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DATE

Wednesday, May 6, 2026 at 9 a.m. ET

CALL PARTICIPANTS

  • Interim Chief Executive Officer and Chief Financial Officer — Michael L. Hodges
  • Chief Operating Officer — Matthew H. Rucker

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TAKEAWAYS

  • Adjusted EBITDA -- $264 million, driven by both commodity prices and ongoing asset development.
  • Adjusted Free Cash Flow -- $119 million, supporting capital returns and debt flexibility.
  • Average Production -- 997 million cubic feet equivalent per day, aligning with previously issued guidance.
  • Cash Operating Costs -- $1.38 per million cubic feet equivalent, representing a quarterly high the company anticipates will decline in later quarters.
  • Capital Investments -- $118 million spent on drilling and completion, with an additional $4 million allocated to maintenance, land, and seismic activity.
  • Share Repurchases -- 866,000 shares bought back at a cost of $172.8 million during the quarter, marking the company's highest quarterly investment in share buybacks.
  • Total Shares Repurchased -- 8.2 million shares since inception of the program (including preferred redemption in 2025), with an average purchase price just above $133 per share, amounting to nearly $1.1 billion returned to shareholders in four years.
  • Liquidity -- $872 million at quarter-end, comprised of $2.9 million in cash and $869.3 million in revolver borrowing capacity, following an increase in elected commitments post-borrowing base redetermination.
  • Net Leverage -- 0.9 times, emphasizing continued balance sheet strength.
  • Discretionary Acreage Acquisition Program Completion -- $102 million invested over four quarters, securing over two years of high-quality inventory in Belmont and Monroe Counties at just over $2 million per net location, which management highlighted as "significantly below implied recent valuation metrics from larger inorganic transactions in the immediate area."
  • Inventory Additions Since 2022 -- Over 4.5 years of high-quality net drilling locations added via the ground game leasing program.
  • 2026 Operating Cost Guidance Reaffirmed -- Per-unit full-year expectation of $1.23 to $1.34 per Mcfe (including LOE, midstream, and taxes other than income).
  • Operational Activity -- Eight gross wells drilled: two Utica wet gas, four Marcellus, and two SCOOP Woodford; five gross Utica dry gas wells turned in line, including the first two U development wells.
  • Efficiency Achievement in Drilling -- Utica average top-hole drilling days improved by 8% over full-year 2025, with a new record of 5.4 days on a single well and a four-well pad average of 5.9 days per well.
  • Marcellus Drilling Efficiencies -- A recent four-well pad yielded a 20% improvement in footage drilled per day versus the prior two operated pads in the area.
  • SCOOP HERO Pad Results -- Achieved an average spud-to-rig-release time of 40 days per well, outperforming the 55-day internal expectation.
  • Safety and Environmental Performance -- Reported zero recordable incidents or spills during this period of highest operational activity.
  • Rig Schedule -- One SCOOP rig released at quarter-end as planned; two rigs continue in Ohio with a transition to a one-rig program for the remainder of 2026 expected after the second quarter.
  • Production Mix Outlook -- Approximately two-thirds of the remaining 2026 scheduled turn-in-lines expected to produce significant liquids, with management stating the company anticipates a move to "more of a low-teens liquids percentage" by year-end.

SUMMARY

Gulfport Energy Corporation (GPOR 0.91%) introduced incoming President and CEO Nick Delazzo, with management emphasizing sustained financial and operational execution as the company transitions leadership. The completed discretionary acreage acquisition program added material drilling inventory at costs below regional market comparables, supporting reserve longevity and near-term value creation. Gulfport’s record pace of share repurchases—approaching 10% of outstanding shares over two quarters—demonstrates active capital allocation and balance sheet flexibility, with no operational or marketing constraints limiting growth options. Strategic rig reductions, improvements in drilling and completion efficiency, and a gradual shift toward higher-liquids exposure in the production mix position the company to benefit from evolving commodity price environments.

  • Management clarified that further land acquisitions and share buybacks will be dynamically balanced, using available free cash flow and revolver capacity as needed.
  • Marketing strategy leverages diverse firm transportation agreements, enabling flexible sales across Gulf Coast, Midwest, and Northeast, with no midstream constraints reported.
  • Operational leadership characterized drilling improvements as ongoing, particularly in the Marcellus and SCOOP, where cycle times and consistency influence long-term capital allocation decisions.
  • Service cost inflation is currently limited to diesel and logistics, while locked multi-year service contracts and internal efficiency gains help offset broader service price pressures.
  • Hedge coverage for 2027 remains at the lower end of the company’s historic 30%-70% target range, with management stating, "Right now, we are a little on the bullish side, so we may keep that a little bit lower, but it will be a dynamic process as we continue to assess what 2027 looks like."
  • Gulfport reiterated intention to maintain leverage at or below one times even while returning substantial capital to shareholders.

INDUSTRY GLOSSARY

  • Mcfe: Thousand cubic feet of gas equivalent, a measurement standard converting oil and NGL volumes into natural gas equivalents for reporting production or reserves.
  • LOE: Lease operating expense, referring to the direct costs of operating and maintaining production assets.
  • Turn-in-line: The process of bringing a drilled and completed well online to begin commercial production.
  • Spud-to-rig-release time: The period from the start of drilling a well (spudding) to rig release, indicating overall drilling cycle efficiency.
  • Discretionary Acreage Acquisition Program: Gulfport’s targeted initiative to acquire additional leasehold near core assets, distinct from routine leasing or larger M&A.
  • HERO pad: Specific well pad in the SCOOP play; contextually, the name for a multi-well development yielding notable drilling efficiency gains during this quarter.
  • Type curve: Standardized production profile used to estimate well performance and economic returns for a specific asset or field.

Full Conference Call Transcript

Michael L. Hodges: Thank you, Jessica, and thank you for joining our call today. Before we begin, I would like to take a moment to welcome a new leader to Gulfport that I know many of you are already familiar with. Last evening, we announced that Nick Delazzo will be joining Gulfport as our President and Chief Executive Officer beginning May 28. Following a thorough search process, the board unanimously agreed that Nick is the right leader at the right time to propel Gulfport into its next chapter. He brings more than two decades of energy industry experience, a sharp focus on operational and financial discipline, and a proven track record of delivering value to shareholders.

Nick is joining Gulfport at a time when the company has never been stronger, and we are excited to work with him to create long-term value for all stakeholders. Nick looks forward to engaging with our employees and shareholders in the coming months, and joining us to take your questions on our next quarterly call in August. With that said, we are off to a great start to 2026 at Gulfport, highlighted by the successful completion of our previously announced discretionary acreage acquisition program and a record quarter of share repurchase activity.

I will share additional details on our land acquisition accomplishments a bit later, but we believe the swift and decisive actions we have taken over the past three years in the Ohio Utica have delivered significant value to the company as the demand for high-quality, low breakeven inventory across the industry continues to increase. When combining these initiatives to grow net asset value with our ability to repurchase nearly 10% of our market cap over the past two quarters at prices well below the underlying value of our business, it has been a very successful close to 2025 and start to 2026.

Turning to our first quarter results, it was an especially strong kickoff to the year financially as the company generated $264 million of adjusted EBITDA and $119 million of adjusted free cash flow, driven by strong commodity pricing and the continued development of our high-quality asset base. Average production totaled 997 million cubic feet equivalent per day, which was consistent with the expectations we provided in February and keeps us on track to deliver on our previously stated full-year production guidance of 1.03 to 1.055 billion cubic feet equivalent per day. Cash operating costs for the first quarter totaled $1.38 per million cubic feet equivalent, also in line with our expectations and similar to last year.

We expect this to be a quarterly high point for Gulfport as we anticipate declining per-unit cost as we move through the year. With our production cadence expected to accelerate later in 2026, the fixed charges embedded in our operating costs are expected to decline on a per-unit basis over the course of the year and land within the range of our full-year guidance. For full year 2026, we are reaffirming our per-unit operating cost guidance, which includes LOE, midstream, and taxes other than income, of $1.23 to $1.34 per Mcfe.

On the capital front, we incurred a total of $118 million related to drilling and completion activity and $4 million related to maintenance, land, and seismic investment while achieving the significant operational success that Matt will address in his comments. Most importantly, and as I mentioned earlier in the call, we wrapped up our previously announced discretionary acreage program, investing approximately $102 million over the past four quarters to add more than two years of high-quality inventory adjacent to our core positions in Belmont and Monroe Counties. These acquisitions were made at an average cost of just over $2 million per net location, significantly below implied recent valuation metrics from larger inorganic transactions in the immediate area.

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

We believe these opportunities continue to rank extremely high as we evaluate the uses of free cash flow in 2026 and beyond. Turning to the balance sheet, our financial position remains strong and we recently completed our spring borrowing base redetermination, adding 10% to elected bank commitments and reaffirming the borrowing base at $1.1 billion. Our trailing twelve-month net leverage exiting the quarter was approximately 0.9 times and, pro forma for the increase in elected commitments, at the end of the first quarter, Gulfport’s liquidity increased by $100 million and totaled $872 million, comprised of $2.9 million of cash plus $869.3 million of borrowing capacity under our revolver.

We greatly appreciate the support of our bank group as we position the company to opportunistically deliver value to our shareholders, and our liquidity position is more than sufficient to fund our development needs for the foreseeable future, providing significant financial flexibility as we continue executing on our capital allocation strategy. As I mentioned earlier, with this balance sheet strength and liquidity in place, we continue to deploy capital towards shareholder returns through our share repurchase program. During the first quarter, we repurchased 866 thousand shares of common stock for approximately $172.8 million, representing the highest quarterly investment in company history and well ahead of our previously announced plans in February.

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

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

Now I will turn the call over to Matt to discuss our operational highlights for the quarter.

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

On the completions front, we brought five gross Utica dry gas wells online during the first quarter, including our first two U development wells, which continue to perform consistent with recently developed straight lateral offsets. Importantly, this activity has unlocked approximately one year of additional high-quality inventory that can be strategically placed in our future development plan, providing additional flexibility. Looking ahead, we have an active completion and turn-in-line schedule with approximately two-thirds of our remaining 2026 turn-in-lines expected to include a significant liquids component in their production profile. This mix highlights the company's balanced approach to developing our assets and provides exposure to dynamic market conditions, allowing us to capture value across changing commodity price environments.

Lastly, I would like to compliment our team's continuous focus on operational improvements, as we delivered strong results during the quarter. In the period with our highest level of activity, the operational teams executed with zero recordable incidents or spills, underlying our commitment to safety and the environment in tandem with best-in-class operations. Our drilling team delivered an exceptional quarter, achieving incremental efficiency gains in each area of our core operations. In the Utica, we maintained our record all-in footage per day realized in 2025, and as we continue to extend lateral lengths across our asset base, we have concentrated our efforts on improving performance in the vertical section of the drilling phase to enhance overall cycle times.

During the quarter, our average top-hole drilling days improved by 8% compared to full year 2025, and we set a new company record for the fastest Utica top hole drilled for Gulfport to date, completing the section in just 5.4 days. Not only did we set a single-well record, the four-well pad delivered an average top-hole record of 5.9 days per well, demonstrating the opportunity for long-lived efficiency gains. In the Marcellus, we finished drilling a four-well pad during the first quarter, and when compared to the prior two Gulfport-operated pads in the area, we delivered a 20% improvement in footage drilled per day.

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

As we have discussed previously, the completion side of our operations has been continuing to perform at very high levels and our emphasis there remains on maintaining those efficiencies. With that consistency, we have been able to deliver our first two pad turn-in-lines of the year on time and on budget. In summary, our operational results this quarter mirror the broader performance Michael outlined—disciplined execution, continuous improvement, and a focus on creating long-term value. The consistency we are seeing across our operating areas positions us well to support Gulfport's strategy. And with Nick preparing to join our team, we are confident our operations are well aligned to support the next phase of execution and deliver durable returns over time.

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

Operator: Thank you. We will now be conducting a question and answer session. We will now open the call for questions. Our first question will come from Neal Dingmann with William Blair.

Neal Dingmann: Good morning, all. Michael and Matt, thanks for the details. My first question is probably for you, Michael. It is on capital allocation. Specifically, how do you all think about allocating for further discretionary acreage—which, again, the stuff you have done seems to have fantastic upside—versus your stock buybacks, where you have been very active? And maybe add one more twist to this: in a quarter like the one we are in now, which is probably your lowest free cash flow quarter of the year, would you consider using debt to do either of those if the opportunity existed?

Michael L. Hodges: Hey, Neal. Thanks for the question. I think it is an excellent one. Our approach has been consistent over the last few years—it has been to capture as many of those high-quality locations as we can. The opportunity set there has been available to us, and we think those generate some of the highest returns when you can drill those in the near term. That has been a priority for us and continues to be a priority. We believe there is still more running room there, and we will likely update the market a little later in the year on what that looks like for the rest of the year. I would say that has consistently been a high priority.

We think the equity is still undervalued; it has been a good opportunity for us to get that back at what we think are attractive prices. So I would say it is a combination of the two. The health of the balance sheet allows us that flexibility, as you pointed out, to lean on that a little bit in quarters where we may have a little bit less free cash flow. As we go into the second quarter, we do still have quite an active development program that Matt talked about. If we see opportunities to use the revolver to get some equity back at a good value, we would consider doing that.

Our approach has been dynamic; we have stayed away from formulaic approaches, and that has worked well for us. I would summarize it by saying it is a combination of all of them, and it is something we evaluate continuously. The priority around locations over the last few years has been a strategically advantageous move for us, and we think others are starting to follow along more closely with that. We will keep you updated as we have more details, but that will continue to be one of the highest priorities.

Neal Dingmann: Great to hear. Your inventory sort of speaks for itself now. Secondly, on marketing—you talked about optimizing the marketing strategy. How has that evolved, and how are you thinking about that strategy? Do you have any constraints if you wanted to crank up production—thinking more about takeaway—if you wanted to expand production?

Michael L. Hodges: It is a good question, Neal. There are really not any constraints around that. We have a very strong firm transportation portfolio that gives us good access to various locations, and that has been an advantage over the last few years. We have Gulf Coast access that gives us LNG-type pricing. We have Midwest exposure that we think is advantaged, certainly in the seasonal periods—the winter season tends to trade very well. We are able to sell gas locally as well. There is a lot of excitement around data center demand, and, as we talked about on the last call, there is some improving outlook for prices even in the Northeast.

So no constraints around being able to sell additional gas. We are always thinking about maximizing free cash flow, and so far we feel like the right way to do that has been to keep our production relatively flat. Certainly, if there were a signal that would be rewarded—or an opportunity to move the needle from a pricing perspective—it is something we could consider. But the strategy has been very successful the last few years and, at least at this point, makes sense for our company. There are no constraints around midstream or downstream markets that would keep us from considering that type of option.

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

Benjamin Zachary Parham: Yes. First off, congrats on Nick joining the team. I think that is a great hire. My first question for Matt—you talked a lot about drilling gains in both the SCOOP and in Appalachia. Could you unpack that a little bit more? Where do you think we are in the evolution of those drilling gains, and what is the runway in front of you to continue to shave days and hours off?

Matthew H. Rucker: Yes, sure. Thanks, Zach. I would categorize that as kind of the sixth inning, if you will, in a baseball analogy. We have talked for a while about our completion side of the business achieving things like 22-hour pumping days, and obviously there are only 24 hours in a day, so it is really about maintaining efficiency there. We have talked a lot about the drilling side and the opportunity set in front of us. This quarter demonstrates that focus that the team has had and the ability for us to keep chipping away at that. What I am most proud of is hitting that in all three core areas and finding those gains.

In the Utica, where we have been operating for a long time, outside the curve and lateral we are finding opportunities in the top-hole section of the wells, which are incremental days you can gain back. The Marcellus is relatively new to us as a company, but not to our operating team, and just now on our third pad there, we have been able to see that 50% increase even with the longest laterals that we have drilled in that play to date. Then in the SCOOP, being able to achieve roughly 40-day cycle times in a pretty challenging environment speaks to us becoming a more consistent program in that asset where we feel more comfortable continuing to deploy capital.

I think there is more room to go, to be fair, but we have made great headway heading into 2026 where that has been a key focus area for us.

Benjamin Zachary Parham: And my follow-up—are you seeing any inflation on service prices at this point? There has been some volatility in the commodity, but we have seen some modest activity adds, and some service providers think there is more coming—maybe not so much in Appalachia, but in other parts of the U.S. What are you seeing?

Matthew H. Rucker: We are certainly seeing it around diesel. That is not only straight fuel price, but it can bleed into logistics and trucking as well. I would say that is where we are seeing the biggest move. A lot of our heavy service contracts around pressure pumping, rigs, and things like that, we do a good job of locking in for the year ahead or being constructive around that. So no real impact to the capital—we are not changing guidance. Some of these efficiencies we have talked about could help offset those recent impacts around diesel. We try to mitigate those things by maintaining and improving our efficiencies and continuing to work with our service providers in this challenging fuel environment.

All in all, I would say we are kind of net neutral at this point, but keeping an eye on it and working with our providers as the year progresses.

Operator: We will hear next from Tim Rezvan with KeyBanc Capital Markets.

Timothy A. Rezvan: Good morning, folks. Thank you for taking our questions. Mike, I want to start on repurchases. You gave specific targets the last two quarters—I know you exceeded it in the first quarter. You did not give one going forward. You used more ambiguous language about it being an attractive use of capital, and we are looking at the first quarter, which was about half of the total for 2025. Should we think about 100% of free cash flow and land there in the ballpark for this year? And is there a reason you did not put a number now and why you did put a number the last couple of quarters?

Michael L. Hodges: Hey, Tim. Thanks for the question. If you think back to the fourth and first quarters: in the fourth quarter, we had some CapEx where we were doing appraisal work and had some acceleration of capital. There was logic around giving a target to ensure the Street understood that we were not borrowing against what we had otherwise allocated to share repurchases—that the accelerated capital was in addition to that. That was the thought process there. We got into the first quarter, saw some opportunity in the equity, and also had the wrap-up of our discretionary acreage program.

Those were the quarters where we gave more of a target, and as you noted, we ended up exceeding it in the first quarter because we saw some opportunities with a block we were able to pick up and changes in what we felt like the underlying value versus the opportunity to buy at was. Going forward for the rest of the year, we will be more consistent with what we have done the last four years—think about things on a full-year basis, not marry ourselves to a formula, and be dynamic. We will not allocate quarter by quarter; we think about it annually.

The balance sheet, at nine-tenths of a turn, gives us some opportunity with a lot of free cash flow coming later this year. We have a lot of liquids development coming up, and we see the environment for liquids as pretty positive right now. I do not think we will allocate all in the later part of the year; we will see what near-term cash flows look like—second quarter, third quarter, even into fourth quarter—see where the equity trades, and allocate accordingly. I understand it is a little bit ambiguous—it is intentionally that way because we want to be dynamic—but we do see a lot of value and plan to continue the repurchase activity.

Timothy A. Rezvan: Okay. That makes sense. As a follow-up on liquids—you put a bar chart in your deck showing the increase in liquids skew. Can you help us ballpark that? Is that like a 15% exit rate or back-half liquids skew? You were at 9% liquids in the first quarter. Should we assume you are going to lean in and maybe be at a 15% plus level going forward?

Michael L. Hodges: I think the nice thing is we have the option to make those changes. Thinking back a few years ago when Matt and I joined, Gulfport did not have that flexibility in the program. Now those things are available to us. You are right—we will become a little more liquids heavy as the year progresses. We have a couple of wet gas Utica pads coming up, some Marcellus development, and our SCOOP, which has the liquids component. There is a fair amount of liquids coming online for us at a very opportune time. As we go into 2027, we can make those decisions as well.

In terms of being 15% liquids—we are a gas company with a mature asset base, so moving that needle to that level may be a bit ambitious. But I do think as we go through the year, you will see us get to more of a low-teens liquids percentage, with the opportunity over time to take that even higher. For this year, back-half weighted, call it low teens, and then we will assess where we want to go for 2027.

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

Carlos Escalante: Hey, good morning to you. Thank you for taking our question. Matt, on the North Marcellus pad or appraisal that you are drilling later this year, can you outline this for us? What is the gross resource that the well spud is testing for, and what is the EUR you need to see to justify a programmatic Marcellus North development versus considering maybe a one-off? I know that there is some production from one of your competitors up there that looks good, but wondering if you see anything particular in your specific area.

Matthew H. Rucker: Sure, Carlos. Thanks for the question. I would bracket that there is not as much delineation for us. When we think about the types of EURs and deliverability we will see there, we approximate it very similarly to our Marcellus South. Quite simply, for us it is a new pocket of development without an infrastructure component at the moment with a third party. We are going in with a two-well approach—one north, one south—to confirm our assumptions and make sure the liquid percentage—both NGLs and oil—and composition are understood so that we can then go to our potential midstream providers to get the best economic outcome for that block of acreage.

There is nothing specific we need to see to pull the trigger; it is more about confirming our type curve from a liquids-weighting perspective and then immediately going into contract negotiations with a midstream and processing provider to unlock that development with good economic parameters.

Carlos Escalante: Thank you. That is very helpful. A quick follow-up for Mike on hedges. You are targeting roughly 30% to 40% hedge coverage in 2027. Presumably you would start to work on that in the near term. At what NYMEX level do you accelerate that or contract that? Is there a floor below which you choose to stay unhedged on the view that the curve is too low?

Michael L. Hodges: It is a good question, Carlos. On the hedging side, we try to remain flexible. Your observation on where we sit for 2027—we have talked previously that we like to be in the 30% to 70% range as we enter a year. We are near the lower end of that if you think about 2027. We have six or seven months left here in 2026. We are pretty bullish on gas going into next year. The volatility earlier this year, and what some of our peers have talked about, indicates there will be opportunities to create value through the hedge program. We like that we have that baseline amount in place already for 2027.

From here, we can nibble when there are opportunities. I do not feel like we have to go do anything in the near term unless we see those opportunities, and typically this time of year is not where you get a lot of them. As we get into next year, we will continue to adjust. There have been years where we are a little more bearish and at the higher end of the range, and years where we are more bullish. Right now, we are a little on the bullish side, so we may keep that a little bit lower, but it will be a dynamic process as we continue to assess what 2027 looks like.

Operator: We will go next to Jacob Roberts with TPH.

Jacob Phillip Roberts: Good morning. I wanted to start on the SCOOP. Obviously, decent results there. You have said in the past that the SCOOP was competitive with your Northeast assets, and the implication here is that it has become even more competitive. What do you need to see in the market to allocate a more meaningful amount of capital to that asset, and where do you see this asset participating in that growth scenario you spoke about if the market calls for it?

Matthew H. Rucker: Thanks for the question, Jake. I will start and Michael can add his comments. The results on the drilling side are a great step in the right direction for us. We have talked about the last couple of years really being about finding operational execution consistency in the SCOOP. If we are able to get those drilling days to 40, sub-40, and do it consistently and repeatably, it gives us a lot more confidence in that asset if the time calls for us to flex activity there. On a single-well IRR basis, it competes in our portfolio.

When you blend that in, it is still a capital-intensive asset with longer cycle times, and we are very mindful of that when we think about our calendar-year cadence and what that does for the company. For this year, we will get these wells completed and turned to sales later in 2Q, evaluate those results, and then it will be part of our program going forward. To the extent we flex more into that in later years, we will always be looking at that within our overall capital allocation program. It is really about seeing that consistency every time we go to drill.

With this one being the best we have done so far, we would like to see that again before we make any radical changes.

Jacob Phillip Roberts: Thank you. That is helpful. As a follow-up, on liquids hedging—I saw you added some swaps in addition to the collars on the oil side during 2027, as well as some propane swaps for 2027. What is the thinking there, and should we expect that number to move higher throughout this year?

Michael L. Hodges: Great observation, Jake. That market improved in the last couple of months, and we really did not have a lot in place for that component of our revenue stream. We saw an opportunity to put a position in. As I mentioned earlier, we like to be in that 30% to 70% range, so we layered those in. That is an area where you have to monitor geopolitical events and decide whether they get resolved in the near term or longer term. We are not going to try to get too cute with it.

If there are opportunities where we can capture a little more value, we could do that, but we made some good progress looking out into next year at prices that are very attractive based on where we have seen realizations for both WTI and NGLs. We will assess our program for 2027. To the extent that we want to continue to lean in on the liquids side, we have unhedged barrels that you can always shift around, and that is a way of adjusting your hedge percentages through your own activity. We will continue to monitor this as we think about the right blend for 2027.

Operator: Moving next to Peyton Dorne with UBS.

Peyton Rogers Dorne: First question on my end, maybe for Mike. Gas pricing was really strong in the first quarter. Could you provide some color on how you see differentials trending in 2Q and as we progress into the summer months?

Michael L. Hodges: Hey, Peyton. Thanks for the question. I want to give a pat on the back to our marketing team. A number of operators in the Northeast saw opportunities with the setup going into February and captured some of the first-of-the-month pricing. Our team did an excellent job there, which led to some outstanding differentials and overall realizations for the quarter. That is something we work on consistently. It does not get a lot of airtime because it is a routine process here. Looking forward, we are still bullish on differentials overall.

We talked about this on the last call, and some of our peers are starting to talk about it as well: a lot of the demand we are seeing coming in the Northeast—specifically around data centers and power demand—seems to be lifting the long-term view on basis in the Northeast. It is an important component of our differential. We have exposure to the Gulf Coast and the Midwest, but still do have some Northeastern exposure that we think is only going to rise going forward. Our full-year guide on differentials is still appropriate. I think there is opportunity for some improvement as we go into later years—2027/2028—as some of that demand starts to show up.

Those are meaningful to our company. Even a $0.05 move in differentials can be important to free cash flow and EBITDA. We are set up well for the year and feel bullish about where things are headed in the future.

Peyton Rogers Dorne: Great, thanks. Just to go back to the Valerie pad in the Marcellus—it was nice to see the drilling efficiencies you obtained there. I know you changed the completion design a bit in the Marcellus when you went from the Hendershot pad to the Yankee pad and targeted the formation a bit differently too. How did you attack Valerie, and what learnings did you incorporate from Hendershot and Yankee into this most recent pad?

Matthew H. Rucker: Some of the completion design testing you spoke of was around the Hendershot being a two-well, one-in-each-direction unbounded delineation test initially. The Yankee four-well pad was more of a true development on our spacing. We learned a lot from that and landed our spacing assumptions where we wanted them. The designs around the Valerie are more about optimizing economics—well spacing and how much sand and water you need to effectively drain the wellbore. We took those learnings and applied them here to look at the best economic outcome. On this pad, that is what we did.

With the ability to have four wells, we did a bit of incremental testing on two of the inter-laterals as well—minor tweaks to continue to get more economically efficient. More to come there, but that is the evolution of what we have been doing.

Peyton Rogers Dorne: Sounds great. Look forward to seeing those. Thanks a lot.

Michael L. Hodges: Thanks, Peyton.

Operator: We will go next to Gabe Daoud with Truist.

Gabe Daoud: Thanks, operator. Good morning, everyone. Thanks for the time and congrats on bringing Nick aboard. Mike, on the back of your comments around in-basin pricing improving later this decade, are there any transport agreements that could be rolling in that period that you would let roll to provide a tailwind to the cost structure and margins?

Michael L. Hodges: It is a good question, Gabe. We are always assessing what we have. There are always smaller pieces within the portfolio that are not as critical and that you consider letting go from time to time, which can help a little bit. There are also opportunities to optimize your book and offload some of those on a shorter-term basis to other operators that need space. As basis improves in the Northeast, there are probably more netback decisions you can make around your firm portfolio and whether it makes sense to hold all of it. From a strategic perspective, we feel really good about the diversity we have and the exposure to different basins. I would not forecast making significant changes.

Having exposure in the Midwest and at the Gulf Coast—and even the diversity from a risk mitigation perspective—makes a lot of sense. You may see some small improvements on the cost structure within the portfolio around our Northeastern position, but nothing I would describe as a wholesale strategic shift for Gulfport at this point.

Gabe Daoud: Got it. Thanks, Mike. That is helpful and makes sense.

David Adam Deckelbaum: As a follow-up, your discretionary land program has been pretty successful over the last several years extending inventory life. How should we think about that program for 2026 and moving forward?

Michael L. Hodges: I am glad you asked, David. It really has been a big part of our success over the last few years. We are in the process right now of formulating our thoughts around it. We like to have a very clear path when we come out and talk about it. We think there continue to be some exciting opportunities around the basin. It is typically something we talk about around midyear. Our next call is likely to be in August. Over the last few years, we have done somewhere between $50 million and $100 million of discretionary acreage programs annually. To the extent that we have been successful—and we have—we like that allocation of capital.

I think there is a strong likelihood we will have something to talk about midyear that is a pretty exciting opportunity to capture more land this year. It is not unlimited—you have to be smart about it. There are areas where we can find locations that move into the near-term development plan, which is what enhances the economics the most. It is not a carpet-bombing exercise; it is us going out and making sure we have that line of sight before we allocate the dollars. We will talk about it more later this year, but you can probably sense in my tone that I am pretty excited about what we will have to share later on.

David Adam Deckelbaum: For sure. Thanks, Mike. Great color—really appreciate it.

Gabe Daoud: Great.

Operator: This now concludes our question and answer session. I would like to turn the floor back over to Michael Hodges for closing comments.

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

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