Mach Natural Resources LP

Good morning, everyone. Thank you for joining us, and welcome to Mock Natural Resources' fourth 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 the company's annual report on Form 10-K, which will also be available on their website or the SEC's website when filed. Today's speakers are Tom Ward, CEO, and Kevin White, CFO. Tom will give an introduction and overview, Kevin will discuss MOC'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, Rob. Welcome to Mock Natural Resources' fourth quarter earnings update. Each quarter, we reiterate the company's four strategic pillars that have guided us since our founding in 2018. Since inception, the company has put a distinct emphasis on delivering exceptional cash returns through distributions. We have distributed back to our unit holders a total of $1.3 billion starting in the fourth quarter of 2018 after our first acquisition, showcasing our consistent and dependable nature across a variety of commodity cycles. We also have remained a consistent distributor of cash to our unit holders post our public offering. Mock has delivered distributions totaling $5.67 per unit from the beginning of 2024 through our last announced distribution of 53 cents. This is an annualized yield of 15%. I doubt that you'll hear another energy company talk about cash returns. However, that is the lifeblood of our business and what makes us different. Additionally, we have delivered an average cash return on capital invested of greater than 30% over the last five years and 23% in 2025 during a down cycle. Clearly, one of the best records of all public equities, not just energy. Therefore, of our four pillars, maximizing distributions is the culmination of the other three and the most important. The second pillar is disciplined execution. MOC has never acquired an asset by paying more than PDP PV10. In other words, all of the blue sky of the company, the acreage, midstream, equipment, offices, are part of our purchase price. We have accomplished this goal 23 times and do not see an end to the requirement. Through this method of deploying capital, we've been diligent in assembling a set of assets across the MidCon and San Juan Basin that have drilling opportunities that we did not have to pay for. Most of our contemporaries are willing to pay millions of dollars per location when they buy into fashionable areas. What we have done is to buy in at least two areas that were seen as distressed when actually they were not. Since 2018, we've spent $1.4 billion developing assets that others thought were worth zero while compiling acreage that now amounts to nearly 3 million acres. And the additional luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash. Currently, both the MidCon and San Juan are seeing renewed outside investment searching for drilling rights. Also, the deep end of Darko is the only place we've expended capital to lease land. The vast majority of our acreage is held by production from the purchases that we've made. We will test the market and see if we can recoup any of our costs for acreage seismic other expenses associated with the deep anadarko. As I mentioned, the San Juan is also now very active with additional sales processes which are paying for upside where we did not. However, our land in the San Juan is all held by production and we are not in any hurry to sell there. we've done extremely well buying distressed properties, then finding them not in distress sometime later. For example, the Sabinol purchase, which closed last September, was bought when the market was certain we would see oil prices below $50. We believe that any time you can buy stable crude production in the 60s, you'll be rewarded at some point. This philosophy also drives our hedging decisions. We had 50% of our production in year one and 25% in year two on a rolling basis. We want to lock in near-term cash flow while having exposure to higher prices in the future. We have a strong belief that our business will be critical to the world over the next few decades and prices will have the tendency to rise faster than the rate of inflation during this time. Our peers have moved to asset-backed securities to purchase production, which takes away future upside and introduces risk from higher prices rather than reward. During the last year, we've moved from drilling oil-dominated assets in the Oswego and condensate window of the stack to dry gas locations in the Deep Anadarko and San Juan. Our reasoning is simple. The Bloomberg Fair Value Prize for West Texas Intermediate Crude Oil was $71.72 $71.72 in 2024. That reduced to $57.42 in 2025. The Bloomberg Fair Value price for Henry Hub natural gas was $3.43 in 2024. That price improved to $4.42 in 2025. In 2026, our drilling is once again concentrating on drilling natural gas wells in the San Juan and Deep End of Darko through the first half of this year. However, we are now preparing to bring back an oil rig in the Oswego and associated oil areas in the last half of 2026 if crude prices remain elevated. As you can see in the presentation updated this morning, Oswego drilling program is very good. Since 2021, we've drilled and completed more than 250 Oswego locations, which have consistently had rates will return above 50%. We also have locations in the Red Fork, Sycamore, and Osage that can be added to our drilling schedule. Therefore, we will plan to reduce the Deep Andarco capex by moving from two rigs to one rig and bring back on the Oswego program if the market allows. The flexibility to choose which commodity to produce depending on the price is one of the hallmarks of our company. The third pillar to discuss is disciplined reinvestment rate. Our goal is to return as much cash to our unit holders as possible, while staying within the guidelines for our strategic principles. We target a reinvestment rate of no more than 50% to maximize cash distribution while maintaining production and profitability. In 2026, we anticipate slightly growing our barrels of oil equivalent while maintaining our desired reinvestment rate. It's a task that is difficult to accomplish, especially with a set of assets that at the time of purchase were not supposed to have any upside value. However, we have not only accomplished this over the past eight years, but have thrived by drilling very high rates of return projects. In 2024, we projected our rate of return on drilling projects to be approximately 55%. In 2025, we made the move from oil to natural gas to maximize the rate of return in a difficult price environment. We succeeded by delivering rates of return of approximately 40%. Since our last earnings release, we have brought on production three additional deep anadarko locations. These three locations combine for approximately 40 million cubic feet of gas per day. In the Deep Anadarko, we anticipate an estimated ultimate recovery of approximately 19.5 BCF or 6.5 BCF per mile of lateral. We believe ranges will be between 5 to 8 BCF per mile of lateral. The Deep Anadarko is located, as the name implies, at a true vertical depth of between 14,000 to 17,000 feet, drilling an additional 15,000 feet of lateral projects make total depth between 29 to 32,000 feet. Our cost to drill and complete are projected to be between $14 to $15 million per location. In the San Juan, we plan to drill seven to eight dry gas main coast wells. The true vertical depth of the main coast is approximately 7,000 feet, and laterals are projected to be a mixture of two and three miles. A three-mile horizontal lateral Mancos well is projected to cost $15 million and recover approximately 24 BCF of reserves, with a 60% first-year decline. Our goal is to lower the drilling and completion costs to approximately $13 million during the 2026 drilling season. The drilling season starts on April 1st and runs through the end of November. The fourth pillar to discuss is to maintain financial strength. Our long-term goal is to have a debt to EBITDA ratio of one times. When we're at that level of leverage, we start to look for additional acquisitions that fit the pillar of disciplined execution. This is a self-imposed guideline to provide financial strength in any commodity price environment. Keeping our leverage low also enables us to flex upwards, as we did for the Transformity ICAV and Savinol acquisitions that closed in Q3 2025. By maintaining low leverage, we can toggle between drilling and acquisitions when opportunities arise in either direction. Currently, during a time when we're not looking to make an acquisition, we can maintain our production levels through drilling due to our low corporate decline of 17%. In other words, we do not have to make any acquisitions unless they fit within the parameters we have set to achieve our goal of maintaining production while deploying only 50% of our operating cash flow, while sending home all of our excess cash. We continue to believe in the long-term value of oil and natural gas. Our acquisition strategy continues to achieve the results we desire. We believe in patience and resilience. Rushing and forcing outcomes may not yield the best results. It is often good to remind oneself to remain calm and persistent while waiting on our desired outcome. As the proverb says, good things come to those who wait. I'll turn the call over to Kevin to discuss financial results.

Thanks, Tom. 2025 year-end reserves capturing the results of 2025 drilling and acquisitions during the year. more than doubled from 337 to 705 million barrels of oil equivalent. Also worth noting, the additions from the results of our development program exceeded the 2025 production by 18%. For the quarter, our production of 154,000 BOE per day was 17% oil, 68% natural gas, and 15% NGLs. Our average realized prices were 58.14 per barrel of oil, 254 per MCF of gas, and 21.28 per barrel of NGLs. Of the $331 million in total oil and gas revenues, the relative contribution for oil was 42%, 44% for gas, and 14% for NGLs. On the expense side, our lease operating expenses was $106 million for the quarter or $7.50 per BOE. Cash G&A for the quarter was $11 million or $0.77 per BOE. We ended the quarter with $43 million in cash and $338 million of availability under the credit facility. Total revenues, including our hedges, which contributed $42 million, and midstream activities, totaled $388 million. Adjusted EBITDA was $187 million and $169 million of operating cash flow and development capex of $77 million or 46% of our operating cash flow. Full year 2025 development costs of 252 million represented 47% of our operating cash flow. In the quarter, we generated $89 million of cash available for distribution, resulting in a distribution of 53 cents per unit, which was paid out yesterday. Rob, I'll turn the call back to you to open the line for questions.