Earnings Call Transcript - MNR Q3 2024

Operator, 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 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?

Tom Ward, CEO

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 will 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 one 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 two 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 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 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, CFO

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 resulted in 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, Operator

Thank you. We'll now begin the question-and-answer session. Our first questions come from John Freeman with Raymond James. Please go ahead with your questions.

John Freeman, Analyst

Good morning, guys.

Tom Ward, CEO

Good morning.

John Freeman, Analyst

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, CEO

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

John Freeman, Analyst

Okay. The other part.

Tom Ward, CEO

Well, I hear it's a little over 40 gross wells.

John Freeman, Analyst

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, Q1 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, CEO

It’s not structured in a specific way as the 2024 program wasn’t at the outset. It all depends on pricing and the 50% reinvestment rate. Currently, we plan to bring in the third rig in February, which will operate in the Ardmore Basin to begin drilling. We expect to keep that rig in Southern Oklahoma for most of the year and have another rig working between Canadian County in Central Oklahoma and Western Oklahoma in the Red Fork sand play that’s being developed. They are also currently working on some of our deeper Mississippian wells in Custer County. I don’t anticipate any irregularities, but if crude or natural gas prices decline and it appears we’ll exceed our 50% reinvestment rate, we would reduce our capital expenditures.

John Freeman, Analyst

That makes sense.

Tom Ward, CEO

The opposite would be true if we made an acquisition or had more operating cash flow through higher prices; we would add a rig.

John Freeman, Analyst

That definitely makes sense. If I could sneak one more in on LOE, you've averaged well below the full-year guidance for the year. You're just over $5.5 of BOE compared to the guide of $5.80 to $6.10, which obviously suggests a significant increase in 4Q. Any insight on that would be helpful. That’s my last question. Thanks.

Tom Ward, CEO

You go ahead and answer, Kev. Kev's going to answer.

Kevin White, CFO

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, CEO

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, Analyst

Got it. Thanks, guys. Appreciate it.

Tom Ward, CEO

Thank you, John.

Operator, Operator

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

Charles Meade, Analyst

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, CFO

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, Analyst

Okay. Got it. That makes sense.

Tom Ward, CEO

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, Analyst

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, CEO

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, Analyst

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

Tom Ward, CEO

Thank you.

Operator, Operator

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

Neal Dingmann, Analyst

Good morning, team. I appreciate your time. Tom, I would like to hear your insights again, as you've done well with some of the beneficial M&A deals. I'm curious about what you're observing currently. When evaluating deals, how do gas and oil opportunities compare? I recognize it varies by play, but if we consider an area like Barnett gas versus something like Mid-Con, how do the prices stack up when comparing gas assets to oil assets?

Tom Ward, CEO

Sure, Neal. We are exploring both gas and oil opportunities more broadly than we have in the past, particularly outside of the Mid-Continent. We are in discussions regarding a couple of small acquisitions, one within the Mid-Continent and one nearby, and we hope to finalize those in the coming months. We are identifying some areas that are not Tier 1, particularly in the Marcellus, and we see potential in regions like Ark-La-Tex for good acquisition opportunities. On the gas side, we're considering Southern Delaware and surrounding areas in the Permian. From an oil perspective, we are interested in purchasing oil when prices are in the 60s, especially when the curve is backwardated. Therefore, we are actively seeking oil opportunities as well.

Neal Dingmann, Analyst

No, you have certainly completed some impressive deals. Additionally, I am curious about the Mississippi wells you mentioned. While you haven't drilled many yet, I'm interested in your thoughts on how these deeper wells will compare in terms of generating returns with some of your other top-performing wells.

Tom Ward, CEO

Yes. Our Custer County deep gas wells are performing exceptionally well. From a rate perspective, we believe they are highly competitive compared to virtually any location in the Lower 48 based on returns. I'm also quite optimistic about long-term natural gas prices. Therefore, if we can achieve rates of return above 50% at these prices, we feel confident about our ability to enter a higher gas market.

Neal Dingmann, Analyst

Makes sense. Thanks so much.

Tom Ward, CEO

Thank you.

Operator, Operator

Thank you. Our final question will come from the line of Michael Scialla with Stephens. Please proceed with your question.

Michael Scialla, Analyst

Hi. Good morning, everyone. I would like to understand the current market conditions for possibly refinancing the term loan, as I know that was a consideration for you.

Tom Ward, CEO

We are always interested in achieving lower financing costs. The RBL high-yield market is quite strong, so we are exploring that option. Currently, we have 101 on the term loan, which impacts our timing. Additionally, we need to consider the covenants associated with the RBL high-yield compared to the term loan, as well as any fees involved in establishing those arrangements. Therefore, when evaluating whether to shift to an RBL high-yield or maintain our term loan for another year or refinance it, all these factors must be taken into account. It's not simply a matter of looking at the interest rate to determine if SOFR plus a number above the high-yield RBL is a better option. In summary, we are assessing the situation and will reach a decision soon. One of our goals is likely to avoid amortization in 2025, which we will pay close attention to.

Michael Scialla, Analyst

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, CEO

We're primarily focused on rates of return. Currently, we have many potential drilling locations, and we want to observe others drilling additional wells near our acreage before we invest any funds. So far, that hasn't happened in a way that gives me confidence these would be development wells rather than exploratory ones. I believe the Cherokee shale wells may face challenges in achieving the same rate of return as the wells in Southern Oklahoma or the Ardmore Basin.

Michael Scialla, Analyst

Great. Thank you.

Tom Ward, CEO

Thank you.

Operator, 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, Analyst

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, CEO

We see it simply as strip pricing. In fact, the strip pricing for natural gas has risen enough compared to last year to justify bringing the rig back online while still adhering to the 50% reinvestment rate.

Geoff Jay, Analyst

Excellent. Thank you very much.

Tom Ward, CEO

Thank you.

Operator, 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.