Mach Natural Resources LP

Good morning, everyone. Thank you for joining today's call to discuss Mock 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 their press release and in other SEC filings. For further discussion of risks and uncertainty that can 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 refer to their press release, which is available on Mock's website, and their 10Q, which will also be 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 will turn the call over to Mr. Tom Ward.

Tom? Thank you, Darrell. Welcome to Mock Natural Resources third quarter earnings update. As a reminder to anyone listening who might not know too much about Mock, we are an upstream energy MLP. We like the attributes of the MLP model for unit holders, the tax benefits and the focus on returning cash. We also remember and acknowledge the misgivings the 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 unit holders 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 PD10. It was not the assets that were bad, but the execution of the asset. We feel the same way about the upstream MOP 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 PB10 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 unit holders. 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 unit holders in times of rising prices. We want exposure to energy for the long term and like being invested in a company that is upside to commodity pricing. We believe that the poor 7 billion people on Earth want to achieve the same standard of living as the wealthy 1 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 risks 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, MOC has invested $1.9 billion by raising $520 million of equity. We have $600 million in net debt and will have distributed $962 million to unit holders. This results in an actualized MOEC 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 build 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 a creep to our distribution due to maintaining low amounts of leverage. If prices move up, we are positioned to use more than 1 million acres of land across the Andarco 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 the commodity cycle we're in. Another point of pride is the ability to assimilate acquisitions into our company at very low costs. Our lease operating expense for the third quarter was $5.85 for BOE, which is at the low end of guidance. For the third quarter, we drilled and brought online 11 gross and 9 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 cap 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 two rigs running. We continued to find ways to drill more lateral length while spending less per foot. In the Oswego, we averaged spread 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 drilling and completion cost was $7.7 million, compared to our predecessor's $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 one times. 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.

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 3, 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 $585 per BOE, again came in at the bow 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 is approximately $784 million. Total revenues, including our hedges and midstream activities, total $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 in the $62 million or 60 cents per unit distribution for this quarter. As we announced, this will be paid on December 10th to holders of record as of November 26th. Darrell, I'll now turn the call back to you to open the line for questions.

Thank you. We'll now be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. One moment, please, while we poll for your questions. Our first questions come from the line of John Freeman with Raymond James. Please proceed with your questions.

Good morning, guys.

Good morning.

Yeah, the first question, so the 2025 plan, you said, assumes a three-rig program. Just given you all highlighted, you know, the improved cycle times, a lower cost per foot, what does the 2025 program assume for turn-on lines?

For turn-ons? How many wells are we turning on? I'll get that for you in just a second.

Okay, and then the other part.

Oh, I hear it. Oh, John, it says it's a little over 40 gross wells.

Perfect. And then just sort of attack on to that. I know like the 2024 program, it was a lot, you know, heavier front end program. Obviously, 1Q was dramatically bigger sort of activity for y'all for the year. Is the 25 program a little bit more smoothed out? Is there any lumpiness? that we need to be aware of in that program?

Well, it's not set up to be as the 24 program really was 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 there currently and some of our other Mississippi and deeper Mississippi wells in Custer County. So I don't foresee anything being lumpy, but if crude prices were to move down or natural gas prices further, and it looks like it would be over our 50% reinvestment rate, then we would move back on CapEx.

That makes sense.

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. Okay.

That definitely makes sense. And if I could just sneak one more in on LOE. Sure. Obviously, for the year, y'all have averaged well below that four-year guidance. I think you're right around a little over $5.50 a BOE relative to the guide of 580, 610. Obviously, it 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.

You can go ahead and answer, Kent. Kent's going to answer.

Yeah. Hey, John. This is Kent. I think the higher guide for LOE for BOE in 25 is driven mainly by flush production this year.

uh you know with the newly acquired ploma assets and and that steeper decline profile it drove down our LOE for BOE metric this year a little bit yeah the ploma wells that we inherited were very high producing a lot of gas with them too so they had low lifting costs got it thanks guys appreciate it thank you john

Thank you. Our next questions come from the line of Charles Mead with Johnson Rice. Please proceed with your questions.

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 these most recent two acquisitions. I guess you closed the latter of the two on October 1st. Can you give us some sense of, you know, 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?

Yeah, for both the Ardmore base and the Kansas assets, you know, the grand total of, The combined production, I think, was about 5,000 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. Okay. Got it.

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.

That makes sense. That does help. 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 mock. And I'm wondering if you could put that – tell me if that's the right read and put those – Put that plan 2025 Custer drilling in context of you know what we should what we should expect from from those targets.

Yeah, we have. We participated in in several continental wells in 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 that acreage is 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 we look for is rate to return and the red fork area that's being developed by Mewburn in western Oklahoma has been good all up and down Dewey to Custer and on out and then the Cherokee shell that they have in in um in ellis and roger mills is is being developed also so that 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 uh if it can compete for a rate of return with our existing uh units to be drilled, we put it in our drilling plan. 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 from actually even going two different directions or in the Ardmore Basin. We will drill Sycamore, the Mississippian, and the Woodford, two different locations, but bring them on at the same time. in the same basic unit. So we'll have from two to five locations at once coming online with the two rig program that we have. The Oswego will continue to be a well at a time in 2025. As you kind of look at the oil guidance, it is deferred some out into 2026 from the actual drilling delays that take place in 2025 from pad drilling.

Thank you, Tom. That's helpful out of detail. Thank you.

Thank you. Our next questions come from the line of Neil Digman with Truist Securities. Please proceed with your questions.

Thanks for the time. Tom, would love to hear just, you know, your thoughts. Again, you guys have been great on some of the accretive M&A deals. I'm just wondering when you're seen out there, what, you know, how do you, when you're looking at deals out there right now, I'm just wondering, gas versus oil deals are, you know, I certainly just, I know it depends where the play, I guess let me ask this way, like, If you look at an area like the Barnett gas or something like that that's a little bit off track versus, you know, maybe like VidCon, just wondering how sort of prices compare, you know, when you're looking at sort of gas versus oil assets.

Sure, Neil. We are looking all around both for gas and oil now more outside of the VidCon than we have in the past year. We're working on a couple of small acquisitions that are one inside the MEDCON, one just outside of it. We'll see if they come across the finish line in the next couple of months. But, you know, 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 Arklatex, 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'd love to buy the oil in the 60s and have it backwardated in the curve so we continue to look for oil opportunities also.

No, you guys have certainly done some nice deals. And then just secondly, I'm curious to know, I know you haven't drilled a ton of them yet, but just wondering, you mentioned some of those deeper Mississippi wells, and I'm just wondering when it comes from a generated return, what's your thought on how those wells compete with some of your other leading wells?

Yeah, our Custer County deep, 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 you might guess, fairly bullish longer-term natural gas prices. So if we can make a north of 50% rate of return here at these prices, we feel like we have a good chance to bring those on into a higher gas market.

Makes sense. Thanks so much. Thank you.

Thank you. Our next question has come from the line of Michael Ciala with Stevens. Please proceed with your question.

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.

Sure. We look at it. We're always interested in having lower financing. RBL high-yield market, as you might guess, is fairly robust. So we look at that. We still have 101 on the term loan, so that plays into what our timing would be. And then covenants that come along with RBL high-yield versus the term loan. and fees that you might incur to put those in place. So everything that whenever we're reviewing, whether we want to move towards an RBL high yield or keep our term loan for another year or refinance a term loan, it all comes into play. So it's not quite so easy as 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.

I appreciate that detail. Tom, you mentioned your ability to pivot pretty quickly. You've been kind of 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 acres there?

Really, it's just rates of return that we look at. Right now, we just have so many potential locations to drill that the 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 would be development wells instead of more exploratory. And they would have, I think the Cherokee Shale Wells in particular, they're, I guess, would be challenged to have the same types of rate to return as a southern Oklahoma or more basin wells. Great. Thank you. Thank you.

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

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 or gas prices kind of contemplated in that addition?

No, it's at Strip. We view it at Strip. And 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. Excellent. Thank you very much. Thank you.

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.