This conference call transcript was computer generated and almost certianly contains errors. This transcript is provided for information purposes only.EarningsCall, LLC makes no representation about the accuracy of the aforementioned transcript, and you are cautioned not to place undue reliance on the information provided by the transcript.
spk03: Good morning, and thank you for attending today's PHX Minerals December 31st, 2022 quarter-end 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 Rob Fink with FNKIR. Please go ahead, sir.
spk05: Thank you, Operator, and thank you, everyone, for joining us today to discuss discuss pH Minerals December 31st, 2022, quarter-end results. Joining us on the call today are Chad Stevens, President and Chief Executive Officer, Ralph D'Amico, Vice President and Chief Financial Officer, and Danielle Mezzo, Vice President of Engineering. The earnings release that was issued yesterday after the close is also posted to PHX's Investor Relations website. Before I turn over the call to Chad, I'd 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 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, it may be amended or supplemented by subsequent quarterly reports on Form 10-Q or other reports filed with the FCC. The statements made during this fall are based upon information known to the company as of today, February 9, 2023. 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. Chad, the call is yours.
spk01: Thanks, Rob. And thanks to all of you for participating in PHX's December 31st, 2022 quarter-end conference call. We appreciate your interest in the company. The decline in natural gas prices that impacted the December quarter continued into the new year. PHX's quarterly financial results reflect a 26% sequential drop in realized natural gas prices. Since then, and in the month of January alone, natural gas front month prices have dropped a further 40%, this being the largest one-month drop since 2001, 22 years ago. This precipitous drop was driven by reduced demand due to warmer weather and less power burn, along with the Freeport LNG export terminals continued in service delay. This terminal represents 2.2 BCF a day of natural gas demand. This important LNG export terminal has been out of service due to an explosion since last summer and represents over 500 BCF of total gas demand being removed from the market. We estimate this event alone represents somewhere between $1 and $2 of negative impact to the current natural gas market. This drop in prices will reduce industry cash flow, which will additionally reduce industry capital expenditures. Though the total U.S. rig count has remained relatively flat over the last months, recent indications are that operators, especially in gas basins, will begin reducing their billing budgets and thus laying down rigs and frack crews, which should reduce domestic U.S. natural gas supply by roughly one BCF per day during the year of 2023. Under a conservative assumption of weather and Freeport vacuum service, officially announced February 1st of this year, it appears that during the second half of 2023 into the 2024 timeframe, natural gas supply demand macro should reach equilibrium and set the stage for a price rebound. PHX has purposely built a strong balance sheet and maintained ample liquidity supported by our hedge book to be able to withstand the current headwinds we face. You can access our hedge schedule that is in our latest investor relations slide deck on our corporate website. Over the last three years, we have enhanced our asset base by selling mature legacy assets Specifically, we exited our relatively higher cost, lower margin, non-op working interest business. We used the proceeds from these divestitures to build a high quality core mineral position in two of the most active areas under reputable credit worthy operators who are actively drilling. These minerals we have acquired are in the core of these basins. and can be economically developed by the operators at almost any commodity price environment. We believe this will allow us to continue to report year-over-year steady royalty volume growth. Our most recent quarter underscores this as our current quarter reflects a 33% royalty volume growth over the same quarter in 2021. During the quarter, we closed on $14.7 million of mineral acquisitions, and since the quarter end, we have closed on or signed binding agreements for an additional approximately $7 million. Our deal flow remains robust, and our disciplined approach evaluating each opportunity remains in place, and I am confident we can continue to build shareholder value. At this point, I would like to turn the call over to Danielle to provide a quick operational overview and then to Raoul to discuss the financials.
spk00: Thanks, Chad, and good morning to everyone participating on the call. For our December 31st, 2022 ended quarter, total production decreased 15% from the prior sequential quarter to 2,215 MMCFE. However, year over year, our royalty volumes increased by 33%. This volume growth is a result of our successful mineral acquisition program on which we have been executing for the last three years. Quarterly, royalty production decreased 12% sequentially. This decrease was primarily a result of two factors, the first being four wells in the Haynesville where we have a high royalty interest that were temporarily shut in to frack offsetting wells. Note that all four wells are back online and that we also own mineral interest in the offsetting pad that was being fracked. These volumes will be reflected in the next few quarters. Secondly, the timing of new wells turned to sales. Let me give some additional color to what I mean by timing of new wells turned to sales. When comparing sequential quarters, volumes can be lumpy due to timing within the quarter of when each new wells production is introduced. Thus, new wells with partial quarters are the culprit. As I will discuss in a moment, our active wells in progress, or WIPs, are the source of new well volumes. And some quarters will have more WIPs completed and turned to sales than other quarters. As a result, the lumpiness is smoothed out when you compare annual volumes. As a mineral owner, we do not control timing of well development, which rests with each operator. As such, there can be some reported volume volatility on a quarter-to-quarter basis. On the working interest side, production volumes declined 22% sequentially to 587,330 MMCFE in the December 31st, 2022 quarter as a result of the sale of our legacy Fayetteville working interest wells in late September 2022, and the natural decline of reserves. Note that the working interest volumes will also decrease in the next quarter as we closed on the sale of our legacy Eagleford and Arcoma working interest assets on January 31, 2023. This is consistent with our stated strategy to exit this part of our business. Royalty volumes represented 73% of total production during our December 31, 2022 quarter and should exceed 80% in the current quarter post the Eagleford and Arcoma divestitures. As recently as calendar year 2021, royalty volumes were only 45% of our total volume. As we have grown our royalty volumes and divested of our non-op working interest, the quality of our asset base is enhanced with improving margins. Additionally, 75% of our quarterly 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. During the quarter ended December 31st, 2022, Third-party operators active on our minerals acreage converted 60 gross or 0.27 net wells in progress or WIPs to producing wells, compared to 49 gross or 0.22 net WIPs converted to PDP in the quarter ended September 30, 2022. The majority of the new wells brought online are located in the Scoop and the Hainesville. At the same time, our inventory of wells in progress remained consistent at 203 gross or 0.83 net wells, compared to the 172 gross or 0.85 net wells reported as of September 30, 2022. The continued track record of well conversions and replenishment of the Inventory of Wells in Progress, or WIPs, shows the repeatability of our business strategy. Additionally, we have mineral interests under a deep inventory of approximately 2,000 gross undrilled locations that will continue to feed this WIP activity. In addition to our WIPs, we regularly monitor third-party operator rig activities in our focus areas, and observed 22 rigs present on PHX minerals acreage as of January 17th. Additionally, we had 91 rigs active within 2.5 miles of PHX ownership. The number of active rigs on our mineral acreage has stayed consistent quarter over quarter despite the recent decrease in natural gas prices. In summary, we continue to see steady development on both our legacy and recently acquired mineral assets, which should lead to annually increasing royalty volumes. Now I will turn the call back to Ralph to discuss financials.
spk02: Thanks, Danielle, and thank you to everyone for being on the call today. As we shared in our last quarterly call, we are transitioning to a calendar year reporting schedule this year to bring us in line with the rest of our public peers and to make it easier for our business and reporting results to be evaluated. With that, on today's call, I'll be generically referring to 1231 period as the quarter or the quarter end of 1231. Natural gas, oil, and NGL sales revenues decreased 32% on a sequential quarter basis to a total of $14.9 million. This decrease is attributable to the 15% lower production volumes, as discussed by Danielle, and 20% lower realized prices during the December 31, 2022 quarter. Realized natural gas prices averaged $5.66 per MCF. 26% lower than the prior sequential quarter. Realized oil prices averaged $82.52 per barrel, 12% lower, and NGLs averaged $28.77 per barrel, 24% lower. Realized hedge losses for the quarter were 3.8 million. For the quarter, approximately 65% of our natural gas, 57% of our oil, and none of our NGL production volumes were hedged at average prices of $3.43 and $49.27, respectively. At the end of January 2023, the lower priced hedge contracts put in place during the height of COVID have officially expired. Approximately 40% of our anticipated 2023 natural gas production has downside protection at between $3.15 and $3.45 per MCF. On the oil side, approximately 68% of our anticipated production has downside protection between approximately $71 and $75 per barrel. Our current hedge book is available in both the 10-Q and our corporate presentation. Total transportation, gathering, and marketing expenses decreased 17% on a sequential quarter basis to $1,460,000. These expenses are primarily tied to movements in production volumes. Production taxes decreased 34% on a sequential quarter over quarter basis to approximately $618,000. These expenses are primarily tied to movements in both production volumes and commodity prices. LOE associated with our legacy non-operated working interest wells increased 6% on a sequential quarter basis to $1 million. While the LOE from the sale of our legacy Fayetteville assets sold in September 2022 came off the books, we experienced an increase in LOE associated with our working interest oil production into Eagleford. Note that the Eagleford asset sale closed on January 31, 2023. And we expect a significant decrease in LOE for the coming quarters. We only have 563 legacy non-operated working interest wellbores remaining in our portfolio. And those on average have lower fixed LOE than the wellbores that we have sold over the prior 12 plus months. Cash GNA was flat at 2.6 million compared to the prior sequential quarter. and would have been slightly lower had we not incurred the costs associated with terminating our ATM program. Adjusted EBITDA was $5.3 million in our quarter ended December 31, 2022, as compared to $8.4 million in the September 30, 2022 quarter. EBITDA was positively impacted by an 11% decrease in total cash expenses, but revenues were negatively impacted by 25%, mainly pulled down by the drop in natural gas prices, as we pointed out. The non-cash impairment of $6.1 million was associated with held-for-sale accounting associated with our Coma properties. The sales price is lower than our book value for the assets, which led to the impairment. Note that given the impairment, there will not be a loss on sales associated with the asset in the upcoming quarter. The Eagleford, on the other hand, had a sales price higher than its book value, which will lead to a non-cash gain in the upcoming quarter. Net income for the quarter was $3.34 million compared to $9.2 million for the prior sequential quarter. Note that this includes a non-cash impairment I just spoke about, which means that backing that out and that income would have effectively be flat on a sequential quarter over quarter basis. We had total debt of 33.3 million as of December 31st, 22. And our debt to trailing 12-month EBITDA was 1.25. As of February 23, pro forma for closing of the working interest sales, our total debt was 23 million. And we had cash on hand of approximately 2.5 million. Lastly, our asset portfolio has been high-graded with improved development visibility. And in an effort to improve transparency and better communication with investors, we have made the strategic decision to provide an operational outlook for calendar year 2023. This is the first time in the history of PHX in which an annual outlook has been issued. We estimate 2023 royalty production to grow approximately 20% at the midpoint of the range compared to calendar 2022. Key expense metrics are expected to remain flat on a per unit basis, and LOE is expected to significantly decline pro forma the sales of the working interest assets we closed on January 31st. A detailed summary can be found in both our press release and our corporate presentation. With that, I'd like to turn the call over to Chad for some final remarks.
spk01: Thank you, Ralph. As I have repeatedly highlighted over the past two years, we continue to enhance our asset base by divesting of mature, non-core, non-op working interest wellbores and reinvesting the proceeds into high-quality minerals in our areas of focus. This provides us with a clear path to annual volume growth. However, as Danielle reported, royalty production in the quarter was impacted by a short-term disruption in the Haynesville due to temporary shut-ins of a few high-interest wells to accommodate crack completions on a set of offsetting wells, a common industry practice. And fewer new wells coming online due to typical seasonal volatility or lumpiness, as also explained by Danielle a moment ago. However, our inventory of WIPs continues to increase, giving us an increase in near-term rebound in reported volumes and our long-term prospects. Results were also impacted by lower commodity prices, but our strong balance sheet and success in divestiture of working interest continues to help us navigate near-term headwinds. We are bullish on our recovery in natural gas prices in the second half of 23 going into 2024 as short-term impacts dissipate. Additionally, I'm also pleased to announce that given the confidence in our strategy and the steady conversion of our inventory, or the WIPs, we have the visibility to begin providing an annual outlook, which you can access on our investor relations presentation from our corporate website. As you can see, despite the current natural gas price headwinds, our strategy is sound, and we expect increasing loyalty volumes in 2023. Our pipeline for acquisitions continues to be robust, but to be sure, we will maintain during the downturn in natural gas prices the same level of technical and economic discipline we have used over the last three years. I believe 2023 will be a tremendous year for PHX, its employees, and its shareholders. I would like to thank our dedicated employees for their hard work and congratulate them on our achievements today. Additionally, I would like to thank our board of directors for their support and insightful wisdom they provide in executing our corporate strategies. This concludes the prepared remarks portion of the call. Operator, please open up the queue for questions.
spk03: Thank you. And at this time, we will conduct our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star followed by the number 2 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 a star key. Once again, to ask a question, press star 1. We'll pause for a moment while we pull up a question. Our first question comes from Donovan Schaefer with Northland Capital Markets. Please state your question.
spk04: Hey, guys. Thanks for taking the questions. So I'll admit my own errors here in that I personally was forecasting a 3% quarter-over-quarter increase for this quarter, and then, you know, you guys had the 15% quarter-over-quarter decline. And I'll just say, you know, the logic I had for the 3% increase was this thesis of, okay, you know, we're hitting this inflection point with companies zeroing in on kind of key locations and the acreage clusters that you guys have, and so we should start to see a sort of pick up from this we've talked about before this embedded growth where you've laid the chips on the table and then as you know activity picks up um and then you know so the haynesville wells um that's you know a good explanation in the lumpiness and the timing of whips being turned in line but i want to check myself on just the broader thesis here of this this sort of embedded growth Should we still expect this idea of there being embedded growth where the chips are on the table and you can continue to even, you know, grow production without necessarily spending additional money as properties get developed? And how do I kind of reconcile that with the outlook? Because, you know, the outlook you guys shared shows basically flat production being at the high end. So just curious if you can talk through that.
spk02: So Donovan, I think you're confusing, it's Ralph, I think you're confusing a couple of things, right? So total corporate production, which we've stated for the last three years, right, is going to consist of growing royalty volumes and decreasing working interest volumes because we're monetizing, we're just allowing the working interest to deplete, right? Royalty volumes are actually, if you look at the midpoint of the guidance, are actually expected to grow 20% on a year-over-year basis. The majority of those volumes are going to be accounted from wells that we already own the minerals underneath and they're currently being worked on or PDP already. So theoretically, if we spent no money this year, there's a high degree of certainty that we're going to hit those numbers on the royalty side. The other thing to keep in mind, and this is very important, a molecule of working interest is generally worth half of a molecule of royalty volumes. Because on average, that royalty volume has twice the cash flow margin as the working interest molecule. So if you hold prices constant, even if total corporate volume, if you held prices constant, Even if total corporate volumes do not increase, if you see the increase in royalty volumes, right, you're still generating additional cash flow at the corporate level because of that difference in margin.
spk04: Right. Okay. So just real quick to kind of rephrase what Ralph is saying and make sure I'm getting it. So if I'm just looking at the outlook table, this idea of like an embedded growth where the chips have been set on the table and the rigs move on. You're seeing that embedded growth on the royalty side for the outlook and on the working interest side, it makes sense that you, you have a large decline there because, um, you know, there's, there's some sales of working interest assets, but then also even the working interests that you still have. Um, if the, if the similar phenomenon we're playing out where rig comes on and whatever you guys are also actually. electing to go non-consent on those. So then you're not actually even participating in those anyway either, right? So that's kind of what's being reflected there.
spk02: Well, so it's the natural decline and the sale on the working interest side. And just to be clear also on ongoing non-consent, generally speaking, whenever somebody proposes an AFE, we try to monetize that AFE and create value for the company. So I don't think that you can make the blanket statement that we just go non-consent. You know, we try to modify that value and allow somebody else to put their money up, and we get compensated for giving them that opportunity.
spk04: But this sort of phenomenon of owning something, you know, acreage in a sense somewhere, and then the rig comes onto it from the working interest, and when it's a working interest situation, that's not going to translate into additional volumes for you guys the way that it would for royalty, generally speaking. Okay. Yeah.
spk01: Let me be clear. When we say working interest, when we say mature assets, they mature in the sense that they've been fully developed. There's really no consistent high-quality drilling locations or drilling opportunities on those assets on that leasehold. Most of the AFEs we do get are workovers. Old wells do need to be worked over clean out the well bores, refract or whatever on those existing well bores. But to be clear, what we're selling has no real true upside growth from a working interest perspective from operators coming in to drill wells. That's one of the reasons we're selling these assets. They have no real growth story or growth upside, and we want to be able to demonstrate to the market that year over year we can grow volumes by way of of royalty. So speaking of growing royalty volumes, this quarter over quarter drop, to be clear and to highlight it, we're a victim of our own success because this particular four set of wells that was shut in, we had a very high net revenue interest, royalty interest in those four wells. And again, we can't control it. It's an industry practice to shut wells in to frack offset wells. We have an interest in the offset wells as well. The poor wells are back on. The new wells are producing. We have an interest in those wells, so our volumes will be back up, but again, we're kind of a victim of our own success buying in high-quality areas where development's going on.
spk02: Yeah, and Donovan, one thing just to kind of finish off the point. Most of the working interests, aside from the Eagleford, right, The prior management teams participated as a working interest owner through their mineral ownership. So what you actually have the ability to do, and in the rare case that somebody comes to drill a well adjacent to it where you still own minerals, even if we choose not to participate on that well, we actually, and that well gets drilled, we actually still maintain the mineral and thus a royalty ownership in that new well. generates additional cash flow from us. So what we're selling is literally a well-bore and leasehold interest, right? And we're retaining the minerals and the royalties associated with all that acreage, right? So I want to be crystal clear about this. We are very cognizant about creating value and not giving away any value. So when we're selling this, it is effectively a well-bore working interest assignment. And if there's any new development in those sections, we will benefit from that development through the legacy ownership of the minerals.
spk04: Okay. And then as a follow-up, the Hainesville shut-ins there is really interesting. From when I was a petroleum engineer, I know the importance of shutting in other wells so they're pressurized and so they don't basically become like a magnet or adjacent tracks to get drawn into them and cause interference and all that stuff. But for your business model, having such small sort of fractional interests, I think it mentally creates just a little bit of a disconnect even for myself that the idea of four wells in the Hainesville having such a large impact when you own... your royalty interests tend to be somewhere between, you know, a fraction of a single percentage point to maybe up to two percentage points. And I realize that can be a factor of 10 difference, you know, 0.2% is, you know, one tenth of 2%. But can you give us a sense of how, because I'm assuming you're talking about four gross wells, you know, just roughly how four gross wells can, move the needle, you know, is it impacting, you know, eight adjacencies, and then you've got, you know, 2% royalty interest there? Is this something that kind of helps us wrap our minds around this? It sort of feels like a disconnect, the idea that you have so many gross wells, but tiny fractional interest, so then how do four wells being shut in really move the needle? And then another question there is just do the adjacent wells that you also have an interest in are those also high royalty interest? Is it higher or is it smaller?
spk02: No, no, no. So on these, it's a good question. So on average, if you look at the corporate presentation and you look at our average NRI per well, I think it's in the 0.6 to 0.7%, right? And if, or that's about the number. These wells, we actually had a, 4.6 4.7 percent interest in these four wells right yeah okay big interest wells but but also right and i think what danielle tried to get to on the call is that there are two factors right that's one of the factors the second factor is so for example right there there is a set of wells uh um We cannot book revenue until the production volume associated with a well is publicly made available. And operators, and this is a state regulation, have X amount of time. Some of them have six months to report production data. So there are instances where we know the well is online, but we cannot book that revenue because there's no production data available. So on a quarter to quarter basis, here's what happens, right? And some of it happened in this quarter, which is there are wells that were online, right? But there's no production data. And fast forward to today, right? Some of those wells literally started reporting production data or last or this week, right? Within the last couple of days. So what ends up happening is you have that lumpiness that we talked about. So The volumes that should have been reported last quarter will be reported in this 331 quarter. And so on a quarter-to-quarter basis, some quarters are going to be high, some quarters are going to be low, and that's why we have consistently said over the last three years that you kind of have to use a 12-month period, whether it's a rolling four quarters or year-over-year, to really compare the performance because in this situation, There were wells that were on production, but we just couldn't book them. And now there's that production data, and they will be booked. So that's what creates that sequential quarter volatility. And some are going to be in our favor. Some are going to be against us. But they will be trued up over a 12-month period.
spk01: And to add to that, Donovan, this is Chad. The four wells that were shut in where we have the 4-plus percent net revenue interest, were relatively new wells completed last fall. So they're still high up on their decline curve and their volumes are very high. So it was a perfect storm of events that caused this quarter over quarter reduction. Those wells are back online. We'll flow those volumes through the next quarter as well as the lumpiness on these whips that Ralph was just talking about.
spk02: And by the way, these four wells with the high interest have been some of the best wells or best assets that we have purchased in the last three years.
spk04: And you said that you had interest in the ones that these four wells are shut in to allow adjacent wells to be completed and that you had interest in those. The adjacent wells, if this is a pad, I can see it being a case where maybe it was just, maybe it was only one new well that was drilled and all three had to be shut in. But so was it one well, two wells, three wells? How many wells were being completed that led to the four shut-ins? And are these also like 4.7% royalties?
spk02: These had development, generally speaking. So there are four wells. There were four new wells coming in. And honestly, we don't have what our interest in those four new wells is. It's less than 4.6%. But I don't remember off the top of my head what it is.
spk04: Okay, okay. All right, thank you. I'll jump back in the queue.
spk03: Thank you. And a reminder to everyone to ask a question, press star 1 on your telephone keypad. To remove yourself from the queue, press star 2 on your telephone keypad. Our next question comes from Derek Whitfield with Stiefel. Please state your question.
spk06: Good morning, all. Hey, Derek. Hey, Derek. With regard to your 23 outlook, could you speak to the expected trajectory for production for the year and your activity assumptions for the Hainesville more broadly?
spk01: So for the Hainesville more broadly, again as I alluded to in my comments, rig count has not dropped in the Hainesville. We've been kind of steady at around 75 rigs and To date, we haven't seen any reduction. We try to buy out in front of the drill bit in these areas, the core areas where the rock is the best. Some of the operators were under Chesapeake. They're the ones with the highest rig counts, and those rigs that they're running, they haven't reduced the rig counts yet. We're anticipating some sort of reduction. We don't know what that is, but we don't think it'll impact the guidance, the outlook, that we've provided in the queue in our investor relations slide deck. So we're confident. We're confident because of the quality of the minerals we've acquired out in front of the drill bit, so to speak.
spk02: Yeah, I mean, I think, Derek, you know, broadly speaking, right, I mean, while the numbers haven't seen it, haven't shown it, right, I mean, we're sort of anticipating, you know, maybe a 10% drop in the Hainesville rate count. You know, obviously, because we're reporting this as a regular quarter and not a fiscal year end, we're the lucky recipients of having to go first, right? So a lot of the public guys haven't yet come out with their 23 plans. But as we've modeled all of our, you know, activity, right, we're being conservative in terms of the slowdown in pace. But to Chad's point, that we believe is coming, but to Chad's point, right, the 23 volumes are the majority of which are spoken for by wells in progress, right? So that's already been started. So even if you lay down a rig today, you assume they're not going to stop drilling the well in the middle of drilling it to lay it down, right? So we're pretty confident about those numbers.
spk01: And going into 24, assuming the current 75 rig count remains constant, Almost half those rigs are within a two and a half mile proximity to PHX minerals. So again, we feel the outlook for 2024 volumes look pretty good in terms of our market share of the overall rig count in the Hainesville.
spk06: Terrific. And maybe for the follow-up, shifting over to the M&A environment, I wanted to ask if you guys could speak to the broader environment for minerals in light of the selloff in natural gas, particularly the next call it 18 months of the curve. And if you sense the bid-ask spread is narrowing post the selloff.
spk01: Well, we were seeing as we moved through kind of Thanksgiving and going into December, a lot of money moving in, especially private equity money, moving into the Hainesville, both on the Louisiana and Texas side. And our partners who are out on the ground helping us acquire these minerals, we're seeing some increase in competition, a little rise in prices. And now with this, as I characterized in my comments, this precipitous drop in natural gas prices, over the last few days our discussions with our boots on the ground, so to speak, Obviously, our valuations have come down a little bit, and the mineral owners who are selling are still expecting the same prices that were being paid a couple of months ago, and so there's going to be probably a time period here where there's a little market therapy, so to speak, but we're still able to, some of the stuff we're acquiring right now at, again, our overall economic analysis we're able to transact on, but we are seeing some disruption in deal closings, so to speak.
spk02: Yeah, I think what you see, and it's interesting, it's a good question, because what you saw in the last quarter, right, if you look at the, you know, what we even reported in the September 30th quarter, we were doing a a large volume by number of deals, right? And the deal size actually got smaller, right? And that was a phenomenon, as Chad said, of that increased competition. And, you know, to maintain the rates of return, we kind of started doing a lot more of the smaller deals to deploy the same amount of capital, right? To stay true to our return requirements. And I think what we're seeing here, you know, January and February is the same thing, right? You kind of have to You're sticking to the smaller stuff because, again, it takes time for that market therapy, as Chad said, to work its way through. And so the smaller guys are sort of the mom and pops who are less – how do I put it? They require shorter periods of market therapy to be able to transact. So I think you're going to see a smaller – smaller average deal size in the 331 quarter, right? And then we sort of get back to normal as we move forward as that bid-ask spread on, you know, the average package size in that $2 to $3 million range that, you know, we saw at the beginning of last year, right, kind of becomes more reasonably priced and we can achieve our return targets.
spk01: And to follow on to that, Derek, The smaller deals are really our bread and butter, our kind of sweet spot. We're a little bit below the radar. The larger private equity firms with a lot of money are looking for much bigger deals, the $20 million to $25 million to $50 million deals. And the $1 million, $2 million, and $3 million deals, we're a tiny little company, and those deals are material to our results and success. So that's where and why we are having the success we've been having.
spk06: And maybe Chad, just a question to build on that response. Would you further suggest that the environment for the smaller deals is better now than it was maybe a quarter ago, two quarters ago? Or do you have the expectation that it could be?
spk01: Yes. Again, market therapy, to Ralph's point, it may or may not take a little time, but we are optimistic that it'll probably open up some more opportunities because of value expectation.
spk06: Very helpful. Thanks for your time.
spk03: Thank you, Derek. Thank you. Our next question comes from Donovan Schaefer with Northland Capital Markets. Please go ahead.
spk04: Hey, Donovan. Hey, guys. Okay. So, glad I'm able to get another couple ones in here. So, one question I have on natural gas prices and kind of your outlook for expecting equilibrium, you know, to get near the end of 2023. I'm curious if you have a take or if you've factored in, you know, there's this idea that as air conditioning has become more and more, you know, a more important part of people's lives and air conditioning adoption becomes more widespread in the US. And then, you know, if you take climate change and hotter temperatures, you can actually have an increase in natural gas demand in the middle of summer. I'm wondering, is that something you, like when you, I'm wondering, you know, have you considered or why are you not, or if not, you know, why not considering potential for some natural gas price recovery more towards the middle of the year? I mean, we saw a bit of that in 2021. I think we saw some of that in 2022, but of course it's complicated by the invasion in Russia and so forth. But do you see the potential for increased power burn through the summer if we were to, say, get a very hot summer?
spk01: Yeah. So current prices have been impacted by hedge funds shorting. Short contracts increased by 60% year over year. today. So the hedges, the hedge guys shorting from a financial perspective have had a huge negative impact on prices as well as on top of that kind of a self-fulfilling prophecy, larger E&Ps as prices started dropping, they started hedging more to protect their cash flows and their CapEx budgets. And so when those companies start hedging, the back end of the curve is suppressed as well. Those two events, again, just kind of, as I said, a self-fulfilling prophecy. That being said, we're still dependent upon weather, but not as much as we were once Freeport is back in service. And once that 2.2 BCF a day comes back online, we're probably currently, with that online, maybe one to one and a half BCF a day oversupplied. But once, if we have a warmer than normal summer, And if prices stay where they are, two more dynamics. Coal-to-gas switching for power burn, as you just alluded to. Natural gas is much cheaper than coal right now, so coal-to-gas switching will increase natural gas power burn. So that'll be a big impact. And then CapEx budgets will drop. Cash flow's going to be reduced. So rigs will lay down. So less supply, more demand. So my guess is it'll flow through, the hedge funds will get squeezed. It'll flow through going into the third and fourth quarter this year. Prices will start being uplifted coming into the winter. Worried about a cold winter. So we'll see the price dynamic improve. 23 going into the first quarter, 24 is my guess.
spk04: Okay, okay. So yeah, a hot summer maybe does more to sort of impact storage levels or something. setting conditions up as you head into winter and not as much driving an outcome for pricing in the summertime itself.
spk02: Let me add one thing here, right? Because I think you touched on something that's important, right? I mean, we can generate pretty good free cash flow even in the $3 to $4 range, right? I think the beauty of and part of the strategy of switching from having this working interest component to being a pure play minerals company is that you know, when you have these drop in prices, I mean, think about, you know, think about, you know, on the working interest side, right? I mean, even on our non-op that we reported, right? Our margins get squeezed even more because you have the impact of inflationary pressures coming from the services side that affects LOE, affects rate costs, et cetera, et cetera, right? That affect the working interest side of things way more than the mineral side of things. And as a mineral-only company, right, we can generate pretty good returns at even $3 to $4, which is effectively what the strip shows today. So, you know, $8 gas was nice, right? But maybe $8, $10 gas wasn't realistic. Neither is $2, right? But if you look at the strip at $3 to $4, we still make a pretty good rate of return. You know, so I want to make sure that You know, you understand that. I mean, we're not sitting here hoping for higher prices to, you know, to bail us out. Sure. The balance sheet is super clean, and the returns are there at even $3 to $4, which is what the strip shows today.
spk04: Okay. And then for the 2023 outlook with transportation gathering and marketing, you have that coming down on a per MCFE basis. I'm just curious, what is driving that? What assumptions are built in there? Is it just lower gas prices, if that's getting used as a fuel for compressors? What's the degree of confidence and what's driving that expectation for transportation costs?
spk02: It's also geographic location of where the production is coming from. There's a lot more production closer to... It's going to cost more to move gas into your coma, as an example, right, than into Haynesville. So, you know, it's really associated with the working interest volumes going away from the divestitures that we've made, right, and continued growth into Haynesville.
spk04: Okay, great. Well, thank you, guys. I'll take the rest of my questions offline. Sounds great.
spk03: Thanks, Eric. Thank you. And we have reached the end of the question and answer session. And I will now turn the call over to Chad Stevens for closing remarks.
spk01: Again, I'd like to thank our employees and shareholders for the continued support and hard work. I'd also like to note that Ralph and I will continue to expand our investor marketing activities over the coming weeks and months through a series of non-deal roadshows and conference presentations aimed at expanding investor awareness. If you would be interested in meeting, please don't hesitate to reach out to myself, Ralph, or the folks at Fink IRR. We look forward to hosting our next quarterly call in mid-May. Thank you.
spk03: Thank you. And that concludes today's conference. All parties may disconnect. Have a great day. Thank you.
Disclaimer