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 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 open for questions. With that, I'll 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 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 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 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. 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 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 three 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, 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 hedge 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 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 our 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 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 combined for approximately 40 million cu ft 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 5–8 Bcf per mile of lateral. The Deep Anadarko is located, as the name implies, at a true vertical depth of between 14,000–17,000 feet. Drilling an additional 15,000 feet of lateral projects make total depth between 29,000-32,000 feet. Our cost to drill and complete is projected to be between $14 million-$15 million per location. In the San Juan, we plan to drill 7–8 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 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 cost 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 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 MMBOE to 705 MMBOE . 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.
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 one from your telephone keypad, and a confirmation tone will indicate your line's in the question queue. You may press star two 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. Our first question is from the line of Neal Dingmann with William Blair. Please proceed with your question.
Morning, guys. Tom, nice details this morning. Tom, just a question. You mentioned about possibly bringing the additional rig to get those wells going to take advantage of higher oil. I was just curious, are there other things? Is there secondary activity? Are there other things that you're, you know, kind of , deliberating to do that you could do to continue to take advantage of oil prices as well?
Yeah, 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 gonna 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. If we could, it all depends, you know, on staying within our 50% of operating cash flow.
As long as 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's up in the $70 range, we make very good rates of return and are competitive with our IKAV and Deep Anadarko gas wells.
Great. Great details. Just secondly, maybe a bit early on, you know, prices haven't been terribly high yet for just a couple weeks. Do you see anything in the M&A market? I mean, oftentimes , sometimes, spreads start to to widen when we see periods like this. Is it early? Are you 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. 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. 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 two rigs working and have just less working interest and still cut back our costs, remembering that we're gonna spend over a couple hundred million dollars this year drilling wells there.
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. 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 longer run. The midstream systems that we paid nothing for give us a good string of cash flow. 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 Derrick Whitfield with Texas Capital. Please proceed with your questions.
Good morning, guys, and great year-end update.
Thanks, Derrick.
In your prepared comments, you seem to highlight the desire to monetize assets across a portfolio that could be experiencing a rerate 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. 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. Obviously , there are three ways that we can bring our debt down. Debt-to-EBITDA would be prices moving up, that's a simple way, and it's happening now. Then along with that, you could cut your distributions back and pay down debt that way, which is not our preference. We could sell some non-EBITDA generating assets.
The Deep Anadarko is the only area that's not HBP and has leasehold that has some term on it, so it seems like the most likely place that we would sell some acreage. You know, 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.
Tom, just on the Deep Anadarko, 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 gonna bring in a partner. We can effectively drill that out over the time of our term on the leasehold. If we don't bring in a partner, we will not spend more in the second half on of our leasehold on CapEx. That's , 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, you know, five years, or , we'll just stop where we are and drill out what we have.
Makes sense. Maybe just shifting over to operations, wanted to focus on your recent Deep Anadarko and Mancos wells. With the benefit of a few advances 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 type curve. I would say it's performing as expected. The Mancos is just better than expected. It's a world-class reservoir. Too much money has been spent on drilling and completing wells there over the past, and 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.
Perfect. Great update today, guys.
Thank you. Just expanding on it. There's just no reason that a Mancos well at 7,000 ft and an easy shell target to drill should cost more than the one of the most difficult wells to drill in the country , in the Deep Anadarko. I just don't believe it will.
Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your questions.
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 wanna go forward with that rig in the back half of the year, targeting the oil Oswego?
Yeah. I mean, even right now, the Oswego competes with the Deep Anadarko from rates of return. 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. What we should do in a market like that is to distribute out to all three, the Deep Anadarko, the Mancos, and the Oswego, and that's what we're attempting to do.
Got it. Thank you for that.
I think, Charles, to look at our Oswego pro.
Go ahead.
To look at our Oswego program and say what we can achieve, just look at the difference. 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. That
Right.
The wells are not consistent. They have good wells and bad wells as you do everywhere. Overall, you get a very consistent return.
Right. 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, you know. There's a wider variance on those Oswego wells. 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? Really what I'm getting at is, you know, is there room in the. You know, are there sticks on the map for you to come in and lay some wells in the back half of 2026 that they're, you know, right alongside some of these four really fabulous ones?
Yeah. It's as in all things are a little more complex. We're drilling within the inside of a field that has regular porosity and algal mounds, so you have different thicknesses. Wells, even they're fairly close together can have a different amounts of porosity that has either been drained or not drained. In the past, what we've seen is that if you stay 660 feet apart, you really don't have interference across the play. You don't know until you drill a well. You can stay within the system, and you can feel very comfortable that over that you're gonna have some really good wells like this. We probably should have showed the 24 drilling results 'cause we had the same thing.
We have wells that have 300% or 400% rates of return, and then others who might have just a 10%-20% rates of return. They can be right next to each other or they can be at different sections. To answer your question, yes, we have 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 gonna be 200%.
Got it. Thank you, Tom.
You bet.
The next question is from the line of Michael Scialla with Stephens. Please proceed with your questions.
Hi. Good morning. I wanted to ask on your guidance, you included wider differentials on natural gas. Excuse me, it seems like there's ample takeaway capacity in both the Mid-Con and San Juan. 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 Anadarko and the San Juan. All we do is try to estimate from the past what we've seen and bring that into 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 basis to widen. 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. I think , that the takeaway isn't an issue.
If you look back over five years in the San Juan, the production's the same. It's not driven by oversupply to increase or loosen the basis. The same way in the Anadarko. We're not seeing this from a supply perspective, so it's just a weather for a fairly warm winter that is widened basis in my opinion.
I appreciate that, Tom. Thanks. I wanted to ask on the Mancos. I know , you talked about the well costs. Do you think , you can drive those down with a different completion style? I know, you completed those three-mile laterals, I think, with less proppant per foot than what has been done there previously. 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 proppant either. We're still using 2,000 lbs 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 gonna save money , is not only on how much proppant we use, but just the focus on saving, just really looking at the best ways to transport sand and chemicals and rig costs. Just, in my opinion, 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. 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 2026 guidance was the midstream profit where y'all raised the guidance by about 40%. Can you just sort of speak to what drove that significant of an improvement?
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, IKAV and Sabinal, we didn't anticipate some accounting treatment on kinda, our own throughput volumes through one of the plants on IKAV. As a result of looking at Q4, a full quarter of results, we're seeing that there's some LOE midstream operating expense being reclassed to GP&T. 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 color, Kent. Just one quick one from me following up. Are y'all looking to take advantage, you know, 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?
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. No, we like to stay. I like having access to commodity movement. We don't wanna be more than 50% hedged in year one and 25% in year two. That, we use that as mainly a mechanical hedge just to guarantee cash flows. For example, if we had no debt like we did in 2023, we wouldn't have any hedges on. I want exposure to the curve.
Thanks, Tom. Appreciate it.
Thank you, Johnny.
The next question is from the line of Jeff Grampp with Northland Capital Markets. Just you with your questions.
Morning, guys. First question, I , just kinda, wanted 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. for my follow-up.
Thank you.
It looks like, you guys, I think , last call were planning some Fruitland coal wells as well for 2026. 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. So I'd say seven to eight 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'll, it will be easier next year in 2027 program to bring on more of those. Again, it's all associated with how much operating cash flow we have. 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.