Gulfport Energy - Q4 2025

Transcript

Operator (participant)

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.

Jessica Antle (VP of Investor Relations)

Thank you, Melissa. Good morning. Welcome to Gulfport Energy's Q4 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.

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. 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. 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. 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 1 times or below. This includes our announced plan to deploy more than $140 million towards repurchases in the Q1 of 2026, 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-$430 million, which includes $35 million-$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 that will facilitate improved well planning in our targeted Monroe County discretionary buy area. The company currently forecasts 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 Q4s. 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 Q1 of 2026, and upon successful completion, we expect to add over two 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 U-development on our Utica position, and delineation and development efforts in the Marcellus have collectively unlocked substantial value across our core assets.

The discretionary acreage acquisition and U-development initiatives, by the end of the Q1 of 2026, will have added over five and a half years of high-quality net locations, in addition to the four years of delineated net Marcellus locations. In total, the company will have expanded our gross inventory by more than 40% and will continue to monitor opportunities to further expand our resource depth. Turning to production, we forecast our development program will deliver 1.03 to 1.055 billion cubic feet equivalent per day in 2026, 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 Q1 of 2026.

In addition, Winter Storm Fern 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 Q4 2026 production will increase approximately 5% compared to the Q4 of 2025. In our investor deck on Slide 11, we include a more detailed outlook on our expected 2026 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 remains 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 DNC 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 Q4, we completed the drilling and completion of our first U-development wells in the Utica. These wells were successfully drilled, fracked, and recently brought online during the Q1. 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 will turn the call over to Michael to discuss our financial results.

Michael Hodges (EVP and CFO)

Thank you, John. Good morning, everyone. I'll start this morning by summarizing the key components of our Q4 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 million in the Q4, 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 costs for the Q4 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 MCFE in 2026, 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 Q4 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. 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-$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 at ending of the year at below 1 times.

As of December 31st, 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 Q4, 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 31st, and since the inception of the program, we have repurchased approximately 7.4 million shares of common stock, including the preferred redemption in September 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, despite our normal front-weighted capital cadence, we announced our plan to allocate more than $140 million to repurchases in the Q1 of 2026, to be funded from Adjusted Free Cash Flow and available revolver capacity, all while maintaining leverage at or below approximately 1 times. Assuming successful repurchases during the Q1, we will have repurchased approximately 7% of our current market capitalization in just the fourth and Q1s 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 us significant flexibility to continue returning capital to shareholders and to invest in highly accretive opportunities that 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 (participant)

Thank you. If you'd like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press Star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question comes from the line of Neal Dingmann with William Blair. Please proceed with your question.

Neal Dingmann (Analyst)

Morning, guys. Thanks for the time. Michael, maybe just something on you, to hit you first, just on the question on the improved forecasted price realizations. Is this, you know, 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. Remind me again, make sure I understand what is giving you all the confidence for these improved realizations or these improved price realizations?

Michael Hodges (EVP and CFO)

Yeah. Hey, Neal, thanks for the question. I'll hit the first part. Certainly, you know, we are active with our basis hedging program. I think we've got some disclosures out in our release that'll 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, it's a few things, right? I mean, I think we have seen rising demand in those kind of local Northeastern basis markets.

You know, I think that's starting to flow through to some of the indexes. If you think about where some of the most liquid Northeast indexes trade, we've seen those come in. 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, you know, the winter storm that we saw in the Q1, I think a number of operators realized some benefit from that. 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 know, you'll see that flowing through into our realizations.

I think we're always on the lookout for ways to maximize value through our marketing team. 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. 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.

Neal Dingmann (Analyst)

Great. Great details. Secondly, John Reinhart, maybe for you or Matthew Rucker, 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. You know, could you talk about, I forget, did you say today you'll have some near-term production impact? You know, again, seems like you guys have been addressing a lot of these internally, things that you've been addressing. You know, sort of what gives you the confidence that a lot of these issues will just be near term, or, you know, what should we think about sort of that third-party issues?

John Reinhart (President and CEO)

Yeah, Neal, thanks for the question. I guess, first of all, I'll set out, it was discussed in the last quarter, you know, how are we 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'll tell you 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, in the wet gas areas.

You know, we cover a lot of ground over these areas. 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. I, you know, 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. They were planned. We forecasted those out. We've voiced what those generally would be in the Q1. That's just generally around midstream downtime, maintenance, compression maintenance.

It's substantial whenever you think about the duration, you know, 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 different maintenance items. The winter storm warning, in combination with these planned maintenance and SIMOPS downtime, Neal, it's around approximately 10 million cubic feet impact for the day. For 2026, that's built into the budget. It was a more meaningful impact in certainly late Q1. Expect those to abate, then with additional turn-in-line, you see a significant improvement in a production cadence from Q4 to Q4 of about 5%, which really positions us well for winter pricing, you know, and what we feel like is going to be a constructive 2027.

Neal Dingmann (Analyst)

Great details. Thanks, John.

John Reinhart (President and CEO)

All right. Thanks a lot, Neal.

Jessica Antle (VP of Investor Relations)

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

Carlos Escalante (Senior Associate)

Hey, good morning, team. Thank you for having me on. I wonder if I 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. It's 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. 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? Thank you.

Michael Hodges (EVP and CFO)

Yeah. Hey, Carlos, this is Michael. I'll take the first part, and John can certainly jump in. I mean, I think it's a good question, right? I think when we look at pricing and think about the right development cadence for Gulfport, we're thinking about, to your point, not just index pricing, but also differentials. The move that I've described this morning on the differential side, it's 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. If you look back at our history, we've traditionally been, call it a flattish, low single digits 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. 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. 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. I think we'd need to see more of that before we would likely adjust our strategy in the future.

Carlos Escalante (Senior Associate)

... Thank you. Appreciate the color, Mike. For my follow-up, a quick one, housekeeping item. Can you perhaps, this is for you, I think, Matt, give us an update on what you're 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've seen any kind of similarities in your Northern Marcellus position relative to these? Thank you.

Matthew Rucker (EVP and COO)

Sure. Yeah, Carlos, happy to take that. You know, I think last quarter we showed kind of the 60, 90 day plots on those. Obviously, the cumulative plots looked very strong and attractive and similar to the Hendershots, if not slightly better on the initial cum. For us, it's really just confirming the type curve. These are both pads are on decline, so they're in their natural decline state. They mirror kind of the type curve that we've built for that area as part of our development planning. No, you know, no significant upside changes, obviously, in a decline environment. You know, 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.

You know, as you think about the Marcellus North, we think it's proximate. 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. Leading into this, you know, 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 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.

Carlos Escalante (Senior Associate)

Terrific. Thank you, guys.

Matthew Rucker (EVP and COO)

Thanks, Carlos.

Michael Hodges (EVP and CFO)

Thanks, Carlos.

Operator (participant)

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

Zachariah Parham (Executive Director of Equity Research)

Thanks for taking my question. You mentioned buying back more than $140 million in shares during 1Q. That comes on the back of buying back a lot of shares during 4Q. Can you just unpack that decision a little bit more? How did you decide on the amount of stock to buy during 1Q? 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's gonna be over the next month.

Michael Hodges (EVP and CFO)

Yeah. Hey, Zach, this is Michael. Happy to dive into that a little bit more. It's a great question. I think from our perspective, you know, we've been consistent buyers of the equity over a long period of time. I think, you know, we do have a bit of a, I'll call it a changing cadence in our free cash flow, and we've not been formulaic in our repurchase activity. I think when we got to Q4 of last year, and then again, here in the Q1 of this year, we wanted to give a little bit more color around what our intentions might be, given that, you know, Q1 for us, sometimes with our capital cadence, is a little bit less free cash flow.

I think we want people to understand that we're not married to just that quarter's cash flow, and that we're gonna be opportunistic when we see, you know, the ability to buy the equity at an attractive value. 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 to, you know, given that we didn't announce that yesterday, and it's probably something that we'll keep close to the vest. Do feel really confident that we'll succeed with the repurchases that we announced. You know, as we go forward, we're gonna keep the balance sheet really healthy. Certainly, you know, 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.

Zachariah Parham (Executive Director of Equity Research)

Thanks, Michael. My follow-up's just on the production cadence. Based on your updated slides, your production's gonna bottom in 2Q, and then peak in 4Q of 2026. 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 highs for the year?

Matthew Rucker (EVP and COO)

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. You know, if you think about that's lower IP on a relative basis than what a dry gas or wet gas would be. Then we kinda pick up towards the back end of 2Q into 3Q with more of our wet gas, dry gas turning lines. That's really what's driving that. It's really just the development cadence side of things with our Marcellus.

Zachariah Parham (Executive Director of Equity Research)

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

Michael Hodges (EVP and CFO)

Hey, Zach, I'm glad you followed up there because I think it's an important point. I think when you're leaving this, you know, 2026 with, call it 5% more production, based on our expectations than you, than you had in 2025, I think it sets you up really well for 2027. I mean, obviously, it's 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's typically a higher price season with a really strong quarter. You can see on the slides that we put out, we do think Q4 is gonna be pretty strong for us.

Yeah, I think maybe where you're going with that is I think we feel really good with that momentum that'll carry us forward, and then obviously have to come back later with some more details around what 2027 really looks like.

Zachariah Parham (Executive Director of Equity Research)

Great. Thanks, Michael. Thanks, Matt.

Operator (participant)

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

Noel Gonzalez (Analyst)

Morning. For my first question here, you guys are increasing your drilled lateral lengths this year, to 16,900 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 DNC efficiencies and costs? How can we think about average lateral length development in future years?

Matthew Rucker (EVP and COO)

Sure, Noel. This is Matt. You're right. 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 15,000-18,000 foot lateral length as we plan out future development in areas where we have more of a blank canvas. You know, as you know, this, you know, Ohio starts to get more developed. We have existing PDP wellbores in and around us. You know, 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, 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 kinda gives us that runway to optimize development. We've got some longer lateral lengths in the program to be more efficient on the DNC side on a $ per foot and realize those gains. I think for us, that 15-18 is a good spot to be. In some cases, we may be longer than that. We've 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. Really a mixed bag there from last year, a little bit more on the longer side this year, but that 15-18 range is kinda where we target, Noel.

Noel Gonzalez (Analyst)

Great, thanks. For my second question here is just on the reserves. Your guys' year-end proved reserves, PV-10, can you 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 PV-10 increase?

Matthew Rucker (EVP and COO)

Yeah. Hey, Noel, it's a good question. 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. As we're out converting PUDs into PDP and, you know, spending the capital to do that, you're certainly removing that cost out of the reserve base and converting those PUDs into PDP. You'll see that you've added value there, even at the same deck, as you pointed out, just because of that conversion. You know, there's always other inputs in there. 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. 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. I appreciate you pointing that out.

Noel Gonzalez (Analyst)

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're turning in line more productive wells than were turned in line before?

Matthew Rucker (EVP and COO)

Yeah, 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. Yes, I think to your point, we are, you know, continuing to improve with what we're developing, and I think you're seeing that flow through to the numbers.

Noel Gonzalez (Analyst)

Great stuff, guys. Thanks.

Operator (participant)

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

Peyton Dorne (Analyst)

Hey, good morning, everybody. Thanks for having me on. You know, on the operating side, it looked like you'd 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. 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? Thank you.

Matthew Rucker (EVP and COO)

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. You know, the team was able to shave down really a couple days per well on our top hole design or our vertical section of the well, and then some incremental gains on just curve and lateral higher ROPs on the wells we drilled. You know, great job by the team there on delivering and continuing to find ways to eke out some more days of reduction. On the frack 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 average 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. We're always striving to get there and maintain. 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 Q1 and the Q2. That was relevant to everybody in the basin as well.

Throughout the year, just utilizing more spot crew work, got off to a little bit of a slow start on some spot crews to help kinda keep our production cadence in line and take advantage of the short cycle time opportunities that we saw in our development program last year. You know, this year, we expect that to be at or above that 18 hours, and the team's already off to a good start in achieving that.

Peyton Dorne (Analyst)

Great. Appreciate all that color. I just wonder if you could touch on some of that base improvement spending that you've budgeted for 2026. You know, 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. Thank you.

John Reinhart (President and CEO)

On the workover side, good point. We did start that program last year, not as much, kind of more on 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. 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, you know, targeting kind of less than 12 months payout, if you can think about that. 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 flats and then kind of quarter-over-quarter exit growth throughout the year. It's a good program for us. It's $15 million in the total year, so not, you know, 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 2026 and into 2027.

Peyton Dorne (Analyst)

Great. Thank you very much.

Operator (participant)

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

Nicholas Pope (Managing Director and Senior Research Analyst)

Good morning, everyone.

John Reinhart (President and CEO)

Morning, Nick.

Matthew Rucker (EVP and COO)

Morning.

Nicholas Pope (Managing Director and Senior Research Analyst)

Hoping you could talk a little bit on the acreage acquisitions. I think the, you know, the discretionary acreage acquisitions, the program that was put in place, that $100 million, the big push to kind of build inventory there. You know, it sounds like the expectation is that's going to run through Q1, and as you complete kind of this portion of the program, curious how you're 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 once you kind of finish this big push?

John Reinhart (President and CEO)

Nick, appreciate the question. You know, I think this is, this is a part of the program, you know, over the past 3 years that we're really, really proud of. I mean, we've 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 optionalities. Even what's more important, outside of the, you know, 4 and a half years of discretionary picks up, this is really high-quality acreage. 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.

You know, it's very good to add that inventory, but just the low break-even, 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. This is a really high-value use of our free cash flow, so we really like it. Leading into that, we've had a lot of success with this program that's ending up in Q1. Clearly, we have a lot of confidence that that number is gonna hit at the high end. Again, this is a continuation in Belmont, Monroe, of just 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.

We're not certainly ready to guide to that, but I will tell you that as the land teams wrap up Q1, if we, you know, when we get line of sight on what's next in that particular realm for spend, we'll come to the market, kind of roll it out. We like to 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. Appreciate the question.

Nicholas Pope (Managing Director and Senior Research Analyst)

Yes, I appreciate it. That's great. kind of shifting a little bit towards the North. You highlighted that, you know, there's some data collection that y'all are gonna be working on, kind of ahead of, you know, anticipated second half, kind of drilling further north in the Marcellus. Just, I'd love to hear, 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, some of that potential further up north in y'all's acreage position?

Matthew Rucker (EVP and COO)

Sure, yeah. If you're talking about the Marcellus North, you know, we will be drilling those wells. There will be some sidewall cores collected during that process with 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 2027. 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.

John Reinhart (President and CEO)

Yeah, Nick, 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, we've got our own development down, you know, down in that Belmont and, you know, the southern area, what we call southern Monroe. 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.

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. 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 50 wells, that's real, and we just need to set it up for full development. This is the first step in that process.

Nicholas Pope (Managing Director and Senior Research Analyst)

Yeah, that's very helpful. I appreciate it. Thanks, guys.

John Reinhart (President and CEO)

Yep.

Operator (participant)

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

John Reinhart (President and CEO)

Thank you for taking the time to join our call today. Should you have any questions, please don't hesitate to reach out to our investor relations team. Have a great day.

Operator (participant)

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