Thank you, Rob. Welcome to Mach Natural Resources' fourth quarter earnings update.

Each quarter, we reiterate the company's four strategic pillars that have guided us since our founding in 2018. Since inception, the company has put a distinct emphasis on delivering exceptional cash returns through distributions.

We have distributed back to our unit holders a total of $1.3 billion starting in the fourth quarter of 2018 after our first acquisition, showcasing our consistent and dependable nature across a variety of commodity cycles. We also have remained a consistent distributor of cash to our unit holders post our public offering.

Mach has delivered distributions totaling $5.67 per unit from the beginning of 2024 through our last announced distribution of 53 cents. This is an annualized yield of 15%.

I doubt that you'll hear another energy company talk about cash returns. However, that is the lifeblood of our business and what makes us different.

Additionally, we have delivered an average cash return on capital invested of greater than 30% over the last five years and 23% in 2025 during a downcycle. Clearly, one of the best records of all public equities, not just energy.

Therefore, of our four pillars, maximizing distributions is the culmination of the other three and the most important. The second pillar is disciplined execution.

Mach has never acquired an asset by paying more than PDP PV-10. In other words, all the blue sky of the company, the acreage, midstream, equipment, offices, are part of our purchase price.

We have accomplished this goal 23 times and do not see an end to the requirement. Through this method of deploying capital, we've been diligent in assembling a set of assets across the Mid-Con and San Juan Basin that have drilling opportunities that we did not have to pay for.

Most of our contemporaries are willing to pay millions of dollars per location when they buy into fashionable areas. What we have done is to buy in at least two areas that were seen as distressed when actually they were not.

Since 2018, we've spent $1.4 billion developing assets that others thought were worth zero while compiling acreage that now amounts to nearly 3 million acres. An additional luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash.

Currently, both the Mid-Con and San Juan are seeing renewed outside investment searching for drilling rights. Also, the deep Anadarko is the only place we've expended capital to lease land.

The vast majority of our acreage is held by production from the purchases that we've made. We will test the market and see if we can recoup any of our costs for acreage, seismic, and other expenses associated with the deep Anadarko.

As I mentioned, the San Juan is also now very active with additional sales processes which are paying for upside where we did not. However, our land in the San Juan is all held by production, and we are not in any hurry to sell there.

We've done extremely well buying distressed properties, then finding them not in distress sometime later. For example, the Sabinal purchase, which closed last September, was bought when the market was certain we would see oil prices below $50.

We believe that anytime you can buy stable crude production in the $60s, you'll be rewarded at some point. This philosophy also drives our hedging decisions.

We hedge 50% of our production in year one and 25% in year two on a rolling basis. We want to lock in near-term cash flow while having exposure to higher prices in the future.

We have a strong belief that our business will be critical to the world over the next few decades, and prices will have the tendency to rise faster than the rate of inflation during this time. Our peers have moved to asset-backed securities to purchase production, which takes away future upside and introduces risk from higher prices rather than reward.

During the last year, we moved from drilling oil-dominated assets in the Oswego and condensate window of the STACK to dry gas locations in the deep Anadarko and San Juan. Our reasoning is simple: the Bloomberg fair value price for West Texas Intermediate crude oil was 71.72, $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 2020 in 2026, our drilling is once again concentrating on drilling natural gas wells in the San Juan and deep Anadarko through the first half of this year.

However, we are now preparing to bring back an oil rig in the Oswego and associated oil areas in the last half of 2026 if crude prices remain elevated. As you can see in the presentation updated this morning, Oswego drilling program is very good.

Since 2021, we've drilled and completed more than 250 Oswego locations, which have consistently had rates of return above 50%. We also have locations in the Red Fork, Sycamore, and Osage that can be added to our drilling schedule.

Therefore, we will plan to reduce the deep Anadarko capex by moving from two rigs to one rig and bring back on the Oswego program if the market allows. The flexibility to choose which commodity to produce depending on the price is one of the hallmarks of our company.

The third pillar to discuss is disciplined reinvestment rate. Our goal is to return as much cash to our unit holders as possible while staying within the guidelines of our strategic principles.

We target a reinvestment rate of no more than 50% to maximize the 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's difficult to accomplish, especially with a set of assets that at the time of purchase were not supposed to have any upside value. However, we have not only accomplished this over the past eight years, but have thrived by drilling very high rates of return projects.

In 2024, we projected our rate of return on drilling projects to be approximately 55%. In 2025, we made the move from oil to natural gas to maximize the rate of return in a difficult price environment.

We succeeded by delivering rates of return of approximately 40%. Since our last earnings release, we have brought on production three three additional deep Anadarko locations.

These three locations combined for approximately 40 million cubic feet of gas per day. In the deep Anadarko, we anticipate an estimated ultimate recovery of approximately 19.5 Bcf, or 6.5 Bcf per mile of lateral.

We believe ranges will be between 5 to 8 Bcf per mile of lateral. The deep Anadarko is located, as the name implies, at a true vertical depth of between 14 to 17,000 feet.

Drilling an additional 15,000 feet of lateral projects make total depth between 29 to 32,000 feet. Our costs to drill and complete are projected to be between $14 to $15 million per location.

In the San Juan, we plan to drill seven to eight dry gas Mancos wells. The true vertical depth of the Mancos is approximately 7,000 feet, and laterals are projected to be a mixture of two and three miles.

A three-mile horizontal lateral Mancos well is projected to cost $15 million and recover approximately 24 Bcf of reserves with a 60% first-year decline. Our goal is to lower the drilling and completion costs to approximately $13 million during the 2026 drilling season.

The drilling season starts on April 1st and runs through the end of November. The fourth pillar to discuss is to maintain financial strength.

Our long-term goal is to have a debt-to-EBITDA ratio of one times. When we're at that level of leverage, we start to look for additional acquisitions that fit the pillar of disciplined execution.

This is a self-imposed guideline to provide financial strength in any commodity price environment. Keeping our leverage low also enables us to flex upwards, as we did for the transformative Ikehav and Sabinal acquisitions that closed in Q3 2025.

By maintaining low leverage, we can toggle between drilling and acquisitions when opportunities arise in either direction. Currently, during a time when we're not looking to make an acquisition, we can maintain our production levels through drilling due to our low corporate decline of 17%.

In other words, we do not have to make any acquisitions unless they fit within the parameters we have set to achieve our goal of maintaining production while deploying only 50% of our operating cash flow while sending home all of our excess cash. We continue to believe in the long-term value of oil and natural gas.

Our acquisition strategy continues to achieve the results we desire. We believe in patience and resilience.

Rushing and forcing outcomes may not yield the best results. It is often good to remind oneself to remain calm and persistent while waiting on our desired outcome.

As the proverb says, "Good things come to those who wait." I'll turn the call over to Kevin to discuss financial results.

Thanks, Tom. 2025 year-end reserves, capturing the results of 2025 drilling and acquisitions during the year, more than doubled from 337 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 77 cents per BOE.

We ended the quarter with $43 million in cash and $338 million of availability under the credit facility. Total revenues, including our hedges, which contributed $42 million, and midstream activities, totaled $388 million.

Adjusted EBITDA was $187 million and $169 million of operating cash flow, and development capex of $77 million, or 46% of our operating cash flow. Full-year 2025 development costs of $252 million represented 47% of our operating cash flow.

In the quarter, we generated $89 million of cash available for distribution, resulting in a distribution of 53 cents per unit, which was paid out yesterday. Rob, I'll turn the call back to you to open the line for questions.

Morning, guys. Tom, nice details this morning.

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

Neal, I think right now if we have one rig running for the last half of the year, it's only going to spend about $25 million. I would love for prices to stay where they are and give us a little more operating cash flow and maybe bring on another oil rig to drill some of the Red Fork locations that we had or even the southern Oklahoma assets that we've not yet been able to get to because of lower prices after making the Flycatcher acquisition.

If we could, it all depends of staying within our 50% of operating cash flow. If our cash flow can move up a bit, we would put maybe a second rig in and out to be bringing on more oil if it's staying in the $70s.

As during anytime oil's up in the $70 range, we make very good rates of return and are competitive with our Ikehav and deep Anadarko gas wells.

Great, great details. Then just secondly, maybe a bit early on, prices haven't been terribly high yet for just a couple of weeks, if you've seen anything in the M&A market.

Sometimes spreads start to widen when we see periods like this. Is it early, are you still seeing opportunities, maybe just any generalities you can sort of comment around the M&A market?

We're pretty much on the sidelines for M&A until we move down our debt. We need to move from the 1.3 times leverage we have today down to a turn before we really start looking to bring on any more debt to make any acquisitions.

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.

Also, if we did in the deep Anadarko, we'd be able to keep two rigs working and have just less working interest and still cut back our costs, remembering that we're going to spend over a couple hundred million dollars this year drilling wells there. To answer your question directly, we're not really in the market looking, and really we're never competitive for these larger transactions that are going on just because the amount of debt that it requires for us to be competitive.

What we can do is buy a larger transaction by using some equity and some debt, and we hope to be back in the market here this year as we pay down our debt.

Could you monetize midstream to get that debt down quicker?

Oh, we could, but then you just pay for it in the longer run. The midstream systems that we've paid nothing for give us a good string of cash flow.

I personally don't like to sell those off just because over the long term, they're good for the company.

Thanks so much.

Thank you.

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

Thanks, Derrick.

In your prepared comments, you seem to highlight the desire to monetize assets across the portfolio that could be experiencing a rerating 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 opportunity set you have?

I'd like to. I don't really know what size we're talking about because we haven't really negotiated anything.

What I'd love to do is pay down some debt so that we can get back in the acquisition market without affecting our distributions. Obviously, there are three ways that we can bring our debt down, the EBITDA would be prices moving up.

That's a simple way and it's happening now. Then, along with that, you could cut your distributions back and pay down debt that way, which is not our preference, or we could sell some non-EBITDA generating assets.

The deep Anadarko is the only area that's not HBP and has leasehold that has some term on it, it seems like the most likely place that we would sell some acreage. The size, I can't really say.

We'll know here very quickly, but it has to be significant, or else we would just do it ourselves.

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

We're about 50,000 acres, which is all we want if we're not going to bring in a partner. We can effectively drill that out over the time of our term on the leasehold.

If we don't bring in a partner, we will not spend more in the second half of our leasehold on capex. That's the way we look at it is whether to bring in a partner and have some additional acreage that will be putting on and drilling more wells over the course of the next five years, or we'll just stop where we are and drill out what we have.

Makes sense. Maybe just shifting over to operations, I wanted to focus on your recent deep Anadarko and Mancos wells.

With the benefit of a few at-bats in these formations, could you speak to how you performed against pre-drill expectations and some of the levers you're planning to pull to drive lower completed well costs?

The first few wells that we drilled in the deep Anadarko were better than anticipated. The last three, I think, are right on our type curve.

I would say it's performing as expected. The Mancos is just better than expected.

I think it's a world-class reservoir. Too much money has been spent on drilling and completing wells there over the past.

I believe the Mancos will be our highest rate of return project as soon as we lower some costs, and I'm confident that our team will be able to do that.

Perfect. Great update today, guys.

Thank you. Just expanding on it, there's just no reason that a Mancos well at 7,000 feet and an easy shale target to drill should cost more than one of the most difficult wells to drill in the country in the deep Anadarko.

I just don't believe it will.

Good morning, Tom and Kevin and the rest of the team there. Tom, I wanted to ask about the Oswego and I guess maybe two questions about the Oswego.

First, I think you addressed this, but just to make it clear, what oil price would you need to see, or do you need to see, to make you want to go forward with that rig in the back half of the year targeting the oily Oswego?

Even right now the Oswego competes with the deep Anadarko from rate of return. I think anytime that you have oil above $70, we're have rates of return well north of 50%.

That meets the requirement of having capital shipped to it. What we should do in a market like that is to distribute out to all three: the deep Anadarko, the Mancos, and the Oswego.

That's what we're attempting to do.

Got it. Thank you for that.

I think, Charles, to look at our Oswego program and say what we can achieve, if you look at an old presentation of ours in 2024, we show everywhere we drilled, and then we show everywhere we drilled in 2025. The Oswego wells are equivalent overall, but just a higher rate of return in 2024 due to pricing.

The wells are not consistent. You have good wells and bad wells, as you do everywhere.

Overall, you get a very consistent return.

Right. That's actually a good leading to my follow-up question because that's one of the things that I noticed on your slide 14 is that there's a wider variance on those Oswego wells.

Something I know we've spoken about before, but I wondered if you could tell me these four really fabulous wells on the left side of your skyline chart here, are those all in the same section? Really what I'm getting at is, are there sticks on the map for you to come in and lay some wells in the back half of '26 that they're right alongside some of these four really fabulous ones?

It's as in all things, they're a little more complex. We're drilling with inside of a field that has vugular porosity and algal mounds, you have different thicknesses.

Wells even they're fairly close together can have a different amounts of porosity that has either been drained or not drained. In the past, what we've seen is that if you stay 660 feet apart, you really don't have interference across the play.

You just don't know until you drill a well. You can stay within the system and you can feel very comfortable that you're going to have some really good wells like this.

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.

They can be right next to each other, or they can be in different sections. To answer your question, yes, we have many, many locations left to drill.

I feel comfortable that they're going to be north of 50% rates of return once we get the program done. I can't tell you which ones are going to be 200%.

Got it. Thank you, Tom.

You bet.

Hi, good morning. I wanted to ask on your guidance.

You included wider differentials on natural gas and seems like there's ample takeaway capacity in both the Mid-Con and San Juan. Can you talk about what caused you to make that change and what are you seeing in those local markets, and maybe tie that into how you're feeling about the gas macro in general?

I love gas macro in general, I can start with there. We are seeing widening basis in the Anadarko and the San Juan, alls we do is try to estimate from the past what we've seen and bring that into the future.

Do I personally believe the San Juan, for example, is going to be wider going forward? I don't.

I think the same reasons that you have warm weather in the West has caused basis to widen, 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.

Then I think that the takeaway it isn't an issue. If you look back over five years in the San Juan, the production's the same.

It's not driven by oversupply to increase or loosen the basis. The same way in the Anadarko, we're not seeing this from a supply perspective, it's just a weather and for a fairly warm winter that is widened basis, in my opinion.

Appreciate that, Tom. Thanks.

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 three-mile laterals, I think, with less proppant per foot than what has been done there previously. I wanted to just see how those are performing now that you've had a little bit more time to look at them relative to the other wells in the play.

They're the same. It's not a lack of proppant either.

We're still using 2,000 pounds a foot. It's just that others have been using more, which, in my opinion, I don't think is needed.

We could probably use less than we do, but where we're going to save money is not only on how much proppant we use, but just the focus on saving. Just really looking at the best ways to transport sand and chemicals and rig costs, and just, in my opinion, the San Juan, over the course of time, has been run by majors who spend too much money, and we need some independents in here to cut costs.

No different than it would be if a major was trying to drill in the Anadarko Basin; they just can't do it as well as we can. I think we'll save money just by watching what we do.

Sounds good. Thank you, Tom.

Thank you.

Thanks. Good morning.

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

Yeah.

Hey, John. This is Kevin.

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

We've captured both components of that in the new guidance, and they're offsetting, but it does improve midstream operating profit.

Thanks for that color, Kevin. Then just one quick one from me following up.

Are y'all looking to take advantage right now of what we've seen on the oil move by adding more hedges, or are y'all sort of kind of waiting to see how this plays out?

If you look in the back of the curve, really anything outside of the next 3 to 6 months, the curve falls off fairly quickly. No, I like having access to commodity movement, and so we don't want to be more than 50% hedged in year one and 25% in year two.

We use that as mainly a mechanical hedge just to guarantee cash flows. If, for example, we had no debt, like we did in 2023, we wouldn't have any hedges on.

I want exposure to the curve.

Thanks, Tom. Appreciate it.

Thank you, John.

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

It did not.

Perfect. Thanks.

For my follow-up, it looks like you guys, I think, last call were planning some Fruitland Coal wells as well for '26. It looks like those have been removed.

Is that just a function of the bullishness you guys have of the Mancos, or were there any other factors playing into that?

Both. I'd said 7 to 8 wells in the Mancos.

If we can pull in another well in the Mancos, we'd like to do that. Our Fruitland Coal is a very good reservoir, consistent reservoir for us to drill.

It will be easier next year in 2027 program to bring on more of those. Again, it's all associated with how much operating cash flow we have.

The restriction to any of this, we have too many locations that are good and not enough operating cash flow.

Not a bad problem to have. I appreciate the time.

Thank you.

Thank you.

Thanks, Rob.