Good day, everyone, and welcome to the Gulfport Energy Corporation Fourth Quarter 2023 Earnings Call. All participants are currently in listen-only mode, and we will open the floor for questions and comments after the presentation. It is now my pleasure to introduce your host, Jessica Antle. Welcome, Jessica. The floor is yours.

Thank you, Karen and good morning. Welcome to Gulfport Energy Corporation's fourth quarter and full year 2023 earnings conference call. I am Jessica Antle, Vice President of Investor Relations. Speakers on today's call include John Reinhart, President and CEO; and Michael Hodges, Executive Vice President and CFO. In addition, Matt Rucker, Senior Vice President of Operations 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 our website in conjunction with the earnings announcement; please review at your leisure. At this time, I would like to turn the call over to John Reinhart, President and CEO.

Thank you, Jessica, and thank you to everyone for joining our call. Reflecting on the message from our conference call in February of last year, I mentioned that in 2023 we would focus on actions to ensure the efficient and sustainable development of our quality inventory, improve margins, optimize efficiencies in our capital programs, maintain a strong balance sheet, and use our free cash flow for value enhancement. We successfully delivered on those commitments and I would like to highlight several accomplishments achieved throughout 2023. Our net production exceeded the upper limit of our initial guidance range while remaining below the midpoint of our initial capital budgets from February. This was accomplished despite additional activities in the fourth quarter that were not part of our original guidance. We invested $48 million of our adjusted free cash flow to acquire strategic Utica liquids-rich acreage, extending our inventory by one and a half years. Additionally, we delineated two years of liquids-rich locations in the Marcellus area, situated above our existing Utica acreage, without incurring extra acquisition costs. Our development program in 2023 generated significant free cash flow, totaling roughly $199 million for the year. After accounting for cash flow used for discretionary acreage acquisitions, we allocated around 99% of our adjusted free cash flow to repurchase our common stock while maintaining a robust balance sheet, significant liquidity, and financial leverage below one time. Production for the year averaged 1,054 million cubic feet equivalent per day, about 3% above the high-end of our initial guidance range from early 2023. This outperformance was due to improved cycle times and quicker well completions, along with strong performance from our development program. We are excited about our shift to a pressure-managed flowback program which promotes longer production plateau periods, slower declines, and cost efficiencies through reduced facility expenses. Based on flowing pressures as a key indicator, we expect this program to enhance Estimated Ultimate Recoveries and development economics, while also lowering our corporate base decline and future capital intensity. Throughout the year, we drilled and completed 24 gross wells, consisting of 2 in Marcellus, 2 in SCOOP, and 20 wells in the Utica. We made meaningful improvements in cycle times, achieving over a 60% year-over-year increase in total footage drilled per day compared to the end of 2022. The fourth quarter saw the highest average total footage drilled per day of the year, providing strong momentum as we began drilling on a three-well pad in SCOOP. We look forward to applying the lessons learned in Utica and the efficiencies gained in 2023 to our 2024 SCOOP Development Program. On the completion side, we made notable efficiency gains in the fracking and drilling-out phases, enhancing average fracking hours per day by 30% in 2023, and increasing the average plugs drilled per day by nearly 50%. We finished the year with a quarterly average of 20.8 fracking hours per day, the highest quarterly average for the year. Our operating team’s emphasis on efficiency and cost reduction led to over $35 million in savings during 2023. As announced previously, we decided to reinvest those savings into developing our high-quality assets with additional drilling and completion operations in the fourth quarter. Despite accelerating activity, we stayed within our expectations for full-year 2023 capital expenditures, which totaled around $443 million, excluding discretionary acreage acquisitions. In terms of Marcellus development, we successfully drilled and completed our first two operated Marcellus wells on our stacked pay acreage in Belmont County. When normalized to a 15,000-foot lateral, these wells achieved an average 60-day initial production rate of approximately 860 barrels of oil per day and 5.2 million cubic feet of natural gas per day. Importantly, these wells were drilled on an existing Utica pad, offering significant midstream flexibility by blending the rich gas from the Marcellus with the existing Utica dry gas production. We are very optimistic as we gather more production data and operate the wells under pressure-managed flow, currently facing less than a 6 PSI pressure drop per day after over 60 days of production. We believe that with ongoing development in the industry around us, we have significantly mitigated the risks associated with our Marcellus position and estimate we've delineated about 50 to 60 gross wells. With a planned development pace of roughly 25 wells per year, this represents about two years’ worth of liquids-rich inventory. Looking ahead, given the strong results and attractive return rates competing for our capital, we are planning to start additional Marcellus development in early 2025. On the front of discretionary acreage acquisitions, we expanded our acreage position by investing $48 million in 2023 in targeted Utica liquids-rich land within our Belmont County development area. With our current drilling pace, we added approximately 1.5 years of core liquids-rich locations at an average cost of around $1.7 million per net location. Together with the reduced risk of our Marcellus acreage, this additional inventory enhances the company's fundamental value and expands our development options going forward. We are prioritizing the development of the recently acquired Utica acreage and aim to begin pad construction in late 2024, with drilling starting in early 2025. Our discretionary acreage acquisition in 2023 allowed us to organically extend our high-quality inventory base at attractive returns. We will continue to explore opportunities to meaningfully increase our leasehold footprint to improve resource depth and believe these opportunities rank highly as we continuously assess and evaluate the use of free cash flow in 2024. As we transition into 2024, the current volatility in the natural gas market underscores the necessity of developing our assets efficiently and sustainably. Building on our momentum from 2023, we plan to keep optimizing our margins, development program cycle times, and operating costs. We project relatively flat production year-over-year while utilizing 10% less capital. Total capital spending for the year is expected to be between $380 million and $420 million, with renewed emphasis on liquids-rich development in both the Utica and SCOOP compared to previous programs. This total capital spending includes $50 million to $60 million towards maintenance land and leasehold investments to bolster our near-term drilling program with increased working interest and lateral footage in areas we plan to drill soon. The anticipated operated working interest for our 2024 Utica program is expected to be 97%, marking a 5% increase over the 2023 program, while the average lateral length of planned activities is projected to increase by nearly 30% from 2023, enhancing our high-return operated development program. In summary, our operational efficiencies and reinvestment in our asset base through land maintenance programs enable us to deliver a 2024 program aligned with 2023 production results despite lower well activity and capital investment. It’s also important to note that our 2024 plan includes approximately $30 million to $35 million for building strategic ducts beyond our normal operating schedule, further showcasing our significant year-over-year efficiencies and ability to achieve similar production levels in 2024 with considerably lower capital. We currently estimate that about 70% of our drilling and completion capital will be spent in the first half of 2024, with spending decreasing in the third and fourth quarters of the year. Regarding production, we expect this spending level to yield 1.045 billion to 1.08 billion cubic feet equivalent per day in 2024, which would be stable in comparison to our average for all of 2023. We are flexible in response to the commodity environment and have the capability to moderately delay or expedite completions as commodity prices and return rates allow. Our investment deck includes a detailed outlook on our expected 2024 capital and production schedule. We project that 92% of our 2024 production will come from natural gas, peaking in the first half of 2024 due to natural gas-directed activity from late last year, and gradually shifting towards a higher share of liquids in the latter half of 2024 and into 2025 as we bring online our more liquids-rich developments. In conclusion, despite facing a challenging commodity environment, we anticipate Gulfport will continue to generate substantial adjusted free cash flow in 2024, and we currently expect a top decile free cash flow yield compared to our natural gas peers. Our focus will remain on returning capital to our shareholders and, excluding acquisitions, we aim to allocate nearly all of our adjusted free cash flow for the full year of 2024 towards common stock repurchases. Now, I will turn the call over to Michael to discuss our financial results.

Thank you, John and good morning everyone. Since John hit on a number of the results for the full year of 2023, I'll start by summarizing our fourth quarter results which further emphasize our operational momentum as we closed out the year and have positioned us to hit the ground running in 2024. Net cash provided by operating activities before changes in working capital totaled approximately $184 million during the fourth quarter, more than doubling our capital expenditures and allowing us to make significant common share repurchases, all while maintaining our balance sheet strength. We reported adjusted EBITDA of $191 million during the quarter and generated adjusted free cash flow of $85 million for the same period driven by our strong hedge position, consistent production base, and low operating cost structure. In other words, we delivered our best quarter of 2023 from an adjusted free cash flow perspective, and leveraged that outcome by adding incremental high-quality locations to our portfolio, while buying back nearly 3% of our market capitalization through our share repurchase program. It was a tremendous finish to what was an outstanding year for Gulfport. Production cost for the fourth quarter totaled $1.16 per million cubic feet equivalent, better than analyst consensus expectations. The company continued to focus on optimizing and reducing costs in the field, combined with our strong production performance during 2023, drove our per unit expenses to the low-end of our guidance on an annual basis highlighting again our 2023 operational performance. As John mentioned, despite our focus on a more liquids-rich activity program in 2024, we currently forecast our per unit operating costs including Lease Operating Expenses (LOE), taxes other than income, and midstream expenses to be in line with 2023 and total in the range of $1.15 to $1.23 per Mcfe. Our all-in realized price during the fourth quarter was $3.20 per Mcfe, including the impact of cash settled derivative. This realized unit price is $0.33 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. We realized a cash hedging gain of approximately $50 million during the quarter, demonstrating the strength of our hedge book and its impact on our cash flows. Our natural gas price differential before hedges was negative $0.51 per Mcf compared to the average monthly NYMEX settled price during the quarter, slightly tighter than the third quarter of 2023. However, basis prices have continued to be under pressure during the quarter driven by elevated storage levels and rising production, especially in the Northeast. As we expected and had previously communicated, we ended the year near the wide end of our 2023 guidance of $0.20 to $0.35 cents per Mcf below the NYMEX price, and currently forecast a similar natural gas differential for the full year of 2024. On the capital front, incurred capital expenditures during the fourth quarter before discretionary acreage acquisitions totaled $69.4 million related to drilling and completion activity, and $13.4 million related to maintenance, leasehold, and land investment. As a reminder, this includes accelerated activity predominantly focused in the liquids areas of the Utica and the SCOOP. Even with this incremental activity, as John previously mentioned, we ended the year below the midpoint of our initial capital budget range provided in February, as well as below the midpoint of the updated capital guidance range provided in October, further highlighting the strong operational performance by the team over the course of 2023. The financial results our team has delivered for 2023 have been exceptional, and we're poised to capitalize on these improvements as we deliver more with less in 2024 and beyond. I want to focus some of my comments this morning on our hedge book which I believe differentiates Gulfport and its ability to play offense in delivering value to shareholders during 2024, while others play defense fortifying their balance sheets or protecting their dividends. With respect to the current hedge position, we are pleased to have downside protection covering 590 million cubic feet per day in 2024 or over 60% of our gas production at an average floor price of $3.69 per Mcf. We have been opportunistically layering in hedges for 2025 and currently have natural gas swap and collar contracts totaling approximately 310 million cubic feet per day at an average floor price of $3.80 per Mcf. On the basis front, we have locked in over 40% of our 2024 natural gas basis exposure and have a nice base of our anticipated 2025 basis exposure locked in as well, providing pricing security at our largest sales points in addition to the risk mitigation our diverse portfolio of firm transportation offers. We believe both the scale and the quality of our natural gas hedge book provide the de-risked foundation for free cash flow expansion that differentiates Gulfport from its peers. Due to our premium hedged position, we are confident that the company will generate adjusted free cash flow in 2024 while others are far more uncertain. In fact, before acquisitions or share repurchases, we project that Gulfport will generate adjusted free cash flow at Henry Hub prices down to approximately $1 per MMBtu for natural gas. This is a testament to not only our advantageous derivative position, but also to the improvement in capital efficiencies and focus on lowering operating costs that is more than offsetting the weakness in the natural gas market today. While we continue to believe there are better days ahead for natural gas, we remain committed to a disciplined approach for hedging our cash flows, and we believe Gulfport delivers a differentiated combination of free cash flow generation capacity and downside protection over the next couple of years. Turning to the balance sheet; our financial position remains top tier with a 12-month net leverage exiting the quarter at 0.9 times, and our liquidity totaling $720.1 million, comprised of $1.9 million of cash plus $718.2 million of borrowing-based availability. 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 gas prices give rise to dislocations that allow us to capture value for our stakeholders. During the fourth quarter we purchased 490,000 shares of common stock for approximately $66 million, which included direct repurchases of common stock from two of our largest shareholders totaling approximately 292,000 shares that allowed us to capture larger blocks of unrecognized equity value with limited impact on our public float. Since initiating the repurchase program in March 2022, and as of February 26, we have repurchased approximately 4.5 million shares of common stock at an average share price of $92.41, reducing our common shares outstanding by 15% at a weighted average price more than 35% below our current share price. We currently have approximately $236 million of availability under the $650 million share repurchase program and plan to continue to use substantially all of our adjusted free cash flow to return to shareholders through common share repurchases, excluding acquisitions for the foreseeable future. In summary, our operational efficiency improvements, robust hedging position, healthy balance sheet, and strong cash margins provide significant flexibility as we navigate 2024. The Gulfport team delivered on all fronts during 2023 and is poised to demonstrate the fundamental value of our asset base as our company propels us into 2024. As we lay out a plan today to deliver more with less, we firmly believe our best days are still ahead of us. And perhaps most importantly, we continue to generate premium free cash flow yields relative to our peers, and utilize that free cash flow to deliver value to our investors as we have the 5-year free cash flow capacity capable of retiring our current market capitalization at future gas prices below $4. With that said, I'll turn the call back over to the operator to open up the call for questions.

Thank you. And we'll take our first question from Bert Donnes from Truist Securities. Please go ahead, Bert.

Good morning, everyone. I'd like to begin with a question about the new guidance. The 10% reduction in capital requirements is certainly noteworthy. Could you break down some of the factors contributing to those savings? Additionally, you mentioned the $30 million to $35 million; could you clarify how that program impacts your duck count or the count of wells in progress, and how you plan to use that information?

Matt will discuss the capital efficiency aspect. As John mentioned earlier, we've observed significant improvements in drilling, with a year-over-year increase of about 50% on the frac side, thanks to our teams doing an exceptional job in the field. We're averaging over 20 pumping hours a day, which allows us to anticipate a 50% savings on a year-over-year basis. When considering our reduced dollar-per-foot well costs from 2023, approximately 65% of those savings stem from efficiencies that will have a lasting impact. Additionally, we've made significant improvements in supply chain management, adapting to the softening market and restructuring existing contracts since the beginning of the year, which accounts for around 35% of the savings. Overall, while these factors may vary with commodity pricing, our focus remains on these lasting efficiencies.

Bertrand, I'll address the question about the inventory. I appreciate you bringing that up. The six ducks we are carrying represent the non-routine inventory we maintain, which holds significant strategic value. This provides us with the flexibility to accelerate completion if commodity prices justify it. The $30 million to $35 million expenditure this year is important because, looking forward, we are not only achieving a 10% year-on-year reduction in our maintenance program but also highlighting the efficiency gains and cost reductions our team has accomplished over the past year. I’m very pleased with our execution, performance, and efficiencies, and I hope this clarifies our inventory counts and any related capital questions.

That certainly does. My second question is about the new Marcellus oil rates, which seem to change the IRR ranking according to your slides. I understand there are specific commodity assumptions involved, but you've mentioned 50 to 60 locations. In the prepared remarks, you suggested that you might start exploring this in 2025. I'm curious if this could become a larger part of the program. How would that work? Would it divert capital from other areas, or would it be additional activity if pricing allows?

That's a great question. We're very excited about the Marcellus, and we have spent a significant amount of time discussing it in our materials. It represents a major value component for the company, especially regarding our inventory and delineation efforts, with no land costs involved. In terms of returns, we're pleased with our investment in the Utica condensate window, our efforts in the Marcellus condensate window, the SCOOP liquids-rich development, and the high-quality Utica dry gas. All of these compete for capital, placing us in a favorable position as it provides us with more options. By the end of 2024 and into 2025, you can expect to see a more balanced participation in liquids within our portfolio. We are certainly considering accelerating our Utica acquisitions by 2025, along with increased activity in the Marcellus. Moving forward, you will notice a more balanced mix of SCOOP liquids-rich development compared to what we have seen historically, primarily due to economics. It's an excellent situation for us, and it's reassuring to invest in areas where we can see quick returns within 12 to 18 months. Overall, I am very pleased with the program as we advance.

And next, we'll go to Tim Rezvan from KeyBanc Capital. Please go ahead, Tim.

Good morning, everyone. When we spoke recently, you indicated that you would weigh repurchases against your ability to procure more inventory. I'm curious about your current perspective on the $40 million to $50 million range you had in mind last year. How is the situation looking today? Are you confident you can acquire more? Also, as you assess the market, are you neutral regarding oil versus gas, or are you currently focusing on one specific area? Thank you.

Tim, this is Michael. Great question. As we look ahead to 2024, our strategy will largely remain the same. Last year, we mentioned that we plan to return most of our free cash flow to shareholders after making necessary acreage acquisitions. We're taking a similar approach this year; we'll be opportunistic. There are still appealing opportunities available, though competition has increased in the basin. In terms of generating the highest returns with our free cash flow, we consistently identify two primary areas of focus: our shares and acquiring future locations. We're not providing specific guidance for this year, but it's a priority for us. We believe that adding these locations provides significant value to the company. Once we have clarity, we'll certainly inform the market. However, it's not a routine process, so we aren't giving that guidance today, but we're very attentive to it. We remain optimistic about achieving similar success. If that doesn’t pan out, we believe reinvesting in our equity is a solid option, so we'll continue in that direction as well.

I was trying to get a specific number from you, but I understand you’re not ready to provide one at the moment. I appreciate the details, Michael. As a follow-up, I wanted to revisit the topic from the previous question regarding the strategic decisions you mentioned. With gas prices currently below $2, what would prevent you from reducing production like your neighbor in OKC? Given the current bleak outlook in the near term, what would motivate you to strategically defer production volumes?

That's a good question. When we evaluate the company, considering our scale and the quality of our assets, we analyze the Present Value (PV) and the returns from our total development program. We aimed to establish a maintenance level program that allows us the flexibility to adjust production levels as needed. Regarding the potential for production decline, we assess it from an economic standpoint. For example, if pricing drops significantly but shows potential for recovery in the following quarters, that’s something we would take into account in terms of the value the company can gain from developing those assets. Our decisions will be based on real-time evaluations and will depend on where we are in the commodity cycle when considering deferrals or acceleration. It’s beneficial to have that flexibility. While it’s not ideal to be in a situation where we need to contemplate such adjustments, we are fortunate not to face constraints like mandatory drilling to hold acreage. Our production delivery will be driven by PV, economic factors, and returns, while also ensuring steady year-to-year production without significant declines. This approach is essentially a real-time economic assessment throughout the year. If we see opportunities for a quarter deferment that could enhance PV for our assets, that is definitely something we will explore.

Thanks, John. I appreciate all the color.

Thank you. And we'll take our next question from Jacob Roberts from TPH. Please go ahead, Jacob.

Good morning. Looking at Slide 23 and 24, is there anything you could point to in terms of maybe well design methodology that is driving the outperformance relative to the peer group?

Yes. I want to highlight that coming in about a year ago, the team has historically done an excellent job of being very aggressive with completion intensities. As we evaluated the development plan, we made some adjustments to the spacing, and the teams worked hard to stimulate those wells. Over the past year, I have been clear that our main focus was to maintain well productivity and not to reduce the estimated ultimate recovery. In fact, we have leveraged aggressive stimulations and adjusted spacing to improve our capital efficiencies, reduce capital costs, and lower expenses. We are very pleased with our solid position in favorable rock formations. By employing an aggressive stimulation program efficiently from a capital standpoint, we are able to achieve positive economic results. The improved well productivity observed in these slides is certainly influenced by the quality of the assets, spacing decisions, and the team's drive for aggressive stimulation. Matt, do you have anything to add?

Yes, no, I think you nailed it, John. It’s certainly a little bit different developments with some of our peers which we think adds tremendous value to the company. And then, we have talked a few times about the pressure-managed flowbacks and kind of lower for longer Initial Production (IP) rates which we believe helps with the pressure maintenance over time and also ultimate recovery. So all those things we feel like put us in a good position in each basin to kind of be peer-leading there.

Thanks, I appreciate that. Staying on the same topic, in your prepared remarks you mentioned applying learning to the SCOOP. I'm curious about the timeline for settling on a development program or methodology that you believe will be effective going forward, especially regarding the application of completion design flowback. I'd like to explore those aspects further.

Yes, this is Matt again. I'll address that and John can add any comments he might have. We are currently in the process of restarting our SCOOP program development. We conducted two wells early last year, but with the new team in place, we paused the program to focus on Marcellus delineation and better understand that asset. During this year’s review, we found many positive insights; the team has been diligently working on how to achieve repeatability in this basin from an execution perspective. At the moment, we are in the middle of developing the first three-well pad, experimenting with new approaches that we adapted from the Utica. Over the next quarter or two, I expect we will begin sharing updates on our progress. Our goal this year is to successfully execute our plan and demonstrate that repeatability, which would help reduce risks associated with future drilling planning in that basin. I hope that clarifies things.

Thanks everybody for participating on our call. Very pleased with the progress from the teams in 2023 into performance, and very happy with rolling out our plan for a great capital efficient 2024 program. Looking forward to our next call to share some results from the first quarter. So, thanks and have a great day.

Thank you. Ladies and gentlemen, this does conclude today's teleconference. We thank you for your participation. You may disconnect your lines at this time, and have a great day.