Good morning, everyone. Thank you for joining today's call to discuss Mach Natural Resources Second Quarter 2024 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 the forward-looking statements, including the factors identified and discussed in our press release this morning and 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, which is 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, and Kevin will discuss Mach's financial results, and then the call will be opened up for questions. With that, I'll turn the call over to Mr. Tom Ward. Tom?

Thank you, Kevin. Welcome to Mach Natural Resources second quarter earnings update. I start each call describing our company framework or our four key pillars. These pillars are focused on being a distribution company as follows: Number one, maintain financial strength. Our goal is to have a long-term debt-to-EBITDA ratio of 1 times or less. By maintaining a low leverage profile, we give ourselves opportunities when markets experience high volatility. Number two, disciplined execution. We acquire only cash-flowing assets at a discount to PDP PV-10 that are accretive to our distribution. 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. Number four, maximize cash distributions. We target peer-leading distributions. This pillar drives all of our decisions. Now on to the second quarter results. In the second quarter, Mach averaged 89.3 MBOE per day of production. This production exceeded our high end of guidance. Our drilling program continues to perform in line with estimates. We achieved another quarter of successful expense and cost control. Lease operating expenses of $5.72 per barrel of oil equivalent were below the low end of guidance, and our new well costs have been below our initial projections, resulting in our drilling program dollars being invested more efficiently. We also divested a small portion of our Western Anadarko acreage for $38 million during the quarter. Mach controls approximately 1 million acres of land that are held by production. The Anadarko Basin has become a focal point of many new and existing drilling programs. These new ideas respond to attractive prospects on lands that we have owned for several years. We are utilizing land as an asset that can be used in times of lower prices to enhance our distribution while not affecting our near-term drilling inventory. We captured some of the value from this asset in the second quarter by selling less than 13,000 acres in an area that we had not targeted for drilling. We continue to hold large land positions in the area for future development or divestiture. Also, during the quarter, we used $21 million of cash to pay down existing debt. This debt payment was the first amortization payment on our first lien term loan. Lastly, we declared a quarterly cash distribution of $0.90 per unit. Mach is an acquisition company that focuses on investments accretive to our distribution. Through this model, we've been active acquirers since 2018. Over the past five years, we have actualized a multiple on invested capital of 1.7 times and averaged the cash received on capital invested of 31%, which we believe is best in class. Through 17 acquisitions, we've acquired vast landholdings that we did not pay for, but now have become valuable assets. In fact, we have many more potential drilling locations than we have operating cash flow to satisfy. Therefore, we have the ability to sell lands or grow our operating cash flow through acquisitions. We then use only 50% of our operating cash flow to drill with while distributing the remainder. In this way, we can pivot more towards drilling at times of higher prices when acquisitions become expensive or more towards acquisitions in times of uncertainty. The largest driver to our distribution is the price we receive for our production. In the second quarter, we received a very low realized price of $1.33 per Mcf for the natural gas we produce. Natural gas makes up 53% of our production and is important to our projected distributions. Obviously, we look forward to receiving a higher price for natural gas production in the coming quarters than we received during this past quarter. Our drilling program continues to achieve results in line with our expectations. Mach currently has 2 rigs running. One of the rigs continues to drill the Oswego formation in Kingfisher County, Oklahoma, and 1 rig is drilling the condensate window of Canadian County, Oklahoma. Since mid-2021, Mach has drilled over 200 Oswego locations and continues to hold a large inventory of wells to be drilled. In the second quarter, Mach spread 12 gross wells and brought online 14 gross operated wells across the combinations of both areas. This drilling cadence is in line with our expectations through the end of 2024. Our CapEx program continues to point towards a reinvestment rate of less than 50% of our operating cash flow for 2024. We reduced our rig count in the Oswego from 2 rigs to 1 rig during the quarter, which resulted in a reduction of CapEx guidance by 15%. As mentioned earlier, our operations team continues to cut expenses on drilling, completions, and lease operating. We adjusted lease operating expense guidance down by 3% per BOE. Our drilling costs have improved due to efficiencies gained through days on location and cost cutting. We first projected our deeper locations in the condensate window to cost $8.6 million per well and costs have been coming in at $7.6 million per well. This compares to our predecessor spending of $9.6 million per well. We moved our Oswego total cycle time per well down to 10.1 days and spent $2.6 million per location. We've added lateral length to further enhance our overall performance. Our average lateral length was extended from 5,400 feet to 6,000 feet during the quarter, and the overall cost was lowered by $32 per lateral foot. We continue to look for ways to lower expenses while maintaining our expected results per well. Mach's goal is to find the cheapest molecules to purchase and then convert those molecules into accretive distributions to our unitholders. In the past, the Mid-Con was the area where the most value could be found per dollar spent. Now the Mid-Con has become a highly sought-after drilling area. Therefore, the time has come for us to expand to other basins where production is less expensive for cash flowing assets. We are actively reviewing projects outside of the Mid-Con as well as continuing to look at all Mid-Con opportunities. We believe in the next few quarters we will substantially add to our portfolio and distributions per unit. I'll now turn the call over to Kevin to discuss our financial results.

Thanks, Tom. I'd like to open with a quick reminder that the comparative income and cash flow statements for both the second quarter and year-to-date for last year reflect only the results of the predecessor entity Mach 3, whereas the 2024 results capture all of the entities and assets of Mach Natural Resources. For the quarter, our production of 89,000 BOE per day was 23% oil, 53% natural gas, and 24% NGLs. Our average realized prices were $79.27 per barrel of oil, $1.33 per Mcf of gas, and $23.83 per barrel of NGLs. Of the $232 million in total oil and gas revenues, the relative contribution for oil was 65%, 15% for gas, and 20% for NGLs. On the expense side, as Tom has mentioned, our lease operating expense of $46.5 million or $5.72 per BOE, again, came in lower than predicted and was a catalyst for us to lower full year LOE guidance. Cash G&A was slightly over $9 million or only $1.12 per BOE. We ended the quarter with $145 million in cash. Our $75 million revolver was undrawn, and our first lien term loan principal was approximately $804 million. Total revenues, including our hedges and midstream activities, totaled $240 million. Adjusted EBITDA was $136 million and $117 million of operating cash flow. After our CapEx for the quarter of $45.6 million, we generated $67.5 million of cash available for distribution, which we used to pay $21 million principal in the first lien term loan and the remainder plus the $38 million of proceeds received from the acreage sale mentioned earlier gives us a total distribution of $85.5 million or $0.90 per unit. This will be paid on September 10th to holders of record as of August 27th. Kevin, we'll turn the call back over to you to field questions.

Our first question today is from Charles Meade from Johnson Rice.

Tom, I wanted to ask about the drop in the rig in the Oswego. It looks like you had a plan to drop that at some point this year, but that – with the CapEx guide down, you did it a little earlier than maybe contemplating your guidance back in February. So I wonder if you could characterize whether that's – or tell me whether that's the right read on the change in your plan and give a little insight into your decision process about why you dropped the rig in 2Q as opposed to run it longer?

Sure. It's very simple that we want to stay under 50% CapEx to our operating cash flow. And so the Oswego rig, we had 2 Oswego rigs running with that cut, then it moved us under 50% for the year of operating cash flow. I'd love to have 2 rigs running or 3 rigs running at Oswego once we get our operating cash flow up.

And then the follow-up: you talked about your D&C performance versus acquisition case on those assets that you acquired from Paloma. I wonder if you could talk about the other side of the coin, how those wells are producing in the early days versus your acquisition case?

Yes, in line with our acquisition case. And really, anything we acquire that we drill on our new drills should just be in line with projections or if you look at Enverus or others, we shouldn't be outperforming those usually we drill interior to other wells that have been drilled. So we don't do step-outs, thus selling the first part of the Cherokee acreage that we did because those wells are fairly new. So anything that we're drilling is in a fairly known area, and we really shouldn't outperform those around us. In fact, the risk would be that we have depletion. And so that's how come we're very careful with well spacing.

Your next question is coming from John Freeman from Raymond James.

First topic. Last quarter, Tom, you mentioned about the increased competition you've been seeing in Oklahoma and that others were willing to pay a substantial premium for undeveloped locations. And obviously, you're reiterating kind of those comments again on this call. And it sounds like what you're saying then is this divestiture that you all did where you kind of took advantage of that kind of heightened competition by divesting some of those Western Anadarko package. It sounds like that, that may not be just a one-off that there could be opportunities in the future just given your massive acreage position to take advantage of that additionally going forward. Is that the right read?

Yes. So in the proven area of the Cherokee shale play, we have probably another 40,000 acres inside of Mach and then inside of Oklahoma and the Cherokee overall area closer to 100,000 total, including that 40,000. So 60,000 acres-or-so that are outside of the proven area and 40,000 in. So as those wells are drilled, we only sold a small portion so we can watch wells that are being drilled and determine if they can then compete with other locations. The fact is that we have a large amount of locations to drill, and we need to increase operating cash flow in order to get to those locations. So we continue to look for ways to find PDP production or crude fill-producing wells to bring in cash flow so that we can increase these proven locations we have in known areas with good rates of return. And so the reminder is that we don't use our drilling program to try to grow our production; we use it to stabilize our declines.

And then you've talked in the past, Tom, about your bullish outlook on natural gas over the coming years with LNG, the increase kind of power burn, et cetera. As you kind of look at the gas strip and as we kind of start to roll through 2025, can you sort of talk about the flexibility that you've got in your properties from kind of a capital allocation perspective? And maybe just some insight into, is there a certain gas price level where you think you might shift more into some of your gassier assets?

It's primarily driven by the rate of return. We hold significant acreage in both the condensate and deep gas windows, which are located in proven areas that have been previously drilled. We monitor this closely. Our main challenge is that we operate two types of rigs: a deep rig that can work in both the condensate and deep gas windows, and smaller rigs focused on the Oswego on the shelf. These rigs are not interchangeable. For instance, we aspire to operate two rigs in both areas, aiming for this near-term goal by 2025, provided we are able to complete some acquisitions we are currently considering.

Our next question is coming from Michael Scialla from Stephens.

I wanted to try and understand your guidance a little bit better. Is that change on the production guidance going forward strictly due to the activity levels? And I think, Tom, you had mentioned you expect the activity to drilling at least to be similar for the second half of the year as it was in the second quarter. Is that the same for the new wells you expect to turn in line? Is that kind of 12 net wells each quarter a good run rate for third and fourth quarter?

Yes, this is Kevin. I expect the rate of drilling and the number of wells completed to remain fairly consistent with what we experienced in the second quarter. You are correct regarding the decrease in our oil production guidance. There are a couple of factors contributing to this: we are dropping a rig late in the first quarter in the Oswego, and we are also facing some delays with certain deeper wells that are coming online, which has led to a lower production forecast.

So nothing really with well performance that surprised you or the mix oil versus gas, it was just the activity level?

That's correct.

And then, Tom, you mentioned the increased competition for deals within the basins, got you thinking about or looking outside of the basin without, giving away too much, can you say where you may be seeing opportunities where you don't have to pay for undeveloped acreage or at least characterize what kind of assets you might be looking for?

Yes. So we're just looking for cash flowing assets. We have all of the drilling opportunities we need. So really, if we can buy something at less than PDP PV-10 that is a steeper discount than what we can find in Oklahoma and put that operating cash flow to work back into the line of drilling that we have, I think that's where we're searching. So anywhere that's dislocated could be for a number of reasons. You might look in second tier, what would be considered second-tier Eagle Ford or Permian, the California is out of favor because of their regulatory environment, so any of those types of opportunities that lower PDP or discounts to PDP are things we'll look at.

Our next question is coming from Geoff Jay from Energy Partners.

Just it's kind of a curveball, but thinking very, very long term. Obviously, there's been a lot of attention to refrac and kind of the Eagle Ford, Bakken, Barnett, I wonder if you think about your PDP assets over the next several years, if you think there might be an opportunity to do some refracs on your acreage?

I've never had any luck with it. I don't know. Rick, do you see? No? Rick is shaking his head. Our acreage doesn't really look like it could refrac. Maybe if other people came in and led the way, we will not be the instigator of refracking here.

Your next question is coming from Jeff Robertson from Water's Research.

Tom, on the competition question, do you anticipate more opportunity in 2025-2026 as some of the consolidation that's taking place causes people to rationalize their portfolios? And then secondly, do you also think that would just bring in increased competition and have an impact on valuations?

Yes. The Mid-Con right now is kind of the second hottest area for exploration that there is outside the Permian. It just has changed very quickly in the last six to eight months. Something that surprised us. It's good for us because of how much acreage we have here, and as more people drill in different areas, it proves up a lot of the acreage of ours that we have held by production. But then I think the other part of the question is as consolidation happens in the industry, people are looking at new areas to go, they're looking more at the Mid-Con because it was a cheaper area than other areas with the same type of drilling upside. So I think that leaves us with maybe the ability to zig when others are zagging and move into back-end areas that are being left behind, and that's our goal.

We reached the end of our question-and-answer session. I'd like to turn the floor back over to management for any further or closing comments.

No more comments. So we appreciate everybody's interest in the company and look forward to speaking soon. Thanks.

Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time, and have a wonderful day. We thank you for your participation today.