Mach Natural Resources maintains financial strength with strategic acquisitions, targets higher distributions as natural gas demand increases in 2026.

OPERATOR - (00:00:35)

Good morning everyone. Thank you for joining us and welcome to Mach Natural Resources third quarter 2025 earnings call. During this morning's call, the speakers will be making forward looking statements that cannot be confirmed by reference to existing and 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 a 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 10Q which will also be available on their website when filed. Today's speakers are Tom Ward Ward, CEO and Kevin White White, cfo. Tom Ward will give an introduction and overview. Kevin White 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 Ward. Tom Ward.

Tom Ward - Chief Executive Officer - (00:02:20)

Thank you Brock welcome to Mach Natural Resources third Quarter 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 to ebitda of around 1 times 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 and A front. That is what we've done with the ICAB Savinol transactions by breaking into two new basins post the ICAB Savinol 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 cash available for distribution 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 mock 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 Savinon in a historically weak crude oil market with the Strip in the low 60s and ICAB has tremendous up 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 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 ICAB and Savinol, we show an example of that capital efficiency by lowering our expected Capebacks 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 ICAB 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 cease drilling our high rate of return Oswego inventory in favor of our drilling program to focus on gas. Our oil inventory is almost entirely held by production (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 named 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 five 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 two and a half year cyclical downturn in crude oil that will reverse in the next few quarters. When that happens, we'll 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 buy we can buy low decline crude assets in the 60s and 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're entering winter in a precarious position of full storage and relying on weather conditions to move the market forward. However, starting in 2026 the US will begin to add demand through LNG exports. We see 24 BCF a day of demand materializing between 2026 and and 2030 just from LNG. This is a much larger story than data center growth for the US 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 for 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 there's more of a this is more of a basis issue with the potential of gas being stranded at Katy 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's 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 or oil and natural gas assets that will contribute more and more to our long term cash available for distribution. The ICAB and Savinaw 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 ICAB Sabinel acquisitions are a good example. ICAB 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 cash available for distribution by 8% in year one, rising to 28% in year five. We now have early results from both the deep Anadarko and the Mancos Shale. 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 3 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 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 five wells that were drilled by ACAV over the summer. Two of these are 10,000ft of lateral length and three or 15,000ft. 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 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 PV10 of around $14 million. Currently, the combined five wells are producing more than 100 million cube feet of gas per day. The current cost to drill Mancos wells is too high in our opinion. These wells are 7,000ft of TVD with laterals that drill very easily because of the shale reservoir. The industry is currently spending 16 to 20 million dollars 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 dollar range next year. ICAB drilled all five of the wells that we are producing. ICAB completed the two two mile laterals and we completed the three three mile laterals. ICAL 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 cost by using more aggressive bidding practices. Reducing acid sand sweeps, diverters, location size, amount of riddles, 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 to 20 million dollars. From 15 to 12 million dollars in every play we have been involved in a 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'll 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 cube 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 Anadarco location. This location is a one well pad. We currently have two rigs running in the Deep Anadarko. The production plan through 1H26 is to have one location coming on this month. A two well pad in January 2026, a two well pad in March of 2026 and a three well pad in June of 2026. The Mancos Shale program for 2026 will begin in May of 2026. We anticipate bringing on seven 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, Midcon, Express and Midchip. Currently The Midcon produces about 9 bcf a day of gas with gas takeaway of approximately 12 bcf a day. Midship 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 Mancos Shell development is coming, however. Energy transfers 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 in 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 - Chief Financial Officer - (00:17:35)

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, 254 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 $652 per boe. Cash G&A was $21 million. It's an important point this quarter to note that the deal costs associated with ICAB 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 Sabinel, the deal costs have been capitalized. Additionally, with the ICAB deal we engaged an outside advisor 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 and 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 and 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 and the absence of expense 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 total $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.

OPERATOR - (00:20:44)

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 two 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.

Neil Dingman - Equity Analyst - (00:21:16)

Morning all. Tom. Nice quarter, Tom. My first question is in the midcon operations specifically, you know, you'll highlight some really nice notable well upside in the play and you know why things have always been going nice there. Seems like more recently you're seeing some just commendable upside.. Is that, is that attributable to going out for some new zones or what, what, what's, what's driving this upside, particularly in that some of this mid con upside.

Tom Ward - Chief Executive Officer - (00:21:45)

Thanks, Neil. It's, it's just really just moving deeper into moving away from a condensate zone into deep gas that 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 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, 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 have been drilled over the years in the deep gas area. It's that the efficiencies of drilling 3 mile laterals and having 15,000ft of TVD with 15,000ft 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, in the natural gas pricing in order to make the rates of return we think we will but the asset, excuse me, the, 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 mid con or others it doesn't seem but 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. So I'm just wondering, when it comes to takeaway and chokes, how would you talk about that program? No, the midcon 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 3bcf 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. Nice job. Thank you, Neil.

OPERATOR - (00:24:27)

The next question is from Charles Mead of Johnson Rice. Please proceed with your question.

Charles Mead - Equity Analyst - (00:24:33)

Good morning, Tom and Kevin and the rest of the mock team there. 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 DNC 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? Yeah, last thing first. If 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 when you look at that all the wells 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 the amount of pressure you're using to get a frac established. Got it. And then I wanted to this is. A little bit bigger picture. The improvement in your 26 guide where you're spending know 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 26 program or is there something else at work? Nope, that's it. All right, thanks, Tom.

Tom Ward - Chief Executive Officer - (00:27:01)

Thank you.

OPERATOR - (00:27:04)

The next question is from Derek Whitfield of Texas Capital. Please proceed with your question.

Derek Whitfield - Equity Analyst - (00:27:10)

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 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?

Kevin White - Chief Financial Officer - (00:27:44)

Oh gosh, Derek, Derek, I think that. I think that. Just have a little caveat to look at what price deck you're talking about for 26. But you know, I think we're expecting, I think we would actually, you know, just through the course of 26 as these wells come online, kind of expect an increasing distribution over the course course of the year.

Tom Ward - Chief Executive Officer - (00:28:17)

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. Yeah, 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 mock shares Regarding the PE 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? Do you want to take. 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 ICAF sav at all happen very often, especially at once just that you have two pretty large groups that we're wanting to swap out but you know, 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 than PDP PB10. 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 bill for distribution and really can't be dilutive on a debt level. A debt perspective. Sorry I rambled about all that. If you need me, if you want to ask me something to clarify, please do. I think you covered it well Tom, and it's going to be both leverage and yield accretive. So certainly thanks for your comments on that and I'll turn it back to the operator. Thank you.

OPERATOR - (00:31:04)

The next question is from Michael Scalia of Stevens. Please proceed with your question.

Michael Scalia - Equity Analyst - (00:31:11)

Good morning guys. Tom, wanted to ask about your comments that the industry tends to overstimulate wells. You mentioned the potential for cutting costs in the Mancos. Wanted 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 in the deep anadarko. We just use a typical frac that's already been moved down to the industry and might have been at 3,000 pounds per foot of sand last couple of years ago that we've moved down and others in just us have moved down closer to £2,000. And I think that's how come 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 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 Manco shell, you're going to get that stimulated. To answer your question, we don't know. We haven't seen it. We have IP 30s 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've moved down our stimulations we haven't seen a decrease in rate of return. Sounds good. I want to see if you could talk about your potential inventory in Both places 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? Yes, 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 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 from growth. And 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 answer 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.

OPERATOR - (00:35:12)

The next question is from John Freeman of Raymond James. Please proceed with your question.

John Freeman - Equity Analyst - (00:35:18)

Thank you. Good morning. Really impressive to see the 18% reduction, the DNC budget and still be able to maintain production. We did notice that the midterm of the land budget basically doubled from the project prior update. Just wondering if you. Excuse me. If you can break choked up a little. Hold on. Yeah, I think. Sorry about that. I was just trying. Oh, that's fine. And the land budget and just sort of what drove that. Sorry about that. Yeah. And then the land budget's mainly in the Deep Anadarko. We are buying a few new leases. We trade around some, some acreage, putting together areas that we didn't have completely HBP through prior acquisitions. But it's, you know, in the whole scheme of the area, it's fairly small, the increase in land to do that. I think with the. If you mention midstream, it's. We inherited Quite a, quite a bit of new midstream with the last two acquisitions and it's just more maintenance and getting them back up to speed, especially in the ICAB acquisition needed to have a little bit of upgrading. And John, just for a little bit.

Kevin White - Chief Financial Officer - (00:36:43)

Of detail, the land piece of that is about 32 million and midstream about 17 million.

John Freeman - Equity Analyst - (00:36:51)

Oh, that's great. Thanks for the breakdown on that. And then just following up on some of the commentary, prior commentary on the M and A front, when we sort. Of look at the basins that you're. Currently operating in, should we assume kind of a plan going forward from an M and 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, you know, expanding into newer areas or basins?

Tom Ward - Chief Executive Officer - (00:37:21)

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. 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 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 the ones we get tend to be in this 100 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. Thanks, Tom. That makes sense. Very helpful. Thank you.

OPERATOR - (00:38:50)

The next question is from Jeff Gramp of Northland Capital Markets. Please proceed with your question.

Jeff Gramp - Equity Analyst - (00:38:57)

Morning. I was curious to expand on the. Hi. 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 and 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. Yeah. Jeff, it's just a thought. 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 spiel 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. You know, you have a total continental deal that's right beside us that I doubt. 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. Agreed. That's helpful. Thank you for my follow up. We're a couple 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. And so, yeah, 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. Great. I appreciate the time. Thank you. Thank you.

OPERATOR - (00:41:31)

The next question is from Jeff J. Of Daniel Energy Partners. Please proceed with your question.

Jeff J. - (00:41:38)

Hi, Tom. Just. I guess I would have interpreted your comments earlier on the macro 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? Yeah, Jeff, whenever you tie in the Mancos hedges or the San Juan hedges, It's where 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. You know, we're back to kind of a weather bet. Which I don't like to make. So the I think when I said 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, if we have a warm winter you could be backed up into late 26 before you see a real recovery in prices. Gotcha. Well, I'm sorry my math was lousy but guess what, follow on to that then. When you guys closed on these deals, can you refresh me like how many rigs were in total we're running for mock and sort of what your plan is for next year. What does that sort of sub 300 million DNC budget contemplate? Sure. So the right now we have two deep ended ARCO wells. 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 seven locations in the Mancos and two 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. Absolutely. Thanks Tom. Thank you.

OPERATOR - (00:44:02)

The next question is from Tim Rezvan of Keybank Capital Markets. Please proceed with your question.

Tim Rezvan - Equity Analyst - (00:44:09)

Good morning folks. Thank you for taking our questions. I was trying to understand the changes in 2026 guidance. You know you put a release out in mid September and then it's been pretty significant changes from there. So you know 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 seven weeks is a big amount. So I'm just trying to understand what changed on the modeling and sort of strategy forecasting side. Sure.

Kevin White - Chief Financial Officer - (00:44:47)

Tim, this is Kevin, so good question. And as Tom just said, you know 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 two things happen. We, we see the returns on our gas drilling as being better and so much more heavily weighted towards gas. And then secondly, you know, kind of the Reduction in CAPEX is also reflective of, you know, basically lower strip prices than we put out the first guidance for 2026. We've seen, you know, forecasting with the lower strip, lower operating cash flow. And again, our companies run pretty simply and straightforward. As you see changes, you know, 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 - Chief Executive Officer - (00:45:50)

Yeah, Tim, I think of it as one of our pillars is a 50% reinvestment rate production growth. The amount of production growth isn't so that 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. 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. 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 4Q25 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? Yeah, I think just over 70 is where we're targeting year end 26. Okay. Okay. Thanks for the comments.

OPERATOR - (00:47:14)

Thank you. The next question is from Selman Akiol of Stifel. Please proceed with your question.

Tim o' Toole - Equity Analyst - (00:47:24)

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 and it seems like there's just a lot of of gas demand kind of coming out of the Southwest and in Arizona. But that project's 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. Thanks. Thank you, Tim. I think it really just depends on the amount of rigs that run. So the San Juan is seasonal, so. 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. 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 Mako 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. 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. Got it. That's all I had. Thank you guys for the time. Thank you.

OPERATOR - (00:49:42)

This now concludes our question and answer session. Thank you for your participation. You may disconnect your lines and have a wonderful day. Day.