PHX Minerals Inc. (PHX) Q1 2023 Earnings Call Transcript

PHX Minerals Inc. (NYSE:PHX) Q1 2023 Earnings Conference Call February 9, 2023 11:00 AM ET

Company Participants

Rob Fink – FNK IR

Ralph D’Amico – VP and CFO

Chad Stephens – President and CEO

Danielle Mezo – VP, Engineering

Conference Call Participants

Donovan Schafer – Northland Capital Markets

Derrick Whitfield – Stifel

Operator

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 FNK IR. Please go ahead, sir.

Rob Fink

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, Senior Vice President and Chief Financial Officer; and Danielle Mezo, Vice President of Engineering. The earnings press release that was issued today after the close is also posted on PHX’s Investor Relations website.

Before I turn the call over 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 expectation of the company.

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

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

The statements made during this call are based upon information known to company as of today, February 9th, 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 would like to turn the call over to Chad. Chad, the call is yours.

Chad Stephens

Thanks Rob, and thanks to all of you on this 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 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 US rig count has remained relatively flat over the last months, recent indications are that operators, especially in gas basins, will begin reducing their building budgets, and thus laying down rigs and frac crews, which should reduce domestic US 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.

THX 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 heads 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 and 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 owned 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.

Danielle Mezo

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 frac offsetting wells. Note that all four wells are back online and then we also own mineral interests 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 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 we’ll have more WIP 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 to 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 Eagle Ford and Arkoma working interest assets on January 31st, 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 31st, 2022 quarter and should exceed 80% in the current quarter post the Eagle Ford and Arkoma 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 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 WIP 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 2000 gross undrilled locations that will continue to feed this WIP activity. In addition to our WIP, 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 a 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 volume.

Now, I will turn the call back to Ralph to discuss financials.

Ralph D’Amico

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 generous generically referring to 12/31 period as the quarter or 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 31st, 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 average $28.77 per barrel, 24% lower.

Realized hedge losses, 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, or hedge that average price as of $3.43 and $49.27 respectively.

At the end of January 2023, the lower priced hedge contracts put in play — 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 decrease expenses, decreased 17% on a sequential quarter basis to $1.460 million. These expenses are primarily tied to movements and 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, 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 G&A 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 31st, 2022 as compared to $8.4 million in the September 30th, 2022 quarter. EBITDA was positively impacted by an 11% decrease in total cash expenses. The revenues were negative 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 will lead to the impairment. Note that given the impairment, there will not be a loss on sales associated with the asset and 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 effectively be flat on a sequential quarter-over-quarter basis.

We had total debt of $33.3 million as of December 31st, 2022 and our debt to trailing 12-month EBITDA was 1.25. As of February 2023, 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.

Chad Stephens

Thank you, Ralph. As I have repeatedly highlighted over the past two years, we continue to enhance our asset base by the vesting 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 shutdowns 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.

However, our inventory of WIPs continues to increase — 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 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 began 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 an executing our corporate strategy.

This concludes the repair prepared remarks portion of the call. Operator, please open up the queue for questions.

Question-and-Answer Session

Operator

Thank you. And at this time, we will conduct our question-and-answer session. [Operator Instructions]

Our first question comes from Donovan Schafer with Northland Capital Markets. Please state your question

Donovan Schafer

Hey, guys, thanks for taking the questions. So, I’ll admit my own my own errors here, in that I personally was forecasting a 3% quarter-over-quarter increase for this quarter. And then you guys had the 15% quarter-over-quarter decline. And I’ll just say the logic of the 3% increase was this thesis of, okay, 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 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.

And then, sort of the Haynesville wells, that’s a good explanation in the lumpiness and the timing of WIPs being turned in line. But I want to 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 grow production without necessarily spending additional money as property is getting developed. And how do I kind of reconcile that with the outlook? Because the outlook, you guys shared shows basically flat production being at the high end, so I was curious if you can talk through that?

Ralph D’Amico

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 stayed at for the last three years, right, is going to consist of growing royalty volumes, and decreasing working interest volumes, because we’re monetizing, or just allowing the working interest to deplete, right.

So, 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. So, theoretically, if we spent no money this year, right, those — there’s a high degree of certainty that we’re going to hit those numbers on the royalty side, right.

The other thing to keep in mind, and 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.

So, if you hold prices constant, right, even if total corporate vol — if you held prices cost — if even total corporate volumes do not increase. If you see the increase in in royalty volumes, right, you’re still generating additional cash flow at the corporate level, because of that difference in margin.

Chad Stephens

Just real quick to kind of rephrase what Ralph saying and make sure I’m getting, 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 have a large decline there, because there’s some sales of working interest assets, but then also even the working interests that you still have. It’s the similar phenomena 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.

Donovan Schafer

Well, so it’s the natural decline in the sale and the working interest aside. And just to be clear, also on going down 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. We try to monetize that — allow somebody else to put their money up and we get compensated for giving them that opportunity.

Ralph D’Amico

Sure. But this sort of phenomenon of owning something, acreage in the sense somewhere, and then the rig comes on to it from the working interest — when it’s a working interest situation, that’s not going to translate into additional volumes for you guys the way that — royalty generally speaking, okay. That makes sense.

Chad Stephens

And let me be clear to characterize. When we say working interest, those — 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 — drilling opportunities on those assets on that leasehold.

Most of the AFEs we do get our workovers. All wells do need to be worked over, clean out the wellbores, refrac or whatever on those existing wellbores. 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 well.

We — that’s one of the reasons we were selling these assets, they have no real growth, story of growth upside, and we want to be able to demonstrate to the market that year-over-year we can grow volumes by way of a royalty. And 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 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. And again, we can’t control it. It’s an industry practice to shut wells into frac offset wells. We have an interest in the offset wells as well. So, the four wells are back on, the new wells are producing, we have an interest in those wells. So, our volumes will be back up, but we again, we’re kind of a victim of our own success buying in high quality areas where developments going on.

Ralph D’Amico

Yes, and Donovan, one thing just to 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. So, 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 — and that well gets drilled, we actually still maintain them, the mineral and thus a royalty ownership in that new well, that generates additional cash flow from us.

So, what we’re selling is literally a wellbore 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 a effectively a wellbore working interest assignment. And if there’s any new developing those sections, we will benefit from that development through that the legacy ownership of the minerals.

Donovan Schafer

Okay. And then as a follow-up, the Haynesville shut-ins, there’s really interesting I — from when I was a petroleum engineer, I know the importance of shutting another wells to pressurize and so they don’t basically become like a magnet for adjacent tracks to get drawn into them and cause interference and all that stuff.

But I’m sure your business model, having such small sort of fractional interests, I think, 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 own, your royalty interests tend to be somewhere between, 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, 0.2% is one-tenth of 2%. But can you give us a sense of how — because I’m assuming you’re talking about four gross wells, just roughly how for gross wells can move the needle, is it impacting eight adjacencies? And then you’ve got 2% relative interest there. There’s something that kind of helped us wrap our minds around this is — sort of feels like a disconnect the idea that you have so many growth wells, the tiny fractional interests and 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 as a smaller?

Ralph D’Amico

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 we’re, that’s about the number these wells, we actually had a 4.6%, 4.7% interest in these four wells, right? Yes. Big interest wells. But also right and I think what Danielle try 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 is a set of wells, we cannot book revenue, right, until the production volume associated with a well is publicly made available, right. 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 wells online, but we cannot book that revenue, because there’s no production data available. Okay.

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 were 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’ve have consistently said over the last three years they use, you kind of have to use a 12 month period, whether it’s a rolling four quarters or year-over-year to really compared the performance because in this situation, right, there were wells that were on production, but we just couldn’t book them, right.

And now there are and now there’s that production data, and they will be booked. So that that’s what creates that sequential quarter volatility, and some are going to be in our favor. So I’m we’re going to be against this right, but they will be trued up over a 12 month period.

Chad Stephens

And I would add to that. Donovan, this Chad. The four wells that were shut in, where we have the 4% plus net revenue interest, we’re 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, will flow those volumes through the next quarter, as well as the lumpiness on these whips that we’re outputting.

Ralph D’Amico

And by the way, these, 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.

Donovan Schafer

And you said that, yes, and this is you, you had an interest in the ones that these were wells are shut into 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 there’s only one new well, that was drilled and all three had to be shut in. But so was it — 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%?

Chad Stephens

Generally speaking, so there are four wells that there were four new wells coming in, and honestly, we don’t have what our interest in those four new wells is it’s, it’s less than 4.6%. But I don’t remember off the top of my head what it is.

Donovan Schafer

Okay. Okay. All right. Thank you. I’ll take — I’d jump back in the queue.

Operator

Thank you. [Operator Instructions] Our next question comes from Derrick Whitfield with Stifel. Please state your question.

Derrick Whitfield

Good morning, all. 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?

Chad Stephens

We can so for the Haynesville more broadly. Again, as I alluded to in my comments, rig count is not dropped in the Haynesville. We’ve been kind of steady at around 75 rigs and today 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 eighth on Chesapeake they have. They’re the ones with the highest rig counts. And 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, but we don’t think it’ll impact the guidance, the outlook that we’ve provided in the queue and in our in our Investor Relations slide deck. So we’re, 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.

Ralph D’Amico

Yes, I mean, I think I think Derrick, broadly speaking, right, I mean, we’re, while the numbers haven’t seen, haven’t shown it, right. I mean, we’re sort of anticipating, maybe a 10%. Drop in the Haynesville rig count. Obviously, because we’re reporting this as a regular quarter and not a fiscal year end, we’re, 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 2023 plans. But as we’ve modeled all of our, activity, right, we’re being conservative in terms of the slowdown and pace, but Chad’s point that we believe is coming.

But to Chad’s point, right, the 2023 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

Chad Stephens

And going into 2024, assuming the 75 — 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 Haynesville.

Derrick Whitfield

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 since the bid ask spread is narrowing post the sell off?

Chad Stephens

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. 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 a 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 with deal closings so to speak.

Ralph D’Amico

Yes. I think what you see any, it’s interesting, it’s a good question, because what you saw in the last quarter, right? If you look at the know, when we even reported into September 30 quarter, we were we were doing a large volume by number of deals, right? And the deal size actually got smaller, right. And that was a phenomenon, as Chad said, have that increased competition. And, 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 meet to stay true to our return requirements.

And I think I think what we’re seeing here, 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, the smaller guys are sort of the — are sort of the mom and pops who, who are less, how do I put it? They, they require shorter periods of market therapy to be able to transact.

So, I think you’re going to see a 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 asks spread on, the average package size in that $2 million to $3 million range that, we saw at the beginning of last year, right kind of becomes more reasonably priced and we can achieve our return targets.

Ralph D’Amico

And to follow on to that, Derrick, 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 and 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 were a tiny little company. And those deals are material to our results and success. So that’s where and why we are having that same success we’ve been having.

Derrick Whitfield

And maybe Chad just the good question to build on that response, which 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?

Chad Stephens

Yes. Again, market therapy to Ralph’s point it may, may or may not take a little time, but we are optimistic that it will probably open up some more opportunities, because of value expectation.

Derrick Whitfield

Very helpful. Thanks for your time.

Ralph D’Amico

Thank you, Derrick.

Operator

Thank you. Our next question comes from Donovan Schafer with Northland Capital Markets. Please go ahead.

Chad Stephens

Hi, Don.

Donovan Schafer

Hi, 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, as you get near the end of 2023. I’m curious if you have a take or views factored in, there’s this idea that as air conditioning has become more and more — a more important part of people’s lives and air conditioning adoption becomes more widespread in the US. And then 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 have you considered or why are you not, or if not — why not considering potential for some natural gas price recovery, more towards the middle of the year? And 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?

Chad Stephens

Yes. So current prices have been impacted by hedge funds, shorting short contracts increased by 60% year-over-year, to-date. So that the Hedges — that the hedge gas 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 in their CapEx budgets. And so when those companies start hedging, the back end of the curve is suppressed as well.

So 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 1 Bcf to 1.5 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 will be a big impact. And then CapEx budgets will drop, cash flows going to be dropped or reduced. So rigs lay down, so less supply, more demand. So my guess is it will flow through, the hedge funds will get squeezed. It will 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 2023 going first quarter 2024 is my guess.

Donovan Schafer

Okay, okay. So yes, hot summer maybe does more to sort of impact storage levels or something, starting conditions up as you head into winter and not as much driving an outcome for pricing in the summertime itself.

Ralph D’Amico

Okay. One thing, let me add one thing here, right, because I think you’ve 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 in part of the strategy of switching from having this working interest component to being a pure-play minerals company is that, when you have these drop in prices, I mean, think about 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 service side, that affects LOE, it 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 there’s a mineral only company, right. We can generate pretty good returns that even $3 to $4, which is effectively what the strip shows today. So $8 gas was nice, right? But maybe $8, $10 gas wasn’t realistic, igniters $2, right. But if you look at the strip at $3 to $4, we still make a pretty good rate of return.

So I want to make sure that you understand that. I mean, we’re not sitting here hoping for higher prices to bail us out.

Donovan Schafer

Sure. Yes.

Ralph D’Amico

Businesses is — is the balance sheet super clean, and the returns are there at even $3 to $4, which is what the strip shows today.

Donovan Schafer

Okay. And then for the 2023 outlook with transportation, gathering and marketing, you have that coming down on a per Mcfe basis. So just curious, what is driving that, is or what assumptions are built in there? Is it just lower gas prices? Is that’s getting used as a fuel for compressors or what — what’s the degree of confidence and what’s driving that expectation for transportation costs?

Ralph D’Amico

It’s also a geographic location of where the production is coming from, right. There’s a lot more production closer to — it’s going to cost more to move gas in the Arkoma as an example, right, then in the Haynesville. So, it’s really associated with the working interest volumes going away that from the divestitures that we’ve made right, and continued growth into Haynesville.

Donovan Schafer

Okay, great. Well, thank you guys. I’ll take rest of my questions offline.

Chad Stephens

Sounds great. Thanks, Don.

Ralph D’Amico

Thanks.

Operator

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.

Chad Stephens

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 road shows and conference presentations aimed at expanding investor awareness. If you would be interested in meeting, please don’t hesitate to reach out to myself or Ralph or the folks who think IR. We look forward to hosting our next quarterly call in mid-May. Thank you.

Operator

Thank you. And that concludes today’s conference. All parties may disconnect. Have a great day. Thank you.