This is our bankruptcy hold music. Greetings, and welcome to the Gulfport Energy Corporation fourth quarter and full year 2025 earnings call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. 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 Corporation 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, as actual results and future events could differ materially from those that are indicated in these forward 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 will 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 two 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 are 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 one times or below. This includes our announced plan to deploy…

Thank you, John, and good morning everyone. I will start this morning by summarizing the key components of our fourth quarter financial results, which highlight the company's strong financial position as we closed out 2025 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 $222,000,000 in the fourth quarter, more than double our capital expenditures for the quarter. We reported adjusted EBITDA of $235,000,000 and generated $120,000,000 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 0.9 times. Total cash operating costs 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 late 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 Mcfe in 2026, with the top-line value contribution from increased NGL production and our improving gas price differentials, which I will 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…

Thank you. We will now open for questions. Our first question comes from the line of Neal Dingmann with William Blair. Please proceed with your question.

Good morning, guys. Thanks for the time. Michael, maybe just something on the forecasted improved forecasted price realizations. 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 these improved realizations? I guess that is 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.

Yes, Neal, thanks for the question. I will hit the first part. Certainly, we are active with our basis hedging program. I think we have got some disclosures out in our release that indicate, yes, we have been doing some basis hedging. I think that has been a part of our program over the last few years, and we have an idea of where we think there is 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, which is what gives us confidence. I mean, it is a few things. Right? I mean, I think we have seen rising demand in those kind of local Northeastern basis markets. I think that is starting to flow through to some of the indexes. So if you think about where some of the most liquid Northeast indexes trade, we have seen those come in, and I am talking about kind of in the out years, we have seen those come in $0.15 or $0.20 over the last 30 to 60 days. I think that is an indication of that rising demand. So that is 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 are certainly unpredictable, but I think you will see that flowing through into our realizations. And then I think we are always on the lookout for ways to maximize value through our marketing team, 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 have 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 would say it is 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. Great details. And then secondly, John, maybe for you or Matt, just question on sort of infrastructure and things you were talking about today. You mentioned, I guess, even again today, some potential downtime and know you have talked about sort of some third-party issues in the past. You know, what could you talk about, I forget that you say today, you will have some near-term production impact and then, you know, again, seems like you guys have been addressing a lot of these internally, things that you have been addressing. You know, so what gives you the confidence that that a lot of these issues will just be near term or, you know, what should we think about sort of those third-party issues?

Yes, Neal. Thanks for the question. I guess first of all, set out, it was discussed in the last quarter how we are going to plan to mitigate this out, you know, these kind of occurrences that have happened. Really, last year was the first initial meaningful one that happened. What I will say is outside of just close coordination with our contractors and vendors, we are 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 and how the offset operators are developing, 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 forecast those out. We voiced what those generally would be in the first quarter, and that is just generally around midstream downtime maintenance, compression maintenance. It is substantial whenever you think about the duration of five to seven days at a time, and then you have to bring on wells, the volumes are pretty impactful, but it is 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, Neal, it is around approximately 10,000,000 cubic feet impact per day for '26. That is built into the budget. So it was a more meaningful impact in, certainly late Q1 and then into early Q2, but that is represented in our slides in our public deck when you look at 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 phase from Q4 to Q4 of about 5%, which really positions us for 2027 well for winter pricing and what we feel like is going to be a constructive environment.

Great details. Thanks, John.

Alright. Thanks a lot, Neal.

Thank you. Our next question comes from the line of Carlos Escalante with Wolfe Research. Please proceed with your question.

Hey, good morning, team. Thank you for having me on. I wonder if we could take Neal's question a step further because, obviously, we all realize and commend you for your efforts on improving your differentials year on year. But it has been clear after a few weeks of listening to your peers that there is an overall 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, on the basis of do you consider growing at some point in the future? Thank you.

Yeah. Hey, Carlos. This is Michael. I will take the first part, John can certainly jump in. But I mean, I think it is a good question. Right? I think when we look at pricing and think about the right development cadence for Gulfport, we are thinking about, to your point, not just index pricing, but also differentials. And so the move that I have described this morning on the differential side, it is meaningful for us. On the other hand, I mean, for us to consider significant changes to our development cadence, we would 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 have traditionally been, call it, a flattish, low-single-digits type company that maximizes free cash flow. And I think that 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 is always an option to the company, but I think maybe why you are not hearing that from some other peers is that it has 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.

Thank you. Appreciate the color, Mike. And then for my follow-up, a quick one. Housekeeping item. Can you, perhaps this for you, I think, Matt, give us an update on what you are seeing on the tail end of the type curve for the Hendershot and the Yankee pads? 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 have seen any kind of similarities in your Northern Marcellus position relative to these. Thank you.

Sure. Yeah, Carlos, happy to take that. I think last quarter, we showed kind of the 60-, 90-day plus on those. Obviously, the cumulative plot looked very strong and attractive, and similar to the Hendershots, if not slightly better on initial cume. For us, it is really just confirming the type curve. These are both pads that are on decline. They are in their natural decline state. They mirror kind of the type curve that we 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 are 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 approximates, we think, you know, 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 well liquids 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.

Terrific. Thank you, guys.

Thanks, Carlos.

Thank you. Our next question comes from the line of Zach Parham with JPMorgan. Please proceed with your question.

Hi. Thanks for taking my question. You mentioned buying more than $140,000,000 in shares during 1Q. That comes on the back of buying a lot of shares during 4Q. Can you just discuss that decision a little bit more? How did you decide on the amount of stock to buy during 1Q? And could you just comment on how much of that you have 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.

Yeah. Hey, Zach. This is Michael. Happy to dive into that a little bit more. It is a great question. So I think from our perspective, we have been consistent buyers of the equity over a long period of time. I think we do have a bit of, I will call it, a changing cadence in our free cash flow. We have 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 are not married to just the back quarter's cash flow and that we are 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 $125,000,000. 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 is why we have done that again this quarter. Again, that is just a way to be a little bit more transparent about our intentions there. As for what we have done so far in the quarter, I will probably defer that question just given that we did not announce that yesterday and it is probably something that we will keep close to the vest. But we do feel really confident that we will succeed with the repurchases that we announced, and as we go forward, we are going to keep the balance sheet really healthy. So certainly, we will continue to monitor what the right way to think about it is and try to be clear when we communicate with the investment community.

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

Yes, Zach, this is Matt. I can take that and let Michael and John hop in. That dip in 2Q, you are right, a little bit different than historical. The primary driver there is we have got the four-well Marcellus pad coming online in that quarter as part of our development cadence. And so think about that, that is 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 turn-in-lines. That is really what is driving that. It is really 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?

Yeah. Hey, Zach, I am glad you followed up there because I think it is an important point. I think when you are leaving 2026 with, call it, 5% more production based on our expectations than you had in 2025, I think it sets you up really well for 2027. I mean, obviously, it is a little bit early to comment on, you know, what the well mix will be next year, what, you know, which pads will come on early in the year, later in the year. I think it is to our advantage to be exiting into what is typically a higher-price season with a really strong quarter. So you can see on the slides that we put out, we do think fourth quarter is going to be pretty strong for us. And yes, I think maybe where you are going with that is we feel really good with that momentum that will carry us forward. And then obviously, we will have to come back later with some more details around what 2027 really looks like.

Great. Thanks, Michael. Thanks, Matt.

Thank you. Our next question comes from the line of Noah Hungness with Bank of America. Please proceed with your question.

Good morning. For my first question here, you guys are increasing your drill lateral lengths this year to 16,900 feet from last year that was 13,500 feet. That is a pretty significant increase. Could you maybe talk about what is driving that and what that means for D&C efficiencies and costs? And then how can we think about average lateral length development in future years?

Yes, sure. Noah, this is Matt. You are 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 lengths, 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, a little bit shorter in lateral. This year, we are getting into some more of our discretionary acreage programs in the wet gas area that kind of gives us that runway to optimize development. So we have got some longer lateral lengths in the program to be more efficient on the D&C side on a dollar per foot and realize those gains. So I think for us that 15,000 to 18,000 is a good spot to be. In some cases, may be longer than that. We have certainly drilled 20,000-footers and 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 15,000- to 18,000-foot range is kind of where we target now.

Great, thanks. And then for my second question here is just on the reserves. Your guys’ year-end proved reserves PV-10 that you give the pricing sensitivity as well, it seems to be up year over year from 2025 versus 2024. Could you maybe talk about some of the moving parts there and what is driving the PV-10 increase?

Yeah. Hey, Noah. It is a good question. So, I mean, if you think about the way the reserves are put together, you have got a component of PDP and some PUDs as well. And so as we are out converting PUDs into PDP and, you know, spending the capital to do that, you are certainly removing that cost out of the reserve base and converting those PUDs into PDP. So you will see that you have added value there even at the same deck, as you pointed out, just because of that conversion. So there are always other inputs in there, and keep in mind that is an SEC reserve base. We certainly have reserves that go well beyond that five-year rule that the SEC limits you to. But I think you picked up on something important there, that 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, you know, it seems like your PDP number is increasing even though your production year over year here is flat. Does that mean that you are turning in line more productive wells than were turned in line before?

Yeah. I think that you can read through to that. I mean, as you convert wells, you produce some of the reserves, you are certainly converting more reserves than just what you are 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, you know, continuing to improve with what we are developing. And I think you are seeing that flow through to the numbers.

Great stuff, guys. Thanks.

Our next question comes from the line of Peyton Dorne with UBS. Please proceed with your question.

Hey, 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. If you could just maybe touch on what some of the drivers of those gains were. On the completion side, it looked like maybe 2025 took a slight step back. Are there any changes you have in store for 2026 to maybe get that metric back up a bit?

Yeah, sure, Peyton. 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 curve and lateral. So the team was able to shave down really a couple of days per well on our top-hole design, and then some incremental gains on just curve and lateral, higher ROPs on the wells 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 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 are 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, kind of the first quarter and the second quarter. That was relative to everybody in the basin as well. And then throughout the year, 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. Then I just wonder if you could touch on some of that base improvement spending that you have budgeted for 2026. I know it is 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? Thank you.

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 have 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, the operations 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 twelve months payout, if you can think about that. So they are 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 is a good program for us. It is $15,000,000 in the total year, so not crazy high, but incrementally has been more than 2025, and we will look to continue to find more of those projects kind of throughout 2026 and into 2027.

Great. Thank you very much.

Thank you. Our next question comes from the line of Nicholas Pope with Roth Capital Partners. Please proceed with your question.

Good morning, everyone.

Good morning. Good morning.

Hoping you could talk a little bit on the acreage acquisitions. I think the discretionary acreage acquisitions, the program that was put in place, $100,000,000, the big push to kind of build inventory there. You know, it sounds like the expectation is that is going to run through first quarter. And as you complete kind of this portion of the program, curious how you are thinking about acreage going forward and kind of what Gulfport 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, appreciate the question. I think this is a part of the program over the past three years we are really, really proud of. I mean, we have seen a substantial growth in our inventory, up 40% gross locations since 2023. This has been a mainstay every year because just inventory improvements, having a durable runway that we can call on, has a lot of optionality. But even what is more important outside of the 4.5 years of discretionary picks up, this is really high-quality acreage. And the fact that we are drilling in this wet gas area that we just bought a few years ago, this is our third pad this year. So it is very good to add that inventory, but just the low breakeven, high quality, we are 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 we really like it. So leading into that, we have had a lot of success with this program that has 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 and Monroe of just really good quality acreage. As we complete this program and look forward, I will tell you that we view this as a very favorable, again, investment for the company. So we are not certainly ready to guide to that, but I will tell you that as the land team is up in Q1, when we get line of sight on what is next in that particular realm for spend, we will come to the market, 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 inventory that we can jump on really quick from a development standpoint. So appreciate the question.

I appreciate it. That is great. Shifting a little bit towards the north. You highlighted that, you know, there is some data collection that you all are going to be working on kind of ahead of, you know, anticipated second half kind of drilling further north in the Marcellus. Just I would 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 de-risk some of that potential further up north in your acreage position.

Sure. Yeah. If you are 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 logging and some tests. Really, that is just geared around us ensuring that we have all the data necessary for us to properly design our fracs. We do not anticipate it being much different than the Southern Marcellus, but while we are there and have the opportunity, it is a cheap way to gather that data and make sure we are looking at it the right way as we go to complete those wells and kind of the ’27. So that is really the work that is going on there. Data that we have taken before, but more in our southern core area, and just an opportunity here to take some more while we are drilling this year in the Marcellus North.

Yes, Nick, I will add on to that too. This drilling is not a delineation effort. I mean, there are a lot of wells just to the east of us across the state. There are wells to the north, and we have got our own development down, you know, down in that Belmont and, you know, the southern area, what we call Southern Monroe. So for us, this is not 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 will 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 as a production mix test and less so as a delineation effort because we have all the confidence in the world that 50 wells, that is real. And we just need to set it up for full development. So this is the first step in that process.

Got it. That is very helpful. I appreciate it.

Thanks, guys. Yep.

Ladies and gentlemen, that concludes our question and answer session. I will 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 do not 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.