Mach Natural Resources LP Common Units representing Limited Partner Interests (MNR) Q1 2026 Earnings Report, Transcript and Summary

Good morning, everyone, and thank you for joining us, and welcome to Mach Natural Resources LP First Quarter 2026 Earnings Call. During this morning's call, for the reconciliation from non-GAAP financial measures to the most directly comparable GAAP measures, please reference the press release and supplemental tables available on Mach Natural Resources LP’s website and their 10-Q, which will also be available on their website when filed. Today’s speakers are Tom L. Ward, CEO, and Kevin R. White, CFO. Tom L. Ward will give an introduction and overview, Kevin R. White will discuss Mach Natural Resources LP’s financial results, and then we will open the call for questions. With that, I will turn the call over to Tom L. Ward.

Thank you, Daryl. Welcome to Mach Natural Resources LP’s 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 have proven significant upside exists. Each year, Mach Natural Resources LP publishes every well we have drilled and the overall IRR based on the year’s price for oil and gas. We have averaged approximately 50% rates of return on our drilling program since it started in 2018. Said another way, we have invested more than $1.3 billion in properties that others would give no value to and returned excellent results. You can see 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 March 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 in chasing growth with high debt. 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 it would be hard to purchase any viable drilling locations without paying for upside. However, as we review our potential 2026 locations, we are drilling on acquisitions from XTO, Paloma, Cheyenne, Flycatcher, Sabinol, 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 Natural Resources LP 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 reinvestments. In 2026, a move down in natural gas is being offset by a move up in oil prices. Mach Natural Resources LP has a 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 Oswego formation in Kingfisher County, Oklahoma. This is an area that is well known to us. We have drilled more than 250 Oswego locations since 2021 with very good results. In the presentation, we are showing that at $75 flat oil, the changes in 2025 Oswego rates of return move from 39% to 90%. At $85 flat oil prices, the program returns move 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 rig in the Clear Fork formation from the Sabinol 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 MMcf of gas per day while our 15 Bcf gas type curve is projected to be 10.6 MMcf of gas per day. In the San Juan, we have 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 five years. We have 575 thousand acres that are held by production that 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 alongside 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 MMcf 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 volumetric production contract that runs through 2030. Given our limited drilling program, we can keep our production in the San Juan flat at approximately 300 MMcf of gas per day. We currently have approximately 65% of the volumes from the San Juan on this contract at a price of $1.72. If basis continues to be low, we have an effective hedge, and if basis moves higher, we will benefit from our drilling program as the production payment amortizes. This is one of the larger volumes of natural gas headed to the growing Western markets as they develop. Mach Natural Resources LP 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 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 iCAV and Sabinol acquisitions last September have moved our leverage up to approximately 1.3x. 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 is 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 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 they are a pebble in my shoe that I would 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 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 five years. I believe we are in rare air here. Only a few tech companies can match our CROCI. We have also averaged a 15% yield since 2024. Both are industry leading. I will now turn the call over to Kevin R. White for the financial results.

Thanks, Tom. The quarter, our production of 158 thousand BOE per day was 16% oil, 70% natural gas, and 14% NGLs. Our average realized prices were $69.73 per barrel of oil, a 20% increase from the 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, it is 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 $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% 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 per unit, which will be paid on June 4, 2026 to holders of record on May 21, 2026. With that, Daryl, we will turn it back to you.

We will now open the call for questions.

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

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 is maintaining oil production rather than continuing to see a decline.

That makes sense. And then the second one, your low CapEx requirements continue to impress. I want to understand if there is inflation built into that or maybe built into your LOE given some cost changes we are seeing as a result of the Iranian conflict. Do you have some of that locked in with your vendors and maybe over certain durations?

We do not have anything really locked in. We can move rigs at 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 why it is important to move quickly before inflation hits. As always, oilfield services’ job is to get our rates of return down to 20%, and we want to drill wells that still have high returns. In fact, the lowest we have on the 4/30 curve of the oil wells we will be drilling this year as of the 4/30 curve was 80%. So it is really just chasing the best areas and spending CapEx as our operating cash flow allows us to. The goal of the company is that we will allow growth if it happens, like if prices move up, but not spending more than 50% of our operating cash flow. So it is not that we are restricting growth; our high rates of return allow us to grow by spending less, and that is what we anticipate continuing to do. Remember, that is really because of all the assets we bought during the darker days. They continue to throw off free cash flow. Anytime you are making acquisitions at $20 oil, it pays big dividends in later years. We will reap those benefits for decades.

That makes sense. Sounds like you are staying flexible. Thank you, guys.

Thank you. Our next questions come from the line of Michael Scialla with Stephens. Please proceed with your questions.

Good morning, guys. With the new plans, do you maintain your guidance, and 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. When would you make that decision if you do decide to hold off on completing those wells?

We are going to delay—we are planning on delaying the Mancos—but go ahead, Kevin.

Sure, just to answer your question around guidance, we think the CapEx guidance holds. As you noted, as we shift to oil, we may actually see an acceleration of production versus spending the CapEx on gas drilling, particularly in the Mancos. We will look to revise guidance as we move to the oil program, probably midyear if and when it is appropriate. As we look at the model, 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 is not that hard of a decision. Usually, once we spend the capital to drill a well, I would want 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 is just really difficult not to defer the gas whenever basis today in the San Juan is low. We think it will improve, but still we do not want to just guess going into the winter. So we will probably move that until after the first of the year. Then in the Mancos it will really depend on weather for when we can frac. We cannot do anything on the New Mexico side until April, I believe, but we can on the Colorado side as long as we are on the Southern Ute Tribe, weather permitting. And sorry, Mike, if I did not catch all your questions, please ask again.

That addresses it. It sounds like even with the shift, there is no change to CapEx; it is going to remain the same. You probably anticipate some minor shift in mix of production and certainly leave some upside for cash flow with the higher oil mix. I wanted to follow up on the Mancos. The five wells that you completed last year, it looks like they are performing extremely well. I think iCAV completed a couple of those and you guys completed three of them. Did you, in fact, cut back on the proppant on the wells that you completed? You had said you felt like they were being overstimulated and you could save some money there. Did those results play out the way you thought?

We did not change the amount of proppant that was used. iCAV did use—and we will use—less proppant than the industry was using earlier. I think that is the direction we are moving. In the San Juan in general, there were proppant sizes up to 3 thousand pounds per foot; we were using closer to 2 thousand pounds, and I think it was totally adequate. We were able to save some money even last year through a few other different methods, but not in the proppant size.

Okay. So that line of sight to savings—what did you save per location?

I think we are saving about $1 million per location.

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

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

Yes, I feel good about something lower, but we will see. Yes, I feel good about $15 million. There is no reason to spend $15 million drilling these wells.

Sounds good. Thank you, guys.

Thank you. Our next questions come from the line of Jeffrey Grampp with Northland Capital Markets. Please proceed with your questions.

Good morning, thanks for the time. Tom, a question on the distribution strategy. It seems like in recent history you have been comfortable maintaining the 100% payout with current leverage mid-1x, but the pebble-in-your-shoe comment makes it seem like perhaps you are reconsidering that just to retain some cash for debt paydown. Is that a fair comment, and 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 the EBITDA goes down as oil prices have moved. If oil prices move higher and gas goes where I think it will, it naturally takes care of itself. Private credit really likes us because we have so much free cash flow. If you have a 19% yield and you might get 10% for a while as you pay down debt, it is not the worst thing. But I am a holder just like the rest of the unitholders, and I like having Christmas four times a year.

Fair enough. For my follow-up, it sounds like the bias based on today’s commodity price dynamic is to defer those gas completions and add that Clear Fork rig. When are you targeting potentially adding that Clear Fork rig, and is it as simple as looking at gas and oil prices over the next few months and the strip to make that decision?

We have fairly well made it—just yesterday. The Clear Fork is clearly superior rate of return at today’s prices than completing the Mancos. We could start that July 1 and have kind of a 30-day turnaround. So more than likely, unless something changes fairly dramatically between now and a month from now, we will delay the Mancos and bring on a Clear Fork rig.

Got it. Understood. Thank you, guys, for the time.

Thank you. Our next questions come from the line of Carson Coronado with Raymond James. Please proceed with your questions.

Good morning. Are you going 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-ask spreads potentially widening?

I do not think it is any harder to get deals done in the ones that we have a niche in, which is really staying away from asset-backed security projects where they can fund. Larger deals are not so good, and areas where you pay for a lot of upside are not so good, like the Marcellus or Haynesville or now even the San Juan. The areas where we are pretty good are assets that are $100 million to $300 million in size that others are not chasing, where we can see some distress for whatever reason. It might be that gas goes to Waha where an ABS really cannot go in and hedge very well over a period of time and they cannot compete with us. There is 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 million to $300 million acquisitions. We can be more aggressive—not on paying for upside—but more aggressive in size if the seller would want to take equity. That is the only way we could really compete in size right now.

Thank you. I also had a follow-up question on maintenance CapEx. The low decline rate helps keep 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 is appropriate. If we are measuring based on volume, then when we are drilling gas wells, there is more volume that comes into the system, and if we are drilling oil wells, the equivalent volume is a little bit lower. But as you mentioned, our base decline rate is probably among the lowest, if not the lowest, among the independents. That gives us the ability to essentially stay the same size, grow a little bit, or shrink a little bit based on just half of our operating cash flow after interest. I would largely equate our guidance CapEx with being kind of maintenance CapEx, if not a little bit more productive than CapEx.

Yes, that is right. Our drilling program is designed to keep our production flattish. That could be down three or four to up three or four percent depending on what prices are. You will not see tremendous growth from drilling; that allows us to distribute more back to unitholders.

Great. Thank you.

Thank you. Our next question comes from the line of Ron Sanchez. Please proceed with your questions.

I was wondering what your average breakeven price on natural gas would be, and do you have hedging?

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

Thank you.

Thank you. Our next questions come from the line of Derrick Whitfield with Texas Capital. Please proceed with your questions.

Good morning and thanks for taking my questions. Going back to your 4Q commentary on divestitures, does the current higher crude price environment 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 do not know if that is going to happen or not. We did go out to a few parties. Gas prices have been lower. I am not sure that we would get paid enough to give up any production that is already flowing now, and I am not really a seller at today’s gas prices. So it becomes harder to do until prices move. We really were not looking at selling any oil projects. It was more around whether we could sell some non-EBITDA-generating assets like leases in order to pay down some debt. I doubt that happens, but we will know more next quarter.

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

Yes. 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 will 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 is great. One more on service cost. Could you speak to what you are seeing in the Anadarko at present and your expectations if oil prices remain elevated?

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 Cal ’27 strip of $72, that is 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. We can move in several rigs and drill different locations across Western Oklahoma and in the Permian. It is really price dependent, but it is 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, the Anadarko Basin. Like our production, it will pay dividends to us for decades.

And on service costs specifically in the Anadarko if we remain in this higher oil price environment?

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

Great update. Thanks for your time.

Thank you. Our next questions come from the line of Charles Meade with Johnson Rice. Please proceed with your questions.

Good morning, Tom and Kevin. Tom, you mentioned four oily plays today: the Oswego, which you gave a lot of detail on, the Ardmore (really more the location than the play), the Red Fork, and the Clear Fork. 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 is a Mississippian member of the SCOOP in what we call the Ardmore Basin at the Sho-Vel-Tum field, basically in Stephens County, Southern Oklahoma—that is going to have very, very high rates of return at today’s oil price. They are fairly deep, expensive wells, but very good. Continental has most of that area, and maybe a private company, Citadel, as well. It is very good. We only have three locations to drill there, so then we look to have consistent operations elsewhere. The next best is the Oswego, and that is more consistent, and we have dozens, if not hundreds, of locations left to drill in the Oswego. We could even move from Stephens County after we complete those wells to two rigs in the Oswego if oil prices remain elevated. Then the Clear Fork, which we picked up from Sabinol, would be number three, and as I mentioned, we have a rig going there in July. Lastly, because it is a little more gassy, is the Western Oklahoma Red Fork, and if gas prices were to move up, it could move up in the hit parade. But today, that would be our fourth of four.

That is great detail, Tom. Even there, the Red Fork is going to be about 80% rates of return?

Yes.

My follow-up is on San Juan Basin supply, demand, and marketing. When you bought that asset from iCAV, you gave a lot of detail about where that gas can go and the options. Prices are pretty tough out there right now, and a lot of gas wants to get to the Gulf Coast, but you have Permian and Waha between you and the Gulf Coast if you wanted to go that way. What are the dynamics we can watch that would signify or be precursors to more favorable pricing in that basin?

Yeah, I mean—

At the time we bought the iCAV assets last summer and closed in September, I would not have thought that our basis hedge was a benefit. We have 65% that we bought on a long-term contract from BP that expires in 2030, effectively at $1.72. Since that time, really due to weather—winter not coming to the West—basically we almost stand alone among public companies in the San Juan in having low basis. Now our realized price has hovered around a dollar in what we receive. I do think that is coming back. To answer your question, it is really more pipe getting out going West, having a larger LNG facility in Mexico, and getting gas to Asia via LNG. That all happens over time. It is pretty good for us now that we did not have to pay up for that gas—we bought it at $1.72 or less. As it amortizes over time, that gives us time for the LNG market to expand, which I believe it is going to. There is a new pipe going across the Navajo Nation that I believe will be FID’d, and along with that, getting gas to the data center buildouts and Southern California, especially the Phoenix market, which seems to be expanding. There is some interest in getting our gas farther West into the upper Western markets and even into the Pacific Northwest. There will be expansion of gas coming out of the West, and really between Hilcorp and us in the San Juan, we control the vast majority of it. It is a good place to be as long as you are patient. It is a five-year program.

Got it. That is great detail. Thank you, Tom.

Thank you so much. We have reached the end of our question and answer session. This concludes our call. We appreciate your participation. You may disconnect your lines at this time and enjoy the rest of your day.