Gulfport Energy Corporation (NYSE:GPOR) Q3 2024 Earnings Call Transcript

Gulfport Energy Corporation (NYSE:GPOR) Q3 2024 Earnings Call Transcript November 6, 2024

Operator: Greetings, and welcome to the Gulfport Energy Corporation Third Quarter 2024 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. 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 third quarter 2024 earnings conference call. I am Jessica Antle, Vice President of Investor Relations. Speakers on today’s call include John Reinhart, President and Chief Executive Officer; and Michael Hodges, Executive Vice President and Chief Financial Officer. 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 to our 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 to everyone for listening to our call. Gulfport’s third quarter results highlight our continued commitment to enhancing shareholder value. During the quarter, the company repurchased approximately $50 million of our common stock, expanded the company’s common stock repurchase authorization by 54% to $1 billion, lower 2024 capital spend guidance midpoint by $15 million, increased high-margin condensate production by 68% quarter-over-quarter, and added to the company’s high-quality inventory with approximately $20 million of discretionary acreage acquisitions, which when combined with the first half of 2024 activity, as approximately one year of incremental liquids-rich drilling locations, which have competitive returns with our high-quality inventory and are targeted for near-term development.

All of this was accomplished while improving our balance sheet by extending maturities by more than three years, increasing liquidity by approximately $200 million and maintaining a very attractive leverage profile below 1 times. In addition to the strong financial performance, the company also issued our 2024 Corporate Sustainability Report and announced the company recently achieved an A grade under the MIQ methane emission standard for all of our natural gas production in Appalachia for the second consecutive year. As a leading natural gas producer, we are committed to emission intensity reductions throughout our operations, and we are proud of our progress in delivering clean, safe, affordable and reliable energy. Moving to our third quarter results, the company delivered adjusted EBITDA and adjusted free cash flow ahead of analyst expectations, bolstered by the strong margins of our liquids-rich turn-in-lines during the quarter.

Operating efficiency improvements and correspondent cycle-time reductions have led to meaningful savings, and we expect to realize over $25 million in capital savings on our drilling and completion activities during 2024. Based on the current commodity price environment, we have elected to allocate the majority of these savings to incremental shareholder returns with the remainder being deployed in high-return capital projects that will position us well for 2025. As a result, the company is lowering our full year 2024 capital guidance by approximately 4% at the midpoint, now forecasting D&C capital to be in the range of $325 million to $335 million and maintaining our maintenance leasehold guidance range of $50 million to $60 million for the calendar year.

Operationally, in Ohio, during third quarter, the company completed drilling on five gross wells with one horizontal drilling rig. In addition, we concluded our 2024 turn-in-line program in the Utica, bringing online seven gross Utica wells during third quarter and 16 gross Utica wells for the full year. In the SCOOP, during the third quarter, the company completed and turned to sales three gross wells in late September, concluding our 2024 turn-in-line program for the year. The company is currently running one rig in the Utica and one rig in the SCOOP with plans to add an additional rig in the Utica focused on liquids-rich drilling late in the fourth quarter. Turning to land capital expenditures through September 30, 2024, we have invested roughly $52 million on maintenance leasehold and land investment, focusing on enhancing our near-term drilling programs with increases in working interest and lateral footage.

Our focus on maintenance lease sold and land spending over the last two years in combination with our discretionary acreage acquisitions have reinforced our future drilling programs and position the company for a future reduction of our anticipated maintenance land requirements going forward. For 2025 Gulfport forecast maintenance leasehold and land spend will be approximately $45 million for the full year, a decrease of approximately 25% from the high end of our 2024 annual guidance. This lower level of maintenance land spending will further support Gulfport’s robust free cash flow generation going forward. We’re excited to announce the strong well performance results from our four well pad in the condensate window of the Utica. As we noted on our second quarter call, the company turned to sales our Lake VII pad in Harrison County, Ohio, in mid-July.

This development represents Gulfport’s first condensate pad since the second quarter of 2020 and referring to slide 12 of our investor deck, we are pleased to provide an update on the early well performance. All four wells have exhibited attractive condensate and NGL production rates in combination with minimal pressure drawdown during the initial 90-day period. Current flowing parameters indicate similar productive capacity is nearby offsets, and given the well’s strong performance during cleanup phase we are now testing increased production rates to determine the optimal production profile for this pad as well as subsequent pads aimed at optimizing long-term well performance, while maximizing risk-adjusted returns. We’re very encouraged by these early production results and believe the Utica condensate window in combination with the Utica lean condensate and Ohio Marcellus has the potential to provide a meaningful impact to the company’s liquids production in the coming quarters and years.

As previously communicated, the company also completed drilling on four additional Utica condensate wells near our Lake VII pad that are targeting completions and turn a line for the first quarter of 2025 as well as development of a four-well Marcellus pad beginning in the first quarter of 2025. We currently forecast over 60% of our total company turn in lines will be liquids rich weighted during 2025, an increase from approximately 37% in 2024. When considering the operational performance, attractive early production results and expected economics, the prudent shift towards increased liquids-rich development highlights the optionality and flexibility of our asset base, as well as reinforces the company’s continuous optimization of our development program targeting enhanced cash flows and improved returns.

Lastly, in our investor deck on slide 11, we have provided an update a pressure managed production results, which we enacted in early 2023. When compared to Gulfport’s historical Utica dry gas well performance, the recent 2023 development program, which is being produced under our managed pressure approach yields higher cumulative recoveries per 1,000 foot of lateral after an extended production period. As we have noted since the rollout of this program, we firmly believe this approach leads to lower upfront capital requirements, longer production plateau periods, shallower declines, improved reserves, lower lease operating expenses, lower water recoveries, less midstream and offset legacy production impacts from new pads being brought online and overall lower production downtime.

In addition to the well performance results, prudent production from development wells allows the company to provide consistent, repeatable results and ultimately improves overall corporate decline rates and lower future maintenance capital requirements. To summarize, 2024 has been a year where the company delivered results that highlighted our focus on shareholder returns, capital reductions, operational efficiency improvements, inventory additions, balance sheet improvements and a shift towards high-margin liquids development. Each of these efforts deliver fundamental value improvements for the company, and we believe are aligned with enhancing shareholder value. Our focus on these key tenets will remain as the company enters 2025. Now, I will turn the call over to Michael to discuss our financial results.

Michael Hodges: Thank you, John, and good morning, everyone. During the quarter, with continued volatility in the commodity backdrop, the company achieved strong results across all facets of the business. Net cash provided by operating activities before changes in working capital totaled approximately $160 million during the third quarter, more than funding our capital expenditures and common share repurchases, while maintaining our balance sheet strength. We reported adjusted EBITDA of approximately $178 million during the quarter and generated adjusted free cash flow of approximately $73 million for the same period, both better than analyst expectations driven by our strong liquids production, gas realizations and operating cost performance.

Production for the third quarter averaged 1.06 billion cubic feet equivalent per day in line with analyst expectations and consistent with the first half of 2024 results, but included a meaningful 68% increase in high-margin oil volumes. Given the current commodity environment, we elected to bring online recent production at restricted rates as well as work collaboratively with our midstream partners on the timing of periodic maintenance, providing flexibility to quickly add production in the future if warranted by commodity prices. For the remainder of 2024, we anticipate our daily production to remain relatively flat on an MMcfe per day basis as we look ahead to what we believe will be an improving gas macro in 2025. Our all-in realized price for the third quarter was $3.09 per Mcfe, including the impact of cash-settled derivatives.

This realized price is $0.93 or 43% above the 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 $85 million for the quarter, demonstrating the value of our hedge book and its impact to our cash flows. With respect to our current hedge position, we are pleased to have downside protection covering nearly 65% of our remaining 2024 natural gas production at an average floor price of $3.63 per MMBtu and natural gas swap and collar contracts totaling approximately 470 million cubic feet per day at an average floor price of $3.61 per MMBtu for 2025, securing a significant portion of our forecasted natural gas production.

We remain constructive on gas prices in 2025 and 2026, carefully choosing to maintain significant upside by utilizing collar structures on a portion of our downside hedges that allow us to participate in prices well above $4 per MMBtu. On the basis front, we continue to lock in our natural gas basis exposure, providing pricing security at our largest sales points in addition to the risk mitigation our diverse portfolio of FT offers. Approximately 15% of our natural gas has firm delivery to the Gulf Coast at TGP 500 Lake Pool and Transco Station 85. And during the third quarter, we locked in a portion of this exposure at very attractive premiums of NYMEX Henry Hub plus $0.30 and plus $0.50 for 2025 and 2026, respectively. We provide further details of our full derivative position on Slide 22 of our investor presentation as well as later today when we expect to file our 10-Q.

Turning to the balance sheet. Our financial position remains strong with trailing 12 months net leverage exiting the quarter below 1x. During the third quarter, we successfully tendered for approximately 95% of the company’s $550 million of 8% senior notes due 2026, while concurrently issuing new long-term senior notes totaling $650 million due 2029, priced at 6.75%. The completion of these transactions extended the weighted average maturity of the company’s long-term senior notes by about 3.2 years and lowered the company’s weighted average interest rate on its long-term senior notes by approximately 1.2%. In addition, we completed our fall borrowing base redetermination in September and amended our revolving credit facility. The amendment, among other things, increased elected commitments from $900 million to $1 billion, reaffirmed our borrowing base of $1.1 billion, reduced our borrowing cost by 50 basis points and extended the maturity of the credit facility to September of 2028.

As of September 30, 2024, our liquidity totaled approximately $909 million, comprised of about $3.2 million of cash, plus $906.2 million of borrowing base 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 situations arise that allow us to capture value for our stakeholders. As we close out 2024 and look ahead to 2025, we forecast continued significant free cash flow generation and common share repurchases will remain a key part of our return of capital strategy, given the unrecognized value we believe remains in our equity. While others often talk about returning value to shareholders through share repurchases, Gulfport continues to deliver on our plan, and the third quarter was no exception as we purchased nearly 2% of our current market cap in this quarter alone.

As John mentioned earlier in the call, our Board of Directors increased our common stock repurchase authorization by 54% to $1 billion and extended the program by a full year so that we can continue our strategy of capturing unappreciated value in our equity. As of October 28 and since the inception of the program, we have repurchased approximately 5.2 million shares of our common stock at an average price of just over $100 per share lowering our share count by about 18% at a weighted average price nearly 30% below our current share price. We currently have approximately $481 million available under the expanded $1 billion share repurchase program. We remain steadfast in our free cash flow allocation framework, and we’ll continue to return substantially all of our adjusted free cash flow, excluding discretionary acreage acquisitions to our shareholders through common stock repurchases.

We believe the consistency of our committed approach to share repurchases over the past few years has delivered tremendous value to our shareholders and changes to our capital allocation framework or other potential strategic considerations would need to be accretive to our fundamental value and compare favorably to repurchasing our undervalued stock. In summary, our quarterly results reflect the same theme that has been communicated in the past several quarters. Continuous operational improvements, delivering excellent results while maintaining a healthy financial position. This year’s program is delivering on all fronts and the capital efficiencies and operational improvements being realized are creating long-lasting improvements allowing us to reduce our future maintenance capital requirements on comparable drilling programs or simply put, we are delivering more with less.

This further supports the free cash flow generation potential of Gulfport and as shown on Slide 6 of our investor presentation illustrates the peer-leading free cash flow yields and five-year free cash flow capacity capable of retiring our market cap at its current level. With that, I will turn the call back over to the operator to open up the call for questions.

Operator: Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Bert Donnes with Truist Securities. Please proceed with your question.

Q&A Session

Bert Donnes : Hi. Good morning team. The improved capital guide looks pretty strong at face value, but we’ve seen some of your peers update their guidance due to shifting activity plans rather than cost reductions. So could you maybe walk us through where the savings came from? Maybe how much was efficiencies or vendor costs? And were there any shifts in your plans?

John Reinhart : Hi. Good morning, Bert, this is John. I appreciate the question. Overall, for 2024, we’ve been very pleased with the operational efficiencies and cost reductions that we’ve seen. And very specifically, there hasn’t been any material shifts with regards to our planned activity out of 2024 into 2025 similar to other operators. So I would attribute the cost savings and capital savings this year, really two-thirds to efficiency gains. This is planning did time between operations execution and just cycle time improvements probably about a third of these savings on the service cost side. So, really pleased with the progress of teams year-to-date with regards to capital reductions. And these two-thirds savings, again, these are long-lived savings that will last throughout the year as we continue to progress. So I appreciate the question. Hopefully, that answers your question.

Bert Donnes: Yeah. Sure does. And then you had some pretty strong liquids growth as well in the quarter from your condensate wells, and you put in a disclosure about more than half of your Northeast wells going to those locations. Just wanted to get an update on how you think about your inventory, maybe ranking them. You have the Utica condensate, Marcellus wells, the dry gas Utica and your SCOOP or any of them edging ahead of the rest.

John Reinhart: No, it’s a great question. This is John, again. We’re in a very good position actually corporately, especially with our discretionary acreage acquisitions over the past two years, to have a lot of toggles that the company can pull with regards to inventory. So as you know, we have several liquids window options whether it’s the SCOOP, the Marcellus, Utica, and there’s various lean and regular condensate wells along with the dry gas options. What I’d tell you is the high-quality inventory really they’re within about 15% to 20% returns, generally speaking. And we as a company, as we look at, how do we allocate that capital, it’s really returns based and what drives the best margins and improves cash flow. So we’re sitting on some options depending on where commodity prices go, to have a lot of different levers to pull.

And right now, what I would tell you is you’ve seen us lean in on the liquids area, the wet gas and the condensate area with regards to acquisitions and capital moving that way. So we’re going to continue to focus on that in the near-term, because it provides the largest uplift to the company. But we also remain pretty nimble. And we have the ability and the flexibility to shift towards gas should those returns go the other way.

Bert Donnes: Make sense. Thanks for your update.

John Reinhart: Yeah. Thanks Bert.

Operator: Thank you. Our next question comes from the line of Doug Leggate with Wolfe Research. Please proceed with your question.

Doug Leggate: Thanks. Good morning, everybody. John, the 60% liquids weight on TILs in 2025 when we spoke last night, you talked about years and years of inventory. Should we consider this as the new normal for the mix?

John Reinhart: Yeah, Doug, this is John. I appreciate the question. What I’ll tell you is just considering our investment in the liquids rich, considering the commodity price outlook and high-quality acreage we’ve been able to pickup and that the company already had in its inventory. This liquid shift will have a fairly continuous presence in the company’s portfolio for years to come. And overall, you might want to say, well, you’re a gas company, and we will always be a gas company, but it will be a meaningful shift in the near-term, let’s just call it, over the next 12 to 18 months to a 4% or 5% shift towards more liquids versus dry gas and which is directly kind of resulting in higher margins and improved free cash flow. So the bottom-line is, yes, it will be a fairly continuous part of our programs, whether it’s the Utica condensate, Utica lean condensate or Marcellus and continued SCOOP.

In some variation or form with regards to what’s driving the best returns for the company. So hopefully, that answers your question, Doug.

Doug Leggate: It does, John. I appreciate the detail, but I wonder if I could have a quick follow-up on the pressure management program. I guess I wonder if you could just characterize what the nature of that is. Now obviously, back pressure compression is one part of it. But are you also managing your flow-back differently in terms of for example, choking back wells to moderate declines in liquids uplift and all the kind of stuff that goes into that. Can you just characterize what exactly is behind that? And whether this is going to be — how widely this can be applied across the portfolio?

John Reinhart: Yeah. No, it’s a great question. I think generally speaking, this philosophy is applied across the portfolio. But what I’ll tell you is depending on commodity prices, there is some flexibility with what that actual rate will be. So it does vary with commodity prices, and it does vary between gas and the condensate window. But generally speaking, to your point, it has a lot of benefits that we tried to provide a slide out there that not only showed some of the benefits with bullet points, but also showed you the actual production profile over the last 12 to 18 months. So many benefits from the program, pinching it back, reducing potential damage, increase in the plateau period, all the things I talked about the script.

And it is transferable to condensate to your point, as well as lean condensate areas. So it’s a program that we’re managing early flow back in initial production periods throughout the portfolio. But again, we’re going to be very responsive to commodity prices and continue assess what exactly is that rate and pressure drawdown is going to provide the best risk-adjusted returns for the company.

Doug Leggate: Thanks for taking my questions, guys.

John Reinhart: Thanks.

Operator: Thank you. Our next question comes from the line of Zach Parham with JPMorgan. Please proceed with your question.

Zach Parham: Thanks for taking my questions. First, just wanted to talk about — last quarter, you talked about having the flexibility to take $25 million out of the budget. In this quarter, you officially removed $15 million from the budget while spending that remaining $10 million. Can you just talk a little bit about the decision process there? Why were those the right amounts to reduce CapEx and to spend?

Michael Hodges: Yeah. Hey, Zach, this is Mike. I’ll take the first shot, and John can jump in. I think as we assess the various options, we’re continuously looking at the highest rates of return. And we do, as I talked about in some of my comments, feel like our equity presents a compelling opportunity. So we did decide to take a bit of a hybrid approach, I would call it, between allocating some of that savings back to shareholders and then actually redeploying a bit of it into little activity here late in the year with a drilling pad. So I think it’s been just a continuous assessment. We certainly could have gone in either direction with it. We could have accelerated further or put it all to shareholders, and I think that was the decision that made the most sense to us.

Zach Parham: Okay. Thanks a lot. And just my follow-up, I wanted to talk about kind of oil and how it trades or how it trends from here you grew oil significantly quarter-over-quarter off a relatively low base, just given what you’re seeing from the early production from the condensate wells and your plans to add the four additional condensate wells in early 2025. Can you talk a little bit about the trajectory of oil production from here?

Michael Hodges: Yeah. Zach, I think you saw, like you said, a big jump here in the third quarter for our company from an oil perspective. I think as you think about the last quarter of the year, we will have a full quarter of the pad that we talked about this morning. So maybe a bit of upside there remaining, but most of that increase has probably been realized for this year. But going into next year, we’re pretty excited as John talked about, with the allocation that we’re at least preliminarily planning for our capital program. I think you’ll see us move from a low 90s gas company, 92%, I think, was our official guide this year to kind of 80%s. So you can think about exactly where that falls. I’m not exactly sure, but it’s something 87%, 88%, 89% gas and probably a similar mixture of oil and NGLs between the two on the liquid side.

But again, that’s going to be a meaningful increase from what we did here in 2024. So it’s going to really juice the bottom line, as John mentioned, from a margin perspective, we see that as a pretty exciting catalyst for next year.

Zach Parham: Thanks, Michael. Appreciate the color.

Operator: Thank you. Our next question comes from the line of Tim Rezvan with KeyBanc Capital Markets, Inc. Please proceed with your question.

Tim Rezvan: Hey good morning and thank you for taking my questions. There’s a lot I can ask. But I guess I’ll start. As you think about your capital program next year, I know you don’t have guidance out, but you’ve tended to have more front-loaded programs. And I know there’s a third rig coming in this year. Do you anticipate that sort of cadence next year? And then as we think about the free — the repurchase cadence, should we kind of think about that in line with quarterly free cash flow? Or are you going to be thinking more on an annual basis? Just trying to understand the free cash flow cadence as gas prices improve and you have that upsized authorization. Thanks.

John Reinhart: Tim, I’ll comment on the D&C activity and Michael can chime in on the share repurchases. I appreciate the question. With regards to the capital program, we will be very similarly to 2024, have a front-loaded capital program. We’re currently running 2 rigs. We’ll be picking up that third rig, let’s just call it, the late Q4 here in the Utica and in much or very similar, at least, although we haven’t provided specific guidance, you’ll find is the drilling activity will go down to 1 rig likely in the Utica and then the SCOOP fall off sometime midyear, and then we’ll be at 1 rig continuously. So, how I would characterize it as a very similar program. It’s just going to be shifted more towards liquids in higher-margin acreage versus historically some dry gas stuff that we’ve drilled. So I’ll turn it to Michael, do you want to address the share repurchases.

Michael Hodges: Yes. I mean, I think it’s a good question, Tim. I think to John’s point, similar to this year, with the capital being front-loaded, you may see a bit of an impact. But I think on our share repurchase, we think of it more on an annual basis to answer your question. And then also, I just want to kind of remind folks that we are opportunistic in our approach as well. So if we have an opportunity, especially we’ve had a large shareholder in the past that has looked to monetize some of their position, and we like that as an opportunity to step in and buy. So I don’t think it will be necessarily in sync with the quarterly capital cadence. We do kind of keep an eye on that, but we do look at it on more of an annual basis. And again, I’d like to be able to step in when there’s a unique opportunity like we’ve seen in the past.

Tim Rezvan: Okay. That makes sense. That’s helpful. And my follow-up, I just wanted to dig a little more into the liquids kind of commentary you gave. I know you don’t have production guidance out, but I’m sure in the back of your head, you have a sense of where that will shake out. Given the big increase in liquids as expected, do you have a need to keep total BOEs flat? Or is the idea that is the liquids economics are so good and you allocate there? Is that really what matters over total production? How do you think about that in 2025?

John Reinhart: Yes. I mean, just I think at a high level, we’d like to discuss maintenance — a lot of people like to discuss kind of maintenance capital and maintenance production. So I mean, just by and large, the philosophy next year will be the same as low single digit or flattish production on an equivalent basis. But most certainly, we are really focusing on enhancing our margins and free cash flow generation. And as I’ve articulated in the script, that really means a shift towards more meaningful weighted turn in lines towards the liquids next year. So all that said, generally equivalent production, we would be somewhere in the flattish range, but you’ll see liquids growth and pretty significant liquids growth moving forward into next year, which will impact our cash flow capabilities.

Tim Rezvan: Appreciate the details. Thank you.

Operator: Thank you. Our next question comes from the line of Noah Hungness with Bank of America. Please proceed with your question.

Noah Hungness: Hi, good morning, all. I just had a question here on your discretionary acreage opportunities and how you see that developing in 2025. This year, you guys have done a really good job adding inventory, both in quality, but also giving you guys extra optionality. And I was wondering if that would continue into next year.

John Reinhart: Yes. Noah, this is John. I’ll touch on that and Michael can chime in on anything he wishes to add. This has been an opportunity over the past couple of years where we’ve really taken advantage of some high-quality acreage opportunities that are bucketed in a way where we could kind of package together three, four, five, six pads together in highly economic and highly attractive areas. So over the past couple of years, we talked about adding about 2.5 years of total inventory to the company and its liquids rich activity areas. I would say that there are subsequent opportunities available out there, although we set the bar pretty high with regards to our expectations. But we’re going to remain, as I would call it, opportunistic and less programmatic in how we approach these meaning if the land teams are pretty good at scouring the land and looking for good high-quality acreage to add to our inventory.

But we have a pretty good high-quality set of inventory within the company. So we’re going to continue to monitor the landscape, look for those opportunities and be opportunistic versus programmatic, but we’re certainly open to adding anything that adds fundamental value to the company.

Noah Hungness: That makes sense. And then my second question is just on your oil differentials. This year, you guys widened the oil differentials. And I was just wondering what was driving that.

Michael Hodges: Yes. Hey, Noah, this is Michael. It’s a good question actually. It’s really a math function to be totally honest with you. So our production is obviously back half weighted this year. And because of that, the oil curve has come down in the second half of the year. But when we guide, we use a calendar month, WTI number that’s flat, a linear average of those months. So we did widen it out just to give folks kind of the right idea for the full year number. But I would tell you that actually our oil differentials themselves on a kind of month-to-month basis have actually remained very strong. There is more oil production coming out of Ohio and certainly, some folks are seeing a little bit of pressure, but we’ve actually been able to hold in that differential really well. So I think as you go into next year, we’ll reassess it and get you some better numbers, but really not much of an operational change there. It’s just simply a math function.

Noah Hungness: Okay. Thank you so much.

John Reinhart: Thanks, Noah.

Operator: Thank you. And our last question comes from the line of Jacob Roberts with TPH. Please proceed with your question.

Jacob Roberts: Good morning.

John Reinhart: Good morning, Jacob.

Jacob Roberts: Wondering if you could comment on your ability to be flexible relative to the liquids mix as we progress through the coming years and what you would need to see on the respective forward curves to make that shift from one way or the other, and if possible, the price points you guys look at to make that determination?

Michael Hodges: Yes. This is Michael. I’ll start out and John can jump in. I mean I think a lot of our commentary has been around that flexibility, right? So there’s certainly a lead time between turn in a drill bit and then turn oil and gas into sales and being able to make those changes. But I do think that if we see a significant fundamental change in commodity price coming, we do have the ability to move from one to the next. And quite frankly, the adds that we’ve made over the last couple of years have really enhanced our ability to do that. I don’t know that, that was always case, but we have a deep dry gas inventory, both in Oklahoma and in Ohio and then now have a much more substantial and significant liquids portfolio.

So as far as exactly where those prices go, again, the returns, as John mentioned, are not all that different. They’re leaning a little bit towards the liquids right now. And that’s why you see us go in that direction with our development, both in 2024 as well as in 2025. But if we saw the gas curve start to move meaningfully. And again, I don’t know that I want to quantify meaningfully, but — and it need to be a sticky change as well, I do think we’re going to see some volatility with gas, but if we saw kind of a sticky change with gas I think you could see the company pivot in a 12- to 18-month time frame to be allocating more to a dry gas program than a liquids program. So it’s a great position to be in, to be able to make those changes in a pretty quick fashion.

I don’t know, John, if you wanted to add anything.

John Reinhart: No.

Jacob Roberts: I appreciate that. No, great answer. And my follow-up would be on the efficiencies you guys have seen, obviously, lowering the capital guide I’m just wondering, as you transition more toward Marcellus or even this more liquids-weighted program. Do you expect those to continue flatline or even reverse as you kind of explore new, so to speak, areas?

John Reinhart: Yes. What I’ll tell you is just generally speaking, the industry and our teams never ceased to amaze me with regards to capital efficiencies and operational execution and improvements. So yes, this industry continues to learn. We just get better and better every year as we progress through things. So will there be some opportunity and some upside for capital efficiencies, whether that’s cost reductions or cycle time improvements, yes. And certainly, there is — to your point, I think, depending on your capital allocation, your well mix, there’s very different cycle times and very different capital intensities between the SCOOP, the Utica and the Marcellus. And it’s our job basically to take that that spend and those spin levels and maximize that for the company’s benefit to maximize free cash flow, shareholder returns and reinvestment in the company.

So I would expect more to come on efficiencies. I would be disappointed if we didn’t see more efficiencies moving forward. And I just know the teams are geared towards constantly beating records. We didn’t talk about some of the records we broke this quarter because sometimes we sound like a broken record. But I’ll tell you that there were a few more records operational and execution that were broke this quarter. So very proud of the guys out in the field are doing a great job and look for more efficiencies to come. And certainly, there’s more opportunities to your point.

Jacob Roberts: Thank you. Appreciate the time.

John Reinhart: Thanks, Jake.

Operator: 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.

John Reinhart: Thank you, everyone, for taking the time to join our call today. The team continues to improve business fundamentals, which further positions Gulfport Energy as an attractive investment with a focus on continuing value enhancement. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. Thank you very much. This concludes our call.

Operator: Thank you. This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation.