Good morning, and thank you for attending today's PHX Minerals' March 31, 2024, Quarter End Earnings Conference Call. [Operator Instructions] As a reminder, this call is being recorded. I would now like to turn the call over to Stephen Lee with FNK IR. Please go ahead, sir. .

Thank you, operator. And thank you for joining us today to discuss PHX Minerals' March 31, 2024, quarterly results. Joining us on the call today are Chad Stephens, President and Chief Executive Officer; Ralph D'Amico, Executive Vice President and Chief Financial Officer; and Danielle Mezo, Vice President of Engineering.

The earnings press release that was issued yesterday after the close is also posted on PHX Investor Relations website.

Before I turn the call over to Chad, I would like to remind everyone that during today's call, including the Q&A session, management may make forward-looking statements regarding expected revenue, earnings, future plans, opportunities, and other expectation of the company.

These estimates and other forward-looking statements involve known and unknown risks and uncertainties that may cause actual results to be materially different from those expressed or implied on the call.

These risks are detailed in PHX Minerals' most recent annual report on Form 10-K, as such may be amended or supplemented by subsequent quarterly reports on Form 10-Q or other reports filed with the Securities and Exchange Commission.

The statements made during this call are based upon information known to PHX as of today, May 9, 2024, and the company does not intend to update these forward-looking statements whether as a result of new information, future events, or otherwise, unless required by law.

With that, I would like to turn the call over to Chad Stephens, PHX's Chief Executive Officer.

Chad?.

A, anticipated completion of U.S.

domestic LNG export facilities beginning in 2025, which we have discussed on prior calls; B, new LNG export facilities under construction or nearing FID on the Pacific coast of Mexico that anticipates an additional 7 BCF of natural gas demand by 2027 and 2028; C, increase in power demand of approximately 30% by the year 2030 from AI and growing data centers that should increase natural gas demand materially; and d, Freeport LNG facility is back up and 100% in service after several months of being down.

Each of these items standalone should be adequate to balance the current oversupply macro and bring our current natural gas storage inventory number to equilibrium. Collectively, these could create an undersupply and move normalized prices up dramatically from their current lows.

Under most of these projections, a more stabilized and higher price environment is needed to encourage more drilling to deliver increased volumes to serve the increased demand. Under any conservative increase in demand I lay out, the old paradigm feast or famine commodity price cycle could disappear.

The need for a less volatile, more predictable price forecast will help provide for the supply necessary to meet the robust growing demand. I believe this is setting PHX up for solid increases in royalty volumes and cash flow in 2025 and beyond.

At this point, I'd like to turn the call over to Danielle to provide a quick operational overview, and then to Ralph to discuss the financials. .

Thanks, Chad, and good morning to everyone participating on the call. For our quarter ended March 31, 2024, total corporate production decreased to 6% from the quarter ended December 31, 2023. Royalty production for the quarter decreased 5% compared to the prior sequential quarter to 1,857 Mmcfe.

The volume decrease during the quarter is primarily associated with Haynesville producer's decision to delay bringing wells online due to low natural gas pricing.

It is important to note that as a mineral holder, we do not control timing on well development, so there can be some volatility on a quarter-to-quarter basis, and volumes associated with our business model are better evaluated on a rolling 12-month basis.

We are also aware of certain new wells in which we have a significant royalty interest that were drilled and completed in December 2023, but the operator deferred bringing to sales in January 2024 due to low gas prices. Had the wells initiated production in January, our year-over-year royalty growth would have reported a volume increase.

We believe those particular wells are now online and producing. Also as discussed in prior recent quarters, our overall corporate volumes are down year-over-year due to the sales of material working interest assets in early 2023. Royalty volumes represented 88% of total production during our March 31, 2024.

80% of our quarter's production volumes were natural gas, which aligns with our long-term position that natural gas is the key transition fuel for sustainable energy future. Oil represented 11% of production volumes and NGL represented 9%.

During Q1 2024, third-party operators active on our mineral acreage converted 85 gross or 0.32 net wells in progress or WIP to producing wells, which is a significant increase compared to 46 gross or 0.098 net in the prior sequential quarter. The majority of the new wells brought online are located outside of the Haynesville.

Even though the number of conversions increased on a sequential quarter basis, these were lower rate wells compared to a typical new Haynesville well. This, along with operator curtailments and new well deferrals, as stated earlier, explains the decrease in sequential royalty production volume.

Have we seen the average number of new well Haynesville conversions this quarter as we realize each of the last six quarters, we would have seen an increase in royalty production volume.

We are very pleased with our well conversion rates, particularly given the challenging natural gas macro environment, which includes some operators deferring bringing completed wells online until there is an improvement in natural gas price.

We also expect an increase of Haynesville locations converting to PDP in the second half of 2024 and full year 2025 as natural gas prices improve. At the same time, our inventory of wells in progress on our minerals, which includes DUCs, wells being drilled, and permits filed remain strong with 230 gross or 1.099 net wells.

The continued track record of well conversions and replenishment of the inventory of wells in progress or WIPs reflects the high quality portfolio of assets we have assembled to provide steady sustainable future growth.

In addition to our WIP, we regularly monitor third-party operator rig activities in our focus areas and observe 15 rigs present on PHX Mineral acreage as of April 23, 2024. Additionally, we had 65 rigs active within 2.5 miles of PHX ownership.

In summary, we continue to see steady development in both our legacy and recently acquired mineral assets, which should lead to annually increasing royalty volume. Now I will turn the call to Ralph to discuss financial. .

Thanks, Danielle, and thank you to everyone for being on the call today.

For our first fiscal quarter ended March 31, 2024, natural gas, oil, and NGL sales revenues decreased 17% to $7.1 million compared to the prior -- compared to the prior sequential quarter due primarily to a decrease in production volumes of 6% and a decrease in realized prices of 12% on an MCFE basis to $3.35 from $3.81 in Q4 2023.

Realized natural gas prices average for the first quarter of '24 were $2.10 per MCF compared to $2.53 in the fourth quarter of '23. Realized oil prices averaged $76.01, down 3% from the fourth quarter of '23. And NGL prices averaged $21.51, down 10% from the fourth quarter of '23.

Realized hedge gains for the quarter were $1.67 million, approximately 62% of our natural gas, 37% of our oil, and none of our NGL production volumes were hedged at averaged prices of $3.82 per MCF and $68.98 per barrel. Most of these hedge contracts were added over the course of the last 18 months.

We continue to be consistent with our hedge program and believe it is doing what it was meant to do, which is to protect our downside. Approximately 48% of our anticipated full year 2024 natural gas production at the midpoint of our guidance has downside protection at approximately $3.34 per MCF.

On the oil side, approximately 37% of our anticipated production at the midpoint of our guidance has downside protection at approximately $64.94 per barrel. We structure our natural gas hedges using both swaps and costless collars, which means that we also have upside exposure on certain volumes up to the $45 range per MCF.

Our current hedge position is available in our recently filed 10-Q. Transportation, gathering, and marketing decreased 11% on a sequential quarter basis to $843,000, primarily due to lower prices and lower volumes during the quarter.

Production and ad valorem taxes decreased 14% on a sequential quarter-over-quarter basis to approximately $392,000 due to lower prices and lower production volumes.

LOE associated with our legacy non-operated working interest wells increased 4% on a sequential quarter-over-quarter basis to $332,000, primarily due to higher workover expenses on our liquid prone wells in Oklahoma, which also means that in the coming quarters, you should see some improved performance out of those wells.

Cash G&A was flat at approximately $2.6 million compared to the prior sequential quarter. Our cash G&A is typically higher in the first and fourth calendar quarters of the year compared to the second and third calendar quarters of the year due to professional fees associated with items such as our 10-K and our shareholder meeting.

Adjusted EBITDA was up to $4.6 million in our Q1 2024 quarter as compared to $4.5 million in Q4 '23. The slight increase in EBITDA, despite lower production volumes and realized prices, is due to the high quality of our assets and the successful implementation of our hedging strategy.

Net loss for the quarter was $200,000 or negative $0.01 per diluted share. We had total debt of $30,750,000 million as of March 31, down $2 million from December 31, 2023. And currently, our debt stands as of right now at about $29,750,000 million, much like last year at this time when natural gas prices fell.

Our acquisition program has remained very disciplined. And if the deals in the marketplace don't generate our required rates of return, we will not chase those deals. We're happy to continue to build liquidity and pay down debt. Our debt to trailing 12-month adjusted EBITDA was 1.58x as of March 31, '24.

As we announced a few weeks ago, during our regularly scheduled semiannual borrowing base redetermination, our bank group maintained our borrowing base flat at $50 million and extended the maturity of our loan from September 1, '25 through September 1, 2028. I'd like to thank our bank group for their continued support.

With that, I'd like to turn the call over to Chad for some final remarks. .

Thank you, Ralph. We are very pleased with our achievements despite a challenging macro environment. The dramatic collapse in natural gas prices in early 2023 and lingering at historic lows currently has had a material impact on natural gas-focused E&P's development activities, especially in Haynesville and Marcellus.

As a mineral owner, we will also be impacted by this. However, our business strategy is to acquire minerals in the core of our focus area with near-term development potential. This can be seen by our continued steady well conversions that supports our expected future royalty volume growth despite the various headwinds.

To recap our progress and achievements and at the risk of sounding a bit redundant from our last call, I want to emphasize that we have built a portfolio of high-quality assets with improved cash margins over the last 4 years, a mineral interest in a deep inventory of undeveloped drilling locations, which supply our well conversions and are categorized as probable reserves.

This conversion rate, which Danielle discussed a moment ago, is explained in our IR slide presentation and will continue to drive increasing royalty volumes and cash flow over the next few years.

As I did last quarter, I direct you to Slide 7 of our newly posted IR presentation that reflect a total 2P, which is total proved and probable reserves, PV-10 reserve value at current NYMEX strip prices close to $300 million.

This reserve value is validated by the independent technical work performed by our outside third-party engineering firm, Cawley, Gillespie. If natural gas prices return to a more normal mid-price cycle and driven by the catalyst which I earlier referred, that PV-10 value reflected on that Slide 7 would be dramatically higher.

We also show in the appendix of our IR presentation and the timing of the new LNG export capacity from the Gulf Coast, which we continually emphasize. Once in service, this will help bring natural gas prices into that mid-price to upper range, and with increased operator activity, increase our royalty production volumes and cash flow.

Since 2020 and to date, we have spent approximately $130 million acquiring our current mineral position in the SCOOP and Haynesville. PHX's current enterprise value is roughly $145 million to $150 million of value. The reserve value I mentioned earlier of at least $300 million is in comparison.

We recognize the disconnect between these facts and our current stock price. We continually work every day searching for the best way to reward our shareholders and close this conundrum by increasing shareholder value. As always, I thank our employees and Board of Directors for their hard work. This concludes the prepared remarks portion of the call.

Operator, please open up the queue for questions. .

[Operator Instructions] Our first question comes from the line of Derrick Whitfield with Stifel. .

For my first question, I wanted to focus on your 2024 guidance. Perhaps leaning in on Danielle's prepared comments.

Can you help frame how you're thinking about cadence of production throughout the year based on your WIP and expected curtailments? And then regarding curtailments more specifically, what is your sense on how material they are at present?.

Hello, Derrick, it's Ralph. Look, I mean, I think when we put out that guidance, we had already seen the slowdown in the pace of development. So our guidance reflects that. Obviously, we think that there's going to be an increase in activity towards the end of the year.

So it can be a little bit more biased towards the end of the second half of the year versus the first half of the year.

That -- having said that, as we sit here and we look at the well conversion rate, even for -- even since March 31, right, in the quarter that we just reported, we continue to see strong activity, which, by the way, includes some Haynesville conversions, which I think some people would maybe not have assumed that they would happen, but they are happening with some of the operators that we have there.

So we continue to remain confident as -- with the guidance that we provided. And obviously, if the facts on the ground change, we'll update everybody on what a revised guidance might be. But as we sit here right now, we continue to remain -- we remain -- we continue to feel good about the numbers that we put out. .

Yes, Derrick, this is Chad. Again, we closely on a quarterly basis, follow the well conversions, broken out as permits, wells being drilled, and wells waiting on completion. And you can go back 6 or 8 quarters and both on a gross and a net basis. Six quarters ago, it compares very similar to where we are today in those categories that I just mentioned.

The big driver or the -- it's dependent upon the net interest in the actual well that's being completed. Haynesville wells, big initial rates, big booming. Initial rates in some of the wells we have interest in up in Oklahoma might not be quite as -- the initial rates might not be quite as strong.

But we are encouraged by some of the activity we're seeing in the SpringBoard III, where we have some really high net interest in sections.

And we're hopeful that the operator will get those wells drilled completed by mid-summer to going into the fall and will positively impact our royalty volumes and we're optimistic that we'll be able to hit our -- the midrange of the guidance we provided. So we watch it very closely and feel pretty good about midpoint of guidance. .

And I will add to that, that on top of the consistency of the conversion rates, we do see that the curtailments on our existing PDP have not been material thus far. It's mainly on the newer DUCs and WIPs that we see a bit of delay. .

And what am I to -- so really picking up on your comments, Chad, regarding the value disconnect. You guys have made great progress when you think about the conversion you've done, your production base from marketing interest to minerals, and you're continuing to grow the mineral space to date.

What in your view is the best way to address that value disconnect? Is it more of the same? Are there other things that you guys are contemplating?.

Well, we're kind of running several parallel paths. Deal size, we would continue to -- right now, as we talked about the first quarter, capital allocation was between dividends, debt payment and a few modest small deals.

So those $200,000, $300,000, $400,000, $500,000 sized deals, we're continuing to attempt to transact, but especially as Ralph alluded to, in the Haynesville, the bid-ask between the seller and the buyer is pretty far apart. The sellers want to sell at a $6 strip, NYMEX strip. We can't -- our economics don't work at that kind of strip price.

So we've not been able to transact moving into the larger kind of the midrange deals, the $2.5 million to $5 million, $6 million sized deals that we did kind of year-end '22 going into 2023.

We haven't been able to transact on any of those as the sellers had decided to just sit on the sidelines and wait for what I keep alluding to as the LNG export facilities driving improved pricing and the sellers will be able to get a much better price for their assets. So those midsized deals, $5 million, $6 million, we've been unable to transact on.

We're continuing -- so those are 2 parallel paths we continue to watch and work.

And then the final is, we continue to talk to larger private entities, larger private sellers, kind of that $10 million to $20 million, $25 million size range, and potentially -- and I would say, that emphasize potentially using our equity to close on these larger-sized deals that will ultimately improve our float.

Our -- it's one of our -- probably our limitations as our daily trading volume. But I think that takes care of itself. If natural gas prices improve and our EBITDA improves, our multiple expansion will improve and our stock price will improve, and that will kind of take care of itself a little bit.

But I would like to see a little bit more shares out there and better float daily trading volume and float. So we'll try to find that right deal to improve the float. But I think some of that will take care of itself if and when prices improve and our EBITDA and cash flow increases by way of that. Ralph, you want to ….

Yes. Derrick, I think keep watching the -- it's interesting. I think none of the public companies really -- since Continental went private, they don't necessarily talk about the SpringBoard plays in the SCOOP. But we keep providing updates on that. And I wish more of the operators would talk about them.

It continues to be the operators that have -- they focus on the Permian, but they have the acreage in the Anadarko Basin. They continue to run rigs in the Anadarko Basin and then drill wells, right? And so that to me tells me that it competes for capital inside of their portfolio.

You just don't see it in the -- in sort of how they communicate to the market, right? So we try to provide some of that.

And I think if people keep looking at what we're -- our messaging on SpringBoard III and how that's progressing along, hopefully, just the public announcements that we make on the well conversions there and how high-quality locations they are, right? People start to pick up that there is more value on that undeveloped component, right? Because again, that's SpringBoard III is 4,000 net royalty acres, the majority of which is undeveloped, but there is significant upside there, that I don't believe folks are assigning value to as we sit here right now.

.

And we -- Derrick, to kind of further comment on your question around the disconnect. We want our shareholders to share in that value that upside.

And then somewhere down the road in the next 6, 12, 18 months, SpringBoard III will become more fully developed and flowing through our financials, which will benefit our shareholders by multiple expansion and increasing volumes and cash flow.

So we want them to be patient and not bail on us too early because of the macro environment we're in right now. We have really high-quality asset there in SpringBoard III, and it's going to ring the bell here at some point in the future. .

And if I could ask maybe just one more.

Given the wider bid-ask spread that you're seeing right now in the Haynesville, perhaps could you speak to the competitive landscape you're seeing in the Anadarko? Or maybe that's not as prevalent?.

I think -- I mean, in terms of the acquisition marketplace, I mean, Oklahoma and the Anadarko Basin continues to be pretty fragmented.

You've seen some larger deals in the $100-plus million size transact over the last six months, right? And I would actually say -- I think I've mentioned this before in prior calls, if you took any of those acquisitions and applied the multiple at which they transacted to our metrics, you end up at a very different place from where we currently trade, which is sort of just touches on the upside that Chad mentioned.

But on the smaller transaction size, smaller deal size that sort of are bread and butter, I would say we continue to see attractive deals.

They're -- the larger -- the amount of capital chasing to smaller deals is not as large, right? And so we tend to be a bit of a bigger fish in a smaller pond, if that makes sense, compared to the Haynesville, where there is, on any normal day, there's a lot more competition and we're a bit of a smaller fish in a bigger pond.

But the pond is big enough where we can still have -- take our piece of it in the Haynesville. That's how I would characterize it. .

Yes. And let me add to that.

So yes, the Haynesville is a much bigger sandbox, so to speak, and a lot more running room and more of a kind of a homogenous reservoir to understand, so you can move around that sandbox and get kind of similar economics and results when you're acquiring minerals, whereas the SpringBoard III is a much more targeted, and it speaks to our technical capabilities, and I'm proud of that, that we early on figured out the SpringBoard III and we're able to stake a flag in that asset.

It's a pretty, again, targeted bull's-eye of a smaller sandbox, so to speak, and we were able to get in there early and assemble quite a nice little 4,000-acre position in that asset. So 2 different opposite ends of the spectrum or opposite side of the same coin, so to speak.

We were able to get in there early enough to have a really -- what will become a significant position in that small sandbox. .

Our next question comes from the line of Charles Meade with Johnson Rice. .

I want to ask a question. I want to ask a question about, I guess, asking you guys, you've got [indiscernible] in your crystal ball for what might happen in the Haynesville.

There have been a number of companies who said, well, we're not going to turn in any wells until things get better, but we're not going to tell you our criteria for when things are better. And I'm just curious if -- you've got exposure to a lot of different operators.

What are you observing as far as when companies are going to -- are electing to turn wells in line? And how is that different across operators? And then with the next threshold, when do you think -- when do you think or what price do you think we need to see before operators start increasing rig count in the play? And I know that's not speculation, but you guys have a really interesting advantage point in that regard.

.

Yes, Charles. So we view the Haynesville in watching the operators and their drilling costs, drilling and completion cost. Economic -- kind of $2.75 to $3-ish type gas prices, the Haynesville is pretty economic for these operators based on what we're seeing in drilling and completion costs.

When you get up kind of at a very high level, flyover level, it takes about 40 rigs to keep the gross volumes in the Haynesville flat. With those big volumes and steep declines, you need about 40 rigs constantly running to keep the volumes flat. Today, we're at 34 rigs.

So we know for sure in watching the gross volumes coming out of the Haynesville basin that the volumes are dropping. And we kind of -- based on what we're seeing, the volume -- gross volumes will decline between 1.2 and 1.4 BCF a day in 2024, part of that overall U.S. domestic decline I was talking about at the start.

It was -- gross domestic production was 102, today it's 96, part of that decline is coming from that Haynesville decline I just talked about. The DUCs, the wells that have been drilled and uncompleted had an inventory in March of '23, around 280. Today, it's around -- it's below 200. That's over 30% drop in the number of DUCs.

And it's really that DUCs supply that operators can turn to and start completing and drive volumes and the increase in volumes. So it's about -- based on what we're seeing today in terms of the rate of wells being completed, we're seeing about a 4-month inventory of DUCs, what we consider to be pretty low.

So when you think about -- if the strip price for '25 kind of stays where it is, we see volumes in the Haynesville increasing in 2025 by over -- a little over 2 BCF a day, 2 to 2.2, maybe 2.4 BCF a day; '26, similar, around 2 BCF a day; and 2027, about 1 BCF a day.

So somewhere 5, 5.5 BCF a day over the next 3 years increase in Haynesville production, which, given our mineral ownership and where all this will happen, is going to obviously speak to our overall volume growth, royalty volume growth over those same next 3 years, which, again, is encouraging to us.

So that gives you a macro of what -- how we view not only the basin but how it effects or impacts us. .

Yes. And Chad, I mean, it looks to me -- I shouldn't say it looks to me. Based on history, I would expect private operators to be kind of quicker responders than public.

Is that what you're seeing? Or is that what you expect to see?.

Yes. But I mean the material, all the material ownership has been kind of consolidated up into a few -- Aethon has got a ton of leasehold, both in the Louisiana side and the Texas side. Aethon, Comstock down in the Robertson County, the big -- this new big Western Haynesville play with these big wells, they consolidate their positions.

Rockcliff just sold to Tokyo Gas. They've got a big position. I just don't think that any of the remaining small private equity-owned companies are going to have any real impact or material impact on the overall gross volumes over the next 2 to 3 years.

Unlike the Permian, there's still quite a few private equity groups out there that can drive volume growth out there. But I don't think the private equities are going to, like they were, going to impact the Haynesville gross volumes. .

And then switching over to the SCOOP. It looks -- from the outside, looking in, it looks like there's pretty steady activity there. And maybe there's a little -- maybe some of the big guys have paused, that are coming back.

Can you give us a sense of what's happening at the leading edge in the SCOOP? Are there any kind of smaller players who are working around the edges? Or are there people testing new zones? What's the kind of -- what's the latest leading edge that you're seeing in the SCOOP?.

Well, so you can look at our IR slide deck and see kind of this narrow fairway north to south between the STACK, the MERGE, what we call the MERGE, and then the SCOOP provides a real fairway of where the development is going on.

And it's still mainly the larger public or what was public, Continental, Marathon, Gulfport, that are running the rigs in the spine of this fairway that I'm talking about. There are a few small private equity guys. Camino is small. Citizen. 89 Energy bought the old Apache assets a few years ago, and they run a rig here or there.

But it's -- again, it's going to be -- given the leasehold position that Devon, EOG, Marathon, Continental, the leasehold position that they have in the core of that play, they're going to drive that development.

Speaking to your question around the margins of the play, I don't think that the margins are going to really drive any overall material influence or impact on gross volumes out of that basin. There is some -- when you look at Western Anadarko Basin out toward the Texas panhandle, you see some development going on out there.

EOG is kind of playing around out there, but there's a couple of small companies. Mewbourne, which is a highly respected company, has been running several rigs out there in the Western Anadarko Basin for quite some time. Crawley, a couple other smaller private equity groups, they're playing out there.

We've actually kind of looked out there at what the -- trying to find about minerals out there, and it's kind of a tough game out there. So we really haven't been able to make any headway there.

So I still think this main fairway that we highlight in our Investor Relations slide deck is going to be where the rig count, CapEx are going to be allocated in the spine, and the main -- any sort of main volume increase is going to come from that fairway. .

Our next question comes from the line of Jeff Grampp with Alliance Global Partners. .

We've seen some operators, I think Chesapeake was pretty noteworthy in this, talking about basically completing wells and then just kind of hanging out until price improves.

Do you guys have any visibility or estimates within your asset base as to the prevalence of that within kind of your wells and process bucket?.

I think, Danielle, I'll let her speak, but she basically stated what we know to date is that, that didn't appear on our assets that we -- obviously, we're not under EQT, but the EQT has announced their deferrals up in the Marcellus, but Chesapeake has announced some deferrals of completing new wells, but not existing production.

So -- and Danielle referred to that. I'll let her kind of comment to --.

Yes. I'll agree with Chad. We have not seen material deferrals on that side. We do see a slowdown. We don't have a ton of wells under Chesapeake that are in that phase of development right now, where their DUC is just sitting at this point in time, at least not with the material interest. We do have wells under them at this time.

We do seem to be under some of the more private operators that are still moving forward with turning their wells on. They've already drilled them. They've already completed them. And from everything that we can tell, they intend to turn them on here in the near future.

So at this time, it hasn't really been a material of the wells just sitting once completed. .

And Jeff, it's Ralph. One more thing. I mean, we continue to see to the extent that the wells have converted, right? I mean, we continue to see new permits filed and new rigs moving to location on our -- adjacent to our acreage, even in to Haynesville.

So it's sort of an interesting dynamic where what you hear on a macro level about the play -- obviously, we're not immune to it, but it appears that the quality of our acreage is sort of showing through here, relative to what you hear about basin-wide commentary. .

And for my follow-up, on the acquisition side of things, I know you guys certainly were not expecting 2024 to be super active from an acquisition side given prices and bid-ask and everything that we've already talked about on the call.

Looking back, do you think Q1 is kind of consistent with what you would have expected coming into the year from kind of a capital deployment perspective? Would you characterize it better, worse? Or I guess, just kind of wondering what you guys are thinking as far as a reasonable amount of acquisitions all things considered on a macro standpoint. .

I mean, look, I mean, I think last year, if you look at last year and you look at natural gas prices, right, they had a -- they dropped pretty materially. Was it about the same time? Maybe it was late February, early March, where they had a big drop, and it stayed down for some period of time, obviously not to the level of this year's drop.

But if you look at how we behaved the last year, that's a pretty good -- it's a pretty good guide to how we're behaving this year, right? I mean, it's -- we're not going to chase deals for the sake of chasing deals. We're going to be conservative. We're going to build cash, pay down debt, improve liquidity.

And when the market improves, we'll go -- we can go back into the market -- and that's the beauty of the minerals business, you can flex down or flex up with your cash flow, whether it's on the acquisition side or debt repayment or whatever it may be, a lot faster than if you are a working interest business that has capital requirements that they don't necessarily have the ability to either defer or do in short notice, right? So second quarter is probably going to be the same.

If you look at last year's second quarter, it was relatively slow on the acquisition front. We build liquidity. And we go from there. And then we -- last year then in September, we did a really nice acquisition in the Haynesville that are already paying dividends for us.

And so if the same happens again, no guarantees, right, we got to find that deal again. That's something that we would look at. But you can look at last year's behavior and how we're behaving this year and you can draw a pretty good correlation. .

Our next question comes from the line of Donovan Schafer with Northland Capital Markets. .

So first, I just want to clarify when a well is -- when it's drilled and when it's a DUC drilled and uncompleted or alternatively also when it's drilled and also completed, but just hasn't been turned in line and is just sort of shut in, where do those get classified? Does that get classified as in progress? And even though it's technically completed, it doesn't go into converted until it's turned in line? Or how does that work from a classification standpoint?.

Yes, that would be correct. Until we truly see that this is producing and online with the first production date, that will be considered a well in progress. .

And then so talking about these DUCs, and particularly, I would say -- I mean, especially I would say, the ones that have been fully completed and shut in.

Is it fair to say, would you expect that dynamic would create like a more accelerated increase in production once things turn around? Because like without that, right, so even if it was just DUCs or there are no DUCs, you need the drilling crews and equipment plus the completion equipment to go through their process, which takes some measure of time.

And then with DUCs, you don't need to worry about the rig, but you still need a completion crew.

So if it's fully completed, and there's really nothing to be waiting on, and it's ready to just kind of turn the valve and that's the barrier between going from in progress to converted, then does that -- does it follow -- I mean, like it's my logic, does the logic hold that there could really be like a kind of step up in a more significant way? Or are there reasons to be more cautious on that?.

Donovan, the way I answer that question is going back to kind of some of the stats I was reviewing with -- when Charles, his question.

So the overall year-over-year from March to March '24, the DUCs had declined by 30% to -- down to about a 4-month average worth of DUCs, the rate at which a DUC can be completed in terms of sales, could -- all those 200 DUCs could be burned off and put to sales in 4 months.

Will that happen? At current gas prices, we don't know the logic or the behavior of these operators that operate these 200 DUCs that are sitting there in inventory.

But to your question, the 200, we don't know whether those are -- actually, they're categorized as DUCs, but we don't know if they are sitting there waiting to be completed, are they -- is there a frac crew sitting there on the well site about to frac the well, have they been completed and waiting to hook the -- put the line up to sales, has the pipeline actually been connected to the wellhead and they're waiting to just turn, we don't -- it's hard for us to determine that detail of intelligence out there on the ground, so to speak.

But we don't think that if all 4 months were done in 1 month, that all 200 DUCs were -- maybe the supply would go up for a couple of months, but the decline would probably burn off a lot of that instantaneous production.

And again, I'd just say that as a normal rate of converting the DUCs to producing in 2025, we see a 2 to 2.5 BCF increase from the Haynesville as gas prices improve. So that speaks to what we think will happen with these DUCs in normal rig rate of 35 to 40 rigs. .

And then turning to the SpringBoard III and kind of activities in that area on your acreage.

Can you just remind us what the production mix is there versus the corporate average? I know, philosophically and strategically, you guys are concentrated on natural gas, but all is equal, oil prices and NGLs potentially are -- would be beneficial in some ways.

So is there something -- is there a movement in that direction at all? Or are these -- or could you try gas?.

So for the SpringBoard, the mix is fairly even between oil, NGLs, and gas, 1/3, 1/3, 1/3 roughly. .

Yes.

Keep in mind that there are some operators that -- in the SpringBoard and also in other parts of the Anadarko Basin that when they pay their mineral holders for NGLs, they don't actually -- they pay on a rich gas content, right? So you may get -- so if it's 1,400 BTU gas, you're going to -- on your check stub, you're going to see 0 NGLs, but you're going to see the gas volumes multiplied by whatever the price is, x1.4 versus x1, right? So you see a mixture of the -- not just the volumes, but in some cases, right, the way you report it is, you don't count the NGL volumes which account better pricing on the gas because of the way that these operators pay you, which is common and as to, they treat everybody the same, right? So it's not nuanced to us.

They treat every mineral holder the same way. .

And you -- yes, you're saying it has to do with the way it's treated sort of from a, I don't know, accounting or billing -- invoicing, billing, whatever type situation, but not -- it's not reflective of are there or are they not doing NGL extraction. Like they may be doing NGL extraction, but they're just not transmitting the information that way.

It's instead [indiscernible] into that scale, right? Okay. So then my last question, if I can just get one more in, was just we talked a lot about the LNG capacity and other infrastructure changes taking place that should be bullish for natural gas.

I guess -- but there's not a lot -- it doesn't come up too much questions about NGL like infrastructure. And so I'm just kind of curious with -- when natural gas prices are so low or is equal and then particularly if oil prices are doing all right, then that can motivate more NGL extraction or ethane rejection or not doing ethane rejection.

And so is there -- are there any developments there or new plants coming -- NGL plants or anything coming online that could have a meaningful material impact of any kind? Just trying to figure out if there's a potentially positive, but like a blind spot there?.

Well, so the Haynesville is dry gas, so there's no NGL liquids coming out of that basin. There is plenty of capacity in the Mid-Continent in the STACK and the SCOOP to process the natural gas that's coming online -- new production that's coming online that has wet gas that needs processing before turning to sales.

The main driver for the NGLs in the next 2 to 3 to 4 years is going to be the Permian Basin. And you see Enterprise, Energy Transfer, several other smaller private equity groups that are building, especially the Delaware Basin, really rich gas out there, they're building NGLs out there.

But -- and so we don't -- I don't actually know what the forecasted NGL barrel, the Y-grade NGL barrel that's forecasted to come out of the basin over the next 2 to 3 years. We don't really watch that as closely. But there is a -- from a macro perspective, there's going to be a huge call on U.S.

supply of NGLs, especially propane and ethane in the near future between now and say, '27 or '28 of maybe 500,000 barrels a day needed for new demand -- global demand. So I think there's probably some upside in terms of pricing once the new supply comes on and feeds this global demand. That's our view on NGLs. .

So just to make sure I'm kind of understanding correctly.

My putting together the kind of different data points here is that there could be potentially some increase in like the NGL mix that would come from, say, the SpringBoard III contribution, but not something to do with like additional processing capacity or anything along those lines that would impact you guys in terms of the mix of NGLs? And then what you could see based on, Chad, you comments just now would be more just potentially pricing benefit from the kind of more macro dynamic.

Is that right?.

Yes. If I understand your question, when you say NGL mix, just quickly, the purity products coming off the NGL barrel are ethane, propane, 2 types of butane and some pentane, which is gasoline. And between ethane and propane, that represents 75% to 80% of a typical barrel.

Ethane is sold each month based on the dynamic between the cents per gallon price of ethane as compared to leaving the ethane in the gas stream and selling it as Btus in the -- for gas price, dollar per MMBtu.

So the number of barrels of ethane can change in any given month based on that dynamic between the ethane price and leaving it in the gas treatment and selling it as a Btu. Propane, they have to take the propane out to make the gas meet pipeline quality specs.

So will the overall NGL barrel out of the SCOOP increase probably, but not -- I don't think in any scenario will it become dramatically a problem or an issue or oversaturated or oversupplied versus what will be coming out of the Permian Basin. .

Thank you. And we have reached the end of the question-and-answer session. I'll now turn the call back over to Chad Stephens for closing remarks. .

Again, I'd like to thank our employees and shareholders for their continued support. I'd also like to note that Ralph and I will continue to expand our investor marketing activities over the coming weeks and months. Specifically, we will be participating in the Stifel Cross Sector Insight Conference that will be hosted in Boston on June 4 and 5.

If you would be interested in meeting at one of these events or at any time, please don't hesitate to reach out to myself, Ralph, or the folks at FNK IR. We look forward to hosting our next call in early August to discuss our second quarter 2024 results. Have a nice day. .

And this concludes today's conference, and you may disconnect your lines at this time. Thank you for your participation..