Gulfport Energy - Earnings Call - Q4 2024

Executive Summary

• Q4 2024 delivered solid operational and cash results with adjusted EBITDA of $202.8M and adjusted free cash flow of $125.2M, while GAAP results showed a net loss of $273.2M driven by a non‑cash impairment under SEC pricing; total net production was 1.06 Bcfe/d and liquids rose 7% QoQ and 13% YoY.
• 2025 outlook targets a >30% liquids production increase to 18.0–20.5 MBbl/d on flat total Bcfe, with base capex of $370–$395M and per‑foot D&C capital ~20% lower YoY; management intends to return substantially all 2025 adjusted FCF via buybacks.
• Cost performance remained strong (cash operating costs $1.19/Mcfe in Q4), and a new Marcellus midstream agreement supports enhanced NGL realizations; management highlighted hedging that secures downside while preserving upside via collars.
• Capital returns were active with $80.1M repurchases (491k shares) in Q4; authorization stands at $1.0B with ~$406.8M remaining capacity as of 2/20/25.

What Went Well and What Went Wrong

What Went Well

• Adjusted EBITDA ($202.8M) and adjusted free cash flow ($125.2M) were strong, helped by liquids uplift, robust realized pricing ($3.36/Mcfe incl. hedges), and operating cost excellence; CFO: “Needless to say, it was an outstanding quarter”.
• Liquids strategy gaining traction: liquids production up 7% QoQ to 16.2 MBbl/d, with 2025 development targeting Utica lean condensate and Marcellus to drive >30% liquids growth.
• Efficiency gains: 2025 D&C capital per foot expected ~20% lower; 2024 saw +10% drilling footage/day and +25% completion hours/day improvements in Utica.

What Went Wrong

• GAAP net loss of $273.2M in Q4 due to non‑cash impairment tied to SEC pricing (Henry Hub $2.13/MMBtu), despite strong non‑GAAP performance.
• Proved reserves decreased ~6% YoY primarily from price revisions, even as extensions/discoveries and performance revisions were positive.
• Management expects slightly higher 2025 per‑unit LOE and midstream costs ($1.20–$1.29/Mcfe) due to liquids‑weighted activity, though margin uplift more than offsets.

Transcript

Operator (participant)

Welcome to Gulfport Energy Corporation fourth quarter 2024 earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Ms. Jessica Antle. Thank you, Ms. Antle. You may begin.

Jessica Antle (VP of Investor Relations)

Thank you, and good morning. Welcome to Gulfport Energy Corporation's fourth quarter and full year 2024 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, Matthew Rucker, Executive Vice President and Chief Operating Officer, 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 make reference to non-GAAP measures.

Reconciliation 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 (President and CEO)

Thank you, Jessica. Good morning, everyone, and thank you for joining us on today's call. On behalf of the Board of Directors and all employees at Gulfport Energy, I would like to congratulate Matthew Rucker on his well-deserved promotion to Executive Vice President and Chief Operating Officer. This promotion is a recognition of the leadership Matthew has provided the company over the past couple of years in leading the operations team. The successes achieved operationally have been paramount in building a culture of continuous improvement, delivering outstanding execution efficiencies and cost reductions throughout our development program. We are looking forward to his future contributions to the company as we continue to strive for best-in-class results for the benefit of all Gulfport Energy stakeholders. I will begin my comments discussing the 2025 development program we announced yesterday alongside earnings, and then highlight a few points that define our strong 2024 performance.

Building on our momentum from last year, Gulfport's 2025 development program reflects significant efficiency gains and portfolio capital allocation optimizations that will allow us to maintain flat total production and flat total base capital invested while substantially growing the company's expected liquids production by 30% year-over-year. The 2025 program is focused on sustaining the company's exposure to a constructive natural gas environment and delivering enhanced hydrocarbon diversification by targeting the lean condensate Utica and low-cost Marcellus condensate windows, all resulting in adjusted free cash flow generation that is estimated at today's commodity prices to be more than double compared to the 2024 results, and consistent with last year regarding our adjusted free cash flow allocation framework, we plan to return substantially all 2025 adjusted free cash flow, excluding discretionary acreage acquisitions through common stock repurchases.

Total capital spend for the year is projected to be flat and in the range of $370 million-$395 million, which includes $35 million-$40 million of maintenance land and leasehold investment. Cost improvements and capital allocation to inventory additions over the past two years facilitate a 2025 development program that delivers a reduction of our annual operated drilling and completion capital on a per-foot of completed lateral basis by approximately 20% when compared to 2024. This substantial efficiency gain is driven by roughly half operational efficiencies and service cost improvements, with the remainder being a function of well mix optimization. The company's operating teams continue to drive efficiencies up and service costs down. When combined with the 2025 portfolio allocation towards Appalachia Liquids, while also maintaining our low-decline SCOOP asset production base, the company is able to accelerate activity on similar total capital spend year on year.

Similar to years past, we currently forecast approximately 75% of our drilling and completion capital will be allocated in the first half of 2025 and trend lower in both the third and fourth quarters of the year. Turning to production, the 2025 plan highlights our transition from delineation to development mode in the Marcellus and includes development targeting the Utica lean condensate acreage recently acquired through our discretionary acreage acquisitions. Notably, this is the first year that the company is completing wells in all five major development areas, inclusive of the SCOOP, Utica dry gas, Utica condensate, Utica lean condensate, and Marcellus, as noted in the investor deck on slide 11.

We forecast approximately 50% of the total company turn-in-line will be liquids-rich weighted during the year, anticipating liquids production defined as combined oil and NGL production will increase over 30% year on year based upon the midpoint of our guidance, and total in the range of 18.0-20.5 thousand barrels per day for the full year. In addition, we expect total equivalent production to be relatively flat to full year 2024, with an increasing production profile as we progress throughout the year, positioning the company attractively for an improving commodity environment with further potential opportunities for capital and production efficiency improvements in the future years. In our investor deck on slide 12, we include a more detailed outlook on our expected 2025 capital and production cadence.

Shifting to the company's 2024 performance, Gulfport achieved strong financial results for the full year highlighted by our high-quality resource base, continued focus on operating efficiencies, and attractive adjusted free cash flow generation. We repurchased approximately 7% of our common shares outstanding through our ongoing stock repurchase program while maintaining a strong balance sheet and continuing accretive inventory additions in the Utica liquids-rich window, adding approximately a year of largely lean condensate inventory. After adjusting for free cash flow utilized for discretionary acreage acquisitions, the company allocated substantially all of our adjusted free cash flow to repurchasing our common stock during 2024, returning 96% of our available adjusted free cash flow to shareholders throughout the year.

Turning to specifics, full year 2024 capital expenditures, excluding discretionary acreage acquisitions, totalled approximately $385 million, and production for the year averaged 1.05 billion cu ft equivalent per day, both in line with the expectations we set forth with investors at the beginning of the year. The company drilled 21 gross wells, which were predominantly focused in the Utica. On the completion side, Gulfport completed and turned to sales 19 gross wells, which included three SCOOP wells, 12 Utica dry gas wells, and four Utica condensate wells. Alongside yesterday's earnings announcement, we provided longer-dated production history from our four-well condensate pad in Harrison County, Ohio, and we are very pleased with the continued strong reservoir performance.

Referring to slide 15 of the investor deck, under our managed pressure approach and following six months or 180 days of production, the L7 wells are exhibiting a relatively flat production profile with minimal daily pressure drawdown. As we noted on our third quarter call in November, we elected to increase production rates on two of the four wells to determine the optimal production profile for this pad, as well as future nearby development, and concluded additional reservoir productive capacity remains. Moving forward, we have the ability to flow at increased initial production rates, preserving long-term well performance while also maximizing returns. We are currently completing our nearby Kage development and look forward to applying our learnings from the L7 pad to this development, which is expected to come online in late March.

In addition, on slide 14 of our investor deck, we provided an update on our Utica dry gas well performance with over 12 months' production history, and as you can see, since we enacted the managed pressure approach in early 2023, the development program has continued to exhibit strong results, yielding higher cumulative recoveries per thousand foot of lateral after an extended production period. Operationally, we continue to focus on improving efficiency, and on the drilling side, we achieve cycle-time improvements in total footage drilled per day of over 9% year on year and over 55% when compared to year-end 2022. On the completion side, we also continue to see efficiency improvements in the frac and drill-out phases of our operations, improving average frac pumping hours per day by 25% in 2024 and average plugs drilled per day by 46%.

Our operating team's high level of efficiency and cost reductions translate into realized savings for our 2025 development program, and we now expect our 2025 Utica per well cost to be below $900 per foot of lateral, or approximately 10% lower than full year 2024. On the discretionary acreage front, the company expanded our acreage footprint by investing $45 million in 2024, largely targeting Utica lean condensate acreage within our Belmont County development footprint. With our current drilling pace, we added over a year of core liquids-rich locations, and when coupled with our 2023 efforts and the de-risking of our Marcellus acreage, we have added over four and a half years of high-margin liquids-rich inventory through delineation and discretionary acreage acquisition efforts.

The additional inventory provides durable fundamental value to the company, as well as competitive returns with our existing high-quality inventory, as we highlight on slide 15 of the investor deck. We will continue to monitor opportunities to increase our leasehold footprint to enhance resource depth, and believe these opportunities rank very high as we evaluate uses of free cash flow in 2025. In closing, we are proud of the progress and solid foundation the Gulfport team has built and continues to build upon. The company remains focused on continued operational improvements and optimizing our asset development and portfolio allocation in order to maximize free cash flow generation and value for our investors. Now I will turn the call over to Michael to discuss our financial results.

Michael Hodges (EVP and CFO)

Thank you, John, and good morning, everyone.

I'll start by summarizing the key components of our fourth quarter financial results, which highlights the strong financial position of the company as we closed out the year and hit the ground running in 2025. Net cash provided by operating activities before changes in working capital totaled approximately $185 million during the fourth quarter, more than tripled our capital expenditures for the quarter, and allowing us to make significant common share repurchases, all while maintaining our balance sheet strength. We reported adjusted EBITDA of $203 million during the quarter and generated adjusted free cash flow of $125 million for the same period, driven by robust natural gas pricing, strong liquids production, and our operating cost excellence.

Said another way, we delivered our best quarter of 2024 from an adjusted free cash flow perspective and utilized the resulting cash to add incremental high-quality inventory while also buying back over 2% of our market capitalization through our share repurchase program. Needless to say, it was an outstanding quarter for Gulfport. Cash operating costs for the fourth quarter totaled $1.19 per million cubic feet equivalent, better than analyst expectations and within our full year 2024 guidance range. In addition, we are pleased to announce that we reached an agreement in early 2025 with a high-quality midstream provider for the gathering, processing, and fractionation of our Marcellus development, and we'll have that solution in place for the upcoming four-well Marcellus turn-in line planned for mid-2025, enhancing the development economics by enabling the extraction and sales of our valuable NGLs.

The company's focus on more liquids-rich activity and the resulting higher weighting of our liquids in our production mix will lead to a slight increase in our 2025 per unit LOE and midstream expenses, including gathering, processing, transportation, and compression costs over full year 2024, and we currently forecast per unit operating costs will total in the range of $1.20-$1.29 per Mcfe. Despite these slightly elevated costs, it is important to highlight that this increase is more than offset by the strong margin performance and value contribution from liquids, leading ultimately to improved cash flows. Our all-in realized price for the fourth quarter was $3.36 per Mcfe, including the impact of cash settled derivatives.

This realized unit price is a $0.57 premium to NYMEX Henry Hub index prices, driven by a differentiated 2024 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 $42 million for the quarter, demonstrating the value of our 2024 hedge book and its effectiveness in bolstering our cash flows. With respect to our current hedge position, we have downside protection covering roughly 50% of our 2025 natural gas production at an average floor price of $3.62 per MMBtu, securing a baseline amount of our forecasted free cash flow generation.

That said, we remain constructive on gas prices in 2025 and 2026, carefully choosing to maintain significant upside by utilizing collar structures on nearly half of those downside hedges in 2025 that allow us to participate in prices above $4 per MMBtu. We have strategically positioned our hedge book in both 2025 and 2026 with less overall production hedged and with a significant portion of collars in our overall hedge book, as we have been believers in an improving gas macro for 2025 and beyond for some time now. 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 firm transportation offers. We provide further details of our full derivative position on slide 22 of our investor presentation and later today when we expect to file our 10-K.

Turning to the balance sheet, our financial position remains very strong, with trailing 12-month net leverage ending the year below one times. As of December 31st, 2024, our liquidity totaled $900 million, comprised of $1.5 million of cash plus $898.2 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. With respect to EBITDA and adjusted free cash flow generation, the recent rise in natural gas prices, along with our continuous operational improvements and more efficient capital program, position 2025 to be a transformative year for Gulfport from a cash flow perspective.

Based on current strip pricing, we forecast our adjusted free cash flow should accelerate throughout the year and has the potential to more than double compared to 2024, all while our net leverage organically declines, further strengthening our already top-tier free cash flow yield relative to our natural gas peers. During the fourth quarter, we repurchased approximately 491,000 shares of common stock for about $80 million, which includes direct repurchases of common stock from our largest shareholder totaling approximately 230,000 shares, which allowed us to capture larger blocks of unrecognized equity value at a discount to market prices without impacting our public float. As of February 20th, and since the inception of the program, we have repurchased approximately 5.6 million shares of common stock at an average price of $105.57, lowering our share count by 17% at a weighted average price nearly 41% below today's opening share price.

We currently have approximately 407 million available under the $1.0 billion share repurchase program and remain steadfast in our free cash flow allocation framework to continue to return substantially all of our adjusted free cash flow, excluding discretionary acreage acquisitions to our shareholders through common stock repurchases. Turning to our year-end reserves, while the lower commodity price environment impacted our overall SEC reserve volumes, the company's proved reserve base increased by approximately 6% when excluding the impact of pricing revisions through the addition of new reserves, positive performance revisions, increases in working interest as a result of our successful leasing efforts, and continued efficiencies in our operations.

Utilizing our 2024 reserve report at a flat $3.50 per MMBtu and $70 per barrel of oil case, and keeping in mind that the reserve report is limited to five years of development, our PV-10 value totals approximately $3.8 billion, a significant uplift from the SEC pricing case that is run at $2.13 per MMBtu and $76.32 per barrel of oil. In addition, the PV-10 value of the 2024 year-end proved reserve represents an increase to the PV-10 value of the 2023 proved reserves at the same flat price case, which is a reflection of the high-quality inventory additions and the significant operational improvements we have made over the last 12 months.

Similar to the third quarter of 2024, under the full cost method of accounting for oil and gas properties, we were required to record a non-cash impairment during the fourth quarter based upon the future value of our reserves utilizing the low SEC natural gas price I mentioned previously. However, the underlying value of our assets remained strong, as evidenced by the PV-10 value of the reserve report at the flat price case I just mentioned, and we remain confident in the long-term quality of our assets. In summary, 2024 was a strong year for Gulfport, and our results reflect a consistent theme that we continue to reiterate. The team's exceptional operational performance continues to deliver superior results while maintaining a healthy financial position.

As we look ahead to 2025, and as John already mentioned, the combination of our optimized development program and the improving commodity price environment provides Gulfport with the ability to deliver meaningful growth in free cash flow generation, and as shown on slide six of our investor presentation, we continue to generate premium free cash flow yields relative to our peers with the 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 (participant)

Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue.

You may press star two if you would like to remove your questions from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for questions. The first question comes from the line of Worth Owens with Seaport Global Securities. Please go ahead.

Worth Owens (Managing Director and Senior E&P Analyst)

Hi, good morning, guys. The new liquids volume that you outlined for full year 2025 looks fairly strong, certainly versus us in the street. So could you maybe talk about if that's a peak level, or can you hold it flat, or maybe even grow it with your current assets? And then to make it simple on the operator, I'm going to bundle my second question into this.

Does the liquids growth and focus change the way you're looking at potential bolt-ons on a gas-first liquids basis, and does it make more sense to focus on PDP-heavy or undeveloped assets?Thanks.

Michael Hodges (EVP and CFO)

Yeah, hey, Worth, this is Michael. I'll take the first part, and then I think John can handle the second part of that question. I think the liquids growth, the 30% that we talked about, is sustainable, absolutely. I think as you look in our investor deck, we've got a slide that lays out the cadence of our production profile for the year. I think the liquids will generally follow that same shape. Because of the timing of the turn-in-line, we may be a little bit oilier early in the year. With that liquids production, we may be a little bit more NGL-heavy later in the year.

But as we look out into the future, we certainly have a lot of development this year in the liquids windows and expect that going forward, we have the option again to continue to allocate towards those areas and deliver more liquids should we choose to do that. But the nice thing that we've talked about over and over again is we have that flexibility to move between windows, and this year is going to be a bit liquids-rich, but we'll monitor the macro on the gas side as well, and we can certainly pivot there. So I'll let John take the second part of that question.

John Reinhart (President and CEO)

Yeah, Worth, thanks again for the question this morning.

I think if you look historically at where the company has allocated its free cash flows, it's purchasing our undervalued shares and with acreage inventory additions, which the thesis behind that really is to use the execution prowess of the team and the great performance by the team to extract value with this undeveloped acreage. So as you think about bolt-on opportunities that may arise throughout the year, what I would tell you is while PDP is somewhat attractive, what would really be attractive to the company is the sizable undeveloped portion of any kind of bolt-on opportunity that may present itself. And it's the same philosophy as we allocate capital towards the discretionary acreage. It's really just using the prowess of the team to extract value from that. So hopefully that answered your question, and certainly appreciate it.

Worth Owens (Managing Director and Senior E&P Analyst)

Certainly does. Thank you.

Operator (participant)

Mr.Owens, are you done with the question?

Worth Owens (Managing Director and Senior E&P Analyst)

Yep, bundled them both in there. Thank you. Thank you.

Operator (participant)

Next question comes from the line of Tim Rezvan with KeyBanc Capital Markets. Please go ahead.

Hi, this is John on for Tim. Thanks for taking our questions. Looks like you'll be turning in line around 30% more lateral footage on just 6% higher D&C costs this year. This is on top of what looks like shorter laterals for some of the wells this year. We're wondering, do you see this front-loaded capex program as conducive to driving these capital efficiencies further, and do you see it as the norm in the years ahead?

John Reinhart (President and CEO)

Yeah, I appreciate the question, John. And the team has been very focused, and we remain very focused on capital efficiency.

The return on the cash employed has been a kind of mainstay tenet for the company as we assess various development options, so front-loaded capital programs certainly deliver that, and I'll tell you that a lot of care and time goes into whenever we plan out and develop these, the timing of the turn-in-line, specifically what window and maturity you turn in line, at what time to maximize the value of the company for the cash flows throughout the year, so yes, I think whenever you look at things from a capital efficiency perspective, that front-loaded capital program, generally speaking, we've been consistent with that through the last couple of years, and I would envision us being consistent with that for the foreseeable future.

Okay, that's helpful.

If I could squeeze in one more, given your potential to generate significant free cash flow this year, it looks like to the tune of $400 million-$500 million or so. How do you think about future capital allocation? Maybe what does the market look like for medium-sized asset packages in the $100 million range or so? And are you comfortable with just returning the majority of this cash as repurchases?

Michael Hodges (EVP and CFO)

Yeah, hey, this is Michael. I'll take the question. Thanks, John. I think our framework has been really effective for us, right? I think we meet with our board and continuously assess all the options for our free cash flow and look at those on a rate-of-return basis and discuss which ones we think actually deliver the best result for our shareholders.

Over the last couple of years, adding to the inventory of the company and buying the shares has both been extremely successful, and so I think that's front and center for us. That said, we always assess opportunities. There's packages around in the market that are small, medium-sized, large. They have PDP components. They have undeveloped components, as John talked about on the last question, and so we take a look at those. But I think, again, with where we feel like our equity trades and the value that we think is still unrecognized, along with the opportunity organically to go out and add locations, those are high bars to clear. So we'll continue to assess those things. I think there's always those other options out there, and if the right thing comes along, then certainly look at it.

But I feel like what we've done so far is making a lot of sense for us and likely to continue that as we go forward.

That makes sense. Appreciate the time.

Operator (participant)

Thank you. Next question comes from the line of Carlos Escalante with Wolfe Research. Please go ahead.

Carlo Escalante (Senior Associate)

Hey, good morning, guys. How are you guys doing? Congratulations, Matt, first of all. I'm starting there purposely because my question is to you. Part of the job. If I take the Utica pads apart, you guys, and I see how you opened the valves on day 120 and all that it means regarding the pressure drawdown and productivity, does that say anything, or does that invite you to perhaps how you frame your unit development moving forward versus what you did with the Utica pad specifically?

Matthew Rucker (EVP and COO)

Yeah, thanks, Carlos. Appreciate that. It certainly does.

I think it's something that we've talked about a long time on the choke management program and the Utica dry gas. Certainly something we've believed in in the liquids window. Tested that out on the lease, as you noted, after 120 days, started to increase those rates a little bit more. I think it's well known in the public space that there's other peers out there that open them a lot more aggressively. So for us, it was an ideal time to test incrementally higher rates to understand what that drawdown looks like and understand how that condensate yield reacts. I think we were very encouraged by the results of that over the last several months and have currently opened up a few other wells on that pad as well.

So, I fully would expect us to slightly tweak, I would say, expectations moving forward on new development in that area, probably somewhere in between, but certainly for us, something that will lean into a little bit more on the tight curve shape.

Carlo Escalante (Senior Associate)

Wonderful. Thank you, Matt.

My second question is regarding your cadence on your allocation to your different five operational areas. So you're very specific, obviously, in how you intend to allocate your capital this year. And it comes to attention that you're signaling on the Marcellus specifically is for eight drilled wells, and you're only turning in line four. However, when you signal to the market your aggregated inventory for Marcellus, you mentioned incremental two years, and that's based on a cadence of 25 wells, 20 wells, right?

So I wonder why you've decided to take the approach of signaling the Marcellus specifically this way when in reality, if I take 2025 as a proxy, your turn-in-line number is presumably less. And if so, is there a change in 2026 that we could expect to see, knowing that obviously you're monitoring the macro at all times?

Michael Hodges (EVP and CFO)

Yeah. Hey, Carlos, this is Michael. It's a good question. When we talk about inventory life, we like to frame everything in terms of corporate inventory life. So you're right. In the Marcellus, we have call it 50-65 locations. And on a corporate perspective, where we develop 20 wells-25 wells a year, that's two plus two and a half years of inventory. In that area specifically, though, we're looking to develop, like you mentioned, eight wells, drill eight wells this year, turn-in-line four.

There's all kinds of factors that go into that. Capital allocation being one of them. We have a new midstream partner in there. Of course, we've got those guys have to lay lines to our pads, and we've got to develop in a responsible and prudent way. And so in any given area, we're going to be developing at a different pace. And so rather than constantly talk about inventory in different windows and different manners, we just talk about it in terms of corporate inventory. But the reality is we'll be developing that Marcellus asset over the next, call it five to six to seven years, utilizing those locations that I just laid out. So two and a half years, I'd call it a corporate inventory, but yeah, certainly going to be in that area for longer than that.

Carlo Escalante (Senior Associate)

Wonderful. Thank you, guys.

Operator (participant)

Thank you.

Next question comes from the line of Brian Velie with Capital One Securities. Please go ahead.

Brian Velie (Energy Equity Analyst)

Good morning, everybody. Thanks for taking my questions. Just a quick one here. I'm trying to get a sense for TIL cadence throughout the year. I know that oil kind of starts to pick up really in earnest in second quarter. NGLs follow more in the third quarter. But it appears that from a footage standpoint, you're going to TIL a similar amount of footage in 2025 as you did in 2024 on the dry gas side. But we're seeing, of course, I assume it's the cadence of when those TILs come online on the dry gas side because it feels like there would be quite a bit of pent-up production on the gas side heading into pretty early 2026.

Is that something that, not to get too far ahead of ourselves with 2026 talk, but something that we should kind of think about heading into 2026? Or are those kind of in your back pocket for 2026 to determine how you want to bring those on?

John Reinhart (President and CEO)

Yeah, Brian, that's a great question. This is John. To your point with the turn-in-line cadence, generally speaking, with a front-loaded capital program, what you'll find is the production will increase throughout the year. Now, that does vary depending on what maturity and what types of wells you're bringing on. For instance, if you're bringing on a lot of dry gas wells, those generally have six to nine to 12-month plateau periods that certainly play in. If you're drilling liquids wells, they have a little bit shorter plateau period. But nonetheless, we try to optimize the timing of those to impact production.

You're going to necessarily see Q2, Q3, to your point, and even Q4 lead into a little bit stronger production profiles for those quarters, generally speaking. This particular year, the function of our Q1 volumes was simply just natural decline, quarter on quarter primarily. Then you'll see the cadence of that production tick up as you move throughout the year. I wouldn't really want to comment on 2026 yet simply because there's still a lot of optimization for the program to do yet. You're absolutely correct that we're positioning the company very well towards Q3, Q4 in a very constructive commodity environment for production levels.

Brian Velie (Energy Equity Analyst)

Okay. Thanks. I guess with that lever to grow there, the implication for capital efficiency that you've picked up in 2025, do you still see any remaining low-hanging fruit?

I mean, you can only complete for so many hours in a 24-hour day. You're pretty close to the cap, but is there anything else that maybe we could look forward to or hear more about as the year progresses?

John Reinhart (President and CEO)

No, I appreciate the question. I won't put Matt on the spot too much, but what I'll tell you is that the industry never ceases to amaze me on its continuous improvement. Things that we're doing now, we wouldn't have thought eight years ago on efficiencies that we could possibly do, and that's a function of just technologies available and just getting better at what we do on the ground, so I believe there's fundamentally always opportunity for efficiencies to grow.

But having said that, we're very proud of the accomplishments with the well cost and the efficiency reductions over the past couple of years because it's really added tremendous value to the fundamental core business. So I suspect there's more to come, probably more moderate gains versus these 10% and 20%ers that we're talking about. But these guys out in the field never cease to surprise me with some upside there. So certainly appreciate the question, and Matt's got his work cut out for him to continuously improve on this performance.

Brian Velie (Energy Equity Analyst)

Got it. Thank you very much for the call, John. We appreciate it.

John Reinhart (President and CEO)

Thanks a lot, Brian.

Operator (participant)

Thank you. Next question comes from the line of Noah Hungness with Bank of America. Please go ahead.

Noah Hungness (Equity Research Analyst)

Morning, everyone. I was just hoping for my first question, you guys could kind of walk me through slide six.

I think the main thing that really sticks out to us here is your ability to maintain your natural gas leverage through a constructive macro outlook while increasing liquids production. Are we kind of thinking about that the right way?

Michael Hodges (EVP and CFO)

Yeah, I think so. No, this is Michael. I mean, I think, again, this slide is really just an indication of the potential of the company over the next five years. So we've been pretty careful not to call it guidance because we allocate capital in a very dynamic fashion, as we've talked about. And so we may see liquids cuts change over the years. We may see us become a little more gas-weighted depending on where the macro goes.

But we take the midpoint of our current year guidance, and we run it out for five years, and we demonstrate that without any real aggressive assumptions, you can see that the business is capable of generating a tremendous amount of free cash flow over the next few years. So again, Matt's going to probably deliver better capital results, we hope, over time. And we think there's things we can do operationally to improve on the cash cost and potentially deliver better realizations on some of these numbers. But I think, yes, the answer to your question is this is, we think, a pretty compelling indication of what we're capable of.

Noah Hungness (Equity Research Analyst)

Great to hear. And then for my second question, I was just kind of hoping you guys could talk about what's underwriting your change in your NGL realizations. I saw it got bumped up quite a bit here.

Is that just because of the wells that you're turning in line this year?

Michael Hodges (EVP and CFO)

Yeah, that's a good question. So a couple of things there. First of all, I want to highlight that we have a really attractive barrel, especially in Appalachia. So our existing Utica production actually is part of a contract where we reject ethane. And so we've always had a strong barrel, I would call it there, just given the fact that that ethane component doesn't exist. We get a gas BTU uplift from the ethane value. And then as you've seen propane prices and butane prices both increase with some of the weather we've had and some of the other demand factors relative to WTI, that certainly pulls up on that % of WTI realization. And then lastly, we announced this morning our new Marcellus agreement.

And so we've been able to negotiate some favorable terms there as well, which again relate to ethane and will allow us to continue to have what we think is a differentiated NGL barrel versus what a typical Belvieu barrel looks like. So just a function of our marketing team's negotiations and some really good outcomes that we've seen in those areas.

Noah Hungness (Equity Research Analyst)

Great. Thanks so much.

Michael Hodges (EVP and CFO)

Thanks.

Operator (participant)

Thank you. As there are no further questions, ladies and gentlemen, we have reached the end of question and answer session. I would now like to turn the floor over to John Reinhart for closing comments.

John Reinhart (President and CEO)

Yep. Thank you for taking the time to join our call today. Should you have any questions, please don't hesitate to reach out to our investor relations team. We hope you have a great day. This concludes our call.

Operator (participant)

Thank you. This concludes today's teleconference.

You may disconnect your lines at this time. Thank you for your.