Mach Natural Resources LP

NYSE:MNR

Q1-2025 Earnings Call

[Operator]

Good morning, everyone. Thank you for joining today's call to discuss MACH 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 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, we 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 will turn the call over to Mr. Tom Ward, Tom?

[Tom Ward, executive]

Thank you, Darrel. Welcome to Mach Natural Resources first quarter earnings update. Each quarter, it is important to reiterate the company's 4 strategic pillars. These are: number one, maintain financial strength. Our goal is to have a long-term debt-to-EBITDA ratio of 1x or less. By maintaining a low leverage profile, we give ourselves opportunities when markets experience high volatility. Number two, disciplined execution. We acquire only cash flowing assets at a discount to PDP PV-10 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 unitholders. 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 4 pillars: maintain financial strength. During the first quarter, we saw a 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 1.0x year-end 2024 to 0.7x 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 unitholders. 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+ on increased production. However, Mach is positioned well from a natural gas perspective with our volume mix, being 54% natural gas, 23% NGLs and 23% oil projected in 2025.

In fact, if we move to 3 rigs in Q4 from the projected 2 rigs in Q3 to the more natural gas weighted deep Anadarko basin. We will grow our natural gas production at the expense of our oil volume in 2025, but keep our overall barrel oil 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 2 rigs during Q3 2025 and with 1 deep rig in the gas area of Anadarko Basin and the other drilling Redford wells in Western Oklahoma. We then project to move to 3 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 Anadarko 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 in crude through an acquisition accretive to our distribution and giving us cash flow to enhance our drilling budget during 2026. Mach is unique in that we have the ability to utilize over our over 2 million acreage inventory to change our drilling mix from 1 year ago when we drilled Oswego and STACK condensate well 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 1 million acres to have an inventory to use when needed.

In fact, we will move a rig on to our newly acquired XTO acreage in June 2025 drilling Red Fork wells. The XTO acquisition is very unique given a huge acreage footprint across Northwest Oklahoma and Western Kansas. This extra 1 million acres also came to us free of cost while maintaining our stated purpose of buying cash-flowing assets at discounts to PDP PV-10.

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 unitholders. 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 of 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 1 rig running in our Oswego program that delivered actualized 66% returns in 2024. This field is a hallmark of Mach, where we have drilled more than 225 wells since 2021. For example, our Oswego D&C costs in 2024 averaged only $2.6 million or $202 per lateral foot.

We achieved median payout periods of 15 months, assuming a flat $70 WTI and $3.50 Henry Hub price. According to Invest, 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 unitholders over the last 5 years and the next 5 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 Woodford 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.

Mach 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 flow and 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 unitholders 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 1-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 unitholders since our inception. Our upcoming distribution of $0.79 per unit results in an LTM yield of 20%.

Mach's cash return on capital invested over the last 5 years is 32%. These industry-leading cash returns have been facilitated through a series of opportunistic acquisitions of cash flow and properties throughout a variety of commodity cycles.

We continue to see success in buying Midtown 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 XTO 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 are already approaching $100 million of acquisitions in 2025. We made 21 acquisitions that 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'd 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, will have the opportunity for us 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. Mach is off to a solid start in 2025 and we've averaged total net production of 80.9 MBoe per day, even though we only used 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 cost remained low at $6.69 per BOE, and we expect that to continue into Q2 with the acquisition of the XTO assets. In the 21 acquisitions 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 Mach 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 7 years in 21 deals.

Mach has a peer-leading PDP decline and reinvestment rate. Our next 12-month PDP decline is projected to be 20%, while reinvestment rate in 2024 was only 47%, both of these statistics are #1 in a group of 16 peer companies. We have exceptionally strong asset coverage with total proved coverage of 3.9x net debt to enterprise value of 21% and PDP PV-10 to total debt of 3.3x.

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 to EBITDA down to 0.7x. In short, Mach is in perfect position to grow during a time of unease in our industry. Over the past 7 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 a 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 4 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.

[Kevin White, executive]

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 356 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% and 33% for gas and 18% for NGLs. On the expense side, our lease operating expense of $49 million was equivalent to $6.69 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 totaled $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 $0.79 per unit, which will be paid out on June 5 to record holders as of May 22. And with that brief overview, Darrel, I'll turn the call back to you to open up the call for questions.

[Operator]

[Operator Instructions]

Our first questions come from the line of Charles Meade with Johnson Rice.

[Charles Meade, analyst]

Tom and Kevin and the rest of the Mach team there. Tom, I want to ask about this acquisition. I have to say, in some ways, it's the 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've just -- what I 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 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 Hugoton field there. So could you just talk more about it?

[Tom Ward, executive]

Sure. It's a small acquisition. So what 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% is of that greater Anadarko basins in the Hugoton, so Southwest Kansas, Texas, Simran and Beaver Counties of Oklahoma. 34% in Major County, Oklahoma. So that's more Northwest Oklahoma, Southwest Kansas, 7% in Elk City, which is deep Anadarko, Bachand WastaCounties, 6% in Woodward, Woods and Alice more Northwest Oklahoma, and then 15% in a frontier play that's been producing for years in owing in the Green River Basin.

So that consists -- so if you -- that comes with 1,400 operated wells, so a lot of wells, 500 nonoperated wells, 1,100 Royalty-only well. 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 buying core Permian or Eagle Ford assets, but I can guarantee you the acreage isn't worthless.

So you get 1 million acres of land. We already have proposals being brought up to us to 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 Anadarko 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 Coloma, there's very few deals that have. And so I just look at another good acquisition in the line of, hopefully, many more to come.

[Charles Meade, analyst]

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 the levers you have to stay under that 50% cap. I believe I heard that you said you dropped 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?

[Tom Ward, executive]

Yes. So we're going to -- we're at 4 rigs today, those -- 2 of those are leaving in June, the first part of June. So basically, say, June 1, the 2 Oswego rigs will be leaving. Okay. That leaves us with 2 rigs running, 1 in the Woodford condensate and 1 in the deep gas area of the Anadarko Basin.

And the deep gas area, we talked -- the reason we've clarified is deep gas is, these are 15,000 feet TVD, 15,000-foot laterals. So very deep, very long laterals and they take more capital, obviously, to drill. And so that's 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, we'll be at 2 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 gas area of the Anadarko Basin in the -- basically September, October.

But that all is -- 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 note 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.

[Operator]

Our next questions come from the line of Derrick Whitfield with Texas Capital.

[Derrick Whitfield, analyst]

Thanks for your time and great acquisition. 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 forward oil to gas ratio that we should think about that drive more gas versus oil development? Or is it simply 70 for the Oswego.

[Tom Ward, executive]

Yes. It's just the Oswego reservoir. And it's a superior reservoir than any place I've drilled, but it is limited in how much gas we can get out of it. And so any time 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 off. We can still have a good rate of return today in the Oswego. Last year, it was 66% IRR and we could still be north of 30% right now.

However, we can -- we target at least 50% rates of return in order to drill. And the other areas we're looking at are at that are higher and the goes 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 in the natural gas or be flexible on being able to move back and forth.

The other thing that our operating team does very good -- 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.

[Derrick Whitfield, analyst]

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 well remains intact based on Q1 strength. And on our numbers, it looks like there could be some upside on the BOE side based on productivity that we're seeing in the deepness development, not necessarily your wells today, but what we've seen across the industry. Is that kind of a 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 reading on.

[Kevin White, executive]

Yes. I think -- this is Kevin. Derrick. I think that is a solid way to look at it.

[Tom Ward, executive]

In 2026, our gas production just grows fairly dramatically. if we can put 2 rigs to work in the deep Anadarko. just getting out. I think that place is just getting started. I think you'll see others joining us very quickly.

[Operator]

Our next questions come from the line of Michael Scialla with Stephens.

[Michael Scialla, analyst]

I want to see if you could talk about the turn in lines you had in the first quarter, it looked like about 9 operated wells there. Were those all Oswego or do you have a breakout of those wells?

[Tom Ward, executive]

So we have a breakout so it's 7 and that to the other 2 were Woodford condensate.

[Michael Scialla, analyst]

Okay. So no results in deep Anadarko yet. I guess, can you talk about what you.

[Tom Ward, executive]

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

[Michael Scialla, analyst]

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

[Tom Ward, executive]

Sure. The wells are expensive, the cost around in, we think we can find basically 5 Bcf a section, and we're going to have rates to return north of 50%.

[Michael Scialla, analyst]

Great. And if you do keep that

[Tom Ward, executive]

Those are 3-mile laterals. So 15,000 feet of lateral late.

If you do keep that the risk to the play, I don't think is the gas. The gas is in place. The risk will be cost. And so we have to watch closely what inflation does what -- where gas prices are. There's a reason that this gas has always been known to be there. So deep 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 $50 strip, we'll bring you to the gas.

[Michael Scialla, analyst]

I just wanted to see if a follow-up to that, if you could 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?

[Tom Ward, executive]

Yes. We'll be growing gas and -- so basically over 20%, and crude oil would be falling basically in '26, but less than 10%.

[Operator]

Our next questions come from the line of John Freeman with Raymond James.

[John Freeman, analyst]

Very nice acquisition. I just want to follow up, Tom, on 1 point you said earlier regarding the reinvestment rate. So just to be clear, because the 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 that would still be at about a 50% reinvestment rate? Is that right?

[Tom Ward, executive]

That's correct.

[John Freeman, analyst]

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

[Tom Ward, executive]

or the gas strip.

[John Freeman, analyst]

Yes, yes, exactly. Perfect. And then on the M&A topic, I mean, 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 -- I would imagine in this volatile market, the bid-out 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?

[Tom Ward, executive]

Yes. We're usually not the seller of the buyer of choice for a seller. There probably needs to be a fill process of some kind that in order to get down to a place to where you have a distressed sale, so I think it does take time, and it's really nothing new. We always draw on the look for larger deals that would bring -- we could use equity here to bring in and increase our distribution per unit.

So 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 in 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 Eagle Ford or the Permian, in the past, we've never been the high bid. So things are moving our way. And just because of you're close to the core Permian doesn't mean you're in it and just because you're close to the core Eagle Ford doesn't mean you're at 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.

[Operator]

Our next questions come from the line of Geoff Jay with Daniel Energy Partners.

[Geoff Jay, analyst]

I'm just curious, given the cost of the deep Anadarko wells sort of where -- what 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 and what gas price?

[Tom Ward, executive]

Yes. I think, Geoff , that if we stay above the 350 strip, 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 50% reinvestment rate. So 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 -- we don't have enough operating cash flow to do both.

[Geoff Jay, analyst]

Got it. SP-35 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 in this year.

[Tom Ward, executive]

Then last quarter, I'd say, less bullish. I think that we are in a period of time through the summer than the refill season that we're still kind of a 0.5 Bcf or so tight. I think that the timing as we come into the fall and winter of the 2 pipes that are coming on in the Haynesville or can get Haynesville gas out that you have LNG demand kind of front-running that.

So -- but then I see at least from our perspective, is that we have a pretty balanced 2026. 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 has changed through the, I guess, the political system that we're going through. So just as 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 gas has got a fairly balanced in the year out instead of being extremely bullish.

[Operator]

Our next questions come from the line of Selman Akyol with Stifel.

[Unknown Analyst]

This is Tim on 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 Midtown or is some of this also up in Wyoming?

[Tom Ward, executive]

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

[Unknown Analyst]

Okay. Got it. I was just curious on potentially lowering some costs there. And then for lease operating expense, the Q had called out some higher costs related to saltwater disposal. Just curious what you guys are broadly seeing on the waterfront in the Mid-Con or if this was more of a one-off item?

[Kevin White, executive]

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

[Operator]

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.