Good morning, everyone. Thank you for joining today's call to discuss Mach Natural Resources' Second Quarter 2025 Financial and Operational Results. 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 will 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 annual report on Form 10-K, which is available on the company's website or the SEC's website. 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 the 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 will turn the call over to Mr. Tom Ward. Tom?

Thank you, Shamali. Welcome to Mach Natural Resources' second quarter earnings update. Each quarter, it is important to reiterate the company's 4 strategic pillars. These are: number one, maintain financial strength. Our goal is to have a long-term debt to EBITDA ratio of 1x leverage. We believe maintaining a turn of leverage is appropriate to give ourselves opportunities when markets experience high volatility. We accomplished the IKAV and Sabinal purchases by having low leverage. Sabinal provides us with long-term upside potential to oil markets priced in the low 60s. We feel this price is not sustainable very far into the future and that ultimately, crude prices will rise even if the near-term outlook is negative. If the OPEC+ announcement of bumper oil supply increases comes to pass, we want to stay in a position to capitalize on more crude oil purchases. In the case of IKAV, we purchased an existing natural gas cash flow stream that is heavily hedged with tremendous upside to market demand in the future and nearly unlimited growth opportunities in the San Juan Basin. Both acquisitions were made because our balance sheet was in pristine condition. We also see headwinds ahead for the natural gas prices as we enter the winter season with full storage and growing supply along with additional takeaway capacity being added before further demand develops in 2026. Therefore, we see continued opportunity to add to our portfolio as long as we maintain our leverage goals. Number two, disciplined execution. We acquire only cash flowing assets at a discount to PDP PV-10 that are also accretive to our distribution. We now have initiated 24 acquisitions, spending more than $3 billion. In every case, we have maintained this execution strategy. This strategy has allowed us to build an acreage base that will be nearly 3 million acres in size with multiple areas that have high rates of return drilling locations that are held by production. We believe that Mach is unique in this regard. Number three, disciplined reinvestment rate. We maintain a reinvestment rate of less than 50% of our operating cash flow. By keeping our reinvestment rate low, we optimize our distribution to unitholders. Mach is also unique in being able to maintain our production with an industry-leading reinvestment rate due to emphasizing our second pillar of disciplined execution. Our entry in the San Juan and Permian Basins will move our decline to 15% from 20% through buying low decline cash flowing assets. This allows us to enhance our operating cash flow and maintain our production during periods of low prices, while looking for areas to purchase if markets become destabilized. However, during periods of high prices, we can use our enhanced cash flow to reinvest more in drilling and grow production during those periods. Mach is positioned well to thrive in both scenarios by being able to pivot from acquisitions during higher prices to drilling of high-return locations that are waiting for us with no expiration dates. The IKAV acquisition is an example of this. In the San Juan, we are acquiring more than 500,000 acres of land that is held by production. If natural gas prices remain elevated, we can switch away from drilling crude oil locations to more natural gas-focused sites. We are planning to implement this strategy in 2026 by using the spring and summer drilling season with 3 rigs searching for natural gas in San Juan drilling for the Mancos Shale dry gas and the Fruitland coal. At today's strip, we plan to maintain our production volumes through 2027, while spending less than 50% of our operating cash flow and using some of the excess to pay down debt. We project increasing our natural gas volumes to 70% post the Sabinal and IKAV acquisitions, and for the first time since our inception, project natural gas to be at least 50% of our revenue stream starting in 2026. All of the main pillars lead to the fourth and most important, delivering industry-leading cash returns on capital invested through distributions to our unitholders. With our announced distribution of $0.38 per unit in the second quarter, we have set back $4.87 per unit to our unitholders since our public offering in October 2023 and more than $1.2 billion in total since inception in 2018. All the while, 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 5 years. Even in this year, with crude prices moving down, we are expecting to have a 25% return on capital invested and have never been less than 20% since our company was founded. Post the IKAV and Sabinal acquisitions, we anticipate having leverage just above 1x. However, we'll work diligently to bring back our leverage to our desired goal by presenting a clear path of reducing our debt levels. We will resist the opportunity to acquire other assets that would lead to moving our leverage higher. Our goal is to continue to look for free cash flowing assets where private equity-backed sponsors need to move towards a more liquid currency by taking our equity. In these circumstances, we see the opportunity to increase our operating cash flow while expanding our drilling budget on our vast acreage. We also continue to be able to purchase small acquisitions in the Mid-Con that fit our goals by using cash on hand. By sticking to our model of reinvesting only 50% of our cash flow, we can keep our production flat to slightly growing while expanding our distributions per unit. Our drilling plans for 2026 revolve around adding to our natural gas mix. We currently plan to have 2 deep Anadarko dry gas rigs running. These locations are targeting natural gas at a depth of approximately 15,000 feet true vertical depth. We then project to drill another 15,000 feet of horizontal length. These drills will cost approximately $14 million and find between 15 to 20 Bcf of gas and have returns in excess of 50% at today's prices. We'll also focus on the San Juan during the summer drilling season. In the San Juan, we plan to have 3 rigs running in 2026. The Mancos dry gas play is targeting 3-mile laterals at a true vertical depth of approximately 7,000 feet. We plan to spend approximately $15 million to $16 million per location to find 15 to 20 Bcf of gas and have a return of greater than 50%. The deep Anadarko and the San Juan gas plays are just developing. Both are known to be prolific gas areas that have not been extensively drilled since the onset of enhanced drilling procedures with large stimulations due to the previous decade of low natural gas prices. Mach has hundreds of thousands of acres across the place to review and bring to market with no time pressure to be implemented without losing our acreage. We also plan to have 1 drilling rig drilling in the Fruitland coal. This development is ongoing in the San Juan with rigs targeting the coal between older vertical wells by drilling multiple laterals from 1 wellbore. The target is shallow at 2,000 feet, and we anticipate having 5,000 to 8,000 feet of lateral in each wellbore. These locations are expected to cost approximately $3 million and have returns in excess of 50%. Lastly, we plan to move back into the Oswego to continue our drilling program that was started in 2021. We've drilled more than 250 wells in the Oswego where a 1.5-mile lateral costs less than $3 million. And even at today's distressed oil pricing, it has returned approaching 40%. Our second deep Anadarko rig is projected to spud in early September. The Oswego locations are projected to start in early 2026, and the San Juan rig should move in early spring 2026. Our focus on gas development through 2026 is driven not only by the current price environment but also by how we see demand over the next 5 years. We see total demand growth of upwards of 25 Bcf of gas per day by 2030. This is broken down to the following: 15.6 Bcf per day of LNG feed gas growth. This includes the facilities under construction in Mexico, which will be an additional outlet for U.S. production and our San Juan purchase is well positioned to meet West Coast demand. 6 Bcf per day of power generation growth is a conservative estimate, but it should be acknowledged that 2 to 4 Bcf of power generation growth will be from the data centers located in Texas, Colorado, the Desert Southwest, and California. Thus, the San Juan acreage is also strategic and well positioned to meet this upcoming demand. 1.1 Bcf per day of demand growth from commercial and industrial and 1.4 Bcf per day of growth from exports to Mexico. We see supply of 6 Bcf per day from the Permian associated gas growth, which is at risk if prices remain soft. 15 Bcf per day of supply growth in the Haynesville and the Northeast in response to LNG and data center demand. This leaves the Eagle Ford, Mid-Con, and San Juan Rockies as the natural supply growth areas to meet demand. We see the current processing capacity of approximately 4 Bcf per day in the San Juan and nearly 16 Bcf per day in Mid-Con to meet the ongoing demand requirements needed to fuel or enhance consumption of U.S. natural gas. During the quarter, Mach drilled 10 total wells consisting of 6 Oswego, 3 Woodford-Miss condensate, and 1 Red Fork location. We're currently drilling 1 Red Fork and 1 deep Anadarko dry gas well. These rigs are located in Dewey and Custer Counties, Oklahoma. In our Oswego program, we averaged 9,850 feet per lateral, our longest locations to date. These locations averaged $3.6 million per well. Mach drilled 3 locations in the Woodford-Miss Program, including the Brockland 3MH, which was drilled to a total depth of 30,384 feet. The Brockland 3MH is waiting on completion alongside the Brockland 2MH, which is drilling currently. Both locations will be completed together starting later this month. In the Woodford-Miss condensate area, we drilled 2 locations that averaged 10,240 feet of horizontal section. Our operation goals for Q3 2025 were to continue to refine and reduce our days on location in our deep Anadarko drilling program while increasing our rig count from 1 to 2 starting in mid-September. We continue to keep our lease operating costs low at $6.52 per barrel and look forward to closing both the Sabinal and IKAV asset purchases to start to work on reducing costs. We're not certain there are additional places to cut LOE. However, in our previous 22 acquisitions, we reduced LOE by between 25% to 33% each. With that, I'll turn the call over to Kevin for the financial results.

Thanks, Tom. For the quarter, our production of 84,000 BOE per day was 23% oil, 53% natural gas, and 24% NGLs. Our average realized prices were $63.10 per barrel of oil, $2.81 per Mcf of gas, and $22.41 per barrel of NGLs. Worth noting, pre-hedge realized prices were lower by 11%, 21%, and 17% for oil, gas, and NGLs compared to the first quarter of this year. Of the $219 million total oil and gas revenues, the relative contribution for oil was 51%, 31% for gas, and 18% for NGLs. On the expense side, our lease operating expense totaled $50 million, as Tom mentioned, $6.52 per BOE. Cash G&A was only $7 million, $0.88 per BOE. We ended the quarter with $13.8 million in cash, and we had drawn on our $750 million revolver. In conjunction with our plan to close the IKAV and Sabinal acquisitions, we are in the latter stages of expanding our RBL and expect the borrowing base and commitments to nearly double from its current amount and to add a handful of new banks to the syndicate. Total revenues, including our hedges and midstream activities totaled $289 million, adjusted EBITDA of $122 million, and $130 million of operating cash flow. We had development CapEx of $64 million. During the quarter, we also had a reduction of cash available for distribution of $8.2 million due to a settlement of a royalty owner legal dispute. We generated $46 million of cash available for distribution, resulting in improved distribution of $0.38 per unit, which will be paid out on September 4 to record holders as of August 21. Shamali, I will now turn the call back to you to open the line for questions.

Our first question comes from Charles Meade with Johnson Rice.

Tom, your production volumes were higher than I anticipated, and it seems many others felt the same way. Could you clarify which part of the legacy Mid-Con portfolio contributed to this unexpected performance? Was it a surprise for you as well? What segments showed the most strength, and did they relate to the recent wells you mentioned in your prepared remarks?

No, Charles, our production is performing well as part of normal operations. We have made a couple of small acquisitions that may have improved some aspects of production, but overall, everything is already in good shape. Our operations team is exceptional and continues to efficiently manage our locations with many workovers. I would say our operations team does an excellent job focusing on the business, and there is nothing unusual to report.

Got it. Okay. And then, Tom, going back to the details you provided in your prepared comments, I was intrigued by the Brockland 3MH well. Is that one of the deeper Anadarko targets you mentioned earlier? The $14 million well cost is targeting 15 to 20 Bcf. Can you let me know if those two are connected and also provide a timeline for when you expect to complete the Brockland?

Yes. We're drilling the second location currently on a 2-well pad, we'll do a zipper frac between the 2 locations that will start in later this month to early September.

For my first question, I wanted to focus on distribution this quarter. Despite the strength of operations, this quarter in production and Charles just covered that. There were a series of onetime events that led to a lower payout than the cash flow minus CapEx would imply. Could you perhaps add some color to those developments for the benefit of investors?

Sure, Derrick. We've streamlined the information for clarity. The legal settlement we reached was related to a common type of litigation in our industry. While it may not be routine for us, we settled a dispute with the royalty owner regarding deductions from their revenue, and our portion of that settlement amounted to approximately $8.2 million, which led to a reduction of $0.07 per unit in distributions. Additionally, lower gas prices this quarter, when compared to the first quarter and current analyst estimates, resulted in another $0.07 decrease from what we would have seen with first-quarter prices or based on consensus estimates. Furthermore, the Panhandle Eastern basis differential was somewhat unique, as we experienced a widening of the basis during the second quarter, which likely went unaccounted for in many analysts' estimates.

Okay. Great. And then as my follow-up, I wanted to focus on your growth profile. As we layer in recent transactions and your deep Miss activity, we're backing into a fairly material natural gas growth trajectory that could exceed 650 million cubic feet per day in 2026. And that's quite a bit above consensus. Is that a fairly fair depiction of the production profile as you guys see it?

Yes, we anticipate our natural gas product mix will exceed 70% in 2026 and approach 75% in 2027. This projection assumes we will continue to have a strong natural gas market, which we believe will persist. While we acknowledge some short-term challenges, we are optimistic about the natural gas market in late 2026 and 2027. The current influx of gas during the fill season puts us in a delicate position as we head into the fall and winter with full storage and several new pipelines coming online ahead of demand. Once demand increases in 2026, we want to position ourselves positively in the gas market. That being said, we are planning to continue drilling natural gas wells independently, without pursuing additional acquisitions. We expect our product mix to significantly rise above 70% natural gas.

We agree with your views, Tom. And maybe just one build on that, just for the benefit of clarity. When you look at your gas production base, you guys, as I understand, have quite a bit of that undedicated today, so you can materially steer that and benefit in a much higher gas price environment than some of your peers. Is that a fair depiction as well?

Yes. I don't know as compared to our peers, but yes, we do have a large amount undedicated.

When we look at the portfolio that you all built, which is anchored on these very stable, low-decline-rate assets, and now you've got this exciting opportunity with the Mancos as well as what's emerging with the Anadarko deep gas. And I'm just interested in your thoughts on kind of how you balance those 2 aspects of your portfolio with kind of legacy proven, low-decline assets, with now like this, an emerging growth play like the Mancos?

Yes. So it all just ties together with our reinvestment rate. So we want to spend 50%. We don't want to spend 20% or 30% or 40%. We like to spend close to 50% of our operating cash flow that keeps our production flat. And the only way you can do that is to have that long life, the balanced portfolio, as you mentioned, of low-decline production that we've built over the years that then allows us to reinvest only 50% in the higher rates of return drilling that the Mancos now and the deep Anadarko, especially, and I guess the Fruitland coal is probably the best of the group as far as just infill drilling and rates of return. But whenever we put that all together, it just gives us a lot of flexibility. We can pivot from oil to gas. We can move back to oil if prices change. We have 3 million acres of high-return drilling locations that we can choose from. So we're in a really ideal situation that we built ourselves now down to a 15% decline that we can continue to grow our production using only 50% of reinvestment rate and choose what rates of return we want and have no real long-term contracts that keep us beholden to drill one particular area over the other. And we don't have any lease expirations. So we truly are able to move around rigs as we want within 30 days.

That's great. The gas differential has widened significantly this quarter, as you mentioned earlier. I understand you've made some recent moves in gas marketing to potentially improve that situation moving forward. Could you provide more details on that? I don't think there's much to say. Essentially, we rely heavily on Panhandle Eastern for most of our Mid-Con gas. Therefore, if the basis widens, our basis also widens, as we do not hedge basis. Kevin seems ready to contribute. Would you like to add something?

Yes. Hey, John, we were talking a little bit about GP&T expense running a little higher due to new treatment of certain costs, certain marketing costs related to the Paloma wells. We had a marketing agreement with kind of a third-party intermediary, and we chose to get out of that agreement and fold in those volumes with kind of the bigger, larger group that we've marketed gas with for years.

Yes. So we use NextEra. Right. And...

Yes, we'll get better pricing with NextEra than we had with the previous intermediary.

I wanted to just talk about 2026. So I realize it all depends on where oil and gas prices go. But based on what you're thinking right now, it sounds like the 3 rigs in the San Juan will drill springtime through summer. I think there's a limited drilling window there. You keep the 2 deep rigs in the Anadarko and then one on the Oswego. Is that where your '26 plans are preliminarily at the moment?

Yes, it really hinges on our operating cash flow. The situation is influenced by pricing and EBITDA levels, so it could increase if prices rise or decrease if they fall. Our spending is tied to 50% of our operating cash flow, and that means there's no guarantee for a development program. Changes in gas and oil prices can also impact our plans. Additionally, it’s challenging for us to predict exactly where our rigs will be because we make those decisions monthly, so I can't provide a definitive answer.

No, I appreciate how fluid that is and your flexibility, but I just want to get your latest thoughts based on...

That is as of today and where our EBITDA sits today, this is exactly what we plan to do. And also permitting. San Juan's not the easiest place to drill of the New Mexico side. You basically have May to December to have everything through. And so that has us kind of in the drilling season of May to September.

Okay. I understand. For the second half of this year, I believe Sabinal had a rig operational. Are there wells planned for completion on the Central Basin platform, or will you pause all activity once the deal is closed?

Yes, they had 2 rigs operating out of 4 locations that they are waiting to complete once we close.

Right. Got it. And then I wanted to ask one more on the kind of unusual items for the quarter. It looked like, to us, we could have it wrong, that your GP&T costs kind of popped up for the second quarter. Is that correct? Or anything unusual happened there?

Yes. Due to the marketing arrangement change that we mentioned, and that took place at the beginning of the second quarter, there's essentially a reclass. I won't bore you with the FASB number of the provision, but it's a reclass of moving GP&T up and revenues also go up. So it is a kind of bottom line neutral impact, and it just has to do with wind title to the gas changes and it's in association with this new marketing arrangement. So net-net, it's kind of a zero-sum game, but in the individual categories of revenue and GP&T, they both went up by similar amounts.

Okay. I understand. So it was primarily the gas price that accounted for the difference between our estimates and others, and there hasn't really been any change in your views regarding gathering and transportation costs?

No. When we update guidance and finalize the acquisitions, that line item will adjust to reflect the new arrangement, but our basis differential above will also change.

And ladies and gentlemen, we have reached the end of the question-and-answer session. And also, this concludes today's conference. You may disconnect your lines at this time. We thank you for your participation. Have a great day.