Mach Natural Resources LP

Good morning, everyone. Thank you for joining us, and welcome to Mock 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 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 MOC'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 MOC's financial results, and then the call will be open for questions. With that, I'll turn the call over to Mr. Tom Ward. Tom?

Thank you, Rob. Welcome to Mock Natural Resources' fourth quarter earnings update. Each quarter, we reiterate the company's four 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 unit holders 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 unit holders post our public offering. Mock has delivered distributions totaling $5.67 per unit from the beginning of 2024 through our last announced distribution of 53 cents. 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 five 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 four pillars, maximizing distributions is the culmination of the other three and the most important. The second pillar is disciplined execution. MOC has never acquired an asset by paying more than PDP PV10. In other words, all of 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 MidCon 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 two 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. And the additional luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash. Currently, both the MidCon and San Juan are seeing renewed outside investment searching for drilling rights. Also, the deep end of Darko 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 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 Sabinol 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 had 50% of our production in year one and 25% in year two 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 Prize for West Texas Intermediate Crude Oil was $71.72 $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 End of Darko 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 will return above 50%. We also have locations in the Red Fork, Sycamore, and Osage that can be added to our drilling schedule. Therefore, we will plan to reduce the Deep Andarco capex by moving from two rigs to one 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 unit holders 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 that at the time of purchase were not supposed to have any upside value. However, we have not only accomplished this over the past eight 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 three additional deep anadarko locations. These three locations combine 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 the 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 to 32,000 feet. Our cost to drill and complete are projected to be between $14 to $15 million per location. In the San Juan, we plan to drill seven to eight dry gas main coast wells. The true vertical depth of the main coast is approximately 7,000 feet, and laterals are projected to be a mixture of two and three miles. A three-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 costs to approximately $13 million during the 2026 drilling season. The drilling season starts on April 1st 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 one times. 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 Transformity ICAV and Savinol 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 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, 254 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 53 cents per unit, which was paid out yesterday. Rob, I'll turn the call back to you to open the line for questions.

Thank you. We'll now be conducting a question and answer session. If you'd like to ask a question at this time, please press star 1 from your telephone keypad and the confirmation tone to indicate your line is in the question queue. You may press star 2 if you'd like to withdraw your question from the queue. For participants that are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please for our first question. Thank you, and our first question is from the line of Neil Dingman with William Blair. Please proceed with your questions.

Morning, guys. Tom, nice details this morning. 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?

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.

Great, great details. And then just secondly, maybe a bit early on, you know, 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, you're still seeing opportunities. Maybe just any generalities you can sort of comment around the M&A market.

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.

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

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. Thanks so much. Thank you.

Our next questions are from the line of Derek Whitfield with Texas Capital. Please receive three questions.

Good morning, guys, and great year-end update.

Thanks, Derek.

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?

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.

And 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?

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.

Makes sense. 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?

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.

Perfect. Great update to you guys.

Thank you. And just expanding on it, there's just no reason that a Mancos well at 7,000 feet and an easy shell target to drill should cost more than one of the most difficult wells to drill in the country, in the deep end of Darko. So I just don't believe it will.

Our next questions come from the line of Charles Mead with Johnson Rice. Please receive their question.

Good morning, Tom and Kevin and the rest of the team there. 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.

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. Got it. Thank you for that. And I think, Charles, 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. They have good wells and bad wells, as you do everywhere. But overall, you get a very consistent return.

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?

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%. Got it.

Thank you, Tom.

You bet.

The next question is from the line of Michael Scala with Stevens. Please receive your questions.

Hi, good morning. 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.

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.

I appreciate that, Tom. Thanks. 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.

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. Sounds good. Thank you, Tom.

Thank you. The next questions are from the line of John Freeman with Raymond James. Please proceed with your questions.

Thanks. Good morning. 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?

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.

Thanks for that, Keller, Kent. 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?

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.

Thanks, Tom. Appreciate it.

Thank you, John.

The next question is from the line of Jeff Gramp with Northland Capital Markets. Please proceed with your questions.

Good morning, guys. 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?

It did not.

Okay. Perfect. Thanks. And for my follow-up, it looks like you 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?

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.

Yeah, not a bad problem to have. I appreciate the time. Thank you. Thank you.

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.