Mach Natural Resources LP ($MNR)

Good morning, everyone. Thank you for joining us, and welcome to Mach Natural Resources Fourth Quarter 2025 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 could 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 to the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mach's website and the company's annual report on Form 10-K, which will also be available on their website or the SEC's 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 opened for questions. With that, I will turn the call over to Mr. Tom Ward. Tom?

Thank you, Rob. Welcome to Mach Natural Resources fourth quarter earnings update. Each quarter, we reiterate the company's 4 strategic pillars that have guided us since our founding in 2018. Since inception, the company has put a distinct emphasis on delivering exceptional cash returns through distributions. We have distributed back to our unitholders a total of $1.3 billion starting in the fourth quarter of 2018 after our first acquisition, showcasing our consistent and dependable nature across a variety of commodity cycles. We also have remained a consistent distributor of cash to our unitholders post our public offering. Mach has delivered distributions totaling $5.67 per unit from the beginning of 2024 through our last announced distribution of $0.53. This is an annualized yield of 15%. I doubt that you'll hear another energy company talk about cash returns. However, that is the lifeblood of our business and what makes us different. Additionally, we have delivered an average cash return on capital invested of greater than 30% over the last 5 years and 23% in 2025 during a down cycle. Clearly, one of the best records of all public equities, not just energy. Therefore, of our 4 pillars, maximizing distributions is the culmination of the other 3 and the most important. The second pillar is disciplined execution. Mach has never acquired an asset by paying more than PDP PV-10. In other words, all the blue sky of the company, the acreage, midstream, equipment, offices are part of our purchase price. We have accomplished this goal 23 times and do not see an end to the requirement. Through this method of deploying capital, we've been diligent in assembling a set of assets across the Mid-Con and San Juan Basin that have drilling opportunities that we did not have to pay for. Most of our contemporaries are willing to pay millions of dollars per location when they buy into fashionable areas. What we have done is to buy in at least 2 areas that were seen as distressed when actually they were not. Since 2018, we've spent $1.4 billion developing assets that others thought were worth zero while compiling acreage that now amounts to nearly 3 million acres. An additional luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash. Currently, both the Mid-Con and San Juan are seeing renewed outside investment searching for drilling rights. Also, the Deep Anadarko is the only place we've expended capital to lease land. The vast majority of our acreage is held by production from the purchases that we've made. We will test the market and see if we can recoup any of our costs for acreage seismic and other expenses associated with the Deep Anadarko. As I mentioned, the San Juan is also now very active with additional sales processes, which are paying for upside where we did not. However, our land in the San Juan is all held by production, and we are not in any hurry to sell there. We've done extremely well buying distressed properties then finding them not in distress sometime later. For example, the Sabinal purchase, which closed last September, was bought when the market was certain, we would see oil prices below $50. We believe that any time you can buy stable crude production in the 60s, you'll be rewarded at some point. This philosophy also drives our hedging decisions. We hedged 50% of our production in year 1 and 25% in year 2 on a rolling basis. We want to lock-in near-term cash flow while having exposure to higher prices in the future. We have a strong belief that our business will be critical to the world over the next few decades and prices will have the tendency to rise faster than the rate of inflation during this time. Our peers have moved to asset-backed securities to purchase production, which takes away future upside and introduces risk from higher prices rather than reward. During the last year, we've moved from drilling oil-dominated assets in the Oswego and condensate window of the STACK to dry gas locations in the Deep Anadarko and San Juan. Our reasoning is simple. The Bloomberg fair value price for West Texas Intermediate crude oil was $71.72 in 2024, that reduced to $57.42 in 2025. The Bloomberg fair value price for Henry Hub natural gas was $3.43 in 2024, that price improved to $4.42 in 2025. In 2026, our drilling is once again concentrating on drilling natural gas wells in the San Juan and Deep Anadarko through the first half of this year. However, we are now preparing to bring back an oil rig in the Oswego and associated oil areas in the last half of 2026 if crude prices remain elevated. As you can see in the presentation updated this morning, Oswego drilling program is very good. Since 2021, we've drilled and completed more than 250 Oswego locations, which have consistently had rates of return above 50%. We also have locations on the Red Fork, Sycamore and Osage that can be added to our drilling schedule. Therefore, we will plan to reduce the Deep Anadarko CapEx by moving from 2 rigs to 1 rig and bring back on the Oswego program if the market allows. The flexibility to choose which commodity to produce depending on the price is one of the hallmarks of our company. The third pillar to discuss is disciplined reinvestment rate. Our goal is to return as much cash to our unitholders as possible while staying within the guidelines for our strategic principles. We target a reinvestment rate of no more than 50% to maximize cash distribution while maintaining production and profitability. In 2026, we anticipate slightly growing our barrels of oil equivalent while maintaining our desired reinvestment rate. It's a task that is difficult to accomplish, especially with a set of assets at the time of purchase, we're not supposed to have any upside value. However, we have not only accomplished this over the past 8 years, but have thrived by drilling very high rates of return projects. In 2024, we projected our rate of return on drilling projects to be approximately 55%. In 2025, we made the move from oil to natural gas to maximize the rate of return in a difficult price environment. We succeeded by delivering rates of return of approximately 40%. Since our last earnings release, we have brought on production 3 additional Deep Anadarko locations. These 3 locations combined for approximately 40 million cubic feet of gas per day. In the Deep Anadarko, we anticipate an estimated ultimate recovery of approximately 19.5 Bcf or 6.5 Bcf per mile of lateral. We believe ranges will be between 5 to 8 Bcf per mile of lateral. The Deep Anadarko is located as a name implies at a true vertical depth of between 14,000 to 17,000 feet. Drilling an additional 15,000 feet of lateral projects make total depth between 29,000 to 32,000 feet. Our cost to drill and complete are projected to be between $14 million to $15 million per location. In the San Juan, we plan to drill 7 to 8 dry gas Mancos wells. The true vertical depth of the Mancos is approximately 7,000 feet and laterals are projected to be a mixture of 2 and 3 miles. A 3-mile horizontal lateral Mancos well is projected to cost $15 million and recover approximately 24 Bcf of reserves with a 60% first year decline. Our goal is to lower the drilling and completion cost to approximately $13 million during the 2026 drilling season. The drilling season starts on April 1 and runs through the end of November. The fourth pillar to discuss is to maintain financial strength. Our long-term goal is to have a debt-to-EBITDA ratio of 1x. When we're at that level of leverage, we start to look for additional acquisitions that fit the pillar of disciplined execution. This is a self-imposed guideline to provide financial strength in any commodity price environment. Keeping our leverage low also enables us to flex upwards as we did for the transformative IKAV and Sabinal acquisitions that closed in Q3 2025. By maintaining low leverage, we can toggle between drilling and acquisitions when opportunities arise in either direction. Currently, during a time when we're not looking to make an acquisition, we can maintain our production levels through drilling due to our low corporate decline of 17%. In other words, we do not have to make any acquisitions unless they fit within the parameters we have set to achieve our goal of maintaining production while deploying only 50% of our operating cash flow while sending home all of our excess cash. We continue to believe in the long-term value of oil and natural gas. Our acquisition strategy continues to achieve the results we desire. We believe in patience and resilience. Rushing and forcing outcomes may not yield the best results. It is often good to remind oneself to remain calm and persistent while waiting on our desired outcome. As the proverb says, good things come to those who wait. I'll turn the call over to Kevin to discuss financial results.

Thanks, Tom. 2025 year-end reserves capturing the results of 2025 drilling and acquisitions during the year more than doubled from 337 million to 705 million barrels of oil equivalent. Also worth noting the additions from the results of our development program exceeded the 2025 production by 18%. For the quarter, our production of 154,000 Boe per day was 17% oil, 68% natural gas and 15% NGLs. Our average realized prices were $58.14 per barrel of oil, $2.54 per Mcf of gas and $21.28 per barrel of NGLs. Of the $331 million in total oil and gas revenues, the relative contribution for oil was 42%, 44% for gas and 14% for NGLs. On the expense side, our lease operating expenses was $106 million for the quarter or $7.50 per Boe. Cash G&A for the quarter was $11 million or $0.77 per Boe. We ended the quarter with $43 million in cash and $338 million of availability under the credit facility. Total revenues, including our hedges, which contributed $42 million and midstream activities totaled $388 million. Adjusted EBITDA was $187 million and $169 million of operating cash flow and development CapEx of $77 million or 46% of our operating cash flow. Full year 2025 development costs of $252 million represented 47% of our operating cash flow. In the quarter, we generated $89 million of cash available for distribution, resulting in a distribution of $0.53 per unit, which was paid out yesterday. Rob, I'll turn the call back to you to open the line for questions.

[Operator Instructions] And our first question is from the line of Neal Dingmann with William Blair.

Tom, nice details this morning. Tom, just a question you mentioned about possibly bringing the additional rig at Oswego 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?

Yes, Neal, 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 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 very good rates of return and are compared -- are competitive with our IKAV and Deep Anadarko gas wells.

Great. Great details. And then just secondly, maybe a bit early on prices haven't been terribly high yet for just a couple of weeks. Have you seen anything in the M&A market? I mean, oftentimes, sometimes spreads start to widen when we see periods like this? Is it earlier, are you still seeing opportunities? Maybe just any generalities you can sort of comment around the M&A market?

We're pretty much on the sidelines for M&A until we move down our debt. So we need to move from the 1.3x 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 Anadarko. We'll see, we don't know yet. We're hopeful to do that. That also, if we did in the Deep Anadarko, we'd be able to keep 2 rigs working and have just less working interest and still cut back our costs, remembering that we're going to spend over a couple of 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 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 market here this year as we pay down our debt.

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

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.

Our next question is from the line of Derrick Whitfield with Texas Capital.

Great year-end update. 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 you're looking at just to, again, help us calibrate the type of opportunities that you have?

Yes, 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 3 ways that we can bring our debt down, which debt-to-EBITDA would be prices moving up that's a simple way, and it's happening now. And then along with that, you can 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 HBP and has leasehold to have some term on it. So it seems like the most likely place that we would sell some acreage. So the size, I can't really say. We'll know here very quickly, but I mean it has to be significant or else we would just do it ourselves.

And Tom, just on the Deep Anadarko, could you, I guess, frame where we are from an acreage position with that trend now?

Yes. We're about 50,000 acres, which is about -- is all we want if we're not going to bring in a partner. So 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 CapEx. So that's -- the way we look at it is we'll bring in a partner and have some additional acreage that we'll be putting on drilling more wells over the course of the next 5 years or we'll just stop where we are and drill out what we have.

Makes sense. And 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 levers you're planning to pull to drive lower completed well costs?

Yes. The first few wells that we drilled in the Deep Anadarko were better than anticipated. The last 3, I think, are right on our type curve. So that's -- I would say it's performing as expected. The Mancos is just better than expected. It's -- 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 Mancos 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. And just expanding on, there's just no reason that Mancos well at 7,000 feet and an easy shale target to drill should cost more than one of the most difficult wells to drill in the country in the Deep Anadarko. So I just don't believe it will.

Our next question comes from the line of Charles Meade with Johnson Rice.

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, you would need to -- what oil price would you need to see or do you need to see to make you want to go forward with that rig in the back half of the year, targeting the oil in Oswego?

Yes. I mean, right now the Oswego competes with the Deep Anadarko 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 3, the Deep Anadarko, the Mancos and the Oswego, and that's what we're attempting to do. And I think, Charles, to look at our -- I'm sorry, to look at our Oswego program and say what we can achieve. Just look at the difference between the -- if you look at an old presentation of ours, in 2024, we show every well we drilled. And then we show every well we drilled in 2025. And the Oswego wells are equivalent overall, but just a higher rate of return in 2024 due to pricing. And so that it's a very consistent. The wells are not consistent. There you have good wells and bad wells you do everywhere. But overall, you get a very consistent return.

Right. And that's actually a good lead into 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 Oswego wells and something I know we've spoken about before. But I wondered if you could tell me your -- these 4 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 -- 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, they're right alongside some of these 4 really fabulous ones?

Yes. As in all things are a little more complex. So we're drilling with -- inside of a field that has vugular porosity and alglemount, 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 300% or 400% rates of return and then others who might have just 10% to 20% rates of return. And -- but they can be right next to each other or they can be in 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% rate of return once we get the program done. I can't tell you which ones are going to be 200%.

The next question is from the line of Michael Scialla with Stephens.

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 Mid-Con 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?

I love gas macro in general. So I'll start with there. The -- we are seeing widening basis in the Anadarko and the San Juan. So we just -- all we do is try to estimate from the past what we've seen and bringing 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 reason that you have warm weather in the West has caused basis to widen. And I think that as you have no hydro in the West, you'll see basis tighten over the course of the year. That's just anybody's guess, but that's mine. And then I think the takeaway isn't an issue. So if you look back over 5 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 Anadarko. We're not seeing this from a supply perspective. So it's just a weather in for a fairly warm winter that has widened basis, in my opinion.

I appreciate that, Tom. And I wanted to ask on the Mancos. I know you talked about the well costs, you think you can drive those down with different completion style. And I know you completed those 3-mile laterals, I think, with less proppant per foot than 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.

Yes, they're the same. It's not a lack of property 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 can probably use less than we do. But we're going to save money is not only on how much proppant we use, but just to focus on saving just really looking at the best ways to transport sand and chemicals and rig costs, just the -- in my opinion, the San Juan over the course of time has been run by majors who spend too much money we need some independence 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 just -- we'll save money just by watching what we do.

The next questions are from the line of John Freeman with Raymond James.

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

John, this is Ken. When we first came out with pro forma guidance to capture the effects of the 2 transactions last year, IKAV and Sabinal, we didn't anticipate some accounting treatment on kind of our own throughput volumes through one of the plants on IKAV. 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.

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

Yes. If you look at the back of the curve, really anything outside of the next 3 to 6 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 1 and 25% in year 2. And that we use that as mainly a mechanical hedge just to guarantee cash flows. But we -- let's -- for example, if we had no debt like we did in 2023, we wouldn't have any hedges on. So I want exposure to the curve.

The next question is from the line of Jeff Grampp with Northland Capital Markets.

First question, I just kind of want to clarify 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?

It did not.

Okay. Perfect. And for my follow-up, it looks like the -- you guys, I think, last call, we're 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?

Yes, both. I said 7 to 8 wells in the Mancos. If we can pull in another well in the Mancos, 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.

Thank you. At this time, we've reached the end of our question-and-answer session, that will also conclude today's conference. We thank you for your participation. You may now disconnect your lines at this time, and have a wonderful day.

Thanks, Rob.