Operator: Good morning, everyone. Thank you for joining today's call to discuss Mach Natural Resources Third 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 their 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 to 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, 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?

Tom Ward: Thank you, Darryl. Welcome to Mach Natural Resources third quarter earnings update. As a reminder to anyone listening who might not know too much about Mach, we are an upstream energy MLP. We like the attributes of the MLP model for unitholders, the tax benefits and the focus on returning cash. We also remember and acknowledge the misgivings that others made during the previous period, now a decade ago due to chasing growth with runaway leverage and fixed distributions along with misalignment between the unitholders and the general partner. Our strategy from the beginning was to buy distressed cash-flowing properties when others were seeking growth through leasing and drilling and outspending cash flow. We were certain the growth model was flawed. And as a result of their failure we were able to purchase the bulk of our cash-flowing assets at steep discounts to PDP PV-10. It was not the assets that were bad, but the execution of the asset. We feel the same way about the upstream MLP model. Therefore, we came up with four pillars to build a successful company as follows. Number one, maintain financial strength. Our goal is to have a long-term debt-to-EBITDA ratio of one-time or less. By maintaining a low leverage profile we give ourselves opportunities when the 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 decisions. In order to maintain the four pillars of our company, we also need to emphasize that our distributions are variable. Therefore, we distribute more cash to our unitholders in times of rising prices. We want exposure to energy for the long-term and like being invested in a company that has upside to commodity pricing. We believe that the poor seven billion people on earth want to achieve the same standard of living as the wealthy one billion. Energy will be the key catalyst for them to do so. Over time this shift will drive demand for our products, not to mention the increased demand for power generation that's already widely discussed. However in quarters of lower pricing, our distribution will also be lower. To offset large risk to falling prices while maintaining exposure to gains, we have chosen to hedge 50% of our next 12 months' production and 25% of the second 12 months. Since 2018, Mach has invested $1.9 billion by raising $520 million of equity. We have $600 million of net debt and we’ll have distributed $962 million to unitholders. This results in an actualized MOIC of 1.9 times and an average CROCI over the last five years of 31%. We did all of this without selling any producing properties and built a company that has $2.3 billion of enterprise value. In the third quarter, we realized average prices of $74.55 per barrel of oil, which is 6% lower than Q2 and $1.73 per Mcf of natural gas. If crude prices or natural gas prices were to deteriorate even further, we are positioned to make acquisitions that ultimately will be accretive to our distribution due to maintaining low amounts of leverage. If prices have moved up, we are positioned to use more than -- or more than 1 million acres of land across the Anadarko Basin to drill more aggressively while staying within our 50% reinvestment rate. This ability to pivot is one of our unique strengths and will continue to underpin our success regardless of which stage of the commodity cycle we are in. Another point of pride is the ability to assimilate acquisitions into our company at very low cost. Our lease operating expense for the third quarter was $5.85 per BOE, which is at the low end of guidance. For the third quarter, we drilled and brought online 11 gross and nine net wells while running two rigs. We also had five gross and four net operated wells at various stages of drilling and completion. Our guidance for 2025 increases our rig count to three rigs with two drilling deeper wells and one drilling the shallow Oswego wells. We plan to expand our drilling in 2025 to locations in the Ardmore Basin on our recently announced acquisition lands in Stevens County, Oklahoma, drilling the Mississippian Sycamore formation and Woodford wells, plus in previously held Custer County, Oklahoma drilling Deep Miss and Red Fork locations, along with the locations in Canadian County, Oklahoma. Drilling is important to us, generating attractive returns and offsetting natural production declines while keeping the reinvestment rate at or below 50%. However, acquisitions will be the primary driver for production growth and associated growth in future distributions. As I mentioned, in Q3, we had 2 rigs running. We continue to find ways to drill more lateral length while spending less per foot. In the Oswego, we averaged a spud to total depth time of 7.43 days while spending $204 per lateral foot. This compares to an average of 10.1 days and $206 per lateral foot in Q2. We also increased our lateral length from 6,123 feet to 6,536 feet in Q3. Our overall cost per completed foot fell from $248 to $231 from Q2 to Q3. In the Woodford, the average completed length was 10,222 feet compared to 10,122 feet in Q2, while the cost per completed foot moved down from $368 to $357. The average completed drilling and completion cost was $7.7 million compared to our predecessors $9.7 million. In both areas, our service costs have remained constant, except for a small reduction in casing prices during the quarter. In the third quarter, we completed a follow-on public offering, generating proceeds of $129 million to fund the two acquisitions announced. We continue to use equity as a useful tool to keep our leverage low while adding to our distribution per unit. As a large unit owner, I'm pleased to fund acquisitions in this manner while increasing our distribution per unit, all the while maintaining our leverage at or below 1x. During the quarter, we have noticed that our pipeline of deals continues to improve. We have more interest from parties willing to sell at prices that are moving into our range and also parties that are willing to engage in discussions regarding trading producing assets for our units. We will see if this materializes into deals that create higher distributions per unit in the coming year. With that, I'll turn the call over to Kevin to discuss our financial results.

Kevin White: I would like to open with a quick reminder that the comparative income and cash flow statements for both the third quarter and year-to-date for last year reflect only the results of the predecessor entity, Mach III, whereas the 2024 reported results capture all of the entities and assets of Mach Natural Resources. For the quarter, our production of 82,000 BOE a day was 23% oil, 53% natural gas and 24% NGLs. Our average realized prices were $74.55 per barrel of oil, $1.73 per Mcf of gas and $22.61 per barrel of NGLs. Of the $209 million in total oil and gas revenues, the relative contribution for oil was 60%, 20% for gas and 20% for NGLs. On the expense side, our LOE of $44 million or $5.85 per BOE again came in at the low end of guidance. Cash G&A was approximately $8 million or only $1.08 per BOE. We ended the quarter with $184 million in cash a bit elevated since we did not close the Ardmore Basin acquisition until October 1st. Our $75 million revolver was undrawn and our first-lien term loan principal was approximately $784 million. Total revenues including our hedges in midstream activities totaled $256 million, adjusted EBITDA of $134 million, and $111 million of operating cash flow. After CapEx of $53 million, we generated $52 million of free cash which we used to pay $21 million of principal on the first-lien term loan and the remainder plus excess balance sheet cash results of the $62 million or $0.60 per unit distribution for this quarter. As we announced this will be paid on December 10th to holders of record as of November 26th. Darryl, I'll now turn the call back to you to open the line for questions.

Operator: Thank you. We'll now be conducting a question-and-answer session. [Operator Instructions] Our first questions come from the line of John Freeman with Raymond James. Please proceed with your questions.

John Freeman: Good morning guys.

Tom Ward: Good morning.

John Freeman: Yes. First question. So, the 2025 plan you said assumes a three-rig program just given you all highlighted the improved cycle-times and lower cost per foot, what is the 2025 program assumed for turn-in-lines?

Tom Ward: For turn ons, how many wells we're turning on? I'll get that for you in just a second.

John Freeman: Okay. and then the other part--

Tom Ward: Well, I hear it's -- John it's -- Kev says it's a little over 40 -- gross wells.

John Freeman: Perfect. And then just sort of a tack on to that. I know like the 2024 program, it was a lot heavier front-end program. Obviously, 1Q was dramatically bigger sort of activity for you all for the year. Is the 2025 program a little bit more smoothed out? Is there any lumpiness that we need to be aware of in that program?

Tom Ward: Well, it's not set up to be so -- as the 2024 program really wasn't when we first went into it. It all depends on pricing and the 50% reinvestment rate. Right now we plan to have the third rig coming in February and that will go to the Ardmore Basin to start drilling. So, we anticipate keeping that rig in Southern Oklahoma basically throughout the year. And then having a rig working between Canadian County in Central Oklahoma to Western Oklahoma the Red Fork sand play that's being developed. They're currently in some of our other Mississippian -- Deeper Mississippian wells in Custer County. So, I don't foresee anything being lumpy, but if crude prices were moved down or natural gas prices further and it looks like we'll be -- it would be over our 50% reinvestment rate, then we would move back on CapEx.

John Freeman: That makes sense.

Tom Ward: The opposite -- I guess the opposite would be true if we made an acquisition or we had more operating cash flow through higher prices, we'd add a rig.

John Freeman: That definitely makes sense. And then if I could just sneak one more in on LOE. Obviously for the year you all have averaged well below that full year guidance. I think you're right around a little over $5.5 of BOE relative to the guide of $5.80 to $6.10, obviously, implies kind of a step-up -- a fairly meaningful step-up in 4Q. Just any sort of color around that would be helpful. And that’s my last one. Thanks.

Tom Ward: You go ahead and answer Kev. Kev's going to answer.

Kevin White: Hey, John, this is Kevin. I think the higher guide for LOE per BOE in 2025 is driven mainly by flush production this year. With the newly acquired Paloma assets and that steeper decline profile, it drove down our LOE per BOE metric this year a little bit.

Tom Ward: Yes the Paloma wells that we inherited were very high producing a lot of gas with them too. So that had low lifting costs.

John Freeman: Got it. Thanks, guys. Appreciate it.

Tom Ward: Thank you, John.

Operator: Thank you. Our next questions come from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade: Good morning, Tom to you and your team there. My first question might be for Kevin but obviously, you guys will decide. You guys closed the most recent two acquisitions I guess, you closed the latter of the two on October 1. Can you give us some sense of how the early days are going there and what we should be thinking about for the incremental volumes from that acquisition, which is I guess maybe a roundabout way of asking what should we be thinking about for fourth quarter production?

Kevin White: Yes for both the Ardmore Basin and the Kansas assets, the grand total of the combined production I think was about 5000 BOE a day when we acquired them. And that really wasn't high enough to push us in the fourth quarter to expect to be out of the guidance range.

Charles Meade: Okay. Got it. That makes sense.

Tom Ward: Yes, Charles, whenever we made guidance originally we had three rigs running in the quarter, first quarter of last year and this kind of brought us back up into the higher end of guidance.

Charles Meade: That makes sense. That's helpful. I didn't see it that way before. So, thank you. And then Tom, you mentioned drilling in Custer County, the Red Fork and the deeper Mississippi. And I think that that's further west in the Anadarko than you've drilled at least as Mach. And I wonder if you could put that – tell me if that's the right read and put those – put that planned 2025 Custer drilling in context of what we should expect from those targets?

Tom Ward: Yes. We have – we participated in several Continental wells in Custer County over the past few years and had a nice block of acreage. We purchased from MEP in 2021 I believe. And that acreage has been sitting there. And now with the deeper rig that we have operating, it is capable of drilling those types of wells. So we just incorporated really – all as we look forward is rates of return and the Red Fork area that's being developed by Mewbourne in Western Oklahoma has been good all up and down drilled Custer and on out the Cherokee shale that they have in Ellis and Roger Mills is being developed also. So all in all, as we're not usually and really don't pride ourselves on being first movers. But once somebody establishes an area around our locations if it can compete from a rate of return with our existing units to be drilled we put it in our drilling plan. So that – you might see a little more gas coming out of those locations also. The 2025 program is probably a little more lumpy from production just because of more pad drilling from actually even going two different directions in the Ardmore Basin. We will drill Sycamore or the Mississippian and the Woodford, two different locations but bringing them on at the same time and in the same basic unit. So we'll have from two to five locations at once coming online. And with the two-rig program that we have at the Oswego we'll continue to be a well at a time in 2025. But that's – as you kind of look at the oil guidance it is deferred some out into 2026 from the actual – the drilling delays that take place in 2025 from pad drilling.

Charles Meade: Thank you, Tom. That’s helpful lot of detail.

Tom Ward: Thank you.

Operator: Thank you. Our next questions come from the line of Neal Dingmann with Truist Securities. Please proceed with your question.

Q – Neal Dingmann: Good morning, team. Thanks for the time. Tom, would love to hear just your thoughts again, you guys have been great on some of the accretive M&A deals. I'm just wondering, what you're seeing out there. What -- how -- when you're looking at deals out there right now, I'm just wondering gas versus oil deals or I certainly -- I know it depends on the play. I guess, let me ask it this way. If you look at an area like just Barnett gas or something like -that it's a little bit off track, versus maybe like Mid-Con I'm just wondering, how sort of prices compare when you're looking at sort of gassy versus oily assets.

Tom Ward: Sure, Neal. We are looking all around both for gas and oil now more outside of the Mid-Con than we have in the past. We're working on a couple of small acquisitions that are -- one inside the Mid-Con, one just outside of it, that we'll see if they come across the finish line in the next couple of months. But we see some kind of stranded areas that are not Tier 1, wouldn't be considered Tier 1 Marcellus. We see some areas even like Ark-La-Tex that you can find some other good potential acquisitions. On the gas side, maybe Southern Delaware and some other areas in and around the Permian. Or from an oil perspective, we love to buy 60 -- the oil in the 60s and have it backwardated in the curve. So we continue to look for oil opportunities also.

Q – Neal Dingmann: No, you guys have certainly done some nice deals. And then just secondly, I would be curious to know you haven't drilled a ton of them yet, but just wondering how do you mentioned some of the deeper Mississippi wells and just wondering when it comes from a -- to generate a return how does -- what's your thought on how those wells compete with some of your other leading wells?

Tom Ward: Yes. Our Custer County, deep gas wells are extraordinarily good. So I think they -- I mean from a rate perspective, so we look at these as being highly competitive to virtually anywhere in the Lower 48 from a rate of return perspective. I'm also as -- my guess fairly bullish longer-term natural gas prices. So if we can make a north of 50% rates of return here. at these prices we feel like we have a good chance to bring those on into a higher gas market.

Q – Neal Dingmann: Makes sense. Thanks so much.

Tom Ward: Thank you.

Operator: Thank you. Our next question has come from the line of Michael Scialla with Stephens. Please proceed with your question.

Q – Michael Scialla: Hi. Good morning, guys --good morning. I want to see how the market looks now for potentially refinancing the term loan. I know that was something you guys were contemplating.

Tom Ward: Sure. We look at it. We're always interested in having lower financing. The RBL high-yield market as you might guess, is fairly robust. So, we look at that. The -- we still have 101 on the term loan, so that plays into what our timing would be. And then, covenants that come along with the RBL high yield versus the term loan, and fees that you might incur to put those in place. So everything that -- when we're reviewing, whether we want to move towards an RBL high yield or keep our term loan for another year or refinance it a term loan, they all play -- it all comes into play. So it's not quite so easy is just to look at the interest rate, and say that basically SOFR plus some number higher than a high-yield RBL is a better deal. So that's a long-winded way to say, we are looking and we'll be making some decisions soon. I think one of the things we probably would like to do is not have the amortization in place for 2025 and something we'll probably focus on.

Michael Scialla: I appreciate that detail. Tom you mentioned your ability to pivot pretty quickly, you've been watching the Cherokee shale play. You mentioned the three-rig program you're thinking about for 2025 and that's really not part of it at this point. But what would you need to see there to start putting some dollars to work in that play? Or are you more likely to continue to sell more acreage there?

Tom Ward: Yeah. Really it's just rates of return that we look at. So right now, we just have so many potential locations to drill that, and we want to see other people continue to drill more wells there near our acreage before we put any dollars to work. So that has not yet been done in a way that I feel comfortable that that would be development wells instead of more exploratory. And they would have -- I think the Cherokee shale wells in particular, there I guess would be challenged to have the same types of rates of return as the Southern Oklahoma or Ardmore Basin wells.

Michael Scialla: Great. Thank you.

Tom Ward: Thank you.

Operator: Thank you. Our final question will come from the line of Geoff Jay with Daniel Energy Partners. Please proceed with your question.

Geoff Jay: Hey, guys. Really quick for me just a point of clarification, is the addition of the rig funded at strip from the recently closed deals? Or is there some increase in oil and gas prices contemplated in that addition?

Tom Ward: It's just strip. We view it as strip. And this the -- actually strip pricing in natural gas increased enough year-over-year to bring the rig back on and still stay within the 50% reinvestment rate.

Geoff Jay: Excellent. Thank you very much.

Tom Ward: Thank you.

Operator: Thank you. That does end our question-and-answer session. And with that that does conclude today's teleconference. We do appreciate your participation. You may disconnect your lines at this time. Enjoy the rest of your day.