Mach Natural Resources LP

good morning everyone thank you for joining us and welcome to mock 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 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 MOC's website and their 10Q. 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 Mock'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?

Thank you, Brock. Welcome to Mock 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 one 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&A front. That is what we've done with the ICAV Sav and All transactions by breaking into two new basins. Post the ICAB 7-0 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 in 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 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 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've 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 Savano in a historically weak crude oil market. With the strip in the low 60s, and ICAB 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 PB10. 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 Savino. 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 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 Mako Shell 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 doesn't 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 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 Manco Shell 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 27 cents per unit in the third quarter, 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'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 Sabinol 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'll be ultimately rewarded. With regard to natural gas, we're 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 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 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 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 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 Indiana Darko 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 Sabino acquisitions are a good example. ICAB and CAEN 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 Manco 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've 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 flow back, and we anticipate them to be equal to our initial pad. In the Mancos, 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 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 pb10 of around 14 million dollars currently the combined five 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 shell reservoir. The industry is currently spending $16 to $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 costs in the $12 million range next year. ICAB drilled all five of the wells that we were producing. ICAB completed the two two-mile laterals, and we completed the three three-mile laterals. ICAB 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, 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 frack, 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 costs, we can add an additional 30 percentage points per location by moving from $15 to $12 million. In every play, We have been involved in a 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 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 30s 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 26 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 Mako Shell Program for 2026 will begin in May, of 2026. We anticipate bringing on seven main coast 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 MidCon is well connected to major interstate systems, including Panhandle Eastern, MidCon Express, and Midship. Currently, the MEDCOM 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 Maine Coast Shell development is coming. However, energy transfers, trans-western 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.

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 $652 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 gap 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 ICAV 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&A was around $7.2 million or 83 cents per BOE. As we analyze this quarter's distribution more closely, the free cash flow from our legacy assets performed as to be 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 35 cents per unit. The non-recurring 13 million deal costs reduced the distribution by about 8 cents 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 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, 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 27 cents 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.