Helvetia Holding AG

SIX:HELN

Greetings, and welcome to the Mach Natural Resources Fourth Quarter and Full Year 2024 Earnings Results Conference Call. [Operator Instructions] 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.

Thank you, Kevin. Welcome to Mach Natural Resources fourth quarter earnings update. Each quarter, it's important to reiterate the company's 4 strategic pillars. These are: number one, maintain financial strength. Our goal is to have a long-term debt-to-EBITDA ratio of 1x or less. By maintaining a low leverage profile, we give ourselves opportunities when markets experience high volatility. Two, this line execution. We acquire only cash flowing assets at a discount to PDP 10 that are accretive to attribution; 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 optimized our distribution to unitholders. 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 4 pillars. Disciplined execution. Our strategy since the founding of the company in 2017 has been to purchasing 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 have followed that with 19 additional acquisitions. We accumulated over 1 million acres of land that is held by production. We have ownership in 4 midstream gathering and processing facilities and significant other infrastructure. We purchased these facilities for $65 million, and these assets contributed $78 million of EBITDA in 2024 alone.

$17 million of that came from third parties and the remainder from higher realized wellhead prices for our own production. And finally, in every single 1 of our acquisitions, our best-in-class operating team has reduced LOE by 25% to 35% from the previous owner's cost. Disciplined reinvestment rate. We now have the distinct advantage of choosing where to drill from hundreds of potential locations on the previously mentioned. 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 these 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 3 rigs running, continuing to drill the Oswego formation of Kingfisher County, where we've drilled more than 225 wells since 2021, and the Mississippian and Woodford formations in the condensate window of the STACK and Ardmore Basin, where we incorporate locations from the last 3 acquisitions made and the deep Mississippian formation in the Anadarko 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 when we paid 0 for. We drill wells that are highly efficient. For example, our Oswego D&C cost in 2024 averaged only $2.6 million or $202 per lateral foot.

By keeping our costs low, we achieved median payout periods of 15 months, assuming a flat $70 WTI and $350 Henry Hub. According to Invest, 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 an unmatched -- to unmatched cash returns, for our unitholders over the last 5 years and the next 5 years. We anticipate spending between $225 million 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.

Maintained 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 2021, $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. Mach also has peer-leading PDP decline in reinvestment rates. Our next 12-month PDP decline is projected to be 20%, while our reinvestment rate in 2024 was only 47%.

Both these statistics are #1 in a group of 16 peer companies. We have exceptionally strong asset coverage with total proved acreage -- total proved coverage of 3.9x. Net debt to enterprise value of 21% and PDP PV total debt of 3.3x. 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-to-EBITDA at 0.8x 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 1-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 were methodical to reinvest 50% of our operating cash flow then receive our calculated cash available for distribution and send it home to unitholders.

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 our operating cash flow, we're allowed to send back distributions to our unitholders. The best way to describe what we do is consistency. In oil price environments, we maximize our distributions while maintaining a clean balance sheet. In times of lower pricing, we lower our CapEx and thus not having long-term contracts on capital expenditures. In doing so, we continue to have excellent cash returns on capital invested. Our coke 2020 to 2024, 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 unit and obtained 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 location drilled this year. We repaid the company's term loan and lowered our net debt to EBITDA to 0.8x from 1.0x. 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 Mid-Continent. Our latest success to have been in the $100 range.

In fact, we've made 20 acquisitions in average just less than $100 million on H1. 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 PV-10, but also acquiring land that one day will be drilled by us at no cost and no time frame operation due to being held by production. This formula served us well. We also like buying crude oil anytime we move into the 60s or less and have a backwardated curve. We see the crude market moving through the inevitable 1 to 2 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's 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 that 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 it's coming when PE firms and a small public company, we'll find our formula for cash returns attractive and want to be a part of larger mark -- of a larger Mach. We welcome these opportunities as a way to grow our business, getting larger cash returns to our unitholders 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 1 of these types of transactions in 2025. Even if we do not make a meaningful acquisition, we will continue to our production through our drilling program and small acquisitions and deliver excellent returns to our unitholders. In 2024, we ranked first out of all public upstream energy companies and distribution yield. We also ranked tenth in the total of 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 rent basis was weighted 59% oil, 21% natural gas and 20% NGLs by revenue in 2024.

However, as we've 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 is 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 3 rigs running versus the 2 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 unitholders.

If we are fortunate enough to add larger acquisitions, we'll be able to then monetize more of the hundreds of high in total rate of return projects, we are waiting to be drilled on our 1.1 million acres of HBP link. This is why our focus remains on free cash flowing assets to acquire prices that are accretive to our distribution. In closing, I want to reemphasize that we are an acquisition company. Our industry cash returns have been made through opportunistic acquisitions. This is our primary lever of growth. Our expectation is to continue making acquisitions that are accretive to our distribution in 2025, just as we have over the last 7 years in 20 deals.

I'll now turn the call over to Kevin to discuss our financial results.

For the fourth quarter, our production 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 in our first lean term principal was $763 million. During the quarter, total revenues, including our hedges and midstream activities totaled $235 million 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 and the remainder results in the $60 million or $0.50 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 the syndicate of 10 banks were currently drawn around $500 million.

And with that, Kevin, I'll turn it back to you to open up the call for questions.

[Operator Instructions] Our first question is coming from Neil Dingmann from Truist Securities.

Tom, I'm pretty optimistic still on just seeing the environment. I'd love to hear gas oil kind of still in the mid-con kind of where kind of your expectations on for this year?

My expectation is on gas and oil.

Just where you're seeing sort of the better you think you might see some of the better deals this year.

Either gas or oil on better deals. 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 the 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 5 or 10 years is going to consistently be down at these levels. And so I do 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 just so you've got pretty notable infrastructure now that you've put together now over the years. Is there -- would we consider monetizing? Or is that just too valuable now to the development of your properties? I did maybe just any comment you can make on the infrastructure and the value that you see behind that.

Yes, Lakewood would we sell some of our infrastructure Yes. I think the -- yes, 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.

Next question today is coming from Charles Meade from Johnson.

Tom, I wanted to, I guess, about the third rig. And can you tell us when it's going to come? I imagine how investment cap, but when is it going to come? And is that going to be focused on this the Anadarko Deep Mississippian that you talked about?

Yes. So the third rig is coming just any day 4 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 -- in the Anadarko and 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 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 Mississippian in Custer County.

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, it's not new this week or this month or maybe this month, we're 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. And I wonder if you could tell us what you think is there. And perhaps as a way of doing that, you said you'd like to buy oil assets and when oil is in the 60s, where do you like to buy gas assets?

I always like to buy gas assets. So there's -- 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 endless demand. So yes, 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 Amico, you're going to get about 50% natural gas and another 25% or so in natural gas liquids along with crude oil being basically 25%. And so any deal we make is just by its very nature in the Mid-Con and natural gas asset. So we've done extremely well in 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 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.

Our next question is coming from Michael Scialla from Stephen.

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

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 we're 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 had proven. There aren't any probable locations because it was drilled in an area and their drilling and others have proved it. So will the 9 locations we drill throughout the rest of this year into next year for going to be PUD already. That's -- it's a good area to drill in. with good rates of return. And in fact, by -- 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 contribution, it was a little bit below on a percentage of cash available for distribution in the third quarter. Can you talk about the factors that went into that decision?

Yes, Michael, if you're looking at the table itself, the cash available for distribution came in at a little above $80 million. But we -- 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 the per unit distribution was shared with the equity purchasers that occurred in February.

So our cash 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 balance sheet during the quarter?

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

Next question is coming from Derek Winfield from Texas Capital.

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 and returns from a D&C 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 to me, it's an easier program to hit our rates 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 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 do -- we'll never say never about our team and their efficiencies, but it kind of looks like it 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 our rates return then to 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 is the big mess?

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 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 1 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 have as 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 can and 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 page. Maybe could you elaborate on that?

Yes. 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 acreage currently. So I 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 it's -- that is focused more in the deeper areas, as you mentioned. The Cherokee also both Turkey shale and the Red Fort 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 is being put together.

Next question today is coming from John from Raymond James.

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 just say that the $30 million of that midstream and land that you all lumped together, the $35 million to $40 million range again for the year, did you say $30 million of that is for land?

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

Yes, land and midstream.

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

But the midstream is virtually the same, I think, as in prior year. So the biggest change -- the biggest part of the change is for leasing activity. But again, as Tom mentioned again, the majority of that just comes as a byproduct of a larger drilling program.

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

Okay. Yes, that makes sense. And then you also talked about just the increased activity that we're seeing in the Anadarko and just Oklahoma overall has seen the biggest increase in drilling activity of any region in the country in the last several months and 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 this year versus last year's budget?

Our budget is usually fairly small. We elect out of most of the nonops 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.

Your next question is coming from Selman Akyol from Stifel.

This is Tim on for Selman. I just wanted to touch on in the prepared comments, you mentioned kind of leaving more liquids in the gas stream given where 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 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. Yes. So sorry, the answer stays in our...

Okay. Got it. And then last 1 for me. BOE expense has kind of been ticking up in 2024, and I believe that was probably due to the Paloma wells. But just curious on kind of the cadence we should look for in 2025, whether it's kind of a flattening or kind of a continuous kind of uptick?

Yes, I think it's basically flat.

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

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