Mach Natural Resources LP (MNR) Earnings Call Transcript & Summary

Good morning, everyone, and thank you for joining us, and welcome to Mach Natural Resources Second Quarter 2026 Earnings Call. 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 may 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 can cause actual results to differ from those in such forward-looking statements, please read the company's filings with the SEC. 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 and the most directly comparable GAAP measures, please reference the press release and supplemental tables, which are available on Mach's website and their 10-Q, which will be also available on their 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?

Thank you, Daryl. Welcome to Mach Natural Resources second quarter earnings update. We reiterate the company's 4 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 PV-10 or less that do not pay -- 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 to maintain 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 1x debt to EBITDA. This pillar is still standing. Therefore, it is important to move leverage back to our stated goal versus the 1.4x 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 accretive 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 unitholders. This pillar drives all of our decisions. We've distributed back $6.67 to our unitholders since 2024. Very few public companies in this country have yields at Mach'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 3 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 and sell them heard of 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 has 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% 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 Mid-Con and gave us additional running room to acquire other assets at rock bottom prices. The tide did not turn on the Mid-Con for lenders until 2024. There is now a wave of lending and equity providers chasing Mid-Con assets. As capital started to move back into the Mid-Con, we've expanded to the San Juan and Central Basin platform of the Permian. We were able to purchase the oil assets of Sabinal in the low 60s per barrel range and also we were able to purchase the natural gas assets of IKAV in the San Juan at less than PDP PV-10. Not only did we purchase the assets at discount prices, we also bought a stream of production in both cases that have less than a 10% decline. Sabinal, 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 5 years, we have delivered an industry-leading CROCI averaging 35%, 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% CROCI to $64.81 per barrel in 2025 when our CROCI was 23%. Since our inception, we've never had a CROCI 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 4x the peer average since 2024. As I mentioned, these returns were accomplished through disciplined acquisitions on top of the best-in-class breakevens in both natural gas drilling and liquids-weighted peers. 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 of 2025 when post tariff Day, we changed our drilling plans from oil-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 2 wells in the Mancos Shale. 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% 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 3 additional rigs running in Oklahoma. These are located in the Oswego, the Red Fork, and Ardmore Basin in 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 1 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 $0.36 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 $75 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 Mancos Shale 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 Mancos Shale. This zone is just now being expanded. Our Mancos shale position represents one of the most compelling emerging natural gas opportunities in North America. The well performance rivals that of the better known Haynesville and Marcellus shale plays with operators recently reporting Mancos initial production rates exceeding 25 million cubic feet of gas per day. The Mancos footprint is approximately 1/3 the size of the Marcellus and 1/10 the size of the Haynesville. However, Mach controls the play with only 3 other sizable owners. We are the second largest producer of natural gas behind Hilcorp and also the second largest owner of acreage. The play has increased more than 20-fold in the last 5 years and now exceeds 500 million cubic feet 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 5 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 in place 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 5 net wells per year. If we choose to increase activity to 10 net wells per year, we could grow Mach's net production to more than 500 million cubic feet of gas per day. This is the benefit of buying low decline cash flowing assets that also have fantastic upside potential. Mancos Shale has potential to dominate the Mach story in the years to come. As in the Oswego, the key to increasing rates of return in the Mancos is to lower cost. We believe that we could lower CapEx of a 3-mile lateral from nearly $20 million to less than $15 million per well. Now that our drilling season is underway, and we have 4 locations drilled, we expect the ongoing program to be in the $13 million range for a completed well. I'll now turn over the call to Kevin to discuss the 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. Cash 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 or 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 31 to holders of record on August 17. Daryl, I'll now turn the call back to you to open the line for questions.

[Operator Instructions] Our first questions come from the line of Neal Dingmann with William Blair.

Tom, my first question is just on your upcoming -- as you've kind of been moving the upcoming overall drilling program. Can you remind me, I think is just double checking most of your near-term D&C focus will be on the Oswego. And if so, could you just remind us how much activity that will consist of and how you're thinking about the economics behind this play in this environment?

Yes, Neal, you're correct. The ongoing drilling program that we have through Q4 of this year is to keep an Oswego rig running. We just have -- we have a lot of locations. The Sycamore locations in Southern Oklahoma are the highest rates of return we have, but there's really only 3 of those left that we picked up through the -- a couple of acquisitions in 2024. So the Oswego is -- continues to be, as I mentioned, the workhorse 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 with 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 2 oil plays. We're yet to know where gas prices will be next year, but we do plan to have a program in the Mancos Shale 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?

You'd have to tell me. We have basically an 85% rate of return at $75 oil. So I think so.

Got it. And then if I could, just on capital allocation, could you remind me you or Kevin, just on broad terms, what -- around your reinvestment rate and then how you intend to deploy the remainder of the cash flow, I think it's pretty straightforward what you all are doing.

Yes, Neal, we -- as I said in the prepared remarks, we were right on top of 50% year-to-date. And 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.

And Neal, the operating cash flow drives what our 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.

Our next questions come from the line of Charles Meade with Johnson Rice.

Tom, I'd like to pick up on that last point. Assuming you had the operating cash flow to do the Mancos 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?

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 kind 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 Bcf, and the Haynesville at 1.6 Bcf. So if you're -- all 3 of those are going to be in line with the same types of production. 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 Mid-Con. So I think that to have an ongoing drilling program for natural gas that competes with oil. So 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 Mancos 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, that it's difficult to be real bullish about it. But the -- 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. As we look out over -- sorry, as I look out over the longer-term period, 5-years. And so -- and you take that looking with our gas contract that we bought amortizing that hedge out through 2030, we should be in a 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 that ultimately, I feel very good about our natural gas positions. It's just how much we spend in '27 might fluctuate.

Right, Tom. I appreciate your comments. It's -- you can be a natural gas bull, but at the same time, be honest about what the next few months look like. Separate -- or second question, I wanted to ask about the Central Basin platform. I actually heard from another company recently about a so-called BMW play, Barnett, Mississippi and Woodford in the Central Basin Platform. And I don't think it's your style to go be a pioneer on a play like that. But I'm curious if you're aware of it and if it's happening near some of your acreage perhaps in Gaines and Andrews.

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 the Clearfork location cleared. So I don't think we'll be doing the BMI.

Our next questions come from the line of Michael Scialla with Stephens.

I want to start with your last comment there, Tom, on the Clearfork. What are the plans there now?

Well, we don't have it in our drilling schedule yet. So right now, the Clearfork -- again, it was -- 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 Clearfork 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 our operating cash flow is. I mean the luxury we have is we sit around on 3 million acres of land that's HBP, and we can pick and choose when we want to drill 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 asked to model it every month.

I feel his pain. I guess just to get a little bit more color on the Clearfork. It sounds like it doesn't compete today with the Oswego. Can you just describe what the opportunity set is there? What's the inventory like? And is this -- would there be vertical wells? Is it under waterflood? Can you just give us a little bit more color on it?

It is under a waterflood, but we drill horizontal wells within a waterflood. And I can kind of tell you, so the -- and there's only like 8 locations. So it's not 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. I guess if it all worked well, you know how many rigs that we've got is 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 the Oswego in the 80s. So just -- if I had more operating cash flow, we 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.

Understood. I wanted to ask on the balance sheet. I think last quarter, you said you kind of anticipate as you move forward, leverage will move down naturally just given where -- especially where oil prices are. But are you 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?