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Greetings. Welcome to Gulfport Energy Corporation's First Quarter 2024 Earnings Call. [Operator Instructions] Please note this conference is being recorded. At this time, I'll now turn the conference over to Jessica Antle, Vice President, Investor Relations. So Antle, you may now begin your presentation.

Thank you, and good morning. Welcome to Gulfport Energy Corporation's First Quarter 2024 Earnings Conference Call. I'm Jessica Antle. Speakers on today's call include John Reinhart, President and CEO; Michael Hodges, Executive Vice President and CFO. In addition, we also have Matt Rucker available for the Q&A portion of today's call, Senior Vice President of Operations. 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 conditions, results of operations, plans, objectives, future performance and business. We caution you that 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 in conjunction with the earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to John Reinhart, President and CEO.

Thank you, Jessica, and thank you to everyone for listening to our call. Gulfport started the year strong, highlighted by continued improvement in operational efficiencies that led to capital spending below analyst expectations and strong free cash flow generation, which allowed us to continue returning capital to shareholders through our common share repurchase program. The significant operational momentum achieved last year continues with another quarter of field operating teams executing at high levels of efficiencies. Several new company records were accomplished this quarter that contributed to strong financial results across the board relative to consensus expectations. Looking at our first quarter highlights, the company generated $186 million adjusted EBITDA and $39 million of adjusted free cash flow. Our average daily production totaled nearly 1.054 million cubic feet equivalent per day, in line with analyst expectations. Operationally, during the first quarter, the company completed drilling on 8 gross wells, 7 within Ohio targeting the Utica formation and 1 in the SCOOP targeting the Woodford formation. We entered the year with 3 operated drilling rigs running and as planned, released 1 Utica rig during the first quarter and currently have 1 rig running in each of our asset areas. On the completions front, we turned to sales 5 gross wells during the quarter, all targeting the Utica and are actively running 1 frac crew in the Utica. As previously mentioned, the operating teams achieved several milestones this quarter, which I'd like to highlight. On the drilling side, we experienced a 9% quarter-over-quarter improvement in footage drilled per day in the Utica, which included a company record of the fastest Utica top hole drilled for Gulfport in the play, totaling just over 6 drilling days. On the completion side, our daily frac pumping hours improved to an average of 21 frac pumping hours per day for the quarter in the Utica, up 23% over full year 2023 and a new Gulfport record. The company's Utica frac provider set a company record with our activity for all of its U.S. pressure pumping fleets, pumping over 675 hours in a 30-day period. Lastly, during the first quarter, the average frac loads drilled per day in the Utica improved by almost 38% over full year 2023, resulting in a quarterly average of 36.7 drilled out per day. I've mentioned this before that these efficiencies corresponding cycle time reductions play an integral role in our corporate level returns, significantly improving turn-in-line timing, reducing costs and ultimately accelerating cash flows and overall enteral performance of the company. I'm very proud of the team's accomplishments over the past year, and we continue to raise the bar every quarter. Specific to our Marcellus development, we included longer-dated production results in our corporate deck on the company's first 2 operated Marcellus wells on our stacked pay acreage in Belmont County, Ohio, and we continue to be very encouraged as we gain more production history. When normalized to a 15,000-foot lateral, the wells delivered an average 120-day initial production rate of approximately 795 barrels per day of oil and 5.5 million cubic feet per day of natural gas. As a reminder, these wells are located on an existing Utica pad, allowing significant midstream flexibility, given our ability to blend the rich gas from the Marcellus wells with existing Utica dry gas production on our initial pad. These wells continue to exhibit strong oil production and under pressure managed flow remain at around 5 psi of pressure drop per day following 120 days of production. We believe this development, along with existing industry offset development in Ohio and West Virginia has significantly derisked our roughly 50 to 60 gross Marcellus locations across our Ohio acreage. As noted previously, the returns on our stacked pay and Marcellus inventory are attractive and compete for capital within our portfolio. Further to that point, the company is currently planning a 4-well Marcellus development on an existing Utica pad beginning in early 2025. In terms of current activity, we remain committed to developing our assets in an efficient and responsible manner. And given the current low natural gas price environment, we have elected to defer certain drilling and completion activities to the second half of 2024. We plan to release the active SCOOP rig in the second quarter after the current 3-well extended lateral pad and plan to resume SCOOP drilling on this deferred pad in the fourth quarter. The shift of the 2-well SCOOP pad to the fourth quarter, which are wells that were planned to be drilled but not completed in 2024, provides optionality of full year capital spend pending assessment of commodity prices. On the completion side, the 3-well Angelo South pad was scheduled to be fracked in the second quarter and due to utilization of a spot crew, the teams were able to shift this planned activity 1.5 months into the third quarter. This shift in activity allows us to realize a value uplift by producing the deferred production and to improving commodity prices. The company continuously assesses the timing and level of development activity to maximize value, and this shift in activity displays the flexibility that we possess in our development plan. These changes in activity will result in a negligible impact on our full year 2024 production, and we reaffirm our full year production to be in the range of 1.045 to 1.080 billion cubic feet equivalent per day. We now forecast approximately 65% of our drilling and completion capital will be allocated in the first half of 2024, and trend lower in both the third and fourth quarters of this year and reaffirm our full year drilling and completion capital guidance range of $330 million to $360 million. Turning to land capital expenditures. Through March 31, 2024, we have invested roughly $18 million on maintenance, leasehold and land investment, focused on bolstering our near-term drilling programs with increases of working interest and lateral footage and units we plan to drill in the near-term. We did not have any discretionary acreage acquisition spend during the first quarter. However, we continue to monitor opportunities to meaningfully increase our leasehold footprint to enhance resource depth and believe these opportunities rank very high as we continuously evaluate uses of free cash flow in 2024. In closing, our solid financial foundation, improved capital efficiency, advantaged expense structure and robust well performance provides us with significant flexibility as we continue our 2024 development program in a volatile market. We believe our operational efficiency improvements and focus on more liquids-rich development this year will further improve margins and ultimately support our robust expected adjusted free cash flow generation. We plan to return to capital to our shareholders and excluding acquisitions, expect to allocate substantially all of our full year 2024 adjusted free cash flow towards common share repurchases. Now I'll turn the call over to Michael to discuss our financial results.

Thank you, John, and good morning, everyone. Despite the low commodity prices seen early in the year, the company generated healthy free cash flow, reduced total debt and returned value to our shareholders, all driven by the significant operational momentum we carried into 2024. Net cash provided by operating activities before changes in working capital totaled approximately $171 million during the first quarter, more than funding our capital expenditures despite the capital program that is roughly 65% weighted to the first half of 2024. We beat analyst expectations for adjusted EBITDA and adjusted free cash flow, driven by our strong price realizations, top-tier hedge book and operating cost performance. Given the contango that currently exists in the natural gas futures curve, we anticipate rising quarterly free cash flow results through the second half of 2024 as capital spending declined significantly and prices are expected to improve in late 2024 and into 2025. Production costs for the first quarter totaled $1.16 per million cubic feet equivalent, in line with analyst consensus expectations and 6% below the first quarter of 2023. The improvement is primarily a result of lower per unit LOE and midstream expenses driven by the company's continued focus on optimizing and reducing costs in the field. For full year 2024, we reaffirm our per unit operating cost guidance, which includes LOE, midstream and taxes other than income of $1.15 to $1.23 per Mcfe, and due to the focus on more liquids-rich development activity in 2024, anticipate per unit cost to trend slightly higher during the second half of 2024. Our all-in realized pricing for the first quarter was $3.16 per Mcfe, including the impact of cash-settled derivatives. This realized unit price is $0.92 above NYMEX Henry Hub index price, highlighting the benefit of Gulfport's differentiated hedge position, diverse marketing portfolio for natural gas and the pricing uplift from our liquids portfolio in both of our asset areas. We realized a cash hedging gain of approximately $65 million for the quarter, demonstrating the value of our hedge book and its impact to our cash flows. Our natural gas price differential before hedges was negative $0.11 per Mcf compared to the average daily NYMEX settle price during the quarter, better than analyst consensus expectations and below the low end of our full year guidance range. Driven by seasonality and strip pricing increasing as we progress through the year, we reaffirm our expectations for natural gas price differentials before hedges to average $0.20 to $0.35 per Mcf below NYMEX for the full year. On the capital front, incurred capital expenditures totaled $106.4 million related to drilling and completion activity and $18 million related to maintenance, leasehold and land investment. As demonstrated by our shift in certain capital spend from the second quarter of 2024 to later in the year, we maintained significant flexibility in our capital program to toggle activity levels as industry conditions change. With respect to our current hedge position, we are pleased to have downside protection covering approximately 60% of our remaining 2024 natural gas production at an average floor price of $3.67 per Mcf. We believe both the scale and quality of our near-term natural gas hedge book differentiates Gulfport in its ability to play offense in delivering value to shareholders during 2024 while others played defense fortifying their pressured balance sheets or protecting their base dividends. We've added slightly to our hedge position for 2025 since our last update and currently have natural gas swap and collar contracts totaling approximately 380 million cubic feet per day at an average floor price of $3.68 per Mcf. We believe brighter days are ahead for natural gas as we move further into 2025 and 2026, and our low fixed cost structure allows us to flex our hedge position based upon where commodity prices are expected to trend. As such, we currently maintain significant upside to natural gas prices in 2025 and 2026 and have utilized collar structures for nearly half of our 2025 downside hedges that allow us to participate in prices well above $4 per Mcf. On the basis front, we have locked in over 40% of our remaining 2024 natural gas basis exposure and have a nice base of our anticipated 2025 exposure locked in at similar levels, providing pricing security at our largest sales points in addition to the risk mitigation, our diverse portfolio of FT offers. Due to our premium hedge position, we are confident that the company will generate substantial adjusted free cash flow in 2024 while others are far more uncertain. And as I mentioned in our call in February, before acquisitions or share repurchases, we project that Gulfport will generate positive adjusted free cash flow at Henry Hub prices well below $1 per MMBtu for natural gas in 2024. This is a testament to not only our advantage derivative position, but also the improvement in capital efficiencies and the focus on lowering operating costs that is more than offsetting the weakness in the natural gas markets today. Turning to our balance sheet. Our financial position remains very strong with a trailing 12-month net leverage exiting the quarter of 0.9x and our liquidity totaling $757 million, comprised of $8.2 million of cash and $749.2 million of borrowing base availability as of March 31, 2024. We utilized cash flow during the first quarter to reduce our absolute debt by $31 million and had $87 million of outstanding borrowings under our revolving credit facility as of March 31, 2024. We currently -- 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 $900 million. 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 as we are positioned to be opportunistic should low prices give rise to dislocations that allow us to capture value for our stakeholders. We continue to view share repurchases as a compelling capital allocation opportunity. And during the first quarter, we repurchased 210,000 shares of our common stock for approximately $29.5 million, which includes a direct repurchase of common stock from one of our largest shareholders, totaling approximately 97,000 shares which allowed us to capture a large block of unrecognized equity value at a slight discount to the market price and without negatively impacting our public float. As of April 25, we had repurchased approximately 4.6 million shares of common stock at an average share price of $93.77, lowering our share count by approximately 16% at a weighted average price more than 70% below our current share price. We currently have approximately $221 million of availability under the $650 million share repurchase program and plan to continue to return substantially all of our adjusted free cash flow to shareholders through our common share repurchases, excluding acquisitions for the foreseeable future. In summary, our first quarter results highlight the strength of our business as we continue to deliver significant value to our shareholders in a volatile commodity environment. This year's program is off to a solid start, and our continued operational improvements, robust hedge position, healthy balance sheet and strong cash margins provides significant flexibility as we navigate 2024. With that, I will turn the call back over to the operator to open up the call for questions.

[Operator Instructions] Our first question is from the line of Bert Donnes with Truist.

I just wanted to start off on the decision to defer some of that activity. Maybe you could go into what changed between now and last quarter. Is it something you're seeing on supply and demand? Was it basis? Was it strip pricing? Or was it just that spot rig you were talking about maybe it just was an easy shift in your program.

Yes. Bert, thanks for joining the call. I appreciate the question. Yes, I think as we noted before on our development plan, we really do appreciate having the flexibility to be able to toggle around activity to maximize value. In this particular case, just the commodity environment over the first quarter and the outlook towards the second half of the year, it really kind of weighed into our decision to assess options to be able to provide some value uplift. And given the completions crew was a spot crew, it was a pretty easy decision to defer that about 1.5 months and realize the uplift. And on the drilling side, that was actually planned to be a carry [ DUC ] this year, as I commented in the script, -- so any time you move, obviously, the drilling closer to production, that's going to give you a value uplift. And we'll just assess pricing in the fourth quarter to see if that's a spend that we want to do in '24 or just shift that to 25. So I think it really boils down to just showing the flexibility of the program, and it was really tied ultimately to this commodity price environment and really just being prudent with our capital plan and making sure that what we're doing maximizes value for the company.

That makes a lot of sense. And then shifting to the Marcellus rate, it seems to be holding up pretty well and especially on the liquids cut. Just wondering if the change in gas prices maybe accelerate activity on that front. In the prepared remarks, you mentioned a pad in early '25. Just is that the only activity currently slated for '25? Or is that a good start? Or maybe are you viewing the results in real time and then going to make a decision?

Yes, Bert, this is Matt. I'll take that one. We're really excited about the results there. Obviously, we continue to talk about that. We assess the long-term productivity still hanging in there looks great. I think '25 was always part of the plan to come back and continued development there. I think a few things around that are just getting units put together. We have pads in place. So that allows us to kind of get after that a little quickly. Not -- I don't think we'll be accelerating any activity in the '24. We have a pretty good set base plan. But as early in the '25 as we can to take advantage of those economics and the return to pad opportunities that we have there is attractive. And then we continue to kind of work midstream solutions there to help maximize our economics. So all of those things come into play. I think, again, we like it. It's part of our development plan and accelerating that very exciting for us.

Our next question is from the line of

John, you mentioned driving some significant accomplishments on efficiency gains on both drilling and completions in the first quarter, and you were below guidance on CapEx for the quarter. Can you talk about how much of these efficiency gains were built into the full year budget? Just trying to understand if there could be some downside to the CapEx budget if you continue to deliver on these gains.

Yes, that's a great question,

And then my follow-up is on the buyback program. Your free cash flow this year will be back-half weighted just given the first -- the heavier first half capital program and the shape of the gas curve. Will the buyback program also follow this trajectory? Maybe just give us a sense of the expected buyback pace going forward?

Yes.

The next question is from the line of Tim Rezvan with KeyBanc Capital Markets.

I wanted to follow up a little bit on the midstream opportunities you have for the Ohio Marcellus. I was wondering if you could give an update on kind of where discussions stand now that you have 4 months of production data from this pad. And maybe how we should think about the pace of development? You talked about 50 to 60 locations. Maybe how many pads you might look to drill in 2025? And just sort of how the midstream and activity will kind of mesh as you go forward?

Yes. Tim, this is Michael. I'll take the first part of that question, and then John or Matt can jump in on kind of development piece. But on the midstream side, certainly, we're involved with a number of counterparties in the area that have available capacity for both gathering and processing in this area. So we feel like we're in an advantaged position there. There's capacity that was left over from times where more gas in the region was flowing. And so we're looking for the best economics, of course, and also need to be able to assess on this first 2-well pads, the volumes and the decline so that we can make the appropriate decisions around how much capacity we need going forward with the midstream counterparty. So we're progressing those discussions. We certainly feel like there's an opportunity there to put Gulfport in a great position going forward. Anytime you've got multiple folks looking for additional gas but nothing to announce at this point and certainly factoring that into our development timing. I'll take it over to John or Matt to talk about where we go from here.

Yes, Tim, again, I appreciate the question. I think as the company sits here and looks at our portfolio, we're very pleased to have a lot of different toggles to push on the liquid side. You've got the Utica condensate that we're focused on this year. You've got the SCOOP condensate and NGLs were focused on. Now you have the Marcellus. So in addition to some really high-quality dry gas acreage. So in the public deck too, we -- if you look at the returns on all those across the fair way, they're within 10% to 15% of each other, depending on the commodity environment. So that's a really good place to have a lot of high-quality acreage that kind of warrants capital. So given that kind of landscape and looking forward, what I would expect is a cadence of about 1 pad to 1.5 pad Marcellus a year. as we develop it. And then certainly, we're going to be mindful of commodity prices change and liquids prices kind of outpace gas and that will move the needle. And consequently, if gas takes a run, you might see us lean down a little bit like a 1 pad year. But having another high-quality liquids-rich play with 2-plus years of inventory within the portfolio to toggle activity on, it's a really good thing. So we're pretty pleased with where we sit. So that's kind of the cadence and the pace and that's how we would look at it, Tim.

Okay. That's helpful. I appreciate the color. And then as my follow-up, when you talked about the activity deferrals you're doing this year, one on the drilling, one on the completion side, I noticed they're both in the SCOOP. Is that just coincidental based on your ability to sort of toggle the schedule or how do we think about the deferrals there? Is that sort of intentional returns base versus the Utica? Or again, just coincidental?

Yes. No, I appreciate the question. Actually, it's really more of a logistical and an economic function. I mean if you look at it, whenever we looked at capital spend this year and we looked at any kind of DUCs that we plan that we're carrying, that's going to rank up there on something to assess given the commodity environment that we're in, in the first half of the year. So really, the uncompleted lack of production for '24 on the DUCs really played into the drilling deferment. And quite frankly, just the spot crew and the availability to shift schedules around versus the continuous crude that we have running in the Utica really played into our economic decisions to be able to shift that 1.5 months and realize some value there. So it's really about logistics and quite frankly, just economics and value uplift.

[Operator Instructions] The next question is from the line of Jacob Roberts with Tudor Pickering Holt.

Circling back to the Marcellus, and we understand it's early days and you had mentioned some learnings from offset operators. We were wondering if there is any need or desire to organically delineate the asset? And if so, any potential upside you see to that location count?

Yes. No, I appreciate the question. I think part of our initial -- you can call it somewhat of a delineation is when we drilled this first 2-well Hendershot pad, we drilled to the Northwest and into the Southeast. And I wouldn't qualify it as a delineation for, is it going to be economic or how prolific is it for us, we knew just right across the river, there were really good Marcellus wells, the developments there. We're really proximate to our locations in our acreage footprint right across the river. So for us, it was more about identifying kind of liquids yields, NGL yields, what's condensate look like. And all that information is really there to help us kind of start looking at the midstream solutions and looking at the productivity. So as we look forward, there are certainly going to be further testing, optimizing spacing, stimulation aggressiveness. So there's going to be certainly some play within how we complete and drill and space those wells in development. But by and large, there's a lot of wells right across the river. So there's a lot of data that we already kind of know and the initial development layout will be more tweaking versus what I would consider more delineation. So we feel really good about the data we have. The well results are great as expected. And we're certainly going to be keyed in though on future development to maximize wherever we can on any of those parameters, the value for the company.

As a second question on the activity deferrals. Is there any impact to what we should be thinking about in terms of liquids percentage mix, whether on a quarterly basis or an annual basis? And maybe reading too much into this, is there any inference that can be drawn in terms of regionally the product mix you're expecting out of those wells?

Yes. Jake, this is Michael. I think to John's comments earlier, the deferral on the completion side was really only about 45 days. So in terms of the impact to the production, as we noted in the script, it was negligible and any impact to the liquids versus gas mix would be negligible as well. As we exit this year, we're going to start to trend a little bit more liquids rich. But again, as we've said in the past, we're still going to be largely a gas company. And as we move into 2025, I think you'll see more of that liquids component show up in our production mix. So I would guide you all towards a similar liquids mix throughout 2024, maybe some changes late in the year. And in terms of any changes to the kind of the overall NGL barrel or just overall liquids mix, I would tell you again that it's not going to be meaningful.

Thank you. At this time, we've reached the end of our question-and-answer session. I'll turn the call back to John Reinhart for closing remarks.

Thank you to everyone for taking the time today to join our call. The team continues to improve business fundamentals, which further provides and positions Gulfport Energy as an attractive investment with optionality tactically and strategically for continuing value enhancement. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. Have a great day.