Mach Natural Resources LP Q4 FY2025 earnings call

• Strategic pillars:
  • Maximizing distributions: Distributed $1.3 billion since 2018, $5.67 per unit from 2024 start with 15% annualized yield, average cash return on capital invested >30% last five years, 23% in 2025.
  • Disciplined execution: Never acquired an asset by paying more than PDP PV10, accomplished 23 times, bought distressed areas that weren't actually distressed, like Sabinol purchase in 2025 when market thought oil prices below $50, but bought stable crude production in 60s. Hedging: 50% of production in year one and 25% in year two on rolling basis. Drilling shift: Moved from oil - dominated assets to dry gas locations in Deep Anadarko and San Juan in 2025, planning to bring back oil rig in Oswego and associated areas in second half of 2026 if crude prices elevated.
  • Disciplined reinvestment rate: Target reinvestment rate no more than 50% to maximize cash distribution while maintaining production and profitability. In 2026, anticipate slightly growing barrels of oil equivalent while maintaining reinvestment rate. Brought on three additional deep Anadarko locations since last earnings release, with estimated ultimate recovery in Deep Anadarko between 5 - 8 BCF per mile of lateral.
  • Maintain financial strength: Long - term goal debt to EBITDA ratio of one times. Currently not looking to make acquisitions unless fit within parameters, focus on paying down debt. Midstream systems are good for long - term cash flow and not inclined to sell them off.

For the quarter, production was 154,000 BOE per day, with 17% oil, 68% natural gas, and 15% NGLs. Total oil and gas revenues were $331 million, with oil contributing 42%, gas 44%, and NGLs 14%. Lease operating expenses were $106 million ($7.50 per BOE), cash G&A was $11 million ($0.77 per BOE). Year - end reserves more than doubled from 337 to 705 million barrels of oil equivalent, with additions from the development program exceeding 2025 production by 18%. In the Deep Anadarko, three additional locations were brought on, combining for approximately 40 million cubic feet of gas per day, with cost to drill and complete projected between $14 - $15 million per location. In the San Juan, plan to drill seven to eight dry gas main coast wells, with a three - mile horizontal lateral Mancos well projected to cost $15 million and recover approximately 24 BCF of reserves, aiming to lower drilling and completion costs to ~$13 million during 2026 drilling season.

• In 2026, plan to drill seven to eight dry gas main coast wells in San Juan, with drilling season from April 1st to end of November. Anticipate slightly growing barrels of oil equivalent while maintaining desired reinvestment rate. Adjusted EBITDA and operating cash flow details. Midstream profit guidance was raised by about 40% due to accounting treatment reclassing midstream operating expense to GP&T, capturing both components which offset and improve midstream operating profit.
  • If crude prices remain elevated, plan to bring back an oil rig in Oswego and associated oil areas in the last half of 2026.

Q: Tom, just a question. You mentioned about possibly bringing the additional rig at those to take advantage of higher oil. Just curious, are there other things? Is there a secondary activity? Are there other things that you're kind of deliberating to do that you could do to continue to take advantage of oil prices as well?

A: Yeah, Neil, I think right now we only look to if we have one rig running for the last half of the year, it's only going to spend about $25 million. I would love for prices to stay where they are. and give us a little more operating cash flow and maybe bring on another oil rig to drill some of the Red Fork locations that we had, or even the Southern Oklahoma assets that we've not yet been able to get to because of lower prices after making the flycatcher acquisition. So if we could, It all depends, you know, of staying within our 50% of operating cash flow. So as long as if our cash flow can move up a bit, we would put more, maybe a second rig in and out to be bringing on more oil if it's staying in the 70s. As you know, that during any time oil is up in the $70 range, we make more. very good rates of return and are competitive with our ICAV and deep end ARCO gas wells.

Q: Yeah, we're pretty much on the sidelines for M&A until we move down our debt. So we need to move from the 1.3 times leverage we have today down to a turn before we really start looking to bring on any more debt to make any acquisitions. So our focus is to pay down debt. And then we might be able to do that, though, by bringing in a partner in the deep end of ARCA. We'll see. We don't know yet. We're hopeful to do that. That also, if we did in the deep end ARCO, we'd be able to keep two rigs working and have just less working interest and still cut back our costs, remembering that we're going to spend over a couple hundred million dollars this year drilling wells there. So to answer your question directly, we're not really in the market looking and Really, we were never competitive for these larger transactions that are going on just because the amount of debt that it requires for us to be competitive. So what we can do is buy a larger transaction by using some equity and some debt. And we hope to be back in the market here this year as we pay down our debt.

Q: Tom, could you monetize midstream to get that debt down quicker?

A: Oh, we could, but then you just pay for it in the long run. So the midstream systems that we paid nothing for give us a good string of cash flow. And so I personally don't like to sell those off just because over the long term they're good for the company.

Q: In your prepared comments, you seem to highlight the desire to monetize assets across the portfolio that could be experiencing a re - rate in value based on the current macro environment. Could you place some parameters around the value of types of transactions that you're looking at just to, again, help us calibrate the type of opportunities that you have?

A: Yeah, I'd like to. I don't really know what size we're talking about because we haven't really negotiated anything. So what I'd love to do is pay down some debt. so that we can get back in the acquisition market without affecting our distributions. So obviously there are three ways that we can bring our debt down, which that EBITDA would be prices moving up. That's a simple way and it's happening now. And then along with that, you could cut your distributions back and pay down debt that way, which is not our preference, or we could sell some non - EBITDA generating assets. The Deep Anadarko is the only area that's not HPP and has leasehold that has some term on it. So it seems like the most likely place that we would sell some acreage. So, you know, the size, I can't really say. We'll know here very quickly, but it has to be significant or else we would just do it ourselves.

Q: Tom, just on the deep and a dark go, could you, I guess, frame where we are from an acreage position with that trend now?

A: Yeah, we're about 50,000 acres, which is all we want if we're not going to bring in a partner. We can effectively drill that out over the time of our term on the leasehold. So if we don't bring in a partner, we will not spend more in the second half of our leasehold on CAPEX. So the way we look at it is we'll either bring in a partner and have some additional acreage that we'll be putting on and drilling more wells over the course of the next five years, or we'll just stop where we are and drill out what we have.

Q: Maybe just shifting over to operations. I wanted to focus on your recent deep Anadarko and Mancos wells. With the benefit of a few at - bats in these formations, could you speak to how you performed against pre - drill expectations and some of the leverage you're planning to pull to drive lower completed well costs?

A: Yeah, the first few wells that we drilled in the deep Anadarko were better than anticipated. The last three, I think, are right on our top curve. So I would say it's performing as expected. The main coast is just better than expected. I think it's a world - class reservoir that has been too much money has been spent on drilling, completing wells there over the past. And we look forward to, I believe the main coast will be our highest rate of return project as soon as we lower some costs. And I'm confident that our team will be able to do that.

Q: Tom, I wanted to ask about the Oswego and I guess maybe two questions about the Oswego. First, I think you addressed this, but just to make it clear, what oil price would you need to see or do you need to see to make you want to go forward with that deal? rig in the back half of the year targeting the oily Oswego.

A: Yeah, I mean, even right now, the Oswego competes with the deep end ARCO from rates of return. So I think any time that you have oil above $70, we have rates of return well north of 50%. And that meets the requirement of having capital shipped to it. And what we should do in a market like that is to distribute out to all three, the Deep Andarco, the Mancos, and the Oswego. And that's what we're attempting to do.

Q: Right, and that's actually a good lead - in to my follow - up question, because that's one of the things that I noticed on your slide 14, is that you have some – there's a wider variance on those Ospiga wells, and something I know we've spoken about before. But I wondered if you could tell me your – these four – really fabulous wells on the left side of your skyline chart here. Are those all in the same section? And really what I'm getting at is, you know, is there room in the – are there sticks on the map for you to come in and lay some wells in the back half of 26 that are, you know, right alongside some of these four really fabulous ones?

A: Yeah, as in all things, they're a little more complex. So we're drilling inside of a field that has vulgular porosity and algal mounds, so you have different thicknesses. So wells even that are fairly close together can have different amounts of porosity that has either been drained or not drained. And in the past, what we've seen is that if you stay 660 feet apart, you really don't have interference across the play. But you just, you don't know until you drill a well. You can stay within the system and you can feel very comfortable that over the, that you're going to have some really good wells like this. And again, we probably should have showed the 24 drilling results because we had the same thing. We have wells that have three or 400% rates of return. and then others who might have just a 10% to 20% rates of return, but they can be right next to each other or they can be at different sections. So to answer your question, yes, we have many, many locations left to drill. I feel comfortable that they're going to be north of 50% rates of return. Once we get the program done, I can't tell you which ones are going to be 200%.

Q: I wanted to ask on your guidance, you included wider differentials on natural gas, and it seems like there's ample takeaway capacity in both the MidCon and San Juan, so can you talk about what caused you to make that change and What are you seeing in those local markets? And maybe tie that into how you're feeling about the gas macro in general.

A: I love gas macro in general, so I can start with there. We are seeing widening basis in the Andarco and the San Juan. So all we do is try to estimate from the past what we've seen and bring that in the future. Do I personally believe the San Juan, for example, is going to be wider going forward? I don't. I think the same reasons that you have – Warm weather in the west has caused bases to widen. And I think that as you have no hydro in the west, you'll see bases tighten over the course of the year. That's just anybody's guess, but that's mine. And then I think that the takeaway isn't an issue. So if you look back over five years in the San Juan, the production is the same. So it's not driven by oversupply to increase or loosen the basis. And the same way in the Antarctica. We're not seeing this from a supply perspective. So it's just weather for a fairly warm winter uh, that, that is a widened basis in my opinion.

Q: I wanted to ask on the Mancos, uh, I know you, you talked about the, uh, the well costs. Um, do you think you can drive those down with a different completion style? And I know you, you, uh, completed those three mile laterals, I think with less prop and per foot than, uh, what has been done there previously. I wanted to just see how those are performing now that you've had a little bit more time to look at them relative to the other wells in the play.

A: Yeah, they're the same. It's not a lack of profit either. We're still using 2,000 pounds a foot. It's just that others have been using more, which in my opinion, I don't think is needed. We could probably use less than we do, but we're going to save money is not only on how much profit we use but just the focus on saving just really looking at the best ways to transport sand and chemicals and and rig rig costs just the in in my opinion the the san juan over the course of time has been run by majors who spend too much money, and we need some independents in here to cut costs. No different than it would be if a major was trying to drill in the Anadarko Basin. They just can't do it as well as we can. So I think we'll save money just by watching what we do.

Q: The biggest change from your previous 26 guidance was the midstream profit where you all raised the guidance by about 40%. Can you sort of speak to what drove that significant of an improvement?

A: Yeah. Hey, John. This is Kent. You know, when we first came out with pro forma guidance, to capture the effects of the two transactions last year, ICAV and Sabinol, we didn't anticipate some accounting treatment on kind of our own throughput volumes through one of the plants on ICAV. And as a result of looking at Q4, a full quarter of results, we're seeing that there's some MOE, midstream operating expense, being reclassed to GP&T. So we've captured both components of that in the new guidance, and they're offsetting. But it does improve midstream operating profit.

Q: And then just one quick one for me following up. Are you all looking to take advantage, you know, right now of what we've seen on the oil move by adding more hedges? Are you all sort of like kind of waiting to see how this plays out?

A: Yeah. If you look at the back of the curve, really anything outside of the next three to six months, the curve falls off fairly quickly. So, no, we like to stay. I like having access to commodity movement. And so we don't want to be more than 50% hedged in year one and 25% in year two. and that we use that as mainly a mechanical hedge just to guarantee cash flows. But we, for example, if we had no debt like we did in 2023, we wouldn't have any hedges on it. So I want exposure to the curve.

Q: First question, I just kind of want to clarify that the current guidance, does that contemplate that shift to the Oswego rig in the second half, or is that just kind of, I guess, some optionality or some assessments that you guys will do over the next handful of months?

A: It did not.

Q: And for my follow - up, it looks like你 guys, I think, last call were planning some Fruitland coal wells. as well for 26. It looks like those have been removed. Is that just a function of the bullishness you guys have of the mancos or were there any other factors playing into that?

A: Yeah, both. I said seven to eight wells in the main coast. If we can pull in another well in the main coast, we'd like to do that. Our Fruitland Coal is a very good reservoir, consistent reservoir for us to drill. It will be easier next year in 2027 program to bring on more of those. And, again, it's all associated with how much operating cash flow we have. So the restriction to any of this, we have too many locations that are good and not enough operating cash flow.