Good morning, everyone, and thank you for joining us, and welcome to Mock Natural Resources, second quarter, 2026 earnings call. 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 may 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 can cause actual results to differ from those in such forward-looking statements, please read the company's filings with the SEC. Please recognize that except as required by law, they undertake no duty to update any forward-looking statements, and you should not place under-reliance on such statements. They may refer to some non-GAAP financial measures in today's discussion. For reconciliation from non-GAAP financial measures and the most directly comparable GAAP measures, please reference their press release and supplemental tables, which are available on Mock's website, and their 10-Q, which will be also 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 Mock'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?

Thank you, Darrell. Welcome to Mock Natural Resources' second quarter earnings update. We reiterate the company's four strategic pillars that have guided us since our founding in 2017. These pillars are disciplined execution. We only purchase cash-flowing assets at a value of PDP, PV10, or less, and do not pay for any leasehold, PUDs, midstream, or infrastructure. The second pillar is disciplined reinvestment rate. We maintain a reinvestment rate of less than 50 percent of our operating cash flow. The third pillar is maintain financial strength. We're cognizant of the peril of too much debt. In order to capture the opportunity of acquiring assets in the san juan and central basin platform we strategically moved leverage above our goal of one times death evita this pillar is still standing therefore it is important to move leverage back our stated goal versus the 1.4 times we're projected to be at the end of the year outside of waiting to solve through increased pricing we continue to look for assets at discounted prices to use our equity to purchase. These purchases need to be accreed to our cash available for distribution. We also have an at-the-market equity program to place $100 million of equity at prices that do not disturb trading. And lastly, we can take a portion of our distribution and pay down debt. Our team is dedicated to meet our goal before the end of 2027. Once we achieve our goal, we'll be in a position to take advantage of any downward movement in the market to make additional bargain purchases. The very reason to bring down debt during a period of exuberance is to be prepared to purchase in a time of want. This is the very essence of our company. The fourth pillar is to maximize distributions to unit holders. This pillar drives all of our decisions. We've distributed back $6.67 to our unit holders since 2024. Very few public companies in this country have yields at MOC's level, and none of them are oil and gas producers. Yields like ours are usually only found at businesses carrying a lot of leverage that often can't sustain once credit tightens or rates move against them. MOC was built entirely different. Our distributions and the cash returns we deliver are second to none, and they're the result of the discipline behind our other three pillars mock was established around a cash return model we've said many times that we had a belief for several years before forming the company that there would be a time when we could buy cash flowing assets that seldom heard of prices by avoiding the tendency of the industry to look for growth through the drill bit our goal is to buy distressed assets at discounted prices to throw off cash we were fortunate to pick the timing correctly and build a large producing base at bargain prices. We continue to look for those types of assets, but it's become harder as more capital is now chasing the same type of cash-flowing assets that we propose to buy and are willing to pay premiums to our model. However, our steadfast approach to value has paid off by giving us a 50-year cash flow stream plus nearly 3 million acres of land that is held by production, and that holds our production flat by spending less than 50 percent of our operating cash flow. Therefore, in times of excess capital provided by private equity and ABS companies, we can pivot to rely on drilling to sustain our model. All of our acquisitions have been made at a discount to the strip at the time of purchase. The timing of some of our acquisitions was quite spectacular, such as buying Alta Mesa through the 363 bankruptcy process in April of 2020. That purchase was made against a $20 oil strip and paid the first lien RBL lenders back less than $0.10 on the dollar. That then made the lending institutions leery of investing in the MedCon and gave us a distal running room to acquire other assets at rock-bottom prices. the tide did not turn on the midcon for lenders until 2024 there is now a wave of lending and equity providers chasing midcon assets as capital started to move back into the midcon we've expanded to the san juan and central basin platform of the permian we were able to purchase the oil assets of sabinol in the low 60s per barrel range and also were able to purchase the natural gas assets of ICAV in the San Juan at less than PDP, PV10. Not only did we purchase the assets at discount prices, we also bought a stream of production in both cases that had less than a 10% decline. Sabanol, in particular, gave us immediate cash flow benefits due to the rise in crude prices since the purchases. Lastly, both have substantial drilling room left on the assets. MOC has a history of strong cash returns on capital invested and cash distributions. Over the past five years, we've delivered an industry-leading croquis averaging 35 percent. Only industry-leading, but also in the top 1 percent of all public companies in the U.S. We also have distributed an industry-leading distribution yield of 15 percent since 2024 through the first quarter of 2026. This performance was achieved through different pricing cycles ranging from $94.23 per barrel in 2022 when we achieved a 53 percent croquis to $64.81 per barrel in 2025 when our croquis was 23 percent since our inception we've never had a croquis of less than 20 percent we cannot find another public company with such a strong record of cash returns our cash distribution policy has led to a yield of four times the pure average since 2024 as i mentioned these returns were accomplished through disciplined acquisitions on top of the best-in-class break-evens of both natural gas drilling and liquid liquid weighted peers post the start of the conflict in iran we moved from drilling 100 natural gas wells to crude heavy drilling this is the same type of pivot that we made in april 2025 when post tariff day we changed our drilling plans from all weighted drilling oil weighted drilling to natural gas this is the luxury of having nearly three million acres of land that's held by production currently we're drilling our last two wells in the manco shell the completion phase of this year's drilling has been delayed until next year in order to stay within our internally mandated annual capex of 50% of operating cash flow. Given that restraint, it's more valuable for us to drill for oil rates of return versus natural gas in the last half of this year. We currently have three additional rigs running in Oklahoma. These are located in the Oswego, the Red Fork, and Ardmore Basin, Sycamore. The Ardmore Basin locations will be completed by the end of Q3. We will defer drilling more red fork locations until the q1 of 27 and keep one rig in the oswego during q4 of 26. our drilling schedule is very fluid one of our hallmarks is the ability to change the product we drill for and the amount we spend very quickly mock has a variable distribution to capture the changes in capex associated with different drilling patterns the pattern in 2026 has been to spend more capex in q2 and q3 while drilling in the san juan the variable nature of our capex reveals itself in our distribution this quarter we will distribute 36 cents per unit since we do not have fixed distributions there's not any pressure to spend more than 50 percent of our operating cash flow on capex in other words the cash flow dictates our pace of capex not the lust for growth at any cost the clear workhorse as far as capex in our portfolio has been the oswego limestone formation in kingfisher county oklahoma we have drilled more than 250 wells on this asset since 200 2021 and recently moved a rig back in the area to continue drilling once oil prices improved and we we show in our presentation the oswego carries a rate of return of 87% at a $75 oil strip. The key to the formation is not how much we find but in how much we spend. We're only looking for approximately 160,000 barrels of oil, but we'll spend only 3.3 million to drill and complete. Cutting costs is the key to our business model. The newest field we have acquired that will also become a drilling workhorse is the manco shell of the San Juan basin within the san juan we now hold 575 000 acres of land that only expires when production ceases the key zone to elaborate on is the manco shell this zone is just now being expanded our manco shell position represents one of the most compelling emerging natural gas opportunities in north america the well performance rivals that of the better known haynesville and marcellus shale place with operators recently reporting mancos initial production rates exceeding 25 million cubic feet of gas per day the mancos footprint is approximately one third one third the size of the marcellus and one tenth the size of the haynesville however mock controls the play with only three other sizable owners we are the second largest producer of natural gas behind Hillcorp and also the second-largest owner of acreage. The plant has increased more than 20-fold in the last five years and now exceeds 500 million QV of gas a day. The San Juan also benefits from a mature natural gas transportation network developed over decades of conventional gas production. We expect over the next five years that additional takeaway capacity will be installed to get the premium gas markets of Arizona and the Pacific Coast LNG markets. This is much different than when the Marcellus and Hainesville were first being explored and there was no takeaway available, which required operators to take on large firm commitments with pipeline companies. We currently have a gas marketing agreement placed through 2030. Therefore, by the time the contract amortizes in 2030, we'll have strategic optionality for our 350 million cube feet of natural gas that can be held flat by drilling only five net wells per year if we choose to increase activity to 10 net wells per year we could grow mocks from that production to more than 500 million cubic feet of gas per day this is the benefit of buying low decline cash flowing assets that also have fantastic upside potential the manco show us has potential to dominate the mock story in the years to come. As in the Oswego, the key to increasing rates of return in the Mancos is to lower costs. We believe that we could lower capex of a three-mile lateral from nearly $20 million to less than $15 million per well. Now that our drilling season is underway and we have four locations drilled, we expect the ongoing program to be in the $13 million range for a completed well. I'll now turn over the call to Kevin to discuss financial results.

Thanks, Tom. For the quarter, our production of 149,000 BOE per day was 15% oil, 69% natural gas, and 16% NGLs. Our average realized prices were $95.40 per barrel of oil, $1.93 per MCF of gas and $28.99 per barrel of NGLs. Of the $360 million total oil and gas revenues, the relative contribution for oil was 54 percent, 30 percent for gas, and 16 percent for NGLs. On the expense side, our lease operating expense was $98 million, or $7.21 per BOE. Cash G&A was approximately $7 million or $0.54 per BOE. We ended the quarter with $41 million in cash and $270 million of availability under the credit facility. Total revenues, including our hedges and midstream activities, totaled $406 million, adjusted EBITDA of $182 million and $154 million of operating cash flow, and our development capex for the quarter was $97 million for 63% of operating cash flow. Year-to-date, our development capex is right on top of 50% of our year-to-date operating cash flow. In the quarter, we generated $60 million of cash available for distribution, resulting in a distribution of $0.36 per unit, which will be paid on August 31st to holders of record on August 17th. And Daryl, I'll now turn the call back to you to open the line for questions.

Thank you. We'll now be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for your questions. Our first questions come from the line of Neil Dingman with William Blair. Please proceed with your questions.

Morning, Tom, the team. Thanks for the details. Tom, my first question is just on your upcoming, as you've kind of been moving the upcoming overall drilling program.

Can you remind me, I think, is just double-checking most of your near-term B&C focus will be on the Oswego, and if so, could you just remind us, you know, how much activity that will consist of and how you're thinking about the economics behind this play in this in this environment yeah neil the you're you're correct the ongoing drilling program that we have through q4 of this year is to keep an oswego rig running we just have we have a lot of locations uh the sycamore locations in southern oklahoma are the highest rates return we have but there's really only three of those left that we picked up through the a couple of acquisitions in 2024 so the oswego is the the continues to be as i mentioned the the workforce of our program and we'll keep a rig at you know depending on pricing but keep a rig there through 2027 also so kind of a consistent rig running in the os in the oswego with if prices stay as they are we'll move a rig back into the Red Fork next year, and that play has a little bit more running room with this also. So those are kind of the two oil plays. We're yet to know where gas prices will be next year, but we do plan to have a program in the Manco Shell to drill and then complete the wells this year, assuming that gas prices are rebounding by next summer.

Tom, does that Oswego compete, you know, with other more well-known oily plays in this kind environment?

Oh, you'd have to tell me. We have basically an 85 percent rate of return at $75 oil, so I think so.

Got it. And if I could, just on capital allocation, could you remind me, you or Kevin, just on, you know, broad terms around your reinvestment rate and then how you intend to deploy the remainder of the cash flow? I think it's pretty straightforward what you all are doing.

Yeah, Neil, we said in those prepared remarks, we were right on top of 50 percent year to date. And, you know, that's one of our pillars to have that reinvestment rate of 50 percent. So we would expect to end the year at a similar number. I mean, it may have a little lumpiness quarter to quarter, but not much.

Very good. Thank you all. The operating cash flow drives what our cash CapEx is. So we're going to stay under 50% of operating cash flow. So as you can see, quarter to quarter, we'll either increase CapEx or decrease CapEx depending on what operating cash flow is or prices. Thank you all. Thanks.

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

Yes, good morning, Tom and Kevin and to the rest of the mock team there. Tom, I'd like to pick up on that last point. Assuming you had the operating cash flow to do the MACUS completions whenever you wanted, what is the price that you need to see in the San Juan basin market for you to pull the trigger and do those completions?

It's not so much that we wouldn't do the completions. It's probably more that we wouldn't spend any CapEx if prices continued to be under $3. I think it would be difficult to have any gas program in the U.S. working. So if you think of the BCF per 1,000 that we see in the Mancos, it sits just under the Marcellus. I think we calculate the Marcellus at 1.9 BCF per 1,000 feet. The Mancos at 1.7 and the Haynesville at 1.6. So if you're – all three of those are going to be in line with the same types of production. You know, the San Juan has its difficulties of basis at times, but then other times it has very good basis like today. It sits on top of the MidCon. So, I'm – yeah, I think that to have an ongoing drilling program for natural gas that competes with oil so that – our problem is that we only have a certain amount of operating cash flow, and that goes to the highest rates of return. And so, going into next year, what we have to look at is if the Makos can compete against our oil reservoirs, and we won't know that really until after we get through this winter. As you know, Charles, I'm a little hesitant right now to be bullish natural gas, but as we come into full storage into the fall and are looking straight in the face of a strong El Nino winter, it's difficult to be real bullish about it. But the – so we'll just evaluate as the year goes into next year. I'm still very – and I think most people are very bullish long-term natural gas. It's just how to get from here to there, and that's basically – it might be a next summer event before we really do much spending on natural gas CapEx. Right. As I look out over the longer-term period of five years and you take that looking at our gas contract that we bought amortizing that hedge out through 2030, we should be in perfect position to capture the demand that everyone sees coming. And I don't think Western Supply is going to keep up with that, and so that ultimately I feel very good about our natural gas positions. It's just how much we spend in, you know, 27 might fluctuate.

Right, Tom. I appreciate your comments. So you can be a natural gas bull, but at the same time be honest about what the next few months look like. Second question, I wanted to ask about the Central Basin platform. I actually heard from another company recently about a so-called BMW play, Barnett, Mississippi, and Woodford in the Central Basin platform. And I don't think it's your style to go be a pioneer on a play like that, but I'm curious if you're aware of it, if it's happening near some of your acreage perhaps in Gaines and Andrews.

You know, I'm not aware of it, and I don't believe it's near any of our properties. And we're having any trouble even getting a clear fork location cleared, so I don't think we'll be doing the BMI. All right. Thank you, Tom. Thank you.

Thank you. Our next question has come from the line of Michael Ciala with Stevens. Please proceed with your questions.

Good morning, guys. I want to start with your last comment there, Tom, on the clear fork. what are the plans there now?

We don't have it in our drilling schedule yet so right now the clear forks again we were planning on it earlier in the year when we thought we'd add another rig but as prices moved away from where they were the clear fork was the first to be exited so as of right now you know we might get the locations in in 2027 it's just really more price dependent it, again, where our operating cash flow is. I mean, the luxury we have is we sit around on 3 million acres of land that's HBP, and we can pick and choose where we want to drill, where we want to drill at the highest rates of return. And so it's just, I realize from being an analyst, it's hard to keep track of what we're trying to do, but it really can change month to month. Ask Kent.

He has to model it every month. i uh i feel his pain um i guess to get a little bit more color on the uh on the clear for again it sounds like it doesn't compete today with the oswego can you just describe what the opportunity set is there what's the inventory like and is this that would they be vertical wells is it under water flood can you just give us a little bit more color on it it is under a water flood but we drill horizontal wells within a water flood and I can kind of tell you so the the and then there's only like eight locations so it's not it's not you know

hundreds of locations so we we pick and choose around what we have and when we buy additional land that comes up it just happens to have some locations that can be drilled on it. I guess if it all worked well, you know how many RIC that we've got for next year if it comes into the program. So like at the end of July, that's going to have a 53% rate of return compared to, you know, the Oswego in the 80s. So just if I have more operating cash flow, we drill it. That's kind of where the point is, I guess. It is a target worthy of drilling. It's just that we're going to stay below 50% of operating cash flow.

Understood. I wanted to ask on the balance sheet, you know, I think last quarter you said you kind of anticipate, you know, as you move forward, leverage will move down naturally, just given where, especially where oil prices are, but still feeling that way, or do you feel compelled to pull back at all on the distribution or to do anything differently than what you're planning or have been planning historically?

Yeah, I mean, it's, I think, 2027 is a year that we need to get our leverage down, and that's, I think, our board is on board with that, so it's It's basically we recognize that we are running a company today that at today's prices, looking at the end of the year, is 1.4 times leveraged, and we want to be at one times leverage. And, you know, if you think about that, the reason that we want to be at or below a turn of leverage is because we never know when something's going to happen. Like, you know, in the next few months, it might be a really good time to be buying a natural gas asset. I'd like to have our leverage back down to a point that we can use some debt to make a purchase before bringing that leverage back down through the equity market. So, yeah, we want to be at a point that we're less leveraged. So, as I mentioned, we have an ATM program that doesn't really affect our trading that will lower our leverage. We can always cut our distribution some. We did that in 2024, I believe, or 2025, 2024, where we amortized some of our distribution to pay down debt. Let's just say it's a focal point that I've talked about it now for nearly a year, I guess three quarters, and our leverage hasn't moved down yet. And so it's just time for us to get started here soon if we don't – what I'd love to do is find an acquisition that we could buy using equity, but there's just a lot of capital chasing a few deals right now.

We'll stay tuned on that. Thanks, Tom.

Thank you. Thank you. Our next questions come from the line of Derek Whitfield with Texas Capital. Please proceed with your questions.

Good morning, Tom and team, and thanks for your time. I wanted to circle back on your earlier comments on natural gas as you see it today. While I realize you can't provide 2027 guidance, we in most of the street likely have elevated gas-weighted CapEx for 2027, which inherently depresses your CAD at current strip. I think what we're all grappling with is how to manage activity as the current pivot favors oil-weighted activity and production into 2027. As we sit here today, should we think about higher activity in oil through the first half and some degree of shift to gas in the second half as a starting point? I mean, you clearly have the flexibility as you go to today to lean into oil or gas, but just that's kind of what we're grappling with.

Yeah, I think that's fair. So I think that basically we don't have the activity in our gas asset next year would be the main coast. So the activity would be that if we choose to spend money at 27 on natural gas, which right now we would plan on it, just assuming that prices pick up into the summertime, that we'd start our completion program sometime in late spring or the springtime. and then have a drilling program through the summer and then complete all those wells come in line with each other.

Yeah, that makes sense.

And then we haven't really worked on a 27 program yet. It's something that we're starting to work on now. So I think obviously by our next quarter call, we'll have a better understanding of where at least we plan to have our CapEx. and it is it's we aren't as easy to follow just because we change we can change both the amount we spend and on what asset we spend it on and it can happen very quickly so i i do understand but in every time that we make a change it's for a higher rate of return understood completely and we also appreciate that we can make changes in five minutes where it's going to take you guys

quite a bit longer with uh with the actual plans themselves so we appreciate it again just trying to kind of work through that because at the end of the day we should be solving for higher cad it just means it might counter depending on where we are with oil and gas at any any point in time but maybe staying on gas but going down a different path with the addition of several large pipelines in the permian including the hue brinson and black home this year how are you guys thinking about the outlook for san juan basis going into next year yeah i'm scared of san juan basis right now uh luckily we're you know we're fairly well hedged with our san juan gas but it's um

uh it's as we go into right now we're sitting what san juan and midcon are sitting 20 cents under the hub. It just seems pretty tight. So I just – I don't know where San Juan basis goes in the near term. I do believe that over a longer period of time that everything opens up. There's the Greenview pipeline that's being brought on by Tallgrass that's going to give us a 2.5 BCF a day. I think that's what they're projecting to the Arizona Pacific North Pacific Coast LNG markets coming in. They project 29 or 30. I think that might be fast tracked as demand is picking up. So I think over time the San Juan is going to be the key place For us, it's just we have to watch carefully what pricing is in order for our CapEx in the meantime. But as we just mentioned, in order to keep our production flat there, we only need five wells. So it is a tremendous amount of capital to keep our production flat. Or it isn't the end of the world if we let it decline, if we're increasing our oil production at a higher price in other places. So we're going to be very flexible, depending on what price gives us.

Great. Thanks for your time.

Thanks, Derek.

Thank you. Our next questions come from the line of Jeff Gramp with Northland Capital Markets. Please proceed with your questions.

Thanks for the time. Tom, your comments on the Mancos well cost, I thought, were really interesting. I think you mentioned $20 million historically. You guys think you can get down to $13 million on this recent batch. And I know in the past you talked about, like, adjusting the completion design was a key lever there, but it seems like there's a lot going on to get that kind of reduction. So I was just hoping to better understand what you guys are seeing there to drive that kind of cost improvement.

Yeah, it's really more just getting services, having different types of like using wet sand versus dry sand, having being comfortable with a couple thousand pounds per foot of frack, which we used last year, and it works perfectly fine. learning some of the a few drilling techniques uh i mean rick could do a lot better job than me explaining i i all i could do is look at the results and see that we're going to be closer to 13 million than than the 15 we projected and the 20 million historically so uh it's to me the main coast is is much like the haynesville is that the haynesville started out with very high well costs and over time in their core area they were able to bring those down and ultimately make the field have a rate of return and that's basically the story of the main coast as you we started out with an incredibly high well cost in in the field that are now being brought down Rick do you want to mention anything about how costs are coming yeah as far as service costs they're they're still in line but we're optimizing our drilling performance and And being able to get reduced over all days, drilling is the main thing we've been able to change. Bringing some new vendors in, obviously, has helped reduce costs as well. Yeah, our savings have basically been both on drilling and completion, but the completion costs have really come down.

I appreciate those details. And my follow-up, given kind of the pace of development that you're laying out, Tom, you know, obviously focused on the oil side, Assuming that kind of program remains static, would you guys anticipate oil production growth in 27? Is this more kind of a maintenance level of capital that we're at there, just trying to kind of triangulate where oil might go over the next handful of quarters?

Yeah, I think it's difficult for us to have too much growth in any of our products because basically we're only spending 50% of our cash flow to keep our production flattish. I think that overall it's easier to grow a natural gas stream, especially if you're drilling $25 or $30 million a day mancos wells. But I'd say our projection at the 27 is basically keeping it flat.

Okay, great. I appreciate the details. Thanks, guys. Thank you.

Thank you. Our next questions come from the line of Tim Resvin with KeyBank Capital Markets. Please proceed with your questions.

Good morning, everybody. Thank you for taking our questions. I just wanted to go back to the balance sheet. I just had one here. Tom, you know, we see the same thing in our model that you do in yours, that around 1.4 times a year end. We do see sort of it kind of grinding down, if you think about strip pricing, into 2027, you know, kind of near a spitting distance of one times at the end of the year. So my question is, if it's such a pressing concern, and I appreciate you being candid about that, are you looking at asset sales? You have a vast acreage footprint. Are you looking at other things like, you know, getting someone to sort of farm into your acreage or some sort of carry? Just kind of curious kind of how broadly you're thinking about options to accelerate that deleveraging.

Yeah, so, I mean, selling assets are difficult because you're losing cash flow. And if you're – let's just say you're a little – not caring for the gas market in the near term, I hate to get rid of low-declined gas assets whenever I believe higher gas prices are around the corner. And so the – and you really don't want to be selling your high-priced oil assets either. So, to me, it's difficult to sell assets, to manage for it, especially when we want to keep our declines low. Let's see. The second part of your question was what else were we thinking about? So, that was the sell assets. What was your other question or point of it?

I would just ask, you know, are you looking to kind of, you know, get someone to farm into acreage, get some sort of carry, you know, just – Yeah, I'm with you now.

So the problem with selling acreage is that it's – you'd love to say it's non-core, but every acre we have today was non-core when we bought it. So – and yet if you look at our results, you see that we're in the top – the top of the piers for gas and oil. And so if you look at any well that we've drilled since inception of the company, we didn't pay for. So that was, by definition, a non-core acreage. And so whenever we plan to go sell a bunch of non-core acreage, you might be selling the next best field. And, you know, as Charles mentioned, we're not going to be the guy who goes out and drills the wildcat, But we're going to have three million acres kind of hanging around to be to look at whenever somebody else does. And so today we have a lot of different companies, Muburn especially, is opening up areas that no one would have ever believed in the Midcon just a couple of years ago. You have Continental that stretches all the way from western Oklahoma to southern Oklahoma, drilling very good wells. and now the Diversified has the Camino asset and just a lot of activity with Flywheel and others in the Midcom. They're developing acreage that, if you would have asked me last year, we'd say was non-core, and if we were in that mode of selling it, we'd have given away the ability to have the high rates of return we do today. So that's a long-winded way to say, I don't really like to sell acreage either. And so selling away your assets to me is not as efficient as if we were to cut a distribution a little.

Okay. Okay. I guess there's trade-offs to everything, but okay. I appreciate that response. Thank you. That's all I had. Thank you.

Thank you, ladies and gentlemen. We have reached the end of our question and answer session. And with that, I would like to bring the call to a close. We appreciate your participation today. You may disconnect your lines at this time, and have a great weekend.