Gulfport Energy Corp (GPOR) Q3 2026 Earnings Call Transcript

Operator: Greetings. Welcome to the Gulfport Energy Corporation Third Quarter 2026 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. 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.

Jessica R. Antle: Thank you, and good morning. Welcome to Gulfport Energy Corporation's Third Quarter 2026 Earnings Conference Call. I am Jessica, Vice President of Investor Relations. And with me on today's call are Nick Dell'Osso and Matthew H. Rucker. Nick will give a brief overview of our results and then we will 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 disclosure 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.

Domenic J. Dell'Osso Jr.: Good morning and thank you for joining our third quarter earnings call. Starting off, I would 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 1 priority was delivering better and more consistent results for shareholders. And a clean, predictable quarter is evidence of that focus. We are 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 3 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 1. Related to growing in basin demand, we are very pleased to have used our firm transport to access 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 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. Of our peers recently described acreage along the Ohio River as beachfront real estate to this growing demand. If that is 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. 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, $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 at attractive upfront bonus and royalty structures leading to opportunities for greater returns. Looking at our SCOOP asset in Oklahoma, we are seeing some really compelling development by our peer companies targeting different horizons. We believe it is 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 are not adding activity to grow volumes for their own sake. We are 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 a reduction in the 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 are lowering our cost structure and our maintenance capital, increasing cash flow per share and allocating every dollar to what is most accretive per dollar invested. Third quarter execution was on track. Continuous operations make that execution more efficient. 2027 is the investment that drives higher returns and free cash flow inflection from 2028 and beyond. Excited about where Gulfport is headed, and I look forward to updating you on our full 2027 plan in February. Operator, we will now open the call for questions.

Operator: Thank you. We will now be conducting a question-and-answer session. Thank you. Our first question is from Bert Donis from William Blair. You may ask your question.

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

Matthew H. Rucker: Yeah, Bert. This is Matthew. 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 will come out with here in a few months. But, by and large, we drill a mix of anywhere between, you know, 3 to 5-well pads. And that is 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 would not read too much into that and or. And specifically around a rig drilling smaller type pad. That. That will be a blend between both rigs, somewhere between 3 and 5 wells per pad.

Bert Donis: Perfect. And then on Slide 8, you put another help 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 it would take is a, you know, $0.20 move in gas or a $0.20, you know, maybe a dollar move in liquids or something like that to flip the economics the other way. Is that something that we would look at as a 2028 event where you would change it, or do you have flexibility to maybe impact second half 2027 plans based on the strip?

Domenic J. Dell'Osso Jr.: We are 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 are 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 have said before, I think it is 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, you know, $0.25 on gas or $1 or $2 on oil, swings 1 pad to the next, you are really trying to go with your highest return at a mid cycle price. And, you know, just execute in a really well-planned fashion. Well said.

Bert Donis: Thanks, team.

Operator: Thank you. Next question comes from Jacob Phillip Roberts of TPH Research. You may proceed with your question.

Jacob Roberts: Good morning. 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 a little bit, obviously. But just wondering what you are seeing from your peers in terms of zone delineation and resource development. and what you are seeing, what you are hearing? And then what do you think this means for your asset and inventory over time?

Domenic J. Dell'Osso Jr.: Yeah. Great question. I will start, and I think Matthew has some stuff to add here. We are seeing a lot of capital form around the area. there is been some transactions recently with some pretty well informed capital showing up in and around our position. Those producers are targeting other zones, a little shallower than the Woodford and some really quite productive. And so we are pretty interested in what we are seeing from everybody and recognize that this acreage may have more value than we have historically thought about. So we are gonna really try to assess that.

Matthew H. Rucker: Yeah. And Jake, just to add to that, I think some of the activity we are paying a lot of attention to is around the inventory we have talked about historically that we have not 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 have been in the condensate window of the Woodford. We are going to take the time to assess, look into the data that we have that we participate in on a nonoperative basis. Learn from that, and then assess how we want to develop this moving forward.

Domenic J. Dell'Osso Jr.: You know, 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 as it can access markets via existing pipes You do not 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 you know, we will see where that goes. But it is interesting optionality to have gas resource in this part of the country right now.

Jacob Roberts: You kind of covered my second follow-up, so I will pivot a bit there on the good ZIP code commentary. We generally agree. I guess this might be a tougher 1 and 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 a 29 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+ year type of inventory.

Domenic J. Dell'Osso Jr.: Well, you are kind of laying out a few different theories there that are a bit hard to react to, in a vacuum. But I would say that you know, you 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 are willing to invest might move. I do not 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 is a lot of gas. And there is a lot of opportunities to bring gas to market. And so I am not I am not thinking that we are underwriting a $5 or $6 gas strip anytime soon. I do think it will grind higher. Over the next few years from. You know, we are kind of $3.50 people. I think it will grind higher from there, and that can certainly ease up how you think about you know, the hurdle rate from a well cost perspective. But I am really not focused on that right now. And instead, I think we, as a team, are focused on continuing 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 is really what our focus is right now. And we will stay you know, pretty tight on that.

Jacob Roberts: I appreciate the time.

Operator: Thank you. Next question is from Tim Rezvan of KeyBanc Capital Markets. You may proceed with your question.

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

Matthew H. Rucker: Yeah, Timothy. 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 is the right percentage right now. that is going to include really the core Marcellus that we have talked about where we have the M3 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 have talked about before, that is really a good test for us to 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 will follow a similar playbook as the core Marcellus that is going to take some time to develop. And so as we have those conversations, I would not expect the percentage of Marcel's development to go up significantly from what we have been doing. Until we get that in place. And then by that time, call it 2029 and beyond, we will 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 are spot on. We have drilled 2 now 4-well pads in the core area. We have seen those drilling times go down on every single pad that we have done, and we have 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 is part of the math here on the dollar per foot that you see in our efficiency improvements next year and beyond. Okay. Good context. I appreciate that.

Tim Rezvan: And as a follow-up, Nick, in your prepared comments, you mentioned continuing discretionary leasing in 2027. I am not trying to pin you down to a number because I know you will not give 1. But is the opportunity set, do you feel like that $100 million level is that out there? Could you transact in that? Or could you transact more? Just trying to understand what the opportunity set is I know that the board has to decide on what that budget is. But what does that opportunity set look like, I guess, what I am trying to ask Thanks.

Domenic J. Dell'Osso Jr.: Good question, Timothy. And you are right that it is a little early for us to give you a specific number here because we are going to work through our budgeting process as we typically would. But, there is plenty of opportunity out there. We are excited about a lot of things we are seeing. Our team is super active. They keep in close contact with a number of different, you know, 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 will be active. So I am 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 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.

Tim Rezvan: Okay. Thank you.

Operator: Thank you. Our next question is from Gabe Daoud from Truist Securities. You may proceed with your question.

Gabe Daoud: Nick, you alluded to this in just your prior answer, but was curious how the buyback fits into the capital allocation framework in 2017. I know there is a lot of calls on capital as you run a continuous 2-rig program as you highlighted, but curious maybe where the buyback sits?

Domenic J. Dell'Osso Jr.: I mean, again, it is competitive. Right? 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 debt or strengthening our balance sheet. We will be looking hard at buybacks, and we will be looking hard at adding really valuable acreage. And all those things have tension against each other. And depending on market conditions and anticipated return of anything you are looking at, you have the opportunity to you know, make a call. I think you know, 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 is what we are 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 option remained relevant and on the table. And it will continue to compete against everything else that we do.

Gabe Daoud: Okay. That makes sense. Appreciate that. And then just as a follow-up, going back to Slide 6, you gave us a D&C per foot, and with an e-fleet locked in. I would 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?

Matthew H. Rucker: Yeah. Good question. We have baked all 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. And our typical cadence of development. what is really attractive about this development plan is we have been able to, offset all of those inflationary costs with our efficiency gains that we planned both from what we are going to feel like we see on the drilling side and the frac side on being a little bit 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 have used historically. So all of that to us is really an offset and then the. You know, any increase in capital you would see next year would be all activity based, Gabe. Right. All right. Awesome. Thanks, Matthew.

Domenic J. Dell'Osso Jr.: Thanks, Nick.

Operator: Our next question is from Carlos Escalante of Wolfe Research.

Carlos Escalante: Hey, good morning, Nick and Matthew and team. That part of the question is actually a perfect segue to what we want to ask. So going back to Slide 6 on DNC rollout, but there is some clear savings that we can see on the middle chart. But I am 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 2027, are there any conditions under which you would stay at a lower cadence versus what you anticipate today?

Domenic J. Dell'Osso Jr.: I will answer the second 1 first. Look. We are clearly headed in this direction, and we are going to start the year with 2 rigs because that is the typical cadence that we have. And so, you know, I will never say never. there is always some market conditions that cause you to rethink your capital allocation. So that is clearly why we are not giving guidance today and why we want to get through winter, and we want to have the full setup of plan laid out in front of us and make sure that we are ready to commit to a full year of this. We want to have all of our vendors lined up. We wanna have all of the pads ready to go, and there is just a lot of detail that you have fairly well baked in November, but not completely. So we will hold on giving a formal answer to that until we give guidance. But, you know, we are clearly looking at this hard and wanting to be moving in this direction. On the breakdown, it is really hard to separate. They are very connected. The contract for the e fleet really becomes a lot easier for us to have taken on when we know that we are 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, you know, 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 to use it at times if we have a pullback in activity. So feel really good about the way that commitment is structured. But, they are interlinked. Sure. Thank you. Appreciate that, Nick.

Carlos Escalante: 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 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 upside case, or would it simply mean that you have more optionality in your capital allocation program moving forward.

Matthew H. Rucker: Yeah. Carlos, I think the latter, to your comment there, the way we are viewing that is we have got a plan for next year that is baked generally speaking, with our core Marcellus. We will delineate through, completions and turn in line the 2 northern Marcellus wells, early next year. We will evaluate the production results. We will 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 are developing. So just more flexibility and optionality and that would be something we would determine at a later date.

Carlos Escalante: Appreciate the color. Thank you, Nick and Matthew.

Operator: Our next question is from Peyton Doorn of UBS. You may proceed with your question.

Peyton Doorn: Hey, good morning everybody. Thank you for having me on. 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? Maybe said in a different way, is there a certain upper bound longer term in terms of how much gas you would like to dedicate to these types of supply agreements?

Domenic J. Dell'Osso Jr.: it is a great question. I think about an agreement like this as essentially a hedge. We are taking gas that we have been selling at Rec Zone 3 in Chicago Citygate, and we are still gonna sell it at those locations. What we have done is we have agreed to a fixed spread for our gas to that location. So the only part of the hedge that is 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 have received in the past. So it is an uplift. And we like that. We did not 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 is 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 are going to continue to listen carefully. We are going to continue to study the market and understand how it is evolving and understand where our gas has the most value, understand where we believe the most upside is. And make, you know, further hedge decisions with all of that information over time. So I do think there is more upside here. I think you know, 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 are not 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, you know, again, the pricing that we can realize here is a great premium to what we have had in the past, and we are really happy with it. So open to doing more, but it has to be on the right economics.

Peyton Doorn: Yeah. Makes sense. And I appreciate all the detail there. And I just want to ask on the balance sheet. You know, debt crept up a bit this quarter. With free cash flow in the fourth quarter looking like it is going to be a nice jump up. I am curious if you are comfortable with where the current leverage stands or if it is kind of at a point where you might try to take it down a little into next year? Thank you.

Domenic J. Dell'Osso Jr.: 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, yeah, I think, you know, look, it is it is 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 are generating most of our cash in the second half of the year, so it will come back down. Still think about that 1 times as a good mid-cycle place to be. And so now that we have ticked above it here for a quarter, we would expect it to come down. Okay.

Peyton Doorn: that is helpful. Thanks for having me on.

Operator: Thank you. Our last question is from Michael Scialla of Pickering Energy Partners. You may proceed with your question.

Michael Furrow: Hi, good morning. Thanks for taking our questions. I would just like to start with a big picture question for you, Nick. So now that you have had more time in the seat and a chance to really 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?

Domenic J. Dell'Osso Jr.: Yeah. I think, you know, not to beat the dead horse here, Michael, but I would just point you to Slide 6. I mean, that is why we laid out all this detail in the deck. This is the biggest opportunity for the company, and Matthew and I are both really excited about how this positions us for the next several years of development in Ohio. We are going to be a lot more efficient. We are going to drive our cost structure lower by better vendor contracting, by better execution, by better planning. And we think there is an opportunity to continue to add great acreage to the business because we have the efficiency that is 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 are gonna have, which is improve capital and operating efficiency, positioning our gas for the growing demand, and adding valuable acreage to the portfolio. And I think, you know, this move that we are making here is the real catalyst to unlock that. So that is what this is all about. And, yes, my confidence has grown as I have been here. on executing exactly this plan.

Michael Furrow: Understood. Appreciate the response, and, I agree. it is a great slide, and the benefits look pretty clear. Just as a follow-up, we could not help but notice the layering on of hedges for next year, particularly the additional swaps. Do you feel like the 2027 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?

Domenic J. Dell'Osso Jr.: Separate decision. Always. Hedges are. You know, they are a trade you can take on and off. But no, I am happy with our hedge position for 2027. I mean, given where the strip is, I would 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 do not really see us hedging beyond 2027 at these levels. But we are always nimble around hedges. And if we like prices in a given period, we can add more. So feel pretty good about the protection we have for 2027. We are continuing to monitor basis hedges, basis hedge opportunities as well as, think about 2028 and 2029. Appreciate the time. Alright. 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 are very excited about what is 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 will be out on the road a little bit, and then we will talk about 2027 on the next quarter. Thanks a lot.

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