Mach Natural Resources LP Aktie

Good morning, everyone, and thank you for joining us, and welcome to Mach Natural Resources Second Quarter 2026 Earnings Call.

During this morning's call, the speakers will be making forward-looking statements that cannot be confirmed by reference to existing information, including statements regarding expectations, projections, future performance and the assumptions underlying such statements. Please note, a number of factors may cause actual results to differ materially from their forward-looking statements, including the factors identified and discussed in their press release and in other SEC filings. For a further discussion of risks and uncertainties that can cause actual results to differ from those in such forward-looking statements, please read the company's filings with the SEC. Please recognize that except as required by law, they undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

They may refer to some non-GAAP financial measures in today's discussion. For reconciliation from non-GAAP financial measures and the most directly comparable GAAP measures, please reference the press release and supplemental tables, which are available on Mach's website and their 10-Q, which will be also available on their website when filed.

Today's speakers are Tom Ward, CEO; and Kevin White, CFO. Tom will give an introduction and overview. Kevin will discuss Mach's financial results, and then the call will be open for questions.

With that, I will turn the call over to Mr. Tom Ward. Tom?

Thank you, Daryl. Welcome to Mach Natural Resources second quarter earnings update. We reiterate the company's 4 strategic pillars that have guided us since our founding in 2017. These pillars are disciplined execution. We only purchase cash flowing assets at a value of PDP PV-10 or less that do not pay -- and do not pay for any leasehold PUDs, midstream, or infrastructure.

The second pillar is disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. The third pillar is to maintain financial strength. We're cognizant of the peril of too much debt. In order to capture the opportunity of acquiring assets in the San Juan and Central Basin platform, we strategically moved leverage above our goal of 1x debt to EBITDA. This pillar is still standing. Therefore, it is important to move leverage back to our stated goal versus the 1.4x we're projected to be at the end of the year.

Outside of waiting to solve through increased pricing, we continue to look for assets at discounted prices to use our equity to purchase. These purchases need to be accretive to our cash available for distribution. We also have an at-the-market equity program to place $100 million of equity at prices that do not disturb trading. And lastly, we can take a portion of our distribution and pay down debt. Our team is dedicated to meet our goal before the end of 2027.

Once we achieve our goal, we will be in a position to take advantage of any downward movement in the market to make additional bargain purchases. The very reason to bring down debt during a period of exuberance is to be prepared to purchase in a time of want. This is the very essence of our company.

The fourth pillar is to maximize distributions to unitholders. This pillar drives all of our decisions. We've distributed back $6.67 to our unitholders since 2024. Very few public companies in this country have yields at Mach's level, and none of them are oil and gas producers. Yields like ours are usually only found at businesses carrying a lot of leverage that often can't sustain once credit tightens or rates move against them. Mach was built entirely different. Our distributions and the cash returns we deliver are second to none, and they're the result of the discipline behind our other 3 pillars.

Mach was established around a cash return model. We've said many times that we had a belief for several years before forming the company that there would be a time when we could buy cash flowing assets and sell them heard of prices by avoiding the tendency of the industry to look for growth through the drill bit. Our goal is to buy distressed assets at discounted prices to throw off cash. We were fortunate to pick the timing correctly and build a large producing base at bargain prices. We continue to look for those types of assets, but it's become harder as more capital is now chasing the same type of cash flowing assets that we propose to buy and are willing to pay premiums to our model.

However, our steadfast approach to value has paid off by giving us a 50-year cash flow stream plus nearly 3 million acres of land that is held by production and that holds our production flat by spending less than 50% of our operating cash flow. Therefore, in times of excess capital provided by private equity and ABS companies, we can pivot to rely on drilling to sustain our model.

All of our acquisitions have been made at a discount to the strip at the time of purchase. The timing of some of our acquisitions was quite spectacular, such as buying Alta Mesa through the 363 bankruptcy process in April of 2020. That purchase was made against a $20 oil strip and paid the first lien RBL lenders back less than $0.10 on the dollar. That then made the lending institutions leery of investing in the Mid-Con and gave us additional running room to acquire other assets at rock bottom prices. The tide did not turn on the Mid-Con for lenders until 2024. There is now a wave of lending and equity providers chasing Mid-Con assets. As capital started to move back into the Mid-Con, we've expanded to the San Juan and Central Basin platform of the Permian. We were able to purchase the oil assets of Sabinal in the low 60s per barrel range and also we were able to purchase the natural gas assets of IKAV in the San Juan at less than PDP PV-10. Not only did we purchase the assets at discount prices, we also bought a stream of production in both cases that have less than a 10% decline. Sabinal, in particular, gave us immediate cash flow benefits due to the rise in crude prices since the purchases. Lastly, both have substantial drilling room left on the assets.

Mach has a history of strong cash returns on capital invested and cash distributions. Over the past 5 years, we have delivered an industry-leading CROCI averaging 35%, not only industry-leading, but also in the top 1% of all public companies in the U.S. We also have distributed an industry-leading distribution yield of 15% since 2024 through the first quarter of 2026. This performance was achieved through different pricing cycles ranging from $94.23 per barrel in 2022 when we achieved a 53% CROCI to $64.81 per barrel in 2025 when our CROCI was 23%. Since our inception, we've never had a CROCI of less than 20%. We cannot find another public company with such a strong record of cash returns.

Our cash distribution policy has led to a yield of 4x the peer average since 2024. As I mentioned, these returns were accomplished through disciplined acquisitions on top of the best-in-class breakevens in both natural gas drilling and liquids-weighted peers. Post the start of the conflict in Iran, we moved from drilling 100% natural gas wells to crude heavy drilling. This is the same type of pivot that we made in April of 2025 when post tariff Day, we changed our drilling plans from oil-weighted drilling -- oil-weighted drilling to natural gas. This is the luxury of having nearly 3 million acres of land that's held by production.

Currently, we're drilling our last 2 wells in the Mancos Shale. The completion phase of this year's drilling has been delayed until next year in order to stay within our internally mandated annual CapEx of 50% of operating cash flow. Given that restraint, it's more valuable for us to drill for oil rates of return versus natural gas in the last half of this year.

We currently have 3 additional rigs running in Oklahoma. These are located in the Oswego, the Red Fork, and Ardmore Basin in Sycamore. The Ardmore Basin locations will be completed by the end of Q3. We will defer drilling more Red Fork locations until Q1 of '27 and keep 1 rig in the Oswego during Q4 of '26. Our drilling schedule is very fluid. One of our hallmarks is the ability to change the product we drill for and the amount we spend very quickly.

Mach has a variable distribution to capture the changes in CapEx associated with different drilling patterns. The pattern in 2026 has been to spend more CapEx in Q2 and Q3 while drilling in the San Juan. The variable nature of our CapEx reveals itself in our distribution. This quarter, we will distribute $0.36 per unit. Since we do not have fixed distributions, there's not any pressure to spend more than 50% of our operating cash flow on CapEx. In other words, the cash flow dictates our pace of CapEx, not the lust for growth at any cost.

The clear workhorse as far as CapEx in our portfolio has been the Oswego limestone formation in Kingfisher County, Oklahoma. We have drilled more than 250 wells on this asset since 2021 and recently moved a rig back in the area to continue drilling once oil prices improved. And we show in our presentation, the Oswego carries a rate of return of 87% at a $75 oil strip. The key to the formation is not how much we find but how much we spend. We're only looking for approximately 160,000 barrels of oil, but we'll spend only $3.3 million to drill and complete.

Cutting costs is the key to our business model. The newest field we have acquired that will also become a drilling workhorse is the Mancos Shale of the San Juan Basin. Within the San Juan, we now hold 575,000 acres of land that only expires when production ceases. The key zone to elaborate on is the Mancos Shale. This zone is just now being expanded. Our Mancos shale position represents one of the most compelling emerging natural gas opportunities in North America. The well performance rivals that of the better known Haynesville and Marcellus shale plays with operators recently reporting Mancos initial production rates exceeding 25 million cubic feet of gas per day.

The Mancos footprint is approximately 1/3 the size of the Marcellus and 1/10 the size of the Haynesville. However, Mach controls the play with only 3 other sizable owners. We are the second largest producer of natural gas behind Hilcorp and also the second largest owner of acreage. The play has increased more than 20-fold in the last 5 years and now exceeds 500 million cubic feet of gas a day. The San Juan also benefits from a mature natural gas transportation network developed over decades of conventional gas production.

We expect over the next 5 years that additional takeaway capacity will be installed to get to premium gas markets of Arizona and the Pacific Coast LNG markets. This is much different than when the Marcellus and Haynesville were first being explored and there was no takeaway available, which required operators to take on large firm commitments with pipeline companies. We currently have a gas marketing agreement in place through 2030. Therefore, by the time the contract amortizes in 2030, we'll have strategic optionality for our 350 million cubic feet of natural gas that can be held flat by drilling only 5 net wells per year.

If we choose to increase activity to 10 net wells per year, we could grow Mach's net production to more than 500 million cubic feet of gas per day. This is the benefit of buying low decline cash flowing assets that also have fantastic upside potential. Mancos Shale has potential to dominate the Mach story in the years to come.

As in the Oswego, the key to increasing rates of return in the Mancos is to lower cost. We believe that we could lower CapEx of a 3-mile lateral from nearly $20 million to less than $15 million per well. Now that our drilling season is underway, and we have 4 locations drilled, we expect the ongoing program to be in the $13 million range for a completed well.

I'll now turn over the call to Kevin to discuss the financial results.

Thanks, Tom. For the quarter, our production of 149,000 BOE per day was 15% oil, 69% natural gas and 16% NGLs. Our average realized prices were $95.40 per barrel of oil, $1.93 per Mcf of gas and $28.99 per barrel of NGLs. Of the $360 million total oil and gas revenues, the relative contribution for oil was 54%, 30% for gas and 16% for NGLs.

On the expense side, our lease operating expense was $98 million or $7.21 per BOE. Cash G&A was approximately $7 million or $0.54 per BOE. We ended the quarter with $41 million in cash and $270 million of availability under the credit facility.

Total revenues, including our hedges and midstream activities totaled $406 million, adjusted EBITDA of $182 million and $154 million of operating cash flow, and our development CapEx for the quarter was $97 million or 63% of operating cash flow. Year-to-date, our development CapEx is right on top of 50% of our year-to-date operating cash flow. In the quarter, we generated $60 million of cash available for distribution, resulting in a distribution of $0.36 per unit, which will be paid on August 31 to holders of record on August 17.

Daryl, I'll now turn the call back to you to open the line for questions.

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

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

Yes, Neal, you're correct. The ongoing drilling program that we have through Q4 of this year is to keep an Oswego rig running. We just have -- we have a lot of locations. The Sycamore locations in Southern Oklahoma are the highest rates of return we have, but there's really only 3 of those left that we picked up through the -- a couple of acquisitions in 2024. So the Oswego is -- continues to be, as I mentioned, the workhorse of our program, and we'll keep a rig depending on pricing, but keep a rig there through 2027 also.

So kind of a consistent rig running in the Oswego with if prices stay as they are, we'll move a rig back into the Red Fork next year and that play has a little bit more running room with this also. So those are kind of the 2 oil plays. We're yet to know where gas prices will be next year, but we do plan to have a program in the Mancos Shale to drill and then complete the wells this year, assuming that gas prices are rebounding by next summer.

Tom does that Oswego compete with other more well-known oily plays in this kind of environment?

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

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

Yes, Neal, we -- as I said in the prepared remarks, we were right on top of 50% year-to-date. And that's one of our pillars to have that reinvestment rate of 50%. So we would expect to end the year at a similar number. I mean it may have a little lumpiness quarter-to-quarter, but not much.

And Neal, the operating cash flow drives what our CapEx is. So we're going to stay under 50% of operating cash flow. So as you can see quarter-to-quarter, we'll either increase CapEx or decrease CapEx depending on what operating cash flow is or prices.

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

Tom, I'd like to pick up on that last point. Assuming you had the operating cash flow to do the Mancos completions whenever you wanted, what is the price that you need to see in the San Juan Basin market for you to pull the trigger and do those completions?

It's not so much that we wouldn't do the completions. It's probably more that we wouldn't spend any CapEx if prices continued to be under $3, I think it would be difficult to have any gas program in the U.S. working. So if you think of kind of the Bcf per 1,000 that we see in the Mancos, it sits just under the Marcellus. I think we calculate the Marcellus at 1.9 Bcf per 1,000 feet, the Mancos at 1.7 Bcf, and the Haynesville at 1.6 Bcf. So if you're -- all 3 of those are going to be in line with the same types of production. The San Juan has its difficulties of basis at times, but then other times, it has very good basis like today, it sits on top of the Mid-Con.

So I think that to have an ongoing drilling program for natural gas that competes with oil. So our problem is that we only have a certain amount of operating cash flow and that goes to the highest rates of return. And so going into next year, what we have to look at is if the Mancos can compete against our oil reservoirs. And we won't know that really until after we get through this winter. As you know, Charles, I'm a little hesitant right now to be bullish natural gas. But as we come into full storage into the fall and are looking straight in the face of a strong El Nino winter, that it's difficult to be real bullish about it. But the -- so we'll just evaluate as the year goes into next year.

I'm still very -- I think most people are very bullish long-term natural gas. It's just how to get from here to there. And that's basically -- it might be a next summer event before we really do much spending on natural gas CapEx. As we look out over -- sorry, as I look out over the longer-term period, 5-years. And so -- and you take that looking with our gas contract that we bought amortizing that hedge out through 2030, we should be in a perfect position to capture the demand that everyone sees coming. And I don't think Western supply is going to keep up with that. And so that ultimately, I feel very good about our natural gas positions. It's just how much we spend in '27 might fluctuate.

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

I'm not aware of it, and I don't believe it's near any of our properties. And we're having any trouble even getting the Clearfork location cleared. So I don't think we'll be doing the BMI.

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

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

Well, we don't have it in our drilling schedule yet. So right now, the Clearfork -- again, it was -- we were planning on it earlier in the year when we thought we'd add another rig. But as prices moved away from where they were, the Clearfork was the first to be exited. So as of right now, we might get the locations in, in 2027. It's just really more price dependent again, where our operating cash flow is. I mean the luxury we have is we sit around on 3 million acres of land that's HBP, and we can pick and choose when we want to drill where we want to drill at the highest rates of return. And so it's just -- I realize from being an analyst, it's hard to keep track of what we're trying to do, but it really can change month-to-month, ask Kent, he asked to model it every month.

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

It is under a waterflood, but we drill horizontal wells within a waterflood. And I can kind of tell you, so the -- and there's only like 8 locations. So it's not hundreds of locations. So we pick and choose around what we have. And when we buy additional land that comes up, it just happens to have some locations that can be drilled on it. I guess if it all worked well, you know how many rigs that we've got is it's for next year if it comes into the program.

So like at the end of July, that's going to have a 53% rate of return compared to the Oswego in the 80s. So just -- if I had more operating cash flow, we drill it. That's kind of where the point is, I guess. It is a target worthy of drilling. It's just that we're going to stay below 50% of operating cash flow.

Understood. I wanted to ask on the balance sheet. I think last quarter, you said you kind of anticipate as you move forward, leverage will move down naturally just given where -- especially where oil prices are. But are you still feeling that way? Or do you feel compelled to pull back at all on the distribution or to do anything differently than what you're planning or have been planning historically?

Yes. I mean I think 2027 is a year that we need to get our leverage down. And that's -- I think our Board is on board with that. So it's just basically, we recognize that we are running a company today that at today's prices, looking at the end of the year is 1.4x levered, and we want to be at 1x leverage. And if you think about that, the reason that we want to be at or below a turn of leverage is because we never know when something is going to happen like in the next few months, it might be a really good time to be buying a natural gas asset. I'd like to have our leverage back down to a point that we can use some debt to make a purchase before bringing that leverage back down through the equity market.

So yes, we want to be at a point that we're less levered. So as I mentioned, we have an ATM program that doesn't really affect our trading that will lower our leverage. There's -- we can always cut our distribution some. We did that in 2024 I believe, or 2025 -- 2024, where we amortized some of our distribution to pay down debt. It's -- let's just say it's a focal point that I've talked about it now for nearly a year, I guess, 3 quarters, and our leverage hasn't moved down yet.

And so it's just -- it's time for us to get started here soon if we don't -- what I'd love to do is find an acquisition that we could buy using equity. And -- but there's just a lot of capital chasing a few deals right now.

Our next questions come from the line of Derrick Whitfield with Texas Capital.

I wanted to circle back on your earlier comments on natural gas as you see it today. While I realize you can't provide 2027 guidance, we and most of the Street likely have elevated gas-weighted CapEx for 2027, which inherently depresses your CAD at current strip. And I think what we're all grappling with is how to manage activity as the current pivot favors oil-weighted activity and production into 2027. As we sit here today, should we think about higher activity in oil through the first half and some degree of shift to gas in the second half as a starting point? I mean you clearly have the flexibility as you noted today to lean into oil or gas, but just that's kind of what we're grappling with....

Yes, I think that's fair. So I think that basically, we don't have any activity in our gas asset next year will be the Mancos. So the activity would be that if we choose to spend money in '27 on natural gas, which right now, we would plan on it, just assuming that prices pick up into the summertime that we'd start our completion program sometime in late spring or the spring time and then have a drilling program through the summer and then complete all those wells come in line with each other.

That makes sense. And then...

Derrick, so we haven't really worked on a '27 program yet. It's something that we're starting to work on now. So I think by the -- obviously, by our next quarter call, we'll have a better understanding of where we -- at least we plan to have our CapEx. And it is -- it's -- we aren't as easy to follow just because we change -- we can change both the amount we spend and on what asset we spend it on, and it can happen very quickly. And so I do understand. But every time that we make a change, it's for a higher rate of return.

Understood completely. And we also appreciate that we can make changes in 5 minutes where it's going to take you guys quite a bit longer with the actual plans themselves. So we appreciate it again, just trying to kind of work through that because at the end of the day, we should be solving for higher CAD. It just means it might counter depending on where we are with oil and gas at any point in time. But maybe staying on gas, but going down a different path. With the addition of several large pipelines in the Permian, including the Hugh Brinson and Blackcomb this year, how are you guys thinking about the outlook for San Juan basis going into next year?

Yes. I'm scared of San Juan basis right now. Luckily, we're fairly well hedged with our San Juan gas, but it's -- as we go into -- right now, we're sitting what -- San Juan and Mid-Con are sitting $0.20 under the hub. It just seems pretty tight. So I just -- I don't know where a San Juan basis goes in the near term. I do believe that over a longer period of time, that everything opens up. There's the GreenView pipeline that's being brought on by Tallgrass that's going to give us 2.5 Bcf a day. I think that's what they're projecting to the Arizona and Pacific North -- Pacific Coast LNG markets coming in. The project 29 or 30. I think that might be fast tracked as demand is picking up.

So I think over time, the San Juan is going to be the key place for us. It's just where we have to watch carefully what pricing is in order for our CapEx in the meantime. But as we just mentioned, in order to keep our production flat there, we only need 5 wells. So it is a tremendous amount of capital to keep our production flat or it isn't the end of the world if we let it decline if we're increasing our oil production at a higher price in other places. So we're going to be very flexible depending on what price gives us.

Our next questions come from the line of Jeff Grampp with Northland Capital Markets.

Tom, your comments on the Mancos well cost, I thought were really interesting. I think you mentioned $20 million historically. You guys think you can get down to $13 million on this recent batch. And I know in the past, you talked about like adjusting the completion design was a key lever there, but it seems like there's a lot going on to get that kind of reduction. So I was just hoping to better understand what you guys are seeing there to drive that kind of cost improvement.

Yes. It's really more just getting services, having different types, like using wet sand versus dry sand, having -- being comfortable with a couple of thousand pounds per foot of frac, which we used last year and it works perfectly fine. Learnings from a few drilling techniques, I mean, Rick could do a lot better job than me explaining it. All I can do is look at the results and see that we're going to be closer to $13 million than the $15 million we projected and the $20 million historically. So it's -- to me, the Mancos is much like the Haynesville is that the Haynesville started out with very high well costs and over time, in their core area, they were able to bring those down and ultimately make the field have a rate of return. And that's basically the story of the Mancos. We started out with incredibly high well costs in the field that are now being brought down.

Rick, do you want to mention anything about how costs are coming?

Yes. As far as service costs, they're still in line, but we're optimizing our drilling performance and being able to get reduced overall days drilling is the main thing we've been able to change. bringing some new vendors in, obviously, has helped reduce costs as well.

Yes. Our savings have basically been both on drilling and completion, but the completion costs have really come down.

Got it. I appreciate those details. And my follow-up, given kind of the pace of development that you're laying out, Tom, obviously focused on the oil side, assuming that kind of program remains static, would you guys anticipate oil production growth in '27? Is this more kind of a maintenance level of capital that were out there? Just trying to kind of triangulate where oil might go over the next handful of quarters.

Yes. I think it's difficult for us to have too much growth in any of our products because basically, we're only spending 50% of our cash flow to keep our production flattish. I think that overall, it's easier to grow a natural gas stream, especially if you're drilling 25 million or 30 million a day Mancos well but I'd say our production -- projection into '27 is basically keeping it flat.

Our next questions come from the line of Tim Rezvan with KeyBanc Capital Markets.

I just want to go back to the balance sheet. I just had one here. Tom, we see the same thing in our model that you do in yours at around 1.4x at year-end. We do see sort of a kind of grinding down if you think about strip pricing into 2027, kind of near spinning distance to 1x at the end of the year. So my question is, if it's such a pressing concern, and I appreciate you being candid about that, are you looking at asset sales? You have a vast acreage footprint. Are you looking at other things like getting someone to sort of farm your acreage or some sort of carry? Just kind of curious kind of how broadly you're thinking about options to accelerate that deleveraging.

Yes. So I mean, selling assets are difficult because you're losing cash flow. And if you're -- let's just say you're a little not carrying for the gas market in the near term, I hate to get rid of low decline gas assets whenever I believe higher gas prices around the corner. And so the -- and you really don't want to be selling your high-priced oil assets either. So to me, it's difficult to sell assets to manage for it, especially when we want to keep our declines low.

The -- let's see, the second part of your question was what else are we thinking about? So that was the sell assets. What was your other question or the point of it?

I just ask, are you looking to kind of get selling acreage to get some sort of carry...

Yes, I'm with you now. The problem with selling acreage is that it's -- you'd love to say it's noncore, but every acre we have today was noncore when we bought it. So -- and yet if you look at our results, you see that we're in the top of the peers for gas and oil. And so if you look at any well that we've drilled since inception of the company, we didn't pay for it. So that was, by definition, a noncore acre. And so whenever we plan to go sell a bunch of noncore acreage, you might be selling the next best field. So -- and as Charles mentioned, we're not going to be the guy who goes out and drills the Wildcat, but we're going to have 3 million acres kind of hanging around to be -- to look at whenever somebody else does.

And so today, we have a lot of different companies, Mewbourne especially, is opening up areas that no one would have ever believed in the Mid-Con just a couple of years ago. You have Continental that stretches all the way from Western Oklahoma to Southern Oklahoma drilling very good wells. And now the diversified as the Camino asset and just a lot of activity with flywheel and others in the Mid-Con that are developing acreage that if you would have asked me last year, we'd say it was noncore. And if we were in that mode of selling it, we'd have given away the ability to have the high rates of return we do today. So that's a long-winded way to say, I don't really like to sell acreage either. And so that selling away your assets to me is not as efficient as if we were to cut a distribution.

Okay. I guess there's trade-offs to everything.

Thank you. Ladies and gentlemen, we have reached the end of our question-and-answer session. And with that, I would like to bring the call to a close. We appreciate your participation today. You may disconnect your lines at this time, and have a great weekend.

Good morning, everyone, and thank you for joining us, and welcome to MACH Natural Resources First Quarter 2026 Earnings Call. During this morning's call, the speakers will be making forward-looking statements that cannot be confirmed by reference to existing information, including statements regarding expectations, projections, future performance and the assumptions underlying such statements.

Please note a number of factors may cause actual results to differ materially from their forward-looking statements, including the factors identified and discussed in our 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 their 10-Q, which will also be available on their website when filed. Today's speakers are Tom Ward, CEO; and Kevin White, CFO. Tom will give an introduction and overview. Kevin will discuss MACH's financial results, and then the call will be open for questions.

With that, I will turn the call over to Mr. Tom Ward. Tom?

Thank you, Daryl. Welcome to MACH Natural Resources first quarter earnings update. Each quarter, we reiterate the company's 4 strategic pillars that have guided us since our founding in 2017. The first pillar I will discuss is disciplined execution. We bought only free cash flowing assets at discounts to the producing properties PV-10. This allowed us to purchase producing assets without paying for any upside even though, over time, we have proven significant upside exists. Each year, MACH publishes every well we've drilled the overall IRR based on the year's price for oil and gas. We've averaged approximately 50% rates of return on drilling program since our program started in 2018.

Said another way, we've invested more than $1.3 billion of properties, so others would give no value to and recurrent excellent results. You can see that on Page 9 of our investor presentation, that our free cash flow breakeven pricing is best-in-class for both oil and natural gas. It is rare, if not unheard of, to be a leader in both. It would be difficult to duplicate what we have built. In 2017, we had a strong opinion that the market was entering a time of distress. We focused on buying free cash flow at valuations, most sellers would not even consider it first. We called it the stages of green.

Ultimately, we did not deal with management teams, but they're lenders. Either through fourth sales or the 363 bankruptcy process. We did not anticipate the COVID event, but we did anticipate investor rejection of our industry from the poor results of the previous decade chasing growth with high debt levels. The result was that our initial unitholders prospered by receiving more than twice their investment through distributions and still owning a company with an enterprise value of more than $3 billion. The purchases we have made continue to bear fruit through their cash flow streams, midstream systems land that is held by production and continued drilling on properties we did not have to pay for.

Even our purchases since the IPO have been contributing to our drilling program, one would have thought that host the 2022 run up in prices that would be hard to purchase any valuable drilling locations without paying for upside. However, as we review our potential 2026 locations, we're drilling on acquisitions from XTO Paloma, Cheyenne flycatcher, Savino and ICAV, which were all made post December 2023. The second pillar to discuss is disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of operating cash flow to optimize distributions to shareholders. We did not establish MACH to grow our production through drilling. Our drilling program is set to stabilize our production.

As I mentioned, our inventory is best-in-class for both oil and natural gas reinvestment. In 2026, moved down the natural gas being offset by a move up in oil prices. MACH has the unique ability to react to these commodity price changes by pivoting from one commodity to another to maximize rates of return. Therefore, we have prioritized our drilling schedule to take advantage of these price changes. Starting May 1, we moved in our first rig to start drilling for oil in the Agogo formation in Kingfisher County, Oklahoma. This is an area that's well known to us. We've drilled more than 250 Oswego locations since 2021 with very good results.

In the presentation, we're showing that a $75 flat oil. The changes in 2025, Oswego rates returned from 39% to 90%. $85 flat oil prices move the program returns to 145%. We let pricing dictate where we spend capital. We will also move in a rig to drill Southern Oklahoma or more basin assets that we acquired from Cheyenne and Fly Catcher purchases in 2024. The third oil-weighted rig will be moving into the Red Fork sand of Western Oklahoma. The majority of Red Fork locations were acquired by our limited leasing program and trades with others from our Cimarex acquisition in 2021. This shift in drilling will amount to adding 3 oil-weighted rigs by postponing the deep Anadarko dry gas program.

We may also delay the completion of our San Juan Mancos program until 2027 to add another oil rig in the Clearfork formation from the Sabinal acquisition. By making these changes, we can keep our reinvestment level below 50% of operating cash flow in 2026 even though we remain optimistic about the long-term potential of our natural gas assets in the Deep Anadarko Basin and San Juan Basin. We now have 5 wells with more than 9 days of production in the Deep Anadarko. These 5 wells have averaged 90-day cumulative production of more than 12 million cubic feet of gas per day, while our 15 bcf gas type curve is projected to be 10.6 million cubic feet of gas per day.

In the San Juan, we've begun our 2026 drilling program where we have 1 rig working drilling Minco shale wells. The San Juan Mancos is fast becoming known as a world-class natural gas asset with potential for meeting the growing demand that we expect to see in the Western markets over the next 5 years. We have 575,000 acres that are held by production that can be developed at any time the market allows. Currently, we will drill 7 wells during the summer's drilling window. We continue to believe that we will be substantially lower than historical drilling costs as we bring in new service providers from the Mid-Con and work with existing service providers in the San Juan to work with our dedicated staff.

Our San Juan drilling program in 2025 was exceptional. We drilled 5 wells that came online last fall and have produced more than 14 Bcf of gas and continue to produce over 60 million cubic feet of gas a day. These wells have been compared to the best set of wells drilled in the U.S. The San Juan gives us long-term natural gas optionality. When we acquired ICAV, we inherited a volume production contract that runs through 2030. Even with our limited drilling program, we can keep our production in the San Juan flat of approximately 300 million cubic feet of gas per day. We currently have approximately 65% of the volumes from the San Juan producing on this contract at a price of $1.72.

If basis continues to be low, we have an effective hedge and a basis move slower that will benefit from our drilling program and time as production payment amortizes. This is one of the larger volumes of natural gas that has access to the growing Western markets as they develop. MACH has 3 million acres of land that are not going anywhere. We have time because our assets are held by production with few lease expiration dates. This large inventory of investment opportunities was the result of acquisitions made over time since 2018, and gives us maximum flexibility to choose where and when to drill to deliver the best-in-class results.

Our third pillar to discuss today is to maintain financial strength. This pillar is designed to keep our leverage in check, Historically, we have kept our leverage at or below 1x. The iCabin/Sabbonol acquisitions last September have moved our leverage up to approximately 1.3x. Our goal is to move that ratio back to our desired double before we make any more acquisitions that require substantial debt. Therefore, our acquisition strategy is currently on hold unless we find an acquisition that's accretive to our cash available cash go for distribution using equity to lower our debt levels.

In the meantime, we can continue with our drilling program and let time move on as our leverage was showed down. We continue to have interest by sellers to exchange production for equity where we might be able to lower leverage by increasing our cash held for distribution to maintain the status quo. Our goal is to not move away from our current method of distribution unless we feel it is necessary. In that case, we can always use some of our distribution for debt reduction. It is safe to say that our debt levels are very manageable, but are a pebble my shoe that I'd prefer to move away from and get back to 1x leverage.

Our final pillar continues to be the most important, maximize distribution to equity holders. This pillar is the culmination of all we work for. Since inception, our goal is to find and acquire cash-flowing assets at distressed prices, reinvest less than 50% of our operating cash flow, keep our leverage low and maximize this pillar. We have been and continue to be successful. The evidence is in our industry-leading distribution. You can see this in 2 ways. Our company has had a cash return on capital invested of more than 20% every year since our inception. We have averaged 35% [indiscernible] over the last 5 years. I believe we're in rare error here. Only a few tech companies can match our [indiscernible]. We have also averaged 15% yield since the beginning of 2024, both are industry leading.

I'll now turn the call over to Kevin to discuss the first quarter financial results.

Thanks, Tom. For the quarter, our production of 158,000 BOE per day was 16% oil 70% natural gas and 14% [indiscernible]. Our average realized prices were $59.73 per barrel of oil. That's a 20% increase from fourth quarter $2.74 per Mcf of gas and $23.75 per barrel of NGLs. Of the $366 million total oil and gas revenues, the relative contribution for oil was 42% to 45% for gas and 13% for NGLs. On the expense side, worth pointing out our lease operating expense was $101 million were only $7.12 per BOE. Cash G&A was approximately $5 million or only $0.37 per BOE. We ended the quarter with $53 million in cash and $305 million of availability under the credit facility.

Total revenues, including our hedges and midstream activities totaled $286 million, adjusted EBITDA was $195 million, and we generated $170 million of operating cash flow, spent $75 million in development CapEx, which represents 40% and of our operating cash flow after interest. And in the quarter, we generated $107 million of cash available for distribution, resulting in a distribution of $0.64 per unit, which will be paid on June 4 to holders of record on May 21.

And with that, Darryl, will turn it back to you to open the line for questions.

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

I want to see if your shift back to the kind of oilier Oswego drilling program. How quickly can that move the needle? Are you maybe at 16% oil now? Can that get to 20% to 25% oil over the next few years? Or does maybe the productivity from your gas assets kind of just offset that with higher volumes, but at the same mix?

No, not really. So it basically keeps our oil production from declining by moving to the oil side of the business. So we might grow 1% or so a year. But really, it's maintaining oil production rather than continue to see a decline.

That's fair. That makes sense. And then the second one, your low CapEx requirements continue to impress. I just want to maybe understand, is there inflation built into that or maybe built into your LOE just with some of the cost changes we're seeing as a result of the Iranian conflict that maybe some of that spending may move? Or do you have some of that locked in with your vendors and maybe over certain durations?

We don't have anything really locked in. We can move rigs at really 30- to 45-day intervals. So we really can move back and forth from different areas as needed for higher rates of return. We are seeing some oilfield inflation. Thus, I think why it's important to move quickly before inflation hits. As always, the oilfield services job is to get our rates return down to 20% and we want to drill wells that still have. In fact, the lowest we have on the 430 curve of the oil wells we'll be drilling this year as of the 430 curve was 80% So it's really just chasing the best areas and spending CapEx as the -- as our operating cash flow allows us to.

I think the goal of the company is that will allow growth if it happens, like if prices move up, but spending more than 50% of our operating cash flow. So it's not that we're restricting growth. It's our high rates of return allows us to grow by spending less, and that's just what we anticipate to continue to do. But remember, that's really because of all the assets we bought during the darker days. They continue to throw off free cash flow anytime you're making acquisitions at $20 oil, it just pays big dividends in years later. We'll reap those benefits for decades.

That makes sense. It sounds like you're staying flexible.

Our next question is come from the line of Michael Scalia with Stephens.

I just wanted to see with the new plans, maintained your guidance. Do you anticipate putting out any new guidance with the shift in the drilling plans and it sounds like you might change your completion plans in the San Juan Basin. I guess when would you make that decision if you do decide to hold off on completing those wells.

Yes. Sorry. I think -- do you have the -- I don't think I can we are going to delay -- we're planning on delaying the Mancos, but go ahead, Kevin.

Sure. Just -- and Mike, just to answer your question around guidance. We think the CapEx guidance is -- as you noted, as we shift to oil, we may actually see an acceleration of production versus spending the CapEx on the gas drilling, particularly in the Mancos. So we'll look to revise guidance as we get moved to the oil program, probably mid-year it's if and when it's appropriate. But it does just as we look at the model, those cycle times on these wells are shorter than some of our deep gas drilling. So it should actually help this year's cash generation.

And it's not that hard of a decision. I mean, usually, I would want to -- once we spend the capital to drill a well to not leave it as a [indiscernible] but whenever we can move to a Clearfork location that today's prices is going to have 100% rate of return. It's just really difficult not to defer the gas whatever basis today to San Juan is low, and we think it will improve. But still, we don't want to just guess going into the winter. So we'll probably move that until after the first of the year, then it will really depend on the Mancos weather provides us when we can move, when we can frac. We can't do anything in the New Mexico side until April, I believe. But we can on Colorado side as long as we're on the Southern new tribes, weather permitting.

Sorry, Mike, if I didn't catch all your questions, just please ask again.

No, that addresses it. I guess it sounds like even with the shift, there's no change to the CapEx is going to remain the same. We probably anticipate some minor shift in the mix of production is what it sounds like in certainly leave some upside for cash flow with the higher oil mix.

Yes, that's correct.

Wanted to follow up on the Mancos. The 5 wells that you completed last year, looks like based on what you have in your presentation and what you said, Tom, they're performing extremely well. I think I have completed a couple of those, and you guys completed, I think, 3 of them. I wanted to see if you did, in fact, cut back on the proppant on the wells that you completed? I know you had said you felt like they were being overstimulated, and you could save some money there and want to see if those results played out the way you thought?

We did not change the amount of proppant that iCAD was using now. [indiscernible] did use and we will use less profit than kind of the industry was earlier. I think that's moving towards what we're going to do. But our -- if you look at San Juan in general, there were proper sizes up to 3,000 pounds a foot that we were using closer to 2,000 pounds. And I think it was totally adequate. So that we were able to save some money even last year just through a little -- a few other different methods, but not in the profit size.

Okay. So that line of state....

I think we're saving about $1 million per location. Yes, $1.5 million per location just from our changes we made, but it was not in proppant.

Got you. So you still feel good about that $15 million target that you talked about.

Yes, I feel good about something lower, but we'll see. Yes, I feel good about $15 million. There's no reason it's been $15 million drilling in these wells.

Our next questions come from the line of Jeff Grampp with Northland Capital Markets.

Tom, I have a question for you on the distribution strategy. It seems like in recent history, you've kind of been comfortable maintaining the 100% payout with current leverage kind of mid, but the pebble in your comment makes it seem like perhaps you're maybe reconsidering that to retain some cat for debt paydown. Is that a fair comment? Or how do you think about payout ratio over the next few quarters?

Yes, I hope not. I do think that over time, it takes care of itself. If you were to look at our model, actually, debt-to-EBITDA goes down as oil prices have moved if oil prices move higher or gas goes to where I think it will. It naturally takes care of it by itself. So we always -- so the reason private credit really likes us so well is because we have so much free cash flow. And so does if you have a 19% yield, then you may get a 10% for a while as you pay down the debt it's not the worst thing. But I'm a holder just like the rest of the unitholders, and I like having Christmas 4 times a year.

Fair enough. That sounds good. For my follow-up, it kind of sounds like the bias based on today's commodity price dynamic is to defer those gas completions and and add that clear 4 rig. But I just wanted to dive into that a bit more. When are you guys kind of targeting potentially adding that clear rig? And is it as simple as looking at gas and oil prices over the next few months in the strip in making that decision?

Yes, fairly well made it so that it was just like yesterday. But it was -- yes, so the Clearfork is clearly a superior rate of return at today's prices than completing the Mancos, and we could start that July 1 and have a 30-day turnaround. So more than likely, unless something changes really dramatically between now and a month from now, will delay the Mancos and bring on a Clearfork rig.

Our next question come from the line of Carson Coronado with Raymond James.

I just wanted to see if you were trying to continue to focus M&A in the current basins you operate in? Or is there a willingness to step into new basins, and does the current commodity price environment make it harder to get deals done with bid as spreads potentially widening?

No, I don't think it's any harder to get deals done, especially the ones that we have a niche in which is really staying away from asset-backed security projects where they can fund. So larger deals were not so good at areas of -- where you pay for a lot of upside, not so good, like the Marcellus or Haynesville or now even the San Juan. The areas we are pretty good at is finding assets that are $100 million to $300 million in size that others aren't chasing that we can see some distress for whatever reason. It might be that gas goes to Waha where and ABS really can't go in and hedge very well over a period of time and they can't compete with us.

There's always a way to find things that work. Our issue right now is that we have too much debt to really take on more debt. So that we want to move down our debt levels so that we can get back into making those $100 million to $300 million type acquisitions. We can be more aggressive not on having to pay for upside but more aggressive in size if the seller would want to take equity. But that's the only way we could really compete at any size.

Great. And I also had a follow-up question on maintenance CapEx. So the low decline rate definitely helps keeping the reinvestment rate under 50%, but what would be a reasonable maintenance CapEx estimate for FCUs.

Yes. I think looking at our existing CapEx guidance really ending if we're measuring that based on volume, then when we're drilling gas wells, there's more volume that come into the system. And if we're drilling oil the equivalent volume is a little bit lower. But again, as you mentioned, our base decline rate is probably among the lowest, if not the lowest, among the independents, and that gives us the ability to essentially stay the same size grow a little bit or shrink a little bit, but based on just half of our operating cash flow after interest. So I'd largely equate our guidance CapEx with being kind of maintenance CapEx, if not a little bit more productive than its CapEx.

Yes, that's right. Our drilling program is designed to keep our production flattish that could be up to down to up 3 or 4 down 3 or 4 depending on what prices are, but you really won't see a tremendous growth from drilling and then that allows us to distribute back more to unitholders.

Our next questions come from the line of Ron Sanchez.

I was just wondering what would be your average breakeven price on natural gas can do -- I mean, yes, that's all.

Sure. It's basically around $1.72, and we've just today posted a new investor presentation, and we have a slide on that on Slide 9, where we show our breakeven for both gas drilling and oil drilling. And it's among the best of the peers for us, as Tom has mentioned many times before, we those are good numbers that we're able to achieve with good cost control, but we're generally just chasing the highest internal rate of return in our portfolio.

Our next questions come from the line of Derrick Whitfield with Texas Capital.

You're going back to your 4Q commentary on divestitures, does the current higher price crude environment seen today, does that change your view on the need to pursue some of the monetizations you were talking about during 4Q?

Yes, Derrick, we were talking about maybe having a partner in the deep Anadarko. I don't know if that's going to happen or not. We did go out to a few parties the gas prices have been lower. I'm not sure that we would get paid enough to give up any production that's already flowing now, and I'm not really a seller at today's gas prices. So it is -- it becomes harder to do until prices move. We really weren't looking at selling any oil projects. But it was really more around could we sell some non-EBITDA generating assets like leases in order to pay down some debt. And doubt that happens, but we'll know more next quarter.

That makes sense. Maybe just with respect to the Permian, will not as economic as your Oswego are there levers there you're considering to increase production in the current environment?

Yes. The Clearfork is in Robertson County on the shelf. So we're having a rig there depending on what our operating cash flow looks like and how much we -- how close we can get to 50% we could keep a rig there for the rest of the year. We'll see how it all looks. But right now, we are going to have a rig there moving down from Oklahoma in -- by the first of the year. So that is in the Permian and those wells are right at 100% rates of return.

That's great. I'm sorry, I didn't pick that up, Tom, I'm just joining the call away. But maybe one more if I could on service costs. I know you commented a little bit earlier on it, but just -- could you speak to what you're seeing in the Anadarko at present? And what your expectations would be if oil prices remain elevated as they are today?

Yes. If oil prices stay where they are, it would take a fairly high gas price to make us move back to drilling gas wells. Last year, that happened as oil prices fell, but today, even at the Colstrip 27 strip is $72, that's good enough for us to keep rigs working. So the flexibility of the moving between oil and gas is good. We have a tremendous backlog of oil locations as you're seeing now. we can move in several rigs and drill different locations across Western Oklahoma and in the Permian. So it's really just price dependent, but the it's really astounding that we were able to put together 2 million acres without having to pay for it in one of the most oil and natural gas rich basins in the world in the Anadarko Basin. So that is another -- like our production, that will pay dividends to us for decades.

Great. And Tom, just on the service cost, like what was your expectations to be in Anadarko if we remain in this oil price environment?

Yes, we're seeing -- you say service cost?

Yes, service cost.

[indiscernible] are going up, steel is going up, labor costs from are going up fuel surcharges are going up. So we are starting to see the effects of inflation. We know from 2022, that, that comes fairly quickly. So it'll all have to be put into the calculation for how much we can drill depending on what prices were paying. So we're still using our current AFEs. We change AFE every month. depending on where prices are. We price out for every well series of wells we do. So we're very quick to react to both oil and gas prices and service costs.

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

Kevin, I got dropped from the call for some reason, too. But Tom, you mentioned 4 oily plays here today. The OsoBio, which you gave us a lot of detail on, but also the armor, which I guess is really more the location rather than the play. But the red work and also the Clearfork. So can -- not to get down into all the details, but can you give us an idea how those plays rank in your appetite for more drilling? And how much running room you have on those?

Sure. The Sycamore with a Mississippian member of the SCOOP in the -- what we call the Arbor Basin that Shameel basically in Stephens County, Southern Oklahoma, that's going to have very, very high rates of return at today's oil price, and they're fairly deep expensive wells, but very good. Continental has most of that area and maybe a private 1 Citadel. But the -- it's good, very -- but we only have 3 locations to drill. So then we look to have the consistent operating the next best is the Oswego, and that's more consistent and we have dozens, if not hundreds of locations left to drill in the Oswego.

And we could even move from the Stephens County after we complete those wells to 2 rigs in the Oswego if oil prices remain elevated. Then the Clearfork was -- we picked up from Sabinal would be #3. And that, as I mentioned, I have a rig going there in July. And then lastly, because of just a little more gas as the Western Oklahoma Red Fork and that if gas prices will move up, it could move up in the HIF parade today, that would be our fourth. Even there, the red for is going to be about 80% rates of return.

Got it. That's great detail what I was looking for. My follow-up is on San Juan Basin, I guess, supply-demand in marketing. When you bought that asset from ICAV, in that earlier presentation, you gave us a lot of detail about where that gas can go and what the options are. But the prices are pretty tough out there right now. And you think a lot of gas wants to get to the Gulf Coast, but you've got the Permian and Waha between you and the Gulf Coast, if you wanted to go that way. So that's, I guess, a long intro to say what are the dynamics that we can watch from our seats on -- that would signify or could be precursors to more favorable pricing in that basin?

Yes. I mean, at the time we bought the ICAV assets last summer in closed in September. I wouldn't have thought that our basis -- our hedge was a benefit. So basically, we have 65% that we bought on a long-term contract from that BP has that expires in 2030. That effectively is $1.72. And then -- but since that time, really due to weather, winter, not coming to the west, basically we almost stand alone in having the low basis of public companies with the San Juan. So the -- that now has hovered around dollar what we receive now. But I do think that's coming back. So -- but to answer your question, it's really more pipe getting out going west, having a larger LNG facility in Mexico, getting gas. I think the Asian sales point will be wanting more Western gas coming across LNG to Asia. And that all happens over time. And so it's really a pretty good for us now that we didn't have to pay for that gas, and we bought it at $1.72 or less.

And so as it amortizes out over time, that gives us time to not only have the LNG market expanding, which I believe it's going to. There's a new pipe going across the Navajo Nation, I believe, or will be -- and then along with that, getting gas to the data center build-outs in Southern California, especially the Phoenix market, which seems to be expanding. There's some interest in even getting our gas up to the west into more of the I guess, the upper western markets and even into the Pacific Northwest. So there will be and expansion of gas coming out of the West and really between Hilcorp and us in San Juan, we control the vast majority of it. So it's a good place to be as long as you're patient. It's a 5-year program.

Thank you so much. We have reached the end of our question-and-answer session. And with that, that does bring our call to a close. We appreciate your participation. You may disconnect your lines at this time, and enjoy the rest of your day.

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 seeing this 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 distal 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 size be 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 than 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 in 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 Juana 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 rate 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 cube 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 Makos 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 ICAV and Sabina 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 those we go to take advantage of higher oil. Just curious, are there other things? Or 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 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 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 compare -- are competitive with our cabin 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 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 could the experience we 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 with 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 -- there 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 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 Mancos wells. With the benefit of a few bets in these formations, could you speak to how you performed against predrill expectations and some of the leverage you're planning to pull to drive lower completed well costs?

Yes. The first few wells that we drilled in the Deep Anadarko, we're 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 Myco 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 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 -- 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 oily Oswego?

Yes. I mean, right now the Oswego competes with the Deep Anadarko rates of return. So I think any time that you have oil above $70 where 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 everyone we drilled. And then we show every what 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 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 porosity in algo mount so you have different thicknesses. So wells even that are fairly close together can have different amounts 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 cost 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.

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 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 -- 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, I Cabinsabinol. 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 fruit lent 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 Putin 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.

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.

Thank you, Brock. Welcome to Mount Natural Resources third quarter earnings update. Each quarter, it is important to reiterate the company's 4 strategic pillars. These are: number one, maintain financial strength. Our long-term goal is to have debt-to-EBITDA of around 1x leverage. We believe that being around a turn levered leads to financial stability throughout different commodity cycles while also providing the ability to flex upward if unique and transformative opportunities become available on the M&A front.

That is what we've done with the IKAV, Sabinal transactions by breaking into 2 new basins. Post the IKAV, Sabinal acquisitions, we've moved up to above 1.3x leverage, a place that we would like to see come down over time in order to continue providing the best opportunities to toggle our acquisition lever and growing the company.

We will more than likely wait a few quarters to see where our debt-to-EBITDA levels shake out. The easiest of all paths to leverage reduction is to have our EBITDA move up. We would like to give the market a chance for that to happen before taking actions such as decreasing CapEx to reduce debt or to use some of our CAD to do the same. We also continue to receive inbounds from PE firms who would like to trade their production to participate in our upside. We continue to be interested in this approach if the combination reduces leverage.

However, having sellers take equity and open Mach up to 2 additional basins was equally important, especially given the size of the acquisitions compared to the amount of additional debt that we have incurred. Each of these areas now allows us to review more acquisitions in the sub-$150 million range in areas where we have established scale. These smaller acquisitions are where we have the ability to purchase at the highest rate of return.

Additionally, we purchased Sabinal in a historically weak crude oil market with the strip in the low 60s, and IKAV has tremendous upside associated with the asset that we do not have to pay for or didn't have to pay for in our acquisition price. Number two, disciplined execution. We continue to only purchase assets that are available at discounts to PDP PV-10. We have accomplished this task 23 times and do not see an end to that requirement. If there does become a time where all assets are trading at a premium, that should be because of higher EBITDA.

In that case, we could pivot to keep our production flat to growing through increasing CapEx for drilling from our increased operating cash flow. In fact, we can do that now even at today's current prices post the acquisition of IKAV and Sabinal. We show an example of that capital efficiency by lowering our expected CapEx 8% for 2026 without affecting our production guidance. Our projection for year-end 2026 and year-end '27 show modest growth with our current less than 50% of CapEx spend on our projected operating cash flow.

Our company has been built on making acquisitions that provide free cash flow at distressed prices. That is why we continue to have an industry-leading cash return on capital invested. The most obvious example is the IKAV purchase. We not only bought the PDP at a discount, but we have targeted to move aggressively to drill both the Fruitland Coal and the Mancos Shale in our 2026 budget.

Number three, disciplined reinvestment rate. We focus on returning cash to our unitholders. Therefore, we target a reinvestment rate of less than 50%. We are unique in being able to keep our production flat with such low reinvestment rate. The reason we can accomplish this is because our decline rate is only 15%. Therefore, it doesn't take a lot of reinvestment to keep our production flat while sending cash back to unitholders. We also have the luxury of choosing whether we drill natural gas or crude oil depending on the price. In May of this year, we ceased drilling our high rate of return Oswego inventory in favor of our drilling program to focus on gas.

Our oil inventory is almost entirely HBP, so we can patiently wait for oil markets to recover to reintegrate those projects into our development plans. Our development plan for 2026 is currently targeting dry gas projects in the Deep Anadarko and the San Juan. We make drilling decisions every month by maintaining contracts that can be altered or eliminated quickly with our service providers. We also have the ability to increase or lower our CapEx depending on pricing as we did this year. By making acquisitions that focus on free cash flow and acquiring future locations at no additional cost, we have built a tremendous amount of backlog of both oil and natural gas locations.

We now have an inventory on our nearly 3 million acres that will be hard to drill in any reasonable time frame while maintaining our reinvestment rate. We do not plan to alter our plan to reinvest less than 50% of our operating cash flow. Therefore, we might look for a drilling partner in our massive holdings of land in the Deep Anadarko and the Mancos Shale drilling. If we do, this would add revenue from our non-EBITDA producing land assets while continuing to achieve our high level of distributions.

Of all the name pillars, they lead to our fourth and most important pillar, delivering industry-leading cash returns on capital invested through distributions to our unitholders. With our announced distribution of $0.27 per unit in the third quarter, we have sent back $5.14 per unit to our unitholders since our public offering in October 2023 and more than $1.2 billion in total since our inception in 2018. This rate of distribution return dwarfs our public company peers.

Even with this massive return, we have grown our business to more than $3 billion -- $3.5 billion of enterprise value without selling any material assets while maintaining a cash return on capital invested of more than 30% per year over the past 5 years. We've never had a year where our cash return on capital invested was less than 20% since our company was founded. This one statistic is what we were formed to accomplish.

We continue to believe that we are nearing the end of a 2.5-year cyclical downturn in crude oil that will reverse in the next few quarters. When that happens, we'll be harvesting the Sabinal crude production at higher prices. The production decline is less than 10% a year. Therefore, our returns will be enhanced. We continue to believe that any time we buy -- we can buy low decline crude assets in the 60s that will be ultimately rewarded. With regard to natural gas, we are nearing a time when demand will start to accelerate.

We've been cautious on pricing since early spring and continue to believe that we are entering winter in a precarious position of full storage and relying on weather conditions to move the market forward. However, starting in 2026, the U.S. will begin to add demand through LNG exports. We see 24 Bcf a day of demand materializing between 2026 and 2030 just from LNG. This is a much larger story than data center growth for the U.S. market. However, data center growth is real and could equate to between 5 and 10 Bcf a day of additional growth if you assume that half of the load will come from natural gas.

I realize that some are concerned about associated gas in the Permian as 4.6 Bcf a day of takeaway capacity comes online by Q4 2027. However, we believe there is more -- this is more of a basis issue with the potential of gas being stranded at [ Cat ] or being passed, trying to make its way around to Henry Hub. The Haynesville remains the only direct path to Henry Hub with the Mid-Con coming in close behind. In any event, there's enough demand being generated to not fear the Permian in our opinion.

Now it's a great time to have purchased $1.3 billion of low declining oil and natural gas assets that will contribute more and more to our long-term cash available for distribution. The IKAV and Sabinal deals were transformational in terms of scale and diversification. You can see the compounding effect on our business by adding operating cash flow. We anticipate having the opportunity to continue to add these areas and in the Anadarko by purchasing smaller-sized assets that are sub-$150 million in size. However, we cannot make acquisitions with all debt.

Therefore, equity holders need to see the larger picture of adding reserves that are accretive to our cash available for distribution, plus increasing our CapEx budget and supercharging our distributions over time. The IKAV, Sabinal acquisitions are a good example. IKAV and Cane took equity for a large part of the purchase price, which made them available for us to pursue. Once completed, they are now accretive to our CAD by 8% in year 1, rising to 28% in year 5.

We now have early results from both the Deep Anadarko and the Mancos shale. In the Deep Anadarko, we brought on our first 2 well pads. These wells have a combined 25,000 horizontal section and are currently producing more than 40 million cubic feet of gas a day. At these rates, we anticipate finding more than 20 Bcf per 3-mile lateral with a PV-10 of approximately $15 million per location. We spent $14 million per well so far in our program.

We've also participated in 3 deep Anadarko wells with Continental and these wells, we have approximately a 20% working interest. They're in the early stages of flowback, and we anticipate them to be equal to our initial pad. In the Mancos, we brought on 5 wells that were drilled by IKAV over the summer. Two of these are 10,000 feet of lateral length and 3 are 15,000 feet. The 2-mile laterals have come in just above our expectations of 30 million per day for the pad and expected EOR of 18 Bcf per well.

Our 3-well 3-mile pad started production in late October. The pad is now producing more than 70 million cubic feet of gas per day. We expect a 3-mile lateral to have an EOR of 24 Bcf of gas and PV-10 of around $14 million. Currently, the combined 5 wells are producing more than 100 million cubic feet of gas per day. The current cost to drill Mancos wells is too high in our opinion. These wells are 7,000 feet of TVD with laterals that drill very easily because of the shale reservoir. The industry is currently spending $16 million to $20 million on each 3-mile well.

We have initially prepared AFEs to spend $15 million for each 3-mile lateral. However, I believe we will achieve well cost in the $12 million range next year. IKAV drilled all 5 of the wells that we are producing. IKAV completed the 2 2-mile laterals, and we completed the 3 3-mile laterals. IKAV spent $13.75 million on their 2 drilled and completed locations. We saved approximately $2 million on each 3-mile completion that we inherited.

These wells will now average $15 million for the 3-mile locations. I get asked a lot about how we're going to achieve these reductions. We have a firm belief that our -- in general, our industry overstimulates wells and doesn't do a great job of maximizing profits. We can reduce cost by using more aggressive bidding practices, reducing acid, sand sweeps, diverters, location size, amount of rentals, et cetera. Or said another way, just about everything on the location. This adds up.

There is a multiplier effect when pumping a job. The larger the frac, the more horsepower is used and more sand and water. All that equates to more cost. The easiest way to gain a rate of return is to spend less. If we are successful in our attempt to lower cost, we can add an additional 30 percentage points per location by moving from $15 million to $20 million -- from $15 million to $12 million in every play, we have been involved in drilling at Mach. We've used this approach. For example, when we started drilling the Oswego, the wells cost twice as much as we were able to spend, and we still have the same outcome on production. I believe we'll also be very effective at lowering costs in the San Juan.

During the quarter, we also completed 2 Red Fork sand wells. These wells are coming on at just over 600 barrels a day and 1.5 million cubic feet of gas. We anticipate the IRR to be in the high 30s at today's oil strip. We're in the final completion stage of our next Deep Anadarko location. This location is a 1-well pad. We currently have 2 rigs running in the Deep Anadarko. The production plan through the first half of '26 is to have 1 location coming on this month, a 2-well pad in January 2026, a 2-well pad in March of 2026 and a 3-well pad in June of 2026.

The Mancos shale program for 2026 will begin in May of 2026. We anticipate bringing on 7 Mancos locations in the fall. We only target natural gas as our commodity of choice for 2026. We also have targeted areas where there's ample gas takeaway. The Mid-Con is well connected to major interstate systems, including Panhandle Eastern, Mid-Con Express and Mid-Chip. Currently, the Mid-Con produces about 9 Bcf a day of gas with gas takeaway of approximately 12 Bcf a day. Midship and Southern Star announced planned expansions of approximately 400 million cubic feet of gas each.

The San Juan also has ample takeaway capacity for the near term. Growth from the Mancos shale development is coming. However, Energy Transfer's Transwestern expansion is also projected to add capacity by 1.5 to 3 Bcf a day to meet demand from the West by year-end 2029. Total surely thought about the ability to add gas when they decided to partner with Continental on their Deep Anadarko inventory. I believe that joint venture is ample proof that the Deep Anadarko inventory is going to provide the necessary help to move natural gas to the hub where LNG demand is exploding.

I'll turn the call over to Kevin to discuss financial results.

Thanks, Tom. For the quarter, our production of 94,000 BOE per day was 21% oil, 56% natural gas and 23% NGLs. Our average realized prices were $64.79 per barrel of oil, $2.54 per Mcf of gas and $21.78 per barrel of NGLs. Of the $235 million total oil and gas revenues, the relative contribution for oil was 50%, 32% for gas and 18% for NGLs.

On the expense side, our lease operating expense was $50 million or $6.52 per BOE. Cash G&A was $21 million. It's an important point this quarter to note that the deal costs associated with IKAV of approximately $13 million are a bit unique. First and foremost, they are nonrecurring. Secondly, due to nuanced GAAP rules, they are required to be expensed whereas in the history of our acquisitions, including Sabinal, the deal costs have been capitalized.

Additionally, with the IKAV deal, we engaged an outside adviser, which again is out of the norm for our acquisition history. As a point of reference, the Sabinal deal costs were approximately $4 million and by the way, were capitalized. Excluding the deal costs, recurring cash G&A was around $7.2 million or $0.83 per BOE.

As we analyze this quarter's distribution more closely, the free cash flow from our legacy assets performed as we expected. The free cash flow from the acquired assets only contributed for a couple of weeks during the quarter, but also performed as expected. And with a higher outstanding unit count associated with the units issued for the acquisitions, the distributions before the G&A impact would have been approximately $0.35 per unit. The nonrecurring $13 million deal costs reduced the distribution by about $0.08 per unit. It is straightforward to expect higher distributions in the immediate upcoming quarters with the benefit of the acquired assets contributing for the full quarter and the absence of expensed deal costs.

We ended the quarter with $54 million in cash and $295 million of availability under the credit facility. Total revenues, including our hedges and midstream activities totaled $273 million, adjusted EBITDA of $134 million and $106 million of operating cash flow and development CapEx of $59 million or 56% for the quarter. Year-to-date, our development costs are approximately 48% of our operating cash flow. We generated $46 million of cash available for distribution, resulting in an approved distribution of $0.27 per unit, which will be paid out December 4 to record holders as of November 20.

Brock, I'll turn the call back to you to open the line for questions.[ id="-1" name="Operator" /> [Operator Instructions] Our first question today comes from Neal Dingmann of William Blair.

Tom, nice quarter. Tom, my first question is in the Mid-Con operations. Specifically, you highlighted some really nice notable well upside in the play and while things have always been going nice there. It seems like more recently, you're seeing some just commendable upside. Is that attributable to going after some new zones? Or what's driving this upside, particularly in that -- some of this Mid-Con upside?

Thanks, Neal. It's just really just moving deeper into -- moving away from a condensate zone into deep gas. It's always been known in the Anadarko. There's a tremendous gas potential as I think it has been noted also that Continental was drilling in Custer County Deep gas in 2017. We picked up Millennial Energy Partners acreage out there in 2020. And since that time, we've been studying the Deep Anadarko. The issue for natural gas producers as you just haven't had a strip that has been competitive with oil.

And so now that we're getting a strip above $4, we can have rates of return north of 50%, which meets our threshold, especially if oil prices are down. So that's the reason we moved into the Deep Anadarko wasn't because of any really new news other than there's been a number of wells that have been drilled over the years in the deep gas area. It's that the efficiencies of drilling 3-mile laterals and having 15,000 feet of TVD with 15,000 feet of lateral isn't for the faint of heart, but there is plenty of gas there.

And so that's -- it's really about keeping our costs down to -- and having a decent strip in the natural gas pricing in order to make the rates of return, we think we will. But the asset -- the natural gas has always been known to be there.

Tom, that leads me to my second question, just on your gas strategy. In the Mid-Con or other areas, it doesn't seem -- do you all have any -- is there any takeaway constraints? And do you all use any sort of managed choke program because it seems like the rates are flowing really nicely. And so I'm just wondering when it comes to takeaway and chokes, how would you talk about that program?

No, the Mid-Con is a great place to work, especially in Oklahoma. It's probably the second easiest state to drill in. We can have Kansas being the easiest and the ability to have gas waiting on you when you get a well done is there. Plenty of takeaway capacity. I think we estimate 3 Bcf a day of takeaway capacity now. So there's just no issues with getting gas online and flowing without restrained rates.

[ id="-1" name="Operator" /> The next question is from Charles Meade of Johnson Rice.

Tom, forgive me, you went through a lot of good detail there, and I may have missed some of it. But I wanted to ask on the Deep Anadarko. I know you just said it's 15,000-foot TVD and then you do another 15,000-foot lateral. What is the D&C cost on those Deep Anadarko locations? That's kind of one. And then two, $20 million a day sounds pretty stout to me, but how did that fit versus your expectations?

Yes. Last thing first, it exactly as we anticipated if you want to have north of 50% rate of return and spend $14 million, which is what we've done. The PV on that is about $15 million each per well, but the rate of return is going to be in the 60s, more than likely depending on what strip is. And that's -- I mean when you look at that, all the wells that we're bringing on, you can see how come that we're able to keep our -- cut CapEx and keep our production flat. Just because of the rates we're getting out of these wells. And right now, the natural gas strip is good.

So that's -- when we target the Deep Anadarko, we plan and have spent $14 million. I think that might improve over time just as we drill more wells, we get better at it. It's not the easiest place to drill. You've got very deep wells, very complicated completions just because of the amount of pressure you're using to get a frac established.

Got it. And then I wanted to -- this is a little bit bigger picture. The improvement in your '26 guide where you're spending 18% less on D&C and the volumes are essentially unchanged. My first instinct is to connect that better capital efficiency with what looks like these really good gas rates at both Western Anadarko and the Mancos. But is that really the driver that has enabled you to put forth this better, more capital-efficient '26 program? Or is there something else at work?

No, that's it.

[ id="-1" name="Operator" /> The next question is from Derrick Whitfield of Texas Capital.

Starting with your distribution, despite the strength in operations this quarter, it did come in a touch lower than expected due to the nonrecurring factors you noted. If we assume a flattish price environment in the capital plan you've outlined for 2026, is it reasonable to assume your distribution would be flattish year-over-year?

Gosh, Eric -- Derek, I think that you just have a little caveat to look at what price deck you're talking about for '26. But I think we're expecting -- I think we would actually just through the course of '26 as these wells come online, kind of expect an increasing distribution over the course of the year.

And Derek, our natural gas volumes next year will be moving up to just over 70%. So if you're bullish natural gas, we should do pretty well.

Yes, that was our thought as well, Tom, if you look at your hedges provided with the gas growth profile. But just wanted to confirm that was -- we were thinking about that right. And then on my follow-up, I wanted to focus on your prepared comments on private equity PDP exchanges for Mach shares. Regarding the kind of PDP exchanges, how large and in what basins are those opportunities in general? And would it be safe to assume that they would be both leverage and yield accretive?

Do you want to take?

Yes. So we're having people kind of contact us. I don't know -- I think it's rare -- I'd start with this. I think it's rare to have an IKAV, Sabinal happen very often, especially at once, just you have 2 pretty large groups that we're wanting to swap out. But at today's strip, especially in oil, and it's not out of the question that others they do reach out. But I'm stumbling here just because there is a cash market with all the ABS participants. And so if somebody wants cash today, they can get it.

But there is a group that prefer to take maybe because of their timing of a fund need to be moving out and they don't want to take today's prices at cash. Those are the types that will look for us. It's not -- I think you probably wouldn't see that out of the Marcellus or the Haynesville or core Permian, really anywhere where you can get paid more than PDP PV-10. But if you're in other areas, I think that we'll continue to have that. And yes, anything we do would be accretive to our cash flow for distribution and really can't be dilutive on a debt level -- a debt perspective. Sorry, I rambled about all that. If you want to ask me something to clarify, please do.

I think you covered it well, Tom. I mean it's going to be leverage and yield accretive. So certainly, thanks for your comments on that, and I'll turn it back to the operator.

[ id="-1" name="Operator" /> The next question is from Michael Scialla of Stephens.

Tom, I wanted to ask about your comments that the industry tends to overstimulate wells. You mentioned the potential for cutting costs in the Mancos. I want to see if you have taken that approach with the Deep Anadarko as well. And do you have enough production history on either these wells in the Mancos or the deep play to give you the confidence that you're not impacting well productivity by cutting back on the proppant.

The Deep Anadarko, we just use a typical frac that's already been moved down. So the industry might have been at 3,000 pounds per foot of sand in the last couple of years ago that we've moved down and others didn't just us have moved down closer to 2,000 pounds. And I think that's how can you see other operators spending relatively in line with us on where costs are. That hasn't happened yet in the San Juan.

And I think chasing estimated ultimate recoveries is sometimes can be -- it can affect negatively the rates of return. And so what we try to do is to find a way to stimulate a well that we don't think will hurt it, but not spend as much money. I think that if you use a 2,000 pound per foot frac job in the Mancos shale, you're going to get that stimulated.

To answer your question, we don't know. We haven't seen it. We have IP30s on wells that are a little bit more stimulated than we will next year. But I'm pretty comfortable that in the past, whenever we moved down our stimulations, we haven't seen a decrease in rate of return.

Sounds good. I want to see if you could talk about your potential inventory in both plays. I know you'd like to watch others sort of delineate your acreage for you. Is there an inventory number you can put on either the Deep Anadarko or the San Juan at this point and maybe look at some potential upside if there's more delineation by you or others there?

Yes. So we just have too much acreage to effectively drill it all. We have 500,000 acres plus in the San Juan. And in the Deep Anadarko, we have more than 120 locations already under lease that we can drill. So that's how I mentioned that at some point, there's just more here to do than a company that's not going to invest 100% or more of your cash flow drilling for growth. That's just not what we do. So it's probably at least -- let's assume that we're successful in expanding the Deep Anadarko by a few more locations.

You have Continental to the Southeast of us, Validus is drilling a few wells, and then we're intermixed. It's not out of the question that we would bring in a partner to help us to bring on more gas. And in that case, it would just be highly accretive to us. So again, I don't know if I answered your question, but that's kind of the way we look at it.

No, that's perfect. I was wondering what the motivation behind bringing in a potential drilling partner was and that really explains it. I think you want to move that value forward without changing your reinvestment decision. So...

[ id="-1" name="Operator" /> The next question is from John Freeman of Raymond James.

Really impressive to see the 18% reduction in the D&C budget and still be able to maintain production. We did notice that the midstream and the land budget basically doubled from the prior update. Just wondering if you can -- choke up a little hold on. Yes, I think -- sorry... I was just trying to... The midstream and the land budget and just sort of what drove that. Sorry about that.

Yes. And the land budget is mainly in the deep Anadarko. We are buying a few new leases. We trade around some acreage, putting together areas that we didn't have completely HBP through prior acquisitions. But it's -- in the whole scheme of the area, it's fairly small, the increase in land to do that. I think with the -- if you mentioned midstream, we inherited quite a bit of new midstream with the last 2 acquisitions and it's just more maintenance and getting them back up to speed, especially in the IKAV acquisition needed to have a little bit of upgrading.

And John, just for a little bit of detail, the land piece of that is about $32 million and midstream about $17 million.

That's great. And then just following up on some of the commentary prior commentary on the M&A front. When we sort of look at the basins that you're currently operating in, should we assume kind of the plan going forward from an M&A perspective is to sort of do kind of these bolt-on deals in the existing positions and basins you're in? Or are you all still open to considering expanding into new areas or basins?

The only way we'd expand in any size is through an equity deal with another partner or the seller. I think that in the 23 acquisitions we've made, most of them, 20 of them probably have been in and around $100 million. So that's really the best area for us to compete. We can't -- we don't have the ability to compete against the ABS market and try to make the types of rates of return that we need to make through an acquisition that are accretive to our cash available for distribution.

So we just stay away. We stay away from others that are going to be bidding upside. We stay away from those who have the ability to come in with a very low cost of capital and maybe bid it to a way to -- that we can't compete. And so that -- I think we look at a lot of deals, but we'll -- the ones we get tend to be in this $100 million to $150 million range where they're highly accretive to us. And keeping in mind that those can't be done with debt, though, because we've now used our debt card and are up over a turn of leverage, and we want to see that come back down.

[ id="-1" name="Operator" /> The next question is from Jeff Grampp of Northland Capital Markets.

I wanted to expand on the drilling partnership opportunity. Any thoughts on what kind of size you're looking for in terms of a partner? I'm just kind of curious what stage of conversations these may be? And is this something that you guys are pretty definitively moving towards? Are we kind of more of an exploratory stage? Just any additional color there would be helpful.

Yes, Jeff, it's just a thought. I hadn't really moved more from my brain to my mouth to you. So there's nothing really -- there's nothing going on. I just think we have too much. And so as I got prepared to write a spill to describe what we have like, my Lance, we have a lot of -- we have more here than I can ever get to. And so that's -- we haven't talked to anyone. We haven't -- we have a Total Continental deal that's right beside us that I doubt they got that for free. So it seems like we probably have an asset that could be maybe profitable to us. We've done this in the past.

You have a lot of buyers that are coming here. The Mid-Con, especially has a great takeaway. And I think that's what the Total deal is showing you is that you can get gas to the hub. And so it seems to me like to be a pretty attractive place to own acreage.

Agreed. That's helpful. And for my follow-up, we're a couple of months into operating the new properties here. Overall, how is integration going? Anything you've learned or that's been surprising in the couple of months that you guys have been taking over in both the Permian and the San Juan?

No, the good people that work hard. I think learning our desires to cut costs and watch what we spend is something that all people have to get used to. We focus on how much bidding. We focus a lot on details. And so yes, it's all going good. We have a new office in Durango, and that's -- I think is -- we'll find that to be an incredibly good place for us to do business.

[ id="-1" name="Operator" /> The next question is from Geoff Jay of Daniel Energy Partners.

Tom, just -- I guess I would have interpreted your comments earlier on the Mancos as constructive but cautious. And I guess in that light, given the strength of the strip in '26, are you sort of content with your hedging as it sits? I think if I did my math right, it's a little shade over 20% hedged for next year. Would you like to see that higher? Or is that a good level?

Yes, Geoff, whenever you tie in the Mancos hedges or the San Juan hedges, we're in 2026 closer to over 60% hedged on natural gas. So we have gone in heavily hedged into 2026. I think there's risk coming into this. We're back to kind of a weather bet, which I don't like to make. So the -- I think when I say precarious, I do believe it's precarious, but there's no doubt that starting in January, demand is going to start going up. I don't see any way for 2027 not to be bullish.

And so that's -- whenever I look at '27 and beyond, you have -- there needs to be a lot more drilling activity than we're seeing today to overcome the demand. So I am bullish. I'm very bullish natural gas. It just is this winter season if we have a warm winter, you could be backed up into late '26 before you see a real recovery in prices.

Got you. Well, I'm sorry, my math was lousy. But I guess a follow-on to that then. When you guys closed on these deals, can you refresh me like how many rigs in total were running for Mach and sort of what your plan is for next year? What does that sort of sub-$300 million D&C budget contemplate?

Sure. So the -- right now, we have 2 Deep Anadarko wells or rigs that are running will continue to run through 2026. And then we start our Mancos and Fruitland Coal drilling program next spring. We'll drill 7 locations in the Mancos and 2 locations in the Fruitland Coal, and that takes up our total CapEx. That's -- keep in mind that that's subject to change every month.

[ id="-1" name="Operator" /> The next question is from Tim Rezvan of KeyBanc Capital Markets.

I was trying to understand the changes in 2026 guidance. You put a release out in mid-September, and then it's been pretty significant changes from there. So we saw CapEx all in down about 10% and production down about 1% to 2%. Is that change reflecting a pivot to 100% gas-focused drilling? I'm just curious, given the -- it's a 10% reduction in 7 weeks is a big amount. So I'm just trying to understand what's changed on the modeling and sort of strategy forecasting side.

Sure, Tim. This is Kevin. So good question. And as Tom just said, we look at our drilling schedule monthly, and we do have the ability to pivot quickly. And so the description that you threw out there is largely correct that we -- 2 things happen. We see the returns on our gas drilling as being better. And so much more heavily weighted towards gas.

And then secondly, kind of the reduction in CapEx is also reflective of basically lower strip prices than we put out the first guidance for 2026. We've seen forecasting with the lower strip, lower operating cash flow. And again, our company is run pretty simply and straightforward. As you see changes in the strip, we'll generally pivot and change our CapEx numbers. If it goes up, we'll look to add good IRR locations. And if it goes down, we probably throttle back some of our activity.

Yes. Tim, I think of it as that one of our pillars is a 50% reinvestment rate. Production growth, the amount of production growth isn't. So whenever we have higher operating cash flow, we get to use half of that and put it directly to work in CapEx. And just luckily -- well, not luckily because we moved down that decline from 20% to 15%, that makes it much easier for us to effectuate this small single-digit growth by only spending 50% of our operating cash flow.

Okay. That's very helpful context. And then again, I know this is subject to change as we've seen. But in this environment, where you're looking at maybe roughly 2/3 gas SKU in 4Q '25 and you're guiding to 71, we should be modeling, I guess, a steady increase in natural gas and you could be looking at maybe a mid-70s rate as we exit '26. Is that the right way to think about things?

I think just over 70% is where we're targeting year-end '26.

[ id="-1" name="Operator" /> The next question is from Selman Akyol of Stifel.

This is Tim O'Toole on for Selman. In your prepared comments, you guys talked about the Desert Southwest expansion. It seems like there's just a lot of gas demand kind of coming out of the Southwest and in Arizona, but that project is not coming online until closer to the end of the decade. So just kind of curious how you guys see the San Juan kind of position there kind of short term and maybe longer term as that project comes online.

Thank you, Tim. I think it really just depends on the amount of rigs that run. So the San Juan is seasonal. So you can only really move in and drill effectively through the spring and summer and be completing in the fall and need to move out by November. And so we kind of look at December to May as the 1st of May through April being a time that's more just getting ready for the next year's season to get permits, all the things that have to be done. I say all that just to say it's not as easy to increase production in the San Juan as it is in other places.

So it does -- the Mancos Shale obviously produces enough. We just brought on 100 million a day out of a 5-well pad, and it only declines by 60% or so. So it's not a traditional extremely high decline. So it could overwhelm the system if there was a tremendous amount of new drilling. I don't see that happening, but you're exactly right that it is through the end of the decade. And one of the things it is at the end of the decade, end of '29, whenever Energy Transfer plans to expand. Right now, we have another couple of Bcf a day of availability of takeaway. So I don't think we're very close to having an issue. But as the caveat is there's a lot of gas to be brought on.

[ id="-1" name="Operator" /> This now concludes our question-and-answer session. Thank you for your participation. You may disconnect your lines, and have a wonderful day.