Gulfport Energy Corporation (NYSE:GPOR) Q4 2023 Earnings Call Transcript

Gulfport Energy Corporation (NYSE:GPOR) Q4 2023 Earnings Call Transcript February 28, 2024

Gulfport Energy Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, ladies and gentlemen and welcome to the Gulfport Energy Corporation Fourth Quarter 2023 Earnings Call. All lines have been placed on a listen-only mode and the floor will be open for questions and comments following the presentation. [Operator instructions] At this time, it is my pleasure to turn the floor over to your host, Jessica Antle. Welcome, Jessica. The floor is yours.

Jessica Antle: Thank you, Karen [ph] 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.

John Reinhart: Thank you, Jessica, and thank you to everyone for listening to our call. Taking a step back to reflect on the message we provided on our conference call in February of last year; I noted during 2023 we would be focused on actions that facilitate the efficient and sustainable development of our quality inventory, enhance margins, optimized efficiencies within our capital programs, all while maintaining an attractive balance sheet and utilizing our free cash flow to position the company for value enhancement The company delivered on those commitments. I’d like to highlight a few of the accomplishments the team achieved over the course of 2023. The company delivered net production above the high-end of the initial guidance range while staying below the midpoint of our initial capital budgets, provided in February, despite adding incremental activity in the fourth quarter that was not included in our original capital guidance.

We augmented our attractive acreage portfolio by allocating $48 million of our adjusted free cash flow to strategic acquisitions of Utica liquids rich acreage that extended our inventory base by one and a half years. And also by delineating two years of liquids rich Marcellus locations, overlying our existing Utica acreage with no incremental linked acquisition costs. Our 2023 development program lead to meaningful free cash flow generations totaling approximately $199 million for the year, and after adjusting for cash flow utilized for discretionary acreage acquisitions, we allocated approximately 99% of our adjusted free cash to repurchase our common stock; all of which was achieved while maintaining our strong balance sheet, ample liquidity and financial leverage below one-time.

Production for the year averaged 1,054 million cubic feet equivalent per day, roughly 3% above the high-end of our initial guidance range provided in early 2023. The outperformance was driven by improved cycle times, accelerating the timing of wells brought online, as well as continued strong well performance from our development program. We remain excited about our shift to a pressure managed flowback program, which drives longer production plateau periods, shallower declines, and capital efficiencies associated with reduced facility costs. Furthermore, based on flowing pressures as the leading indicator, this program should contribute improved EURs and enhanced development economics while improving corporate base decline and lowering future capital intensity.

Operationally for the full year, the company drilled and turned to sales 24 gross wells, which included 2 Marcellus, 2 SCOOP and 20 wells in the Utica. On the drilling side we achieved meaningful cycle time improvements throughout the year, experiencing over a 60% year-over-year improvement and total footage drill per day when compared to year-end 2022. The company’s fourth quarter average total footage drill per day was the highest for the year providing strong momentum as we commenced drilling on a three well pad in the SCOOP, and look forward to applying our Utica learnings and operational efficiencies realized in 2023 to our 2024 SCOOP Development Program. On the completion side, we also saw a significant efficiency improvement in the frac and drill out phases of our operations, improving average frac pumping hours per day by 30% in 2023, and average plugs drill per day by almost 50%; exiting the year with a quarterly average of 20.8 frac pumping hours per day, again, our highest quarterly average for the year.

Our operating team’s high level of efficiency and cost reduction focus resulted in over $35 million in capital savings during 2023. And as previously announced, we elected to reinvest those savings into the development of our high-quality assets by adding incremental drilling and completion operations during the fourth quarter. Even with this acceleration of activity, we continue to deliver within expectations of full year 2023 capital expenditures which totaled approximately $443 million, excluding discretionary acreage acquisitions. Specific to our Marcellus development; we drilled and completed the company’s first two operated Marcellus wells on our stack pay acreage in Belmont County. When normalized to a 15,000 foot lateral, the wells delivered an average 60-day initial production rate of approximately 860 barrels per day of oil, and 5.2 million cubic feet a day of natural gas.

As a reminder, these wells are located on an existing Utica pad, allowing significant midstream flexibility in our ability to blend the rich gas from the Marcellus wells with existing Utica dry gas production. We remain very encouraged as we continue to gain more production data and produce the wells under pressure managed flow, currently experiencing less than 6 PSI pressure drop per day, following 60-plus days of production. We believe the hinder shot [ph] development, along with existing industry offset development in Ohio and West Virginia has significantly de-risked our Marcellus position, and now estimate we have delineated approximately 50 to 60 gross wells. Assuming our Marcellus development cadence of roughly 25 wells per year, this equates to approximately two years of liquids rich inventory.

When considering the strong results and the attractive rates of return that compete for capital across our premier asset portfolio, we anticipate additional Marcellus development beginning in early 2025. On the discretionary acreage acquisition front, the company expanded our acreage position by investing $48 million in 2023 towards targeted Utica liquids rich acreage within our Belmont County development footprint. With our current drilling pace, approximately 1.5 years of core liquids rich locations were added at an average cost of approximately $1.7 million per net location. When coupled with the de-risking of our Marcellus acreage, the additional inventory provides durable fundamental value to the company, as well as expanding optionality in our go-forward development plans.

The company is prioritizing development of the recently acquired Utica acreage and plans to begin pad construction in the area in late-2024, with plans to commence drilling in early-2025. The discretionary acreage acquisition spending in 2023 allowed us to organically extend our high-quality inventory base at extremely attractive returns. We will continue to monitor opportunities to meaningfully increase or leasehold footprint to enhance resource depth and believe these opportunities rank very high as we continuously assess and evaluate uses of free cash flow in 2024. As we move into 2024, the current volatile natural gas environment reinforces the importance of developing our assets in an efficient and sustainable manner. Building on the momentum from 2023, we plan to remain focused on farther optimizing our margins, development programs cycle times and operating costs.

The company forecasts delivering relatively flat production year-over-year on 10% less capital invested. The total capital spending for the year is projected to be in the range of $380 million to $420 million; with more focus on liquids rich development in both, the Utica and SCOOP than prior programs. Our total capital spin includes $50 million to $60 million of maintenance land and leasehold investment, focused on bolstering our near-term drilling program with increases of working interest and lateral footage in units we plan to drill near-term. The company’s 2024 Utica turning line [ph] operated working interest is anticipated to be 97%, an increase of 5% over 2023’s program, with the average lateral length of the planned activity up nearly 30% over 2023; increasing our exposure to our high return operated development program.

Simply put, our significant operational efficiencies and reinvestment in our asset base through our land maintenance program allows us to deliver a 2024 program in line with 2023 production results on less well activity and capital invested. It is worth highlighting that our 2024 program also includes roughly $30 million to $35 million of capital allocated towards building strategic ducts beyond our normal operating cadence enhancing future capital program optionality and further highlighting our significant year-over-year efficiencies and our ability to deliver similar production in 2024 on meaningfully lower capital. We currently forecast approximately 70% 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 the year.

Turning to production, we anticipate this level of spin will deliver 1.045 billion to 1.08 billion cubic feet equivalent per day in 2024; relatively flat over our full year 2023 average. We are remaining flexible in light of the commodity backdrop and possess the ability to moderately defer or accelerate completions should commodity prices and rates of return warren [ph]. In our investment deck on Slide 11, we included a more detailed outlook of our expected 2024 capital and production cadence. We currently forecast our 2024 production to total 92% natural gas, which will be higher in the first half of 2024 as a result of our natural gas directed activity late last year, and move slightly towards the higher liquids waiting towards the back half of 2024 and into 2025 as we bring online our more liquids rich development.

In closing, despite a challenging commodity backdrop, we project Gulfport will continue to generate meaningful adjusted free cash flow in 2024 and currently forecast a top decile [ph] free cash flow yield relative to our natural gas peers. We plan to continue to focus on the return of 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 will turn the call over to Michael to discuss our financial results.

Michael Hodges: 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.

Said in other way, we delivered our best quarter of 2023 from an adjusted free cash flow perspective, and leverage 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 LOE, taxes other than income and midstream expenses will 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 realize the cash hedging gain of approximately $50 million during the quarter, demonstrating the strength of our hedge book and its impact to 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 had 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 color 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-risk 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 projected the 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 advantage 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 were 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 to 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 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 are pushed 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.

See also 21 Countries that Have the Highest Rates of Cancer Deaths and 15 Developed Countries with Citizenship Tests.

Q&A Session

Operator: Thank you. [Operator Instructions] And we’ll take our first question from Bert Donnes from Truist Securities. Please go ahead, Bert.

Bertrand Donnes: Good morning, everybody. Just want to start off on the — maybe a question on the new guidance. The 10% lower capital requirement is certainly impressive. Just wondering if you could isolate some of the drivers of those savings you’re seeing? And then, you mentioned the $30 million to $35 million, maybe you could quantify where that program leaves you on a duck count [ph] or a well in progress count? And how you utilize that?

John Reinhart: Well, Matt will talk a little bit on the capital efficiency side. As John highlighted in the call, or the script there; we’ve seen quite a bit on the drilling side, obviously 50%, kind of year-over-year on the frac side as teams are doing an excellent job in the field, getting those pumping hours per day, pretty much at maximum at this point; we’re over 20 hours a day on average. So, all that translates into that 50% [ph] savings we’d expect to see kind of going forward on a year-over-year basis. You think about our decreased dollar per foot well costs from 2023, primarily 65% or so of that is on the efficiencies, that’s long lasting. And then we’ve done a really good job on the supply chain front, working towards the softening market and also just restructuring some contracts that are in place when we got here early in the year; so that kind of translates the other 35% of those savings.

So, all in all those things can fluctuate on the commodity pricing side but certainly those efficiencies are where we’re focused because those are long lasting.

Matt Rucker: Bertrand, I’ll take the question on the duck side [ph]; I appreciate you asking that. I think carrying those six ducks [ph] which is roughly the number that would we would call your non-routine type duck [ph] inventory carrying for the company, it really holds a lot of strategic value. It provides optionality for us to actually accelerate completion should commodity prices warrant, but whenever you think about that $30 million to $35 million that we spent this year on it, I think to your point is that is incremental actual capital that if you look on a go-forward type maintenance level program, not only are we realizing 10% year-on-year reduction, but also that non-reoccurring type duck [ph] just kind of reinforces how much efficiency gains and how much cost reductions a team has achieved over the past year.

So, real pleased with the execution and performance and efficiencies, and hopefully that kind of clarifies duck [ph] counts and have questions regarding him for capital.

Bertrand Donnes: That sure does. And then my second question is, if I’m not mistaken on your slides, the new Marcellus oil rates seem to shake up the IRR ranking. I know there’s certain commodity assumptions in there but you outlined 50 to 60 locations; I think in the prepared remarks you mentioned — maybe dipping your toe into it in 2025. I just wasn’t sure; is there a role for this to be become a bigger part of the program? And how does that work; does it pull capital away or is it incremental activity if pricing permits?

John Reinhart: It’s a great question. I mean, we’re very excited about the Marcellus, it’s been a great deal of time actually talking about it in the script and it’s certainly in the IR deck. Big value component for the company with regards to the inventory counts and the delineation efforts — zero land costs. As we think about this to your point about returns, we’re very pleased with how we’re sitting with our investment in the Utica condensate window, the delineation efforts in the Marcellus condensate window, we’ve got the SCOOP liquids rich development, and you’ve got really high quality Utica dry gas. So all of these you can see — I think there’s a slide in the investor deck that kind of gives you an approximate return level; these all compete for capital which is in a very good — it’s a very good place to be for the company.

So it gives us a lot more optionality. So I think on a point forward perspective, you certainly will see end of 2024 and into 2025, a bit more balanced liquids participation within our portfolio. So yes, I would certainly consider it as we talked about accelerating the Utica acquisitions recently in 2025, we talked about the acceleration in 2025 activity for the Marcellus, you’ll see a more balanced SCOOP liquids type rich mix within the portfolio of development moving forward than what we’ve seen historically, just sheerly because of economics. So great place to be, and it’s nice to be able to delineate and spend some money on acreage that you can immediately kind of take the bid to within 12 to 18 months, it really reduces the returns and I am real pleased with the program moving forward.

Operator: [Operator Instructions] And next, we’ll go to Tim Rezvan from KeyBanc Capital. Please go ahead, Tim.

Timothy Rezvan: Good morning, folks. When we spoke recently, I know you all said you would balance repurchases against your ability to sort of, find more inventory. So I was just kind of curious, you have line of sight last year on that $40 million to $50 million. How does the ground game look today? Are you opportunistically — I guess, are you confident you can add more? And I’m just trying to think as you look, are you agnostic to oil versus gas? Are you kind of focused on one area right now? Thanks.

Michael Hodges: Tim, this is Michael. Great question. So I think as we look into 2024, the strategy really remains the same. So we’ve said last year that we’re going to return substantially all of our free cash flow back to shareholders after discretionary acreage acquisitions. That’s really a similar strategy this year, we’re going to be opportunistic. There’s still opportunities that we like out there, it’s certainly getting more competitive as the basin has gained more attention. But as we look at the opportunity to generate the highest rates of return with our free cash flow, there’s two particular categories that always rise to the top of that list; and those are our shares, and it’s also our opportunity to grab future locations.

So we’re not guiding to it this year, it’s something that we’re always focused on. We do think that it’s a tremendous value back to the company when we can add those types of locations. So at the point that we have line of sight will certainly update the market, it’s not programmatic and so we don’t provide that guidance this morning but we’re still very focused on it. And I think we’re optimistic that we can have similar levels of success. If that’s not the case, our equity — we feel like it’s a great place to spend money, so we’ll continue to go there as well.

Timothy Rezvan: Okay. I was just trying to get a number out of you but I understand that you’re not ready to give one now. So, appreciate that — the details, Michael. And as my follow-up, just kind of wanted to pick up the topic from the prior question on the ducks [ph]. You mentioned having strategic ducks [ph] — you mentioned the ability to defer or accelerate as needed in 2024. So I guess when you look at a gas prices today at sub $2, what would keep you from joining your neighbor at OKC [ph] and kind of letting production decline? You know, things seem pretty bleak here in the near-term; so — what would you look to to actually do more of a strategic deferral of volumes?

John Reinhart: Yes, that’s a good question. I think whenever we look at the company and the scale and size in our footprint, and quite frankly, the quality of assets and the execution; we assess the PV and the returns on our total development program. And I mean, if you kind of take a look at where we stand, we kind of wanted to come out with a maintenance level program that was down the fairway with the ability to toggle down or toggle up without [ph]. But I’ll tell you is — so to the question of what it would take to decline volumes; I would say we look at them on an economic basis. So if we’re looking at for instance, pricing that’s materially lower, it turns out to be material lower with upside a quarter later or two quarters later; that’s certainly something we’re going to consider with regards to the value that the company will realize on developing those assets.

So it’s a real-time kind of assessment as we look at the program, and it really will depend on where we are in the commodity cycle — should we choose to do something with regards to deferrals or acceleration. And it’s very nice actually to have that toggle. I mean it’s — maybe a bad thing that we’re in the environment that we’re asking to consider those things but what I’ll tell you is, not having the requirements of [indiscernible], drilling to hold acreage; I mean, these are all things that we are very fortunate not to be in a place to have to consider whenever we think about the cadence and control. And what we’re going to deliver from a production standpoint is truly based on PV and economics and returns. And we’re also very mindful of just the cadence of the production and making sure that it flows year-to-year without any kind of dramatic declines.

So hopefully, that kind of buckets it for you. I think it’s just more of an economic assessment real-time as we go through the year. And if we see some potential with a quarter deferment — let’s say on a turning line [ph] where we can add some PV to those assets, that’s certainly something that we’re going to consider doing.

Timothy Rezvan: Thanks, John. I appreciate all the color.

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

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

John Reinhart: Yes. Well, what I’ll point you to is, I think coming in here about a year ago; historically, the guys have done a good really good job here at being very aggressive on completion intensities. So, as we looked across and assess the development plan and development program, spacing was adjusted a bit wider, and the teams really were aggressively stimulating those. And I’ve been very clear for the past year where our focus was, was not going backwards on well productivity and not going backwards on the EURs [ph], as a matter of fact, taking all those advantages of aggressive stimulations and moderating spacing and actually getting our capital efficiencies up, and our capital costs down and our expenses down. So, we’re real pleased to have a solid footprint in very good rock.

And with that asset, if you go and employ a very aggressive simulation program, and you do it fairly efficiently, from a capital perspective that really just leads to overall economic results. And the well productivity results you’re seeing on these slides is certainly driven by asset quality, and spacing, and stimulation, aggressiveness from the teams. And Matt, if you have anything else to add?

Matt Rucker: 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 flow backs and kind of lower for longer IP rights which we believe helps with the pressure maintenance overtime, 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.

Jake Roberts: Thanks, appreciate that. Staying on the same topic, in the prepared remarks you mentioned applying learning to the SCOOP. Just curious on the timeline before you kind of settle in on a development program or the methodology that you think works going forward; and this in terms of applying completion design flow back, just — I would like to explore those aspects, please.

Matt Rucker: Yes, this is Matt again. I’ll take that and John can add comments, if he has any. We’re in the middle of kind of restarting up our SCOOP program development, we did kind of two wells early last year, and with the new team in place to kind of put the pause on that to focus on Marcellus delineation and kind of get our arms wrapped around that asset. In that review this year, a lot of good things have come out of it; a lot of technical reviews, the team has been working pretty diligently on understanding how do we best get repeatability on this basin from an execution standpoint. And so, right now we’re on that first three well pad, we’re kind of right smack in the middle of that development, trailing some new things that we’ve kind of taken from the Utica and applied here.

So, I would expect for us throughout the next quarter or two to be able to start sharing some of those progress updates. But ultimately for us, if we can kind of execute on that plan this year — kind of prove that repeatability, it just de-risks our program in the way we look at that asset for future planning on drilling cadence in that basin is. If that helps?

Jake Roberts: Absolutely. Perfect time [ph].

Operator: Thank you. I’ll turn the floor to John Reinhart for closing remarks.

John Reinhart: 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.

Operator: 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.