Greetings, and welcome to the Gulfport Energy Corporation First Quarter 2025 Earnings Call. It is now my pleasure to introduce your host, Jessica Antle. Thank you. You may begin.

Thank you, and good morning. Welcome to Gulfport Energy Corporation’s first quarter 2025 earnings conference call. I am Jessica Antle, Vice President of Investor Relations. Today’s speakers include John Reinhart, President and CEO, Michael Hodges, Executive Vice President and CFO, and in addition, we have Matthew Rucker, Executive Vice President and Chief Operating Officer, who will be available for the Q&A portion of today’s call. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the company’s financial condition, results of operations, plans, objectives, future performance, and business. We caution you that the actual results 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. Reconciliations to the comparable GAAP measures will be posted on our website. An updated Gulfport presentation was posted yesterday evening to the website in conjunction with the earnings announcement. At this time, I would like to turn the call over to John Reinhart, President and CEO.

Thank you, Jessica, and thank you for joining our call today. Gulfport began 2025 with strong momentum, delivering first quarter results that exceeded internal expectations. The company realized a $0.45 per Mcfe premium to NYMEX Henry Hub on a natural gas price equivalent basis, opportunistically repurchased 60 million of Gulfport common shares at attractive prices amid market volatility, highlighted corporate planning flexibility with a shift in second half 2025 capital allocation towards natural gas drilling and reaffirmed the company’s full year guidance driven primarily by a forecasted 20% growth in our natural gas volumes by the fourth quarter of 2025. The success of the marketing, operational, and planning teams positions the company attractively throughout the year and into year end, aligning well with a constructive natural gas outlook for 2026. Our priorities remain centered on maintaining an attractive balance sheet, generating significant free cash flow, executing a robust shareholder return program, enhancing operational efficiencies, and advancing our development program to support production growth throughout the year. Moving to our first quarter results, our average daily production totaled 929 million cubic feet equivalent per day, aligning with company expectations and keeping us on track to deliver our previously stated full year production guidance of 1.04 million to 1.065 million cubic feet equivalent per day and are positioned favorably for meaningful natural gas production growth in the upcoming quarters. The company remains committed to developing our assets in a responsible manner and allocating capital to the highest value opportunities. Given the current commodity environment, as you will see from the investor deck on Slide 11, we have updated our drilling plan to include a four well dry gas Utica pad during 2025 and deferred a four well Marcellus pad to 2026. These planning optimizations highlight the company’s flexibility to be dynamically responsive to market conditions in order to maximize shareholder value. Inclusive of these changes, we are reaffirming our full year operated drilling and completion capital guidance of $335 million to $355 million. On the land front through March 31, 2025, we have invested roughly $11 million on maintenance leasehold and land investment focused on bolstering our near term drilling programs with increases in working interest and lateral footage in units we plan to drill near term. While we did not have any discretionary acreage acquisition spend during the first quarter, we continue to assess the landscape and remain optimistic about opportunities to meaningfully increase our leasehold footprint to enhance resource depth. These opportunities rank very high as we evaluate uses of free cash flow in 2025. Operationally, in Ohio during the first quarter, the company completed drilling on 13 gross wells, 7 targeting Ohio Utica, 4 targeting Ohio Marcellus, and 2 in the SCOOP targeting the Woodford. We entered the year with three operated rigs running and as planned released the SCOOP drilling rig in mid-February and released the second Ohio drilling rig just last week. We currently have one rig running in Ohio and anticipate this drilling cadence to continue for the remainder of 2025. On the completions front, we brought online seven gross Utica wells in March including three Utica dry gas wells and four Utica condensate wells, which represent our cage development in Southwest Harrison County highlighted on Slide 12 of the investor presentation. Located further west in the condensate window relative to the Lake VII Pad, the cage is performing exceptionally well, delivering early production rates nearly double those of the nearby highly productive Lake VII Pad. This outperformance reflects continued optimization in completion and facility designs as well as a revised managed pressure flowback strategy. Taking our learnings from the Lake VII Pad, we refined the stimulation procedures and redesigned the cage facilities to accommodate higher flow rates. During the initial flowback, we increased production volumes to take advantage of strong reservoir productivity and higher liquids yields. These early results, in combination with the continued strong performance of the Lake VII development, reinforce the attractiveness of this acreage and the development optionality it possesses. Specific to our Marcellus activity, we continue to be encouraged by our Hendershot Pad results. The company’s first operated Marcellus wells on our STACK pay acreage in Belmont County, Ohio that were turned to sales November 2023. Following roughly a year and a half of production history, our forecasted oil EURs per foot of lateral place these two wells in the top 5% of all Marcellus oil wells drilled to date. We are excited to transition to development mode in the Marcellus during 2025. The company completed drilling the four well Yankee pad during the first quarter and recently finished stimulation operations on the pad and plans to bring these wells online late in the second quarter. Lastly, as noted in our opening comments, the team’s continuous focus on operational improvements led to several new execution records. On the drilling side, in the Utica, we experienced a 28% improvement over full year 2024 in footage drilled per day. The company’s average spud to rig release days also decreased by over 30% compared to full year 2024, including records of 13.7 days spud to rig release for a 15,000 foot Utica lateral and 15.1 days spud to rig release on a Utica lateral reaching over 20,000 feet. On the completion side and subsequent to the quarter, our Utica frac provider set two new company records for continuous pumping performance in the Northeast, both of which were on Gulfport operated pads. On the recently completed Marcellus pad, the teams achieved 97.5 continuous pumping hours completing 69 stages, placing over 23 million pounds of sand and pumping roughly 490,000 barrels of water in that time period. At the same time, a second fleet achieved over 105 continuous pumping hours on a Gulfport Utica dry gas pad completing 63 stages while placing over 21 million pounds of sand. Both of these milestones significantly surpassed their previous records and highlight the strong collaboration and alignment with our vendors to make these results possible. In closing, we experienced a strong quarter of execution and are well positioned to continue delivering on our financial and strategic objectives for 2025. The reallocation of activity to more dry gas development and strong natural gas growth throughout the year will position the company to capitalize on the strengthening commodity environment as we enter 2026, ultimately improving free cash flow generation and allowing us to prioritize returning capital to shareholders. Now, I will turn the call over to Michael to discuss our financial results.

Thank you, John, and good morning everyone. Our first quarter financial performance highlights a strong start to the year with results ahead of company expectations and the operational momentum that John described positioning us well for the remainder of 2025. Net cash provided by operating activities before changes in working capital totaled approximately $207 million during the first quarter, more than funding our capital expenditures despite a capital program that is roughly 75% weighted to the first half of 2025. We reported adjusted EBITDA of approximately $218 million during the quarter and generated adjusted free cash flow of $36.6 million for the same period, bolstered by our strong realized pricing and GAAP differentials better than analysts and company expectations. Cash operating costs for the first quarter totaled $1.31 per million cubic feet equivalent in line with the company expectations and an expected quarterly high point for Gulfport as we anticipate declines moving forward. With our production cadence expected to accelerate throughout 2025, 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. Similar to previous years and consistent with our internal expectations, our first quarter operating costs were impacted by winter weather operations that led to slightly higher per unit costs early in the year than in other periods. For the full year of 2025, we are reaffirming our per unit operating cost guidance, which includes LOE, midstream and taxes other than income of $1.2 to $1.29 per Mcfe. Our all-in realized price for the first quarter was $4.11 per Mcfe before the impact of cash settled derivatives. This realized unit price is $0.45 or 12% above the NYMEX Henry Hub index price, highlighting the benefit of Gulfport’s diverse marketing portfolio for natural gas and the pricing uplift from our liquids portfolio in both our asset areas. As you are likely aware, winter weather this year delivered daily pricing during periods of peak demand that was above what would otherwise be expected. As a result, our natural gas price differential before hedges was an $0.08 per Mcf premium to the average daily NYMEX settled price during the quarter, ahead of analyst consensus expectations and significantly better than even the narrow end of our full year guidance range. Turning to the balance sheet, our financial position remains strong with trailing 12 month net leverage exiting the quarter at approximately 0.9 times, down from the prior quarter and benefiting from the increasing cash flow our business has delivered over the past year. As of March 31, 2025, our liquidity totaled $906 million comprised of $5.3 million of cash plus $901.1 million of borrowing base availability. We recently completed our spring borrowing base redetermination and our lenders unanimously reaffirmed our borrowing base of $1.1 billion with the elected lender commitments remaining at $1 billion. Our liquidity today is more than sufficient to fund any development needs we might have for the foreseeable future and provides tremendous flexibility from a financial perspective going forward. With respect to EBITDA and adjusted free cash flow generation, the rising natural gas curve over the next twelve months along with our continuous operational improvements position 2025 to be a transformative year for Gulfport from a cash flow perspective. Based on current strip pricing, we forecast our adjusted free cash flow to grow significantly over the coming quarters, which should further strengthen our already top tier free cash flow yield relative to our natural gas peers. We continue to view share repurchases as a compelling capital allocation opportunity and during the first quarter, we repurchased 341,000 shares of common stock for approximately $60 million and since the inception of the program, we have repurchased approximately 5.9 million shares of our common stock at an average price of $108.99 lowering our share count by approximately 17% at a weighted average price that is 40% below our current share price. As of March 31, we had approximately $356 million available under our $1 billion share repurchase program and remain steadfast in our free cash flow allocation framework as we plan to return substantially all of our adjusted free cash flow, excluding discretionary acreage acquisitions to our shareholders through common stock repurchases. We believe our committed approach to share repurchases over the past few years has delivered tremendous value to our shareholders and we will remain opportunistic rather than programmatic, allowing us to allocate capital dynamically when we believe the current valuation does not reflect the strength of our underlying fundamentals. As such, repurchasing shares at current levels represents a highly attractive use of capital. In summary, this year’s development program is off to a solid start as we execute on what will be a pivotal year for the company regarding free cash flow generation. We continue to succeed operationally on all fronts, prudently allocating capital to highest value opportunities, and returning a significant portion of our adjusted free cash flow to shareholders through our common share repurchase program. With that, I will turn the call back over to the operator to open up the call for questions.

Our first question comes from Tim Rezvan with KeyBanc Capital Markets.

Thank you for taking our questions. I want to follow first, John. You have this front end loaded capital program that you’ve run a couple of years. And when you look at kind of the first quarter results, is there any kind of regret that maybe this big sequential decline in production impacted your ability to take advantage of the strongest quarter of the year in terms of demand and pricing? And kind of how committed are you to this sort of front end loaded program going forward?

Hey, Tim. I appreciate the question and thanks for being on the call. What I’ll tell you is, as we look for development cadence throughout the year, we’re very sensitive to commodity environments and certainly having the hindsight of seeing where prices were dictates how we would allocate capital. I’ll tell you that in the first quarter, the volumes were planned to be lower. This was a cadence due to a turn in the line shortage in Q4. I think moving forward as we look at the well mix between dry gas, which has a much more stable production level, and the liquids, we’ll certainly take that into account. The shift towards dry gas in itself will actually work to accelerate cash flows for the company. So I wouldn’t say I regret the front-loaded capital program. We’ve used this for the past two years. I think what happened this year was in particular a shift towards liquids and the shorter plateau period caused production levels to fall off a little more aggressively versus dry gas. But moving forward with the shift in dry gas, we’ll be mindful of the program and ensure that we capitalize on volumes in the peak pricing seasons. So hopefully that answers your question.

Yes. That’s good context with the liquids wells. Thanks for that. And then as my follow-up, you reminded us in your prepared comments, John, that you haven’t budgeted for discretionary acreage but you see opportunities. Typically CEOs don’t state that by accident in their comments. So can you talk maybe a bit about what you’re seeing on the dry gas or wet gas side of things? And how is that market relative? Obviously, the oil market has seen quite a bit of volatility and A&D is probably stuck in the mud. So can you talk about what you’re seeing on that on the wet gas side and what gives you optimism that you may have an opportunity in front of you? Thank you.

Yes. I appreciate the question. The company is in a really fortunate position this year to have a fairly robust free cash flow profile. As we noted, we’re going to continue the same framework moving forward this year as we have the last two years, prioritizing shareholder returns and reinvesting in the company, to your point regarding discretionary acquisitions. As we look through the landscape in Ohio, I would tell you the teams are currently assessing. We’re very selective about where we’re focusing; it’s very much related to economics and what will deliver the highest cash flows because whenever we historically made these acquisitions, we put the bit to it and developed it within a year and a half to two years. That really impacts your returns. So as we examine the landscape, we favor the dry gas and the wet gas areas. You can look at the slide in our investor deck that highlights the returns in these areas and that will lead you to why we’re focusing on those areas. We’re not seeing a major appreciation in price; due to market volatility, it’s been relatively flat. I would also not rule out any investment pickups in the condensate window. However, they must be extremely attractive prices to warrant our capital allocation and discretionary program. We’re excited about the opportunities that exist and will continuously assess them, with more updates on the progress that the land teams will achieve throughout the year.

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

Thanks for taking my question. First, could you just talk a little bit more about the cage pad, maybe what’s driving the outperformance of the cage development versus the lake pad? Is it something in well design or frac design? Is it geology or facilities that you have in place? Just would like to get a little more color there on the outperformance.

Yes. Thanks, Zach. This is Matt. I’ll take that one. We took the Lake Pad. The teams did a really good job kind of dissecting the outcome of that pad. A couple of factors contribute to this; really around frac design, rightsizing the fracture's sand loading, water loading, as well as what we consider to be a really effective cluster spacing design on that pad. As we talked about last time, we tested a more aggressive approach on that lake pad after a period of choke management to assess those results. Through those results, we gained a better understanding of the reservoir as well as requirements from the facility standpoint to be able to flow at higher rates. All of these factors were combined on this pad with an efficient development process. We’ve been very pleased with the initial results from the first thirty days. It's still early, but with very strong results, minimal drawdown speaks for itself around the IP30 there. So a very good result from the teams there and certainly something we think we can apply moving forward to the rest of our inventory.

Thanks for that. Also wanted to ask on the shift in activity. Shifting a little bit of activity in the second half of the year towards dry gas versus wet gas. I know it’s early, but how are you thinking about 2026? Could you be looking to grow gas a little bit next year? Your 4Q implied gas rate is just over a Bcf a day. If you held that flat next year, that’d be 5% or 6% growth. Just looking for some early thoughts on how you’re thinking about 2026.

Yes, Zach, appreciate the question. To your point on the 2025 schedule, what we wanted to highlight here was the team’s flexibility. As we look at these wells that we’ll be drilling and not turn to sales, we feel it was a very prudent shift towards natural gas by pushing out the Marcellus pad into 2026 and prioritizing the four well dry gas pad. We won’t be providing guidance for 2026, but we are closely observing the macro environment on the oil side, supply-demand, and its impact on price. The natural gas market is setting up extremely constructively, prompting us to shift towards a more balanced wet gas and dry gas program for 2026. More details will follow towards the end of the year, but we like how the macro is shaping up for gas-weighted areas in our portfolio and this shift in drilling activity in the second half of 2025 gives you an early idea of how we’re thinking about 2026.

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

For my first question here, I want to point out your drilling efficiencies seem to continue to improve. I was wondering if the cutting edge drill times and frac efficiencies are contemplated in your current 2025 CapEx guidance?

Noah, this is Matt. You’re right. The teams have continuously pushed to do more and never cease to amaze with the results that they generate. On the drilling side and both the frac side, we’ve modeled in the average efficiencies we’ve observed over the past twelve months. Any improvements beyond that would certainly benefit us. We don’t continuously upgrade those throughout the calendar year, but based on where we’re at today, I believe reaffirming the capital guidance aligns with our activity. There’s certainly a lot of upside potential specifically on the drilling side, and we’re excited about what that team can achieve for us.

Sounds good. And then last month there was the Borealis pipeline expansion open season. I was wondering if Gulfport would be interested in signing up for that or how Gulfport views signing up for any additional FTE out of basin?

Yes. Hey, Noah, this is Michael. It’s a great question. We are familiar with the project and assess any projects like that on a netback basis. The way we think about those things is where does that gas go, what’s the cost to get it there, and what kind of sales price we could expect if we signed up for something like that. I won’t comment specifically on that project, but we’re always looking for projects where we believe we can improve our netbacks. We do have the fortunate position of having uncommitted volumes, which gives us an advantage to take on what I would consider premium opportunities if they fit in our portfolio versus a competitor that may not share that flexibility. So, yes, we evaluate all of that. Our marketing team has excelled in the first quarter on our differentials, and if we find projects that make sense, you’ll likely see us involved.

Our next question comes from the line of Gabe Daoud with TD Cowen.

I was hoping to ask on Utica D&C per foot; given some of the efficiencies you’ve highlighted, I think you're targeting less than $900 a foot for 2025. Is that a level you are currently at today? Or are you progressing towards that level? I’m just curious, again, the efficiencies just continue to screen off the charts; is there more downside potential to that number?

Yes, Gabe, thanks for the question. This is Matt. We’re hitting that target today as we rolled out the budget and capital guidance. The numbers you highlighted are indeed part of that plan. As we’ve delivered on some of these efficiencies across selected pads, we are seeing costs drive lower. If we can sustain that improvement, there’s continuous downside potential to those per well costs. However, we are currently achieving that target and that is factored into the reaffirmed capital guidance.

Got it. And then maybe just a follow-up going back to Tim’s question regarding land purchases and A&D generally. Would love your thoughts on larger scale M&A in the basin and how Gulfport fits into that.

I appreciate the question, Gabe. Yes, I think as opportunities arise, they will come in various forms, and we’ll assess anything potentially accretive to the shareholders. We maintain a high bar regarding return on capital, considering what that would look like in relation to other uses of cash flow for the company, including share repurchases and discretionary acreage spending. We remain open to exploring any opportunities that would deliver value for the company and be accretive to our shareholders, but we also have a significant bar that we measure those against.

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

Thank you for taking our question. I would like to first ask about your decision to pivot into the dry gas Utica acreage instead of drilling the Marcellus well towards the end of the year. Our specific question is, what is the guiding principle under which you made this move? Additionally, what are the key commodity levels at which you believe it’s more favorable to bolster your economics and free cash flow for these commodities?

Yes. That’s an excellent question, Carlos. I’ll start by saying that’s a moving target for us as we look at efficiency gains, capital cost reductions, pricing, EURs, and well productivity; these are dynamic factors we continuously assess and upgrade. From a commodity price perspective, we are constantly observing market dynamics. Currently, there seems to be potential volatility and downward pressure on the oil side. I want to reiterate that our Marcellus condensate wells and Utica condensate wells still perform exceptionally well economically. For us, it’s about ensuring that we maximize our returns on the resources available and that drives how we allocate capital, which led us to push our second Marcellus pad to 2026 while prioritizing dry gas. The macroeconomic climate is very favorable for gas in 2026 and that awareness of volatility in the other commodity environments was a prudent move.

On that note, do you believe that with your recent pivot into a more liquids-heavy strategy, notwithstanding that you’re still 11%-12% of total production, your hedging strategy on gas changes given that the mix is somewhat of a hedge to your gas production? Does your hedging philosophy change with that incremental exposure to liquids? Or do you have the same thoughts around that as before?

Yes. Hey, Carlos, this is Michael. I’ll take that one. I think our hedging strategy has remained relatively consistent. When you have a strong balance sheet and low leverage, we can make hedging decisions strategically rather than reactively try to protect against downside risks. Looking specifically at our recent gas hedges, we aim to maintain some upsides within our collar positions. This reflects the bullish perspective we hold as we move forward on the gas side. As for liquids, we’ll protect some downside where it makes sense, but we are still predominantly a gas company. We remain focused on gas at this juncture as we approach the latter part of 2025 and into 2026, so no significant changes in our overall strategy.

Our next question comes from the line of Jacob Roberts with TPH.

I wanted to circle back to the cage pad. I wondered if you foresee this being the only activity you have planned there for the year. If so, when you do return to this area, how will you think about potential well design changes given the uptick from the lake pad? Additionally, did you foresee these types of results? If not, would you have pursued more activity here, or are we looking at more activity in a better oil price environment?

Yes, Jacob, this is Matt. Regarding well design changes, we consistently review every pad and type curve area for tweaks we can implement to improve well performance and cost-effectiveness. There are certainly lessons learned that can be taken from here. We’re pleased with the subsurface results from the initial 30 days, and there’s still plenty of time left for assessment. With regards to recovery levels from that pad and well spacing in frac designs, we will continue to evaluate those. What we’ve observed is ongoing improvement in costs that we can leverage to further enhance economics. I’ll pass it over to John for the second part of your question.

I appreciate the question, Jake. Even though we’re not guiding to 2026, we’ve indicated some shifts towards wet and dry gas in our late 2025 drilling schedule, which may impact production in 2026. We will remain focused on wet and dry gas, but I want to underscore that Marcellus and condensate at these rates of productivity continue to look appealing as capital costs decrease. Therefore, I wouldn’t completely rule out diversifying our mix next year; however, we approach it with caution and maintain a focus on maximizing returns in our capital allocation.

Thank you. We have reached the end of the question and answer session. I would like to turn the floor back to John Reinhart for closing remarks.

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

Ladies and gentlemen, this concludes today’s conference. You may disconnect your line at this time. We thank you for your participation. Have a great day.