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Good morning, and thank you for attending today's PHX Minerals March 31, 2023 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.
And I would now like to turn the call over to Rob Fink with FNK, IR. Thank you, Rob. Please go ahead, sir.
Thank you, operator, and thank you, everyone, for joining us today to discuss PHX Minerals March 31, 2023 quarter end results. Hosting the call today are Chad Stephens, President and Chief Executive Officer; Ralph D’Amico, Senior Vice President and Chief Financial Officer; and Danielle Mezo, PHX's Vice President of Engineering. The earnings press release that was issued yesterday 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 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 the call are based upon information known to PHX as of today, May 10, 2023. 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 all that said, I'd now like to turn the call over to Chad. Chad, the call is yours.
Thanks, Rob, and thanks to all of you on this call for participating in PHX's March 31, 2023, quarter end conference call. We appreciate your interest in the company and are pleased with the financial results we reported yesterday.
The first quarter results demonstrated the value creation potential inherent in our minerals-only business model. We generated a significant improvement in adjusted EBITDA even on lower realized commodity prices as we navigate through the current period of extraordinarily weak commodity prices and its impact on the industry. This improvement in financial performance reflects the benefits of higher royalty volumes, which have much better cash flow margins than working interest volumes and a decrease in LOE and other cash expenses as we divested non-op working interest assets.
With higher margins, our model enables us to materially reduce risk and generate cash even when commodity prices are low. We believe we will see an improvement in commodity prices, especially natural gas in the second half of the year as supply and demand imbalances improve, even if commodity prices remain depressed, we believe there are near-term opportunities for further growth in our asset base, as demonstrated by our encouraging results this quarter.
Rig counts in the Haynesville dropped approximately 15% during the quarter from 76 to 64 rigs, but rig activity on PHX acreage went up from 10 in January to 14 at the end of the quarter. This is an encouraging sign for us, and it demonstrates the rigor and discipline we have employed in identifying, evaluating and securing minerals in the best rock quality and areas of highest drilling activity.
We have consistently spoken about our efforts to high grade our asset base and we now have a portfolio of highest quality projects, which should be the last to slow down in a commodity downturn. We think we are seeing that dynamic play out in the Haynesville and Scoop.
Operators in our core focus areas are converting locations to cash flowing wells at a slightly higher pace this year versus last year, even with the lower commodity prices. We can continue to convert cash proceeds from selling non-operating assets into acquisitions to build our minerals portfolio as well as prudently manage our leverage.
We completed a little over $10 million in acquisitions during the quarter, adding to our royalty asset base for future periods with greater emphasis on the scoop and continue to see ample deal flow. Of note, our debt balance declined versus the December quarter, reflecting the positive cash flow generation of our model as well as flexibility in capital deployment.
At this point, I'd 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 March 31, 2023 ended quarter, total production increased 12% from the prior sequential quarter to 2,482 MMcfe. Quarterly royalty production increased 29% sequentially to 2,094 MMcfe, a quarterly company record. This increase was primarily a result of new wells in the Haynesville, Scoop and Bakken being put on production.
The majority of which were purchased as undeveloped locations as part of our acquisition strategy. This is a clear indication of our successful execution of acquisitions ahead of the drill bit. Also note that we achieved this record royalty volume despite eight gross Haynesville wells where we have a high royalty interest experiencing intermittent production halt during the quarter due to pipeline constraints.
Had those wells been on for the full quarter, our royalty production volumes would have been even higher. We have been informed by the operator that these wells are back online at this time.
On the working interest side, production volumes declined 34% sequentially to 388.5 MMcfe in the March 31, 2023 quarter. As a result of the sale of our legacy Eagle Ford and Arkoma working interest wells on January 31, 2023; and the natural decline of the working interest reserves.
Note that working interest volumes will also decrease in the next quarter as the March 31, 2023 quarter had a full month of production associated with the divested assets. This is consistent with our stated strategy to exit this part of our business.
Royalty volumes represented 84% of total production during our March 31, 2023 quarter. As recently as calendar year 2021, royalty volumes were only 45% of our total volume.
Reflecting on our reported volumes over the last several quarters, you will note our total corporate volumes have remained relatively flat. This is due to the loss of volumes associated with the sale of working interest assets, offset by the gain in our growing royalty volume.
With the divestiture of our working interest assets virtually complete, we estimate our total corporate volumes, which are now 85% royalty will reflect steady growth in the coming quarters. Significantly, our corporate volumes were up by 12% despite working interest volumes being down sequentially 34% due to the sale of non-op working interest assets in January, as I discussed a moment ago.
As we have grown our royalty volumes and divested of our non-operating interest, the quality of our asset base is enhanced with improving margins. Additionally, 79% 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. Oil represented 13% of production volumes and NGL represented 8%.
During the quarter ended March 31, 2023, third-party operators active on our mineral acreage converted 117 gross or 0.46 net wells in progress or WIP, to producing wells compared to 60 gross or 0.27 net WIP converted to PDP in the quarter ended December 31, 2022. The majority of the new wells brought online are located in the Haynesville, Scoop and Bakken.
At the same time, our inventory of wells in progress remained consistent at 198 gross or 0.64 net wells compared to the 203 gross or 0.83 net wells reported as of December 31, 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 interest under a deep inventory of approximately 2,000 gross undrilled locations that will continue to feed this WIP activity.
In addition to our WIPs, we regularly monitor third-party operator rig activities in our focus areas and observed 26 rigs present on PHX Mineral acreage as of April 10. Additionally, we had 95 rigs active within 2.5 miles of PHX ownership. The number of active rigs on our mineral acreage has actually increased quarter-over-quarter despite the recent decrease in natural gas prices. We believe this is a result of owning minerals in the core of the basins in which we focus with competitive economics across various pricing environments.
In summary, we continue to see steady development on both our legacy and recently acquired mineral assets, which should lead to annually increasing royalty volumes.
Now, I will turn the call to Ralph to discuss financials.
Thanks, Danielle, and thank you to everyone for being on the call today. As a reminder, we recently changed our fiscal year to a calendar year. So when I refer to Q1, I mean March 31, ended quarter. We will file 10-Qs for the June and September quarters, and then a 10-K for the December 31 ended period.
Natural gas, oil and NGL sales revenues was decreased 20% on a sequential quarter basis to a total of $11.9 million. Breaking down this number further, royalty sales volumes decreased 4% to $10.1 million as a result of higher production volumes, but lower realized commodity prices.
Working interest sales revenues decreased 60% to $1.7 million as a result of lower production volumes associated with the divestiture of the Eagle Ford and Arkoma assets as well as lower realized commodity prices.
Realized natural gas prices averaged $3.53 per Mcf, 38% lower than the prior sequential quarter. Realized oil prices averaged $0.7601 per barrel, 8% lower, and NGLs averaged $25.18 per barrel, 13% lower.
Realized hedge gains for the quarter were $630,421. This number is inclusive of the off-market derivatives where we received, and we received total cash of $256,676. Note that, we do not have any remaining off-market derivatives associated with the 2020 COVID-induced contracts. So the accounting and the understanding of our hedge contracts going forward in our financials should be a lot easier for everybody to follow.
For the quarter, approximately 48% of our natural gas, 45% of our oil and 0% of our NGL production volumes were hedged at average prices of $4.06 and $63.10 respectively. Approximately 40% of our anticipated remaining calendar 2023 natural gas production has downside protection through hedge contracts at approximately $3.31 per Mcf.
On the oil side, approximately 55% of our anticipated remaining 2023 production has downside protection at approximately $74.92 per barrel. Most of our natural gas hedges are structured as costless collars, which means that we also have upside in those volumes to the $6 range. Our current hedge position is available in our most recently filed 10-Q.
Total transportation, gathering and marketing decreased 22% on a sequential quarter basis to $1.13 million and decreased 32% on a per unit or Mcfe basis to $0.45, primarily as a result of our non-op working interest divestitures in the Eagle Ford and Arkoma, which had much higher per unit metrics compared to our royalty assets. These expenses are primarily tied to changes in production volumes.
Production taxes decreased 6% on a sequential quarter-over-quarter basis to approximately $581,000. These expenses are primarily tied to movements in both production volumes and commodity prices. LOE associated with our legacy nonoperated working interest wells, decreased 46% on a sequential quarterly -- quarter-over-quarter basis to $546,000.
Note that the Eagle Ford and Arkoma asset sales, which closed on January 31, 2023, still had a full month of LOE as part of the quarterly results. Removing the LOE associated with those assets would have shown a quarterly LOE expense of approximately $350,000.
Cash G&A was down 11% to $2.35 million compared to the prior sequential quarter, as the prior quarter incurred costs associated with terminating our ATM program. Adjusted EBITDA was $7.74 million in the quarter ended March 31, 2023, as compared to $5.33 million in the December 31, 2022 quarter.
Adjusted EBITDA was positively impacted by higher royalty volumes, which have much better margin than working interest volumes and a 20% decrease in total cash expenses, primarily associated with the sale of our lower-margin, non-op working interest assets, while being offset by lower commodity prices. The noncash gain on sale of $4.4 million was associated with the divestiture of the Eagle Ford working interest asset.
Recall the last quarter, we had a $6.1 million impairment associated with held-for-sale accounting from our Arkoma properties. Again, note that all of these are noncash items. Net income for the quarter was $9.6 million or $0.27 per share compared to $3.3 million or $0.09 per share for the prior sequential quarter. Note that this includes the noncash gain this quarter and impairment in the prior quarter.
Adjusting for these items and the unrealized mark-to-market on the hedges, pretax net income increased approximately 100% to $4.7 million or $0.13 per share. We had total debt of $26 million as of December 31, 2022, compared to $33.3 million as of December 31, 2022, as we use a portion of the proceeds from the sale of the Eagle Ford and Arkoma working interest assets, as well as our discretionary cash flow to reduce our debt level in light of current natural gas pricing environment. Our debt to trailing 12-month EBITDA was 0.91 times at March 31st, 2023.
Lastly, as part of our regularly scheduled semiannual borrowing base redetermination, our borrowing base was reduced by $5 million or 10% to $45 million. This reduction is associated with current natural gas pricing macro environment and not a reflection of the quality of our assets. We continue to have a great relationship with our bank group and we look forward to continue to partner with them across all commodity pricing environments.
Our asset retirement obligation liability or ARO associated with working interest assets stands currently at $1 million as of March 31st, 2023. We have decreased this liability by $1.8 million since September 30th, 2021 when our ARO stood at $2.8 million. This reflects again just continuous improvement on our balance sheet profile.
We recorded an income tax receivable of $776,000 this quarter compared to an income tax payable of $576,000 in the previous quarter. This change was generated by a net operating loss due to the divestiture of the Eagle Ford working interest, which we anticipate will offset all federal taxable income in 2023 and be carried forward into 2024.
Lastly, our mineral only strategy has minimal capital commitments, which allows us to pivot very quickly to reallocate capital as necessary be it to reduce debt, increase or decrease the size of our acquisition program, all while maintaining excellent coverage on our dividend.
With that, I'd like to turn the call over to Chad for some final remarks.
Thank you, Ralph. Before we close, I would like to highlight a couple of important points from both Danielle's and Ralph's comments. First, with our non-op working interest divestitures largely complete, we expect to resume growth in our corporate volumes, which will be primarily driven by our increasing royalty volumes.
Secondly, despite a 20% sequential drop in our quarterly revenue, our EBITDA was 45% higher this quarter. This is the result of a favorable mix of higher royalty volumes which increased by 29% and that created a higher margin of 60% this quarter versus 40% margins the last quarter. We anticipate operating with the higher cash margins going forward.
Lastly, as we have pointed out, the hedges we established at the height of COVID at the insistence of our banks have now completely rolled off. Our current hedge book provides much better downside protection, while maintaining upside exposure.
We have made remarkable progress in transforming PHX over the last three years and have achieved on the specific plans we originally established and communicated to the market. We are now positioned to grow even further using the free cash flow from our quality assets and strong financial position and look forward to keeping you updated.
Deservingly, I would also 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, sir. We will now be conducting the question-and-answer session. [Operator Instructions] And the first question comes from the line of Derrick Whitfield with Stifel. Please proceed with your question.
Good morning and congrats on a strong start to 2023
Thanks, Derrick
Thanks, Derrick
For my first question, I wanted to focus on 2023 guidance. While we haven't seen a material slowdown in activity across your assets yet, and in fact, we've somewhat seen the opposite -- the expectation is for a further softening in gas-focused activity. In light of your WIP and the macro environment, do you still feel comfortable with 2023 guidance as outlined
Derik, it's Ralph. Yes, I think at this point, we do. Again, if you look at the rig activity on our minerals and as Chad pointed out, right, I mean, we've really focused on buy minerals in the core of the core, right? So in theory, right, those have the best margins. And if you're an operator, those would be the last assets that you -- where you drop a rig from. We have followed what all the operators have stated publicly in terms of rig activity. And we think there may be some softening coming towards the third quarter of this year from a rig count standpoint, this is in the Haynesville.
But I think if you're an operator and you're looking forward into what the 2024 curve looks like and if they have the ability to hedge those volumes, right, they're going to be -- they're going to have to make some decisions about whether they actually drop the rigs or did they keep them operating, right, and hedge into a much stronger 2024 versus 2023.
And I also think that would offset the -- any potential decline in the Haynesville as we're seeing very strong performance on our liquids-rich assets, both in the Anadarko Basin and some other areas of the country where maybe our nets are not that high, but we still have interest in whether it be in the Bakken or in the Uinta Basin, you continue to see activity with oil prices where they are. So all of that to say is, as we sit here today, we're still very comfortable with the guidance that we provided.
That's great. And then with respect to the M&A environment, could you speak to what you're seeing in the market at present, given the pullback in gas prices? And further, what is your preference at present for capital allocation between the Anadarko and Haynesville opportunities you're seeing?
Yes, Derrick Hi, this is Chad. Since January, gas prices had a stunning breathtaking plunge, we've really seen the bid ask between sellers and buyers. The gap has widened quite a bit. So it's real difficult for us to transact in the Haynesville, given where we think the mineral values are and what the seller's expectations are. So our capital allocation to acquiring more minerals in the Haynesville has slowed down even though we do see deal flow, it's hard for us to transact at seller expectations value.
So we've slowly pivoted toward and allocating more capital in the springboard in the SCOOP/STACK area in that higher quality rock quality areas and where operators are going to be drilling more wells in the SCOOP/STACK area that are more liquids-rich, and we're having some success there.
Yes. The other thing I would also add, Derrick, is that look, we're very economic animals, right? So we want to allocate capital to the best rates of return. And while clearly our strategy is to grow the business, we're not going to grow for the sake of growing. That doesn't make any sense if the economics are not there, right, so.
Yes. Let me be clear, when I loosely used the word SCOOP/STACK, that nomenclature has some real bad headline news around it from several years ago when a well performance in bankruptcies were just ramping across that area. We have a very tight band of area that we're willing to acquire minerals in based on rock quality and well performance. So we're not going to get outside of that very thin fairway. That's the area we're going to focus on and stay within that area.
Yes. And again, if the deal flow is not there or the valuation is not there, we'll continue to pay down debt. I think at some point, sellers' expectations are going to have to come down or you're just going to hold these assets -- continue to hold these assets.
And we want to be in a great financial position to allocate that capital at the appropriate time. But we're very patient in terms of how we evaluate these transactions. And we're going to keep maintaining a very strong balance sheet and improving upon it for when the right time comes.
That's great. understood on the areas of focus, and congrats again on strong update this morning.
Thanks, Derrick.
And the next question comes from the line of Jeff Grampp with Alliance Global Partners. Please proceed with your question.
Good morning guys.
Good morning.
Sticking on the topic of – Hi. sticking on the ND topic, almost $11 million of deals in the quarter, which given your commentary on bid-ask spreads seems even more noteworthy. How are you guys thinking about managing the liquidity going forward given the bank's price-related borrowing base cuts and kind of juxtaposing that with your obvious strategy to continue finding more royalty deals?
And a related point, does equity ever enter the conversation in terms of kind of bridging that gap and preserving liquidity as a means of acquisition funding, or just kind of wondering how you guys are thinking about kind of managing those two conflicting components.
Well, I think from a leverage standpoint, nothing has changed in terms of our strategy, right? I mean, from even going back to early 2020 when Chad became full-time CEO and we changed the strategy, that from a liquidity standpoint our goal was to get the balance sheet or the debt to about one times debt-to-EBITDA, one times to 1.2 times, somewhere around there. And that's exactly where we've been for the last, I think, four or five quarters, right, from a high of almost three times back in 2020. And I think the plan is to continue to maintain that.
I think that from a royalty business standpoint, regardless of what the bank does, the banks may do, whether -- this is across the industry, it's not just related to us in terms of advance rates. Not having the obligations coming in on the non-op working interest gives us a tremendous amount of flexibility to react to, again, any -- whether it's less access to debt or the bid ask spread on acquisitions turns in our favor. We can very quickly reallocate capital. That's the beauty of the Minerals business, which is just not available on the non-op working intrasite component where you still don't control the timing, but you got to pay their bills.
In terms of how we fund acquisitions, I mean, we've always said everything is on the table. It's very deal specific, right? I mean you just have to wait and see. Certainly, nothing -- there's nothing that we're looking at one way or the other. But we've always said that flexibility across the balance sheet is something that's important for us to consider.
Yes. And Jeff, let me add to that. And when I talk about from 2020 to where we are today and using words like transforming the company, the old company was really identified as a hybrid. We had half the value of the company was in non-op working interest. Half the company was in royalty reserves and royalty revenue, and it's very difficult for anybody to get really interested in investing in the company. So we, over the last three years, completely transformed the company into a story that's completely around growth in mineral royalty reserves, acquiring minerals and increasing our royalty reserves. So that, kind of hybrid overhang, has virtually been removed. We still have a small bit of value in non-operating interest, and at some point we'll look at or consider selling.
But -- so with that, we're clean balance sheet, low leverage, great clean cash flow and high margins. The real, I guess kind of overhang right now is just our size. So we need to -- Ralph and I will continue to look at larger-size deals. Our bread and butter has been this $1 million to $2 million to $3 million, $4 million size deals that no one else really focuses on, they're too small to move the needle for most of our larger peer groups. So we're able to transact the bid-ask spread in the Haynesville is a little wide right now.
We're able to transact at this lower value area, because there's not a lot of competition. But we do need to grow, and we're going to do so patiently and methodically, but at some point, we'll look at larger deals. And if they're larger, we're most likely going to have to use some equity, and we've demonstrated that in the past that at the right time for the right deal at the right value, we would consider and will -- the Board would consider using equity to do so. So we're going to continue to keep our head down, execute on the deal size, that we -- that's gotten us to where we are today, while we're also looking around the horizon, on the landscape for some larger.
Got it. I appreciate all that commentary. For my follow-up on the hedging side of things, looking out into 2024, it looks like you guys tacked on a little bit more to the hedge book for 2024. You guys obviously have a strong balance sheet, not very capital intensive given the royalty asset base. And so thinking about the constructive view you guys have on gas pricing, is it fair to expect that the hedge book for 2024 is probably not going to be that significant, thereby providing some more pricing upside to you guys, or are you kind of thinking about balancing -- locking in some cash flow versus giving some price upside?
I'm going to let Ralph talk about the actual hedges, and then I'll give you our view of the gas macro.
Yes. I mean I think it's -- there's actually -- you got to think about two things, right? So, because we have some fairly high royalty volume growth component, right, from new wells coming online, right, even as we get into 2022, 2023 and 2024, those are volumes that are not yet currently in our books, right? So you cannot hedge that. So our philosophy has always been, look, let's be – those are fully exposed to movements in commodity price, right, both up and down. But the existing PDP production that we have, right, what we think is let's be a little bit more aggressive on that PDP component, and let's use collars, right, where think of it as catastrophe insurance is really the way that I think about it, right? Because we're locking in – I’ll just use an example. Let's say, it's into 2024, right.
You can lock in $3 by $5 on the existing PDP well. We still -- even if the market stays – stays below $3. We still generate really good cash flow at $3, with those hedge contracts. And we have -- and we're exposing ourselves up to 5 in that example I gave. And then the volumes are going to come online are 100% exposed to it.
So I think it's a prudent thing to layer in a minimal amount of -- or the appropriate amount of hedges is a better way to say it. That basically covers all of our fixed expenses and it covers our dividend payment, right. That's the catastrophe insurance that I was kind of talking about and then remain exposed to the upside, which we continue to be bullish on natural gas. Chad will talk about that here in a second, as we go forward. So that's been the strategy. And in a Contango market, where forward prices are higher than they are today, right. That's -- we think that's the appropriate structure. Go ahead, Chad.
So Jeff, following up on that, if that gives you a picture on our view of how and why we hedge, and it really somewhat tied, as Ralph alluded to, tied to the bank – bank requirements. But when you look at the gas macro picture and how kind of miserable it is right now, coming out of winter, the two -- obviously, the two headline pieces of news there were the mildest winter weather we've had in quite some time. Heating degree days were way down by 20 -- almost 25%.
And Freeport, the Freeport LNG terminal has been down out of service since last June. That to date from last June to today, it took out 800 Bcf of demand for the winter alone, Freeport, the absence of Freeport LNG export to demand down by about 300 Bcf. So between weather and Freeport, gas prices have collapsed, and you saw that really in January, one of the sharpest drops in January natural gas prices since like 2001. So really got the attention of the industry. surprisingly, power demand has remained resilient and natural gas has been responsive to that power demand by really being priced associated with PRB coal.
And so price is just under the price for PRB coal, and there's more demand for natural gas at the current price is to feed the power demand. By past month, you saw milder weather. So the market expected about 125 to 100 Bcf of increase in storage, but you actually saw about 65 Bcf per half, the expected amount in inventory change. So it does suggest that maybe we're not as on a Bcf per day supply metric. We're not quite as oversupplied as the market believes and with Freeport now back fully in service as of the end of March, there will be a couple of terminals that are going to have some maintenance in the coming June, July period. But with Freeport back in and when you have all the LNG export capacity back in service going into the fall and this coming winter, we think that there'll be a balancing will reach equilibrium.
And if we have a normal winter with normal heating degree days and the normal export capacity for LNG, prices will move back up above $3 and that's kind of our overall view on how and why we hedge based on kind of that view.
Got it. All right. Thanks so much Danielle. I appreciate the time.
Sure.
[Operator Instructions] Our next question comes from the line of Donovan Schafer with Northland Capital Markets. Please proceed with your question.
Hi guys. Thanks for taking my questions. I want to start off with -- so for this quarter, the natural gas pricing came in quite a bit better than I expected, excluding hedges. It's not from NGL uplift since you report that separately. So I'm wondering, if there is something here being a royalty company, if there's a timing lag when I look at benchmark prices, Henry Hub fell more than 50% from the fourth quarter to the first quarter but your pre-hedge realizations fell meaningfully less than that. So is that just changes in kind of differentials, or is there like a month maybe lag or something because of the way royalty revenue gets recognized?
Yeah, there's a little bit of a lag in there. So if a well is already on production, right, we accrue for it. But -- and then, we true it up when we actually get a check. But if it's a new well, as an example, so let's say that, the new well is publicly announced on -- I'm going to make this up. This is not an exact way. I'm just giving it as an example. It's available on January 15, right, where we can book that well.
But that well actually came online on December 1st, right? So that December 1st to December 31st, right, gets baked into -- it's effectively that lag that you're talking about that gets baked into the current quarter, right? And so this is normal of every single mineral company out there. And it happens every quarter, sometimes up, sometimes down. It's just a reflection of the operators making the production data available for the mineral owners should be able to book that well.
Okay. Okay. That's helpful. And then turning to the SCOOP and the STACK, we've heard about Continental kind of accelerating activity in the Bakken. We know that, it's private and Haynesville is back in charge, are you seeing signs of anything like that from Continental in the SCOOP or the stack?
Yeah, absolutely. So they have ramped up activity in some of their core springboard plays. We see permitting. We see DUCs and WIP getting filed regularly with increasing pace. And we assume that as they see their results come in, they'll pick up the pace out there as well, so, all that bodes well for future development out in their course to play.
Yeah. So Donovan we are watching one area where we've got a mineral interest under 15 wells that as we speak, they are completing them, and they should be on production here by mid- to late June going into early July.
Yeah. So if you look at Page 21 of our corporate presentation that's posted on our website that will have the map of the SpringBoard 3 play and again, you can look at this later at your leisure. But if you look at them, there's a number four on the map, those that -- those 15, 16 wells that Continental is drilling that we have an interest in. And they're fully ramping up in this area. There's just no other way to say it. And again, this is prior to Continental going private, but I think Harold Hamm has always stated that this is the best quality rock in his inventory. So I mean, I don't know what he's going to do, but I would think that means that, again, this is the last place where you would slow down.
Okay. And then last question, you guys have been making very rapid progress on the transition to being royalty only. And kind of just given that pace 84% was royalty last year -- last quarter, but that's sort of an average. So what's kind of the run rate right now? Is it north of 85% and then when you plan -- how aggressive you are wanting to get to 100%, or will you be happy kind of no rush just get north of 90 sooner than later and then take your time.
I mean I think the way to think about it is, yes, we're in that sort of mid-80s as a range, right? And as new volumes come online in -- for royalties and the working interest depletes down, right, without any reinvestment or participation in new wells, you're going to see it start to move towards 90. We have we've stated this before that I think we started off with maybe around 2,000 working interest wellbores, and we've sold about 1,500. So there is 500 left. But I would say in this pricing environment, it probably doesn't make sense. We don't want to force it. There's no -- we got great pricing last year on the assets that we sold.
We're not going to force it in this pricing environment. But I would say, out of those 500, right, it's the old 80-20 rule. 80% of the value is in 20% of the assets, right? So we're going to focus on the -- we re-rank all those wells, and we focus on the bottom, let's say, bottom 100 and we'll figure out a way to monetize those, and that's going to have a de minimis impact, if any, to cash flow or to our reserves, right? So that's kind of how we think about it. But I think anything with real value in this pricing environment, we're -- I don't -- we don't think it makes sense to force it. There's no need. There's no difference between being 85% or 90% and 95% from our understanding
You claim loan game, yes, totally makes sense. Okay. That's helpful. I'll follow-up if I have any other questions.
Thanks, Donovan.
Thanks, Donovan.
At this time, there are no further questions. And I would like to turn the floor back over to Chad for any closing comments.
Thank you, operator. Again, I'd like to thank our employees and shareholders for their continued support. I'd also like to note that Ralph and I will continue to expand our investor marketing activities over the coming weeks and months, through a series of non-deal road shows and conference presentations aimed at expanding investor awareness. If you'd be interested in meeting, please don't hesitate to reach out to myself, Ralph, or the folks at IR. We look forward to hosting our next quarterly call in mid-August. Thank you, and have a good day.
Thank you, everyone. This does conclude today's conference. You may disconnect your lines at this time. Thank you for your participation, and have a great day.