PHX Minerals Inc.

Good morning, and thank you for attending today's PHX Minerals December 31st, 2023 year-ended earnings conference call. At this time, all lines will be muted during the presentation of the call with an opportunity for a Q&A session at the end. As a reminder, this call is being recorded. I would now like to turn the call over to Stephen Lee with FNK IR. Thank you. Please go ahead.

Thank you, and good morning. Thank you for joining us today to discuss PHX Minerals, December 31st, 2023 annual results. Joining us on the call today are Chad Stevens, President and Chief Executive Officer, Ralph D'Amico, Senior Vice President and Chief Financial Officer, and Danielle Mezzo, Vice President of Engineering. The earnings press release that was issued yesterday after the close is also posted on PHX Investor Relations website. Before I turn the call over to Chad, I'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 quality reports on Form 10Q or other reports filed with the Securities and Exchange Commission. The statements made during this call are based upon information known to PHX as of today, March 13, 2024, and the company does not intend to update these forward-looking statements, whether as a result of new information, future events, or otherwise, unless required by law. With that, I would like to turn the call over to Chad Stephens, PHX Chief Executive Officer. Chet?

Thanks, Stephen, and thanks to all of you on this call for participating in PHX's December 31st, 2023 fiscal year-end earnings conference call. We appreciate your interest in the company. I am pleased to report another strong year for PHX. We delivered a 23% increase in royalty volumes, expanded our 2P royalty reserves by 12%, and generated significant operating cash flow as well as net income. This performance enabled us to increase our quarterly dividend by 33%, reflecting our confidence in our business strategy and ability to continue to generate consistent cash flows. I'm especially pleased of these accomplishments despite another challenging year in the natural gas market. This demonstrates the value of our risk mitigated business model as we can deliver strong profitability even during a period of challenging pricing. During the past year, PHX deployed more than 30 million to acquire nearly 2,400 net royalty acres in the Hainesville and Scoot Plays. The acquisition of these high-quality minerals will further drive our royalty volumes, margin expansion, and cash flow over the course of the next two to three years. We continue to maintain modest leverage backed by a strong balance sheet, and our M&A activity is built on proven processes focused on high-quality minerals that can convert to production quickly. With our strong financial position and a highly focused acquisition strategy, we are poised to unlock value for our shareholders as the commodity pricing environment improves. In the fourth quarter, PHS continued to experience robust activity on our mineral acreage, which Danielle will discuss in more detail in a moment. We are encouraged by the quarter's well-in-progress inventory, which stands at an all-time high for the company, including ducts, whips, and permits. The number of rigs present on PHX and its surrounding acreage remains strong. This provides good visibility for our production growth in the coming quarters. I direct you to our latest IR slide deck posted last night that explains in detail the pace of operator development on our minerals and our inventory of undrilled locations. It is this inventory that fuels the development that drives our year-over-year royalty volume growth. As natural gas prices touched a four-year low last month, we began to see natural gas-focused E&Ps begin reducing budgets deferring well completions into the future awaiting better prices the latest being eqt which announced two weeks ago they are curtailing one bcf a day of production at least through march and cnx yesterday announced they are deferring completion of a number of wells and curtailing their current production until natural gas prices improve despite slower industry-wide development activities We are expecting a 4% increase in royalty volume and 2% increase in total corporate volumes in 2024, speaking to the quality of our assets. Please reference our press release and corporate presentation for our full 2024 guidance. With reduced drilling and production activities just discussed, and the expected increases in demand from new LNG export facilities coming online in 2024 and 2025, We believe this will balance the market and improve commodity prices as we move forward. At this point, I'd like to turn the call over to Danielle to provide a quick operational overview and then to Raoul to discuss the financials.

Thanks, Chad. And good morning to everyone participating on the call. For our year-ended December 31st, 2023, total corporate production decreased 3% from the year-ended December 31st, 2022. And for the quarter-ended December 31st, 2023, increased 4% from the December 31st, 2022 quarter. Recall that calendar 2022 includes 100% of the working interest volumes in the Arcoma and Eagleford, which we sold in January of 2023. Performer for the divestiture, we would have seen an increase in total corporate volumes on an annual basis. As we move forward, it will be easier to compare period over period volumes as we are effectively done with our working interest divestitures. Working interest volumes now represent only 10% of total corporate volumes. This will become an even smaller percentage as working interest production continues to decline and royalty volumes continue to grow. 79% of our last quarter's production volumes were natural gas, which aligns with our long-term position that natural gas is the key transition fuel for a sustainable energy future. Oil represented 11% of production volumes, and NGL represented 10%. Annual royalty production for 2023 increased 23% to 8,123 MMCFE, and quarterly royalty production increased 19% from the year-ago quarter to 1,946 MMCFE, respectively. The volume growth over the last 12 months is a result of the successful execution of our mineral acquisition program. It is important to note that as a mineral holder, we do not control timing on well development, so there can be some volatility on a quarter-to-quarter basis, and volumes associated with our business model are better evaluated on a rolling 12-month basis. Production volumes associated with our non-op working interest decreased 59% for the year due to the sales of our Arcoma and Eagleford assets and decreased 49% compared to the year-ago quarter for the same reason. Note that we are not participating in new working interest wells, so our non-op working interest volumes will continue to decrease due to its natural decline rate relative to our total volumes and become less relevant to the business. Royalty volumes represented 87% of total production during our December 31st, 2023 quarter, and 87% for the full 2023 calendar year. 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, which Ralph will talk about shortly. We have high-graded our asset base which provides a much stronger collateral base with which to support our bank credit facility. Our total approved reserves decreased 11% to 71.2 BCFE with a PV10 of 110 million at SEC pricing, primarily as a result of the sales of our legacy non-operated working interest assets. We continue to execute our corporate strategy to exit this portion of our business, which we have consistently messaged since 2020. As we have divested of these non-op working interest assets, we have redeployed the proceeds into our mineral acquisition program, which has contributed to our improved margins and inventory of undeveloped drilling locations. At December 31, 2023, our approved royalty reserves increased 9% to 57.8 BCFE, with a PV10 of $97 million at SEC pricing. And our undrilled development inventory mentioned earlier by Chad and which we categorize as probable reserves increased 13% to 99.6 BCFE with a PV10 of 157.9 million. These undrilled probable reserves are undeveloped locations that have been identified by rigorous geologic and engineering analysis and offset existing producing wells. The only uncertainty is regarding the timing of development by the operator. Given that our minerals are located in the core of our focus areas with top-tier rock quality under reputable and highly active operators, we are confident these undeveloped locations will ultimately be converted to producing, resulting in increasing royalty volumes and robust reserve replacement. During the quarter ended December 31, 2023, third-party operators active on our mineral acreage converted 46 gross or 0.098 net wells-in-progress or WIPs to producing wells. For the full 2023 calendar year, third-party operators active on our mineral acreage converted 314 gross or 1.034 net whips to producing wells, compared to 313 gross or 1.15 net in calendar 2022. The majority of the new wells brought online are located in the Hainesville and the Scoot. We are very pleased with our well conversion rates, particularly given the challenging nature given the challenging natural gas macro environment, which includes some operators deferring bringing completed wells online until there is an improvement in natural gas prices. At the same time, our inventory of wells in progress on our minerals, which includes ducts, wells being drilled, and permits filed, increased on a net basis to 263 gross, or 1.295 net wells, compared to the 278 gross, or 1.09 net wells, reported as of September 30, 2020. 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. In addition to our WIPs, we regularly monitor third-party operator rig activities in our focus areas and observed 14 rigs present on PHX Minerals acreage as of February 12, 2024. Additionally, we had 57 rigs active within 2.5 miles of PHX ownership. In summary, we continue to see steady development in both our legacy and recently acquired mineral assets, which should lead to annually increasing royalty volumes. Now 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 a reminder, we changed our fiscal year in December of 2022 from a 12-month year ended September 30th to a December 31st fiscal year. The 10-K filed yesterday reflects the new December 31st year end. For our fourth quarter ended December 31st, 2023, natural gas, oil, and NGL sales volumes decreased 4% to $8.5 million compared to the prior sequential quarter, due primarily to a slight decrease in production volumes of 4%, partially offset by a modest 1% increase in realized prices. For the full year 2023 calendar year, natural gas, oil, and NGL sales revenues decreased 49% to 36.5 million. Breaking down this number further, royalty production volumes actually increased 23%, offset by a 59% decrease in working interest production volumes compared to calendar 2022, primarily due to the sale of the Eagleford and Arcoma properties, which we closed in January of 2023. Additionally, realized commodity prices decreased 47% on an MCFE basis to $3.90 in 2023 compared to $7.33 in calendar 22. Realized natural gas prices averaged for the quarter end of December 31st, 2023 were $2.53 per MCFE for the full 2023 calendar year, Realized natural gas prices were $2.61 per MCFE. Realized oil prices averaged $78.66 and $76.76 per barrel for the quarter and full year, respectively. NGLs averaged $24 and $22.18 per barrel for the quarter and full year, respectively. Realized hedge gains for the quarter were $275 and $2.6 million for the quarter and the full year, respectively. For the quarter and full calendar year, respectively, approximately 44% and 46% of our natural gas, 36% and 42% of our oil, and none of our NGL production volumes were hedged at average prices of $335 and $353 per MCF, and $74.91 and $70.96 per barrel. Approximately 50% of our anticipated full-year 24 natural gas production at the midpoint of our guidance has downside protection at approximately $3.45 per MCF. On the oil side, approximately a third of our anticipated production at the midpoint of our guidance has downside protection at approximately $65.15 per barrel. We structure our natural gas hedges using both swaps and costless collars, which means we also have upside exposure on certain volumes to the $45 range. Our current hedge position is available in our recently filed 10K. Total transportation, gathering, and marketing increased 36% on a sequential quarter basis to $946,000, primarily due to a large percentage of new volumes coming from cost-bearing leases compared to the prior quarter when a higher percentage of the new volumes came from cost-free leases. For the full calendar year, these transportation expenses decreased 40% to $3.7 million, primarily due to the sales of our higher-cost working interest assets in the Eagleford and the Arcoma. Production and ad valorem taxes increased 4% on a sequential quarter basis to approximately $457,000 due to higher production in Louisiana, which applies its tax rate to production volumes and not revenues. For the full calendar year production, an ad valorem tax has decreased 42% to $1.9 million, again, primarily due to the sales of the higher cost working interest assets in the Eagleford and Arcoma. LOE associated with our legacy non-operated working interest wells decreased 12% on a sequential quarter basis to $319,000. For the full calendar year, LOE decreased 57% to $1.6 million, again, due to the sales of those higher cost working interest assets. Cash G&A was up 11% to $2.5 million compared to the prior sequential quarter, primarily due to normal year-end professional fees. For the full calendar year, cash G&A decreased 4% to 9.5 million, primarily due to higher efficiencies associated with our cost control efforts. Adjusted EBITDA was 4.5 million in the quarter ended December 31st, 23, as compared to 6.3 million in September 30th, 2023 quarter. For the full 2023 calendar year, Adjusted EBITDA was 22.7 million compared to 26.7 million in calendar 22. The 15% decrease in annual EBITDA is despite an actual 47% decrease in realized commodity prices and the sale of the two working interest assets in January of 23. Net income for the quarter was 2.5 million or 7 cents per diluted share compared to net income of 1.9 million or $0.05 per diluted share for the prior sequential quarter. For the full calendar year, 2023 net income was $13.9 million or $0.39 per diluted share compared to net income of $17.1 million or $0.48 per diluted share. We had total debt of $32.75 million as of December 31, 2023, compared to $33.3 million as of December 31st, 22. Our debt to trailing adjusted EBITDA was 1.5, 1.45 as of December 31st, 23. Since implementing our new minerals only strategy in 2020, we have high graded our asset and improved our cash margins while reducing the leverage metrics of the company. Our now high quality undeveloped location and inventory will serve as the catalyst to grow reserves and royalties in the future. Our strategy to manage leverage is influenced by our view of the macroeconomic climate and the opportunities set before us, with projected leverage in the most draconian economic environment never to be above 2.0 times. Our hedge position, as discussed above, helps protect our strong balance sheet while providing upside exposure. We manage the risk based on a mid-price cycle, assuming a low price range for natural gas of $1.75 to $2.50, and a high price range of $4.50 to $5. With that, I'll turn the call over to Chad for some final remarks.

Thank you, Ralph. As I commented in my opening remarks, we are very pleased with our achievements during 2023, despite the challenging macro environment. The dramatic collapse in natural gas prices has had a material impact on natural gas focus E&P's development activities, especially in the Hainesville and Marcellus. As a mineral operator, we will also be impacted by this. However, our business strategy is to acquire minerals in the core of our focus area with near-term development potential. This can be seen by our expected royalty volume growth in 2024, despite the various headwinds. Put another way, we are structured to generate solid and consistent cash flows, even during challenging times due to our focused risk-mitigated approach. With a strong and conservative balance sheet, we will continue to be proactive in our mineral acquisition, further enhancing shareholder value in the future. To recap our progress and achievements, we have built a portfolio of new, high-quality assets with improved cash margins over the last four years. a mineral interest in a deep inventory of undeveloped drilling locations that has and will continue to drive increasing royalty volumes in cash flow. Danielle talked earlier about PV10 value of our proved and probable reserves. In this regard, I direct you to slide seven of our newly posted IR presentation that reflect a total 2P PV10 reserve value at current NIMAC strip prices of close to $300 million. If natural gas prices return to a more normal mid-price cycle, that PV10 value would be dramatically higher. We also show in the appendix of our IR presentation the timing of new LNG export capacity from the Gulf Coast. Once in service, this will help bring natural gas prices into that mid-price to possibly upper range and increase our royalty production volumes and cash flow. Since 2020 and to date, we have spent $130 million acquiring our current mineral position in the Scoop and Haynesville. THX's current enterprise value is roughly $145 million, with a reserve value I mentioned earlier of at least $300 million. We recognize the disconnect between these facts and our current stock price. We continually work every day searching for the best way to reward our shareholders and close this conundrum by increasing shareholder value. The company continues to make notable progress only through the hard work of our dedicated employees and the keen wisdom provided by our board. So in closing, I thank them for their efforts. We look forward to keeping you updated. This concludes the prepared remarks portion of the call. Operator, please open up the queue for questions.

Thank you. Ladies and gentlemen, the floor is now open for questions. If you would like to ask a question, please press star 1 on your telephone keypad at this time. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. Once again, that's star 1 to register a question at this time. Today's first question is coming from Nate Pendleton of Stifel. Please go ahead.

Good morning. Can you provide some color on what you're seeing on the ground regarding wells being turned to production in the Hainesville? And how have you incorporated that into your 2024 guidance?

Hey, Nate, it's Ralph. Yeah, I mean, you know, obviously everybody's seen the announcements from, you know, Chesapeake and some others about slowing down the pace of development, right? We continue to see activity where, in some cases, you know, they'll permit a well where they will bring a rig on location, set casing, and get the surface ready, and then sort of move that well off location and move it to someplace else, right? So to us, that really indicates that, you know, again, they're taking a temporary pause, right? But, you know, they have every intention of, at some point... you know, in a better pricing environment of circling back and, you know, and finish drilling and completing those wells and putting them on sales. And we've also seen a few wells where the well has actually been completed. You can see the report on the Louisiana State website. It's just a matter of the operator not wanting to turn the well on and get all that flush production, you know, sold at current prices, right? So... You know, we think as, you know, prices sort of get back approaching $3, right, and if you follow the curve, that's probably towards the second half of this year, those volumes will start coming back online. And so our guidance and sort of what we anticipate is incorporates all of that, right? So you're still seeing a pretty strong conversion number. It's just more geared towards the second half of the year than it is the first half of the year.

Got it. I appreciate the detail, Ralph. And can you share any updated thoughts on future prices, specifically for natural gas, given that it seems you've added hedges during the quarter for 2025 and 2026?

Yeah, I mean, you know, obviously we continue to be optimistic on gas prices. I mean, in the long term, you know, it is the key fuel for energy transition. And certainly these LNG projects that, you know, despite what the government announced in terms of slowing down permitting, that slowdown in permitting doesn't affect any of these projects that are coming online in the next 18 months plus, right? So we think those volumes are going to come online and or those projects will come online and they're going to need new volumes. Having said that, you know, when you look at the forward curve, And you see $3.50, you know, $4 during winter, right? Our view is we want to lock in some of those prices, right? Nobody has a crystal ball. And, you know, and so if we lock down a good percentage of our volumes at that price, we think those are reasonable prices. And if prices go above that, you know, it means that development's going to be accelerated on our other locations, which are not hedged at this point since they're not producing, right? So to us, it's a nice balance of locking in attractive pricing and still getting, you know, still having a lot of exposure to higher prices if they go above $4.

So, and Nate, this is Chad. So just a couple of data points for you. In December, uh gross u.s domestic natural gas production hit an all-time high of 105 bcf a day today with the curtailments that i discussed in my my comments that's right now about 100 bcf a day gross and going down given all the announced curtailments cutbacks uh lack of of activity capex cuts so that's going down and then with lng um all of the known projects that are in construction as we speak and targeted to be in service toward the end of 24, but much more materially in the first and second quarter of 2025, that's 9 BCF per day of additional LNG export capacity on top of the 13 BCF a day that's existing. So we're going to have over 20, approaching 2022 BCF a day of LNG export capacity by mid- 2025, which we feel like will more than balance the market at a gross production of 100 plus or minus a little bit, 100 BCF a day, and should lift prices into what we talked about, reference kind of a mid-price cycle for 450, maybe possibly $5 MCF NYMEX. So we're optimistic that mid-25, the market's going to be balanced.

Got it. Thanks for taking my questions.

Thank you. The next question is coming from Charles Mead of Johnson Rice. Please go ahead.

Good morning, Chad, to you and your whole team there. I appreciate your recitation of some of what the public operators have done, CNX most recently, but also ECT and Chesapeake. I suppose this is a little bit along the lines of the previous question. Can you give us insight into either what you – into what the private operators in the Hainesville are doing, either from what you can kind of observe through regulatory filings or perhaps if you've had any communication from those operators?

Yeah, we have a lot of minerals underneath Athon, which is a private – private equity-backed company based in Dallas, and they were really the one that, back in 2018, 2017 and 18, really unlocked the technology to make the Haynesville what it is today. And they really slowed their rolls, so to speak. I'm not sure the number of rigs they've dropped, but they've really cut back their completions, curtailing their production, just like the public operators. So we're seeing a similar behavior on the private equity just based on what they're doing and what we see they're doing.

Got it. That's helpful. And that's a little more difficult part of the market for us to observe. And then going back to some of your prepared comments about that you're still going to grow royalty volumes. We know that the Haynesville, it's flat down. And so the other piece implies, or I think it implies, that you're still seeing a lot of activity on your scoop and stack assets. So I wonder if you could talk about that side of the asset portfolio, what you're seeing with trends on operators there, whether more in the north, more in the south, what kind of targets, and anyone in particular who's really ramping activity.

Yeah, and Charles, to speak to that specifically, I do want to comment. It's an interesting dynamic in the Haynesville area. over the year over year from this time last year in March, when you think about it, January, February, March of 2023, gas prices fell off a cliff. And it was really beginning in March that the rig activity really collapsed. But if you look at, uh, rig counts in the Hainesville this time last year, it was over 30 in excess of 30, um, proximal to our, we, we follow rigs in and around our area. And it was in excess of 30 rigs within a couple of miles of our minerals and our activity. And today, that's dropped by about a third to around a little over 20 rigs in and around our place. Then you look at the rigs on our minerals, and it's relatively flat year over year. So our actual percent market share, as we call it, has actually gone up because the gross rig count's gone down, but the rig activity on our minerals has gone up. And that just speaks to the quality So that's one reason we will report a modest year-over-year increase in our natural gas royalty volumes because of that. Also, there's two areas of the scoop that we focus on. One of the more active operators is Continental. They're very efficient in the way they file permits, and within a few weeks of filing a permit, they get a rig on and start drilling a well. They're very efficient in that way, and we follow them. So they've continued to run a couple of rigs in the scoop areas that we're focused on. So we're, again, because they're so consistent and efficient in their execution, implementation and execution, we're confident that with their behavior with the rig count in and around our minerals, that's helping drive the year-over-year royalty volume growth at least a modest single digit for this year, given where natural gas prices are.

Got it. That's helpful. Added detail. Appreciate it.

And the one other thing, you know, one quick thing, Charles. I mean, it's interesting in the mid-con, right? I mean, aside from all the private guys like Continental 89, Citizen, Charter Oaks, Newborn, all those guys who are currently drilling on us, there's a number of public guys who are also drilling on us today. They don't like to advertise it because they also have assets in the Permian, and they prefer to talk about their Permian assets. But, you know, the way we look at it is the wells they're drilling on our minerals in Oklahoma have to compete on a return standpoint to the Permian, otherwise it wouldn't be drilling it. So they may not talk about it, but they sure are spending money in drilling those wells, and we benefit from that. And I think that's something that's generally overlooked just because, you know, they choose not to talk about the scoop and the stack in other areas of Oklahoma. But that's a factor that does happen, we pay attention to, and it is beneficial to us.

Thank you, Ralph.

Thank you. The next question is coming from Jeff Gramp of Alliance Global Partners. Please go ahead.

I had a capital allocation question. question for you um as we look into 24 you know given your hedge book as well as the high margin royalty model um it seems like you guys will still have you know a decent chunk of some discretionary free cash flow post dividend what's the appetite for acquisitions in this market and how would you kind of compare contrast or balance um you know presumably some lower pricing along with you know making sure you're not going over your skis from a liquidity and leverage standpoint

That's a good question, Jeff. Yeah, look, I mean, I think you can look at last spring as sort of a, you know, sort of as an example of what we did. You know, last spring, natural gas prices also dropped, right? And there was a big bid-ask spread between what sellers of minerals were looking for and what, you know, we were willing to pay for them. know and so i think if you look at this year it's probably going to be something fairly similar we've always been very disciplined and we don't change our underwriting economics or metrics or the way that we we look at acquisitions regardless of the commodity price environment um you know and so if prices if if what sellers are willing to sell minerals for if it comes down right then great we can execute on that if it doesn't come down what we generally do is what we did last year. We continue to build liquidity and wait for prices to come our way. The good news is, as Chad mentioned, we have an inventory of over 2,000 gross locations that are very high quality. That allows us to still grow our reserve volumes and our royalty production volumes without having to rely on you know, on acquisitions in the near term, right? So I would say that's the plan. We're going to be patient. And if pricing makes sense, we can acquire minerals. And if they don't, we'll build liquidity, pay down debt, and eventually the market will reach equilibrium again, just like it did last year.

Okay. I appreciate those details. For my follow-up, on the new slide deck, it looked like It might be a new slide calling out the Texas side of the Haynesville and some recent results there. Just wondering if you guys now consider that core, and maybe that's not new. You guys just wanted to shine a little bit more of a light on it, but is that an area that you guys are spending more time on than, say, 12, 24 months ago?

Yeah, we've always spent time in that area, right? I think the purpose of this slide was to kind of show that know particularly with the announcement that athon was dropping rigs and under that ami that they had with uh with blackstone right what we wanted to be able to do with this slide is differentiate the area of the uh texas side of the haynesville in which we own minerals to what you know what that ami area was right and what you can see on here is that it continues where we are it continues to be actively developed including you know, current development by Athon regardless of pricing in this area. So we were just trying to differentiate it versus what we're doing versus what's out there in the marketplace today.

And to be clear, Jeff, the Athon Blackstone AMI is along the river there between Angelina and Nacogdoches County where you see a few horizontal wells down there versus where our green minerals are up in St. Augustine and a little bit of eastern Nacogdoches where a lot of the rig activity has remained.

Great. I appreciate those details, guys. Thanks for the time.

Thank you. The next question is coming from Donovan Schaefer of Northland Capital Markets. Please go ahead.

Hey, guys. Thanks for taking the questions. I first want to ask about 2024 guidance. So in the last few calls, you've talked about how you know, now that you've mostly completed the conversion of royalty-only from working interest now to, you know, overwhelming majority being royalty-only interest, and that, you know, now that that conversion has been basically done, you'd be in this, like, a return-to-growth mode, growing the royalty-only production at a double-digit rate, and I think even in some cases you alluded to continuing the historical growth rate, which has been closer to 20% for the royalties. Obviously, the guidance at the midpoint is 4% year-over-year growth for royalties and 8% at the high end of that range. And that's, of course, below. I mean, that's not double-digit and, of course, below 20%. A lot of things are happening, certainly in the macro environment. We've already talked about a lot of that. But I'm just curious if you could – If you can talk through if the earlier views and perspectives sort of still hold and if it's really just been a matter of change in development activity or the pace. Maybe another way to put it would be if we hadn't seen such a dramatic decline in natural gas prices in the second half of January. Do you think would the guidance more likely have been somewhere? Do you think it would have hit that double-digit growth rate at a midpoint or, you know, something closer to 20%? I'm just trying to reconcile the past comments with the current situation. And if the past comments still hold, but for a more normal environment. Yeah. Hey, Donovan. Yeah.

Yeah, this is Chad. I'll answer first and then let the others maybe follow on. So again, to be clear, we've consistently messaged this, that there's two different dynamics at play when we talk about volumes. One is corporate volumes. Corporate volumes have two components, non-op working interest and royalty. And we've constantly messaged and focused on on our royalty-only volume growth, because we weren't doing anything on non-op working interest. We were divesting of non-op working interest, redeploying proceeds, using our cash flow, and buying royalty, mineral interest and royalty in these two areas. When you look at our investor relations slide deck, we highlight organic royalty production growth. We talk about it in our quarterly 10Qs and year-end, year-over-year. It's all about royalty because we're not doing anything, investing any capital, allocating any capital to non-op working interests. So that's why we continue to highlight and feel good about double-digit royalty volume growth, whatever period you're comparing. Now to what you just talked about and what we've been discussing, with natural gas prices and cash prices today are below $1.50. I think strips about $1.65 or something, but cash prices, what buyers are actually negotiating for and buying on a daily basis is below $1.50. So it's bad out there. And so the E&Ps, Chesapeake, EQT, everybody's cutting back CapEx, cutting back rigs, curtailing production. And so we have taken that into account, knowing what we know, We've taken that into account for our 2024 guidance and pulled way back on that double-digit growth to that modest single-digit growth based on what we know is going on in the Haynesville, our operators in the Haynesville and the operators in the Scoop stack. So we feel pretty good about that little single-digit 4% what we're talking about. If we hit the high end of that, great, but we feel really good about That midpoint, Ralph, I don't know if you want to add to that.

Yeah, I mean, you know, I mean, we don't operate in a vacuum, right, Donovan, right? So if operators are, if you look at what the gas guys are saying, flat to down year over year, mostly down year over year, right? I mean, we're certainly not immune to it. In a $3 pricing environment, right, you know, whenever that comes back, or if we were here today, I think the historical growth rate, based on the pace of development and the number of rigs that those operators would be running, yes, we would go back to what we've averaged over the last three years, right? But that is, you know, dependent on what the operators do, which is dependent upon what, you know, natural gas prices do. So, you know, to answer your question, yes, if you have $3 price and operators are drilling, At a similar rate, yes, our growth would return to what we've historically been able to achieve over the last three years.

Not only royalty volume growth would move back up into that double-digit range, which would then drive higher cash flow, cash flow per share, and that PV10 reserve value that I mentioned as well.

Yeah, yeah, no, there's kind of like a, there's sort of a stacked layers of variables that would drive upside. So that's great. And then as a follow up, I want to ask, I think I asked on the last call about this, but kind of just looking for an update here. The issue of associated gas coming out of the Permian or potentially other basins where, you know, in the current natural gas price environment, the gas-focused drillers are not, you know, they have an incentive to slow down, but oil prices are still at a healthy level, you know, kind of bouncing around or kind of close to $80-ish a barrel. So more oil-focused production continues, and that's going to get associated with gas. You know, I know there's a pipeline that's going to bring more of the Permian gas to markets where you sell your gas, and there's, you know, that should line up with LNG capacity coming online, but just curious if we can get any update there between the last four months or so since the last call.

Again, when you look at the U.S. natural gas market and the supply and demand dynamics, there's really three main areas that are driving the overall growth in natural gas supply. One, Marcellus pretty much right now as we speak capped there's no more capacity coming out of the basin all the pipelines are full so as those operators announced their capex budgets year-over-year everything all their production announced production is relatively flat and as EQT is indicated they're going to actually be curtailing but overall there's no new material volumes coming out of the Marcellus to feed increase in demand from LNG. Then you've got the Haynesville, which has huge growth year over year and can grow at a pretty fast clip with those big wells that are being drilled throughout the overall Haynesville Basin. And then recently announced, as you alluded to, in the Permian Associated Gas, Kinder Morgan has a new project there. It's actually being built as we speak and is going to add half a BCF a day of supply of Associated Gas to Other than that, most of the other or all the other pipelines coming out of the Permian Basin are pretty much full. So you're only having a half a BCF a day of incremental increase to be in service by end of the year or early first quarter of 2025 with this all this new demand, LNG demand coming. So that's again why I feel confident that overall, Um, that the market will be balanced first quarter to mid 2025 and pull, pull prices up and support support prices over the next, you know, 24 to 36 months.

Okay, great. That's helpful. And if I can just squeeze one last question and I want to ask about, um, you know, I believe, I believe it was in the inflation reduction act, but there's the proposal of, you know, a fee on methane. I kind of forget where we are in the rulemaking process or if final numbers have been established there or not, but I'm curious if you guys have done any analysis there, if it's something you've been following closely at all as to whether there is a fee. Is it at the state level where it'd have to be worked out of whether that's something that could be borne by the royalty interest owners? or if it's kind of a settled, you know, it's already settled that that would all be, you know, working interest and a royalty interest. And if you think there could be an impact on just the overall economics of natural gas with a methane fee in place. Any color there would be helpful.

So the two subjects that I try to follow, at least generally, though it's pretty complicated, are one, a carbon tax, so to speak, And there is a carbon market out there for companies who want to try to be neutral that are high emitters. So they're buying carbon credits in the carbon tax market to try to balance their emissions. But we're not an emitter, so we don't worry about that, so to speak, as a mineral owner. The methane fee is still in a legislative discussion, so it's hard to understand who would pay it, how it would work. Would the mineral owner be... burdened by it. It depends upon how the oil and gas lease reads and what sort of fees that the operator can pass through to the mineral owner through a deduction on the royalty rates that they're paying. It's so early in the game there. It's hard to really determine what the impact would be for a royalty owner.

Okay. That's helpful. Thank you, guys. I'll take the rest of my questions offline.

Thanks.

Thank you. At this time, I'd like to turn the floor back over to Mr. Stephens for closing comments.

Thank you, operator. Again, I'd like to thank our employees and shareholders for the continued support. I'd also like to note that Ralph and I will continue to expand our investor marketing activities over the coming weeks and months. Specifically, we will be participating in the KeyBank Virtual Minerals Conference on March 26, the Alliance Global Virtual Energy Conference on April 10, and the Staple Cross-Sector Insights Conference that will be hosted in Boston on June 4th and 5th. If you'd be interested in meeting at one of these events at any time, please don't hesitate to reach out to myself, Ralph, or the folks at ThinkIR. We look forward to hosting our next call in early May to discuss our first quarter 2024 results. Thank you.

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