity environment, you know, 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 (EVP and CFO)

Yeah, 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, you know, I think we're certainly conscious of that as we make these decisions. John hit on the point. I think it's really about unlocking the inventory and, 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.

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 (Equity Analyst)

Great, thanks. That's very helpful. Maybe one quick follow up. 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. We're working on two back to back years returning more than 90% of free cash flow to shareholders. This year it's 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 is on acquisitions of land versus buybacks than maybe it has been 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 two 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?

Michael Hodges (EVP and CFO)

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 two years. This is three years in a row that we've been able to add those locations.

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, you know, buying back the equity, assuming that the value continues to be, you know, a proposition that we think makes a lot of sense. As I sit here today, that's the way we think about it and certainly able to adjust that as we move forward. You know, we think that that's the highest and best use of our free cash flow right now.

Brian Velie (Equity Analyst)

Perfect. Thanks very much, Michael. Appreciate it, guys. Good work on the inventory adds.

John Reinhart (President and CEO)

Thanks, Brian.

Operator (participant)

The next question comes from the line of Tim Resben with KeyBanc Capital Markets. Please proceed.

Tim Rezvan (Managing Director)

Good morning, folks. Thanks for taking my questions. I know you all do not have 2026 guidance out yet, but we are trying to understand sort of the puts and takes of your recent comments. You are accelerating some activity in Q4 and you mentioned some constraints that you have seen in Q1 from midstream and offset fracs. We saw a pretty dramatic kind of skew 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 do not have guidance, but just trying to understand kind of the impact of your Q4 acceleration and how that is going to shape the next couple quarters. Can you give any context on that?

Michael Hodges (EVP and CFO)

Yeah.

Hey 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's been involved, we've had a fairly front loaded capital program and that was true in 2025 as well. If you think about the timing of the turn in lines for some of that activity, you're going to see a lot of that coming online, call it second, third, you know, 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.

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

Tim Rezvan (Managing Director)

Okay, okay, that's helpful. I appreciate that. You know, talk on ops real quick. Slide 8 showed sort of this outperformance of the Yankee Wells versus the Hendershot pad. 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 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?

Thank you.

Matthew Rucker (EVP and COO)

Yeah, this is Matt, happy to take that one. Certainly, you know, from that Hendershot pad, first two wells that we performed here in Ohio, lots of lessons learned, core data taken, things like that. When we came back in for the full development opportunity here at the Yankee, certainly applied those lessons. I cannot necessarily attribute it to one specific thing, but we did change our complete design techniques based on what we saw in the first two wells, as well as some different targeting within the formation there based on our core data.

Our production results.

You know, all those things combined and understanding the reservoir fluid system a little better after the first two allowed us to really hone in on what those are based on just learnings and other plays and basins. I think that's the result we're seeing here and certainly applicable to the rest of our position, which has kind of, you know, given us the support here to continue to add to our inventory.

Tim Rezvan (Managing Director)

Okay, thanks for the details.

Matthew Rucker (EVP and COO)

Thanks, Tim.

Operator (participant)

The next question comes from the line of David Deckebaum with TD Cowen. Please proceed.

David Deckelbaum (Managing Director)

Thanks guys for taking my questions today.

John Reinhart (President and CEO)

Thanks, David.

David Deckelbaum (Managing Director)

Morning.

Just curious, just on the Marcellus delineation, you know, first activity, I guess up in Belmont, you know, one, I guess when are you thinking about doing some of your own work in Jefferson? I guess as you look at delineated activity in Belmont, you know, what percentage do you think that that would incrementally de-risk of Marcellus prospectivity in Belmont? I suppose as well, like would the intention 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 (President and CEO)

Yeah, I think to your first question on activity and just our general inventory add there, you know, 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 in 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, they 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. That offset operator who drilled that well, it's got substantial production that's public now. I'd reference you to Ascent Resources as well on some, some of their inventory data.

It really facilitated us recognizing, you know, what we believe is a materially de-risked footprint here. I will tell you that we're pretty conservative and we took a conservative approach on these 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 in honor of the data that we saw for these 50 or 60 net inventory wells. 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 as that southern Jefferson. For us we're agnostic to it.

What we're looking for is what well mix that's going to provide. By the end of this year, or, sorry, the end of next year, we'll have a pretty good understanding of the production mix. To your question about development opportunities, we'll then take that information and start looking at midstream contracts, processing agreements. We're probably two to three years out from actually fully developing that northern core. 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, you know, we're not an exploration company. We like to really de-risk what we do, you know, operationally.

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. That's just the way the structure works. We feel positive about the opportunities to potentially add some locations in the future. We won't have any kind of real well set data or anything to compare to at least over the next year and a half. There's more to come there in the future.

David Deckelbaum (Managing Director)

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 spends that would accelerate the path into 4Q 2025 to really, I guess, offset impacts that would have happened in the first quarter. You guys announced you're going to buy back about $125 million of shares in the fourth quarter, 3.5% of your cap, 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 2026?

Michael Hodges (EVP and CFO)

Yeah, 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, you know, we've remained pretty consistently committed to it, David, so I think, you know, 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, you know, 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. 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.

I do not 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. I do not know if John or Matt, you have anything you want to add to that?

John Reinhart (President and CEO)

No, I'll touch on the preparedness and kind of contingencies. You know, we've really been focused as we've talked about on adding additional inventory and these inventories kind of scour different landscaped areas. We've been focused on dry gas, wet gas, we've developed and certainly some Marcellus, we've developed some condensate wells. As you think about, you know, kind of preparations for future occurrences and incidents, these all are in different footprints in different areas. 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.

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.

David Deckelbaum (Managing Director)

Appreciate it, guys.

John Reinhart (President and CEO)

Yes, sir.

Operator (participant)

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

Jacob Roberts (Director of Research)

Good morning,

John Reinhart (President and CEO)

Jake.

Morning

Jacob Roberts (Director of Research)

guys.

I wanted to ask, on the 2U 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 (President and CEO)

Yeah, 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 would be longer lateral development. 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. What that did was it took a very sub economic short lateral. Even at $3.53-$3.75 gas and let's just call it 20% IRR. These are still attractive returns, but they're just, they don't compete for capital with our current portfolio, you know, and they raise those up to somewhere along the lines of 60% plus returns.

What we're effectively doing is combining some of these sub economic shorter laterals and moving them to the left in the skyline chart. It is really a function of the acreage position and maximizing our utilization of our current footprint.

That's how I would characterize it.

Jacob Roberts (Director of Research)

Great, thank you.

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.

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 (EVP and CFO)

Yeah. Hey Jake, this is Michael. I think not necessarily like. If you think about our position in the area, we're having kind of ongoing discussions. You know, we are a bit on the smaller side. 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. Just kind of demonstrating that out.

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.

Jacob Roberts (Director of Research)

Great.

Appreciate the time.

Michael Hodges (EVP and CFO)

Thank you.

Operator (participant)

The next question comes from the line of Peyton Dorn with UBS. Please proceed.

Peyton Dorne (Director and Energy Equity Research Analyst)

Hey John and team, thank you very much for getting me on. 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 Cage 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 have obviously added a bit more to that Marcellus opportunity set. Thank you.

Michael Hodges (EVP and CFO)

Yeah. Hey, 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. You mentioned our Marcellus pad. Our Yankee pad is the four well pad in the Marcellus, we had some strong recoveries there. I think the liquid yield on those wells has looked very attractive to us. Our new midstream agreement that we actually signed earlier this year, this is the first four well pad where we've been able to process the liquids over there. Good recoveries. There are some strong economics over there as well. John mentioned in his prepared remarks, we do not talk a lot about it, but actually have some really good pricing around some components of the barrel of that NGL barrel over there. That was a positive.

The other area that you did not mention is, you know, we have our wet gas development. You know, that has come on this year, and I would tell you that the yields there have actually been very strong as well. That is in our kind of, we called it our wet gas Utica. It is part of our discretionary acreage budget that we spent over the last couple years. We put those wells on earlier this year and we saw, I would tell you, kind of outperformance on the NGL side. You know, we have got favorable contracts up there. Not a lot has changed in our legacy Ohio Utica contracts. That Marcellus contract on the marketing side is very strong from an economic perspective.

You know, we feel really good that our netbacks have been strong, even when, you know, I would tell you that some others in the basin have seen some weakness in NGLs.

Peyton Dorne (Director and Energy Equity Research Analyst)

Yeah, certainly. Good to see you. Thanks for getting me on.

Michael Hodges (EVP and CFO)

Thanks, Beyon.

John Reinhart (President and CEO)

Thanks.

Operator (participant)

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

Noah Hungness (Equity Research Associate)

Morning.

First question here. Last week, Governor Mike DeWine announced the Energy Opportunity Initiative $100 million fund for power developments in Ohio.

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 (EVP and CFO)

Yeah, hey, no, this is Michael, great question. I think, you know, we've seen increasing levels of interest, and I was just going to, you know, 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. 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. 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, 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. We are always kind of balancing the long term commitment element of that with the pricing opportunity that we have. To your point, I think it is very favorable. I would call positive momentum in the area right now. Ultimately, we have gas, a lot of gas that is still uncommitted to any of those projects. To the extent there are further opportunities, you know, we can certainly consider those.

Noah Hungness (Equity Research Associate)

That's really helpful.

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. You know, it is long laterals, three, three and a half miles. Given the undeveloped nature of the bench, why do you think the lateral lengths are not longer? You know, something like four miles or.

Four and a half miles?

Matthew Rucker (EVP and COO)

Yeah, no, 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. For us, this is kind of in that wheelhouse of where we like to be with minimal risk on the operations side. You know, 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.

Noah Hungness (Equity Research Associate)

That makes sense.

Thank you.

Michael Hodges (EVP and CFO)

Thanks.

John Reinhart (President and CEO)

Thanks.

Operator (participant)

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

Carlos Escalante (Senior Associate)

Hey, good morning, team. Thank you for taking my question. Look, I think the inventory disclosure is.

Very helpful for the market, so I.

Can appreciate your efforts across multiple horizons.

To deepen your portfolio bench and the value add that it has. I wonder what kind of conversations.

Are taking place aiming at larger opportunities in particular around what your role is in broader consolidation.

This goes for both of your operated basins.

I mean, we've seen a lot of.

Activity on a relative scale and the Anadarko in general.

Just wondering where your head is at with that.

Michael Hodges (EVP and CFO)

Yeah, I'll start and then John can jump in. Carlos, thanks for the question. I think Neil 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. You know, I think they're, you know, likely. You're aware that there's been some activity up in Appalachia. I think for the company, you know, we've been disciplined over the last few years and feel like the strategy has really been effective for us. I think that'll continue. I think, you know, 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. From our perspective, the growing interest down there is positive. I think, you know, again, you know, we like what we have and we think we create value through the drill bit. For us to develop that asset still makes a lot of sense.

Carlos Escalante (Senior Associate)

Thank you, guys. I'll turn it right over. Back to you.

John Reinhart (President and CEO)

Thanks, Carlos.

Operator (participant)

The next question comes from the line of Nicholas Pope with Roth MKM. Please proceed.

Nicholas Pope (Managing Director and Senior Research Analyst)

Good morning.

John Reinhart (President and CEO)

I Morning.

Nicholas Pope (Managing Director and Senior Research Analyst)

Just hoping we could talk a little.

Bit more about the 2U development kind.

Of reach total depth on these wells.

Curious what risks you're looking at remaining?

As you kind of move to completion.

Bringing these wells online, I guess compared to the wells that you have existing and a similar lateral length, but I guess obviously a different.

Geometry on these wells.

Matthew Rucker (EVP and COO)

Yeah, Nick, this is Matt. Thanks for the question. You know, we did get both wells, TD and K is starting to move into the completion phase here in the fourth quarter.

You know, I would just tell you.

The risk, you know, 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. When you talk about U shape development, it is really important on the front end to get your well designed planning accurately. 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 are able to get those things down. I see that as a minimal risk based on the well designed planning that the teams have done over the last several months preparing for this development.

Nicholas Pope (Managing Director and Senior Research Analyst)

Got it.

That makes sense.

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 (EVP and COO)

Yeah, 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'll 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 e rate per foot over the life of the well. I would expect that to look very similar. In our type curves on a, you know, 15,000 foot lateral, we're in that 30 million a day range. Adjusting around that for us in a choke management situation, that's what that would look like.

Nicholas Pope (Managing Director and Senior Research Analyst)

Got it.

That's very helpful.

I appreciate it.

Thank you.

John Reinhart (President and CEO)

Thank you.

Operator (participant)

Thank you.

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

John Reinhart (President and CEO)

Thank you for taking the time to join our call today. Should you have any questions, please do not hesitate to reach out to our investor relations team.

Have a great day.

Operator (participant)

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