Mach Natural Resources LP (NYSE:MNR) Q3 2025 Earnings Call Transcript

Mach Natural Resources LP (NYSE:MNR) Q3 2025 Earnings Call Transcript November 7, 2025

Tom Ward: 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.

Q&A Session

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.

Kevin White: 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.

Neal Dingmann: 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?

Tom Ward: 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.

Neal Dingmann: 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?

Tom Ward: 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.

Charles Meade: 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?

Tom Ward: 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.

Charles Meade: 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?

Tom Ward: No, that’s it. [ id=”-1″ name=”Operator” /> The next question is from Derrick Whitfield of Texas Capital.

Derrick Whitfield: 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?

Neal Dingmann: 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.

Tom Ward: 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.

Derrick Whitfield: 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?

Neal Dingmann: Do you want to take?

Tom Ward: 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.

Derrick Whitfield: 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.

Michael Scialla: 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.

Tom Ward: 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.

Michael Scialla: 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?

Tom Ward: 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.

Michael Scialla: 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.

John Freeman: 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.

Tom Ward: 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.

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

John Freeman: 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?

Tom Ward: 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.

Jeffrey Grampp: 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.

Tom Ward: 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.

Jeffrey Grampp: 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?

Tom Ward: 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.

Geoff Jay: 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?

Tom Ward: 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.

Geoff Jay: 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?

Tom Ward: 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.

Timothy Rezvan: 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.

Kevin White: 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.

Tom Ward: 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.

Timothy Rezvan: 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?

Kevin White: 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.

Timothy O’Toole: 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.

Tom Ward: 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.