Good morning, 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 FNK IR. Please go ahead, sir. Thank you, operator, and thank you everyone for joining us today to discuss PHX Minerals December 31st, 2022 quarter-end results. Joining us on the call today are Chad Stephens, President and Chief Executive Officer, Ralph D'Amico, Vice President and Chief Financial Officer, and Danielle Mezo, 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, may be amended or supplemented by subsequent quarterly reports on Form 10-Q or other reports filed with the SEC. The statements made during this call are based upon information known to the company as of today, February 9th, 2022. 2023, excuse me. 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. Thanks, Rob, and thanks to all of you on the call 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 terminal's 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 drilling budgets and thus laying down rigs and frac crews, which should reduce domestic U.S. natural gas supply by roughly 1 Bcf per day during the year of 2023. Under a conservative assumption of weather and Freeport back in 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 use 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 Ralph to discuss the financials. Thanks, Chad, and good morning to everyone participating on the call. For our December 31, 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 frac offsetting wells. Note that all four wells are back online, and that we also own mineral interests in the offsetting pad that was being frac'd. These volumes will be reflected in the next few quarters. The timing of new wells turn to sales. Let me give some additional color to what I mean by timing of new wells turn 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 WIP, are the source of new well volumes, and some quarters will have more WIP completed and turn 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 31, 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 Eagle Ford and our Arkoma 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 Eagle Ford and our Arkoma divestitures. As recently as calendar year 2021, royalty volumes were only 45% of our total volumes. As we have grown our royalty volumes and divested of our non-op working interests, 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 WIP, to producing wells, compared to 49 gross or 0.22 net WIPs converted to PDP in the quarter ended September 30th, 2022. The majority of the new wells brought online are located in the SCOOP and the Haynesville. 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 30th, 2022. The continued track record of well conversions and replenishment of the inventory of wells in progress, or WIP, 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 observe 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. I will turn the call back to Ralph to discuss financials. 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 reported results to be evaluated. With that, on today's call, I'll be generically referring to 12/31 period as the quarter where the quarter ended 12/31. 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 in the Eagle Ford. Note that the Eagle Ford asset sale closed on January 31st, 2023, we expect a significant decrease in LOE for the coming quarters. We only have 563 legacy non-operated working interest well bores remaining in our portfolio, those on average have lower fixed LOE than the well bores that we have sold over the prior 12-plus months. Cash G&A was flat at $2.6 million compared to the prior sequential quarter 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. The 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 Arkoma 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 Eagle Ford, 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, net income would have effectively be flat on a sequential quarter-over-quarter basis. We had total debt of $33.3 million as of December 31, 2022, 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. 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. 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 well bores and reinvesting the proceeds into high quality minerals in our areas of focus. This provides us with a clear path to annual volume growth. 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 frac 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. Our inventory of WIP continues to increase, giving us in a near-term rebound in reported volumes and our long-term prospects. Results were also impacted by lower commodity prices. Our strong balance sheet and success in divestiture of working interest continues to help us navigate near-term headwinds. We are bullish on a recovery in natural gas prices in the second half of 2023 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 royalty 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 to date. Additionally, I would like to thank our board of directors for their support and insightful wisdom they provide in executing our corporate strategy. This concludes the prepared remarks portion of the call. Operator, please open up the queue for questions. Thank you. At this time, we will conduct our 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 that your line is in the question queue. You may press star followed by 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 keys. Once again, to ask a question, press star one. We'll pause for a moment while we pull for questions. Our first question comes from Donovan Schafer with Northland Capital Markets. Please state your question. Hey, guys. Thanks for taking the questions. 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 have had the 15% quarter-over-quarter decline. I'll just say, you know, the logic as 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. We should start to see a sort of pickup 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. You know, the Haynesville wells, that's, you know, a good explanation in the lumpiness and the timing of WIP being turned in line. I wanna check myself on just the broader thesis here of 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? How do I kinda reconcile that with the outlook? 'Cause, you know, the outlook you guys shared shows basically flat production being at the high end. Just curious if you can talk through that. Donovan, it's Ralph. I think you're confusing a couple things, right? Total corporate production, which we've stated for the last three years, right, is gonna consist of growing royalty volumes and decreasing working interest volumes because we're monetizing or 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, right? 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, right, already. Theoretically, if we spent no money this year, right, there's a high degree of certainty that we're gonna hit those numbers on the royalty side, right? The other thing to keep in mind, this is very important, right? A molecule of working interest is generally worth half of a molecule of royalty volumes, right? Because on average, that royalty volume has twice the cash flow margin as the working interest molecule. If you hold prices constant, right? 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. Right. Okay. This makes it... Just real quick to kinda rephrase what Ralph is saying and make sure I'm getting it. 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. On the working interest side, it makes sense that you have a large decline there because, you know, there's some sales of working interest assets. Also even the working interests that you still have, if the similar phenomenon were playing out where rig comes on and whatever, you guys are also actually electing to go non-consent on those. You're not actually even participating in those anyway either, right? That's kinda what's being reflected there. Well, so there it's the natural decline in the sale on the working interest side. Just to be clear also on going non-consent. Generally speaking, whenever somebody proposes an AFE, we try to monetize that AFE and create value for the company. I don't think that you can make the blanket statement that we just go non-consent. you know, we try to monetize that value. Allow somebody else to put their money up, and we get compensated for giving them that opportunity. Sure. but this sort of phenomenon of owning something, you know, acreage in a sense somewhere, and then the rigs 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. No. It would for royalty, generally speaking. Okay. All right. That makes sense. Yeah. Yeah. Let me be clear to characterize. 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 wellbores, re-frac or whatever on those existing wellbores. To be clear, what we're selling has no real true upside growth from a working interest perspective. Right. from operators coming in to drill wells. We. That's one of the reasons we're selling these assets. They have no real growth story or growth upside, and we wanna be able to demonstrate to the market that year-over-year, we can grow volumes by way of royalty. 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 we, this particular four set of wells that was shut in, we had a very high net revenue interest royalty interest in those four wells. Again, we can't control it. It's an industry practice to shut wells in to frac offset wells. We have an interest in the offset wells as well. The four wells are back on. The new wells are producing. We have an interest in those wells. Our volumes will be back up. Again, we're kind of a victim of our own success buying in high-quality areas where development's going on. Yeah. Donovan, one thing just to kind of finish off the point. Most of the working interests aside from the Eagle Ford, right? The prior management teams participated as a working interest owner through their mineral ownership. What you actually have the ability to do, 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... That well gets drilled, we actually still maintain the mineral and thus a royalty ownership in that new well that generates additional cash flow from us. What we're selling is literally a wellbore and leasehold interest, right. We're retaining the minerals and the royalties associated with all that acreage, right. I wanna be crystal clear about this. We are very cognizant about creating value and not giving away any value. When we're selling this, it is effectively a wellbore working interest assignment. If there's any new development in those sections, we will benefit from that development through the legacy ownership of the minerals. Okay. As a follow-up, the Haynesville shut-ins there is really interesting and, you know, From when I was a petroleum engineer, I know the importance of, you know, shutting in other wells so they're pressurized, and so they don't, you know, basically become like a magnet for adjacent fracs to, you know, get drawn into them and cause interference and all that stuff. For your business model, having, you know, such small sort of fractional interest, I think it mentally creates just a little bit of a disconnect, even for myself, that the idea of four wells in the Haynesville having such a large impact when, you know, 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. I realize that can be a factor of 10 difference, you know, 0.2% is, you know, one-tenth of 2%. Can you give us a sense of how. 'Cause 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 kinda help us wrap our minds around this? It sort of feels like a disconnect, the idea that you have so many gross wells with tiny fractional interest, so then how do four wells being shut in really move the needle? Another question there is just do the adjacent wells that you also have an interest in, are those also high royalty interests? Is it high or is it a smaller? No, no. It's a good question. 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? That's about the number. These wells, we actually had a 4.6%, 4.7% interest in these four wells, right? Wow. Yeah. Okay. These were big interest wells. 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... For example, right? There is a set of wells, We cannot book revenue, right, until the production volume associated with a well is publicly made available, right? Operators, and this is a state regulation, have X amount of time. Some of them have six months to report production data. There are instances where we know the well is online, but we cannot book that revenue because there's no production data available. Okay? On a quarter-to-quarter basis, here's what happens, right? Some of it happened in this quarter, which is there are wells that were online, right, but there's no production data. Fast-forward to today, right, some of those wells literally started reporting production data or this week, right, within the last couple of days. What ends up happening is you have that lumpiness that we talked about. The volumes that should have been reported last quarter will be reported in this 3/31 quarter. 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, right, there were wells that were on production, but we just couldn't book them, right? Now there's that production data, and they will be booked. That's what creates that sequential quarter volatility. Some are gonna be in our favor, some are gonna be against us, right? They will be trued up over a 12-month period. To add to that, Donovan, this is Chad. The four wells that were shut in, where we have the 4%+ net revenue interest, were relatively new wells completed last fall. They're still high up on their decline curve, and their volumes are very high. 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 WIPs that Ralph was just talking about. Yeah. 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. You said that, you know, and this is 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, you know, if this is a pad, I can see it being a case where, you know, maybe it was only one new well that was drilled and all three had to be shut in. 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% royalty interests? They're in a pad development, generally speaking. 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. Okay. Okay. All right. Thank you. I'll jump back in the queue. Thank you. A reminder to everyone, to ask a question, press star one on your telephone keypad. To remove yourself from the queue, press star two on your telephone keypad. Our next question comes from Derrick Whitfield with Stifel. Please state your question. Good morning, all. Hey, Derrick. Hey, Derrick. With regard to your 2023 outlook, could you speak to the expected trajectory for production for the year and your activity assumptions for the Haynesville more broadly? For the Haynesville more broadly, again, as I alluded to in my comments, rig count has not dropped in the Haynesville. We've been kinda steady at around 75 rigs, 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 Aethon, Chesapeake. They have, they're the ones with the highest rig counts, they're 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, we don't think it'll impact the guidance, the outlook that we've provided in the Q and in our investor relations slide deck. We're confident. Yeah. We're confident because of the quality of the minerals we've acquired out in front of the drill bit, so to speak. Yeah. I mean, I think, Derrick, you know, broadly speaking, right, I mean, while the numbers haven't shown it, right, I mean, we're sort of anticipating, you know, maybe a 10% drop in the Haynesville rig 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? A lot of the public guys haven't yet come out with their 23 plans. As we've modeled all of our, you know, activity, right, we're being conservative in terms of the slowdown in pace. To Chad's point. That we believe is coming. To Chad's point, right, the 23 volumes are the majority of which are spoken for by wells in progress, right? That's already been started. Even if you lay down a rig today, you assume they're not gonna stop drilling the well in the middle of drilling it to lay it down, right? We're pretty confident about those numbers. Going into 2024, assuming the current 75 rig count remains constant, almost half those rigs are within a 2.5 mile proximity to PHX Minerals. Again, we feel the outlook for 2024 volumes look pretty good in terms of our market share of the overall rig count in the Haynesville. Terrific. Maybe for the follow-up, shifting over to the M&A environment, wanted to ask if you guys could speak to the broader environment for minerals, in light of the sell-off in natural gas, particularly the next, call it 18 months of the curve. If you sense the bid-ask spread is narrowing post the sell-off. 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 Haynesville, both on the Louisiana and Texas side. 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. 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. The mineral owners who are selling are still expecting the same prices that were being paid a couple of months ago. There's gonna be a probably a time period here where there's a little market therapy, so to speak. 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. We are seeing some disruption in deal, with deal closings, so to speak. 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 large volume by number of deals, right? The deal size actually got smaller, right? That was a phenomenon, as Chad said, of that increased competition. You know, to maintain the rates of return, we kinda started doing a lot more of the smaller deals to deploy the same amount of capital, right? To stay true to our return requirements. I think what we're seeing here, you know, January and February is the same thing, right? You're sticking to the smaller stuff because again, it takes time for that market therapy, as Chad said, to work its way through. you know, the smaller guys are sort of the you know, are sort of the mom-and-pops who, you know, who are less How do I put it? they require shorter periods of market therapy to be able to transact. you know, I think you're gonna see a smaller average deal size in the 3/31 quarter, right? 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 million-$3 million range that, you know, we saw at the beginning of last year, right? Kinda becomes more reasonably priced and we can achieve our return targets. To follow on to that, Derrick, the smaller deals are really our bread and butter, our kinda 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. That's where and why we are having the success we've been having. 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? 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. Very helpful. Thanks for your time. Thank you, Derrick. Thank you. Our next question comes from Donovan Schafer with Northland Capital Markets. Please go ahead. Hey, Donovan. Hey, guys. Okay, glad I'm able to get another couple ones in here. One question I have on natural gas prices and kinda your outlook for expecting equilibrium, you know, as we 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 U.S. 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. You know, do you see the potential for increased power burn through the summer if we were to, say, get a very hot summer? Yeah. Current prices have been impacted by hedge funds shorting. Short contracts increased by 60% year-over-year to date. 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. When those companies start hedging, the back end of the curve is suppressed as well. Those two events, again, it 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. Once that 2.2 Bcf a day comes back online, we're probably currently with that online, maybe 1 Bcf- 1.5 Bcf a day oversupplied. 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. That'll be a big impact. CapEx budgets will drop. Cash flow's gonna be reduced, rigs will lay down. Less supply, more demand. 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. We'll see the price dynamic improve 2023, going into first quarter of 2024 is my guess. Okay. Okay. Yeah, any hot summer maybe does more to sort of impact storage levels or something, setting conditions up as you head into winter, not as much driving an outcome for pricing in the summertime itself. You know. Okay. One thing. Let me add one thing here, right? 'Cause I think you touched on something that's important, right? I mean, we can generate pretty good free cash flow even in the $3-$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, 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 rig costs, et cetera, right? That affect the working interest side of things way more than the mineral side of things. As a mineral only company, right, we can generate pretty good returns at even $3-$4, which is effectively what the strip shows today. You know, $8 gas was nice, right? Maybe $8-$10 gas wasn't realistic, neither is $2, right? If you look at the strip at $3-$4, we still make a pretty good rate of return. You know, so I wanna make sure that, you know, you understand that. I mean, we're not, we're not sitting here hoping for higher prices to, you know, to bail us out. Sure. Business is up, and also the balance sheet's super clean, and the returns are there at even $3-$4, which is what the strip shows today. Okay. For the 2023 outlook with transportation, gathering, and marketing, you have that coming down on a per Mcfe basis. Just curious, what is driving that? You know, what assumptions are built in there? You know, is it just lower gas prices if that's getting used as a fuel for compressors? Or, you know, what's the degree of confidence and what's driving that expectation for transportation costs? It's also the geographic location of where the production's coming from, right? There's a lot more production closer to, you know, it's gonna cost more to move gas into Arkoma, as an example, right, than into Haynesville. 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. Okay, great. Well, thank you guys. I'll take the rest of my questions offline. Sounds great. Thanks. 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 Stephens for closing remarks. 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 FNK IR. We look forward to hosting our next quarterly call in mid-May. Thank you. Thank you. That concludes today's conference. All parties may disconnect. Have a good night.