Gulfport Energy Corp. - Ordinary Shares (New) Stock

Greetings. Welcome to the Gulfport Energy Corporation Third Quarter 2026 Earnings Call. [Operator Instructions] And please note, this conference is being recorded. I will now turn the conference over to Jessica Antle, Vice President of Investor Relations. Jessica, you may begin.

Thank you, and good morning. Welcome to Gulfport Energy Corporation's Third Quarter 2026 Earnings Conference Call. I am Jessica Antle, Vice President of Investor Relations. And with me on today's call are Nick Dell'Osso and Matthew Rucker. Nick will give a brief overview of our results, and then we'll open up the teleconference for Q&A.

I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements. Actual results and future events could differ materially from those that are indicated in these 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. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to Nick.

Good morning, and thank you for joining our third quarter earnings call. Starting off, I'd like to congratulate our team on our very strong third quarter results. Production, capital and operating costs all landed right in line with guidance. As you are aware, we forecasted total and, importantly, liquids production to be up meaningfully from second quarter, and we delivered on that planned ramp. In fact, liquids production represented 13% of total production in the quarter on the strength of our recent wet gas Utica TILs.

That higher value mix, strong realized liquids pricing and our disciplined cost structure translated into strong EBITDA and adjusted free cash flow, both up meaningfully from the second quarter. Similarly, the fourth quarter is off to a good start, and we remain on track to execute within our original guidance ranges. Last quarter, I said our number one priority was delivering better and more consistent results for shareholders, and a clean, predictable quarter is evidence of that focus. We're pleased with the predictability of our business and remain focused on the next phase of business improvements to generate higher returns for shareholders.

Our strategy will be built around three key value drivers: improving our capital and operating efficiency, positioning our gas to respond effectively to growing in-basin demand and growing our acreage position in areas with high return potential to Gulfport shareholders. An important first step in maturing this strategy is our plan to move to continuous operations in Appalachia. We have included a slide in our presentation this morning to highlight the value of moving to a continuous 2-rig program in Appalachia and the expected improvement to our D&C cost per foot and the near-term development of our highest return long lateral wet gas pads.

Connected to this decision is the contracting of an electric frac fleet beginning in mid-2027, allowing us to reduce diesel exposure and total completion spend. All combined, we have line of sight to reduce our D&C cost per foot by more than 20% between now and 2028. The reduced white space in our development plan, lower costs and higher liquids content all point to improved returns on capital and a free cash flow inflection in 2028. Just as important, a lower cost structure reduces the reinvestment rate required to hold the business flat. And that, in turn, raises free cash flow per share in every year that follows, not just the next one.

Related to growing in-basin demand, we're very pleased to have used our firm transport access to premium markets in the Upper Midwest to sign another supply agreement at attractive pricing beginning in Q4 2028 that supports growing demand in the region. We are maintaining floating exposure to a basis location that has historically been a premium pricing point while locking in a higher spread to that location than we have received in the past. We like the structure of retaining strategic exposure to a dynamic market we believe has further upside while establishing ourselves as an important source of supply with an attractive spread.

Combined with our 10-year agreement delivering into Ohio beginning in mid-2027, this incremental contract secures advantageous pricing for about 10% of our forecasted Appalachia production over the life of the agreements, contracted at a premium to what we have historically received for those same molecules, all using firm transport we already hold. We think this is strong evidence of the demand-pull nature of Appalachia gas markets and how marketers and customers are looking to secure available supply. One of our peers recently described acreage along the Ohio River as beachfront real estate to this growing demand. If that's the beach, we have our toes in the water at Gulfport. Our core position sits in the heart of Ohio, where new gas-fired generation and data center load are just starting to show up, and we have about 30% to 40% of our production sold in basin to benefit as it grows.

Third, from an acreage growth perspective, we closed $83 million of Ohio state land acquisitions this quarter and are finishing out our $140 million 2026 discretionary program with $50 million to $55 million of remaining spend before year-end. This will continue to add valuable life to our portfolio of attractive drilling opportunities and support our ability to run a more effective development program. This program will continue into 2027, and we expect to focus on areas that have great rock and attractive upfront bonus and royalty structures leading to opportunities for greater returns.

Looking at our SCOOP asset in Oklahoma, we're seeing some really compelling development by peer companies targeting different horizons. We believe it's prudent to reduce our activity in the SCOOP during 2027 and reassess our development plan in consideration of these opportunities beyond our historical primary target. We will work through the year to reset our longer-term development program to better capture the upside we believe exists in this acreage, while the reduction in SCOOP capital helps to fund the shift to capital in Appalachia. We will provide 2027 financial guidance concurrent with our Q4 earnings as we typically do, but want to give investors a few things to consider today as laid out in our slide deck.

As we move to a more efficient continuous 2-rig program in Appalachia, realize the savings from the e-fleet and incorporate recent high-quality acreage in the wet gas window with long lateral units, our wells drilled per year and liquids content will increase and cost per lateral foot will decrease. This, in turn, positions us to better serve our growing demand base in Appalachia and realize higher value per unit and further creates advantages in returns on expected acquired acreage. We believe this strategy will generate attractive returns for shareholders in a more sustainable fashion over the coming periods. We're not adding activity to grow volumes for their sake. We're doing it because every dollar we invest will generate more cash.

A more efficient base of operations means more efficient cash flow generation and our flexibility to allocate that cash to the highest return opportunities increases with reduction in reinvestment rate and allows us to clearly evaluate the merits of buybacks, balance sheet, acreage and drill bit. Every dollar competes on the same basis: what it adds to cash flow and value per share. For 2026, we expect adjusted free cash flow to grow more than 15% over 2025 at $3 gas. That discipline remains true in 2027. Even with low projected gas prices and the repositioning of our capital, we expect free cash flow to remain strong, still a double-digit free cash flow yield at $3 gas, and we expect to be active across the full suite of investment opportunities.

To that end, we announced today a 33% increase in our share repurchase authorization to $2 billion, having repurchased approximately $1.2 billion of our stock since the program began. And we will do all of this while maintaining a strong balance sheet. To sum up, we're lowering our cost structure and our maintenance capital, increasing cash flow per share and allocating every dollar to what's most accretive per dollar invested. Third quarter execution was on track. Continuous operations make that execution more efficient and 2027 is the investment that drives higher returns and free cash flow inflection from 2028. I'm excited about where Gulfport is headed, and I look forward to updating you on our full 2027 plan in February. Operator, we'll now open the call for questions.

[Operator Instructions] Our first question is from Bert Donnes from William Blair.

I really appreciate Slide 6. It gives us all a pretty good idea of what you're maybe thinking about next year. I couldn't help but notice the second rig is maybe targeting a smaller pad size on average. Is that by design so that you could quickly adjust it up and down? Or is that a little bit too cute? And maybe does that fit perfectly with that frac crew? Or would you need to adjust the frac crew if you move that around?

Yes, Bert, this is Matt. I appreciate the question. This is an illustrative slide for 2027. We still got a lot of work to do to shore up the budget, which we'll come out with here in a few months. But by and large, we've drilled a mix of anywhere between 3 to 5 well pads and -- that's in this program. I think any shuffling around will fit very nicely with 1 continuous frac fleet as we do have a little bit of white space in there with some wiggle room as we shift things around. So I wouldn't read too much into that and specifically around a rig drilling smaller-type pads. That will be a blend between both rigs, somewhere between 3 and 5 wells per pad.

Perfect. And then on Slide 8, you put another helpful graph where you show the economics between your wet gas and your dry gas. And you noted that your turn-in-line schedule right now is liquids-rich weighted, at least in the near term. But it looks like all it would take is a $0.20 move in gas or $0.20, maybe $1 move in liquids or something like that to flip the economics the other way. Is that something that we would look at as a '28 event where you would change it? Or do you have the flexibility to maybe impact second half '27 plans based on the strip?

We're pretty flexible. We can move things around a bit. Our highest return opportunities right now as a company are clearly in the wet gas area of long laterals. So we're going to focus there initially. And I think that will hold up through a fair amount of price sensitivity. So we have a lot of flexibility. But I've said before, I think it's really hard to think about timing your allocation of capital around the cycles of commodity prices that the cycles of commodity prices move a lot faster than your cycles of capital. So to the extent that $0.25 on gas or $1 or $2 on oil swings 1 pad to the next, you're really trying to go with your highest return opportunities at a mid-cycle price and just execute in a really well-planned fashion.

Our next question comes from Jacob Roberts of TPH Research.

Nick, I wanted to ask on the SCOOP asset. I think you guys are keeping your ear to the ground there in 2027 and kind of backing off a little bit, obviously. But just wondering what you are seeing from your offset peers in terms of zone delineation and resource development and kind of what you're seeing, what you're hearing? And then what do you think this means for your asset and inventory over time?

Yes. Great question. I'll start, and I think Matt has some stuff to add here. We're seeing a lot of capital form around the area. There's been some transactions recently with some pretty well-informed capital showing up in and around our position. That -- those producers are targeting other zones, some a little shallower than the Woodford -- and some really quite productive. And so we're pretty interested in what we're seeing from everybody and recognize that this acreage may have more value than we've historically thought about. So we're going to really try to assess that.

Yes. And Jake, just to add to that, I think some of the activity we're paying a lot of attention to is around the inventory we've talked about historically that we haven't really been drilling. And so you think about the Springer, specifically the Sycamore and then the deeper dry part of the Woodford that we have inventory located there that we have not drilled historically. We've been in the condensate window of the Woodford. We're going to take the time to assess, look into the data that we have that we participate in on a nonoperated basis, learn from that and then assess how we want to develop this moving forward.

I think I talked about this on the last call, but I would reiterate that gas in Central Oklahoma does have some pretty good value as you think about the power market dynamics. It is -- it can access markets via existing pipes. You don't need incremental infrastructure to get that gas to pretty attractive markets. And given the interest in developing data centers and new power options, Oklahoma is a really good market for that. So we'll see where that goes. But it's interesting optionality to have gas resource in this part of the country right now.

You kind of covered my second follow-up. So I'll pivot a bit there on the good ZIP code commentary. We generally agree. I guess this might be a tougher one in a bit longer term. But when we think about the illustrative 2027 and the elimination of white space, with the 2-rig cadence, I think your slides note 13 years of inventory at that pace. In the 2028, 2029 scenario when we hope to see much higher demand regionally than there is today, would you feel comfortable going back to a 2.5-rig program where there is that white space? Or are we going to be thinking about the longer-term growth dynamics of this play as trying to be as efficient as possible and waiting to add those rigs until you can kind of fill it up and maintain that 15-plus-year type of inventory?

Well, you're kind of laying out a few different theoreticals there that are a bit hard to react to in a vacuum. But I would say that we always think about allocating capital based on a mid-cycle price. And so if our mid-cycle price view were to change dramatically, then your threshold for capital efficiency as to how you think about where you're willing to invest might move. I don't actually really expect that to happen in 2028 or 2029. I think more of what you see is this continued rising of the floor of gas -- there will be moments where gas spikes up high, and those are going to be great times for our company and for our industry. But there's a lot of gas. And there's a lot of opportunities to bring gas to market.

And so I'm not thinking that we're underwriting a $5 or $6 gas strip anytime soon. I do think it will grind higher over the next few years from -- we're kind of $3.50 people. I think it will grind higher from there. And that can certainly ease up how you think about the hurdle rate from a well cost perspective. But I'm really not focused on that right now. And instead, I think we as a team are focused on how do we continue to drive that cost per foot down. That opens up the ability to invest more consistently at any point in the cycle. It opens up the ability to generate more cash from every dollar you spend, which gives you more financial flexibility in how you think about every decision from returning capital to shareholders to reducing debt to adding valuable assets to the portfolio. So that's really what our focus is right now, and we'll stay pretty tight on that.

Our next question is from Tim Rezvan of KeyBanc Capital Markets.

Nick, I want to ask about the Marcellus. Gulfport has done a pretty good job delineating the inventory in Eastern Ohio, and you've talked about 100 locations. Returns seem a bit lower, but it is still pretty an intriguing kind of liquids lever. It seems likely there'll be more opportunity to drive efficiencies here given you're newer in the drilling program. So can you talk about how activity may trend going forward as, like, a percentage of your TIL count? And/or is it sort of TBD until you get that next 2-well pad online?

Yes, Tim, I appreciate the question. I think you can kind of see that a little bit on Slide 6 in the shaded bars, we give an indication of what percentage that mix looks to be for us. And I think that's the right percentage right now. That's going to include really the core Marcellus that we've talked about, where we have the midstream and processing agreements. For 2027, it does include the turn-in-lines of the 2 delineation wells to the north. And so as we've talked about before, that's really a good test for us to understand the liquids mix in that northern acreage block that we have and the long-term productivity of the gas, so we can go to market on negotiations for a gathering and processing agreement where that acreage is undedicated.

So we'll follow a similar playbook as the core Marcellus. That's going to take some time to develop. And so as we progress those conversations, I wouldn't expect the percentage of Marcellus development to go up significantly from what we've been doing until we get that in place. And then by that time, call it, '29 and beyond, we'll have more drillable inventory ready to go. And that certainly -- that mix could change depending on market conditions. From an efficiency standpoint, I think you're spot on. We've been -- we've drilled 2 now, 4-well pads in the core area. We've seen those drilling times go down on every single pad that we've done, and we've seen our dollar per foot decrease dramatically from the first 2 wells that we did in the state of Ohio. I expect that to continue as we develop 2 more full development pads next year, and that's part of the math here on the dollar per foot that you see in our efficiency improvements for next year and beyond.

Okay. Okay. Good context. I appreciate that. And as a follow-up, Nick, in your prepared comments, you mentioned continuing discretionary leasing in 2027. I'm not trying to pin you down to a number because I know you won't give one. But is the opportunity set, do you feel like that $100 million level is that out there? Could you transact in that? And could you transact more? Just trying to understand what the opportunity set is. And I know that the Board has to decide on what that budget is, but what does that opportunity set look like, I guess, is what I'm trying to ask.

Good question, Tim. And you're right that it's a little early for us to give you a specific number here because we're going to work through our budgeting process as we typically would. But there's plenty of opportunity out there. We're excited about a lot of things we're seeing. Our team is super active. They keep in close contact with a number of different -- directly with landowners and with other brokers and really trying to assess the opportunities. And they exist across a number of different, I would call them, subparts of the play, and we'll be active.

So I'm pretty optimistic about this company's ability to continue to add great acreage to this portfolio at really attractive prices. And I think our governor will be how we think about capital allocation, the competition for capital allocation from the balance sheet, from the value of our stock from all of those things. So I think the governor will be what do we choose to do as opposed to are there enough opportunities.

Our next question is from Gabe Daoud from Truist Securities.

Nick, you alluded to this in your prior answer, but I was curious how the buyback fits into the capital allocation framework in '27. I know there's a lot of calls on capital as you run a continuous 2-rig program, as you highlighted, but curious maybe where the buyback fits.

I mean, again, it's competitive, right? We have -- we will have excess free cash flow in the year. And the way I think about that excess free cash flow is we will be looking hard at exactly how we implement this decision to go to 2 rigs and the timing of that, we will be looking hard at reducing or strengthening our balance sheet. We'll be looking hard at buybacks, and we'll be looking hard at adding really valuable acreage. And all of those things have tensioned against each other. And depending on market conditions and anticipated return of anything you're looking at, you have the opportunity to make a call. I think I like that.

I like the ability to have a number of options for where to allocate our capital in ways that generate the highest rate of return. That's what we're paid to do as management teams. And I think we have a full suite of options in front of us, and we increased the authorization so that it was clear that, that option remained relevant and on the table, and it will continue to compete against everything else that we do.

Okay. That makes sense. Appreciate that. And then just as a follow-up, going back to Slide 6, you gave us the D&C per foot and with an e-fleet locked in. And I'd imagine you contracted the second rig for a longer period of time. But just curious, like, what type of inflationary pressures, if any, are, kind of, embedded in those D&C per foot numbers?

Yes, great question. We've baked all of that in for 2027 based on our service contracts. I think on a stand-alone basis, we would have expected to see around 5% inflation for 2027 in our typical cadence of development. What's really attractive about this development plan is we've been able to offset all of those inflationary costs with our efficiency gains that we planned, both from what we're going to feel like we see on the drilling side and the frac side on being a little bit faster and better at what we do, but the ability to go sign up and lock in an e-fleet, which is significant dollar savings on an annualized basis versus us utilizing our dual fuel fleets that we've used historically. So all of that to us is really an offset. And then any increase in capital you would see next year would be all activity-based, Gabe.

Our next question is from Carlos Escalante of Wolfe Research.

That part of the question is actually a perfect segue to what we want to ask. So going back to Slide 6 on D&C per lateral, there's some clear savings that we can see on the middle chart. But I'm trying to understand, parse through what is the breakdown of those savings? How much does it come from the continuous operations versus the electric frac fleet starting in mid-2027? And then when you think about decision triggers into early '27, are there any conditions under which you'd stay at a lower cadence versus what you anticipate today?

I'll answer the second one first. Look, we're clearly headed in this direction, and we're going to start the year with 2 rigs because that's the typical cadence that we have. And so I will never say never, there's always some market conditions that cause you to rethink your capital allocation. So that's clearly why we're not giving guidance today and we want to get through winter, and we want to have the full setup of our plan laid out in front of us and make sure that we're ready to commit to a full year of this activity. We want to have all of our vendors lined up. We want to have all of the pads ready to go. And there's just a lot of detail that you have fairly well baked in November, but not completely. So we'll hold on giving a formal answer to that until we give guidance. But we're clearly looking at this hard and wanting to be moving in this direction.

On the breakdown, it's really hard to separate. They're very connected. The contract for the e-fleet really becomes a lot easier for us to have taken on when we know that we're going to be moving to a more active program in Appalachia. Those fleets require commitment. That commitment, in this case, is 18 months. And so we wanted to be in a place where we felt like we had good line of sight to having this level of activity. Now that said, we can sublease that out if we need to or work with the vendor to allow others at times if we have a pullback in activity. So we feel really good about the way that commitment is structured, but they're interlinked.

Sure. Appreciate that, Nick. And then perhaps just as a quick reminder to us on the North Marcellus and maybe how that relates to how you view the next 2 years. What is the underlying assumption of a possibly successful appraisal where you see results you like on that well? -- that go into the 2028 target and goals and whether that is -- that would pose an upside case or it would simply mean that you have more optionality in your capital allocation program moving forward?

Yes, Carlos, I think the latter to your comment there, the way we're viewing that is we've got a plan for next year that's baked, generally speaking, with our core Marcellus. We'll delineate through completions and turn-in-line the 2 Northern Marcellus wells early next year. We'll evaluate the production results. We'll go to market for our midstream and processing agreements, which takes some time. And then upon successful completion of that, I view it as more optionality in our development program. Our expectation is that this area will be very similar to our core Marcellus. And so you can think about the successful delineation there being an extension of the well set that we have currently that we're developing. So just more flexibility and optionality, and that would be something we would determine at a later date.

Our next question is from Peyton Dorne of UBS.

I thought the new gas supply agreement that you detailed was a positive. Is this something that you see Gulfport looking to expand in the future, if possible? Or maybe said in a different way, is there a certain upper bound longer term in terms of how much gas you'd like to dedicate to these type of supply agreements?

That's a great question. I think about an agreement like this as essentially a hedge. We're taking gas that we've been selling at REX Zone 3 and Chicago Citygate, and we're still going to sell it at those locations. What we've done is we've agreed to a fixed spread for our gas to that location. So the only part of the hedge that's in place is the spread we receive to those 2 pricing points. We still float at that point and just get a spread to it. And that spread is pretty attractive relative to what we've received in the past. So it's an uplift. And we like that. We didn't have to take on any more cost to do it because this is with firm transport that we already had. So this is a really good trade for us.

Again, these 2 contracts combined to be about 10%. So I think there's plenty more that we could do here. And we have had other inbounds from people trying to secure gas across Appalachia thinking about the role that Gulfport plays in that. We're going to continue to listen carefully. We're going to continue to study the market and understand how it's evolving and understand where our gas has the most value, understand where we believe the most upside is and make further hedge decisions with all of that information over time. So I do think there's more upside here.

I think Gulfport will be a beneficiary of this growing demand. And we talked last quarter about how some companies will do really long-term agreements that maybe aren't the right fit for a company like Gulfport, but an agreement like this, which is 5 or 10 years on the long end, fits much better. And again, the pricing that we can realize here is a great premium to what we've had in the past, and we're really happy with it. So open to doing more, but it has to be on the right economics.

Yes, makes sense. I appreciate all the detail there. And I just wanted to ask on the balance sheet. Debt crept up a bit this quarter with free cash flow in the fourth quarter looking like it's going to be a nice jump up. I'm curious if you're comfortable with where the current leverage stands? Or is it kind of at a point where you might try to take it down a little bit into next year?

It will be down at year-end. It will be back more towards 1x at year-end or right about 1x actually at year-end. So yes, I think, look, it's up this quarter. We closed on the big state lands acquisition during the quarter, and we had a lot of priorities this year. And we're generating most of our cash in the second half of the year, so it will come back down. Still think about that 1x is a good mid-cycle place to be. And so now that we've ticked above it here for a quarter, we would expect it to come down.

Our last question is from Michael Furrow of Pickering Energy Partners.

I'd just like to start with a big picture question for you, Nick. So now that you've had more time in the seat and a chance to really kind of look under the hood, where do you see the room for the most improvement? And are there certain opportunities that are clearer to you now than they were from the outside looking in?

Yes. I think not to beat the dead horse here, Michael, but I would just point you to Slide 6. I mean this is why we laid out all this detail in the deck. This is the biggest opportunity for the company, and Matt and I are both really excited about how this positions us for the next several years of development in Ohio. We're going to be a lot more efficient. We're going to drive our cost structure lower by better vendor contracting, by better execution, by better planning.

And we think there's an opportunity to continue to add great acreage to the business because we have this efficiency that's showing up and turn that acreage into great returns for our shareholders. So we think all of this is connected, and I go back to those 3 priorities that we're going to have, which is improved capital and operating efficiency, positioning our gas for the growing demand and adding valuable acreage to the portfolio. And I think this move that we're making here is the real catalyst to unlock that. So that's what this is all about. And yes, my confidence has grown as I've been here on executing on exactly this plan.

Understood. Appreciate the response. And I agree it's a great slide, and the benefits look pretty clear. Just as a follow-up, we couldn't help but notice the layering out of hedges for next year, particularly the additional swaps. Do you feel like the '27 hedge book is in a good place at this stage? And additionally, does the hedge protection kind of change your decision to allocate capital towards buybacks? Or do you kind of view it as a separate decision?

Separate decision. Always, hedges are -- they're a trade you can take on and off. But no, I'm happy with our hedge position for '27. It's -- I mean, given where the strip is, I'd love to have more at the average hedge price that we have. And if we were to get some cold this winter that were to pop gas prices up to an attractive level again, then I think we would hedge more. I don't really see us hedging Cal '27 at these levels. But we're always nimble around hedges. And if we like prices in a given period, we can add more. So we feel pretty good about the protection we have for '27. We're continuing to monitor basis hedge opportunities as well as think about '28 and '29.

All right. Okay. Thank you all. I appreciate everybody's time on the call this morning and all the questions. We really do have a great inflection in front of us at Gulfport. We're very excited about what's to come in 2027 and beyond. I think the setup for this company is really fantastic. So look forward to seeing you all in between now and earnings as we'll be out on the road a little bit, and then we will talk about '27 on the next quarter. Thanks a lot.

Ladies and gentlemen, thank you for your participation. This concludes today's teleconference. Please disconnect your lines, and have a wonderful day.

Greetings, and welcome to the Gulfport Energy Corporation Second Quarter 2026 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host, Jessica Antle. You may begin.

Thank you, and good morning. Welcome to Gulfport Energy Corporation's Second Quarter 2026 Earnings Conference Call.

I am Jessica Antle, Vice President of Investor Relations. With me today is Domenic Dell'Osso, Michael Hodges and Matthew Rucker. Nick will give a brief overview of our results, and then we'll open up the teleconference for Q&A.

I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements. Actual results and future events could differ materially from those that are indicated in these 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.

Please refer to the most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review at your leisure.

At this time, I would like to turn the call over to Nick.

Good morning, and thank you for joining our call, which is my first as CEO of Gulfport. I thought I'd start out with a few comments about why I'm excited to join this company at this time.

Gulfport has a great asset base in dynamic regions with rapidly growing gas demand, has a strong balance sheet and a competitive cost structure. Gulfport's team is highly talented and motivated, and the Board is experienced and knowledgeable across multiple disciplines and well suited to guide the company to additional value creation. Like most companies, Gulfport is far from perfect today. But with our assets, team and geographic exposure to growing demand, I believe it is uniquely positioned for significant value creation for shareholders for many years to come.

The most important factors to creating value for an E&P company are straightforward and well documented, have a deep inventory of high rate of return drilling opportunities, highly efficient operational execution, low operating costs and low financial leverage. Gulfport has largely been on the path to succeed on all of these fronts with significantly improved operating performance over the last three years and considerable success in inventory expansion through off the ground leasing, new development delineation and proving up the Ohio Marcellus development opportunities in the portfolio.

The recent success in the State Lands Auction and our announcement today of $140 million budget for discretionary land purchases in 2026 are two great highlights of high-quality inventory growth. That said, I believe we can continue to improve operational and capital efficiency through tighter drilling and completion execution and improved planning to mitigate risks outside of our direct operational control.

At our best, we compete with anyone in the Basin. And I think with the right approach and a focus on data and planning, we can make every point of execution best-in-class. We can also continue to strengthen and deepen our inventory by improving returns on locations we already own with more efficient execution and adding quality leasehold when and where returns are attractive, inclusive of acreage acquisition costs.

Our balance sheet is strong today, and we will maintain a conservative mid-cycle leverage ratio. We will support that balance sheet with hedges that seek to protect the capital at risk in our drilling program at all times and remain flexible to hedge more when prices are materially above mid-cycle levels.

Delivering better and more consistent results for shareholders will be our #1 priority. So you will hear our team focus on our foundation of safe and environmentally sound operations, execution efficiency, cash flow competitiveness, drilling inventory expansion and downstream market access. Given the macro dynamics of growing in-Basin demand for natural gas and to power AI data centers, we should stay focused on these crucial elements of competitiveness to create levers for future growth as demand materializes.

As we look to best position Gulfport in this strong market, we are fortunate to have a business that is generating significant free cash flow and is therefore, ready to fund opportunities to create additional value. Ongoing effective capital allocation represents the most important decision for us as a management team and Board to get right to maximize the value we can create.

Capital allocation must be competitive, and we will define the terms of competition around creating the highest financial returns and advancing our strategic goals of improving execution, deepening and strengthening inventory, lowering our breakevens, opening additional or higher-value market access, maintaining a strong balance sheet and returning capital to shareholders.

We will look at all of our activity and capital allocation decisions through this lens and optimize outcomes for shareholders as we consider drilling capital spend, investments in operating efficiency, new leaseholder acquisitions and shareholder buybacks. We recognize every dollar of free cash flow has competing uses, and the resulting tension in capital allocation allows us to consistently optimize the opportunities that create the greatest long-term value for shareholders.

We firmly believe this capital allocation model, combined with consistent industry-leading execution will drive improved returns and cash flow on a per share basis. In the near term, we have great momentum going into the second half of 2026. Our production is accelerating following our first half of the year capital program. In particular, our liquids volumes will be more than 50% higher than the first half of 2026. Additionally, we are looking forward to executing on our discretionary leasehold budget, which, when combined with the recent acreage purchase from the state land auction, increases our net Appalachia location count by approximately 20%.

Before we conclude, I want to recognize and thank Michael Hodges for his support during this transition and for his many contributions to Gulfport. Michael leaves the company in a position of financial strength, and I appreciate the role he has played in helping build the foundation we have today. After many years of service and spending considerable time on the road between Dallas and Oklahoma City, Michael has chosen to devote more time to his family.

We all understand and appreciate the need to make this decision. We thank him for his leadership and wish him and his family the very best in the future.

This company has all the tools needed to create significant shareholder value and grow our share price. I am very much looking forward to working with all the talented Gulfport employees to prudently and methodically execute on our strategy and position this company for industry-leading returns for many years to come.

Operator, we'll now open up the call for questions.

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

Nick, great to hear from you again. And Michael, obviously, best of luck. I'm sure we'll talk soon. Nick, my first question is on your inventory. Specifically, as you step in the CEO seat, could you speak to how you view your Gulfport's current inventory duration and quality and maybe what the street seems to be missing.

Yes. Great question. Thanks, Neal. I'd ask you to look at Slide 8 in our deck today. We put in there a chart that Enverus recently published, highlighting that we have one of the best weighted average breakevens of inventory across the gas space. I'm really proud of this for this company. They've worked hard to position the company to have that really high-quality inventory. And sitting at around 15 years of drilling inventory, I think the depth is pretty attractive.

Now in terms of overall scale, it's always nice to have more. But I think this company has been and will continue to be judicious about how it thinks about adding scale and ensure that we do so with a focus on value. It's pretty easy to fall in love with the idea of scale and add too much or pay too much for it. We'll be pretty careful about doing that. But overall, I think the duration of the company implied by the scale that we have and the quality of inventory that we have is best-in-class.

I do think the industry I do think the investor community might be missing some of the quality applied to the duration that we have when thinking about our position relative to our peers.

Yes, I agree with that just look at the current price. Then second question, just on execution. I know when we spoke with you last night, you all mentioned you'll continue to execute well. But with that, you'll continue to look for ways to improve upon this execution. I'm just wondering, again, being new into the seat, do you see some low-hanging fruit when you work with Matt's team around this? What do you all anticipate the sort of near and further focus will be around this?

Yes, it's a great question as well. So I'm excited about this. I think Matt is excited about this. I think the team is excited about this. As soon as I started, he and I went up to Ohio and out to the field office here in Oklahoma together, spent some good quality time with the teams, talked about the challenges they see every day. As I noted in my introductory comments, when you look at our performance, there are individual wells that we've drilled that are absolutely the best execution that you see across the industry.

My goal is to help the team have the resources, the foresight and the planning needed to deliver on that kind of performance with everything that we do. So I think it's very possible to do that. I think we've got to be really engaged with our operating teams, invest in the things that make sense to improve our processes, improve our data quality, improve our planning and give them the tools they need to do the things that they do well.

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

I resonate the message before to you, Mike, best of luck. First question, Nick, to you, knowing that you generally have a great feel for the gas macro, I wonder if you can perhaps frame your capital allocation framework into 2027 when you contrast that against an inventory expansion campaign, both organic and organically you've had over the past three years.

Yes. So the inventory expansion campaign that you see taking place over the last couple of years, but then specifically this year in 2026 is a function of a multiyear effort. The company made a decision to focus on leasehold growth a couple of years ago. And some of that took place immediately, but a lot of it takes time to negotiate leases, to develop relationships with landowners and prove to those landowners that we're going to be a quality partner and be the best person, best company to develop their minerals.

The team has done an excellent job on that effort over the last couple of years. And so what you see this year is that with a couple of years of really pushing and working all of those relationships, we have seen a wave of opportunities become available this year that we've been able to execute on. So we have really good line of sight on what that $140 million of the 2026 budget goes to and what those leases are and the fact that we should be able to complete that program this year in that size.

I would tell you that with that effort over the last couple of years, the majority of those efforts are really coming to fruition in 2026. And based on how that has evolved, I would not expect that we will see the same kind of volume in 2027. So when you think about the $140 million this year, you think about the fact that we also had the opportunity to participate in the State Land Auction this year to the tune of $83 million of successful bids. We've added some fantastic acreage.

It really does help to solidify the duration that Neal asked about in the first question and build on it. And so when we think about how we allocate capital going forward, there will still be an active leasing program, and I hope to have as many opportunities to add super high-quality locations at attractive prices every year. But realistically, it probably won't be as big as this year. And so when you think about the free cash flow available to this company, that frees up free cash for other things.

We've been buying shares, which is great. But we also have a balance sheet that sits right around 1x levered today. And I think a good conservatively run E&P company will have through cycles, that or less debt. So we'll have the ability to bring that back down so that we can be prepared for anything else that shows up in the future from a capital allocation standpoint.

That flexibility is very, very important to us and means you want to have lower leverage when you have the cash flow to bring your leverage down.

I appreciate that. And then as my follow-up, it's been generally the position of Gulfport to be a late adopter when it comes to new trends thinking about the data center and power trend in Appalachia and the demand pull that, that brings. And I don't think you feel, you don't think dissimilarly to that. So I wonder where you are today on your seat, why do you think the right approach is to be a late adopter and wait for the Basin to prove out in a way what the true magnitude of the demand pull is and play after that instead of participating head on.

Yes. I actually don't think we've been a late adopter at all, Carlos. I think the company has done a good job of positioning itself. We're a smaller cap company than some of the much bigger peers. And so naturally, when you think about the long-term partnerships that some people have been able to focus on for data centers, we're probably not going to be first on the list for that.

That said, we sell a lot of gas in Basin, and that comes with pretty attractive transportation costs. We have seen basis tighten over the last couple of months. It's tightening in the face of lower Henry Hub prices, which is not uncommon. But to be tightening at this time of the year, we think, is potentially some green shoots of where that demand is showing up in Basin. So we're really excited about what that local pricing can mean for us. The fact that we have low GP&T with some in-basin sales and a lot of flexibility about who we sell to. We think we're really well positioned for capitalizing on this trend of growing in-basin demand.

The one thing I would tell you about whether or not we're late is that these projects take a long time to come together. And they are going to be on an uncertain time line. And for a company of our size, I think there are no to being early with growth volumes in a way that would result in you seeing reduced prices for your product ahead of the demand being there. I think it would be better to allow that demand to show up and there would be a real call on our volumes rather than trying to show up ahead of time.

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

I want to share congratulations to Mike on the future. I want to start, again, going back to Slide 8, which you referenced earlier. The bar chart on the bottom right is pretty interesting, showing your next five years of development. And I think we recognize it's illustrative and subject to change. But we couldn't help but notice the percent of activity you plan on these sort of ongoing acquisitions. So I'm just curious, how much of that is driven by the HBP versus kind of drilling the best rock you have in-house?

And I'm curious on kind of the Marcellus allocation because from other materials, the returns there seem to be slightly below some of the other opportunities you have.

Yes, Tim, this is Matt. I'll comment on that, and Nick can chime in after. You're looking at that the right way. I think the HBP comment is fair. The vast majority of the acreage when we got here in 2023 was HBP. And so obviously, not a huge need to move on that in the intermediate. This discretionary acreage acquisition program over the last three years, we've talked about it being highly economic.

We look for opportunities that compete to the far left of our skyline. I think that's what you're seeing here. We're able to execute on it quickly. We're able to mass it of a position where we can put it on the drill schedule in the near term, which juices the returns. Then it's able to compete or overtake some of the existing wells that are still very low breakevens to the Enverus chart on the left, but still widely compete for capital and put us in a position to execute on that very quickly.

The Marcellus, we've talked about with that delineation and the attractive economics, that will continue to be a part of our program. It will be a smaller piece likely. The commodity price environment and the capital allocation decisions we make certainly can flex that up or down one way or the other. But we're really excited about it. And so it will continue to be a part of our program. I think what that helps us deliver is a really balanced approach to the commodity and how we think about our long-range planning.

Yes. I'll just add to that, Tim. I think you asked specifically, are these locations in our near-term drilling program just because of HBP concerns. And I would just reiterate what Matt said, which is no. What we've highlighted in this chart is that the team has been able to identify and secure acreage in some of the best areas of the play and really high grade the company's inventory to have it be in the position of the chart that we included from Enverus that shows our weighted average breakevens and the competitive nature of the company's inventory.

So this to me is one of the most impressive things about this leasehold program over the last couple of years is that the team didn't just go out and buy go pasture on the fringes of the play. Instead, the team bought actionable near-term high-quality acreage that is going to greatly improve the return through the drill bit for this company relative to where we would have been without it.

Okay. Okay. I appreciate the clarity on that. And then, Nick, I couldn't help but notice you mentioned the phrase 'execution efficiency' several times during your prepared comments. Obviously, you bring learnings from a bigger organization in the Gulfport. Is there any more context you can provide on kind of what you mean? And I guess where I'm going is Gulfport has had a history in the last couple of years of having a very front-end loaded capital program, and we've typically seen production troughing in the first quarter as a result. Do you have any views on kind of that schedule and how you're thinking about, is that part of the efficiency initiatives that you have?

Yes, I'm really glad you asked this question. I do have views on that, as you might imagine. I would frankly love to see us get to a place where we can run a more consistent program in the Basin. It's going to take some work. We need to be well planned across all the disciplines and services that need to be brought to bear in order to do that and do it effectively. But it is a goal of mine to get there. I don't know that we will get there fully in 2027. I can't give you a time line just yet. But I do believe that consistent continuous operations will drive our ability to lower our well costs and execute better wells every time that we turn the drill bit.

So I think all of that works to our favor if we can get there, but we've got to get there the right way, be well planned and not force an answer too quickly that then results in moving the wrong direction on a cost basis.

Your next question comes from the line of Peyton Dorne with UBS

On the Marcellus, it sounds like the early commentary on the new pads performance was pretty positive. At the 1Q update, you highlighted the drilling efficiency gains on the pad. I wonder if you could just touch on the completion side. And then when you look at that pad's overall well cost, how you see costs trending versus your earlier Marcellus drilling?

Yes. Sure, Peyton. I'll take that one. You noted it, we had a really good first quarter drill on that pad, four wells, 16,000-foot lateral average. We finished that in the second quarter with the same momentum on the completion side. So had a really efficient frac out there over 20 hours pumping a day. We're able to place our stages exactly how we wanted to. That well got, those pads got turned into sales at the end of the quarter and are kind of finished up flowback at this point.

We did choke those back a little bit more on the ramp-up in the cleanup phase. We believe there's some opportunity there on the subsurface side to improve recoveries. All that's looking great at the moment. We've turned the pad up to its full IP potential. It's hanging in there strong, relatively flat. What we've seen is better-than-anticipated gas rates and liquids rates, which is very encouraging because on the other side of the fence, the costs have been driven down pretty significantly on a dollar per foot basis.

So compared to the shorter laterals that we did last year, it's running about 25% lower on the D&C side on the dollar per foot. So all of that leads to a highly economic project and is reflective of how we're going to develop that asset throughout the life of the play because we've now got the playbook for our interlateral spacing as well as our preferred lateral length that we'll deploy on the rest of the acreage here. So really excited about that project with those wells and where the liquids rates have come in at.

Okay. Great. And then just as a follow-up, Nick, I believe in the commentary, you noted the opportunity there for opening greater market access. And then in Carlos' question, you kind of referenced the in-Basin sales. I wonder if you could just maybe expand upon this, what opportunities are you seeing in the near and medium term for improved market access? Is there just a desire to get more gas to different sales points in Basin or out of Ohio? Just curious if you could kind of provide a bit more detail there.

It's really about working with customers to determine how we can best help them solve their needs and making sure that we're getting gas where it needs to be. Given our overall credit rating, which was just upgraded, by the way, we're really pleased with that. But given our overall credit rating and size, we know we won't be the first choice for 15-year, 20-year contracts.

That said, we think we are well positioned to sell gas into some of these projects that are being set up right in our backyard. So we want to make sure that we are getting gas where it is available to these customers that we understand what they need, that we can be flexible in how we deliver it. I think there's lots of opportunity to do that for a company of our size in addition to what you've seen from some of the bigger companies with the really long-term contracts.

Your next question comes from the line of Gabriel Daoud with Truist Securities.

Congrats Nick and Michael, all the best to you moving forward. I was hoping we can maybe get some updated thoughts around the buyback, not only for this year, but maybe even on a longer-term basis, Gulfport last several years has been pretty active from a buyback standpoint. Is there any maybe change in how we should be viewing that moving forward?

I don't think there's a lot of change. I think the company is going to continue to generate a lot of free cash flow. And that's one of the reasons why I dwelled on capital allocation for a few minutes in my prepared comments. We'll be very thoughtful about that capital allocation. We have a handful of strategic goals for the company. And within that, we will always weigh our ability to invest towards achieving those strategic goals against the returns available in buying our shares.

Shares have been trading lower for a good part of this year. The company has been buying some stock. We will also always weigh that against where the balance sheet sits. As I noted before, this has been a pretty big spend year for Gulfport because we had some great opportunities to secure really high-quality inventory.

I don't think that we will have the volume of transactions next year to consume that much of our free cash flow around inventory growth. If I'm wrong and we do, that will be a great day, but I don't think that's the case. And as a result, I would think that we'll bring some leverage down through the year. But we will also be in a position because of the free cash flow that we generate to continue buying our shares.

We'll continue to be active with our buyback program in the second half of this year. We know we have plenty of balance sheet capacity and financial flexibility to maintain an active program, but then also keep an eye on reducing debt. So we will balance all of those things together.

I think are in a great place to, we're in a really fortunate place where we have all of these choices from a capital allocation standpoint to have this level of free cash flow, to have the opportunities to invest in the business and then to be also challenging that investment against what it looks like to buy our shares at the same time is really a great decision to be making.

For sure. That's helpful color. And then I guess as a follow-up, you talked about inventory duration and the depth of the company's position, how attractive it is. But I guess as you maybe think about portfolio optimization on a go-forward basis from both the acquisition and divestiture side, like I think folks are curious maybe your views on larger scale M&A. And then maybe as a way to fund that, you divest the SCOOP to become a little bit more of a pure play in Appalachia or Ohio. So curious, how would you respond to that, Nick?

Yes. The way I think about M&A is, there are benefits to scale for sure. But only if you get the right assets at the right price and they truly make your company better and not just bigger. You've heard me talk about stuff like this many times in the past, and my views on it haven't changed. Deals are hard. And it's not a good strategy to say we are going to go out and buy something because if you do that, you become myopically focused on that and you're likely to make a mistake.

Instead, I think our strategy needs to be and is to focus on making our business better every day. If we do that, then as opportunities show up to add acreage, to add production to grow our footprint, we will have the confidence to know that we can do it successfully. When assets are for sale, one of the things that I think companies really need to ask themselves is why they're the right buyer of a given asset. Everything that we do is competitive. And if someone is selling their assets, you know that there are others bidding for those same assets. If you're going to win that bid, you better know how you are going to pay more than someone else and make it work.

You have to have a strategic advantage. You have to have a view of what you can do with the assets differently than what others would be willing to do, and that's why you're able to win the bid. You have to be in a really strong financial position because maybe not all of your competitors are in a position to pay fair value for a given set of assets.

All of those things have to come together. You have to have a seller that is willing and like-minded. You have to have the opportunity to add value to the assets and you have to have a valuation that makes sense. Because all of those things are pretty hard to line up, you don't really go into a strategy saying we are absolutely going to do that. You go into it saying, we're going to position ourselves as the very best company in an area so that when opportunities show up, we will be the most competitive, and we can be very choosy about whether or not we want to own something.

As far as you asked about SCOOP, SCOOP is an interesting asset for Gulfport. It's an asset that hasn't seen a lot of investment over the last couple of years but has seen relatively steady production. And the production of SCOOP is in a pretty interesting geographic location. You're going to have a lot of gas come out of the Permian for a while, but we're going to continue to see gas demand around the Gulf Coast grow very rapidly. And at some point, we will need gas from the Mid-Continent to show up. The primary reason I have that view is that you're going to always be bumping up against pipeline capacity out of the Permian. It will stay full.

There is available pipeline capacity from the Mid-Continent today that for the right investment at the right time when gas prices are right, you can deliver into these growing markets for a great return. So, I really like the geographic positioning of the Mid-Continent from a macro perspective. I really like our assets. I think we need to do a bit of work on the assets to understand the right way to invest in it and think about our strategy with it. So, I would say more to come on the SCOOP, but we are intrigued by the potential of value in the SCOOP, and we've got work to do to understand that asset better.

Your next question comes from the line of John Edelman with Jefferies.

Just one taking a bit of a different angle on gas marketing. It was notable that you guys released 60,000 a day of firm transportation, about 10% of your takeaway, which makes sense given your outlook on M2 and it's something that a lot of your peers are doing in Appalachia right now. Just a few questions sort of like could you frame the free cash flow uplift opportunity there that was underlying that specific decision? And then what is sort of the opportunity to add or relinquish FT going forward? And if there's any real impacts in the near term on your GP&T rate given that offset by liquids growth, higher processing costs as well?

Yes, I'll start here, and Michael may have some stuff to add. That was a relatively small opportunity for us. I think you've got to actively manage an FT portfolio over time if you're going to create value. And when you have somebody else that has a need for a particular piece of transport and is willing to make a trade that works for you, you should do it. So I'm a fan of actively managing these portfolios. I wouldn't read a whole lot into a long-term trend of that other than active management is the trend. So Mike, anything to add.

Yes. And I would just maybe add to that. I think to Nick's point, we're looking at these on a netback basis. So this wasn't an extremely expensive piece of FT, but because we could get to a strong sales point without it, we've got strong flow assurance in the area, we just made the decision that economically, there was an uplift there. But in terms of kind of carry forward into the future. I mean, I think we really like our FT portfolio. I think we've got a good diversity there. Some of the sales points we've been getting to are very valuable to us. So we're always going to be looking for the right opportunity to add value there, but I don't think there's probably a trend that you could extrapolate from that one decision other than we're just going to stay on top of it going forward.

Your next question comes from the line of Chris Baker with Evercore ISI.

A lot of good questions. Just wanted to zero in on some of the sort of the quality aspect of the 40 locations you've talked about adding through the acreage acquisition program. Any help us just in terms of framing that up relative to the legacy inventory base?

So you'll see a handful of slides in the deck that are new this time, we really tried to highlight the quality of the recent purchases of acreage. It doesn't incorporate everything that we're buying this year, obviously, because we don't own it yet. But you can see how we've been going about it and what we've been targeting and the kind of quality we've been able to get. I would expect this year to look similar. So anything to add there, Matt?

Yes, nothing really else to add. It's bolting on to the same general areas that we've been active in, in the last couple of years. To Nick's point earlier, that's been a culmination of the last couple of years of work by the team, and that's where that execution will end up. So kind of split across our asset base areas with our high attractive rates of return, and those bars will change over time.

That's great. And just as a follow-up, I appreciate the comments around '27 acquisition opportunity set likely not being as significant as the step-up we're seeing this year. Just in terms of how to think about buyback in the second half of the year and capacity to do that, just given that step-up in investment spend. Any help in terms of framing up? I think historically, repurchases have been, call it, 80% to, I think, a little over 100% last year in terms of free cash flow. Any comments there just in terms of what we could see in the second half?

I'm going to hold off on giving any specific guidance on a quarter-by-quarter basis of buybacks other than just to note that we do expect to be active, and we're going to continue to think about capital allocation as I laid out.

This now concludes our question-and-answer session. I would like to turn the floor back over to Nick Dell'Osso for closing comments.

All right. Thanks, everybody, for joining this call. I'm really excited about what's in front of us here at Gulfport. We've got a lot of great assets. The Southwest Appalachian Basin in general, Ohio, in particular, is a really interesting place to be doing business right now. I think Gulfport with the inventory position that we have and the operating capabilities that we've showcased over the last couple of years is better positioned than anybody to take advantage of the growth opportunities for value in this Basin. I expect that to show up in our stock price. So really look forward to working with all of you over the next many years to highlight the investment opportunity that is Gulfport. Thanks again for the time this morning, and we will see everybody out on the road.

Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines, and have a wonderful day.

Greetings, and welcome to the Gulfport Energy Corporation First Quarter 2026 Earnings Call. [Operator Instructions] Please note, this conference is being recorded. I would now like to turn the conference over to your host, Jessica Antle. Please go ahead.

Thank you, Carrie, and good morning. Welcome to Gulfport Energy Corporation's First Quarter 2026 Earnings Conference Call. I am Jessica Antle, Vice President of Investor Relations. Speakers on today's call include Michael Hodges, Executive Vice President and Chief Financial Officer; and Matthew Rucker, Executive Vice President and Chief Operating Officer. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements.

Actual results and future events could differ materially from those that are indicated in these 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. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to Michael Hodges.

Thank you, Jessica, and thank you for joining our call today. Before we begin, I would like to take a moment to welcome a new leader to Gulfport that I know many of you are already familiar with. Last evening, we announced that Nick Dell'Osso will be joining Gulfport as our President and Chief Executive Officer beginning May 28. Following a thorough search process, the Board unanimously agreed that Nick is the right leader at the right time to propel Gulfport into its next chapter.

He brings more than two decades of energy industry experience, a sharp focus on operational and financial discipline and a proven track record of delivering value to shareholders. Nick is joining Gulfport at a time when the company has never been stronger, and we're excited to work with him to create long-term value for all stakeholders. Nick looks forward to engaging with our employees and shareholders in the coming months and joining us to take your questions on our next quarterly call in August.

With that said, we are off to a great start to 2026 at Gulfport, highlighted by the successful completion of our previously announced discretionary acreage acquisition program and a record quarter of share repurchase activity. I will share additional details on our land acquisition accomplishments a bit later, but we believe the swift and decisive actions we've taken over the past 3 years in the Ohio Utica have delivered significant value to the company as the demand for high-quality, low breakeven inventory across the industry continues to increase.

When combining these initiatives to grow net asset value with our ability to repurchase nearly 10% of our market cap over the past 2 quarters at prices well below the underlying value of our business, it has been a very successful close to 2025 and start to 2026. Turning to our first quarter results. It was an especially strong kickoff to the year financially as the company generated $264 million of adjusted EBITDA and $119 million of adjusted free cash flow, driven by strong commodity pricing and the continued development of our high-quality asset base.

Average production totaled 997 million cubic feet equivalent per day, which was consistent with the expectations we provided in February and keeps us on track to deliver on our previously stated full year production guidance of 1.03 billion to 1.055 billion cubic feet equivalent per day. Cash operating costs for the first quarter totaled $1.38 per million cubic feet equivalent, also in line with our expectations and similar to last year, what we expect to be a quarterly high point for Gulfport as we anticipate declining per unit costs as we move through the year.

With our production cadence expected to accelerate later in 2026, the fixed charges embedded in our operating costs are expected to decline on a per unit basis over the course of the year and land within the range of our full year guidance. For full year 2026, we are reaffirming our per unit operating cost guidance, which includes LOE, midstream and taxes other than income of $1.23 to $1.34 per Mcfe. On the capital front, we incurred a total of $118 million related to drilling and completion activity and $4 million related to maintenance land and seismic investment while achieving the significant operational success that Matt will address in his comments.

Most importantly, and as I mentioned earlier in the call, we wrapped up our previously announced discretionary acreage program, investing approximately $102 million over the past 4 quarters to add more than two years of high-quality inventory adjacent to our core positions in Belmont and Monroe counties. These acquisitions were made at an average cost of just over $2 million per net locations, significantly below implied recent valuation metrics from larger inorganic transactions in the immediate area.

We have focused our efforts over the past few years in the wet gas and dry gas windows of the Ohio Utica, areas that generate some of the strongest returns in our portfolio and where we can convert these locations into producing assets in short order. As a reminder, since 2022, our targeted discretionary acreage acquisitions have added over 4.5 years of high-quality net locations, enhancing the durability of our asset base and reinforcing the significant value uplift we are achieving through the execution of our ground game leasing program. We continue to monitor opportunities to further strengthen our leasehold footprint and increase our resource depth, and we believe these opportunities continue to rank extremely high as we evaluate the uses of free cash flow in 2026 and beyond.

Turning to the balance sheet. Our financial position remains strong, and we recently completed our spring borrowing base redetermination, adding 10% to elected bank commitments and reaffirming the borrowing base at $1.1 billion. Our trailing 12-month net leverage exiting the quarter was approximately 0.9x and pro forma for the increase in elected commitments at the end of the first quarter, Gulfport's liquidity increased by $100 million and totaled $872 million, comprised of $2.9 million of cash plus $869.3 million of borrowing capacity under our revolver.

We greatly appreciate the support of our bank group as we position the company to opportunistically deliver value to our shareholders and our liquidity position is more than sufficient to fund our development needs for the foreseeable future, providing significant financial flexibility as we continue executing on our capital allocation strategy. As I mentioned earlier, with this balance sheet strength and liquidity in place, we continue to deploy capital towards shareholder returns through our share repurchase program.

During the first quarter, we repurchased 866,000 shares of common stock for approximately $172.8 million, representing the highest quarterly investment in company history and well ahead of our previously announced plans in February.

As of March 31 and since the inception of the program, we have repurchased approximately 8.2 million shares of common stock, including the preferred redemption in 2025 at an average price of just over $133 per share, more than 30% below our current share price and totaling nearly $1.1 billion of capital returned to shareholders over the past 4 years. Over just the last two quarters alone, we have allocated over $300 million towards repurchasing what we believe to be our undervalued common stock, resulting in the retirement of nearly 10% of our shares outstanding.

Given our current valuation and the strength of our underlying fundamentals, we expect share repurchases to remain an attractive capital allocation priority and plan to maintain an active repurchase program through 2026, supported by adjusted free cash flow and available revolver capacity, all while maintaining leverage at or below 1x. In closing, Gulfport is delivering consistent financial results, maintaining disciplined capital allocation across asset bases and returning significant capital to our shareholders, all while preserving flexibility to navigate market conditions and pursue value-enhancing opportunities. With a strong foundation in place and a proven leader joining our company, we are confident in our ability to continue executing our strategy and creating durable long-term value for our shareholders. Now I will turn the call over to Matt to discuss our operational highlights for the quarter.

Thank you, Michael. Operationally, during the first quarter, the company completed drilling of eight gross wells, comprising of two Utica wet gas wells, four Marcellus wells and two SCOOP Woodford wells. We entered the year with three operating drilling rigs running and as planned, released the SCOOP rig at the end of the first quarter and currently have two rigs drilling ahead in Ohio. We plan to release one rig at the end of the second quarter, transitioning to a one-rig program in Ohio for the remainder of 2026.

On the completions front, we brought five gross Utica dry gas wells online during the first quarter, including our first two U-development wells, which continue to perform consistent with recently developed straight lateral offsets. Importantly, this activity has unlocked approximately one year of additional high-quality inventory that can be strategically placed in our future development plan, providing additional flexibility. Looking ahead, we have an active completion and turn-in-line schedule ahead of us with approximately 2/3 of our remaining 2026 turn-in-lines expected to include a significant liquids component in their production profile.

This mix highlights the company's balanced approach to developing our assets and provides exposure to dynamic market conditions, allowing us to capture value across changing commodity price environments. Lastly, I'd like to complement our team's continuous focus on operational improvements as we delivered strong results during the quarter. In the period with our highest level of activity, the operational teams executed with 0 recordable incidents or spills, underlining our commitment to safety in the environment in tandem with best-in-class operations. Our drilling team delivered an exceptional quarter, achieving incremental efficiency gains in each area of our core operations.

In the Utica, we maintained our record all-in footage per day realized in 2025. And as we continue to extend lateral lengths across our asset base, we have concentrated our efforts on improving performance in the vertical section of the drilling phase to enhance overall cycle times. During the quarter, our average top hole drilling days improved by 8% compared to full year 2025, and we set a new company record for the fastest Utica top hole drilled for Gulfport to date, completing the section in just 5.4 days.

Not only did we set a single well record, the 4-well pad delivered an average top hole record of 5.9 days per well, demonstrating the opportunity for long-lived efficiency gains. In the Marcellus, we finished drilling a 4-well pad during the first quarter and when compared to the prior two Gulfport operated pads in the area, we delivered a 20% improvement in footage drilled per day. Lastly and perhaps most notably, I'm extremely proud of our team's performance in the SCOOP and the drilling results achieved on our recent Hero pad.

On average, the team delivered the pad with a spud-to-rig release time of approximately 40 days per well, beating our internal expectation of 55 days. These results highlight the team's ability to apply learnings from our best-in-class operations in Ohio and deliver more consistent execution in the SCOOP, where drilling is more challenging. Collectively, these results underscore the strength of our operating team's leadership and our ability to consistently deliver best-in-class execution across all of our operating areas.

As we've discussed previously, the completion side of our operations has been continuing to perform at very high levels, and our emphasis there remains on maintaining those efficiencies. With that consistency, we've been able to deliver our first two pad turn-in-lines of the year on time and on budget. In summary, our operational results this quarter mirror the broader performance Michael outlined, disciplined execution, continuous improvement and a focus on creating long-term value.

The consistency we're seeing across our operating areas positions us well to support Gulfport's strategy. And with Nick preparing to join our team, we're confident our operations are well aligned to support the next phase of execution and deliver durable returns over time. With that, I will turn the call back over to the operator and open the call up for questions.

[Operator Instructions] And our first question will come from Neal Dingmann with William Blair.

My first question, Michael, is probably for you. It's on capital allocation. Specifically, how do you all think about kind of, I guess, more on a go-forward allocating for further discretionary acreage that, again, the stuff you've done seems to have fantastic upside versus your stock buybacks that you've been very active and maybe add one more twist to this, a quarter like that we're in now where probably your lowest free cash flow quarter of the year, would you consider using debt to do either of those if the opportunity exists?

Yes. Neal, thanks for the question. I think it's an excellent one. So we -- I think our approach is consistent over the last few years, and it's been to capture as many of those high-quality locations as we can. The opportunity set there, obviously, is -- it's been available to us, and I think those generate some of the highest returns when you think about being able to drill those in the near term. So I think that's been a priority for us, and it continues to be a priority.

We do believe there's still more running room there. We'll likely update the market a little bit later in the year on what we think that looks like for the rest of the year. So I would say that's been consistently a high priority. I think the equity is still undervalued. It's certainly been a good opportunity for us to get that back at what we think are attractive prices. So I'd say it's a combination of the two. The health of the balance sheet allows us that flexibility, as you pointed out, to lean on that a little bit in quarters where we may have a little bit less free cash flow.

So to your point, as we go into the second quarter, we do still have quite an active development program that Matt talked about. I think if we see opportunities to use the revolver to get some equity back at a good value, we would consider doing that. Our approach has been dynamic. I think we've stayed away from kind of formulaic approaches, and I think that's worked well for us as well. So I'd summarize it by saying it's a combination of all of them, and it's something we evaluate continuously. But the priority around locations over the last few years, we feel like it's been a strategically advantaged move for us. And we think others are actually starting to follow along more closely to that. So we'll keep you guys updated as we have more details there, but I think that that's going to continue to be one of the highest priorities.

Great to hear. Yes, your inventory sort of speaks for itself now. And then secondly, on -- kind of around Slide 6 on the marketing, you talked about optimizing the market strategy. I'm just wondering, when doing that again, how has that sort of evolved? And when you're thinking about that marketing strategy, again, do you all ever have -- is there constraints if you wanted to crank up maybe not quite in the marketing group, but if you want to -- I'm thinking more about takeaway. Is there any sort of constraints if you want to crank up production as well? So I'm kind of, I guess, twofold, maybe just how the marketing fits into if you want to expand production at all.

Yes. It's a good question, Neal. I think there's really not any constraints around that. We've got a very strong firm transportation portfolio that gives us good access to various locations. And I think that's been really to our advantage over the last few years. We've got Gulf Coast access that gives us kind of LNG type pricing. We've got Midwest exposure that we think is advantaged certainly in the seasonal period, winter season, it tends to trade very well. So we're able to sell gas locally as well.

There's obviously a lot of excitement around data center demand, and we feel like I talked about on the last call, there's some improving outlook for prices even just in the Northeast. So no constraints around being able to sell additional gas. I think we're always thinking about maximizing free cash flow. And so far, we feel like the right way to do that has been to keep our production relatively flat. Certainly, if there was a signal that, that would be rewarded or there's an opportunity to move the needle from a kind of a pricing perspective, it's something we could consider. But I think the strategy has been very successful the last few years and at least at this point, something that we feel like makes sense for our company. But yes, really no constraints around midstream or downstream markets that would keep us from considering that type of an option.

And our next question will come from Zach Parham with JPMorgan.

First off, congrats on Nick joining the team. I think that's a great hire. But my first question, I just wanted to ask, Matt, you talked a lot about drilling gains in both the SCOOP and in Appalachia. Could you unpack that a little bit more? Like where do you think we are in the evolution of those drilling gains? Like what's the runway in front of you to continue to shave days and hours off?

Yes, sure. Thanks, Zach. I think I categorize that in kind of the sixth inning, if you will, on baseball analogy. We've talked for a while about our completion side of the business, achieving things like 22 hours pumping days. And obviously, there's only 24 hours in a day. So it's really about maintaining efficiencies there. We've talked a lot about the drilling side and the opportunity set in front of us. And I think this quarter just demonstrates that focus that the team has had and the ability for us to keep clawing at that.

And what I'm most proud of is just hitting that in all 3 core areas and finding those gains, right? So when you think about the Utica, we've been doing that for a long time. And so now outside the curb and lateral, we're finding opportunities in the top hole section of the wells, which, again, are incremental days that you can kind of gain back there. The Marcellus is relatively new to us, obviously, but as a company, but not as an operating team.

And so just now on our third pad there, we've been able to see that 50% increase even with the longest laterals that we've drilled in that play to date. And then obviously, the SCOOP being able to achieve kind of the 40-day cycle times there in a pretty challenging environment speaks to more of getting us in line with being a consistent program in that asset where we feel more comfortable about continuing to deploy capital there. So yes, I think there's more room to go to be fair, but great headway so far kind of heading into '26, where that's been a key focus area for us.

And my follow-up, I just wanted to ask on inflation and if you all are seeing any inflation on service prices at this point. There's obviously been some volatility in the commodity, but we've seen some modest activity adds and talking to the service providers, they think there's more coming, maybe not so much in Appalachia, but in other parts of the U.S. Just curious what you're seeing there.

Yes. I mean, certainly, we're seeing it around the diesel. That's not only just straight fuel price, but that can bleed into things like logistics and trucking as well. I'd say that's where we're seeing the biggest move. A lot of our heavy service contracts around pressure pumping and rigs and things like that, we do a good job of kind of locking that in kind of in the year ahead or being constructive around that. So no real impact to the capital. We're not changing guidance.

I think some of these efficiencies we've talked about, Zach, have helped offset those recent impacts that we've seen kind of around the diesel. So again, we try to mitigate those things by our efficiencies and maintaining and improving those and continue to work with our service providers, certainly in this challenging fuel environment that we're in right now. But all in all, I'd say we're kind of net neutral at this point, but keeping an eye on it and certainly working with our providers as the year progresses.

We'll hear next from Tim Rezvan with KeyBanc Capital Markets.

Michael, I want to start on repurchases. You gave specific targets the last two quarters. I know you exceeded it in the first quarter. You didn't give one going forward. You used kind of ambiguous language about saying it's an attractive use of capital. And then we're looking at the first quarter, which was about half of the total for 2025. So should we just kind of think about what 100% of free cash flow is and kind of land there in the ballpark for this year? Just trying to kind of understand just I guess that's part A. And then part B is like, is there a reason you didn't put a number and a reason why you did put a number in the last couple of quarters?

Yes. Tim, thanks for the question. So I think if you think back to fourth quarter and first quarter, fourth quarter, we actually had some CapEx. We were doing some appraisal work and we had some acceleration of some capital. So I think there was logic around kind of giving a target and making sure the Street understood that we were not borrowing against what we'd otherwise allocated to share repurchases that we felt like that the accelerated capital was in addition to that.

So I think that was really the thought process there. We got into the first quarter, saw some opportunity in the equity, of course, and also had the wrap-up of our discretionary acreage program. So those were really the quarters where we gave more of a target. And then to your point, we ended up exceeding it here in the first quarter because we saw some opportunities with a block that we were able to pick up and also just some changes in what we felt like was the underlying value versus what the opportunity to buy it at was. And so that was really the strategy there.

I think if you think about us going forward for the rest of the year, really more consistent, I guess, with what we've done in the last 4 years, which is think about things on more of a full year basis, not marry ourselves to a formula of try and be dynamic around it. We won't kind of allocate quarter-by-quarter. We do think about it on more of an annual basis. And then also the balance sheet, I mentioned being 0.9 of a turn gives us some opportunity with a lot of free cash flow coming later this year.

So we talked about we've got a lot of liquids development coming up. We certainly see the environment for liquids pretty positive right now. So I don't think we will kind of allocate all to the later part of the year. I think we'll kind of see what near-term cash flows look like, whether that's second quarter, third quarter, even into fourth quarter, and we'll see where the equity trades and kind of allocate accordingly. So I understand it's a little bit ambiguous. I think it's kind of intentionally that way because we want to be dynamic around it, but we do see a lot of value there and plan to continue with the repurchase activity.

Okay. Okay. That makes sense. And then as my follow-up, just on that theme of liquids. I know you put a bar chart on Slide 9 of your deck, kind of showing the increase in liquids skew. Can you just help us kind of ballpark think about that? Do you think about that as like a 15% sort of exit rate or a back half liquid skew? And then where I'm going with this is, I know it's early and you have a new CEO coming, but do you feel like that's a better rate? You talked about getting balanced, but you were about 9% liquids in the first quarter. So should we assume you're kind of going to lean in and maybe that could be at a 15-plus percent level going forward? Just curious any thoughts around that.

Yes. I think it's a good question. I think the nice thing as we sit here is that we have the option to make those changes. So I think thinking back a few years ago, Matt and I joined, I don't think Gulfport had that flexibility in the program. So in answer to your question, I think those things are available to us where they weren't previously. I think as you go through the rest of the year, you're right, we will become a little bit more liquids heavy. We've got a couple of wet gas Utica wells or pads coming up. We've got some Marcellus development coming up.

Matt mentioned our SCOOP, which has a liquids component. So there's a fair amount of liquids coming online for us at a very opportune time. And obviously, as we go into '27, we can start to make those decisions as well. In terms of can we be 15% liquids, I mean, certainly, we're a gas company, and so you've got a mature asset base that moving that needle maybe to that level is a bit ambitious. But I do think you'll see as we go through the year, us going to more of a low teens type of a liquids percentage with the opportunity, Neal -- or I'm sorry, Tim, over time to take that even higher. But I think, again, probably for this year, it's back half weighted, call it, low teens, and then we'll assess where we want to go for 2027.

Our next question will come from Carlos Escalante with Wolfe Research.

I'd like to ask my first question to you, Matt, on the North Marcellus pad or appraisal that you're drilling later this year. What is -- if you can outline this for us, do you think it's the gross resource that the well spud is testing for? And what's the EUR you need to see to justify a programmatic Marcellus North development versus consider maybe a one-off Sci test. I know that there is some production from one of your competitors up there that looks good, but wondering if you see anything in particular in your specific area.

Yes. Sure, Carlos. Thanks for the question. I would bracket that, Carlos, it's not as much delineation for us. I think when we think about what types of EURs and deliverability we'll see there, we approximate it very similarly to our Marcellus South. Quite simply for us, it's a new pocket of development with not an infrastructure component at the moment with a third party.

And so when you think about that, we're kind of going into there, not guns a-blazing, but we're going in with a 2-well approach, kind of one north, one south to really just confirm our assumptions and make sure the liquids percentage, both NGLs and oil and composition of that are -- we understand it so that we can then go into a broader negotiation with our potential midstream providers to get the best economic output for that, that block of acreage that we have. So nothing we need to see to pull the trigger. I would tell you, it's more of a let's just confirm our type curve from a liquids weighting perspective and then immediately go into kind of those contract negotiations with a midstream provider and a processing provider to really unlock that development and set good economic parameters around it.

That's very helpful. And then a quick follow-up and more miscellaneous question, Mike. On hedges, you're targeting roughly 30% to 40% of hedge coverage on 2027. Presumably, you would start to work on that in the near term. But wondering at what NYMEX level do you accelerate that or you contract that? And is there a floor below which you choose to stay unhedged on the view that the curve is too low, which you can make an argument that there's a case to be made that, that could be true.

Yes, it's a good question, Carlos. I think on the hedging side, we try and remain flexible with that. So your observation on where we sit for 2027, I think we've talked previously, we kind of like to be in that 30% to 70% range as we enter a year. So we're near the lower end of that if you think about '27. Obviously, we've got 6, 7 months left here in 2026. I think we're pretty bullish on gas going into next year.

I think the volatility that we saw earlier this year and that some of our peers have talked about really indicates that there's going to be opportunities to create value through the hedge program. So I think for us, we like that we have that baseline amount in place already for 2027. And from here, I think we can just nibble when there's opportunities. So I don't feel like we have to go do anything or that we're going to be kind of pushing to increase that, maybe as you mentioned, in the near term unless we see some of those.

And typically, this time of year is perhaps not where you get a lot of those opportunities. So as we get into next year, we'll continue to adjust. There's been years where we're a little bit more bearish and we're at the higher end of the range that I described, and there's been years where we're a little bit more bullish. Right now, I'd say we're a little on the bullish side. So we may keep that a little bit lower, but it will be kind of a dynamic process as we continue to assess what '27 looks like.

We'll go next to Jacob Roberts with TPH.

I wanted to start on the SCOOP. Obviously, some decent results there. But just wondering, you guys have said in the past that the SCOOP was competitive with your Northeast assets and the implication here is that it's become even more competitive. Just wondering what you're needing to see in the market to allocate a more meaningful amount of capital to that asset and maybe even where you see this asset participating in that growth scenario or the market to call for it that you spoke about.

Yes, sure. Thanks for the question, Jake. I'll start. Michael can add his comments. I think the results here that we're talking about on the drilling side are a great step in the right direction for us. We've talked about it for the last couple of years is really for that SCOOP asset is finding the operational execution consistency, and so if we're able to get those drilling days kind of 40 sub-40 and do it consistently and repeatably, it certainly gives us a lot more confidence in that asset if the time calls for us to accelerate some activity there.

And so as you think about it in our entire portfolio on a single well IRR, it certainly does compete. When you start to blend that in currently, it's still a capital-intensive asset with longer cycle times. And so we're very mindful of that as we think about kind of our calendar year cadence and what that does for the company. So we still -- we look at that on an annual basis.

I think for this year, we'll get these wells completed and turned to sales here sometime later in 2Q, and we'll evaluate those results. And then it will be part of our program moving forward. To the extent we look to flex into that more in the later years, I think that's something we'll always be looking at as part of just our overall capital allocation program. But really, it's about just seeing that consistency every time we go to drill, Jake. And with this one being the best one we've done so far, we'd certainly like to see that again before we make any radical changes around that.

That's helpful. And then on the follow-up, I wanted to touch on the liquid hedging. I saw you guys added some swaps in addition to the collars on the oil side during 2027 as well as some propane swaps through 2027. So just wondering what the thinking is there? And then should we expect that number to move higher throughout this year?

Yes, it's a great observation there, Jake. I think, obviously, that market has improved here in the last couple of months, and we really didn't have a lot in place for that component of our revenue stream. So I think we saw an opportunity there to put a position in. And again, I think from our perspective, we like to be somewhere in that 30% to 70% range that I mentioned earlier.

And so we saw that and kind of layered those in. I think that's an area where you kind of have to monitor all the geopolitical events and decide whether or not you think those get resolved in the near term or a little bit longer term. We're not going to try and get too cute with it. So I think if there's opportunities where we feel like we can capture a little bit more value, we could do that. But I do think we made some good progress looking out into next year at some prices that are, quite frankly, very attractive based on kind of where we've seen realizations for both WTI and NGLs.

And then we'll kind of assess our program for 2027, as I mentioned earlier. And so to the extent that we want to continue to lean in on the liquid side, we have unhedged barrels potentially there that you could always kind of shift around. And of course, that's a way of kind of adjusting your hedge percentage just through your own activity. So I think that's one that we'll continue to monitor as we think about what the right blend for 2027 looks like.

Moving next to Peyton Dorne with UBS.

First question on my end, maybe for Mike. Gas pricing was really strong in the first quarter. I'm just curious if you could provide maybe some color on how you see differentials sort of trending here in 2Q and then maybe how you see them shaping up a bit as we progress into the summer months?

Yes. Peyton, thanks for the question. I think I do want to give a pat on the back to our marketing team. So I know a number of the operators in the Northeast saw some opportunities with the setup going into February and capturing some of the first of the month pricing. I think our team did an excellent job following suit there and certainly led to some pretty outstanding differentials and overall realizations for the quarter. So that's something that we work on consistently here.

It doesn't get a lot of airtime just because it's a pretty routine process, but we sit down and go through that. I think as you go out, I think we're still bullish on differentials overall, something that we talked about on the last quarterly call, and I think some of our peers are starting to talk about as well that a lot of the demand that we're seeing coming in the Northeast, specifically around the data centers and the power demand seems to be lifting that long-term view on basis in the Northeast.

So again, it's an important component of our differential. We certainly have exposure to the Gulf Coast and the Midwest. But still do have some of that Northeastern exposure that we think is only going to rise going forward. So our full year guide on differentials, we feel is still appropriate. I'll be honest, I think that there's some opportunity for some improvement there as we go into later years, '27, '28, some of that demand starts to show up. And those are meaningful to our company. If you think about just even a $0.05 move in differentials and what that could mean to the bottom line in terms of free cash flow and EBITDA, it's pretty important to us. So yes, I think where we're setting up for the year is really good, but do feel bullish about where things are headed in the future.

Great. I just want to go back to the Valerie pad in the Marcellus. It was nice to see the drilling efficiencies that you guys, the team obtained there. And I know you had changed the completion design a bit in the Marcellus when you went from the Hendershot pad to the Yankee pad. You targeted the formation a bit differently, too. So I'm just curious how you might have attacked Valerie and then what learnings you kind of incorporate into that pad from both Hendershot and Yankee for this most recent one?

Yes, sure. I mean some of the completion design changes or testing you spoke of was more around the Hendershot was kind of a 2-well, one in each direction, unbounded delineation test initially. And then with the Yankee that we did last year, the 4-well pad was more of a true development on our spacing assumptions. I'd say we certainly learned a lot from that. I think it kind of confirmed our spacing assumptions where we wanted them to be. I would tell you that the designs around the Valerie are more about optimizing the economics of that.

And so you think about the well spacing and how much sand you need, how much water you need, to effectively drain that wellbore. We took those learnings and kind of applied it here to look at the best economic outcome. And so on this pad, that's what we did. And then kind of with the ability to have 4 wells, there's -- we did a little bit of incremental testing on two of the inter laterals that we're looking at as well, just minor tweaks to, again, just continue to get more economically efficient there. So more to come with that, but that's kind of the evolution of what we've been doing there to your question and look forward to sharing those results later in the year.

We'll go next to Gabe Daoud with Truist.

Congrats on bringing Nick aboard. I was wondering, maybe, Mike, on the back of your comments to the last question around in-basin pricing improving later this decade. I guess on the back of that, is there -- are there any transport agreements that could be rolling in that period where you would, I guess, let roll to provide a tailwind to the cost structure and margins?

Yes. I mean it's a good question, Gabe. I mean we're always assessing kind of what we have, and there's always smaller pieces within the portfolio that sometimes aren't as critical. And I would say that you consider letting go from time to time that do help a little bit. There's also opportunities you guys are probably aware to optimize your book and even offload some of those on a shorter-term basis to other operators maybe that need space.

So I think there's I think as basis improves in the Northeast, there's probably more of those kind of netback decisions that you can make around your firm portfolio and whether or not it makes sense to hold all of it. But I would tell you that just kind of from a strategic perspective, we feel really good about the diversity that we have and the exposure to the different basins. So I don't know that I would forecast us making significant changes.

I mean, having the exposure in the Midwest, having the exposure in the Gulf Coast, just even the diversity from a risk mitigation perspective, I think, makes a lot of sense. So I think, yes, maybe to summarize, there's probably some small improvements that you may see on the cost structure just even within our portfolio around our Northeastern position, but nothing that I would say would be a wholesale strategic shift for Gulfport at this point.

Got it. Got it. That's helpful. Makes sense. And then I guess just as a follow-up, your discretionary land program has been pretty successful over the last several years, extending inventory life. Just curious, how should we think about that program for '26 and moving forward?

Yes. I'm glad you asked, Gabe. It really has been a big part of our success over the last few years. I think we're actually in the process right now of formulating our thoughts around it. We do like to have a very clear path when we come out and talk about it. We do think there continues to be some exciting opportunities around the basin. So it's typically been something we talk about around the midyear.

I know our next call is likely to be in August. But over the last few years, I think we've done somewhere between $50 million and $100 million of discretionary acreage programs. I think to the extent that we've been successful, which we have, I think we like that allocation of capital, like I talked about earlier. And I think there's a strong likelihood that we'll have something to talk about midyear that's a pretty exciting opportunity to capture more land this year.

So it's not unlimited. I mean, there's certainly -- you have to be smart about it. There's areas that we feel like we can find locations that move into the near-term development plan, which really is what enhances the economics the most. And so it's really not a carpet bombing exercise. It's us going out and trying to make sure that we have that line of sight before we allocate the dollars. So we'll talk about it more later this year, but you can probably sense in my tone that I'm pretty excited about what we'll have to share later on.

And this now concludes our question-and-answer session. I would like to turn the floor back over to Michael Hodges for closing comments.

Yes. Thank you, operator, and thanks to everyone for taking the time to join the call today. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. This concludes our call. Thank you, and have a great day.

Greetings, and welcome to the Gulfport Energy Corporation Fourth Quarter and Full Year 2025 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Jessica Antle, Vice President of Investor Relations. Thank you. You may begin.

Thank you, Melissa, and good morning. Welcome to Gulfport Energy's Fourth Quarter and Full Year 2025 Earnings Conference Call. Speakers on today's call include John Reinhart, President and Chief Executive Officer; and 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. Actual results and future events could differ materially from those that are indicated in these 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. Please refer to our most recent earnings release and our investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review at your leisure.

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. I'll begin my comments with a discussion of the 2026 development program we announced yesterday with our earnings release, followed by an overview of the 2025 results. Building on our consistent operational execution, successful discretionary acreage acquisition programs and strong financial performance, our 2026 outlook is centered on prioritizing our most attractive opportunities and allocating capital to maximize value.

This year's development program is focused on sustaining the company's exposure to a constructive natural gas environment. And as such, we plan to center the majority of our development efforts in the dry gas and wet gas windows of the Utica. These development areas represent our highest return wells at today's commodity prices and we forecast more than 75% of our 2026 turn-in-line program to be weighted to these 2 areas.

As a reminder, the Utica wet gas which ranks as the most economic development area in the company's portfolio has been a key focus of our inventory adds over the past few years, and this planned development activity reinforces our success of adding high quality, high-return inventory that supports near-term development. We remain consistent in our capital allocation framework and continue to believe the most attractive uses of our available free cash flow our discretionary acreage acquisitions, highlighted by today's announcement of the expected successful results of our existing program and the continued repurchase of our undervalued equity. We expect to maintain an active repurchase program through 2026, and our strong financial position provides maximum flexibility as we intend to utilize both our adjusted free cash flow generation and available capacity on our revolving credit facility to opportunistically repurchase our equity while maintaining an attractive leverage ratio of approximately 1x or below.

This includes our announced plan to deploy more than $140 million towards repurchases in the first quarter of 2022. And reflecting our confidence in the value of our business and the upside we see in our equity today. Total capital spend for the year is projected to be in the range of $400 million to $430 million which includes $35 million to $40 million of maintenance land and seismic investment. Embedded in this program is approximately $15 million targeting base production improvements across both basins, which includes highly accretive workovers aimed at enhancing long-term well performance and reducing natural production declines.

In addition, we plan to invest an incremental $10 million in the Marcellus North development area when compared to our 2025 full year spend directed at drilling 2 wells in Jefferson County, Ohio during the second half of 2026 and then to be carried as DUCs into 2027. This activity is aimed at confirming phase window and production mix, which will support future development planning and midstream evaluation across our substantial inventory positions in both Jefferson and Belmont Counties.

With respect to our maintenance land and seismic investments, this spend includes approximately $5 million directed towards acquiring proprietary 3D seismic in 2026 and that will facilitate improved well planning in our targeted Monroe County discretionary by area. The company currently forecast approximately 60% of our drilling and completion capital will be deployed in the first half of 2026, with the activity trending slightly lower in the third and fourth quarters.

We will continue to execute on our current discretionary acreage acquisition program, primarily in Belmont and Monroe Counties. Driven by our recent success, we now expect to achieve the high end of the previously provided range, investing approximately $100 million in total, of which $62.9 million was deployed at year-end 2025. We plan to conclude this program during the first quarter of 2026 and upon successful completion, we expect to add over 2 years of core drilling inventory at our current development pace. These acquisitions are being made at approximately $2 million per net location well below recent valuation metrics implied in larger inorganic transactions in the immediate area and reinforces the significant value uplift we are capturing through these attractive organic leasing efforts.

Since 2022, our targeted discretionary acreage acquisitions, successful execution of new development on our -- excuse me, Utica position and delineation and development efforts in the Marcellus have collectively unlocked substantial value across our core assets. The discretionary acreage acquisition and new development initiatives by the end of the first quarter of will have added over 5.5 years of high-quality net locations in addition to the 4 years of delineated net Marcellus locations.

In total, the company will have expanded our gross inventory by more than 40%, and we'll continue to monitor opportunities to further expand our resource depth. Turning to production. We forecast our development program will deliver 1.03 million to 1.055 billion cubic feet equivalent per day in 2026. And relatively flat over our full year 2025 average. This outlook incorporates several temporary factors, including known production downtime associated with simultaneous operations of an offsetting operator as well as planned third-party midstream maintenance in the first quarter of 2026.

In addition, winter storm created weather-related downtime that modestly impacted full year volumes and is incorporated in our full year production guidance. Importantly, these impacts are short lived. And as we move through 2026 we expect production levels to strengthen as new wells come online and these production impacts abate, which positions the company attractively for an improving commodity environment. Reflecting this momentum, we forecast fourth quarter 2026 production will increase approximately 5% compared to the fourth quarter of 2025.

In our investor deck on Slide 11, we include a more detailed outlook on our expected 2020 capital and production cadence Shifting to the company's 2025 performance, Gulfport delivered another year of strong operational and financial performance, strategically expanding our high-quality resource base and remain consistent in our commitment to returning capital to shareholders. After adjusting for free cash flow utilized for discretionary acreage acquisitions, the company returned more than 100% of our adjusted free cash flow to shareholders through common stock repurchases during the year, all while maintaining a solid financial position with leverage below 1x at year-end. Full year 2025 capital expenditures -- excluding discretionary acreage acquisitions, totaled approximately $463 million, including $354 million of base operated D&C capital expenditures and $35 million of maintenance land spending with production for the full year, averaging 1.04 billion cubic feet equivalent per day.

In the fourth quarter, we completed the drilling and completion of our first development well in the Utica. These wells were successfully drilled, fracked and recently brought online during the first quarter. Early results are encouraging with the performance tracking in line with expectations and consistent with recent traditionally developed dry gas offsets.

In closing, 2025 represented a solid year of execution for Gulfport with operational performance supporting attractive adjusted free cash flow generation, inventory expansion and consistent capital return through equity repurchases. As we move into 2026, our story remains the same, prioritize our highest return opportunities, deepen our high-quality resource base and grow sustainable free cash flow that can be used to continue delivering meaningful returns to our shareholders.

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

Thank you, John, and good morning, everyone. I'll start this morning by summarizing the key components of our fourth quarter financial results, which highlight the company's strong financial position as we close out 2025 and and began 2026 with considerable momentum that has translated to an excellent start to the year.

Net cash provided by operating activities before changes in working capital totaled approximately $222 million in the fourth quarter more than double our capital expenditures for the quarter. We reported adjusted EBITDA of $235 million and generated $120 million of adjusted free cash flow during the quarter. With this strong cash flow generation supporting our significant common share repurchases and active discretionary acreage acquisition program, all while maintaining the strength of our balance sheet at year-end leverage of 0.9x. Total cash operating cost for the fourth quarter totaled $1.25 per Mcfe in line with our full year 2025 guidance range and supporting our outstanding margins for the quarter.

As John mentioned, we continue to prioritize development of our high-return Utica wet gas assets, which resulted in a higher weighting of NGLs in our production mix in the last half of 2025 that we expect to continue into 2026. As a result, we are forecasting a slight increase to our 2026 per unit LOE and midstream expenses, including gathering, processing, transportation and compression costs over the full year of 2025, from the continued development of our high-margin liquids-rich assets. We currently forecast per unit operating costs to be in the range of $1.23 to $1.34 per Mcf in 2026 and with the top line value contribution from increased NGL production and our improving gas price differentials, which I'll highlight shortly, more than offsetting the slight change in operating costs and ultimately leading to rising cash flows.

Our all-in realized price for the fourth quarter was $3.65 per Mcfe, including the impact of cash-settled derivatives and a $0.10 premium to the NYMEX Henry Hub index price. While we have experienced significant volatility over the past several months, we continue to believe we are entering an exciting period for the natural gas market, supported by LNG export growth and increasing natural gas-fired power generation driven by rising power demand from the build-out of new data centers. These more permanent structural shifts, along with the recent price strength following Winter Storm Fern, are expected to derive meaningful improvements in our natural gas price realizations going forward.

As such, based on our marketing portfolio for our natural gas and current forward markets, we have tightened our forecasted natural gas differential for full year 2026 by 25% compared to 2025 and we currently forecast to realize $0.15 to $0.30 per Mcf below NYMEX Henry Hub for the full year 2026, further bolstering our free cash flow outlook for 2026. With respect to EBITDA and adjusted free cash flow generation, the rise in expected natural gas prices and our improving outlook for realizations, when combined with our returns-focused capital allocation, position 2026 to provide incremental growth for Gulfport from a cash flow perspective.

Based on current strip pricing, we forecast our adjusted free cash flow has the potential to grow significantly when compared to 2025, providing substantial financial optionality and allowing us to allocate additional free cash flow to the most accretive opportunities and further strengthen our already top-tier free cash flow yield relative to our natural gas peers.

Turning to the balance sheet. Our financial position remains strong with trailing 12-month net leverage ending the year at below 1x. As of December 31, 2025, our liquidity totaled $806 million comprised of $1.8 million of cash plus $804.3 million of borrowing base availability. The strength of our balance sheet and our strong financial position today provide tremendous flexibility as we are positioned to be opportunistic should situations arise that allow us to capture value for our stakeholders. When coupled with the meaningful growth in our expected free cash flow generation in 2026, we are well positioned to continue our track record of returning capital to shareholders through our equity repurchase program and investing in highly accretive discretionary acreage acquisition opportunities.

During the fourth quarter, we repurchased 665,000 shares of common stock for approximately $135 million, ahead of our previously announced plans in November and inclusive of a direct repurchase of common stock from our largest shareholder, totaling approximately 46,000 shares, which allowed us to capture a larger block of unrecognized equity value at a discount to market prices without impacting our public float. As of December 31 and since the inception of the program, we have repurchased approximately 7.4 million shares of common stock, including the preferred redemption in September of 2025 at an average share price of $125.19, nearly 35% below our current share price.

We believe our consistent and disciplined approach to repurchases has created substantial value for our shareholders, and we will continue to evaluate opportunities where the return profile is clearly compelling. Given our current valuation and the strength of our underlying fundamentals, we see continued share repurchases as an attractive allocation of capital.

Accordingly, and despite our normal front-weighted capital cadence, we announced our plans to allocate more than $140 million to repurchases in the first quarter of 2026. And -- to be funded from adjusted free cash flow and available revolver capacity, all while maintaining leverage at or below approximately 1x. Assuming successful repurchases during the first quarter, we will have repurchased approximately 7% of our current market capitalization in just the fourth and first quarters alone.

In summary, Gulfport exited 2025 with strong operational momentum a resilient balance sheet and an asset portfolio that continues to improve in both quality and depth. Our disciplined approach to capital allocation combined with an increasingly constructive natural gas backdrop, position us to deliver meaningful adjusted free cash flow growth in 2026. This financial strength provides a significant flexibility to continue returning capital to shareholders and to invest in highly accretive opportunities and enhance long-term shareholder value.

With that, I will turn the call back over to the operator to open up the line for questions.

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

Michael, maybe just something on -- you hit you first just on the question on the forecasted -- improved forecasted price realization. Is this -- you just were talking about and was very positive. Are you locking in now some basis hedges are you doing other things now to capture these improved realizations? I guess that's kind of my first point. And then remind me again, make sure I understand what is giving you all the confidence for these improved realizations or these improved price realizations.

Thanks for the question. I'll hit the first part. Certainly, we are active with our basis hedging program. I think we've got some disclosures out in our release that will indicate, yes, we've been doing some basis hedging. I think that's been a part of our program over the last few years, and we have an idea of where we think there's value to capture there. And tend to be opportunistic around those moves and certainly have seen some improving opportunities. I think that really leads into the second part of your question is, what gives us the confidence? I mean it's a few things, right? I mean I think -- we have seen rising demand in those kind of local Northeastern basis markets. I think that's starting to flow through to some of the indexes.

So if you think about where some of the most liquid Northeast indexes trade. We've seen those come in. And I'm talking about kind of in the out years, we've seen those come in $0.15 or $0.20 over the last 30 to 60 days. I think that's an indication of that rising demand. So that's giving us additional confidence I think the winter storm that we saw in the first quarter, I think a number of operators realized some benefit from that. I mean I do think sometimes that we forget that those periods of volatility provide a lot of value when they occur, they're certainly unpredictable. But -- so I think you'll see that flowing through into our realizations. And then I think we're always on the lookout for ways to maximize value through our marketing team and -- and there have been some opportunities to do some smaller deals. I know some of our peers sometimes look for the big wins, but we've had some opportunities to do some smaller deals with some folks that aggregate gas in order to provide supply, and those typically provide an uplift to the index price as well. So I'd say it's a combined effort from those things, but we do feel good that going into this year, we should see a meaningful improvement in our realizations.

Great details. And then Secondly, John, maybe for you or Matt, just a question on sort of infrastructure and things you were talking about today, you mentioned, I guess, even again today, some potential downtime. And I know you've talked about sort of some third-party issues in the past. What -- could you talk about -- I forget did you say today, you'll have some near-term production impact? And then again, it seems like you guys have been addressing a lot of these internally things that you've been addressing sort of what gives you the confidence that a lot of these issues will just be near term? Or what should we think about sort of that third-party issues?

Yes, Neil, thanks for the question. I guess, first of all, I'll set out -- it was discussed in the last quarter, how are we going to plan to mitigate this these kind of occurrences that have happened really last year was initial meaningful 1 that happened. What I'll say is outside of just closer coordination with our contractors and vendors, we're really focused on just creating optionality within our development program in various areas in the dry gas areas and the wet gas areas, we cover a lot of ground over these areas. And I think just building in some flexibility with how you develop these wells considering how the offset operators develop. I mean -- it also helps the midstream partners kind of plan around a flatter type growth profile, more manageable.

So how you mitigate it long term is really just create more optionality, and we do that through planning and through our discretionary acreage program. I think overall, whenever we talk about the impacts to 2026, they are short term and they were planned. We forecasted those out. We poised what those generally would be in the first quarter. And that's just generally around midstream downtime maintenance, compression maintenance. It's substantial whenever you think about the duration of 5 to 6, 7 days at a time, and then you have to bring on wells the volumes are pretty impactful, but it's only for a week or so, given a couple of different maintenance items -- the winter storm warning in combination with these planned maintenance and SIMOPS downtime, Neil, it's around approximately 10 million cubic feet impact for the day for 26. That's built into the budget. So it was a more meaningful impact in certainly late Q1 and into early Q2. But that's represented in our slides in our public deck when you look at the production cadence. We certainly, as you look out through the year, expect those to abate. And then with additional turn-in lines, you see a significant improvement in our production cadence from Q4 to Q4, about 5%, which really positions us well for winter pricing and what we feel like is going to be a constructive 2027.

Our next question comes from the line of Carlos Escalante with Wolf Research.

I wonder if I could take Neil's question a step further because obviously, we all realize and comment for your efforts on improving your differentials year-on-year. But it's been clear after a few weeks of listening to your peers that there's an overall willing unwillingness from them to take an improving basis at the back of growing local demand -- it seems like most of them are positioning to grow with proactive discretionary capital ready to be deployed.

So I was wondering if you can perhaps elaborate on your game plan on that context and maybe in the basis of do you consider growing at some point in the future?

Carlos, this is Michael. I'll take the first part and John can certainly jump in. But I mean, I think it's a good question, right? I think when we look at pricing and think about the right development cases for Gulfport, we're thinking about to your point, not just index pricing, but also differentials. And so the move that I've described this morning on the differential side, is meaningful for us.

On the other hand, I mean, for us to consider significant changes to our development cadence, we'd be looking out the curve and probably for a more significant change that would incentivize some kind of growth. So -- if you look back at our history, we've traditionally been, call it, a flattish, low single-digit type company that maximizes free cash flow. And I think that's played out really well for us. I think that it helps us to kind of be consistent in our messaging. And I think that a lot of our investors like what they get from Gulfport I think if you saw a structural shift that was, again, longer term and that was more meaningful, maybe you see some index price change beyond just what the strip shows out the curve. I think that's always an option to the company.

But I think maybe why you're not seeing that from some other peers is that it's been a pretty subtle change to this point. I do feel bullish about it going forward. But I think we need to see more of that before we would likely adjust our strategy in the future.

I appreciate the color, Mike. And then for my follow-up, a quick one. housekeeping item. Can you perhaps list for you, I think, Matt, give us an update on what you're seeing on the tail end of the type curve for the Henderson and the Yankee patch. Just wondering how those are developing now a few months out of their first production. And maybe if you can provide any color on if you've seen any kind of similarities in your Northern Marcellus position relative to these...

Yes, Carlos, happy to take that. I think last quarter, we showed kind of the 60-, 90-day plus on those. Obviously, the cumulative plots look very strong and attractive and similar to the Hendershot, if not slightly better on initial cume -- for us, it's really just confirming the type curve. These are both pads are on decline to their international decline state. They mirror kind of the type curve that we've built for that area as part of our development planning.

And so no significant upside changes, obviously, in a decline environment, but also for us, they're holding in very strong. And so they support the long-term type curve on our well spacing and our development plan for that area. As you think about the Marcellus North, we think it's approximate. We think that acreage is on par, obviously, with our south position and has been delineated by some other operators a little bit further to the north. And so leading into this kind of discretionary area spend this year will really just be to John's point earlier, more for us to get a better handle on the liquid mix which will enable us to then look at our midstream contracts and negotiations where we can then deploy full-scale development there like we did in the South.

Our next question comes from the line of Zach Parham with JPMorgan.

You mentioned buyback more than $140 million in shares during 1Q that comes on the back of buy back a lot of shares -- can you just unpack that decision a little bit more? How did you decide on the malnostock demand during 1Q? And could you just comment on how much of that you've bought already quarter to date or have you been active in the market? Just trying to get a sense of how aggressive that buyback is going to be over the next month?

Yes. Zach, this is Michael. Happy to dive into that a little bit more. It's a great question. So I think from our perspective, we've been consistent buyers of the equity over a long period of time. I think -- we do have a bit of a, I'll call it, a change in cadence in our free cash flow, and we've not been formulaic in our repurchase activity.

So I think when we got to fourth quarter of last year and then again here in the first quarter of this year, we wanted to give a little bit more color around what our intentions might be given that first quarter for us sometimes with our capital cadence is a little bit less free cash flow. And I think we want people to understand that we're not married to just that quarter's cash flow and that we're going to be opportunistic when we see the ability to buy the equity at an attractive value.

So winding back to last year, we announced that we would target around $125 million. We actually were able to do a little bit more than that, which was great. I mean we saw an opportunity there to surpass that number slightly. And that's why -- we've done that again this quarter. Again, that's just a way to be a little bit more transparent about our intentions there. As far as what we've done so far in the quarter, I'll probably defer that question just given that we didn't announce that yesterday, and it's probably something that we'll keep close to the best, but do feel really confident that we'll succeed with the repurchases that we announced. And as we go forward, we're going to keep the balance sheet healthy to...

Certainly, we'll continue to monitor what the right way to think about it is and try and be clear when we communicate with the investment community.

Michael. My follow-up is just on the production cadence. Based on your updated slides, your production is going to bottom in 2Q and then peak in 4Q of that's a bit of a different trajectory than you've had in the last few years. Can you just talk about that shift and give a little color on how your volumes could trend headed into early 2027, given that you'll exit 2026 at the highest for the year.

Yes, Zach, this is Matt. I can take that and let Michael and John hop in. That dip in 2Q, you're right, a little bit different than historical Primary driver there is we've got the 4-well Marcellus pad coming online in that quarter as part of our development cadence. And so if you think about that, that's lower IP on a relative basis than what a dry gas or wet gas would be and then we kind of pick up towards the back end of 2Q into 3Q with more of our wet gas, dry gas turning lines. So that's really what's driving that. It's really just the development cadence side of things with our Marcellus.

Any comment on what that can do as you enter into 2027 in the winter, can you sustain that level of production or anything you could add there?

Yes. Zack, I'm glad you followed up there because I think it's an important point. I think when you're leaving this '26 with, call it, 5% more production based on our expectations than you had in '25, I think it sets you up really well for 2017. I mean, obviously, it's a little bit early to comment on what the well mix will be next year, which pads will come on early in the year, later in the year. I think it is to our advantage exiting into what's typically a higher price season with a really strong quarter.

So you can see on the slides that we put out, we fourth quarter is going to be pretty strong for us. And yes, I think maybe where you're going with that is I think we feel really good with that momentum that will carry us forward. And then obviously, I have to come back later with some more details around what '27 really looks like.

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

For my first question here, you guys are increasing your drill lateral lengths this year to 1,900 feet from last year, that was 13,500 feet. That's a pretty significant increase. Could you maybe talk about what's driving that, what that means for D&C efficiencies.

Costs? And then how can we think about average lateral light development in future years?

No. This is Matt. You're right, yes, an increase year-over-year around that. I think primarily speaking, as we think about lateral lengths for us, we try to optimize in that 15,000 to 18,000 foot lateral length as we plan out future development in areas where we have more of a blank canvas. As you know, Ohio starts to get more developed. We have existing PDP wellbores in and around us. And so a little bit of the decrease last year, the lower lateral length was just in regards to the land position and some of the wells that we drilled in and around existing areas, again, really highly economic wells just a little bit shorter in lateral.

This year, we're getting into some more of our discretionary acreage programs in the wet gas area that kind of gives us that runway to optimize development. And so we've got some longer lateral lengths in the program to be more efficient on the D&C side on $1 per foot and realize those gains. So I think for us, that 15% to 18% is a good spot to be. In some cases, we may be longer than that. We've certainly drilled 20,000 footers in a little past and sometimes we may be shorter just depending on the land position down in that 12,000 foot range. So really a mixed bag there from last year, a little bit more on the longer side this year, but that 15% to 18% range is kind of where we target [indiscernible]

Great. And then for my second question here is just on the reserves. You guys is year-end proved reserves [indiscernible] tighten give the pricing sensitivity as well. It seems to be up year-over-year from '25 versus '24. Could you maybe talk about some of the moving parts there and what's driving the PD1 increase?

Yes. No, it's a good question. So I mean if you think about the way the reserves are put together, you've got a component of PDP and some PUDs as well. And so as we're as we're out converting PUDs into PDP and spending the capital to do that, you're certainly removing that cost out of the reserve base and converting those PUDs into PDP. So you'll see that you've added value there even at the same deck as you pointed out, just because of that conversion. So there's always been other inputs in there. And keep in mind, that's an SEC reserve base. So we certainly have reserves that go well beyond that 5-year rule that the SEC limits you to. But I think you picked up on something important there that is we are adding value, we feel like year-over-year, even at a consistent price deck. So I appreciate you pointing that out.

Well, I guess also the question is, it seems like your PDP number is increasing even though even though your production year-over-year hearing is flat, does that mean that you're turning in line more productive wells and were turned in line before?

Yes. I think that you can read through to that. I mean as you convert wells, you produce some of the reserves, you're certainly converting more reserves than just what you're producing. So that PDP volume does go up as you convert wells from PUD to PDP. But yes, I think -- to your point, we are continuing to improve with what we're developing, and I think you're seeing that flow through to the numbers.

Our next question comes from the line of [indiscernible] with UBS.

Good morning, everybody. Thanks for having me on. On the operating side, it looked like you had made some pretty solid gains on your drilling efficiency. I wonder if you could just maybe touch on what some of the drivers of those gains were. And on the completion side, it looked like maybe 2025 took a slight step back. Are there any changes you have in store for '26 to maybe get that metric back up a bit.

Yes, sure, [indiscernible] On the drilling side, we continue to get incrementally better, to your point. I think where we made the most progress in 2025 was more on our top hole drilling efficiencies and some slight improvement on our carbon laterals. So the team was able to shave down really a couple of days per well on our top hole design our vertical section of the well and then some incremental gains on just curband-lateral, higher on the wells that we drilled.

So great job by the team there on delivering and continuing to find ways to eke out some more days of reduction. On the frac side, we did have a dip this year. A lot of things playing into that for us. I think just to keep in mind, we averaged around 18 hours pumping per day, which is pretty impressive and quite frankly, comparable to a lot of our -- the best peers we have in the basin. The year prior, we were averaging 21 hours a day, and that was an incrementally great year for the company and a really hard bar to consistently achieve I would tell you, but we're always striving to get there and maintain. So a little bit in the last year, started the year a little bit slow with a drought in Ohio that caused some water sourcing issues for us in kind of the first quarter and the second quarter that was relevant to everybody in the basin as well. And then throughout the just utilizing more spot crew work, got off to a little bit of a slow start on some spot crews to help kind of keep our production cadence in line and take advantage of the short cycle time opportunities that we saw in our development program last year. So this year, we expect that to be at or above that 18 hours, and the team is already off to a good start in achieving that.

Great. Appreciate all that color. And then I just wondered if you could touch on some of that base improvement spending that you have budgeted for 2026. I know it's a smaller amount of CapEx. But I wonder just how this was different from normal workover spending and kind of how you see the base decline rate shaping up for Gulfport in 2026?

Yes. So on the workover side, good point. We did start that program last year. So not as much kind of more in the back end of the year. As a company, we've seen the opportunity set here just with increasing commodity prices to take advantage of really strong near-term economic attractiveness. And so identifying those with the production teams and the operation teams to then go deploy that capital for the incremental flattening of the base production is a huge win for us. These projects are targeting kind of less than 12 months payout if you can think about that. So they're really highly economic. They do help us support the base decline and increase that over time, which inevitably kind of flows through our flat to then kind of quarter-over-quarter exit growth throughout the year. And so it's a good program for us. It's $15 million in the total year. So not crazy high, but incrementally has been more than 2025, and we'll look to continue to find more of those projects kind of throughout '26 and into '27.

Our next question comes from the line of Nicholas Pope with ROTH Capital Partners.

Hoping you could talk a little bit on the acreage acquisitions. I think the discretionary acreage acquisitions, the program that was put in place that $100 million, the big push to kind of build inventory there. It sounds like the expectation is that's going to run through first quarter. And as you complete kind of this portion of the program. Curious how you're thinking about acreage going forward and kind of what what go forward is thinking about kind of the lay of the land and the potential of kind of re-upping a program or continuing acreage acquisitions beyond kind of 1Q once you kind of finish this big push?

Yes. So Nick, I appreciate the question. I think this is a part of the program over the past 3 years is what we're really, really proud of. I mean we've seen a substantial growth in our inventory gross locations since 2023. This has been a mainstay every year because just inventory improvements have in a durable runway that we can call on, has a lot of optionalities. But even what's more important outside of the 4.5 years of discretionary picks up, this is really high-quality acreage. And the fact that we're drilling in this wet gas area that we just bought a few years ago, this is our third pad this year. So -- it's very good to add that inventory, but just the low breakeven, the high quality, we're picking it up in bulk where we can go out and develop and drill and we can do it very quickly. And so this is a really high value use of our free cash flow. So -- so we really like it.

So leading into that, we've had a lot of success with this program that's ended up in Q1. Clearly, we have a lot of confidence that, that number is going to hit at the high end. Again, this is a continuation in Belmont roots really good quality acreage. As we complete this program and look forward, I'll tell you that we view this as a very favorable again investment for the company. So -- we're not certainly ready to guide to that, but I will tell you that as the land teams wrap up Q1 when we get line of sight on what's next in that particular realm for spend will come to the market and kind of roll it out. But we like the spend. We think the investors like it and we like the optionality that the inventory brings and especially the inventory that we can jump on really quick from a development standpoint. So I appreciate the question.

I appreciate it. That's great. Kind of shifting a little bit towards the North you highlighted that there's some data collection that you are going to be working on kind of ahead of anticipated second half kind of drilling further north in the Marcellus. Just I'd love to hear which, I guess, kind of what data is needed, where maybe you guys are? And I guess, kind of what information is already kind of in hand as you kind of move and try to kind of derisk some of that potential further up north in all's acreage position?

Sure. Yes. If you're talking about the Marcellus North, we will be drilling those wells. There will be some science collected during that process with some sidewall cores and some additional logging and some tests. Really, that's just geared around us ensuring that we have all the data necessary for us to properly design our fracs -- we don't anticipate it being much different than the Southern Marcellus. But while we're there and have the opportunity, it's a cheap way to gather that data and make sure we're looking at it the right way as we go to complete those wells in kind of the first part of '27. So that's really the work that's going on there. It's data that we've taken before, but more in our Southern core area and just an opportunity here to take some more while we're drilling this year in the Marcellus North.

Yes. Nick, and I'll add on to that, too. This drilling isn't a delineation effort. I mean there's a lot of wells just to the east of us across the state. There's wells to the north, and we've got our own development down donation and is the southern area, what we call Southern [indiscernible] So for us, this isn't a delineation effort. But what we do want to do before we go wholesale development is really get a handle on the production mix a little bit more data on the production profile, what it might look like, what the pressures look like.

So we'll be blending this first pad into a dry gas line to be able to assess that. And that really helps us design and come up with our plans with regards to midstream infrastructure, processing agreements, what we need, what kind of capacity we need. So I would think about it more in the line of a production mix test and less so on a delineation effort because we have all the confidence in the world that, that 50 wells that's real. And we just need to set it up for full development. So this is the first step in that process.

Ladies and gentlemen, that concludes our question-and-answer session. I'll turn the floor back to Mr. Reinhart for any final comments.

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.

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

Greetings, and welcome to the Gulfport Energy Corporation Third Quarter 2025 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded.

It is now my pleasure to introduce Jessica Antle, Vice President of Investor Relations. Please go ahead.

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 favorably -- into a favorable economic commodity price environment.

While we continue to optimize our 2026 development program amongst our attractive development areas and plan to announce our formal capital and production guidance in February, the discretionary capital investments made in 2025 will benefit the 2026 program.

Along with these incremental capital investments, the company reiterates our commitment to return capital to shareholders through our ongoing common share repurchases. And this incremental capital spending will not reduce the amount we previously planned to allocate towards share buybacks during 2025. In total, we expect to allocate approximately $325 million to common stock repurchases during the year, while maintaining financial leverage at or below an attractive 1x.

On the land front, through September 30, 2025, we have invested roughly $23.4 million on maintenance, leasehold and land investment, focused on bolstering our near-term drilling programs with increases of working interest and lateral footage in units we plan to drill near term. In addition, we continue to pursue discretionary acreage acquisitions, primarily in the dry gas and wet gas windows of the Utica, and we have invested approximately $15.7 million during the first 9 months of 2025.

We reiterate our plans and remain on track to allocate $75 million to $100 million in total before the end of the first quarter of 2026 and currently forecast approximately $60 million of cumulative spend by year-end 2025. Upon successful completion of our planned expenditures, this is planned to add over 2 years of core drilling inventory, further bolstering our undeveloped well counts and development optionality beyond the additions we announced earlier today.

Specific to our Marcellus activity, we continue to be very encouraged by our Hendershot pad results in our first multi-well development, the 4-well Yankee pad brought online late in the second quarter and located in the Marcellus core development area. The Yankee pad is exhibiting attractive performance compared to its direct offset, the Hendershot 5-well, and when normalized to 15,000-foot laterals, tracking in line on a 2-stream equivalent comparison. Notably, the Yankee pad represents our first Marcellus pad to be gathered and processed under our new midstream agreement, which enhances development economics by enabling the extraction and sales of valuable NGLs, especially considering the favorable ethane treatment that the contract provides.

In addition to our Marcellus core inventory, as I noted, recent peer development activity has expanded our Ohio resource liability into Northern Belmont and Southern Jefferson Counties, where we hold a meaningful amount of acreage, as depicted on Slide 8 of our investor presentation. We estimate approximately 120 to 130 gross locations across the defined Marcellus North development area, expanding Gulfport's gross Marcellus inventory by approximately 200%. We plan to drill our first Marcellus North development in early 2026 and look forward to discussing the development results once the wells come online and we gain production history.

In summary, we remain focused on expanding and responsibly developing Gulfport's high-quality, low breakeven inventory while prioritizing shareholder returns and maintaining our strong financial position. The expansion of our Ohio Marcellus inventory, validation of new development and targeted discretionary acreage acquisitions have increased our total net inventory to roughly 15 years with breakevens below $2.50 per MMBtu, and we remain committed to returning capital to shareholders through common share repurchases, including the planned incremental repurchases in the fourth quarter of 2025, again, all while preserving a strong balance sheet.

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

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

We reported adjusted EBITDA of approximately $213 million during the quarter and generated adjusted free cash flow of approximately $103 million, which includes the impact of approximately $12.4 million of discretionary capital expenditures. Our all-in realized price for the third quarter was $3.37 per Mcfe, including the impact of cash settled derivatives, resulting in a premium of $0.30 above the NYMEX Henry Hub index price.

This outperformance reflects Gulfport's differentiated hedge position, the pricing uplift from our liquids portfolio and the impact of our diverse marketing portfolio for our natural gas. As many of our peers have discussed, we are entering an exciting time for the natural gas market, fueled by LNG expansion and the increase in demand for natural gas power generation that is accelerating from the build-out of new data centers. This evolving landscape presents exciting opportunities and while on a smaller scale than some industry peers, Gulfport has been able to benefit from our firm transportation portfolio to secure targeted arrangements with larger gas marketers that deliver incremental value to the company.

We continue to evaluate additional opportunities to supply gas to meet this growing demand and Ohio appears to be fertile ground for future development in this area. This market trend also pairs well with our direct exposure to the growing LNG corridor near the Gulf Coast through our firm transportation agreements that access the TGP 500 and Transco 85 sales points, markets which averaged more than $0.50 above the NYMEX Henry Hub index price during the third quarter. Together, these marketing and takeaway arrangements improve our realized prices, increase our all-in netbacks and ultimately lead to enhanced durability in our free cash flows.

Turning to the balance sheet. Our financial position remains strong with 12-month net leverage exiting the quarter at approximately 0.81x, down from the prior quarter and benefiting from the increasing EBITDA our business has delivered over the past year. As of September 30, 2025, our liquidity totaled $903 million, comprised of $3.4 million of cash plus $900.3 million of borrowing base availability. And we recently completed our fall borrowing base redetermination with our lenders, unanimously reaffirming our borrowing base at $1.1 billion, with elected lender commitments remaining at $1 billion.

Our strong liquidity and financial position today is more than sufficient to fund any development needs we might have for the foreseeable future and provides tremendous flexibility from a financial perspective as we are positioned to be opportunistic should situations arise that allow us to capture value for our stakeholders. As demonstrated through our discretionary acreage acquisitions, proactive capital initiatives and planned share repurchases announced alongside our earnings.

As John mentioned previously, we completed the opportunistic redemption of all outstanding shares of Gulfport's preferred stock during the third quarter. The company redeemed a total of 2,449 shares of preferred stock at an aggregate redemption value of approximately $31.3 million. This is a milestone financial accomplishment for Gulfport as the completion of this transaction simplifies our capital structure and underscores our belief in the attractive value proposition that Gulfport's equity represents.

Inclusive of the preferred redemption, during the third quarter, we repurchased 438,000 shares of common stock for approximately $76.3 million. And since the inception of the program, we have repurchased approximately 6.7 million shares of common stock at an average price of $117.45 per share, approximately 40% below the current share price.

Our consistent approach to share repurchases over the last 2 years has delivered tremendous value to our shareholders. That said, we also remain opportunistic, utilizing our financial flexibility to allocate capital when we believe the current valuation does not reflect the strength of our underlying fundamentals. And as such, repurchasing shares at today's level represents a highly attractive use of capital.

As John mentioned, we expect the incremental discretionary capital expenditures announced today to be funded without impacting our planned share buyback program and alongside earnings announced plans to allocate approximately $125 million to common stock repurchases in the fourth quarter of 2025 to be funded from adjusted free cash flow and available revolver capacity, all while maintaining leverage at or below 1x.

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

With that, I will turn the call back over to the operator to open up the call for questions.

[Operator Instructions] And the first question comes from the line of 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?

Thanks for the question. I think one of the things that we're pretty proud of here is the team's constant focus on operational execution and their ability to test and optimize the completions and drilling, quite frankly, and drill out phases of our development.

The teams -- what I'll point you to, the teams have progressed, especially in the different windows of the Utica with cluster spacing, with sand. So for instance, there's been a pretty material change in the way we allocate sand, whether it's 40/70 or 100 mesh, the cluster spacing, the stage sizes. So the teams are constantly evolving, assessing and testing as we move through our development program in both the Marcellus and the Utica and the condensate, and the well results showed that. So pretty pleased with how the teams are focused on that, that optimization and certainly look for more to come.

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

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

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

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, I appreciate the question. I think as we looked at the company's portfolio, I mean, it should be no surprise to anybody that we've been very focused on expanding the high-quality inventory over the past 3 years. We probably sound like a broken record whenever we say it, but that is a key focus for us. And as we looked at the fourth quarter, there's robust cash flow. The company has a healthy balance sheet. And almost every investor meeting that we have wants to see us kind of grow that inventory. And I think we agree, having sustainable long-term low breakeven inventory is very important for the company. It just provides durability, that's very important.

So as we looked at all that, it was the right time to take a look at this appraisal bucket, which was primarily allocated towards these U-development. And this is a real opportunity for the company to take what was -- what I would call shorter lateral type development that were subeconomic to the right side of the skyline and really pull forward some really good, high-quality return 20 gross wells, that also adds, by the way, some dry gas into '26.

So, I think the company was positioned very well overall financially. The commodity environment really looks constructive, and it was just the right time to continue to expand on our inventory through the Marcellus delineation efforts and all the technical work there as well as the U-development.

Yes. And I just think maybe I'd add to that, Brian. I think the timing certainly helps, right? I mean I think the gas environment is strong. And I think we're certainly conscious of that as we make these decisions. But John hit on the point. I think it's really about unlocking the inventory. And we'll see what the results look like. We'll get these things completed near the end of the year, get the production online. Some of this appraisal capital, I think John mentioned in his remarks, was also related to some legacy DUCs and some refracs. And so, we'll kind of see what the productivity of these projects are.

And so I think as far as thinking about next year at this point, probably a little early to guide you on kind of how much incremental there is there, but we'll certainly be following up. And I think John mentioned this in his prepared remarks, looking for other opportunities within the portfolio where we can apply some of these learnings that we've had.

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 [ SKU ] to the production in 2025 with first quarter down a lot. How should we think about sort of the shape of production? I know you don't have guidance. But just trying to understand kind of the impact of your 4Q acceleration and how that's going to shape the next couple of quarters? Can you give any context on that?

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.

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

Yes. I think to your first question on activity and just our general inventory add there. There are several well points to the east of us. And I think even Michael, Matt and I in our prior lives down in Monroe County, there's been several Marcellus. And then here, we were, of course, up in that Belmont area. I think there's a lot of data points.

What really kind of triggered the timing for us here is that northern data point that kind of shored up the structural features and structural mapping as you go from south to north, which really kind of put a pin in it for us and that offset operator who drilled that well. It's got substantial production that's public now. And I'd reference you to Enverus as well on some of their inventory data. It really facilitated us recognizing what we believe is a materially derisked footprint here.

I will tell you that we're pretty conservative, and we took a conservative approach on this inventory adds in the Marcellus. If you reference Slide 8 in the investor deck, it kind of shows ongoing assessment. And I think that's maybe what you're referring to. We wanted to make sure that we stayed structurally and honored to structural and honored the data that we saw for these 50 or 60 net inventory wells, but there is meaningful upside.

I think to your point, as we think about development, we're going to drill this first pad in Northern Belmont, which kind of ties along to the same structure and features is that Southern Jefferson. So for us, it's -- we're agnostic to it. What we're looking for is what well mix that's going to provide. So by the end of this year -- or sorry, the end of next year, we'll have a pretty good understanding of the production mix. And so, to your question about development opportunities, we'll then take that information and start looking at midstream contracts, processing agreements. So we're probably 2 to 3 years out from actually full developing that northern core, but we are going to drill our first well up there to get a good idea of production mix.

On the South ongoing assessments, what I'll tell you is we're not an exploration company. We like to really derisk what we do operationally. So as we work from the east to the west, that will naturally start to delineate that ongoing assessment area where we feel like there's some real upside there potentially for the company because the actual play moves to the west as you go farther south, just that's the way the structure works. So there's a little bit -- we feel positive about the opportunities to potentially add some locations in the future, but we won't have any kind of real well set data or anything to compare to at least over the next 1.5 years. So that -- there's more to come there in the future.

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?

Yes. I'll touch on the preparedness and kind of contingencies. We've really been focused, as we talked about on adding additional inventory. And these inventories kind of scour different landscape areas. So we've been focused on dry gas, wet gas. We've developed -- and certainly some Marcellus. We've developed some condensate wells. So as you think about kind of preparations for future occurrences and incidents, these all are in different footprints in different areas.

So, by default of just adding this low breakeven, high-quality blocky acreage we can develop, it does set us up for contingent options as we move forward for any kind of unforeseen or unplanned incidents that we might have in the future. So, by default, we're actually focused on doing that by these inventory adds, and we feel like that's a very prudent action for us to take just considering what's happened over the last year.

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?

Yes, it's a great question. I'll tell you that the general first review over our portfolio and acreage footprint, these are more geared towards looking at land configurations that would limit lateral lengths. Otherwise, there would be longer lateral development. So, for instance, when the teams went through and scoured in these highly productive, high-quality acreage positions, we had 20 gross locations that we could actually form through basically combining, let's just call it, double that amount of shorter laterals. And what that did was it took a very subeconomic short lateral even at 350, 375 gas, let's just call it 20% IRRs. These are still attractive returns, but they just -- they don't compete for capital with our current portfolio. And they raised those up to somewhere along the lines of 60% plus returns.

So what we're effectively doing is combining some of these subeconomic shorter laterals and moving them to the left in the skyline chart. So, it's really a function of the acreage position and maximizing our utilization of our current footprint. That's how I would characterize it.

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

The other area that you didn't mention is we have our wet gas development that's come on this year. And I would tell you that the yields there have actually been very strong as well. So that's in our kind of -- we called it our wet gas Utica. It's part of our discretionary acreage budget that we spent over the last couple of years. We put those wells on earlier this year. And we saw, I would tell you, kind of outperformance on the NGL side.

So again, we've got favorable contracts up there. Not a lot has changed in our legacy Ohio Utica contracts, but that Marcellus contract on the marketing side is very strong from an economic perspective. And so, we feel really good that our netbacks have been strong even when I would tell you that some others in the basin have seen some weakness in NGLs.

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. Great question. I think we've seen increasing levels of interest. I was just going to -- I mentioned that maybe a little bit earlier in my prepared remarks that there's a lot of activity going on in Ohio right now. I think -- Ohio, I think I called it fertile ground, but it certainly seems like there's a favorable regulatory environment. There's favorable political environment, and there's just a lot of interest in projects in that area.

So again, from our perspective, we're a bit smaller than some of the other guys out there. So, more likely for us to participate in kind of some aggregation strategy of marketing firms that put together volumes of gas come to us looking for volumes. We can get some uplift in our value when we do that. I think you're aware that we like to keep things fairly flexible in our business. So we're always kind of balancing the long-term commitment element of that with the pricing opportunity that we have.

So, to your point, I think it's very favorable, I call it positive momentum in the area right now. And ultimately, we've got gas, a lot of gas that's still uncommitted to any of those projects. And so to the extent there's further opportunities, we can certainly consider those.

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.

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

Yes, I'll start, and then John can jump in. Carlos, thanks for the question. I think Neal asked a little bit earlier a similar question where I think our view on those opportunities is that we have pretty compelling opportunities within our existing portfolio, and we're measuring anything outside our portfolio against those opportunities. So I think there -- likely, you're aware that there's been some activity up in Appalachia. I think for the company, we've been disciplined over the last few years and feel like the strategy has really been effective for us. So I think that will continue.

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

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.