Mach Natural Resources LP

Good morning everyone and thank you for joining us and welcome to Mock Natural Resources second quarter 2026 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 statement including the factors identified and discussed in their press release and in other SEC filings. For further discussion of risks and uncertainties that can 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 under reliance on such statements. They may refer to some non-GAAP financial measures in today's discussion. For reconciliation from non-GAAP financial measures and the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mock's website, and their 10-Q, which will be also 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, Darrell. Welcome to Mock Natural Resources' second quarter earnings update. We reiterate the company's four strategic pillars that have guided us since our founding in 2017. These pillars are disciplined execution. We only purchase cash-flowing assets at a value of PDP, PB10 or less and do not pay for any leasehold, PUDs, midstream, or infrastructure. The second pillar is disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. The third pillar is maintain financial strength. We're cognizant of the peril of too much debt. In order to capture the opportunity of acquiring assets in the San Juan and Central Basin platform, we strategically moved leverage above our goal of one times debt EBITDA. This pillar is still standing. Therefore, it is important to move leverage back to our stated goal versus the 1.4 times we're projected to be at the end of the year. Outside of waiting to solve through increased pricing, we continue to look for assets at discounted prices to use our equity to purchase. These purchases need to be accretive to our cash available for distribution. We also have an at-the-market equity program to place $100 million of equity at prices that do not disturb trading. And lastly, we can take a portion of our distribution and pay down debt. Our team is dedicated to meet our goal before the end of 2027. Once we achieve our goal, we'll be in a position to take advantage of any downward movement in the market to make additional bargain purchases. The very reason to bring down debt during a period of exuberance is to be prepared to purchase in a time of want. This is the very essence of our company. The fourth pillar is to maximize distributions to unit holders. This pillar drives all of our decisions. We've distributed back $6.67 to our unit holders since 2024. Very few public companies in this country have yields at Mock's level, and none of them are oil and gas producers. Yields like ours are usually only found at businesses carrying a lot of leverage that often can't sustain once credit tightens or rates move against them. Mock was built entirely different. Our distributions and the cash returns we deliver are second to none, and they're the result of the discipline behind our other three pillars. Mock was established around a cash return model. We've said many times that we had a belief for several years before forming the company that there would be a time when we could buy cash flowing assets at seldom heard of prices by avoiding the tendency of the industry to look for growth through the drill bit. Our goal is to buy distressed assets at discounted prices that throw off cash. We were fortunate to pick the timing correctly and build a large producing base at bargain prices. We continue to look for those types of assets, but it's become harder as more capital is now chasing the same type of cash flowing assets that we propose to buy and are willing to pay premiums to our model. However, Our steadfast approach to value has paid off by giving us a 50-year cash flow stream plus nearly 3 million acres of land that is held by production. And that holds our production flat by spending less than 50% of our operating cash flow. Therefore, in times of excess capital provided by private equity and ABS companies, we can pivot to rely on drilling to sustain our model. All of our acquisitions have been made at a discount to the Strip at the time of purchase. The timing of some of our acquisitions was quite spectacular, such as buying Alta Mesa through the 363 bankruptcy process in April of 2020. That purchase was made against a $20 Wall Strip and paid the first lien RBL lenders back less than 10 cents on the dollar. that then made the lending institutions leery of investing in the MidCon and gave us additional running room to acquire other assets at rock bottom prices. The tide did not turn on the MidCon for lenders until 2024. There is now a wave of lending and equity providers chasing MidCon assets. As capital started to move back into the MidCon, we've expanded to the San Juan and Central Basin platform of the Permian. We were able to purchase the oil assets of Sabinol in the low 60s per barrel range and also were able to purchase the natural gas assets of ICAV in the San Juan at less than PDP, PV10. Not only did we purchase the assets at discount prices, we also bought a stream of production in both cases that have less than a 10% decline. Sabinol in particular gave us immediate cash flow benefits due to the rise in crude prices since the purchases. Lastly, both have substantial drilling room left on the assets. Mock has a history of strong cash returns on capital invested and cash distributions. Over the past five years, we have delivered an industry-leading croquis averaging 35%. Not only industry-leading, but also in the top 1% of all public companies in the U.S. We also have distributed an industry-leading distribution yield of 15% since 2024 through the first quarter of 2026. This performance was achieved through different pricing cycles ranging from $94.23 per barrel in 2022 when we achieved a 53% croquis to $64.81 per barrel in 2025 when our croquis was 23%. Since our inception, we've never had a croquis of less than 20%. We cannot find another public company with such a strong record of cash returns. Our cash distribution policy has led to a yield of four times the peer average since 2024. As I mentioned, these returns were accomplished through disciplined acquisitions on top of the best-in-class break-evens in both natural gas drilling and liquids-weighted peers. Post the start of the conflict in Iran, we moved from drilling 100% natural gas wells to crude heavy drilling. This is the same type of pivot that we made in April 2025 when post-tariff day we changed our drilling plans from all-weighted drilling, oil-weighted drilling to natural gas. This is the luxury of having nearly 3 million acres of land that's held by production. Currently, We're drilling our last two wells in the Mancos Shale. The completion phase of this year's drilling has been delayed until next year in order to stay within our internally mandated annual capex of 50% of operating cash flow. Given that restraint, it's more valuable for us to drill for oil rates return versus natural gas in the last half of this year. We currently have three additional rigs running in Oklahoma. These are located in the Oswego, the Red Fork, and Ardmore Basin Sycamore. The Ardmore Basin locations will be completed by the end of Q3. We will defer drilling more Red Fork locations until the Q1 of 27 and keep one rig in the Oswego during Q4 of 26. Our drilling schedule is very fluid. One of our hallmarks is the ability to change the product we drill for and the amount we spend very quickly. MOC has a variable distribution to capture the changes in capex associated with different drilling patterns. The pattern in 2026 has been to spend more capex in Q2 and Q3 while drilling in the San Juan. The variable nature of our capex reveals itself in our distribution. This quarter, we will distribute 36 cents per unit. Since we do not have fixed distributions, there's not any pressure to spend more than 50% of our operating cash flow on capex. In other words, the cash flow dictates our pace of capex, not the lust for growth at any cost. The clear workhorse as far as CapEx in our portfolio has been the Oswego Limestone Formation in Kingfisher County, Oklahoma. We have drilled more than 250 wells on this asset since 2021 and recently moved a rig back in the area to continue drilling once oil prices improved. And we show in our presentation the Oswego carries a rate of return of 87% at a $75 oil strip. The key to the formation is not how much we find, but in how much we spend. We're only looking for approximately 160,000 barrels of oil, but we'll spend only $3.3 million to drill and complete. Cutting costs is the key to our business model. The newest field we have acquired that will also become a drilling workhorse is the Mancos shell of the San Juan Basin. Within the San Juan, we now hold 575,000 acres of land that only expires when production ceases. The key zone to elaborate on is the Mancos Shale. This zone is just now being expanded. Our Mancos Shale position represents one of the most compelling emerging natural gas opportunities in North America. The well performance rivals that of the better known Hainesville and Marcellus shale plays, with operators recently reporting Mancos initial production rates exceeding 25 million cubic feet of gas per day. The Mancos footprint is approximately one-third the size of the Marcellus and one-tenth the size of the Hainesville. However, Mott controls the play with only three other sizable owners. We are the second largest producer of natural gas behind Hillcorp and also the second largest owner of Acreage. The play has increased more than 20-fold in the last five years and now exceeds 500 million cubic feet of gas a day. The San Juan also benefits from a mature natural gas transportation network developed over decades of conventional gas production. We expect over the next five years that additional takeaway capacity will be installed to get to premium gas markets of Arizona and the Pacific Coast LNG markets. This is much different than when the Marcellus and Haynesville were first being explored and there was no takeaway available, which required operators to take on large firm commitments with pipeline companies. We currently have a gas marketing agreement placed through 2030. Therefore, by the time the contract amortizes in 2030, we'll have strategic optionality for our 350 million cubic feet of natural gas that can be held flat by drilling only five net wells per year. If we choose to increase activity to 10 net wells per year, we could grow mocks from that production to more than 500 million cubic feet of gas per day. This is the benefit of buying low decline cash flowing assets that also have fantastic upside potential. The Mancos show us has potential to dominate the mock story in the years to come. As in the Oswego, the key to increasing rates of return in the Mancos is to lower costs. We believe that we could lower capex of a three-mile lateral from nearly $20 million to less than $15 million per well. Now that our drilling season is underway and we have four locations drilled, we expect the ongoing program to be in the $13 million range for a completed well. I'll now turn over the call to Kevin to discuss financial results.

Thanks, Tom. For the quarter, our production of 149,000 BOE per day was 15% oil, 69% natural gas, and 16% NGLs. Our average realized prices were $95.40 per barrel of oil, $1.93 per mcf of gas, and 2899 per barrel of NGLs. Of the $360 million total oil and gas revenues, the relative contribution for oil was 54%, 30% for gas and 16% for NGLs. On the expense side, our lease operating expense was $98 million or $7.21 per BOE. Gas G&A was approximately $7 million. or 54 cents per BOE. We ended the quarter with 41 million in cash and 270 million of availability under the credit facility. Total revenues including our hedges and midstream activities totaled $406 million, adjusted EBITDA of $182 million and $154 million of operating cash flow. and our development capex for the quarter was $97 million for 63% of operating cash flow. Year-to-date, our development capex is right on top of 50% of our year-to-date operating cash flow. In the quarter, we generated $60 million of cash available for distribution, resulting in a distribution of 36 cents per unit, which will be paid on August 31st to holders of record on August 17th. Daryl, I'll now turn the call back to you to open the line for questions.