Mach Natural Resources LP

Greetings and welcome to the Mock Natural Resources fourth quarter and full year 2024 earnings results conference call. At this time, all participants are in listen-only mode. If anyone should require operator assistance, please press star zero on your telephone keypad. A question and answer session will follow the formal presentation. You may press star one at any time to be placed into question queue. As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to Chief Executive Officer and Director, Tom Ward. Please go ahead, Senator.

Thank you, Kevin. Welcome to Mock Natural Resources' fourth quarter earnings update. Each quarter, it's important to reiterate the company's four strategic pillars. These are, number one, maintain financial strength. Our goal is to have a long-term debt-to-dividend ratio of one times or less. By maintaining a low leverage profile, we give ourselves opportunities when markets experience high volatility. Two, disciplined execution. We acquire only cash flowing assets at a discount to PDP, PD10, that are accretive to our distribution. 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. and four, maximizing cash distributions. We target peer leading variable distributions. This pillar drives all decisions. I'd like to add additional color to each of these four pillars. Disciplined execution. Our strategy since the founding of the company in 2017 has been to purchase cash flowing assets at bargain prices while paying nothing for associated acreage and future drilling and very little to nothing for the associated infrastructure and midstream assets. Our company was built during a time of distress in our industry. We made our first acquisition in early 2018 and then followed that with 19 additional acquisitions. We accumulated over 1 million acres of land that is held by production. We have ownership in four midstream gathering and processing facilities and significant other infrastructure. We purchased these facilities for $65 million, and these assets contributed $78 million of EBITDA and $24 million alone. $17 million of this midstream EBITDA came from third parties and the remainder from higher realized wellhead prices for our own production. And finally, in every single one of our acquisitions, our best-in-class operating team has reduced LOE by 25% to 35% from the previous owner's cost. Disciplined reinvestment rates. We now have the distinct advantage of choosing where to drill from hundreds of potential locations on the previously mentioned 1.1 million acres. In general, we look for opportunities to invest in projects with the potential to have at least 50% IRRs. In our presentation posted today on our website, we list all of the locations drilled in the Oswego and Wood formations during 2024. In short, even during a year with exceptionally low natural gas prices, we achieved our goal. Natural gas prices have recently moved up, and that will result in more operating cash flow during 2025. We plan to move in an additional rig in 2025 and still stay below our 50% reinvestment rate while adding high rate of return wells to our production. In 2025, we anticipate three rigs running. Continue to drill the Oswego formation of Kingfisher County, where we've drilled more than 225 wells since 2021. The Mississippian and the Woodford formations in the condensate window of the Stack and Ardmore Basin, where we incorporate locations from the last three acquisitions made, and the Deep Mississippian formation in the Andarco Basin. It is worth highlighting that out of the 45 wells drilled in our Oswego and Woodford drilling program, that greater than 35% achieved more than 100% rates of return. These were all drilled on lands that we paid zero for. We drill wells that are highly efficient. For example, our Oswego DNC cost in 2024 averaged only $2.6 million or $202 per lateral foot. By keeping our costs low, we achieve medium payout periods of 15 months, assuming a flat $70 WTI and $350 Henry Hub. According to Inverse, this compares to 14 months in the Delaware and 15 months in the Midland Basins, where purchasing locations can cost more than $10 million each. All of these statistics add up to unmatched cash returns for our unit holders over the last five years, and the next five years. We anticipate spending between $225 to $240 million on drilling and completion plus workovers in 2025. With this expenditure, we anticipate holding our production basically flat, either up or down a few percentage points on a BOE basis. Maintain financial strength. We also watch our leverage very closely. During the downturn starting in 2019, we adjusted our development capex from $101 million to only $28 million in 2020, $61 million in 2021, then $291 million in 2022 as prices rose. All the while, our EBITDA grew from $119 million to $719 million over the same period. We achieved this exceptional performance by being able to acquire cash-producing properties in a distressed environment due to our strong balance sheet. MOC also has peer-leading PDP decline and reinvestment rates. Our next 12-month PDP decline is projected to be 20%, while our reinvestment rate in 2024 was only 47%. Both of these statistics are number one in a group of 16 peer companies. We have exceptionally strong asset coverage with total approved coverage of 3.9 times, net debt enterprise value of 21%, and PDP PB10 to total debt of 3.3 times. Our LOE averaged $6.17 per BOE in the fourth quarter of 2024, and our 2024 free cash flow was $8.43 per BOE. We're also starting 2025 with a net debt EBITDA at 0.8 times pro forma for our recent offering. Maximizing distributions. Management tries to understand risk and mitigate that risk where possible. We hedge 50% of our oil and natural gas on a rolling one-year basis and 25% during the second year. We also have a variable distribution that rises and falls with the changes in pricing. Each quarter, we are methodical to reinvest 50% of our operating cash flow, then receive our calculated cash available for distribution and send it home to our unit holders. We've done this since our inception and do not plan to change our approach. During this time, we have distributed back to our owners over $1 billion. When we hold our production flat by spending less than 50% of our operating cash flow, we are allowed to send back distributions to our unit holders. The best way to describe what we do is consistency. In all price environments, we maximize our distributions while maintaining a clean balance sheet. In times of lower pricing, we lower our capex, thus not having long-term contracts on capital expenditures. In doing so, we continue to have excellent cash returns on capital invested. Our croaky five-year average from 2020 to 2024 is 32%. This was achieved through several commodity cycle fluctuations. During 2024, we delivered total net production of 86.7 MBOE a day and reported net income and adjusted EBITDA of $185 million and $601 million, respectively. We also distributed $310 million, or $3.20 per unit, and attained a cash return on capital invested metric of 25%. Recently, we closed a bolt-on acquisition in the Ardmore Basin of approximately $30 million that will provide additional locations for us to drill this year. We repaid the company's term loan and lowered our net debt to 8.8 times from 1.0 times. We then entered into a new revolving credit facility with an initial borrowing base of $750 million. We continue to have success buying assets in the MidCon. Our latest successful acquisitions have been in the $100 million range. In fact, we've made 20 acquisitions that average just less than $100 million on each one. This approach is important as we can stay away from large, well-capitalized competitors to buy assets that are less expensive. We focus these acquisitions on not only acquiring PDP at less than PV10, but also acquiring land that one day will be drilled by us at no cost and no time frame for expiration due to being held by production. This formula has served us well. We also like buying crude oil any time we move into the 60s or less and have a backward-rated curve. We see the crude market moving through the inevitable one to two standard deviations, both up and down, and want to be ready with a strong balance sheet during times when pricing is at the bottom of a cycle. We do not envision a longer-term down cycle in the vein of 2015 to 2020. and feel like it is a good time to lean in on a crude acquisition if we can find the right deal that fits our criteria for investing. However, we also do not stray away from our basic philosophy of needing an acquisition to be accretive to our distribution. We also will trade in natural gas if the opportunity arises at the correct price. In order for us to make a larger acquisition, say something north of $500 million, We need to find a partner who will be willing to take equity alongside of us. We believe our time is coming when PE firms and small public companies will find our formula for cash returns attractive and want to be a part of a larger mock. We welcome these opportunities as a way to grow our business while creating larger cash returns to our unit holders and having more float so that institutional investors can participate on a larger scale in our business. I feel that we will accomplish at least one of these types of transactions in 2025. Even if we do not make a meaningful acquisition, we will continue to replace our production through our drilling program and small acquisitions and deliver excellent returns to our unit holders. In 2024, we rank first out of all public upstream energy companies in distribution yields. We also ranked 10th in the total shareholder returns. We achieved these returns at a time of very low natural gas prices. In fact, 2024 had the lowest natural gas prices since the early 1990s. Our commodity mix on a revenue basis was weighted 59% oil, 21% natural gas, and 20% NGLs by revenue in 2024. However, as we move into 2025, we can see what happens in a higher natural gas environment with our volume by product being 54% natural gas, 23% NGLs, and 23% oil. Therefore, in a $4 plus environment for natural gas, we're leaving all of our liquids in the gas stream and producing 77% of our production as natural gas. This increase in EBITDA allows us to have more operating cash flow. which enables us to add another rig in 2025 to have three rigs running versus the two we had in 2024. We remain focused on the price for our products and our reinvestment rate. The reinvestment rate drives our budget, not the IRR of the wells we drill. We feel confident we can continue to achieve high return drilling results, but we will not move away from our core tenets of keeping the reinvestment rate low to maximize cash returns to unit holders. If we are fortunate enough to add larger acquisitions, we'll be able to then monetize more of the hundreds of high internal rate of return projects we have waiting to be drilled on our 1.1 million acres of HVP land. This is why our focus remains on free cash flowing assets to acquire prices that are creative to our distribution. In closing, I want to reemphasize that we are an acquisition company. Our industry-leading cash returns have been made through opportunistic acquisitions. This is our primary lever of growth. Our expectation is to continue making acquisitions that are accreted to our distribution in 2025, just as we have over the last seven years in 20 deals. I'll now turn the call over to Kevin to discuss our financial results.

Thanks, Tom. For the fourth quarter, our production of 86.7 thousand BOE per day was 24% oil, 52% natural gas, and 24% Our average realized prices were $70.06 per barrel of oil, $2.31 per MCF of gas, and $25.82 per barrel of NGLs. Our G&A stayed flat during the quarter at $8 million, or around $1 per BOE. We ended the quarter with $106 million in cash, and our first lean term principal was $763 million. During the quarter, total revenues, including our hedges and midstream activities, totaled $235 million, adjusted EBITDA of $162 million, and $134 million of operating cash flow. After CapEx of $60.5 million, we generated $81 million of free cash, which we used to pay our final operating principal amortization of roughly $20.6 million on the first lien term loan, and the remainder results in the $60 million or 50 cents per unit distribution for this quarter and was paid earlier this week. As Tom mentioned, we've closed on a new $750 million RBL made up of a syndicate of 10 banks. We're currently drawn around $500 million. And with that, Kevin, I'll turn it back to you to open up the call for questions.

Certainly. Without me conducting a question and answer session, if you'd like to be placed into question queue, please press star 1 on your telephone keypad. We ask you please ask one question, one follow-up, then return to the queue. One moment, please, while we poll for questions. Our first question is coming from Neil Dingman from Truist Securities. Your line is now live. Morning, all.

Thanks for the time. Tom, I'm pretty optimistic still on just the M&A environment. I'd love to hear You know, gas, oil kind of still in the mid-con, kind of what were your expectations out for this year?

My expectations on gas and oil?

Just for, you know, we're seeing sort of the better. You think you might see some of the better deals this year?

Oh, yeah. Either gas or oil on better deals. Yeah, that's it. Good question. We kind of take what is delivered to us. So if we can make a deal on gas or oil that fits our criteria, we try to do it. I mentioned that I love buying oil in the 60s. We've made a lot of money over the past several years. buying low-priced oil, especially in a backward-rated curve, and letting that come to us over time. I just don't believe we're in a type of market over the next five or ten years that is going to consistently be down at these levels. And so I do like buying crude oil at these prices. And we look at those deals, but we also look at natural gas. And if we can make a good natural gas acquisition that's accretive to our distribution, we'll do so. But I guess if I had to pick one of the two right now, I think we would lean in on a crude oil deal.

Got it. And then secondly, as you pointed out, and I think justly so, you've got pretty notable infrastructure now that you've put together now over the years. Would you ever consider monetizing or is that just too valuable now to the development of your properties? And again, maybe just any comment you can make on the infrastructure and the value that you see behind that.

Yeah, like would we sell some of our infrastructure? Yeah, I think they're pretty critical to our operations. I don't see any reason for us to be trying to get rid of them. As we mentioned, every year that goes by, we produce more EBITDA than we paid for the whole system. So it's just... they are valuable, but they're also valuable to us, and we'd have to pay somebody else if we were to pass them on to them. So I don't think so. I think we'll plan to keep them.

Great value there. Thanks, Tom.

Thank you.

Thank you. Next question today is coming from Charles Mead from Johnson Rice. Your line is now live.

Good morning, Tom and Kevin.

Good morning.

Tom, I... I wanted to ask, I guess, about the third rig, and can you tell us when it's going to come? I imagine how long it stays is really going to be a function of your reinvestment cap, but when is it going to come, and is that going to be focused on the Anadarko Deep Mississippian that you talked about?

Yes, so the third rig is coming – just any day for a four-well program in the Oswego, and then that rig will leave and we'll pick up another rig that starts the Deep Mississippian project in the Antarctica in western Oklahoma. So it's really driven by reinvestment rate. As prices have moved up, our operating cash flow has moved up, so we're able to – to bring in a rig in the Oswego that allows us to stay closer to 50% reinvestment rate. But that's going to be a short term while we bring in a larger rig to drill the deep Mississippi and Custer County.

Got it. Yeah, it would make sense. You'd need a bigger rig for Custer County than the Oswego and Kingfish. The second question, Tom, I really appreciate the comments you laid out on oil, but I'm wondering if you could do the same for gas. I mean, it's not new this week or this month, but maybe this month. We're looking at backwardation in the gas curve for the first time in a long time with this big run we've had in natural gas prices. And I wonder if you could tell us what you think the setup is there, and perhaps as a As a way of doing that, you said you like to buy oil assets. When oil was in the 60s, where do you like to buy gas assets?

I always like to buy gas assets. I think long term, I'm no different than basically anyone else now that believes that natural gas is the fuel of the next 10 years that's going to have tremendous demand. So, yeah, maybe in 2028 or so you get the Qatar LNG coming on that might dampen natural gas prices some for a time. But I think demand overall just is increasing. And any time you buy something in Andarco, you're going to get about 50 percent natural gas and another 25 percent or so in natural gas liquids, along with crude oil being basically 25 percent. And so any deal we make is just by its very nature in the mid-con a natural gas asset. So we've done extremely well at buying cheap natural gas. My belief is that we still could look towards a $5 curve this summer as we need to do refills as we're going into refill season and need to be back at 3.8 TCF or so by the end of October. So I've I don't know, you know, we'll have plenty of times of moving up and down and around with gas prices, but I still think there could be a dollar move here in the summer strip.

Thank you for the thoughts, Tom.

You bet.

Thank you. Next question is coming from Michael Shiala from Stevens. Your line is now live.

Good morning, guys. Tom, I wanted to see if you could talk a little bit more about the recent bolt-on you did. You mentioned the nine PUDs. Any probable locations with that? And I'm curious, you know, you bought typically from distressed sellers. It looks like you paid well below PV10 value here. Could you characterize the seller situation here, why they were willing to let it go for the price that they did?

Yeah, they weren't as distressed as most of the sellers we've had over time because they were just individuals who went out and drilled a few wells and were able then to sell those at basically PDP, PV10 to us and made a lot of money. And so they drilled good wells, they sold us the wells that they drilled, and then we paid a fair price for those, and then we inherited the PUDs that they'd proven There aren't any probable locations because it was drilled in an area and their drilling and others have proved it. So the nine locations we drill throughout the rest of this year and the next year are going to be PUDs already. So it's a good area to drill in with good rates of return. And in fact, just by the very nature of being in our drilling program, we expect to have 50% rates of return.

Sounds good. I wanted to ask on the fourth quarter distribution, it was a little bit below on a percentage of cash available for distribution. Then third quarter, can you talk about the factors that went into that decision?

Yeah. Michael, I'm not sure if you're looking at the table itself, the cash available for distribution came in at a little above $80 million. And that's after interest expense, but before we made our principal amortization. So the principal amortization took a little over $20 million away from that $81 million. And so net after the principal payment, we did send out all the cash that we generated for the quarter. The per unit number was a little bit lower because it was, you know, the per unit distribution was shared with the equity purchasers that occurred in February.

Our cash is available for distribution. When we send that out, it's fairly mechanical and keeps basically everyone happy, both equity and our debt holders.

So it's really all due to the recapitalization of the... the balance sheet during the quarter.

Yeah, if you were looking at the per unit number.

Yep. Perfect. Thank you. You bet.

Thank you. Next question is coming from Derek Whitfield from Texas Capital. Your line is now live.

Good morning, all. Thanks for your time.

Sure.

Wanted to focus on your 2024 drilling program results with my first question. As you guys look back on the 2024 program, are you seeing opportunities for the Woodford to close the gap versus the Oswego in returns from a DNC efficiency or optimization perspective?

We've been pretty efficient. I think both of those zones are basically doing what we've asked them to do. The Oswego program is just much more mature and, you know, to me it's an easier program to hit our rate to return just because it's fairly simple to drill and or i guess not as complex to drill as some of the deeper woodford and just the the the amount of communication that we have in between wells it tends to be a little less so I don't think it really necessarily closes the gap. We've already cut the drilling cost by nearly $2 million a well from when the prior operator had it. So I will never say never about our team and their efficiencies, but it kind of looks like I wouldn't expect a different outcome in 2025 versus 2024. Therefore, I mean, what can happen is that an Ardmore Basin well or a deep Mississippian well can have higher rates of return than a condensate well in the condensate window. So, therefore, after the next couple of wells that are drilled in the condensate window, we'll be moving that rig to the Ardmore Basin.

Yes, that makes sense. And maybe... Regarding M&A, could you more broadly speak to the competitive landscape in the mid-con? As it appears, the privates like Validus are most responsible for the competitive environment we're seeing today. And then also just maybe leaning in on where you were just now on the organic leasing opportunities you're seeing and the deepness.

Yeah, the mid-con has become a very popular place. And our rig count has gone up. Over the last year, the amount of interest in buying assets has gone up and well-capitalized companies are moving in to purchase assets. So that is, we have never really been great at buying very large packages other than the Paloma one was the one exception for us. But the amount of competition for those types of assets continues to be fairly strong. So I see us having the niche still of buying $100 million type assets where others are really looking and continue to look for free cash flowing assets that might not have much of the drilling upside, but we really don't need that because we have so many opportunities ourselves inside of our existing acreage. So, I mean, what we're really focusing on is trying to grow our operating cash flow and then using 50% of that to increase our drilling budget into high rate of return drilling that we already have captured inside our existing acreage.

And, Tom, just on the organic leasing opportunities you guys are seeing across the beach, maybe could you elaborate on that?

Yeah, I mean, most of the – we already have so much acreage that's held by production. I mean, across the deep Anadarko and the deeper condensate window, we have over 65,000 acres currently. So it just – we don't have to lease very much. I think our total budget for leasing this year is – around $30 million for 2025. So that is focused more in the deeper areas, as you mentioned. The Cherokee also, both the Cherokee Shell and the Red Fork Sands have been areas we've been watching. And whenever we – most of our leasing budget is places that we already own acreage. We propose a well, and then we buy the rest of the unit as it's being put together.

Very helpful. Thanks for your time.

You bet.

Thank you. Next question today is coming from John Freeman from Raymond James. Your line is now live.

Good morning, guys. Hey, John. Just following up on that last comment, Tom, because it looks like on a year-over-year basis, the midstream and land expenditures as a percentage of the total budget is doubling, both like on a percentage of the total and on a dollar amount. And Did you just say that the $30 million of that midstream and land that you all lumped together, the $35 to $40 million range you gave for the year, did you say $30 million of that is for land?

Yeah, I think that's our budget for land, isn't it, $30 million?

Land and midstream. Okay, so yeah, that does include both. I'm sorry, John. But the midstream stays virtually the same, I think, as in prior years. So the biggest part of the change is for land. leasing activity. But again, as Tom mentioned, the majority of that just comes as a byproduct of a larger drilling program.

And John, as you move into another rig running, that does have just more locations that we add acreage on.

Okay. Yeah, that makes sense. And then You know, you also talked about, you know, just the increased activity that we're seeing in Anadarko. I know just Oklahoma overall has seen the biggest increase in drilling activity of any region in the country the last several months and, you know, just sits behind only the Permian at this point. What sort of impact, if any, does sort of a non-op portion of your budget see this year versus last year's budget?

Our non-op budget is usually fairly small. We elect out of most of the non-ops that are proposed to us. We are participating in a couple of deep gas wells that are being drilled now by Continental. But in general, I think our non-op budget stays fairly consistently low.

Got it. Thanks. Nice quarter, guys.

Thank you.

Thank you. Next question is coming from Salman Akhil from Steve Poole. Your line is now live.

Hi. Good morning, guys. This is Tim on for Salman. I just wanted to touch on in the prepared comments you mentioned kind of leaving more liquids in the gas stream given where, you know, natural gas prices are. Just curious, are you guys able to make that election across your footprint or is it only where you guys kind of have the infrastructure?

No, we can make that election basically across our production.

Okay, got it. And would you expect that to, you know, have natural gas production guidance to trend towards the high end and NGLs maybe trend a little lower or any kind of comments you can provide on that?

It stays in the range. Yeah. Yeah. So, sorry, the answer is it stays in our range. Okay, got it.

And then last one for me. BOE expense has kind of been, you know, ticking up in 2024, and I believe that was partially due to the Paloma Wells. But just curious on kind of the cadence we should look for in 2025, whether it's, you know, kind of a flattening or, you know, kind of a continuous kind of uptick.

Yeah, I think it's basically flat.

Okay, perfect. Thank you guys for the time. Yes.

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

Kevin, thank you. Thanks to everyone for joining. We look forward to our next call in a quarter. 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.