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spk07: Good morning, and thank you for attending today's PHX Minerals March 31st, 2024 quarter and earnings conference call. At this time, all lines will be muted during the presentation of the call with an opportunity for a Q&A session at the end. As a reminder, this call is being recorded. I would now like to turn the call over to Stephen Lee with FNKIR. Please go ahead, sir.
spk00: Thank you, operator, and thank you for joining us today to discuss PHX Minerals March 31st, 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 Mezzo, Vice President of Engineering. The earning 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 want to remind everyone that during today's call, including the Q&A session, management may make four looking statements regarding expected revenue, earnings, future plans, opportunities, and other expectations 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 quality reports on Form 10-Q or other reports filed with the Securities and Exchange Commission. The statement made during this call are based upon information known to PHX as of today, May 9th, 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'd like to turn the call over to Chad Stephens, PHX Chief Executive Officer. Chad.
spk02: Thanks, Steven, and thanks to all of you on this call for participating in PHX's March 31st, 2024 quarter end earnings conference call. We appreciate your interest in the company. In spite of a 40% drop in natural gas prices from a year ago, PHX reported steady, positive, adjusted EBITDA and cash flow while operators are curtailing their existing production and deferring bringing new wells to sales. due to low gas prices. PHX's year-over-year and sequential quarter royalty volumes were down slightly. With prices and volumes lower, our year-over-year EBITDA was down materially. However, our EBITDA compared to the prior sequential quarter was up slightly and reflects our solid hedging program built to protect our financial plan. This allowed us to service our dividend, reduce debt, and close on a modest amount of acquisitions, approximately $1.1 million, $2 million, and $1.5 million, respectively. Ralph will discuss leverage in a moment, but I would like to point out that our banks recently reaffirmed our borrowing base at the same $50 million and extended the maturity. This does highlight the quality of our assets. As our existing production depletes, our existing PDP reserve base We backfill that bucket through our well conversions, which is our undeveloped drilling locations that includes a reserve category of probable and possible. Danielle will walk you through these conversions in a moment. Looking to the future, the significant positive macro events in play are, one, the operator activity in our core areas continues to maintain a consistent number of conversions of these undrilled locations to producing at actual PHX historical levels. And two, the natural gas supply demand macro is improving. The U.S. domestic natural gas supply is down from a December 2023 high of approximately 102 BCF per day to current volumes of around 96 BCF per day and dropping. Also, the natural gas demand narrative continues to build positive sentiment from, 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 seven 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 stand alone 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 Doral to discuss the financials.
spk01: Thanks, Chad. And good morning to everyone participating on the call. For our quarter ended March 31st, 2024, total corporate production decreased 6% from the quarter ended December 31st, 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 producers' 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 a 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 Hainesville. Even though the number of conversions increased on a sequential quarter basis, these were lower rate wells compared to a typical new Hainesville well. This, along with operator curtailments and new well deferrals, as stated earlier, explains the decrease in sequential royalty production volumes. Had 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 volumes. 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 Hainesville 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 ducts, wells being drilled, and permits filed, remains 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 WIPs, 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 financials.
spk03: 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 six 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 averaged 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 average 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 10Q. 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 work-over 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 10K 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 one penny per diluted share. We had total debt of 30,750,000 as of March 31st, down two million from December 31st, 2023, And currently our debt stands as of right now at about $29,750,000. 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 1.58 times as of March 31st, 24. As we announced a few weeks ago, during a regularly scheduled semi-annual borrowing base redetermination, our bank group maintained our borrowing base flat at 50 million and extended the maturity of our loan from September 1st, 25 to September 1st of 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.
spk02: 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 Hainesville 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 four 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 Daniel discussed a moment ago, is explained in our IR slide presentation and will continue to drive increasing royalty volumes and collect 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 approved and probable reserves, PV10 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, Colley Gillespie. If natural gas prices return to a more normal mid-price cycle and driven by the catalyst to which I earlier referred, that PV10 value reflected on that slide seven would be dramatically higher. We also show in the appendix of our IR presentation 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 today, we have spent approximately $130 million acquiring our current mineral position in the Scoop and Hainesville. PHX's current enterprise value is roughly $145 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.
spk07: Thank you. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. Our first question comes from the line of Derek Woodfield with Stifel. Please proceed with your question.
spk08: Good morning, all, and thanks for your time.
spk06: Hey, Derek.
spk08: For my first question, I wanted to focus on your 2024 guidance, perhaps leaning in on Danielle's prepared comments. Could 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's your sense on how material they are at present?
spk03: Hey, Derek, it's Ralph. You know, look, I mean, I think when we put out that guidance, you know, we had already seen the slowdown in the pace of development. So our guidance reflects that. You know, obviously, you know, 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. Having said that, you know, as we sit here and we look at the well conversion rate, you know, even since March 31st, right, in the quarter that we just reported, you know, we continue to see strong activity, which, by the way, includes some Haynesville conversions, which, you know, 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, You know, we continue to remain confident with the guidance that we provided. And obviously, if the facts on the ground change, we will update everybody on, you know, on what, you know, 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.
spk02: Yeah. Derek, 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 six or eight quarters and both on a gross and a net basis, you know, 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. Painesville wells, big initial rates, big booming initial rates, and 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 three where we have some really high net interest in sections. And we're hopeful that the operator will get those wells drill 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 the mid-range of the guidance we've provided. So we watch it very closely and feel pretty good about mid-point of guidance.
spk01: 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.
spk08: Terrific. And what I might do, 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 working interest to minerals, and you're continuing to grow the mineral space today. 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?
spk02: 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 two, three, four, $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, NIMEX 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 mid-range deals, the two and a half to five, $6 million size deals that we did kind of year in 22 going into 2023, we haven't been able to, transact on any of those as the sellers have decided to just sit on the sidelines and wait for what I keep alluding to is the LNG export facilities driving improved pricing and the sellers will be able to get a much better price for their assets. So those mid-size deals, five, six million, we've been unable to transact on. We're continuing. So those are two 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 say that, emphasize potentially using our equity to close on these larger size deals that will ultimately improve our float. That's one of our, probably our limitations is 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'll 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 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?
spk03: Yeah, Derek, and I think keep watching the, you know, it's interesting. I think none of the public companies really, since Continental went private, they don't necessarily talk about the springboard plays and the scoop. But, you know, we keep providing updates on that. And, you know, I wish more of the operators would talk about them. You know, it continues to be the operators that have, you know, You know, they focus on the Permian, but they have acreage in the Anadarko Basin. They continue to run rigs in the Anadarko Basin and drill wells, right? And so, you know, that to me tells me that it competes for capital inside of their portfolio. You just don't see it in the, you know, 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, you know, our messaging on Springboard 3 is, and how that's progressing along. You know, 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 Springboard 3 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.
spk02: And we, Derek, to kind of further comment on your question around the disconnect, we want our shareholders to share in that value, that upside. And somewhere down the road in the next 6, 12, 18 months, Springboard 3 will become more fully developed and flowing through our financials, which will benefit our shareholders by multiple expansion and increasing volumes in 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 3, and it's going to ring the bell here at some point in the future.
spk08: Makes complete sense, guys. And if I could ask maybe just one more. Given the wider bid-ask spread that you're seeing right now in the Hainesville area, perhaps could you speak to the competitive landscape you're seeing in the Anadarko where maybe that's not as prevalent?
spk03: I think, I mean, in terms of the acquisition marketplace, I mean, you know, Oklahoma and the Anadarko Basin continues to be pretty fragmented. You know, you've seen some larger deals in the hundred plus million dollar size transact, you know, over the last, you know, six months, right? And And I would actually say, you know, 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, you know, touches on the upside that Chad mentioned. But on the smaller transaction size, you know, smaller deal size that's sort of our bread and butter, I would say, you know, we continue to see, you know, You know, the amount of capital chasing the smaller deals is not as large, right? And so, you know, we tend to be a bit of a bigger fish in a smaller pond, if that makes sense, compared to the Haynesville where, you know, 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's big enough where we can still have, you know, take our piece of it. into Hainesville. That's how I would characterize it.
spk02: Yeah, and let me add to that. So yeah, the Hainesville 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 3 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 3 and were able to stake a flag in that asset. It's a pretty, again, targeted bullseye 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 two different opposite ends of the spectrum are opposite sides 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.
spk08: That's very helpful. Thanks for your time.
spk07: Thank you. Our next question comes from the line of Charles Mead with Johnson & Rice. Please proceed with your question.
spk05: Good morning, Chad, Danielle, and Ralph. I want to ask a question about, I guess, asking you guys to appear 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, 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, or what price do you think we need to see before operators start increasing rig count in the play. And I know that's a lot of speculation, but you guys have a really interesting vantage point in that regard.
spk02: Yeah, Charles. So we view the Haynesville in watching the operators and their drilling costs, drilling completion costs, 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 completion costs. When you get up kind of at a very high level, flyover level, it takes about 40 rigs to keep the growth volumes in the Hainesville 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 growth volumes coming out of the Hainesville Basin that the volumes are dropping. And we kind of, based on what we're seeing, the 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. Gross domestic production was 102. Today it's 96. Part of that decline is coming from that Hainesville decline I just talked about. The ducts, 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 ducts. And it's really that duct supply that operators can turn to and start completing and drive volumes and 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 four-month inventory of ducts, what we consider to be pretty low. So when you think about if gas, the strip price for 25 kind of stays where it is. We see volumes in the Haynesville increasing in 2025 by a little over 2 BCF at a 2 to 2.2 maybe 2.4 BCF a day, 26 similar, around 2 BCF a day. In 2027, about a BCF a day. So somewhere 5, 5.5 BCF a day over the next three 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 three years. which again is encouraging to us. So that gives you a macro of how we view not only the basin, but how it affects or impacts us.
spk05: Yeah. And Chad, I mean, it looks to me, or I shouldn't say it looks to me, based on history, I would expect private operators to be kind of quicker responders than publics. Is that what you're seeing or is that what you expect to see?
spk02: Yeah, but the, I mean, the material, all the material ownership has been kind of consolidated up into a few. Athon's got a ton of leasehold, both in the Louisiana side and the Texas side. Athon, Comstock, down in the Robertson County, the big, this new big western Hainesville play with these big wells. They consolidate their positions Rockcliffe 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 two to three 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 growth volumes.
spk05: Got it. 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 Are there any kind of smaller players who are working around the edges, or are there people testing new zones? What's the latest leading edge that you're seeing in the scoop?
spk02: Well, so, and you can look at our slide deck and see kind of this narrow fairway north to south between the stack and the merge, what we call the merge, and then the scoop that provides a real fairway of where the development's going on. And it's still mainly the larger public or what was public continental marathon at Goldport 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 a small citizen. 89 Energy bought the old Apache company. assets a few years ago, and they run a rig here or there. But 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. Mewburn, 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 of other smaller private equity groups, they're playing out there. We've actually kind of looked out there at what the, trying to buy 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, capexes are going to be allocated in this spine, and the main, any sort of main volume increase is going to come from that that fair way.
spk05: Thank you for that detail.
spk07: Thank you. Our next question comes from the line of Jeff Grant with Alliance Global Partners. Please proceed with your question.
spk04: Morning, guys. I was curious. 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 till 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?
spk02: I think Danielle, and I'll let her speak, but she basically stated what we know to date is that it doesn't appear on our assets that we're obviously we're not under EQT, but the EQT's announced they're deferrals up in the Marcellus, but Chesapeake has announced some deferrals of completing new wells, but not existing production. And Danielle referred to that. I'll let her kind of comment, too.
spk01: Yeah, 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 they're ducted and just sitting at this point in time, at least not with a 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.
spk03: 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, you know, We continue to see new permits filed and new rigs moving to location on our acreage or adjacent to our acreage, even in the Haynesville. So it's sort of an interesting dynamic where when you hear on a macro level about the play, obviously you are not immune to it, but it appears that, you know, that the quality of our acreage is sort of showing through here relative to what you hear about basin-wide commentary.
spk04: Got it. That's helpful. And for my follow up on the acquisition side of things, I know you guys certainly were not expecting, you know, 2024 to be, you know, 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, you know, 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?
spk03: I mean, look, I mean, I think last year, if you look at last year and you're looking at your gas prices, right, that they dropped pretty materially. You know, it was at about the same time. Maybe it was late February, early March. um, where they had a big drop and it stayed down for, you know, for some period of time, obviously not to the level of, of, of this year's drop. But if you look at how we behaved the last year, that's a pretty good, that's a pretty good, um, you know, it's, it's, 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, um, for the sake of chasing deals. We're going to be conservative. We're going to, you know, build cash, pay down debt, you know, improve liquidity. And when the market improves, you know, we'll go, you know, we can go back into the market. And that's a 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're a working interest business that has, you know, capital requirements. that they don't necessarily have the ability to either, you know, defer or what do on short notice, right? So, you know, 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 built liquidity and, you know, we go from there. And then we, you know, last year then in September, we did a really nice acquisition, you know, into Haynesville that, you know, you know, are already paying dividends for us. And so if the same happens again, no guarantees, right? We've got to find that deal again. You know, 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.
spk04: All right. That's helpful. Thanks, Ralph. Appreciate it.
spk07: Thank you. Our next question comes from the line of Donovan Stafer with Northland Capital Markets. Please proceed with your question.
spk06: Hey, guys. Thanks for taking the questions. So first, I just want to clarify when a well is, you know, when it's drilled and when it's a duct 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, doesn't go into converted until it's turned in line? Or how does that work from a classification standpoint?
spk01: Yes, that would be correct. Until we truly see that it is producing and online with a first production date, that will be considered a well in progress.
spk06: Okay, great. you know, talking about these ducks, 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, you know, would you expect that 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 ducks, or there are no ducks, you know, you'd need the drilling crews and equipment, plus the completion equipment to go through their process, which takes some measure of time. And then with ducks, 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, you know, in progress to converted. then does that does it follow i mean would like is my logic does the logic hold that there could really be like a kind of step up um in a more significant way or are there reasons to be more cautious on that donovan the the way i answer that question is going back to kind of some of the stats i was reviewing with uh when charles his question um so the the overall year over year from march to march 24
spk02: the ducks had declined by 30% down to about a four-month average worth of ducks. The rate at which a duck can be completed and turn to sales, all those 200 ducks could be burnt off and put to sales in four months. Will that happen? At current gas prices, we don't know the logic or the behavior of these operators that operate these 200 ducks that are that are sitting there in inventory. But to your question, the 200, we don't know whether those are actually, they're categorized as ducts, but we don't know if they are sitting there waiting to be completed. Is there a frack crew sitting there on the well site about to frack the well? Have they been completed and waiting to hook the line up to sales? Has the pipeline actually been connected to the wellhead and they're waiting to just turn the, we don't, it's hard for us to, to determine that detail of intelligence out there on the ground, so to speak. But we don't think that if all four months were done in one month, that all 200 ducks 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 just say that as a normal rate of converting the ducts to producing in 2025, we see a two to two and a half BCF increase from the Hainesville as gas prices improve. So that speaks to what we think will happen with these ducts and normal rig rate of 35 to 40 rigs.
spk06: Okay, thanks. That's helpful. And then turning to the springboard three 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 SQL oil prices and NGLs potentially would be beneficial in some ways. So is there a movement in that direction at all, or are these all pretty dry gassed?
spk01: So for the springboard, the mix is fairly even between oil NGLs and gas, you know, a third, a third, a third roughly.
spk03: Yeah, keep in mind that there's 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 zero NGLs, but you're going to see the gas volumes multiplied by whatever the price is times 1.4 versus times 1, right? So you see a mixture of, you know, not just the volumes, but in some cases, right, the way you report it is you don't count the NGL volumes, but you count better pricing on the gas because of the way that these operators pay you. which is common and happens to, you know, they treat everybody the same, right? So it's not nuanced to us. They treat every vendor or holder the same way.
spk06: And, yeah, you're saying it has to do with the way it's treated sort of from a, I don't know, accounting or billing or invoicing, billing, whatever type situation, but it's not reflective of are they 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 into that scalar, right? Okay. So then my last question, if I can just get one more in, was just, we talk 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 MGL infrastructure. And so I'm just kind of curious, When natural gas prices are so low, all else equal, and particularly if oil prices are doing all right, then that can motivate more NGL extraction or ethane rejection or not doing ethane rejection. Are there any developments there or new plants coming out, 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.
spk02: 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, in 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 two to three to four 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. that are building NGLs out there. And so 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 two to three years. We don't really watch that as closely. But there is a, from a macro perspective, there's gonna 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 the NGLs.
spk06: So just to make sure I'm kind of understanding correctly, my, my putting together of the kind of different data points here is that there could be potentially some increase in like the NGO mix that would come from say the springboard three contribution, but not something to do with like a additional processing capacity or anything along those lines that would impact you guys in terms of, um, the mix of NGLs, and then what you could see based on, Chad, your comments just now, would be more just potentially pricing benefit from the kind of more macro dynamic. Is that right?
spk02: Yeah, if I understand your question, when you say NGL mix, just quickly, the purity products coming off the NGL barrel are ethane, propane, two 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 for gas price, dollar per m and BTU. 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 stream 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 NGO barrel out of the scoop increase? Probably, but 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?
spk06: Okay. Got it. Thank you. That's helpful. All right. I'll take the rest of my questions offline.
spk07: Thanks. Thank you. And we have reached the end of the question and answer session. I'll now turn the call back over to Chad Stevens for a closing remark.
spk02: 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 Steeple Cross-Sector Insights Conference that will be hosted in Boston on June 4th and 5th. 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 Think IR. We look forward to hosting our next call in early August to discuss our second quarter 2024 results. Have a nice day.
spk07: And this concludes today's conference and you may disconnect your lines at this time. Thank you for your participation.
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