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Mach Natural Resources LP reported its third-quarter 2025 earnings, revealing a significant earnings per share (EPS) miss but a slight revenue beat. The company posted an EPS of -$0.28, falling short of the analyst forecast of $0.88, resulting in a negative surprise of 131.82%. Despite this, revenue came in at $273 million, surpassing expectations of $265.81 million, a 2.54% surprise. Following the earnings release, Mach Natural’s stock price dropped by 1.66% to $12.08, with further declines in premarket trading. This represents a stark contrast to the company’s last twelve months performance, where it achieved a positive EPS of $1.95 according to InvestingPro data. The company has maintained profitability over the past year despite recent headwinds in the energy sector.
Key Takeaways
- Mach Natural’s EPS fell significantly short of expectations, marking a substantial miss.
- The company reported a revenue beat, with actual figures surpassing forecasts by 2.54%.
- Stock price decreased by 1.66% post-earnings, with further declines in premarket trading.
- Strategic focus on natural gas production and cost-cutting measures were highlighted.
- CEO Tom Ward expressed optimism about nearing the end of a cyclical downturn in crude oil.
Company Performance
Mach Natural Resources experienced mixed results in Q3 2025. While the company managed to exceed revenue expectations, the substantial EPS miss highlights challenges in profitability. The company remains focused on natural gas production, with significant developments in the Deep Anadarko and San Juan basins. Mach Natural’s strategic initiatives, including cost-cutting measures and production efficiency, are aimed at maintaining competitive positioning in the energy sector.
Financial Highlights
- Revenue: $273 million, a slight increase from forecasts.
- Earnings per share: -$0.28, a significant miss compared to the forecast of $0.88.
- Adjusted EBITDA: $134 million.
- Operating Cash Flow: $106 million.
- Cash Available for Distribution: $46 million.
Earnings vs. Forecast
Mach Natural’s Q3 2025 EPS of -$0.28 was a stark contrast to the forecasted $0.88, resulting in a negative surprise of 131.82%. However, revenue exceeded expectations by 2.54%, with actual figures at $273 million compared to the anticipated $265.81 million. This earnings miss represents a significant deviation from previous quarters, where Mach Natural had generally aligned more closely with forecasts.
Market Reaction
Following the earnings announcement, Mach Natural’s stock price fell by 1.66% to $12.08. The stock continued to decline in premarket trading, reflecting investor concerns over the substantial EPS miss. The stock’s performance is currently closer to its 52-week low of $11.50, indicating a challenging market environment for the company.
Outlook & Guidance
Mach Natural remains optimistic about its future prospects, with a strategic focus on natural gas production. The company has hedged over 60% of its natural gas for 2026 and anticipates increasing distributions throughout the year. Additionally, Mach Natural has reduced its 2026 capital expenditure by 18% while maintaining production levels, signaling a commitment to cost efficiency.
Executive Commentary
CEO Tom Ward stated, "We continue to believe that we are nearing the end of a two-and-a-half-year cyclical downturn in crude oil," reflecting optimism about the market’s recovery. Ward also highlighted the company’s strategy of acquiring assets that provide free cash flow at distressed prices, emphasizing a focus on long-term value creation.
Risks and Challenges
- Volatility in crude oil and natural gas prices could impact revenue and profitability.
- Execution risks associated with cost-cutting and production efficiency measures.
- Potential market saturation and competitive pressures in the energy sector.
- Regulatory and environmental challenges impacting operational strategies.
- Dependence on successful integration of acquisitions to sustain growth.
Q&A
During the earnings call, analysts inquired about the potential for private equity asset exchanges and the company’s cost reduction strategies. Executives addressed these concerns by emphasizing strong well performance in new basins and discussing the market outlook for natural gas, reinforcing Mach Natural’s strategic focus on efficiency and growth.
Full transcript - Mach Natural Resources LP (MNR) Q3 2025:
Brock, Moderator/Operator, Mach Natural Resources: Good morning, everyone. Thank you for joining us, and welcome to Mach Natural Resources Q3 2025 earnings call. During this morning’s call, the speakers will be making forward-looking statements that cannot be confirmed by reference to existing information, including statements regarding expectations, projections, future performance, and the assumptions underlying such statements. Please note, a number of factors may cause actual results to differ materially from their forward-looking statements, including the factors identified and discussed in their press release and in other SEC filings. For further discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements, please read the company’s filings with the SEC. Please recognize that, except as required by law, they undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. They may refer to some non-GAAP financial measures in today’s discussion.
For reconciliation from non-GAAP financial measures to the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mach’s website, and their 10-Q, which will also be available on their website when filed. Today’s speakers are Tom Ward, CEO, and Kevin White, CFO. Tom will give an introduction and overview. Kevin will discuss Mach’s financial results, and then the call will be open for questions. With that, I’ll turn the call over to Mr. Tom Ward. Tom?
Tom Ward, CEO, Mach Natural Resources: Thank you, Brock. Welcome to Mach Natural Resources Q3 earnings update. Each quarter, it is important to reiterate the company’s four strategic pillars. These are, number one, maintain financial strength. Our long-term goal is to have debt/EBITDA of around one time’s 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 ICAV Savinol transactions by breaking into two new basins. Post the ICAV Savinol acquisitions, we’ve moved up to above 1.3 times 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/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 action 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 two 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 Savinol in a historically weak crude oil market with a strip in the low 60s, and ICAV has tremendous upside associated with the asset that we do not have to pay for or did not 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/PV10. 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 ICAV and Savinol. 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 2027 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 ICAV 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 unit holders. 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 does not take a lot of reinvestment to keep our production flat while sending cash back to unit holders. 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 pivoting our drilling program to focus on gas.
Our oil inventory is almost entirely HBP, so we can patiently wait for oil markets to recover to reintegrate those projects into our development plans. Our development plan for 2026 is currently targeting dry gas projects in the Deep Anadarko and the San Juan. We make drilling decisions every month by maintaining contracts that can be altered or eliminated quickly with our service providers. We also have the ability to increase or lower our CapEx depending on pricing, as we did this year. By making acquisitions that focus on free cash flow and acquiring future locations at no additional cost, we have built a tremendous amount of backlog of both oil and natural gas locations. We now have an inventory on our nearly 3 million acres that will be hard to drill in any reasonable timeframe 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 Meco 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 named pillars, they lead to our fourth and most important pillar: delivering industry-leading cash returns on capital invested through distributions to our unit holders. With our announced distribution of $0.27 per unit in the Q3, we have sent back $5.14 per unit to our unit holders 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 $3.5 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 five years. We have 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 two-and-a-half-year cyclical downturn in crude oil that will reverse in the next few quarters. When that happens, we will be harvesting the Savinol 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 can buy low-decline crude assets in the 60s that we 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 from the Permian as 4.6 BCF a day of takeaway capacity comes online by Q4 2027. However, we believe this is more of a basis issue with the potential of gas being stranded at Caddo or Sabine Pass trying to make its way around to Henry Hub. The Haynesville remains the only direct path to Henry Hub with the Midcon coming in close behind. In any event, there is enough demand being generated to not fear the Permian, in our opinion. Now is 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 ICAV and Savinol 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 ICAV-Savinol acquisitions are a good example. ICAV and Cain 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 one, rising to 28% in year five. We now have early results from both the Deep Anadarko and the MECO Shell. In the Deep Anadarko, we brought on our first two 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 three-mile lateral with a PV10 of approximately $15 million per location. We spent $14 million per well so far in our program. We have also participated in three Deep Anadarko wells with Continental. In 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 MECOs, we brought on five wells that were drilled by ICAV over the summer. Two of these are 10,000 feet of lateral length and three are 15,000 feet. The two-mile laterals have come in just above our expectations of 30 million per day for the pad and expected EUR of 18 BCF per well.
Our three-well, three-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 three-mile lateral to have an EUR of 24 BCF of gas and a PV10 of around $14 million. Currently, the combined five wells are producing more than 100 million cubic feet of gas per day. The current cost to drill Mach’s 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-$20 million on each three-mile well. We have initially prepared AFEs to spend $15 million for each three-mile lateral. However, I believe we will achieve well cost in the $12 million range next year. ICAV drilled all five of the wells that we are producing.
ICAV completed the two two-mile laterals, and we completed the three three-mile laterals. ICAV spent $13.75 million on their two drilled and completed locations. We saved approximately $2 million on each three-mile completion that we inherited. These wells will now average $15 million for the three-mile locations. I get asked a lot about how we’re going to achieve these reductions. We have a firm belief that, in general, our industry overstimulates wells and doesn’t do a great job of maximizing profits. We can reduce costs by using more aggressive bidding practices, reducing acid, sand sweeps, diverters, location size, amount of riddles, etc. 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 fract, 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 $12 million. In every play we have been involved in and drilling at Mach, we have 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 will also be very effective at lowering costs in the San Juan. During the quarter, we also completed two 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 30% at today’s oil strip.
We’re in the final completion stage of our next Deep Anadarko location. This location is a one well pad. We currently have two rigs running in the Deep Anadarko. The production plan through the first half of 2026 is to have one location coming on this month, a two well pad in January of 2026, a two well pad in March of 2026, and a three well pad in June of 2026. The MECO Shell program for 2026 will begin in May of 2026. We anticipate bringing on seven MECO’s locations in the fall. We only target natural gas as our commodity of choice for 2026. We also have targeted areas where there is ample gas takeaway. The Midcon is well connected to major interstate systems, including Panhandle Eastern, Midcon Express, and Midchip.
Currently, the Midcon produces about 9 BCF a day of gas with gas takeaway of approximately 12 BCF a day. Midchip and Southern Star have 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 MECO Shell development is coming. However, Energy Transfer’s Transwestern expansion is also projected to add capacity by 1.5-3 BCF a day to meet demand from the west by year-end 2029. Total surely thought about the ability to add gas when they decided to partner with Continental on their Deep Anadarko inventory. I believe that joint venture is ample proof that the Deep Anadarko inventory is going to provide the necessary help to move natural gas to the hub where LNG demand is exploding. I’ll turn the call over to Kevin to discuss financial results. Thanks, Tom.
For the quarter, our production of 94,000 BOE per day was 21% oil, 56% natural gas, and 23% NGLs. Our average realized prices were $64.79 per barrel of oil, $2.54 per MCF of gas, and $21.78 per barrel of NGLs. Of the $235 million total oil and gas revenues, the relative contribution for oil was 50%, 32% for gas, and 18% for NGLs. On the expense side, our lease operating expense was $50 million or $6.52 per BOE. Cash G&A was $21 million. It’s an important point this quarter to note that the deal costs associated with ICAV of approximately $13 million are a bit unique. First and foremost, they are non-recurring. Secondly, due to nuanced GAAP rules, they are required to be expensed, whereas in the history of our acquisitions, including Savinol, the deal costs have been capitalized.
Additionally, with the ICAV deal, we engaged an outside advisor, which again is out of the norm for our acquisition history. As a point of reference, the Savinol 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. 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 non-recurring $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 in 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 4th to record holders as of November 20th. Brock, I’ll turn the call back to you to open the line for questions. Thank you.
We will now be conducting a question-and-answer session. If you would like to ask a question, please press Star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press Star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the Star keys. Our first question today comes from Neil Dingman of William Blair. Please proceed with your question. Morning, Tom. Nice quarter. Tom, my first question is in the Midcon operation. Specifically, you highlight some really nice, notable well upside in the play, and why things have always been going nice there. Seems like more recently you are seeing some just commendable upside.
Is that attributable to going after some new zones, or what’s driving this upside, particularly in some of this Midcon upside? Thanks, Neil. 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’s 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. Since that time, we’ve been studying the Deep Anadarko. The issue for natural gas producers is you just haven’t had a strip that has been competitive with oil. 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. That’s the reason we moved into the Deep Anadarko.
It 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 is that the efficiencies of drilling three-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. It is really about keeping our costs down and having a decent strip in the natural gas pricing in order to make the rates of return. We think we will. The asset, excuse me, the natural gas has always been known to be there. Tom, that leads me to my second question just on your gas strategy. In the Midcon or others, it doesn’t seem, but do you all have any—does there any takeaway constraints? And do you all use any sort of managed choke program?
Because it seems like the rates are flowing really nicely. And so I’m just wondering, when it comes to takeaway and chokes, how would you talk about that program? No, the Midcon’s 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. Wow, that’s great to hear. Thanks, Tom. Thanks, Tom. Thank you, Neil. The next question is from Charles Mead of Johnson Rice. Please proceed with your question. Good morning, Tom, and Kevin, and the rest of the Mach team there. Tom, forgive me.
You went through a lot of good detail there. I may have missed some of it. I wanted to ask on the Deep Anadarko. I know you just said it is 15,000 foot TVD, and then you do another 15,000 foot lateral. What is the DNC cost on those Deep Anadarko locations? That is kind of one. Two, $20 million a day sounds pretty stout to me, but how did that fit versus your expectations? Last thing first, it fit exactly as we anticipated if you want to have a north of 50% rate of return and spend $14 million, which is what we have 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.
When you look at that, all the wells we’re bringing on, you can see how come that we’re able to keep our CapEx cut and keep our production flat just because of the rates we’re getting out of these wells. Right now, the natural gas strip is good. 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 is not the easiest place to drill. You have very deep wells, very complicated completions just because of the amount of pressure you’re using to get a frac established. Got it. I wanted to—this is a little bit bigger picture—the improvement in your 2026 guide where you’re spending 18% less on DNC 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 2026 program, or is there something else at work? Nope, that’s it. All right. Thanks, Tom. Thank you. The next question is from Derek Whitfield of Texas Capital. Please proceed with your question. Good morning, all, and thanks for your time. Thanks, Derek. Starting with your distribution, despite the strength in operations this quarter, it did come in a touch lower than expected due to the non-recurring 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? Oh, gosh, Derek.
Derek, I think that could just have a little caveat to look at what price deck you are talking about for 2026. I think we are expecting—I think we would actually, just through the course of 2026, as these wells come online, kind of expect an increasing distribution over the course of the year. Derek, our natural gas volumes next year will be moving up to just over 70%. If you are bullish natural gas, we should do pretty well. That was our thought as well, Tom. If you look at your hedges, everybody with the gas growth profile. Just wanted to confirm that we were thinking about that right. On my follow-up, I wanted to focus on your prepared comments on private equity PDP exchanges for Mach shares.
Regarding the PE kind of PDP exchanges, how large and in what basins are those opportunities in general? Would it be safe to assume that they would be both leverage and yield accretive? Do you want to take—yes. We are having people kind of contact us. I do not know. I think it is rare. I would start with this. I think it is rare to have an ICAV, Savinol happen very often, especially at once, just that you have two pretty large groups that were wanting to swap out. At today’s strip, especially in oil, it is not out of the question that others—and they do reach out. I am stumbling here just because there is a cash market with all the ABS participants. If somebody wants cash today, they can get it.
There is a group that prefer to take, maybe because of their timing of a fund, need to be moving out, and they do not want to take today’s prices at cash. Those are the types that will look for us. It is not—I think you probably would not see that out of the Marcellus or the Haynesville or Permian, really anywhere where you can get paid more than PDP PV10. If you are in other areas, I think that we will continue to have that. Yes, anything we do would be accretive to our cash flow for distribution and really cannot be dilutive on a debt perspective. Sorry, I rambled about all that. If you want to ask me something to clarify, please do. I think you covered it well, Tom. I mean, it is going to be both leverage and yield accretive.
Certainly, thanks for your comments on that, and I’ll turn it back to the operator. Thank you. The next question is from Michael Scialla of Stephens. Please proceed with your question. Good morning, guys. 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? Yeah, in the Deep Anadarko, we just use a typical frac that’s already been moved down.
The industry might have been at 3,000 pounds per foot of sand in the last couple of years ago that we have moved down, and others. It was not just us. It moved down closer to 2,000 pounds. I think that is how come you see other operators spending relatively in line with us on where costs are. That has not happened yet in the San Juan. I think chasing estimated ultimate recoveries sometimes can affect negatively the rates of return. What we try to do is to find a way to stimulate a well that we do not 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 are going to get that stimulated. To answer your question, we do not know. We have not seen it.
We have IP30s on wells that are a little bit more stimulated than we will next year. I am pretty comfortable that in the past, whenever we have moved down our stimulations, we have not seen a decrease in rate of return. Sounds good. I want to see if you could talk about your potential inventory in both plays. I know you 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 is more delineation by you or others there? Yeah, we just have too much acreage to effectively drill it all. We have 500,000 acres plus in the San Juan. In the Deep Anadarko, we have more than 120 locations already under lease that we can drill.
That’s how come 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. 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. Valdez 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. In that case, it would just be highly accretive to us. I don’t know if I answered your question, but that’s kind of the way we look at it. No, that’s perfect.
I was wondering what the motivation behind bringing in a potential drilling partner was, and that really explains it. I think you want to move that value forward without changing your reinvestment decisions. So understood. Thanks for that, Tom. Thank you. You bet. The next question is from John Freeman of Raymond James. Please proceed with your question. Thank you. Good morning. Really impressive to see the 18% reduction in the DNC 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—excuse me—if you can choke up a little. Hold on. Yeah, I think—I’m sorry about that. I was just trying to understand the midstream and the land budget and just sort of what drove that. Sorry about that. Yeah, and the land budget’s mainly in the Deep Anadarko.
We are buying a few new leases. We trade around some acreage and putting together areas that we did not have completely HBP through prior acquisitions. In the whole scheme of the area, it is fairly small, the increase in land to do that. I think if you mentioned midstream, it is true. We inherited quite a bit of new midstream with the last two acquisitions, and it is just more maintenance and getting them back up to speed, especially in the ICAV acquisition needed to have a little bit of upgrading. John, just for a little bit of detail, the land piece of that is about $32 million, and midstream about $17 million. Oh, that is great. Thanks for the breakdown on that.
Just following up on some of the 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 y’all still open to considering expanding into newer areas or basins? The only way we’d expand in any size is through an equity deal with another partner or the seller. I think that in the 23 acquisitions we’ve made, most of them, 20 of them probably have been in around $100 million. That’s really the best area for us to compete.
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. 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 very low cost of capital and maybe bid it to a way that we can’t compete. I think we look at a lot of deals, but the ones we get tend to be in this $100 million-$150 million range where they’re highly accretive to us.
Keeping in mind that those cannot be done with debt, though, because we have now used our debt card and are over a turn of leverage, and we want to see that come back down. Thanks, Tom. That makes sense. Very helpful. Thank you. The next question is from Jeff Gramp of Northland Capital Markets. Please proceed with your question. Good morning. I was curious to expand on the—Good morning. Hi. I wanted to expand on the drilling partnership opportunity. Any thoughts on what kind of size you are looking for in terms of a partner? Just kind of curious what stage of conversations these may be. Is this something that you guys are pretty definitively moving towards? Are we kind of more of an exploratory stage? Any additional color there would be helpful. Yeah, Jeff, it is just a thought.
I hadn’t really moved more from my brain to my mouth to you. There is nothing really—there is nothing going on. I just think we have too much. As I got prepared to write a spiel to describe what we have, I am like, "My lands, we have a lot of—we have more here than I can ever get to." We have not talked to anyone. We have a TotalEnergies Continental Resources deal that is right beside us that I doubt they got for free. It seems like we probably have an asset that could be maybe profitable to us. We have done this in the past. You have a lot of buyers that are coming here. The Midcontinent, especially, has great takeaway. I think that is what the TotalEnergies deal is showing you, that you can get gas to the hub.
It seems to me like to be a pretty attractive place to own acreage. Agreed. That’s helpful. Thank you. For my follow-up, we’re a couple of months into operating the new properties here. Overall, how’s 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? 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. Yeah, it’s all going good. We have a new office in Durango, and that, I think, is we’ll find that to be an incredibly good place for us to do business. Great. I appreciate the time. Thank you. Thank you.
The next question is from Jeff Jay of Daniel Energy Partners. Please proceed with your question. Hi, Tom. Just I guess I would have interpreted your comments earlier on the macro as constructive but cautious. I guess in that light, given the strength of the strip in 2026, 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? Yeah, Jeff, 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.
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. Whenever I look at 2027 and beyond, there needs to be a lot more drilling activity than we’re seeing today to overcome the demand. I am bullish. I’m very bullish on natural gas. It just is this winter season, if we have a warm winter, you could be backed up into late 2026 before you see a real recovery in prices. Gotcha. I’m sorry my math was lousy. I guess I’d follow on to that then. When you guys closed on these deals, can you refresh me how many rigs in total we’re running for Mach and sort of what your plan is for next year?
What does that sort of sub-$300 million DNC budget contemplate? Sure. So right now, we have two Deep Anadarko wells or rigs that are running. We’ll continue to run through 2026. And then we start our Mancos and Fruitland Coal drilling program next spring. We’ll drill seven locations in the Mancos and two locations in the Fruitland Coal, and that takes up our total CapEx. Keep in mind that that’s subject to change every month. Absolutely. Thanks, Tom. Thank you. The next question is from Tim Resvan of KeyBank Capital Markets. Please proceed with your question. Good morning, folks. Thank you for taking our questions. 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. We saw CapEx all in down about 10% and production down about 1-2%.
Is that change reflecting a pivot to 100% gas-focused drilling? I’m just curious, given it’s a 10% reduction in seven weeks is a big amount. I’m just trying to understand what’s changed on the modeling and sort of strategy forecasting side. Sure, Tim. This is Kevin. Good question. As Tom just said, we look at our drilling schedule monthly, and we do have the ability to pivot quickly. The description that you threw out there is largely correct, that two things happen. We see the returns on our gas drilling as being better, and so much more heavily weighted towards gas. Secondly, 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.
Our companies 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. If it goes down, we probably throttle back some of our activity. Tim, I think of it as that one of our pillars is a 50% reinvestment rate. Production growth, the amount of production growth, is not. Whenever we have higher operating cash flow, we get to use half of that and put it directly to work and make it in CapEx. Just luckily—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. That is very helpful context.
I know this is subject to change, as we have seen, but in this environment where you are looking at maybe roughly two-thirds gas skew in 2024, 2025, and you are 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 2026. Is that the right way to think about things? Yeah. I think just over 70 is where we are targeting here in 2026. Okay. Okay. Thanks for the comments. Thank you. The next question is from Selman Akyol of Stifel. Please proceed with your question. Hi. Thank you. Good morning. 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’s not coming online till closer to the end of the decade. 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. Thanks. Thank you, Tim. I think it really just depends on the amount of rigs that run. 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.
We kind of look at December to May, the first 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. The Mancos Shale obviously produces enough. We just brought on 100 million a day out of a five-well pad, and it only declines by 60% or so. It’s not a traditional extremely high decline. 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.
One of the things is at the end of the decade, end of 2029, whenever Energy Transfer plans to expand. Right now, we have another couple of BCF a day of availability of takeaway. I do not think we are very close to having an issue. The caveat is there is a lot of gas to be brought on. Got it. That is all I had. Thank you guys for the time. Thank you. This now concludes our question and answer session. Thank you for your participation. You may disconnect your lines and have a wonderful day.
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