Earnings Call Transcript - MNR Q4 2024

Operator, Operator

Greetings, and welcome to the Mach Natural Resources Fourth Quarter and Full Year 2024 Earnings Results Conference Call. 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, sir.

Tom Ward, CEO

Thank you, Kevin. Welcome to Mach Natural Resources' fourth quarter earnings update. Each quarter, it's important to reiterate the company's four strategic pillars. The first pillar is maintaining financial strength, with a goal of a long-term debt-to-EBITDA ratio of 1x or less. By keeping leverage low, we create opportunities in volatile markets. The second pillar is disciplined execution, which involves acquiring cash-flowing assets at a discount that are accretive to our total output. The third pillar is maintaining a disciplined reinvestment rate, keeping it below 50% of our operating cash flow to optimize distributions to unitholders. Lastly, the fourth pillar focuses on maximizing cash distributions, targeting top-tier variable distributions that drive our decision-making. To elaborate on disciplined execution, our strategy since the company was founded in 2017 has been to buy assets at undervalued prices while incurring minimal costs for associated acreage and infrastructure. We began acquisitions in early 2018 and have completed 19 additional purchases, accumulating over 1 million acres of production-held land. We also have ownership in four midstream facilities, which we acquired for $65 million and that contributed $78 million of EBITDA in 2024, with significant portions coming from improved pricing for our production. In terms of disciplined reinvestment, we now have the advantage of selecting from hundreds of potential drilling locations. Our investment strategy focuses on projects that can deliver at least 50% internal rates of return. Even in a year marked by low natural gas prices, we achieved our goals and expect to increase operating cash flow in 2025 with higher natural gas prices. We're planning to add another rig while still adhering to our reinvestment rate policy. Regarding maintaining financial strength, we are vigilant about our leverage. We adjusted our development spending in response to market conditions, significantly reducing it when necessary, while our EBITDA grew substantially. Our performance reflects our ability to acquire cash-producing properties in challenging market conditions due to our solid financial position. In maximizing distributions, we manage our risks by hedging a portion of oil and natural gas production and maintain a variable distribution model aligned with price changes. We consistently reinvest half of our operating cash flow while distributing the rest back to unitholders, totaling over $1 billion since our inception. Our approach focuses on consistency, allowing us to provide strong returns even amid price fluctuations. In 2024, we recorded impressive production numbers, net income, and EBITDA while paying out substantial distributions. We made a significant acquisition recently and improved our financial position by repaying our term loan. Our acquisition strategy has been focused on smaller transactions that align with our financial criteria, ensuring that we acquire properties that are both cash-generating and have potential for future growth. As we move into 2025, we plan to continue increasing our production through our drilling program. We also expect to rank highly in shareholder returns again, particularly benefiting from changes in our commodity mix and improved natural gas prices. In closing, we are committed to being an acquisition-driven company, and our growth strategy remains focused on making prudent acquisitions that enhance our distribution capabilities. Now, I will hand the call over to Kevin to discuss our financial results.

Kevin White, CFO

For the fourth quarter, our production of 86,700 BOE per day was 24% oil, 52% natural gas, and 24% NGLs. 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 per BOE. We ended the quarter with $106 million in cash, and our first lien term principal was $763 million. During the quarter, total revenues, including our hedges and midstream activities, totaled $235 million, with an 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 principal amortization of roughly $20.6 million on the first lien term loan. The remainder resulted in the $60 million or $0.50 per unit distribution for this quarter, which was paid earlier this week. As Tom mentioned, we've closed on a new $750 million revolving credit facility made up of a syndicate of 10 banks, and we are currently drawn around $500 million. And with that, Kevin, I'll turn it back to you to open up the call for questions. Our first question is from Neal Dingmann at Truist Securities.

Neal Dingmann, Analyst

Tom, I'm pretty optimistic still on just seeing the environment. I'd love to hear gas and oil expectations for this year.

Tom Ward, CEO

My expectation is on gas and oil.

Neal Dingmann, Analyst

Just where you're seeing some of the better deals this year.

Tom Ward, CEO

That’s a 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 I love buying oil in the $60s. So we've made a lot of money over the past several years buying low-priced oil, especially in a backwardated 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. 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.

Neal Dingmann, Analyst

Got it. And then secondly, as you pointed out, you have notable infrastructure now that you've put together over the years. Is there any consideration to monetizing? Or is that just too valuable now to the development of your properties? Any comment you can make on the infrastructure and the value that you see behind that?

Tom Ward, CEO

Yes, Lakewood, would we sell some of our infrastructure? Yes. 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 they are valuable, but they're also valuable to us, and we would have to pay someone else if we were to pass them on to them. So I don't think so. I think we'll plan to keep them.

Operator, Operator

Next question today is coming from Charles Meade from Johnson.

Charles Meade, Analyst

Tom, I wanted to ask about the third rig. Can you tell us when it's going to come? I imagine it’s about investment cap, but when will it arrive? And is that going to be focused on the Anadarko Deep Mississippian that you talked about?

Tom Ward, CEO

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

Charles Meade, Analyst

Got it. Yes, it would make sense. You need a bigger rig for Custer County than the Oswego and Kingfish. But second question, Tom. I really appreciate on oil, but I'm wondering if you could do the same for gas. I mean, we've been looking at a backwardation in the gas curve for the first time in a long time with this big run we've had in natural gas prices. I wonder if you could share your thoughts there. Also, you mentioned you'd like to buy oil assets when oil is in the $60s; where do you like to buy gas assets?

Tom Ward, CEO

I always like to buy gas assets. I think long term, I'm no different than anyone else who believes that natural gas is the fuel of the next ten years that's going to have endless demand. So yes, maybe in 2028 or so, you'll see the Qatar LNG coming on that might dampen natural gas prices for a time. But I think overall demand just keeps increasing. During any deal we make, just by its very nature in the Mid-Con, you're going to get about 50% natural gas and around 25% in natural gas liquids along with crude oil being about 25%. We've done extremely well in cheap natural gas. My belief is that we could look towards a $5 curve this summer as we need to do refills, going into refill season and need to be back at approximately 3.8 Tcf by the end of October. So I don't 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.

Operator, Operator

Our next question is coming from Michael Scialla from Stephen.

Michael Scialla, Analyst

Tom, I wanted to see if you could talk a little bit more about the recent bolt-on acquisition. You mentioned the 9 PUDs. Any probable locations with that? I'm curious because you typically buy from distressed sellers, and it looks like you paid well below PV-10 value here. Could you characterize the seller situation here and why they were willing to let it go for that price?

Tom Ward, CEO

Yes, the word is 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 then able to sell those at basically PDP, PV10 to us and made a lot of money. They drilled good wells, sold us the wells they drilled, and we paid a fair price for those, inheriting the PUDs that they had proven. There aren't any probable locations because it was drilled in an area where their drilling and others have proved it. So the 9 locations will be drilled throughout the rest of this year into next year as PUDs already. It's a good area to drill in with good rates of return. In fact, by being in our drilling program, we expect to have 50% rates of return.

Michael Scialla, Analyst

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

Kevin White, CFO

Yes, Michael, the cash available for distribution was just over $80 million. This amount accounts for interest expense but not for principal amortization. The principal amortization deducted a little over $20 million from that total. Therefore, after the principal payment, we distributed all the cash generated for the quarter. The per unit amount was slightly lower because it was shared with the equity purchasers from February.

Tom Ward, CEO

So our cash available for distribution, when we send that out, is fairly mechanical and keeps everyone happy, both equity and our debt holders.

Operator, Operator

Next question is coming from Derek Winfield from Texas Capital.

Unknown Analyst, Analyst

I wanted to focus on your 2024 drilling program results. As you look back on the 2024 program, are you seeing opportunities for the Woodford to close the gap versus the Oswego in returns from a drilling and completion efficiency or optimization perspective?

Tom Ward, CEO

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, to me, it's an easier program to hit our rates of return just because it's fairly simple to drill or not as complex to drill as some of the deeper Woodford. The communication we have between wells tends to be a little less. So I don't think it necessarily closes the gap. We've already cut the drilling cost by nearly $2 million a well from when the prior operator had it. Therefore, I wouldn't expect a different outcome in 2025 versus 2024. However, what can happen is that an Ardmore Basin well or a deep Mississippian well can have rates of return that can compete with a condensate well in the condensate window. So after the next couple of wells that are drilled in the condensate window, we'll be moving that rig to the Ardmore Basin.

Unknown Analyst, Analyst

Yes, that makes sense. Regarding M&A, could you more broadly speak to the competitive landscape in the Mid-Con? It appears the privates like Validus are responsible for the competitive environment we're seeing currently. Also, could you comment on the organic leasing opportunities you're seeing?

Tom Ward, CEO

Yes. 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 increased, and well-capitalized companies are moving in to purchase assets. We have never really been great at buying very large packages, with the Paloma 1 being the one exception for us. However, the competition for those types of assets continues to be fairly strong. I see us having the niche still of buying $100 million type assets while others are really looking for free cash flowing assets with as much drilling upside. We don't need that because we have so many opportunities ourselves inside our existing acreage. Therefore, we are focusing on trying to grow our operating income and using 50% of that to increase our drilling budget into high rate of return projects we already have captured inside our existing acreage.

Unknown Analyst, Analyst

Regarding the organic leasing opportunities you guys are seeing across the region. Could you elaborate on that?

Tom Ward, CEO

Most of the time, we already have so much acreage that's held by production. Across the deep Anadarko and the deeper condensate window, we have over 65,000 acres currently. We don't have to lease very much. Our total budget for leasing this year is around $30 million for 2025. This is focused more in the deeper areas, as you mentioned. The Cherokee both Turkey shale and the Red Fort sands have been areas we've been monitoring. Most of our leasing budget goes to places where we already own acreage. We propose a well and then buy the rest of the unit as it's being put together.

Operator, Operator

Next question today is coming from John from Raymond James.

John Freeman, Analyst

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 land amount. Did you say that the $30 million of that midstream and land that you all lumped together, is $30 million for land?

Tom Ward, CEO

Yes, I think that's our budget for land at $30 million.

Kevin White, CFO

Yes, land and midstream.

Tom Ward, CEO

So that includes both. I'm sorry, John.

Kevin White, CFO

But the midstream is virtually the same as in prior years. The biggest change is for leasing activity. But again, as Tom mentioned, the majority of that comes as a byproduct of a larger drilling program.

Tom Ward, CEO

And John, as you think about that, as you move into another rig running, that does provide more locations than we had acreage.

Operator, Operator

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

Tom Ward, CEO

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

Operator, Operator

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.