Gulfport Energy Corporation (NYSE:GPOR) Q1 2025 Earnings Call Transcript

Gulfport Energy Corporation (NYSE:GPOR) Q1 2025 Earnings Call Transcript May 7, 2025

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

Jessica Antle : 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.

John Reinhart: 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 reaffirm 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 and 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 of 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 the opportunities to meaningfully increase our leasehold footprint to enhance resource depth and believe 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 that are 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 and delivering early production rates nearly double those of the nearby highly productive Lake VII Pad. This outperformance reflects continued optimization and 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 and during the initial flowback we have increased production volumes to take advantage of strong reservoir productivity and higher liquids yields being observed.

These early results in combination with the continued strong performance of the Lake VII development reinforce the perspective nature of this acreage and development optionality that it possesses. Specific to our Marcellus activity, we continue to be very 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 placed 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 plan 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% when compared to full year 2024, which included 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 further allowing us to continue to prioritize returning capital to shareholders.

Now, I will turn the call over to Michael to discuss our financial results.

Michael Hodges: 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 of 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 meaningfully 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. And 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 we will be a pivotal year for the company with regard to 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.

Q&A Session

Operator: [Operator Instructions]. Our first question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

Tim Rezvan: 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?

John Reinhart: 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 the commodity environments and certainly having the hindsight of seeing where prices were certainly dictates what the company and how we would allocate capital. I’ll tell you that in the first quarter, the volumes were planned to be lower. This was as of a cadence to your point from a turn in line shortage in Q4. I think moving forward as we look at the mix, the well mix between dry gas which has a lot more stable production level with regards to flat production profile versus the liquids, we’ll certainly take that into account and the shift towards the dry gas in and of itself will actually work to accelerate cash flows for the company.

So wouldn’t say I would regret front loaded capital program. We’ve used this for the past two years. I think what would happen this year was in particular a shift towards liquids and the shorter plateau period had the production levels fall off a little bit more aggressively versus dry gas. But moving forward with the shift in dry gas, I think we’ll be mindful of the program and ensure that we capitalize on volumes in the peak seasons for pricing. So hopefully that answers your question.

Tim Rezvan: 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 and 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.

John Reinhart: Yes. Appreciate the question. Yes, I think first of all the company is in a really fortunate position this year to have a fairly robust free cash flow profile. And as we noted, we’re going to continue the same framework moving forward into this year as we have the last two years prioritizing shareholder returns and reinvesting in the company to your point with the discretionary acquisitions. As we look through the landscape in Ohio, I would tell you that the teams are currently assessing. What we’re very picky about where we’re focusing, it’s very much related to economics and what’s going to deliver the highest cash flows because simply put whenever we go out historically over the past two years and made these acquisitions, we put the bit to it and developed it within a year and a half to two years.

That really does impact your returns. So as we look at the landscape, we favor right now 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 kind of lead you to why we’re focusing in those areas. We’re not seeing a major appreciation in price out there. Just I think with the market volatility, it’s been relatively flat. And I would also not roll out any kind of investment pickups in the condensate window. What I will tell you though is they have to be extremely attractive price to be able to warrant our capital allocation and the discretionary program. So we’re pretty excited about the opportunities that are out there. We continuously assess and throughout the year we’ll have more updates on the progress that the land teams will achieve.

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

Zach Parham: 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.

Matthew Rucker: Yes. Thanks Zach. This is Matt. I’ll take that one. We took that lake pad. The teams did a really good job kind of dissecting the outcome of that pad. I think a couple of things go into play there for us really around frac design, kind of rightsizing the fracture around proper sand loading, water loading as well as just what we consider to be a really effective kind of cluster spacing design on that pad. As well as with we talked last time about kind of our testing of going a little more aggressive on that lake after a period of choke management to assess those results. I’d tell you through those results, we kind of got a better understanding of the reservoir as well as just what it would take from the facility standpoint to be able to flow at higher rates.

So all of those things kind of were put together here on this pad with a really, really good efficient development. We’ve been very pleased with the first thirty days results here. Still early, but very strong results, minimal drawdown speaks for itself around the IP30 there. So very good result from the teams there and certainly something we think we can take and apply forward to the rest of our inventory out there when we get to it.

Zach Parham: 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.

John Reinhart: Yes, Zach, appreciate the question. I mean to your point on the 2025 schedule, what we really wanted to do was highlight the team’s flexibility here. And as we look at these wells that we’ll be drilling and not turn to sales, we feel like it was a very prudent shift towards natural gas by pushing out the Marcellus pad into ’26 and prioritizing the four well dry gas pad. We won’t be providing guidance on ’26, I think to your question. But what I will tell you is that we certainly are looking at the macro environment on the oil side, the supply demand, its impact on price and gas is setting up extremely constructively, which kind of shifts us towards a more weighted wet gas kind of dry gas program for 2026.

So more to come whenever we come to the end of the year for specific details, but what I will tell you is, we like how the macro is shaping up for the gas weighted areas in our portfolio And this shift in the second half of 2025 with the drilling should give you an idea of how we’re thinking about 2026 early on.

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

Noah Hungness: For my first question here, I want to your drilling efficiencies seem to continue to improve. And I was wondering if the cutting edge drill times and frac efficiencies are contemplated in the current 25 CapEx guidance?

Matthew Rucker: Noah, this is Matt. You’re right. I think the teams have continuously pushed to do more there and never cease to amaze with the results that they can churn out. On the drilling side and both the frac side, we I would say we’ve got modeled in kind of the average efficiencies that we’ve been seeing over the last call it 12 months. Anything above and beyond that certainly would be a benefit to us. And so those are we don’t continuously upgrade those throughout the calendar year. But based on where we’re at today, I think just reaffirming the capital guide with activity we have is where we are. So but a lot of upside there I think for the guys specifically on the drilling side. We continue to make larger chunks of gain there and really excited about what that team can deliver for us.

Noah Hungness: Sounds good. And then last month there was the Borealis pipeline expansion open season. And I was just wondering is this something that Gulfport would be interested in signing up for? Or how does Gulfport view kind of signing up for any additional FTE out of basin?

Michael Hodges: Yes. Hey, Noah, this is Michael. It’s a great question actually. We are familiar with the project and we assess any projects like that on a netback basis, right? So the way we think about those things is where does that gas go, what’s the cost to get to that location and what kind of a sales price could we expect if we were to sign up for something like that. So I won’t comment specifically on that project, but we’ll tell you that we’re always looking projects where we believe we can improve our netbacks. We do have the fortunate position of having uncommitted volumes. So again, I think that’s an advantage here at Gulfport that we can take on what I would consider premium opportunities if they fit in our portfolio versus a competitor that perhaps doesn’t have that flexibility.

So, yes, I would just tell you that we look at all that stuff. Our marketing team has done a really excellent job here in the first quarter on our differentials. And I think to the extent we find projects like that, that makes sense, then you’ll see us likely be involved.

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

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

Matthew Rucker: Yes, Gabe. Thanks for the question. This is Matt. Certainly, that’s something we’re hitting today as we kind of rolled out the budget and the capital guide there. Those numbers that you highlighted there were part of that plan. As we’ve delivered on some of these efficiencies on some select pads here, we are seeing those costs drive a little bit lower. So if we can sustain that and continue to improve there, obviously there’s continuous downside to those per well costs. But currently achieving that have been for the year and that’s kind of what’s rolling into the reaffirmed capital guidance.

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

John Reinhart: I appreciate the question Gabe. Yes, I think as opportunities arise and they come in certainly multiple forms, we’ll assess anything that would be potentially accretive to the shareholders. What I will tell you is that we certainly have a high bar with regards to return on capital, what that might look like based on the other uses of cash flow that we have in the company with share repurchases, with discretionary acreage spend. So, we certainly remain open and we will assess any opportunities that would provide value fundamentally for the company and be accretive to our shareholders. But we do also have a pretty hot bar that we measure that against.

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

Carlos Escalante: Thank you for taking our question. I guess we would like to first ask about your — to dig in a little more about your decision to pivot into the dry gas Utica acreage as opposed to drilling that Marcellus well towards the end of the year. Our specific question is, what is the guiding principle under which you decide to make this move? And if I can elaborate a little more on that, what are the key commodity levels at which you believe for each of the relevant commodities that it’s more favorable as you point out to bolster your economics and your free cash flow from one to the other?

John Reinhart: Yes. It’s a great question Carlos. Thanks. I’ll start by saying that’s kind of a moving target for us as we look at efficiency gains, capital cost reductions, pricing, EURs and well productivity that’s dynamic kind of scenario that we continuously assess and upgrade. What I will tell you from a commodity price specific and we take a look at the next year, two years, we follow the macro and just right now as we look at the landscape there’s just a lot of potential volatility and downward pressure on the oil side. I will reiterate though that these Marcellus condensate wells and these Utica condensate wells still perform exceptionally well economically. What I’ll tell you is for us it’s more of a making sure that we’re developing and maximizing the returns on the resources that we have in the company.

That drives how we kind of allocate capital and that shifted us to move towards our second Marcellus pad for this year pushing it to 26 and prioritizing dry gas. The macro is very favorable for gas in 26 throughout the end of this year and into next. And given the volatility in the other commodity environments that was a prudent move we felt.

Carlos Escalante: So just on that as my follow-up, do you believe that with your recent pivot into more liquids heavy strategy notwithstanding you’re still 11%, 12% of your total production that your hedging strategy on gas changes given that the mix is kind of a hedge to your gas production. Does your hedging philosophy change with that incremental exposure to liquids? Or do you still you have the same thoughts about that around that as you did before?

Michael Hodges: Yes. Hey, Carlos, this is Michael. I’ll take that one. I think our hedging strategy has remained relatively consistent. I mean, I think when you have the financial position that we have with a strong balance sheet and a low leverage, we’re able to make hedging decisions strategically I would call it as opposed to kind of reacting and trying to maybe protect downside. So I think when you look at especially what we’ve done here in the last quarter for example with some of our gas hedges trying to keep some upside in our collar positions. I think that’s an indicator to John’s point of the bullishness that we feel as you move forward on the gas side. I think when you look at us in liquids, I think again that’s an area we’ve grown in, but it’s still a smaller part of our revenue stream.

And so I don’t think it really changes our strategy around liquids hedging. I think we’ll protect some downside there where we see opportunities. But again, we’re still an 89% gas company. I think John, he mentioned in his comments, we’re still focused on gas at this point as we move into later in 2025 and 2026. So no real change in the overall strategy there. I think we do feel like the macro, as John pointed out, sets up well next year and we’re adapting the hedging approach to fit that strategy.

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

Jacob Roberts: I wanted to circle back to the cage pad there. I was wondering if you guys foresee this is the only activity you guys have planned there for the year, I believe. So I’m just wondering when you do get back to this area, how you’re thinking about any potential well design changes from here given the step up from the lake pad? And then I was wondering if you guys had foreseen these types of results and if you didn’t or would you have sent more activity here potentially or we should be looking for more activity in a better oil price environment?

Matthew Rucker: Yes. Jacob, this is Matt. On the first one there, as far as well design changes, I think we’re always consistently pad to pad in each of our type curve areas looking at tweaks we can make to improve not only well performance, which is the economics, right, from a cost effectiveness standpoint. So I think there are certainly things to take away from here. I would say very pleased with the subsurface results in the initial 30 days. There’s still a lot of time left to go. We’ve given ourselves some time here with the development schedule you mentioned. So we’ll continue to assess kind of the overall recoveries of that pad and the well spacing in the frac designs. And then moving forward, I think what we’ve seen is continuous improvement on the cost side that we can lean into a little bit more, which bolsters the economics.

So both of those things, think we’ll take those learnings from when we’re ready to develop the next one. And I’ll pass it on to John for kind of part two of that question.

John Reinhart: Yes. I appreciate the question, Jake. I think even though we’re not guiding to ’26, we’ve talked a little bit about some of the shifts towards the wet and dry gas in late 2025 drilling that will lead to some production impact in 2026. To your point, I think we are going to be continuously focused on that wet and dry gas. But what I will tell you is the Marcellus and the condensate especially at these rates productivity and as capital goes down, it’s still an attractive option. So I wouldn’t rule out necessarily. We’re going to have a diverse mix next year but what I will tell you is just more specifically, we feel very comfortable leaning in considering the macro with dry gas and wet gas development with other areas of hydrocarbon maturities put into the program. But certainly probably not something we’re leaning into next year with regards to liquids.

Operator: Thank you. And 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.

John Reinhart: 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.

Operator: 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.