Equity Commonwealth

Good morning, everyone. Thank you for joining today's call to discuss Mock Natural Resources' first 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 their SEC filings. For 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 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 Mock's website, and their 10Q, 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 Mock's financial results, and then the call will be opened for questions. With that, I will turn the call over to Mr. Tom Ward. Tom?

Thank you, Darrell. Welcome to Mock Natural Resources' first 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 to EBITDA ratio of one time or less. By maintaining a low leverage profile, we give ourselves opportunities when markets experience high volatility. Number two, disciplined execution. We acquire only cash flowing assets at a discount to PDP PB10 that are accretive to our distribution. 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. Number four, maximize cash distributions. We target peer leading variable distributions. This pillar drives all of our decisions. I'd like to add additional color to each of the four pillars. Maintain financial strength. During the first quarter, we saw significant progress on reducing our already low leverage. We completed the refinancing of our debt, repaying $763 million on our term note, using proceeds from our new credit facility, our recent equity offering, along with cash from our balance sheet. We exited the quarter with $460 million drawn on our new credit facility, which reduced our net debt to EBITDA ratio from 1.0 times at year end 2024 to 0.7 times at the end of Q1. The refinancing of our debt provides significant savings, lowering our projected interest expense for 2025 by $22 million, while also eliminating quarterly amortization payments of $21 million. These savings will ultimately manifest themselves through higher free cash flow and our ability to enhance distributions to our unit holders. We focus on maintaining financial strength in order for our company to be successful through various commodity cycles. The current market environment is challenging, with oil prices recently dipping in the 50s for the first time since early 2021, reflecting trade policy uncertainties and indications from OPEC Plus on increased production. However, markets positioned well from a natural gas perspective with our volume mix being 54% natural gas, 23% in GLs, and 23% oil projected in 2025. In fact, if we move to three rigs in Q4 from a projected two rigs in Q3 to the more natural gas-weighted deep and arco basin, we will grow our natural gas production at the expense of our oil volume in 2025, but keep our overall barrel equivalent basically flat. However, in 2026, we will experience double-digit growth on the back of the additional gas drilling. We believe the deep Anadarko will be an exceptional area to drill for natural gas. The trick is to do this while keeping our reinvestment rate below 50% of operating cash flow. We project moving out of the Oswego drilling as of early June and down to two rigs during during Q3 2025 with one deep rig in the deep in the deep gas area of Anadarko Basin and the other drilling red fork wells in western Oklahoma. We then project to move to three rigs in Q4 by adding a second deep gas rig. If it appears that we need to delay that rig until Q1 26 in order to meet our reinvestment rate of 50%, we will do so. As I mentioned, the increased drilling activity in the deep end ARCO is predicated on keeping our investment rate below 50% of our operating cash flow. Our plan is to add operating cash flow during this down cycle and crude through an acquisition accretive to our distribution and giving us cash flow to enhance our drilling budget during 2026. MOC is unique in that we have the ability to utilize our over 2 million acreage inventory to change our drilling mix from one year ago when we drilled Oswego and stacked condensate wells to a completely different set of wells to maximize our return on capital invested. Disciplined execution. Our second pillar, disciplined execution, has always meant being prudent in how we acquire assets. Our strategy since the company's outset has been to purchase cash flowing properties at bargain prices while paying little to nothing on the associated acreage and infrastructure. In January, we closed on a $30 million acquisition that fit our specific criteria and plan to begin exploiting that future drilling opportunities on its associated acreage. However, With the drop in crude prices, we have delayed drilling in the Ardmore Basin in favor of natural gas drilling. Our large inventory and associated drilling opportunities are only hampered by keeping our reinvestment rate under 50%, which is why we are always intently focused on acquisitions of cash flowing properties that can accelerate our development plans. The XTO acquisition now gives us another million acres to have an inventory to use when needed. In fact, We will move a rig onto our newly acquired XTO acreage in June 2025 during Red Fork Wells. The XTO acquisition is very unique given the huge acreage footprint across northwest Oklahoma and western Kansas. This extra million acres also came to us free of cost while maintaining our stated purpose of buying cash flowing assets at discounts to PDP PV10. Disciplined reinvestment rate. Our third pillar of maintaining a disciplined reinvestment rate focuses on spending only 50% of our cash flow on our development costs, allowing us to optimize our distributions to our unit holders. The development of our inventory is focused on stabilizing our production decline and bolstering our bottom line through high rate of return projects, typically of at least 50%. Our expectation for 2025 is to spend between $260 million and $280 million. Please remember that our CapEx program is fungible and depends on our success for adding additional operating cash flow to keep our reinvestment rate in check. Our change in drilling is due to natural gas prices moving up while oil prices have fallen. In a $70 environment, we would like to have at least one rig running in our Oswego program that delivered actualized 66% returns in 2024. This field is a hallmark of MOC where we have drilled more than 225 wells since 2021. For example, our Oswego DNC cost in 2024 averaged only $2.6 million or $202 per lateral foot. We achieved medium payout periods of 15 months, assuming a flat $70 WTI and 350 Henry Hub price. According to Inverus, this compares to 14 months in the Core Delaware and 15 months in the Core Midland Basins, where purchasing locations can cost more than $10 million each. All of these statistics add up to unmatched cash returns for our unit holders over the last five years and the next five years. However, It is prudent to take our first pause in the Oswego program until crude prices recover and not waste this valuable resource when natural gas locations provide superior rates of return. We eagerly await adding an Oswego rig when crude prices recover. The Woodward Condensate and Ardmore Basin locations are also on hold until crude prices rise to a point where they compete with natural gas drilling in the deep Anadarko. MOC is in an enviable position. of having too many good locations to drill, thus the need to increase our operating cash flow during a time of lower crude prices. Suffice it to say, we are on the hunt for cash flowing PDP assets to be able to drill more in the mid-con. Maximizing distributions. Our fourth pillar is one that drives all of our decisions, maximizing distributions. We are disciplined in our execution and capital strategy, and by reinvesting 50%, into our development program, we leave significant amounts of cash available for distribution that can be passed on to unit holders through our quarterly distributions. These quarterly distributions are variable and will rise and fall with changes in pricing. However, we are proactive in managing our risk where possible and had 50% of oil and natural gas production on a rolling one-year basis and 25% during the second year. Over the next 12 months, our hedge volumes are an average price of $69.31 for oil and $3.77 for gas. Our distribution-focused approach has been rewarding to our owners. We have distributed over $1 billion back to unit holders since our inception. Our upcoming distribution of 79 cents per unit results in an LTM yield of 20%. Mock's cash return on capital invested over the last five years is 32%. These industry-leading cash returns have been facilitated through a series of opportunistic acquisitions of cash-flowing properties throughout a variety of commodity cycles. We continue to see success in buying mid-con assets, with our most recent acquisition closing just last week. The $60 million XTO acquisition fits perfectly with what we have done since inception of the company in 2017. We found an asset that delivers free cash flow while also giving us free land to develop at a distressed purchase price. The XCO acquisition is primarily natural gas with a mix of production of 79% natural gas, 7% NGLs, and 14% oil. We continue to see the best value in acquisitions that are at or below $100 million, but they do add up. We were already approaching $100 million of acquisitions in 2025. We made 21 acquisitions and have spent just over $2 billion since early 2018. This approach is important because we stay away from large, well-capitalized competitors to buy assets that are less expensive. This formula has served us well. During this period of uncertainty in crude markets, we would also like to find a larger acquisition that continues to fit our basic business model. We believe that if crude prices remain under $60 for very long, we'll have the opportunity for a seller to merge into a larger, well-capitalized company. This type of acquisition will allow us to expand our operating cash flow and maintain a robust drilling schedule on the more than 2 million acres of land that we have held by production. The key to any acquisition is that it must be accretive to our distribution. MOC is off to a solid start in 2025. We've averaged total net production of 80.9 in BOE per day, even though we only use 37% of our operating cash flow during the quarter. This did result in a lower oil volume than we projected due to deferring drilling in the Ardmore Basin that we projected to start in Q1. Our lease operating costs remain low at $6.69 per BOE, and we expect that to continue into Q2 with the acquisition of the XCO assets. In the 21 acquisitions that we have made, we have averaged approximately a 30% decrease in LOE. We expect the same in this acquisition. Markets change, and the most successful companies need to be able to react to change quickly. I want to reemphasize that Mock is an acquisition company. Our industry-leading cash returns have been made through opportunistic acquisitions. This is our primary lever of growth. Our expectation is to continue making acquisitions that are accretive to our distribution in 2025, just as we have over the last seven years in 21 deals. Mock has a peer-leading PDP decline and reinvestment rate. Our next 12-month PDP decline is projected to be 20%, while our reinvestment rate in 2024 was only 47%. Both of these statistics are number one in a group of 16 peer companies. We have exceptionally strong asset coverage with total approved coverage of 3.9 times, net debt to enterprise value of 21%, and PDP PV10 to total debt of 3.3 times. Our LOE averaged $6.69 per BOE in Q1 2025, and our 2024 free cash flow was $8.43 per BOE. We also have moved our net debt EBITDA down to 0.7 times. In short, MOC is in perfect position to grow during a time of unease in our industry. Over the past seven years, our very best acquisitions have come when oil prices were down. In fact, we bought Alta Mesa through a 363 bankruptcy process in 2020 when oil was at $20 per barrel. I do not know how long OPEC Plus will increase production or how long the trade war will continue or if we'll go into a global recession. But I do know that if we keep our balance sheet strong and stick to our four pillars, that we can weather any storm and can build an even stronger foundation for the future when prices rebound. I also believe that prices ultimately do rebound as the world looks to the U.S. to provide stability and energy to the 7 billion people striving to be as wealthy as the lucky 1 billion of us. I'll now turn the call over to Kevin to discuss our financial results.

Thanks, Tom. For the quarter, our production of 81,000 BOE per day was 24% oil, 53% natural gas, and 23% NGLs. Our average realized prices were $70.75 per barrel of oil, $3.56 per MCF of gas, and $27.33 per barrel of NGLs. Of the $253 million total oil and gas revenues, the relative contribution for oil was 49%, 33% for gas and 18% for NGLs. On the expense side, our lease operating expense of $49 million was equivalent to $669 per barrel. Cash G&A was slightly less than $9 million, resulting in about $1.20 per BOE. We ended the quarter with $8 million in cash, $460 million drawn on the $750 million revolver. As of today, after closing the XTO acquisition, we have $530 million drawn on the RBL. Total revenues, including our hedges and midstream activities, total $227 million. Adjusted EBITDA of $160 million and $143 million of operating cash flow. After the development capex of $52 million, which was 37% of the operating cash flow, we generated over $94 million of cash available for distribution, resulting in an approved distribution of 79 cents per unit, which will be paid out on June 5th to record holders as of May 22nd. And with that brief overview, Darrell, I'll turn the call back to you to open up the call for questions.

Thank you. We will now be conducting the 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 yourself 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, for your first question. Our first questions come from the line of Charles Mead with Johnson Rice. Please proceed with your questions.

Good morning, Tom and Kevin and the rest of the mock team there. Good morning. Tom, I want to ask about this acquisition. I have to say, in some ways, this slide 13 that you have here, it's stunning. And I feel like maybe you're being a bit coy about this, and I'm trying to figure out Is it because this is a... I mean, you've doubled the acreage position of the company with a $60 million deal. I just want to try to get you to see if you're willing to talk a little bit more about... I think you gave us the production split, but the total production, the total production, the EBITDA from the asset base, and also... It looks to me that obviously you've got some great Anadarko Basin stuff here, but it looks to me like you've picked up a big chunk of the Yucatan field there. So could you just talk more about it?

Sure. It's a small acquisition, so 1,600 BOE a day. So it's not that it produces so much. It does carry, as you said, a lot of acreage. So 85% is in the greater Anadarko Basin. 38% of that greater Andarco Basin is in the Hugaton, so southwest Kansas, Texas, Cimarron, and Beaver Counties of Oklahoma. 34% is in Major County, Oklahoma. So that's more northwest Oklahoma, southwest Kansas. 7% in Elk City, which is deep Andarco, Beckham, and Washtenaw Counties. 6% in Woodward, Woods, and Ellis, so more northwest Oklahoma. And then 15% in a frontier play that's been producing for years in Wyoming in the Green River Basin. So that consists of, so if you have, that comes with 1400 operated wells. So a lot of wells, 500 non-operated wells, 1100 royalty only wells. And then as you mentioned, 990,000 net acres across 40% in Oklahoma, 57% in Kansas. and 3% in Wyoming. So it's not, I don't think people would look at this and say it's in the heart of the Anadarko Basin or it's not like buying core Permian or Eagleford assets, but I can guarantee you the acreage isn't worthless. So you get a million acres of land. We already have proposals being brought up to us do reworks and drill new wells in southwest Kansas. We're planning to drill some wells in northwest Oklahoma. And for $60 million, it just seems like a good deal. And that's why I believe it is a good deal. The ability for our team in the Andarco Basin in southwest Kansas, we already have teams in place. I think we'll do a good job of lowering LOE. The asset I don't think has been worked as hard as maybe we'll take a look at it. And so I think we'll increase production and be able to make this a very good acquisition. But keeping in mind, it is a pretty small amount in our overall company. So it's not going to move the needle tremendously. But if we keep on doing these types of acquisitions, they add up. And that's what we've done since 2018. This is the type of deal that we've made over and over and over again that just slowly builds a company. And there's a reason that we can stay at a 50% reinvestment rate and still keep our production flattish. It's not easy to do, and most don't. So it takes a rare company to be able to do that. I think this is just an example of why we can and why we are able to do what we do. It's not going to change our company dramatically, but really very few. Outside of Paloma, there's very few deals that have. And so I just look at it as another good acquisition in the line of hopefully many more to come.

Got it. That's helpful, Tom. And then if I could go back to your prepared comments when you were talking about the optionality or, you the leverage you have to stay under that 50% cap. I believe I heard that you said you'd drop your third rig if you needed to to stay below 50, and that would probably be on an oily asset. Did I understand that correctly?

Yeah, so we're at four rigs today. Two of those are leaving in June, the first part of June. So basically, say, June 1st. the two Oswego rigs will be leaving. Okay, that leaves us with two rigs running, one in the Woodford condensate and one in the deep gas area of the Anadarko Basin. And the deep gas area we talked about, the reason we clarified as deep gas is these are 15,000 feet TBD, 15,000 foot laterals. So very deep, very long laterals. And they take more capital, obviously, to drill. And so that what we but with that we get with the highest rates of return we can have in our company or in that area. So what we plan to do then is move post June will be at two rigs and the Woodford condensate as of today is going to move to the Red Fork Sands area starting in Major County working down through Custer. That leaves the second rig and then we'll Right now we project to add a third rig back to the deep gas area of the Anadarko Basin in basically September, October.

Got it. Thank you for straightening me out on that.

I'm sorry, it's all predicated on staying below a 50% reinvestment rate. And so we've done that in the past. And also you should know that the first quarter we only spent 37% of our reinvestment rate. We still project that we'll spend closer to 50% in the overall 2025. So we look at our reinvestment rate on a yearly basis, not a quarterly basis.

Got it. Thank you for all that detail, Tom.

You bet.

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

Good morning, all, and thanks for your time and great acquisition.

Thank you.

Maybe going back to Charles' point, just on the shift in development activity, I wanted to lean in on your prepared comments on the Oswego. While there are a few variables at play, including oil-to-gas ratio and service prices, is there a foreign oil-to-gas ratio that we should think about that drives more gas versus oil development, or is it simply 70 for the Oswego?

Yeah, it's just the Oswego's 80% oil reservoir. And it's a superior oil reservoir than any place I've drilled. But it is limited in how much gas we can get out of it. And so anytime you have this tremendous move with gas going up and oil going down, the rates of return just move away from being able to drill Oswego's. we can still have a good rate of return today in the Oswego. Last year, it was 66% IRRs, and we could still be north of 30% right now. However, we target at least 50% rates of return in order to drill, and the other areas we're looking at are at that or higher, and the Oswego's not. So that is just a very simple rate of return-driven decision. If we had more operating cash flow, we would probably add rigs either more into natural gas or be flexible in being able to move back and forth. The other thing that our operating team does very good at, is very good at, is keeping our rig cadence in a place where we're only 30 days out from being able to move rigs around. So we can release a rig in a month's notice and go to a different area. And I think that's very important for us to maintain that. I don't know if that answered your question or not.

It did. So thanks for the clarity there. And then, again, we're making these changes here on the fly this morning with our model. But it does appear full year guidance for oil remains intact based on Q1 string. And on our numbers, it looks like there could be some upside on the BOE side based on productivity changes. that we're seeing as deep misdevelopment, not necessarily your wells today, but what we've seen across industry. Is that kind of the fair way to think about it? I know that you talked about 2026 being more upside to gas, but these are highly prolific wells that you guys are bringing on.

Yeah, I think this, Kevin, Derek, I think that is a solid way to look at it, yeah.

In 2026, our gas production just grows fairly dramatically. if we can put two rigs to work in the deep end of Dark Hill. Thanks, guys. I think that play is just getting started. I think you'll see others joining us very quickly.

Perfect. Thanks, guys.

You bet.

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

Good morning, Tom. Good morning, Kevin. I want to see if you could talk about the turning lines you had in the first quarter. It looked like about nine operated wells there. Were those all Oswego, or do you have a breakout of those wells?

Somebody had a breakout. So it's seven Oswegos, and the other two were Woodford condensate. Okay.

So no results in the deep Anadarko yet. I guess, can you talk about... No, no.

The first well is being drilled right now in the vertical section.

Gotcha. And can you talk about what you're expecting there in terms of well costs and recoveries?

Oh, sure. The wells are expensive. They'll cost around $13 million. We think we can find, basically, 5 BCF a section, and we're going to have rates return north of 50%. Great.

And if you do keep that second rig.

And, Mike, those are three-mile laterals, so 15,000 feet of lateral length. Right.

And if you do keep that second rig.

The risk to the play I don't think is the gas. The gas is in place. The risk will be costs. And so we have to watch closely what inflation does, where gas prices are. There's a reason that this gas has always been known to be there. So deep and dark gas is nothing new. It's that Oklahoma has never really been explored horizontally for natural gas, where the gas is, because gas prices since 2008 have basically been a price that you couldn't explore for it. So there's a tremendous amount of natural gas left to be discovered or brought online. It's actually been discovered in Western Oklahoma, and it has good access to marketing to get to the hub. So it's a great place to drill if prices are right. You give me a 350 strip, we can bring you... You give me a 350 strip, we'll bring you the gas.

I just wanted to see a follow-up to that. You talked about how it would set up 2026 to where you'd basically grow your gas volumes at the expense of oil. Could you get maybe a little bit more specific? If you do keep that second rig active in the fourth quarter, what could your production mix look like next year? You said it was 54% right now gas. What might that look like for 2026?

Yeah, we'll be growing, I guess, basically over 20%. And crude oil would be falling basically in 26 by less than 10%.

Okay, great. Thank you, Tom. Thank you.

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

Good morning, guys. Very nice position. I just want to follow up, Tom, on one point you said earlier regarding the reinvestment rate. So just to be clear, because that really low reinvestment rate you had in 1Q, at the current strip, your reinvestment rate on the current plan, we'll call it 270 million at the midpoint of the CapEx, that would still be at about a 50% reinvestment rate, is that right?

That's correct.

Okay, so the oil strip would have to weaken from here for you to not add that second rig that was going to go to the deep gas.

Or the gas strip.

Or the gas strip, yeah, yeah, exactly. Perfect. And then on the M&A topic, I know last quarter you talked about how you'd love to buy oil assets if oil was in the 60s or lower. And you talked about on this call really wanting to look at some larger deals. Just maybe talk to, I would imagine in this volatile market, the bid-ask spreads are pretty wide. Maybe you can just speak to that. Do we have to be at this kind of level oil price for a while for those spreads to narrow, just what you're seeing.

Yeah, and, you know, we're usually not the seller or the buyer of choice for a seller. There probably needs to have been a failed process of some kind in order to get down to a place to where, you know, you have a distressed sale. So I think it does take time. And it's really nothing new. We always are on the look for larger deals that would bring – we could use equity here to bring in and increase our distribution per unit. It's really not a new concept. It just is – it seems like we're getting closer in areas outside of the mid-con than we have in the past. We've been the high bid on a couple of – deals that did not transact because the seller chose to pull them. But I can tell you that in the Eagleford or the Permian, in the past, we've never been the high bid. So, you know, things are moving our way. And just because you're close to the core Permian doesn't mean you're in it. And just because you're close to the core Eagleford doesn't mean you're in it. And that doesn't mean you can always have the amount, just because it has that zip code doesn't mean that it brings the same as those other type of assets. Those are the type of assets we'll look for.

Thanks, Tom. Nice quarter.

Thank you.

Thank you. Our next questions come from the line of Jeff Jay with Daniel Energy Partners. Please proceed with your questions.

Hi, guys. I'm just curious. know given the cost of the deep anadarko wells sort of where where does the strip need to be for you to add that second rig in other words where do you feel like the rate of return becomes less attractive at what at what gas price yeah i think jeff that if we stay above a 350 strip uh it just it's really more about operating cash flow so the wells are going to have plenty of rate of return

It's just that we have stipulated that we can't go over a 50% reinvestment rate. That's what I want as an investor, and I think that's what makes us unique. And it just keeps us from being able to meet all the locations we have. So I don't think it's going to be – if gas prices stay anywhere near where they are today or even fell, the project would be fine. It's that we don't have enough operating cash flow to do both.

Got it. And then I'd be remiss if I didn't ask if you're incrementally more bullish or less bullish on natural gas for the remainder of this year.

Then last quarter, I'd say less bullish. I think that we are in a period of time through the summer, the refill season, that we're still kind of a half a BCF or so tight. I think that the timing as we come into the fall and winter of the two pipes that are coming on in the Hainesville or can get Hainesville gas out, that you have LNG demand kind of front-running that. But then I see, at least from our perspective, is that we have a pretty balanced 2026 demand. And so then you tell me if we're going to go into recession or you have demand from any number of areas that demand is changed through, I guess, the political system that we're going through. So it just is, I don't know. I would look, though, at, I guess, probably for the first time since we've started doing these calls, I see natural gases got fairly balanced in the year out instead of being extremely bullish.

Right. Well, that's helpful. Thanks, Tom.

Thank you, Jeff.

Thank you. Our next question has come from the line of Salman Akyal with Stifel. Please proceed with your questions.

Hi. Good morning. This is Tim . Congrats on the quarter and the acquisition. Going back to the acquisition, you guys mentioned, well, in the PowerPoint, there was some midstream and other infrastructure. Just wondering, kind of, is this mostly within the MidCon or is some of this also up in Wyoming?

No, it's really in the midstream is in the Ringwood Field in Major County, Oklahoma, and then at Hugaton Basin. So the but I mean they're very small so really doesn't add too much to the to the overall project.

OK, got it. I was just curious on potentially lowering some costs there and then. For lease operating expense, the the queue had called out some higher costs related to saltwater disposal. Just curious what you guys are broadly seeing. on the waterfront in the MidCon or if this was more of a one-off item?

Yeah, this is Rick. I would say stepping outside of where we have infrastructure going and drilling, you know, the Anadarko Basin, we do have infrastructure there, but it's third party. So our costs have gone up some there compared to drilling within our Oswego area. So that would be the thought there.

Got it.

Thank you guys for the time. Thank you. Thank you. 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 do appreciate your participation today. You may now disconnect your lines. Enjoy the rest of your day.