Mach Natural Resources LP (NYSE:MNR) Q2 2025 Earnings Call Transcript

Mach Natural Resources LP (NYSE:MNR) Q2 2025 Earnings Call Transcript August 9, 2025

Operator: Good morning, everyone. Thank you for joining today’s call to discuss Mach Natural Resources’ Second Quarter 2025 Financial and Operational Results. During this morning’s call, the speakers will be making forward-looking statements that cannot be confirmed by reference to existing information, including statements regarding expectations, projections, future performance and the assumptions underlying such statements. Please note, a number of factors will cause actual results to differ materially from their forward-looking statements, including the factors identified and discussed in their press release and in other SEC filings. For a further discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements, please read the company’s annual report on Form 10-K, which is available on the company’s website or the SEC’s website.

Please recognize that except as required by law, they undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. They may refer to some non-GAAP financial measures in today’s discussion. For reconciliation from non-GAAP financial measures to the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mach’s website and their 10-Q, which will also be available on the website when filed. Today’s speakers are Tom Ward, CEO; and Kevin White, CFO. Tom will give an introduction and overview, Kevin will discuss Mach’s financial results, and then the call will be open for questions. With that, I will turn the call over to Mr. Tom Ward.

Tom?

Tom L. Ward: Thank you, Shamali. Welcome to Mach Natural Resources’ second quarter earnings update. Each quarter, it is important to reiterate the company’s 4 strategic pillars. These are: number one, maintain financial strength. Our goal is to have a long-term debt to EBITDA ratio of 1x leverage. We believe maintaining a turn of leverage is appropriate to give ourselves opportunities when markets experience high volatility. We accomplished the IKAV and Sabinal purchases by having low leverage. Sabinal provides us with long-term upside potential to oil markets priced in the low 60s. We feel this price is not sustainable very far into the future and that ultimately, crude prices will rise even if the near-term outlook is negative.

If the OPEC + announcement of bumper oil supply increases comes to pass, we want to stay in a position to capitalize on more crude oil purchases. In the case of IKAV, we purchased an existing natural gas cash flow stream that is heavily hedged with tremendous upside to market demand in the future and nearly unlimited growth opportunities in the San Juan Basin. Both acquisitions were made because our balance sheet was in pristine condition. We also see headwinds ahead for the natural gas prices as we enter the winter season with full storage and growing supply along with additional takeaway capacity being added before further demand develops in 2026. Therefore, we see continued opportunity to add to our portfolio as long as we maintain our leverage goals.

Number two, disciplined execution. We acquire only cash flowing assets at a discount to PDP PV-10 that are also accretive to our distribution. We now have initiated 24 acquisitions, spending more than $3 billion. In every case, we have maintained this execution strategy. This strategy has allowed us to build an acreage base that will be nearly 3 million acres in size with multiple areas that have high rates of return drilling locations that are held by production. We believe that Mach is unique in this regard. Number three, disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. By keeping our reinvestment rate low, we optimize our distribution to unitholders. Mach is also unique in being able to maintain our production with an industry-leading reinvestment rate due to emphasizing our second pillar of disciplined execution.

Our entry in the San Juan and Permian Basins will move our decline to 15% from 20% through buying low decline cash flowing assets. This allows us to enhance our operating cash flow and maintain our production during periods of low prices, while looking for areas to purchase if markets become destabilized. However, during periods of high prices, we can use our enhanced cash flow to reinvest more in drilling and grow production during those periods. Mach is positioned well to thrive in both scenarios by being able to pivot from acquisitions during higher prices to drilling of high- return locations that are waiting for us with no expiration dates. The IKAV acquisition is an example of this. In the San Juan, we are acquiring more than 500,000 acres of land that is held by production.

If natural gas prices remain elevated, we can switch away from drilling crude oil locations to more natural gas-focused sites. We are planning to implement this strategy in 2026 by using the spring and summer drilling season with 3 rigs searching for natural gas in San Juan drilling for the Mancos Shale dry gas and the Fruitland coal. At today’s strip, we plan to maintain our production volumes through 2027, while spending less than 50% of our operating cash flow and using some of the excess to pay down debt. We project increasing our natural gas volumes to 70% post the Sabinal and IKAV acquisitions, and for the first time since our inception, project natural gas to be at least 50% of our revenue stream starting in 2026. All of the main pillars lead to the fourth and most important, delivering industry-leading cash returns on capital invested through distributions to our unitholders.

With our announced distribution of $0.38 per unit in the second quarter, we have set back $4.87 per unit to our unitholders since our public offering in October 2023 and more than $1.2 billion in total since inception in 2018. All the while, we would have — we have grown our business to more than $3.5 billion of enterprise value without selling any material assets while maintaining a cash return on capital invested more than 30% per year over the past 5 years. Even in this year, with crude prices moving down, we are expecting to have a 25% return on capital invested and have never been less than 20% since our company was founded. Post the IKAV and Sabinal acquisitions, we anticipate having leverage just above 1x. However, we’ll work diligently to bring back our leverage to our desired goal by presenting a clear path of reducing our debt levels.

We will resist the opportunity to acquire other assets that would lead to moving our leverage higher. Our goal is to continue to look for free cash flowing assets where private equity backed sponsors need to move towards a more liquid currency by taking our equity. In these circumstances, we see the opportunity to increase our operating cash flow while expanding our drilling budget on our vast acreage. We also continue to be able to purchase small acquisitions in the Mid-Con that fit our goals by using cash on hand. By sticking to our model of reinvesting only 50% of our cash flow, we can keep our production flat to slightly growing while expanding our distributions per unit. Our drilling plans for 2026 revolve around adding to our natural gas mix.

We currently plan to have 2 deep Anadarko dry gas rigs running. These locations are targeting natural gas of a depth of approximately 15,000 feet true vertical depth. We then project to drill 50 — another 15,000 feet of horizontal length. These drills will cost approximately $14 million and find between 15 to 20 Bcf of gas and have returns in excess of 50% at today’s crisis. We’ll also focus on the San Juan during the summer drilling season. In the San Juan, we plan to have 3 rigs running in 2026. The Mancos dry gas play is targeting 3-mile laterals at a true vertical depth of approximately 7,000 feet. We plan to spend approximately $15 million to $16 million per location to find 15 to 20 Bcf of gas and have a return of greater than 50%. The deep Anadarko and the San Juan gas plays are just developing.

Both are known to be prolific gas areas that have not been extensively drilled since the onset of enhanced drilling procedures with large stimulations due to the previous decade of low natural gas prices. Mach has hundreds of thousands of acres across the place to review and bring to market with no time pressure to be implemented without losing our acreage. We also plan to have 1 drilling rig drilling in the Fruitland coal. This development is ongoing in the San Juan with rigs targeting the coal between older vertical wells by drilling multiple laterals from 1 wellbore. The target is shallow at 2,000 feet, and we anticipate having 5,000 to 8,000 feet of lateral in each wellbore. These locations are expected to cost approximately $3 million and have returns in excess of 50%.

Lastly, we plan to move back into the Oswego to continue our drilling program that was started in 2021. We’ve drilled more than 250 wells in the Oswego where a 1.5-mile lateral cost less than $3 million. And even at today’s distressed oil pricing, has returned approaching 40%. Our second deep Anadarko rig is projected to spud in early September. The Oswego locations are projected to start in early 2026, and the San Juan rig should move in, in early spring 2026. Our focus on gas development through 2026 is driven not only by the current price environment, but also by how we see demand over the next 5 years. We see total demand growth of upwards of 25 Bcf of gas per day by 2030. This is broken down to the following: 15.6 Bcf per day of LNG feed gas growth.

This includes the facilities under construction in Mexico, which will be an additional outlet for U.S. production and our San Juan purchase is well positioned to meet West Coast demand. 6 Bcf a day per day and 6 Bcf per day of power generation growth is a conservative estimate, but it should be acknowledged that 2 to 4 Bcf of power generation growth will be from the data centers located in Texas, Colorado, the Desert Southwest and California. Thus, the San Juan acreage is also strategic and well positioned to meet this upcoming demand. 1.1 Bcf per day of demand growth from commercial and industrial and 1.4 Bcf a day of growth from exports to Mexico. We see supply of 6 Bcf a day from the Permian associated gas growth, which is at risk if prices remain soft.

15 Bcf per day of supply growth in the Haynesville and the Northeast in response to LNG and data center demand. This leaves the Eagle Ford, Mid-Con and San Juan Rockies as the natural supply growth areas to meet demand. We see the current processing capacity of approximately 4 Bcf a day in the San Juan and nearly 16 Bcf a day of Mid-Con to meet the ongoing demand requirements needed to fuel or enhance consumption of U.S. natural gas. During the quarter, Mach drilled 10 total wells consisting of 6 Oswego, 3 Woodford-Miss condensate and 1 Red Fork location. We’re currently drilling 1 Red Fork and 1 deep Anadarko dry gas well. These rigs are located in Dewey and Custer Counties, Oklahoma. In our Oswego program, we averaged 9,850 feet per lateral, our longest locations to date.

These locations averaged $3.6 million per well. Mach drilled 3 locations in the Woodford-Miss Program, including the [ Brockland 3MH ], which was drilled to a total depth of 30,384 feet. The [ Brockland 3MH ] is waiting on completion alongside the [ Brockland 2MH ], which is drilling currently. Both locations will be completed together starting later this month. In the Woodford-Miss condensate area, we drilled 2 locations that averaged 10,240 feet of horizontal section. Our operation goals for Q3 2025 were to continue to refine and reduce our days on location and our deep Anadarko drilling program while increasing our rig count from 1 to 2 starting in mid-September. We continue to keep our lease operating costs low at $6.52 per barrel and look forward to closing both the Sabinal and IKAV asset purchases to start to work on reducing costs.

We’re not certain there are additional places to cut LOE. However, in our previous 22 acquisitions, we reduced LOE by between 25% to 33% each. With that, I’ll turn the call over to Kevin for the financial results.

Kevin R. White: Thanks, Tom. For the quarter, our production of 84,000 BOE per day was 23% oil, 53% natural gas and 24% NGLs. Our average realized prices were $63.10 per barrel of oil, $281 per Mcf of gas and $22.41 per barrel of NGLs. Worth noting, pre-hedge realized prices were lower by 11%, 21% and 17% for oil, gas and NGLs compared to the first quarter of this year. Of the $219 million total oil and gas revenues, the relative contribution for oil was 51%, 31% for gas and 18% for NGLs. On the expense side, our lease operating expense totaled $50 million, as Tom mentioned, $6.52 per BOE. Cash G&A was only $7 million, $0.88 per BOE. We ended the quarter with $13.8 million in cash, and we had drawn million on our $750 million revolver.

In conjunction with our plan to close the IKAV and Sabinal acquisitions, we are in the latter stages of expanding our RBL and expect the borrowing base and commitments to nearly double from its current amount and to add a handful of new banks to the syndicate. Total revenues, including our hedges and midstream activities totaled to $289 million, adjusted EBITDA of $122 million and $130 million of operating cash flow. We had development CapEx of $64 million. During the quarter, we also had a reduction of cash available for distribution of $8.2 million due to a settlement of royalty owner legal dispute. We generated $46 million of cash available for distribution, resulting in improved distribution of $0.38 per unit, which will be paid out on September 4 to record holders as of August 21.

Shamali, I will now turn the call back to you to open the line for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Charles Meade with Johnson Rice.

Charles Arthur Meade: Tom, your production volumes were a little higher than I think — than I was looking for, and I think a lot of people on the Street were looking for. So I was wondering if you could tell me if there’s any — what part of the kind of legacy Mid-Con portfolio delivered — or maybe you can say it looks like a beat — it surprised us, was it a surprise to you? And what parts of the portfolio really had the strength? And was it perhaps related to some of these recent wells that you spoke about in your prepared comments?

Tom L. Ward: No, Charles, just normal operations that our production is doing well. We had a couple of bolt-on acquisitions that might have enhanced some of the production — but basically, the — there are — all areas already pretty well. We have a great operations team and continue to keep our locations working with a lot of workovers. So we just — I would say our operations team just does an excellent job focusing on business, but nothing out of the ordinary.

Charles Arthur Meade: Got it. Okay. And then, Tom, going back to the — you gave us a lot of detail in your prepared comments, and I was intrigued by this [ Brockland 3MH ] well. Is that one of the sort of the deep Anadarko targets that you were talking about earlier? The $14 million well cost, targeting 15 to 20 Bcf as in — maybe you can tell me if those 2 are connected and then maybe give us a time line for when you’re going to complete the [ Brockland ].

Tom L. Ward: Yes. We’re drilling the second location currently on a 2-well pad, we’ll do a zipper frac between the 2 locations that will start in later this month to early September.

Operator: Our next question comes from the line of Derrick Whitfield with Texas Pacific Land Corporation.

Derrick Lee Whitfield: For my first question, I wanted to focus on distribution this quarter. Despite the strength of operations, this quarter in production and Charles just covered that. There were a series of onetime events that led to a lower payout than the cash flow minus CapEx would imply. Could you perhaps add some color to those developments for the benefit of investors?

Tom L. Ward: Sure, Derrick. I think we’ve kind of narrowed it down for ease of digestion here. The legal settlement, again, it’s a fairly ordinary type of litigation, I guess, in our business that we see frequently. It’s not that ordinary for us, but we did reach a settlement with the royalty owner dispute on deductions that we were making from their revenue, and that our share of that settlement was roughly $8.2 million. So that reduced the distribution by $0.07 per unit. And then the second part of that, really, it comes down to gas prices. Lower gas prices this quarter, and I’m comparing this to the first quarter and also really where consensus is out there, results in another $0.07 reduction from — had we had prices similar to the first quarter or also kind of versus looking at the consensus analyst estimates that are out there.

And then I think maybe the Panhandle Eastern basis differential maybe was a little bit unique versus other basins across the country and that we had basis widened during the second quarter. And again, that may not have been — it kind of happened real time as we went through the quarter and probably wasn’t captured, I think, in a lot of analysts’ estimates of the quarter.

Derrick Lee Whitfield: Okay. Great. And then as my follow-up, I wanted to focus on your growth profile. As we layer in recent transactions and your deep Miss activity, we’re backing into a fairly material natural gas growth trajectory that could exceed 650 million cubic feet per day in 2026. And that’s quite a bit above consensus. Is that a fairly fair depiction of the production profile as you guys see it?

Tom L. Ward: Yes. So we see our natural gas product mix moving north of 70% in 2026 and closer to 75% in 2027. So yes, as we drill, that’s assuming we’d continue to have a robust natural gas market, which we do believe — even though we see near-term headwinds, we want to be long natural gas in late ’26 and ’27. Were very strong bulls. Just the amount of gas coming through the fill season this year leaves us in a precarious place, in my opinion, that we’ll be moving into the fall and winter season with full storage and a couple of new pipelines coming on ahead of demand. But once demand hits in 2026, then we do want to be long gas, which we’re just making — all that to say is we’re making an assumption, we’ll continue to drill natural gas wells and — but stand-alone right now without making other acquisitions. Yes, we see ourselves moving up from a product mix to substantially above 70% natural gas.

Derrick Lee Whitfield: We agree with your views, Tom. And maybe just one build on that, just for the benefit of clarity. When you look at your gas production base, you guys, as I understand, have quite a bit of that undedicated today, so you can materially steer that and benefit in a much higher gas price environment than some of your peers. Is that a fair depiction as well?

Tom L. Ward: Yes. I don’t know as compared to our peers, but we — yes, we do have a large amount on dedicated.

Operator: Our next question comes from the line of John Freeman with Raymond James.

John Christopher Freeman: When we look at the portfolio that you all built, which is anchored on these very stable, low-decline-rate assets, and now you’ve got this exciting opportunity with the Mancos as well as what’s emerging with the Anadarko deep gas. And I’m just interested in your thoughts on kind of how you balance those 2 aspects of your portfolio with kind of legacy proven, low-decline assets with now like this, an emerging growth play like the Mancos?

Tom L. Ward: John, you’re asking how we found them?

John Christopher Freeman: No, no, no, I’m sorry, just how you balance the portfolio between you’ve got these exciting growth plays that require, obviously, steeper decline rates, more capital, just sort of the development process of these emerging plays versus your stable, very low-decline- rate type assets that’s sort of been the foundation of the company.

Tom L. Ward: Yes. So it all just ties together with our reinvestment rate. So the — we want to spend 50%. We don’t want to spend 20% or 30% or 40%. We like to spend close to 50% of our operating cash flow that keeps our production flat. And the only way you can do that is to have that long life, the balanced portfolio, as you mentioned, of low-decline production that we’ve built over the years that then allows us to reinvest only 50% in the higher rates of return drilling that the Mancos now and the deep Anadarko, especially, and I guess the Fruitland coal is probably the best of the group as far as just infill drilling and rates of return. But whenever we put that all together, it just gives us a lot of flexibility. We can pivot from oil to gas.

We can move back to oil if prices change. We have 3 million acres of high-return drilling locations that we can choose from. So we’re in a really ideal situation that we built ourselves now down to a 15% decline that we can continue to grow our production using only 50% of reinvestment rate and choose what rates of return we want and have no real long-term contracts that keep us beholden to drill 1 particular area over the other. And we don’t have any lease expirations. So it — we truly are able to move around rigs as we want within 30 days.

John Christopher Freeman: That’s great. And then the gas differential kind of widened out a good bit this quarter that you all highlighted earlier. I believe you all have taken some kind of recent steps on kind of the gas marketing side to possibly improve that going forward. Maybe if you could just sort of elaborate on that? I don’t think so. I think that basically, we’re — we are at the mercy of Panhandle Eastern for most of our Mid-Con gas. And so if basis widens, our basis widens, we don’t hedge basis. Maybe — Kevin’s getting ready to say something. Do you want to take it?

Kevin R. White: Yes. Hey, John, we were talking a little bit about GP&T expense running a little higher due to new treatment of certain costs, certain marketing costs related to the Paloma wells. We had a marketing agreement with kind of a third-party intermediary, and we chose to get out of that agreement and fold in those volumes with kind of the bigger, larger group that we’ve marketed gas with for years.

Tom L. Ward: Yes. So we use NextEra. Right. And…

Kevin R. White: Yes, we’ll get better pricing with NextEra than we had with the previous intermediary.

Tom L. Ward: Yes. Okay. I didn’t know where you’re going with that. But yes, NextEra has been a good partner with us.

Operator: Our next question comes from the line of Michael Scialla with Stephens Inc.

Michael Stephen Scialla: I wanted to just talk about 2026. So I realize it all depends on where oil and gas prices go. But based on what you’re thinking right now, it sounds like the 3 rigs in the San Juan will drill spring time through summer. I think there’s a limited drilling window there. You keep the 2 deep rigs in the Anadarko and then one on the Oswego. Is that where your ’26 plans are preliminarily at the moment?

Tom L. Ward: Yes, as long as our operating cash flow holds up. So it all depends on pricing and where EBITDA is, but it could expand if prices move up and can contract if they don’t. So it is — the barometer for us on how much we spend is 50% of our operating cash flow. So it’s never written in stone that we’re going to have that development program. And it’s also subject to change if prices move, if gas prices move down and oil prices move up, that could also switch. So we are more difficult, I think, to monitor with exactly where our rigs are going to be because every month, we make a decision here, so I can’t tell you.

Michael Stephen Scialla: No, I appreciate how fluid that is and your flexibility, but I just want to get your latest thoughts based on…

Tom L. Ward: That is as of today and where our EBITDA sits today, this is exactly what we plan to do. And also permitting. San Juan’s not the easiest place to drill of the New Mexico side. You basically have May to December to have everything through. And so that has us kind of in the drilling season of May to September.

Michael Stephen Scialla: Okay. Got you. And then for the second half of this year, I think Sabinal had a rig running. And were there some wells there that — do you plan on going ahead and completing those on the Central Basin platform? Or do you kind of halt all the activity when you close the deal?

Tom L. Ward: Yes, they had 2 rigs running out of 4 locations that they’re waiting on completion that will complete once it’s — once we close.

Michael Stephen Scialla: Okay. Got it. And then…

Tom L. Ward: Also, IKAV would — should have basically 5 locations ready to complete at closing.

Michael Stephen Scialla: Right. Got it. And then I wanted to ask one more on the kind of unusual items for the quarter. It looked like, to us, we could have it wrong, that your GP&T costs kind of popped up for second quarter. Is that correct? Or anything unusual happened there?

Kevin R. White: Yes. Due to the marketing arrangement change that we mentioned, and that took place at the beginning of the second quarter, there’s essentially a reclass. I won’t bore you with the FASB number of the provision, but it’s a reclass of moving GP&T up and revenues also go up. So it is a kind of bottom line neutral impact, and it just has to do with wind title to the gas changes and it’s in association with this new marketing arrangement. So net-net, it’s kind of a zero-sum game, but in the individual categories of revenue and GP&T, they both went up by similar amounts.

Michael Stephen Scialla: Okay. I got it. So really, it was the gas price that was the — kind of the — maybe the difference between our estimates and some others, not — there’s really no change to what you’re thinking in terms of gathering and transportation cost?

Tom L. Ward: No. We’ll — and when we update guidance, when we close the acquisitions, that line item will change to reflect that new arrangement, but again, so will our basis differential up above.

Operator: Our next question comes from the line of Geoff Jay with Daniel Energy Partners.

Geoff Jay: Just a real quick one for me just to make sure I understand the activity changes, I mean, as she sits today. So the 3 rigs in the San Juan next year, are those all incremental? Or are there some kind of working now, I guess? And then in the Permian then, as I understand it, you are going to basically let the 2 rigs they have currently drop and go to 0 until you see a better drilling signal. Do I have that right?

Tom L. Ward: That’s correct. The San Juan currently has 1 rig that will be leaving shortly sometime in late August, early September, so let’s say, this month. And then we’ll be picking up, hopefully, 2 Mancos rigs and 1 to 2 Fruitland coal. Right now, we have a set up for 1, but I’d love to drill with 2. And then that — at today’s prices, that then would nudge out some of our oil locations. So that if all things were just fantastic, we would — we’d have 3 to 4 rigs. I’m just projecting 3 in the San Juan and 2 in the deep Anadarko drilling for gas and 1 rig that is looking Oswego oil just because it’s a steady, very low risk, good, oil-producing area with high rates of return, but they still don’t match the natural gas locations that we have today.

Geoff Jay: Now fine. That’s all for me.

Operator: Our next question comes from the line of [ Carey Messiano with Stifel ].

Unidentified Analyst: It’s kind of a bizarre one, but in terms of the acquisitions, was there any preference given to acquisitions that would take part cash and part units? Or would you guys have bought other properties? Or have you looked — did you look at other properties that wanted all cash, but the other properties wanted — would take both? Was there any consideration made for that?

Tom L. Ward: No, that’s — yes, they — we can’t do an acquisition of any size more than $300 million or $400 million that doesn’t require equity so the — anyone who would like to move from a private company into a more public liquid holding, they need to take equity if they’re of any size, especially anything over $400 million, for sure, that we can’t do with — and still then maintain our leverage ratios that we have to have in order to maintain our 4 pillars. So yes, the easy answer is, yes, the taking equity was a large part, in fact, the only reason we could do either of the acquisitions.

Unidentified Analyst: Okay. And did you look at any others that said they wanted all cash?

Tom L. Ward: We look at — yes, we look at a lot of throw-in bids with equity and get declined.

Unidentified Analyst: Okay. Yes. Okay. That’s fair. I was just wondering about that. Somebody had mentioned it to me that’s involved out there in Texas, and they said there was some other properties that wanted all cash or something in their opinion. But I just thought I’d run that by you guys. So that stands…

Tom L. Ward: Yes, any — you have to — so — I mean, the other thing to think about is that every seller has an opportunity. There’s plenty of competition to take all cash, so you have to believe, which I believe, it’s actually better to take our equity and ride along with a company that’s going to give you 15% to 20% distributions while you wait and look for a time that you want to exit. So to me, it’s — along with, if you have a belief that oil is going to be above $60 or $70 over time, gas prices are moving up in the future — why wouldn’t you take equity and instead of a cash offer that’s basically equal with where our equity offer is?

Unidentified Analyst: Yes. And I guess that just shows that these people that are selling do believe in what they’re selling, and they’re not just trying to take a buck and get out, but they are along for the ride. That’s a perfect way to couch it to the clients that I’ve got in this. So I appreciate that, Tom. I’ve been following you for years.

Operator: And ladies and gentlemen, we have reached the end of the question-and-answer session. And also, this concludes today’s conference. You may disconnect your lines at this time. We thank you for your participation. Have a great day.