Mach Natural Resources - Earnings Call - Q2 2025

Executive Summary

• Q2 2025 delivered total revenues of $289M, net income of $90M, and Adjusted EBITDA of $122M; average production was 83.6 Mboe/d and the quarterly distribution was $0.38 per unit.
• On S&P Global definitions, EPS materially beat ($0.76 vs $0.50 consensus)* while revenue modestly missed ($222.4M vs $238.4M consensus); note consensus “revenue” excludes certain items the company includes in “total revenues.”
• Management highlighted a pivot toward natural gas and closed-in Q3 guidance update pending two announced acquisitions totaling ~$1.3B that add Permian and San Juan scale and diversify the portfolio.
• Cash costs remained disciplined (LOE $6.52/Boe); distribution was lower versus Q1 driven by a one-time legal settlement and weaker gas pricing/basis in the Mid-Con.

Values retrieved from S&P Global*

What Went Well and What Went Wrong

What Went Well

• Strong execution with steady operations and disciplined model: “Our second quarter results reflect continued strong execution of our 2025 plan…distribution of $0.38 per common unit” (CEO Tom Ward).
• Strategic expansion: two accretive acquisitions (~$1.3B) add Permian and San Juan entry, with plans to update guidance after closing; management emphasized balance sheet strength enabling deals.
• Cost control and operating consistency: LOE held at $6.52/Boe; production 83.6 Mboe/d with balanced mix (23% oil/53% gas/24% NGLs).

What Went Wrong

• Distribution down vs Q1 ($0.38 vs $0.79) due to ~$8.2M legal settlement with royalty owners (~$0.07/unit) and weaker gas prices/basis (~$0.07/unit) (CFO).
• Gas basis headwinds (Panhandle Eastern) widened during Q2; management does not hedge basis and noted exposure in the Mid-Con.
• Adjusted EBITDA down sequentially ($122M vs $160M in Q1) on commodity realizations despite solid volumes.

Transcript

Speaker 4

Good morning, everyone. Thank you for joining today's call to discuss Mach Natural Resources' second quarter 2025 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 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 and supplemental tables, which are available on Mach's website and their 10-Q, 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 Mach's financial results, and then the call will be open for questions. With that, I'll turn the call over to Mr. Tom Ward. Tom?

Speaker 0

Thank you, Shamali. Welcome to Mach Natural Resources' second quarter earnings update. Each quarter, it is 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/EBITDA ratio of one times leverage. We believe maintaining a turn of leverage is appropriate to give ourselves opportunities when markets experience high volatility. We accomplished the ICAV and SAVNOL purchases by having low leverage. SAVNOL provides us with long-term upside potential to oil markets priced in the low $60s. We feel that this price is not sustainable very far into the future and that ultimately crude prices will rise, even if the near-term outlook is negative. If the OPEC Plus announcement of bumper oil supply increases comes to pass, we want to stay in a position to capitalize on more crude oil purchases.

In the case of ICAV, we purchased an existing natural gas cash flow stream that is heavily hedged with tremendous upside to market demand in the future and nearly unlimited growth opportunities in the San Juan Basin. Both acquisitions were made because our balance sheet was in pristine condition. We also see headwinds ahead for natural gas prices as we enter the winter season with full storage and growing supply, along with additional takeaway capacity being added before further demand develops in 2026. Therefore, we see continued opportunity to add to our portfolio as long as we maintain our leverage goals. Number two, disciplined execution. We acquire only cash-flowing assets at a discount to PDP PV10 that are also accreting to our distribution. We now have initiated 24 acquisitions, spending more than $3 billion. In every case, we have maintained this execution strategy.

This strategy has allowed us to build an acreage base that will be nearly 3 million acres in size, with multiple areas that have high rates of return drilling locations that are held by production. We believe that Mach is unique in this regard. 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. Mach is also unique in being able to maintain our production with an industry-leading reinvestment rate due to emphasizing our second pillar of disciplined execution. Our entry in the San Juan and Permian Basins will move our decline to 15% from 20% through buying low-decline cash-flowing assets.

This allows us to enhance our operating cash flow and maintain our production during periods of low prices while looking for areas to purchase if markets become destabilized. However, during periods of high prices, we can use our enhanced cash flow to reinvest more in drilling and grow production during those periods. Mach is positioned well to thrive in both scenarios by being able to pivot from acquisitions during higher prices to drilling of high-return locations that are waiting for us with no expiration dates. The ICAV acquisition is an example of this. In the San Juan, we're acquiring more than 500,000 acres of land that is held by production. If natural gas prices remain elevated, we can switch away from drilling crude oil locations to more natural gas-focused sites.

We are planning to implement this strategy in 2026 by using the spring and summer drilling season with three rigs searching for natural gas in the San Juan during drilling for the Mancos Shale, dry gas, and the Fruitland Coal. At today's strip, we plan to maintain our production volumes through 2027 while spending less than 50% of our operating cash flow and using some of the excess to pay down debt. We project increasing our natural gas volumes to 70% post the SAVNOL/ICAV acquisitions and, for the first time since our inception, project natural gas to be at least 50% of our revenue stream starting in 2026. All of the main pillars lead to the fourth and most important: delivering industry-leading cash returns on capital invested through distributions to our unit holders.

With our announced distribution of $0.38 per unit in the second quarter, we have sent back $4.87 per unit to our unit holders since our public offering in October 2023 and more than $1.2 billion in total since inception in 2018. All the while, we have grown our business to more than $3.5 billion of enterprise value without selling any material assets while maintaining a cash return on capital invested more than 30% per year over the past five years. Even in this year, with crude prices moving down, we are expecting to have a 25% return on capital invested and have never been less than 20% since our company was founded. Post the ICAV and SAVNOL acquisitions, we anticipate having leverage just above one times. However, we'll work diligently to bring back our leverage to our desired goal by presenting a clear path of reducing our debt levels.

We will resist the opportunity to acquire other assets that would lead to moving our leverage higher. Our goal is to continue to look for free cash-flowing assets where private equity-backed sponsors need to move towards a more liquid currency by taking our equity. In these circumstances, we see the opportunity to increase our operating cash flow while expanding our drilling budget on our vast acreage. We also continue to be able to purchase small acquisitions in the Midcon that fit our goals by using cash on hand. By sticking to our model of reinvesting only 50% of our cash flow, we can keep our production flat to slightly growing while expanding our distributions per unit. Our drilling plans for 2026 revolve around adding to our natural gas mix. We currently plan to have two deep Anadarko dry gas rigs running.

These locations are targeting natural gas of a depth of approximately 15,000 feet true vertical depth. We then project to drill another 15,000 feet of horizontal length. These drills will cost approximately $14 million and find between 15 to 20 BCF of gas and have returns in excess of 50% at today's prices. We'll also focus on the San Juan during the summer drilling season. In the San Juan, we plan to have three rigs running in 2026. The Mancos dry gas play is targeting three-mile laterals at a true vertical depth of approximately 7,000 feet. We plan to spend approximately $15 to $16 million per location to find 15 to 20 BCF of gas and have a return of greater than 50%. The deep Anadarko and the San Juan gas plays are just developing.

Both are known to be prolific gas areas that have not been extensively drilled since the onset of enhanced drilling procedures with large stimulations due to the previous decade of low natural gas prices. Mach Natural Resources has hundreds of thousands of acres across the plays to review and bring to market with no time pressure to be implemented without losing our acreage. We also plan to have one drilling rig drilling in the Fruitland Coal. This development is ongoing in the San Juan with rigs targeting the coal between older vertical wells by drilling multiple laterals from one well bore. The target is shallow at 2,000 feet, and we anticipate having 5,000 to 8,000 feet of lateral in each well bore. These locations are expected to cost approximately $3 million and have returns in excess of 50%.

Lastly, we plan to move back into the Oswego to continue our drilling program that was started in 2021. We've drilled more than 250 wells in the Oswego where a one-and-a-half-mile lateral costs less than $3 million, and even at today's distressed oil pricing, it has returns approaching 40%. Our second deep Anadarko rig is projected to spud in early September. The Oswego locations are projected to start in early 2026, and the San Juan rig should move in in early spring 2026. Our focus on gas development through 2026 is driven not only by the current price environment but also by how we see demand over the next five years. We see total demand growth of upwards of 25 BCF of gas per day by 2030. This is broken down to the following: 15.6 BCF per day of LNG feed gas growth.

This includes the facilities under construction in Mexico, which will be an additional outlet for U.S. production, and our San Juan purchase is well-positioned to meet West Coast demand. Six BCF per day of power generation growth is a conservative estimate, but it should be acknowledged that two to four BCF of power generation growth will be from the data centers located in Texas, Colorado, the desert Southwest, and California. Thus, the San Juan acreage is also strategic and well-positioned to meet this upcoming demand. 1.1 BCF per day of demand growth from commercial and industrial, and 1.4 BCF per day of growth from exports to Mexico. We see supply of six BCF per day from the Permian-associated gas growth, which is at risk if prices remain soft. 15 BCF per day of supply growth in the Haynesville in the Northeast in response to LNG and data center demand.

This leaves the Eagle Ford, Midcon, and San Juan Rockies as the natural supply growth areas to meet demand. We see the current processing capacity of approximately four BCF per day in the San Juan and nearly 16 BCF per day in Midcon to meet the ongoing demand requirements needed to fuel or enhance consumption of U.S. natural gas. During the quarter, Mach drilled 10 total wells consisting of six Oswego, three Woodford-Miss Condensate, and one Red Fork location. We're currently drilling one Red Fork and one deep Anadarko dry gas well. These rigs are located in Dewey and Custer Counties, Oklahoma. In our Oswego program, we averaged 9,850 feet per lateral, our longest locations to date. These locations averaged $3.6 million per well. Mach drilled three locations in the Woodford-Miss program, including the Brockland 3MH, which was drilled to a total depth of 30,384 feet.

The Brockland 3MH is waiting on completion alongside the Brockland 2MH, which is drilling currently. Both locations will be completed together starting later this month. In the Woodford-Miss Condensate area, we drilled two locations that averaged 10,240 feet of horizontal section. Our operation goals for Q3 2025 are to continue to refine and reduce our Dazon location in our deep Anadarko drilling program while increasing our rig count from one to two starting in mid-September. We continue to keep our lease operating costs low at $6.52 per barrel and look forward to closing both the SAVNOL and ICAV asset purchases to start to work on reducing costs. We're not certain there are additional places to cut LOE. However, in our previous 22 acquisitions, we've reduced LOE by between 25% to 33% each. With that, I'll turn the call over to Kevin for the financial results.

Speaker 5

Thanks, Tom. For the quarter, our production of 84,000 BOE per day was 23% oil, 53% natural gas, and 24% NGLs. Our average realized prices were $63.10 per barrel of oil, $2.81 per MCF of gas, and $22.41 per barrel of NGLs. Worth noting, pre-hedge realized prices were lower by 11%, 21%, and 17% for oil, gas, and NGLs compared to the first quarter of this year. Of the $219 million total oil and gas revenues, the relative contribution for oil was 51%, 31% for gas, and 18% for NGLs. On the expense side, our lease operating expense totaled $50 million, as Tom mentioned, $6.52 per BOE. Cash G&A was only $0.088 per BOE. We ended the quarter with $13.8 million in cash, and we had drawn $565 million on our $750 million revolving credit facility.

In conjunction with our plan to close the ICAV and SAVNOL acquisitions, we are in the latter stages of expanding our RBL and expect the borrowing base and commitments to nearly double from its current amount and to add a handful of new banks to the syndicate. Total revenues, including our hedges and midstream activities, totaled $289 million, adjusted EBITDA of $122 million, and $130 million of operating cash flow. We had development CAPEX of $64 million during the quarter. We also had a reduction of cash available for distribution of $8.2 million due to a settlement of royalty owner legal dispute. We generated $46 million of cash available for distribution, resulting in an approved distribution of $0.38 per unit, which will be paid out on September 4th to record holders as of August 21st.

Shamali, I will now turn the call back to you to open the line for questions.

Speaker 4

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. One moment, please, while we pull for questions. Our first question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Speaker 3

Yes, good morning, Tom and Kevin.

Speaker 4

Morning.

Speaker 3

Tom, your production volumes were a little higher than I think I was looking for, and I think a lot of people on the street were looking for. I was wondering if you could tell me if there's any, you know, what part of the kind of legacy MidCon portfolio delivered, or you know, maybe you can say it looks like it beat, it surprised us. Was it a surprise to you? What parts of the portfolio really had the strength? Was it perhaps related to some of these recent wells that you spoke about in your prepared comments?

No, Charles, just normal operations that our production is doing well. We had a couple of bolt-on acquisitions that might have enhanced some of the production. Basically, all areas are running pretty well. We have a great operations team and continue to keep our locations working with a lot of workover. I would say our operations team just does an excellent job focusing on business, but nothing out of the ordinary.

Got it. Okay, thank you. Tom, going back to the, you gave us a lot of detail in your prepared comments, and I was intrigued by this Brockland 3MH well. Is that one of the sort of the deep Anadarko targets that you were talking about earlier that, you know, $14 million well costs are targeting 15 to 20 BCF? Maybe you can tell me if those two are connected and then maybe give us a timeline for when you're going to complete the Brockland.

Yes, we're drilling the second location currently on a two-well pad. We'll do a zipper frac between the two locations, and we'll start in later this month to early September.

Okay, got it. Thank you.

You bet.

Speaker 4

Thank you. Our next question comes from the line of Derrick Whitfield with Texas Capital. Please proceed with your question.

Good morning, guys, and thanks for your time.

Hey, Derek.

For my first question, I wanted to focus on distribution this quarter. Despite the strength of operations this quarter in production, and Charles just covered that, there were a series of one-time events that led to a lower payout than the cash flow minus CapEx would imply. Could you perhaps add some color to those developments for the benefit of investors?

Speaker 5

Sure, Derek. I think we've kind of narrowed it down for ease of digestion here. The legal settlement, again, it's a fairly ordinary type of litigation, I guess, in our business that we see frequently. It's not that ordinary for us, but we did reach a settlement with the royalty owner dispute on deductions that we were making from their revenue, and our share of that settlement was roughly $8.2 million. That reduced the distribution by $0.07 per unit. The second part of that, really, it comes down to gas prices. Lower gas prices this quarter, and I'm comparing this to the first quarter, and also really where consensus is out there, results in another $0.07 reduction from, you know, had we had prices similar to the first quarter or also kind of versus looking at the consensus analyst estimates that are out there.

I think maybe the Panhandle Eastern Basis differential maybe was a little bit unique versus other basins across the country, and that we had bases widened during the second quarter. That may not have been, it could have happened real time as we went through the quarter and probably wasn't captured, I think, in a lot of analysts' estimates of the quarter.

Great, thanks, Kevin. As my follow-up, I wanted to focus on your growth profile. As we layer in recent transactions and your deep miss activity, we're backing into a fairly material natural gas growth trajectory that could exceed 650 million cubic feet per day in 2026. That's quite a bit of bump in census. Is that a fairly fair depiction of the production profile as you guys see it?

Yeah, so we see our natural gas product mix moving north of 70% in 2026 and up closer to 75% in 2027. As we drill, that's assuming we continue to have a robust natural gas market, which we do believe, even though we see near-term headwinds, we want to be long natural gas in late 2026 and into 2027. We're very strong bulls. Just the amount of gas coming through the fill season this year leaves us in a precarious place, in my opinion, that we'll be moving into the fall and winter season with full storage and a couple of new pipelines coming on ahead of demand. Once demand hits in 2026, then we do want to be long gas, which we're just making all that to say is we're making an assumption we'll continue to drill natural gas wells, but stand alone right now without making other acquisitions.

Yes, we see ourselves moving up from a product mix to substantially above 70% natural gas.

We agree with your views, Tom. Maybe just one build on that for the benefit of clarity. When you look at your gas production base, you guys, as I understand, have quite a bit of that undedicated today. You can materially steer that and benefit in a much higher gas price environment than some of your peers. Is that a fair depiction as well?

Yeah, I don't know as compared to our peers, but yes, we do have a large amount undedicated.

Terrific. Thanks, guys.

Thank you.

Speaker 4

Thank you. Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question.

Speaker 2

Good morning. Thank you. When we look at the portfolio that y'all built, which is anchored on these very stable, low-decline rate assets, now you've got this exciting opportunity with the Mancos, as well as what's emerging with the Anadarko deep gas. I'm just interested in your thoughts on how you balance those two aspects of your portfolio, the legacy proven low-decline assets with this emerging growth play like the Mancos.

John, are you asking how we found them?

I'm sorry. Just how you balance the portfolio between you've got these exciting growth plays that require obviously steeper decline rates, you know, more capital, just sort of the development process of these emerging plays versus, you know, your stable, very low-decline rate type assets, you know, that have sort of been the foundation of the company.

Yeah, so I mean, it all just ties together with our reinvestment rates. We want to spend 50%. We don't want to spend 20% or 30% or 40%. We like to spend close to 50% of our operating cash flow that keeps our production flat. The only way you can do that is to have that long life, the balanced portfolio, as you mentioned, of low-decline production that we built over the years. That then allows us to reinvest only 50% in the higher rates of return drilling that the Mancos now and the deep Anadarko especially. I guess the Fruitland Coal is probably the best of the group as far as just in-field drilling and rates of return. Whenever we put that all together, it just gives us a lot of flexibility. We can pivot from oil to gas. We can move back to oil if prices change.

We have 3 million acres of high-return drilling locations that we can choose from. We're in a really ideal situation that we've built ourselves now down to a 15% decline that we can continue to grow our production using only 50% of a reinvestment rate and choose what rates of return we want and have no real long-term contracts that keep us beholden to drill one particular area over the other. We don't have any lease expirations. We truly are able to move around rigs as we want within 30 days.

That's great. The gas differential kind of widened out a good bit this quarter that y'all highlighted earlier. I believe y'all have taken some recent steps on the gas marketing side to possibly improve that going forward. Maybe if you could just elaborate on that.

Oh, I don't think so. I think that basically we are at the mercy of Panhandle Eastern for most of our Midcon gas, and if basis widens, our basis widens. We don't hedge basis. Maybe Kent's getting ready to say something. Do you want to take it?

Yeah, hey John. We were talking a little bit about GPMT expense running a little higher due to new treatment, certain costs, certain marketing costs related to the Paloma wells. We had a marketing agreement with kind of a third-party intermediary, and we chose to get out of that agreement and fold in those volumes with kind of the bigger, larger group that we've marketed gas with for years.

Yeah, so we use NextEra.

Right.

Right. You get better pricing with NextEra than with the previous intermediary.

Yes, okay. I didn't know where you were going with that. Yes, NextEra has been a good partner with us.

That's great. That makes sense. Thanks, guys. Appreciate it.

Thank you.

Speaker 4

Thank you. Our next question comes from the line of Michael Scialla with Stephens, Inc. Please proceed with your question.

Hi, good morning, guys. I wanted to just talk about 2026. I realize it all depends on where oil and gas prices go, but based on what you're thinking right now, it sounds like the three rigs in the San Juan will drill springtime through summer. I think there's a limited drilling window there. You keep the two deep rigs in the Anadarko and then one on the Oswego. Is that where your 2026 plans are preliminarily at the moment?

Yes, as long as our operating cash flow holds up. It all depends on pricing and where EBITDA is, but it could expand if prices move up and can contract if they don't. It is the barometer for us on how much we spend is 50% of our operating cash flow. It's never written in stone that we're going to have that development program. It's also subject to change if prices move. If gas prices move down and oil prices move up, that could also switch. We are more difficult, I think, to monitor with exactly where our rigs are going to be because every month we make a decision here. I can't tell you.

Yeah, I appreciate how fluid that is in your flexibility. I just want to get your latest thoughts based on.

That is as of today and where our EBITDA sits today, this is exactly what we plan to do. Also, permitting. You know, San Juan's not the easiest place to drill. The New Mexico side, you basically have May to December to have everything through, which has us kind of in the drilling season of May to September.

Okay, gotcha. For the second half of this year, I think SAVNOL had a rig running. Were there some wells there that you plan on going ahead and completing on the Central Basin platform, or do you kind of halt all the activity when you close the deal?

Yeah, they had two rigs running at four locations that they're waiting on completion, that we'll complete once we close.

Okay, got it.

They're also ICAV, which should have basically five locations ready to complete at closing.

Right, got it. I wanted to ask one more on the kind of unusual items for the quarter. It looked like to us, we could have it wrong, but your GP&T cost kind of popped up for the second quarter. Is that correct or did anything unusual happen there?

Speaker 5

Yeah, due to the marketing arrangement change that we mentioned, and that took place at the beginning of the second quarter, there's essentially a reclass, and won't bore you with the FASB number of the provision, but it's a reclass of moving GP&T up and revenues also go up. It is a kind of bottom line neutral impact, and it just has to do with when title to the gas changes, and it's in association with this new marketing arrangement. Net-net, it's kind of a zero-sum game, but in the individual categories of revenue and GP&T, they both went up by similar amounts.

Okay, I got it. It was the gas price that was kind of the maybe the difference between our estimates and some others. There's really no change to what you're thinking in terms of gathering and transportation costs.

No, when we update guidance, when we close the acquisitions, that line item will change to reflect that new arrangement. Again, so will our basis differential up above.

Got it. Thanks, Kevin. Thanks, Tom.

You bet.

Speaker 4

Thank you. Our next question comes from the line of Geoff Jay with Daniel Energy Partners. Please proceed with your question.

Hey guys, just a real quick one for me just to make sure I understand the activity changes. As she sits today, the three rigs in the San Juan next year, are those all incremental or are there some kind of, we're working now, I guess? In the Permian, as I understand it, you are going to basically let the two rigs they have currently drop and go to zero until you see a better drilling signal. Do I have that right?

That's correct. The San Juan currently has one rig that will be leaving shortly sometime in late August, early September, so let's say this month. We'll be picking up hopefully two Mancos rigs and one to two Fruitland Coal. Right now we have set up for one, but I'd love to drill it with two. At today's prices, that then would nudge out some of our oil locations. If all things were just fantastic, we'd have three to four rigs. I'm just projecting three in the San Juan and two in the deep Anadarko drilling for gas and one rig that is looking Oswego oil just because it's a steady, very low-risk, good oil-producing area with high rates of return, but they still don't match the natural gas locations that we have today.

Yeah, that's all for me. Thanks.

Thank you.

Thank you. Our next question comes from the line of Carrie Mangiano with Stifel. Please proceed with your question.

Hi, thanks for taking the question. In terms of the acquisitions, was there any preference given to acquisitions that would take part cash and part units, or would you guys have bought other properties, or have you looked, did you look at other properties that wanted all cash, but the other properties would take both? Was there any consideration?

No, we have that. Yes, we can't do an acquisition of any size more than $300 million or $400 million that doesn't require equity. Anyone who would like to move from a private company into a more public liquid holding, they need to take equity if they're of any size, especially anything over $400 million for sure, that we can't do with and still then maintain our leverage ratios that we have to have in order to maintain our four pillars. The easy answer is yes, the taking equity was a large part. In fact, the only reason we could do either of the acquisitions.

Okay, did you look at any others that said they wanted all cash?

We look at a lot of throw-in bids with equity and get declined.

Okay, that's what I was just wondering about. Somebody had mentioned it to me that's involved out there in Texas, and they said there were some other properties that wanted all cash or something in their opinion, but I just thought I'd run that by you guys. That stands true.

Yeah, you have to, the other thing to think about is that every seller has an opportunity. There's plenty of competition to take all cash. You have to believe, which I believe, it's actually better to take our equity and ride along with a company that's going to give you 15% to 20% distributions while you wait and look for a time that you want to exit. To me, it's along with, you know, if you have a belief that oil is going to be above $60 or $70 over time or gas prices are moving up in the future, why wouldn't you take equity instead of a cash offer that's basically equal with where our equity offer is?

Yeah, I guess that just shows that these people that are selling do believe in what they're selling and they're not just trying to take a buck and get out, but they are along for the ride. That's a perfect way to couch it to the clients that I've got in this. I appreciate that, Tom. I've been following you for years.

Speaker 5

Thank you.

Speaker 4

Thank you. Ladies and gentlemen, we have reached the end of the question and answer session. This concludes today's conference, and you may disconnect your lines at this time. We thank you for your participation. Have a great day.