Thank you, Darryl. Welcome to Mach Natural Resources' first quarter earnings update.

Each quarter, we reiterate the company's four 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've proven significant upside exists.

Each year, Mach publishes every well we've drilled and the overall IRR based on the year's price for oil and gas. We've averaged approximately 50% rate of return on drilling program since our program started in 2018.

Said another way, we've invested more than $1.3 billion in properties that others would give no value to and returned 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 at first.

We called it the stages of grief. Ultimately, we did not deal with management teams, but their lenders, either through forced 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 post the 2022 run-up in prices, that it 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, Sabinal, and IKAV, 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 our 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, move down in natural gas is being offset by a move up in oil prices.

Mach has a unique ability to react to these commodity price changes by pivoting from one commodity to another to maximize rate of return. Therefore, we have prioritized our drilling schedule to take advantage of these price changes.

Starting May 1st, we moved in our first rig to start drilling for oil in the Oswego 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 at $75 flat oil, that changes in 2025 Oswego rates of return 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 Ardmore Basin assets that we acquired from Cheyenne and Flycatcher 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 three 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 Clear Fork 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 five wells with more than 90 days of production in the deep Anadarko. These five 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 one rig working drilling Mancos 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 and can be developed at any time the market allows. Currently, we will drill seven 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 five 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 IKAV, 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 at 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 if basis moves lower, we will benefit from our drilling program in 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 1 times.

The IKAV and Sabinal acquisitions last September have moved our leverage up to approximately 1.3 times. Our goal is to move that ratio back to our desired level 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 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 ratio 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 available for distribution to maintain the status quo. Our goal is to not move away from our current method of distributions 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 in my shoe that I'd prefer to move away from and get back to 1 times 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 two ways: our company has had a cash return on capital invested of more than 20% every year since our inception.

We have averaged 35% CROCI over the last 5 years. I believe we are in rare air here.

Only a few tech companies can match our CROCI. 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% NGLs.

Our average realized prices were $69.73 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%, 45% for gas, and 13% for NGLs.

On the expense side, worth pointing out, our lease operating expense was $101 million, or only $7.12 per BOE. Cash G&A was approximately $5 million, or only 37 cents 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% of our operating cash flow after interest. In the quarter, we generated $107 million of cash available for distribution, resulting in a distribution of 64 cents per unit, which will be paid on June 4th to holders of record on May 21st.

With that, Darryl, we'll turn it back to you to open the line for questions.

Wanted to see if your shift back to the kind of oilier Oswego drilling program, how quickly can that move the needle? You may be 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. It basically keeps our oil production from declining by moving to the oil side of the business.

We might grow a percent or so a year, but really it's maintaining oil production rather than continuing to see a decline.

That's perfect. That makes sense.

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 maybe over certain durations?

We don't have anything really locked in. We can move rigs at really 30 to 45-day intervals.

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 service's job is to get our rates of return down to 20%. In fact, the lowest we have on the 4/30 curve of the oil wells we'll be drilling this year for the 4/30 curve was 80%.

It's really just chasing the best areas and spending CapEx as our operating cash flow allows us to. I think that the goal of the company is that we'll allow growth if it happens, like if prices move up, but not spending more than 50% of our operating cash flow.

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 continue to do.

Remember that that's really because of all of 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. Sounds like just staying flexible.

Thank you, guys.

Thank you.

Morning, guys. 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?

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?

Sorry. I think did you hear the question?

I don't think I caught everything. We're planning on delaying the Mancos, but go ahead, Kevin.

Sure, Mike, just to answer your question around guidance. 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.

We'll look to revise guidance as we get moved to the oil program probably mid-year if and when it's appropriate. It does, just as we look at the model, those cycle times on these wells are shorter than some of our deep gas drilling, it should actually help this year's cash generation.

Yeah.

It's not that hard of a decision. Usually I would want to, once we spend the capital to drill a well, to not leave it as a DUC, but whenever we can move to a Clear Fork location that at today's prices is going to have a 100% rate of return, it's just really difficult not to defer the gas whenever basis today at the San Juan is low and we think it'll improve, but still we don't want to just guess going into the winter.

We'll probably move that until after the first of the year. Then it will really depend in the Mancos what weather provides us to 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 Ute tribe, weather permitting. Sorry, Michael, 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, the CapEx is going to remain the same.

We probably anticipate some minor shift in the mix of production is what it sounds like, and certainly leaves some upside for cash flow with the higher oil mix.

That's correct.

Wanted to follow up on the Mancos. The five 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 IKAV completed a couple of those, and you guys completed I think three of them. 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 wanted to see if those results played out the way you thought.

We did not change the amount of proppant that IKAV was using. Now, IKAV did use, and we will use, less proppant than kind of the industry was earlier.

I think that's moving towards what we're going to do. If you look at the San Juan in general, there were proppant sizes up to 3,000 lb a foot, that we were using closer to 2,000 lb, and I think it was totally adequate.

That we were able to save some money even last year just through a few other different methods, but not in the proppant size. I think we're saving about a million dollars per location.

Yeah, $1.5 million per location just from our changes that we made, but it was not in proppant.

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

Oh, yeah, I feel good about something lower, but we'll see. Yes, I feel good about $15 million.

There's no reason to spend $15 million drilling these wells.

Sounds good. Thank you, guys.

Thank you.

Morning, guys. Thanks for the time.

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-1 times.

The pebble in your shoe comment makes it seem like perhaps you're maybe reconsidering that to retain some CAD for debt paydown. Is that a fair comment, or how do you think about payout ratio over the next few quarters?

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.

The reason private credit really likes us so well is because we have so much free cash flow. If you have a 19% yield, and you make a 10% for a while as you pay down debt, it's not the worst thing, but I'm a holder just like the rest of the unitholders, and I like having Christmas four 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 add that Clear Fork rig. I just wanted to dive into that a bit more.

When are you guys kind of targeting potentially adding that Clear Fork 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?

Pretty well made it. That it was just like yesterday.

The Clear Fork is clearly superior rate of return at today's prices than completing the Mancos. We could start that July 1st and have a 30-day turnaround.

More than likely, unless something changes really dramatically between now and a month from now, we'll delay the Mancos and bring on a Clear Fork rig.

Got it. Understood.

Thank you, guys, for the time.

Hi there. Good morning.

I just wanted to see if you all were going to continue to focus M&A in the current basins you operate in, or is there a willingness to step into new basins? Does the current commodity price environment make it harder to get deals done with bid-ask spreads potentially widening?

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. Larger deals we're not so good at, areas 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 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 an 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.

We want to move down our debt levels so that we can get back into making those $100 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. Thank you.

I'll set a follow-up question on maintenance CapEx. The low decline rate definitely helps keeping the reinvestment rate under 50%.

What would be a reasonable maintenance CapEx estimate for us to use?

I think looking at our existing CapEx guidance, really depending if we're measuring that based on volume, then when we're drilling gas wells, there's more volume that come into the system. If we're drilling oil wells, the equivalent volume is a little bit lower.

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. I'd largely equate our guidance CapEx with being kind of maintenance CapEx, if not a little bit more productive than maintenance CapEx.

That's right. Our drilling program is designed to keep our production flattish.

That could be up two, down two, up three or four, down three or four 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.

Great. Thank you.

I was just wondering, what would be your average breakeven price on natural gas? That's all.

Hedging?

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 again, it's among the best in the peers.

For us, as Tom's mentioned many times before, 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.

Thank you.

Good morning and thanks for taking my questions.

Sure.

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

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. It becomes harder to do until prices move.

We really weren't looking at selling any oil projects. It was really more around could we sell some non-EBITDA generating assets like leases in order to pay down some debt?

I doubt that happens, but we'll know more next quarter.

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

The Clear Fork is in Robertson County on the shelf, having a rig there depending on what our operating cash flow looks like and 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 by the first of the year.

That is in the Permian, and those wells are right at 100% rates of return.

That's great, sorry I didn't pick that up, Tom. I'm just joining the call late.

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?

If oil prices stay where they are, it would take a fairly high gas price to make us move back to drill gas wells. Last year that happened as oil prices fell, but today, even at the Cal strip, '27 strip is $72, that's good enough for us to keep rigs working.

The flexibility of 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. It's really just price dependent, but It's really astounding that we were able to put together 2 million acres without have to pay for it in one of the most oil and natural gas-rich basins in the world in the Anadarko Basin.

That is another like our production, it will pay dividends to us for decades.

Great. Tom, just on the service costs, what would your expectations be in the Anadarko if we remain in this higher oil price environment?

You say service costs? We're seeing bits are going up, steel's going up, labor costs are going up, fuel surcharges are going up.

We are starting to see the effects of inflation. We know from 2022 that that comes fairly quickly.

It'll all have to be put into the calculation for how much we can drill depending on what prices we're paying. We're still using our current AFEs.

We change AFE every month depending on where prices are. We price out for every well a series of wells we do.

We're fairly quick to react to both oil and gas prices and service costs.

Great update. Thanks for your time.

Thank you.

Morning, Tom and Kevin. I got dropped from the call for some reason, too.

Tom, you've mentioned four oily plays here today: the Oswego, which you gave us a lot of detail on, but also the Ardmore, which I guess is really that's more the location rather than the play, but the Ardmore, the Red Fork, and also the Clear Fork. 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 in those?

Sure. The Sycamore, which a Mississippian member of the SCOOP, in what we call the Ardmore Basin, Sho-Vel-Tum field basically, and Stephens County, Southern Oklahoma, that's going to have very, very high rates of return at today's oil price.

They're fairly deep, expensive wells, but very good. That Continental has most of that area and maybe a private company, Citadel.

We only have three locations to drill. Then 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.

We could even move from the Stephens County after we complete those wells to two rigs in the Oswego if oil prices remain elevated. Then the Clear Fork we picked up from Sabinal would be number three, and that as I mentioned, have a rig going there in July.

Then lastly, because it's just a little more gas, is the Western Oklahoma Red Fork. That if gas prices were move up, it could move up in the hit parade, but today that would be our fourth of four.

Even there, the Red Fork is going to be about 80% rates of return.

Got it. That's great detail, what I was looking for.

Excuse me. My follow-up is on San Juan Basin, I guess supply, demand, and marketing.

When you bought that asset from IKAV, 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. You think a lot of gas wants to get to the Gulf Coast, but you've got Permian and Waha between you and the Gulf Coast if you wanted to go that way.

That's, I guess, a long intro to say what are the dynamics that we can watch from our seats that would signify or could be precursors to more favorable pricing in that basin?

At the time we bought the IKAV assets last summer, going and closed in September, I wouldn't have thought that our basis our our hedge was a benefit. Basically we have 65% that we bought on a long-term contract from that BP has that expires in 2030.

That's that effectively is at $1.72. Then but, since that time, really due to weather, winter not not coming to the West, basically we almost stand alone in having the low basis of public companies with the San Juan.

The that now has, hovered around $1 of what we receive now. I I do think that's coming back.

To answer your question, it's really more more pipe getting out, going west, having a larger LNG facility in in Mexico getting gas. I think the Asian sales point will will be wanting more Western gas coming across the LNG to to Asia.

That all happens over time. It's really pretty good for us now that we didn't have to pay for that gas and and we bought it at $1.72 or less.

As it as it amortizes out over time, that gives us time to to not only have the LNG market expanding, which I believe it's going to. There's a there's a new pipe going across the Navajo Nation now, I believe, or will be FID'd.

Then along with that, getting gas to the data center build-outs in in Southern California, especially the Phoenix market, which seems to be expanding. There there's some interest in even getting our our gas to the west into more the the I guess the upper west Western markets and and even into the Pacific Northwest.

It there there will be an expansion of gas coming out of the West. Really between Hilcorp and us in San Juan, we control the vast majority of it.

It's it's a good place to be as as long as you're patient. It's it's a 5-year program.

Got it. That is great detail.

Thank you, Tom.

Thank you.