Mach Natural Resources (MNR) Q2 2026 earnings call transcript

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?

Thank you, Darrell. Welcome to MACH NATURAL RESOURCES' second quarter earnings update. We reiterate the company's four strategic pillars that have guided us since our founding in 2017. These pillars are disciplined execution. We only purchase cash-flowing assets at a value of PDP, PB10, or less, and do not pay for any leasehold, PUDs, midstream, or infrastructure. The second pillar is disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow.

The third pillar is maintained financial strength. We're cognizant of the peril of too much debt. In order to capture the opportunity of acquiring assets in the San Juan and Central Basin platform, we strategically moved leverage above our goal of one-times-death EBITDA. This pillar is still standing. Therefore, it is important to move leverage back to our stated goal versus the 1.4 times we're projected to be at the end of the year. Outside of waiting to solve through increased pricing, we continue to look for assets at discounted prices to use our equity to purchase. These purchases need to be accreed to our cash available for distribution. We also have an at-the-market equity program to place $100 million of equity at prices that do not disturb trading.

And lastly, we can take a portion of our distribution and pay down debt. Our team is dedicated to meet our goal before the end of 2027. Once we achieve our goal, we will be in a position to take advantage of any downward movement in the market to make additional bargain purchases. The very reason to bring down debt during a period of exuberance is to be prepared to purchase in a time of want. This is the very essence of our company. The fourth pillar is to maximize distributions to unit holders. This pillar drives all of our decisions. We've distributed back $6.67 to our unit holders since 2024.

Very few public companies in this country have yields at MOC's level, and none of them are oil and gas producers. Yields like ours are usually only found at businesses carrying a lot of leverage that often can't sustain once credit tightens or rates move against them. MACH was built entirely different. Our distributions and the cash returns we deliver are second to none, and they're the result of the discipline behind our other three pillars. MACH was established around a cash return model. We've said many times that we had a belief for several years before forming the company that there would be a time when we could buy cash flowing assets that seldom hurt up prices by avoiding the tendency of the industry to look for growth through the drill bit.

Our goal is to buy distressed assets at discounted prices to throw off cash. We were fortunate to pick the timing correctly and build a large producing base at bargain prices. We continue to look for those types of assets, but it's become harder as more capital is now chasing the same type of cash-flowing assets that we propose to buy and are willing to pay premiums to our model. However, our steadfast approach to value is paid off by giving us a 50-year cash flow stream plus nearly 3 million acres of land that is held by production, and that holds our production flat by spending less than 50 percent of our operating cash flow.

Therefore, in times of excess capital provided by private equity and ABS companies, we can pivot to rely on drilling to sustain our model. All of our acquisitions have been made at a discount to the strip at the time of purchase. The timing of some of our acquisitions was quite spectacular, such as buying Alta Mesa through the 363 bankruptcy process in April of 2020. That purchase was made against a $20 oil strip and paid the first lien RBL lenders back less than $0.10 on the dollar.

That then made the lending institutions leery of investing in the MidCon and gave us a distal running room to acquire other assets at rock-bottom prices. The tide did not turn on the MidCon for lenders until 2024. There is now a wave of lending and equity providers chasing MidCon assets. As capital started to move back into the MIDCON, we've expanded to the San Juan and Central Basin platform of the Permian.

We were able to purchase the oil assets of Sabanol in the low 60s per barrel range, and also were able to purchase the natural gas assets of ICAV in the San Juan at less than PDP, PV10. Not only did we purchase the assets at discount prices, we also bought a stream of production in both cases that had less than a 10% decline. Sabanaw, in particular, gave us immediate cash flow benefits due to the rise in crude prices since the purchases.

Lastly, both have substantial drilling room left on the assets. MACH has a history of strong cash returns on capital invested and cash distributions. Over the past five years, we have delivered an industry-leading croquis averaging 35 percent. We are not only industry-leading, but also in the top 1% of all public companies in the U. S. We also have distributed an industry-leading distribution yield of 15% since 2024 through the first quarter of 2026. This performance was achieved through different pricing cycles, ranging from $94.23 per barrel in 2022, when we achieved a 53% croquis, We have been working with a CROQI to $64.81 per barrel in 2025 when our CROQI was 23%. Since our inception, we have never had a CROQI of less than 20%.

We cannot find another public company with such a strong record of cash returns. Our cash distribution policy has led to a yield of four times the pure average since 2024. As I mentioned, these returns were accomplished through disciplined acquisitions on top of the best-in-class break-evens in both natural gas drilling and liquid-weighted piers. Post the start of the conflict in Iran, we moved from drilling 100% natural gas wells to crude-heavy drilling. This is the same type of pivot that we made in April 2025 when post-tariff day we changed our drilling plans from all-weighted drilling, oil-weighted drilling, to natural gas. This is the luxury of having nearly 3 million acres of land that's held by production. Currently, we're drilling our last two wells in the Manco shell.

The completion phase of this year's drilling has been delayed until next year in order to stay within our internally mandated annual capex of 50 percent of operating cash flow. Given that restraint, it's more valuable for us to drill for oil rates of return versus natural gas in the last half of this year. We currently have three additional rigs running in Oklahoma. These are located in the Oswego, the Red Fork, and Ardmore Basin Sycamore. The Ardmore Basin locations will be completed by the end of Q3. We will defer drilling more Red Fork locations until Q1 of 27 and keep one rig in the Oswego during Q4 of 26. Our drilling schedule is very fluid. One of our hallmarks is the ability to change the product we drill for and the amount we spend very quickly.

MACH has a variable distribution to capture the changes in CAPEX associated with different drilling patterns. The pattern in 2026 has been to spend more CAPEX in Q2 and Q3 while drilling in the San Juan. The variable nature of our CAPEX reveals itself in our distribution. This quarter, we will distribute 36 cents per unit. Since we do not have fixed distributions, there's not any pressure to spend more than 50% of our operating cash flow on CAPEX. In other words, the cash flow dictates our pace of CapEx, not the lust for growth at any cost.

The clear workhorse as far as CapEx in our portfolio has been the Oswego limestone formation in Kingfisher County, Oklahoma. We have drilled more than 250 wells on this asset since 2021 and recently moved a rig back in the area to continue drilling once oil prices improved And we show in our presentation the Oswego carries a rate of return of 87 at a oil strip The key to the formation is not how much we find, but how much we spend. We're only looking for approximately 160,000 barrels of oil, but we'll spend only $3.3 million to drill and complete.

Cutting costs is the key to our business model. The newest field we have acquired that will also become a drilling workhorse is the Manco shell of the San Juan basin. Within the San Juan, we now hold 575,000 acres of land that only expires when production ceases. The key zone to elaborate on is the Manco shell. This zone is just now being expanded. Our Manco shell position represents one of the most compelling emerging natural gas opportunities in North America. The well-performance rivals that of the better-known Hainesville and Marcellus shale place, with operators recently reporting MACHOS initial production rates exceeding 25 million cubic feet of gas per day.

The MACHOS footprint is approximately one-third the size of the Marcellus and one-tenth the size of the Hainesville. However, MACHC controls the play with only three other sizable owners. We are the second largest producer of natural gas behind Hillcorp and also the second largest owner of acreage. The plant has increased more than 20-fold in the last five years and now exceeds 500 million QV of gas a day.

The San Juan also benefits from a mature natural gas transportation network developed over decades of conventional gas production. We expect over the next five years that additional takeaway capacity will be installed to get to premium gas markets of Arizona and the Pacific Coast LNG markets. This is much different than when the Marcellus and Haynesville were first being explored and there was no takeaway available, which required operators to take on large firm commitments with pipeline companies. We currently have a gas marketing agreement placed through 2030. Therefore, by the time the contract amortizes in 2030, we'll have strategic optionality for our 350 million cubic feet of natural gas that can be held flat by drilling only five net wells per year.

If we choose to increase activity to 10 net wells per year, we could grow MOCs from net production to more than 500 million cubic feet of gas per day. This is the benefit of buying low-declined cash-flowing assets that also have fantastic upside potential. The Mankos show us it has potential to dominate the mock story in the years to come.

As in the Oswego, the key to increasing rates of return in the Mankos is to lower costs. We believe that we could lower capex of a three-mile lateral from nearly $20 million to less than $15 million per well. Now that our drilling season is underway and we have four locations drilled, we expect the ongoing program to be in the $13 million range for a completed well.

I will now turn over the call to Kevin to discuss financial results. Thanks, Tom. For the quarter, our production of 149,000 BOE per day was 15% oil, 69% natural gas, and 16% NGLs. Our average realized prices were $95.40 per barrel of oil, $1.93 per MCF of gas, and $28.99 per barrel of NGLs. Of the $360 million total oil and gas revenues, the relative contribution for oil was 54%, 30% for gas, and 16% for NGLs. On the expense side, our lease operating expense was $98 million, or $7.21 per BOE. Dash G&A was approximately $7 million, or $0.54 per BOE. We ended the quarter with $41 million in cash and $270 million of availability under the credit facility.

Total revenues, including our hedges and midstream activities, totaled $406 million, adjusted EBITDA of $182 million and $154 million of operating cash flow. And our development capex for the quarter was $97 million for 63% of operating cash flow. Year-to-date, our development capex is right on top of 50% of our year-to-date operating cash flow. In the quarter, we generated $60 million of cash available for distribution, resulting in a distribution of $0.36 per unit, which will be paid on August 31st to holders of record on August 17th.

Darrell, I'll now turn the call back to you to open the line for questions.

Yeah, Neil, you're correct. The ongoing drilling program that we have through Q4 of this year is to keep an Oswego rig running. We have a lot of locations. The Sycamore locations in southern Oklahoma are the highest rates for return we have, but there's really only three of those left that we picked up through a couple of acquisitions in 2024. So the Oswego continues to be, as I mentioned, the workforce of our program, and we'll keep a rig, depending on pricing, but keep a rig there through 2027 also. So kind of a consistent rig running in the Oswego. If prices stay as they are, we'll move a rig back into the Red Fork next year, and that play has a little bit more running room with this also.

So those are kind of the two oil plays. We're yet to know where gas prices will be next year, but we do plan to have a program in the manco shell to drill and then complete the wells this year, assuming that gas prices are rebounding by next summer. Tom, does that Oswego compete with other more well-known oily plays in this kind of environment? Oh, you'd have to tell me. We have basically an 85% rate of return of $75 oil, so I think so.

And then if I could, just on capital allocation, could you remind me, you or Kevin, just on, you know, broad terms around your reinvestment rate and then how you intend to deploy the remainder of the cash flow?

Yeah, Neil, we said in those prepared remarks, we were right on top of 50% year to date. And, you know, that's one of our pillars to have that reinvestment rate of 50%. So we would expect to end the year at a similar number. I mean, it may have a little lumpiness quarter to quarter, but not much.

The operating cash flow drives what our cash capex is. So we're going to stay under 50% of operating cash flow. So as you can see, quarter to quarter, we'll either increase CapEx or decrease CapEx, depending on what operating cash flow is or prices.

Assuming you had the operating cash flow to do the MACHUS completions whenever you wanted, what is the price that you need to see in the San Juan basin market for you to pull the trigger and do those completions? Oh, it's not so much that we wouldn't do the completions. It's probably more that we wouldn't spend any CapEx if prices continued to be under $3. I think it would be difficult to have any gas program in the U. S. working. So if you think of the BCF per 1,000 that we see in the Mancos, it sits just under the Marcellus. I think we calculate the Marcellus at 1.9 BCF per 1,000 feet, the Mancos at 1.7, and the Hainesville at 1.6.

So if you're all three of those are going to be in line with the same types of production, And, you know, the San Juan has its difficulties of basis at times, but then other times it has very good basis, like today it sits on top of the MEDCON. So, yeah, I think that to have an ongoing drilling program for natural gas that competes with oil, so that our problem is that we only have a certain amount of operating cash flow and that goes to the highest rates of return And so going into next year what we have to look at is if the MACHs can compete against our oil reservoirs And we won't know that really until after we get through this winter.

As you know, Charles, I'm a little hesitant right now to be bullish natural gas. But as we come into full storage into the fall and are looking straight in the face of a strong El Nino winter, it's difficult to be real bullish about it. So we'll just evaluate as the year goes into next year.

I'm still very – I think most people are very bullish long-term natural gas. It's just how to get from here to there, and that's basically – it might be a next summer event before we really do much spending on natural gas capex. Right. As I look out over the longer-term period of five years, and you take that looking at our gas contract that we bought, amortizing that hedge out through 2030, we should be in perfect position to capture the demand that everyone sees coming. And I don't think Western Supply is going to keep up with that, and so ultimately I feel very good about our natural gas positions. It's just how much we spend in 27 might fluctuate.

I'm not aware of it, and I don't believe it's near any of our properties. And we're having any trouble even getting a clear fork location cleared, so I don't think we'll be doing the BMI.

What are the plans there now? Well, we don't have it in our drilling schedule yet. So right now, the clear forks, again, we were planning on it earlier in the year when we thought we'd add another rig. But as prices moved away from where they were, the Clear Fork was the first to be exited. So as of right now, we might get the locations in in 2027. It's just really more price dependent again where operating cash flow is. I mean, the luxury we have is we sit around on 3 million acres of land that's HVP, and we can pick and choose where we want to drill at the highest rates of return. And so it's just – I realize from being an analyst, it's hard to keep track of what we're trying to do, but it really can change month to month.

Ask Kent. He has to model it every month. I feel his pain.

What's the inventory like? And would they be vertical wells? Is it under water flood? Can you just give us a little bit more color on it? It is under a water flood, but we drill horizontal wells within a water flood, and I can kind of tell you. So the – and then there's only like eight locations, so it's not, you know, hundreds of locations. So we pick and choose around what we have, and when we buy additional land that comes up, it just happens to have some locations that can be drilled on it. But I guess if it all worked well, do you know how many, Rick, we've got?

It's for next year if it comes into the program. So like at the end of July, that's going to have a 53% rate of return compared to, you know, the Oswego in the 80s. So just if I had more operating cash flow, we'd drill it. That's kind of where the point is, I guess. It is a target worthy of drilling. It's just that we're going to stay below 50% of operating cash flow.

But still feeling that way, or do you feel compelled to pull back at all on the distribution or to do anything differently than what you're planning or have been planning historically?

Yeah, I mean, I think 2027 is a year that we need to get our leverage down, and I think our board is on board with that. So it's just basically we recognize that we are running a company today that at today's prices, looking at the end of the year, is 1.4 times leveraged, and we want to be at one times leverage. And if you think about that, the reason that we want to be at or below a turn of leverage is because we never know when something's going to happen.

Like, you know, in the next few months, it might be a really good time to be buying a natural gas asset. I'd like to have our leverage back down to a point that we can use some debt to make a purchase before bringing that leverage back down through the equity market. So, yeah, we want to be at a point that we're less leveraged. So, as I mentioned, we have an ATM program that doesn't really affect our trading that will lower our leverage. We can always cut our distribution some. We did that in 2024, I believe, or 2025, 2024, where we amortized some of our distribution to pay down debt.

Let's just say it's a focal point that I've talked about it now for nearly a year, I guess three quarters, and our leverage hasn't moved down yet. And so it's just time for us to get started here soon if we don't – what I'd love to do is find an acquisition that we could buy using equity. But there's just a lot of capital chasing a few deals right now.

We'll stay tuned on that.

Thank you, Ben.

As we sit here today, should we think about higher activity in oil through the first half and some degree of shift to gas in the second half as a starting point? I mean, you clearly have the flexibility as you voted today to lean into oil or gas, but just that's kind of what we're grappling with. Yeah, I think that's fair. I think that basically we don't have the activity in our gas asset next year will be the main coast.

So the activity would be that if we choose to spend money at 27 on natural gas, which right now we would plan on it, just assuming that prices pick up into the summertime, that we'd start our completion program sometime in late spring. Or the springtime, and then have a drilling program through the summer, and then complete all those wells come in line with each other.

And there it goes. So we haven't really worked on a 27 program yet. It's something that we're starting to work on now. So I think by the, you know, obviously by our next quarter call, we'll have a better understanding of where we at least would plan. We are not as easy to follow just because we can change both the amount we spend and on what asset we spend it on And it can happen very quickly I do understand but every time that we make a change it for a higher rate of return Understood completely, and we also appreciate that we can make changes in five minutes where it's going to take you guys quite a bit longer with the actual plans themselves.

Yeah, I'm scared of San Juan basis right now. Luckily, we're fairly well hedged with our San Juan gas, but it's just we go into right now we're sitting what San Juan and Midcon are sitting 20 cents under the hub. It just seems pretty tight. So I just I don't know where San Juan basis goes in the near term. I do believe that over a longer period of time, everything opens up. There's the Greenview pipeline that's being brought on by Tallgrass that's going to give us 2.5 BCF a day. I think that's what they're projecting to the Arizona Pacific Coast LNG markets coming in. And they project 29 or 30. I think that might be fast-tracked as demand is picking up.

So I think over time, the San Juan is going to be the key place for us. It's just we have to watch carefully what pricing is in order for our capex in the meantime. But as we just mentioned, in order to keep our production flat there, we only need five wells. So it is a tremendous amount of capital to keep our production flat, or it isn't the end of the world if we let it decline, if we're increasing our oil production at a higher price in other places. So we're going to be very flexible depending on what price gives us.

Tom, your comments on the Mancos well cost, I thought, were really interesting. I think you mentioned $20 million historically. You guys think you can get down to $13 million on this recent batch. I know in the past you talked about, like, adjusting the completion design was a key lever there, but it seems like there's a lot going on to get that kind of reduction. So I was just hoping to better understand what you guys are seeing there to drive that kind of cost improvement. Yeah, it's really more just getting services, having different types of like using wet sand versus dry sand, having being comfortable with a couple thousand pounds per foot of frack, which we used last year, and it works perfectly fine.

And learning a few drilling techniques, I mean, Rick could do a lot better job than me explaining it. All I can do is look at the results and see that we're going to be closer to $13 million than the $15 million we projected and the $20 million historically. So to me, the main coast is much like the Hainesville, is that the Hainesville started out with very high well costs. And over time, in their core area, they were able to bring those down and ultimately make the field have a rate of return.

And that's basically the story of the MACHO. We started out with incredibly high well costs in the field that are now being brought down.

Rick, do you want to mention anything about how costs are coming? As far as service costs, they're still in line, but we're optimizing our drilling performance and being able to get reduced over all days.

Drilling is the main thing we've been able to change. Bringing some new vendors in, obviously, has helped reduce costs as well.

Yeah, our savings have basically been both on drilling and completion, but the completion costs have really come down.

And my follow-up, given kind of the pace of development that you're laying out, Tom, you know, obviously focused on the oil side, assuming that kind of program remains static, would you guys anticipate oil production growth in 27? Is this more kind of a maintenance level of capital that we're at there, just trying to kind of triangulate where oil might go over the next, you know, handful of quarters? Yeah, I think it's difficult for us to have too much growth in any of our products, because basically we're only spending 50 percent of our cash flow to keep our production flattish. I think that overall, it's easier to grow a natural gas stream, especially if you're drilling 25 or 30 million a day manco swells.

But I'd say our projection at the 27 is basically keeping it flat.

I just wanted to go back to the balance sheet. I just had one here. Tom, you know, we see the same thing in our model that you do in yours at around 1.4 times a year end. And we do see sort of it kind of grinding down if you think about strip pricing into 2027, you know, kind of near spitting distance of one times at the end of the year.

So my question is, if it's such a pressing concern, and I appreciate you being candid about that, are you looking at asset sales? You have a vast acreage footprint. Are you looking at other things like, you know, getting someone to sort of farm into your acreage or some sort of carry? I'm just kind of curious kind of how broadly you're thinking about options to accelerate that deleveraging.

Yeah, so, I mean, selling assets are difficult because you're losing cash flow, and if you're – let's just say you're a little – not caring for the gas market in the near term, I hate to get rid of low-declined gas assets whenever I believe higher gas prices around the corner. And so the – and you really don't want to be selling your high-priced oil assets either. So to me, it's difficult to sell assets to manage for it, especially when we want to keep our declines low. So the – let's see. The second part of your question was what else were we thinking about? So that was the sell assets. What was your other question or point of it?

Yeah, I'm with you now. The problem with selling acreage is that you'd love to say it's non-core, but every acre we have today was non-core when we bought it. And yet if you look at our results, you see that we're in the top of the piers for gas and oil. And so if you look at any well that we've drilled since inception of the company, we didn't pay for. So that was by definition a non-core acre. And so whenever we plan to go sell a bunch of non-core acreage, you might be selling the next best field. And as Charles mentioned, we're not going to be the guy who goes out and drills the wildcat, but we're going to have 3 million acres kind of hanging around to look at whenever somebody else does.

And so today we have a lot of different companies, Muburn especially, is opening up areas that no one would have ever believed in the MidCon just a couple of years ago. You have Continental that stretches all the way from western Oklahoma to southern Oklahoma, drilling very good wells. And now the Diversified has the Camino asset. It's just a lot of activity with Flywheel and others in the Midcom. They're developing acreage that, if you would have asked me last year, we'd say was non-core, and if we were in that mode of selling it, we'd have given away the ability to have the high rates of return we do today. So that's a long-winded way to say I don't really like to sell acreage either.

And so that selling away your assets, to me, is not as efficient as if we were to cut a distribution a little.