Good morning, welcome to the Evolution Petroleum Third Quarter 2026 earnings release conference call. All participants are in a listen-only mode. Please also note today's event is being recorded. At this time, I would now like to turn the conference over to Brandi Hudson, Investor Relations Manager. Please go ahead.
Thank you. Welcome to Evolution Petroleum's fiscal Q3 2026 earnings call. I'm joined today by Kelly Loyd, President and Chief Executive Officer, Mark Bunch, Chief Operating Officer, and Ryan Stash, Senior Vice President, Chief Financial Officer, and Treasurer. We released our fiscal third quarter 2026 financial results after the market closed yesterday. Please refer to our earnings press release for additional information containing these results. You can access our earnings release in the Investors section of our website. Please note that any statements and information provided in today's call speak only as of today's date, May 13th, 2026, and any time-sensitive information may not be accurate at a later date. Our discussion today will contain forward-looking statements of management's beliefs and assumptions based on currently available information. These forward-looking statements are subject to the risks, assumptions, and uncertainties as described in our SEC filings.
Actual results may differ materially from those expected. We undertake no obligation to update any forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including Adjusted EBITDA and Adjusted Net Income. Reconciliations to the most directly comparable GAAP measures are included in our earnings release. Kelly will begin with opening remarks, followed by Mark with an operational update, and then Ryan will review the financial results. After our prepared comments, the management team will open the call for questions. As a reminder, this conference call is being recorded. If you wish to listen to a webcast replay of today's call, it will be available on the Investors section of our website. With that, I will turn the call over to Kelly.
Thank you, Brandi, and good morning, everyone. Before walking through the quarter, I want to step back and provide some context on where we are as a company and how we're thinking about the path forward. Over the last seven years, we have deliberately reshaped Evolution's portfolio, expanding beyond our legacy asset base into a more diversified, capital-efficient platform designed to generate durable free cash flow through commodity cycles. That has meant adding long-life, low-decline assets such as Jonah and Barnett, expanding our non-operating working interest base through acquisitions like Tex Mex, and most recently, building a minerals and royalty platform that we believe can become a durable and growing component of our portfolio.
The common thread across these decisions is the same: building a business with long life assets, modest capital requirements, sustainable free cash flow, and the ability to support our dividend while compounding per share value over time. That is the framework through which we evaluate every capital allocation decision, and it is the lens through which I would encourage investors to evaluate our results, including in quarters like this one, where reported results were impacted by items that do not reflect the underlying earnings power of the business. With that context, let me address the fiscal third quarter directly. This was a more challenging period than the second quarter, and I want to be transparent about what drove the variance. A combination of isolated and largely non-operational items weighed on our reported results, including regional natural gas pricing dislocations that impacted realized prices at Jonah and Barnett.
A $1.2 million one-time prior period transportation adjustment at Delhi related to changes made by the operator dating back to 2024, and weather-related production disruptions across multiple fields during the January ice storms. These are not structural issues. They don't reflect any change in the underlying quality of our assets or our cost structure or our strategy. These were largely timing related and one time in nature, and we expect underlying performance to normalize as they roll off. Setting those items aside, what stands out to me is how the portfolio held up despite those headwinds. Production was essentially flat year-over-year at 6,700 BOE PD , a result we view as a meaningful sign of resilience given the level of weather-related disruption and downtime we experienced in the quarter.
Contributions from our new acquisitions helped offset downtime and natural declines at certain assets, which is exactly the kind of portfolio-level stability we have been working to build. This reflects the benefits of diversification across assets, commodities, and operating partners. That diversification is not accidental. It is the direct result of the capital allocation discipline we have applied consistently over multiple years. On our mineral and royalty program, we continued to make progress during the quarter. We completed two additional Louisiana mineral and royalty acquisitions targeting the Haynesville and Bossier Shales, bringing the total consideration for our Louisiana minerals to approximately $5 million. These assets are being actively developed by operators in the area. Wells are being drilled and completed, and we expect contributions from these positions to begin building as that activity translates into production.
All of that to say, the financial contribution from our minerals platform is still in early stages. However, the activity we see from operators gives us confidence that the production ramp we underwrote when we made these acquisitions is right on track. We will provide more specific updates as those results come through. As we move into the fiscal fourth quarter, we expect the picture to look meaningfully different. The prior period Delhi adjustment is behind us. The February gas dislocation at Jonah was a singular weather event. Differentials are returning to more normal levels. The Tex Mex workover program is in its final phase, and we expect that asset to be a more meaningful contributor as that work is completed.
The combination of these factors, alongside the continued ramp of our minerals and royalty assets, gives us confidence that the fourth quarter will better reflect the underlying earnings power of this business. We expect to generate robust cash flow in the fourth quarter and beyond, which reinforces our continued confidence in the dividend. In addition, we believe the current commodity price environment provides incremental upside from here. On May 11th, our board declared our 51st consecutive quarterly dividend and 16th consecutive dividend at $0.12 per share, a milestone that reflects the durability of our underlying cash generation across a range of commodity environments. Our capital allocation framework has not changed. Protect the balance sheet, support a dividend we believe is sustainable through cycles, and deploy capital where we see compelling risk-adjusted returns.
As always, dividends are paid at levels that are meant to be sustainable given the current outlook for multiple years to come. This portfolio has always been designed to withstand any ill effects of the odd difficult quarter, and it is this same framework that gives us confidence in what we expect to be a strong finish to fiscal 2026. Before I hand it over to Mark for more detail on our operations, I want to leave you with one final thought. Looking at the broader picture for commodity prices, in March of 2026, WTI oil prices reached their highest levels since 2022 and remain at elevated, although highly backwardated risk premium levels. The significant increase in forward oil commodity prices as of March 31st resulted in an unrealized loss on the mark-to-market value of our hedges for the quarter.
Additionally, the large non-cash loss associated with unrealized hedge losses was based off of a crude oil strip at the end of March, where spot prices for WTI were over $100 per barrel. No one knows where WTI will be at 6/30/2026, but where we sit today, we think it is likely that the unrealized losses will show a reversal in the next quarter. Although our unrealized gains and losses on hedges will fluctuate as forward commodity prices change, I sometimes think that people forget that selling oil for higher prices than our hedges is a really good thing. The current oil price environment will provide incremental upside in the fourth quarter as we expect to benefit from the higher pricing to the extent that prices exceed our applicable oil hedges.
Additionally, our NGLs, which are priced as a percentage of crude oil, remain unhedged and should receive the full benefit of pricing. As far as our natural gas hedges are concerned, we expect to realize a benefit as our hedges are priced at levels higher than current strip pricing. With that, I'll turn the call over to Mark.
Thank you, Kelly, and good morning, everyone. I will focus my remarks on key operational highlights from the quarter and encourage listeners to review our earnings press release and filings for additional details across our asset base. Overall, our operations continued to demonstrate steady base performance across the portfolio during the quarter. The results were impacted by the weather-related disruptions and one-time items Kelly described. Now on to our assets. At our Haynesville and Bossier Shales, we continue to build scale and are prioritizing value on wells that are either currently producing or expected to be producing within one year of purchase. To that end, we expect 23 wells to be brought online and meaningfully contribute to revenue and cash flow in the fiscal fourth quarter. At SCOOP/STACK, production from the mineral and royalty interests acquired in August 2025 modestly contributed to overall volumes during the quarter.
Additionally, there are seven gross wells in progress and 12 gross wells on production that we are still awaiting first production and revenue data. At Chaveroo, production increased year-over-year, reflecting the benefit of wells brought online over the past 12 months. The January winter storm and gas interference on the wells with ESPs decreased production by a 30 net BOE PD quarter-over-quarter. Subsequent to quarter end, we converted one well from ESP to rod pump. Currently, all but one of our seven wells has now been converted to rod pumps. We continue to advance permitting for the next six wells, expect to have those permits in hand before the end of fiscal 2026. At Tex Mex, oil production increased quarter-over-quarter due to a successful workover program.
At the end of the prior quarter. However, January winter storms not only impacted production, but also caused power outages and surface equipment damages that required repairs. This led to higher expenses in the quarter. We expect Tex Mex to continue to improve. Subsequent to quarter end, we began a new workover program, which we expect will increase production by an additional 100 net BOE PD by the end of fiscal Q4. At Delhi, revenues were impacted by the one-time prior period transportation adjustment Kelly described earlier, which is now behind us. The January winter storm outages impacted production for six days during the quarter, and the CO₂ recycle compressor, which is down for most of the prior quarter, remained down for 40 days during fiscal Q3, negatively affecting production. These issues were resolved during the quarter.
Despite this, field level profitability remained strong, supported by lower operating costs, reflecting the continued benefit of the cessation of CO₂ purchases that concluded late in fiscal Q3 of last year. We expect production volumes to improve as operational stability continues. At Barnett, quarterly production was heavily impacted by the winter storm as well, resulting in a decline of approximately 160 BOE PD . The impacts carried into February and restored by March. Across the portfolio, production was heavily impacted by the January winter storm and other downtime accounting for over 300 net BOE PD . These have been resolved during the quarter, and we remain focused on maintaining operational flexibility, optimizing our cost structure, and deploying capital where returns are most attractive. With that, I will turn it over to Ryan.
Thank you, Mark. Good morning, everyone. As Brandi mentioned earlier, we released our earnings yesterday, which contains more information on our results. For today, I'd like to go through our fiscal third quarter financial highlights. In fiscal Q3, we had total revenues of $20.2 million, down 11% year-over-year. The decrease in revenues was primarily driven by an 11% decline in average realized equivalent prices, partially offset by a slight increase in production volumes. The decline in pricing reflected regional natural gas pricing dislocations at Jonah and Barnett during the quarter, but especially in the month of February, as well as $1.2 million in one-time prior period transportation adjustments at Delhi, related to a new marketing contract entered into by the operator and dating back to December 2024.
Net loss for the quarter was $8.9 million or $0.26 per diluted share, compared to a net loss of $2.2 million or $0.07 per diluted share in the year ago period. This quarter was negatively impacted by $7.6 million in unrealized hedge losses due to the spike in crude oil prices with the war in Iran. Excluding the impact of selected items, including the unrealized hedge losses, Adjusted Net Loss quarter was $2.9 million, compared to $0.8 million in Adjusted Net Income in the year ago period. Adjusted EBITDA was $3.1 million compared to $7.4 million in the prior year quarter, reflecting lower revenues due to historically unfavorable differentials, production downtime at many of our assets, and realized losses on derivative contracts.
More specifically, as it relates to differentials, in Jonah, the winter differentials were the worst since we have owned the asset and the lowest in the past 10 years due to the warmest winter on record for the West Coast. Going forward, we would expect differentials at Jonah and our other natural gas assets to return to more historical levels. We estimate that the winter differentials negatively impacted our realized price per BOE by approximately $3.39 as compared to the prior year period. Lease operating expenses improved to $13 million or $21.49 per BOE, compared to $22.32 per BOE in the prior quarter.
The decrease was primarily driven by reduced ad valorem taxes at Barnett Shale and the continued benefit of the cessation of CO₂ purchases at Delhi, partially offset by the addition of the Tex Mex properties and incremental work overactivity during the quarter. The addition of our royalty assets in Oklahoma and Louisiana have also contributed to higher margins and lower operating costs for our asset base. On the hedging front, we have continued to add additional hedges to comply with our credit facility covenants. Our ongoing goal remains to reduce downside commodity price risk and protect cash flow for our shareholder return strategy while preserving the maximum potential upside. This strategy can result in realized and unrealized losses on our hedges in some periods, such as the current quarter, but benefit us in other periods and will provide more predictable and stable cash flows over time.
Turning to the balance sheet. As of March 31st, 2026, cash on hand totaled $2.6 million. Borrowings under our credit facility stood at $56.5 million, with $0.8 million in letters of credit outstanding. Total liquidity, including cash and available borrowing capacity, was approximately $10.3 million, providing us with the flexibility to support our ongoing operations, capital allocation priorities, and selective growth initiatives. During the quarter, we paid dividends totaling $4.3 million. As previously announced, the board declared a quarterly cash dividend of $0.12 per share, reflecting our continued commitment to returning capital to shareholders. Overall, our asset base and balance sheet strength position us to continue returning capital to shareholders while selectively deploying capital into opportunities that we expect to be accretive over the long term, just as we have done over the past seven years. I'll now hand it back over to Kelly for closing comments.
Thanks, Ryan. To sum it up, fiscal Q3 was a quarter shaped by temporary headwinds rather than structural weakness. The portfolio held up well at the asset level. Our minerals and royalty strategy continued to advance, and we maintained the dividend for the 51st consecutive quarter, which we believe speaks to the durability of our underlying cash flow. As these one-time items roll off and our recent acquisitions contribute more fully, we expect our results to better reflect the earnings power we have built in this business in the fiscal Q4 and thereafter. We look forward to updating you on our progress. With that, I'll turn it over to the operator to begin the Q&A session. Thank you.
We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw the question, please press star then two. At this time, we will pause momentarily to assemble our roster. Our first question comes from Jeff Robertson with Water Tower Research. Please go ahead.
Thank you. Good morning. Mark, at Delhi, with the new crude marketing agreement that the operator entered into, can you talk about how much flexibility Evolution has to or and whether you want to do any, as you allude us to in the press release, to do anything different with respect to marketing your equity production from that field?
Hey, yeah, Jeff, I'm gonna flip that. Actually, I know you asked me, but I'm gonna flip it over to Ryan to answer.
That's part of the thing we've actually been kinda actively looking at. We do actually have a lot of flexibility in the JOA to take the production in kind, which we're actively looking at now. The one point I'll make on the actual changes is obviously it was a move from, you know, Denbury to Exxon. The ultimate contract with Plain hasn't changed that much other than they're now trucking, where in the past they had a pipeline that went down. That's really the biggest difference in kinda charges. To directly answer your question, we're definitely looking at that, and it's something that we're actively considering, and we think we probably can do a little bit better than what they are in the market.
Ryan, in the second quarter and going forward, do you expect the G&T charges to be similar to what they were last year as opposed to in previous quarters as opposed to what they were in your second fiscal quarter?
Yeah. I mean, in gathering there's, you know, there's nothing that's been out of the ordinary that I'm aware of in the past quarter. I mean, those have been relatively constant. I mean, there are some contracts we've mentioned in the past, like, you know, Barnett that is tied a little bit to natural gas pricing, so it will move a bit. Overall, it's more volume driven, right? You know, I wouldn't expect those to vary much from historical.
Can you talk about what kind of communications you're having from your operators with respect to any initiatives they might have to go out and do short cycle workover type projects or whether there are opportunities to bring wells back online to take advantage of the high oil prices we have at least for the next month, at least the next couple of months?
Yeah. Jeff, this is Mark, you know, yeah, our operators are all working towards that. In fact, we actually mentioned one in particular. You know, Tex Mex, they really accelerated their second round of workovers to bring things online in New Mexico, largely because the prices went up. The timing was really good. We speeded that up somewhat. Yeah, everybody's looking at making sure that they keep as much production, oil production on as possible.
Jeff, hey, this is Kelly. I'll just add on. I mean, Mark's right. Across the board, we're seeing it. Look, these are simple projects that are fast, right? Drilling takes longer to get on production. If you do a workover that takes, you know, a week and things are back up producing, I mean, if you evaluate these, I mean, these are very, very high return projects that can get done quickly and can be meaningful. We've seen a lot of guys try to do that as much as they can. In Hamilton Dome, you're seeing activity increase really across the board.
Lastly before getting back in the queue. Kelly, can you speak to the state of both the non-op market and the minerals market, just given the volatility in commodity prices and what that means for trying to value transactions?
Yeah. You know, it's interesting. On the non-op side, it's, I mean, I would almost argue it's kind of a dearth of availability. Like, there isn't a whole lot that we've seen out there. On the mineral side, again, you know, working with some folks that we, you know, have a whole lot of confidence and trust in, we've been able to do sort of, you know, I don't know if you wanna call it bespoke, but deals we put together and along with them and go execute on. And minerals just, you know, in general, especially when you're able to build them in little onesies and twosies like we have been, they're more liquid.
We can find real dislocations and opportunities which, like I said, we and the folks we're working with have been doing a great job of finding those, and we expect to see that continuing. There will be a flip. You know, at some point, the non-op will come back in vogue, and we'll start seeing better returns. When you only have a couple deals and a bunch of people bidding on them, it just hasn't, you know, in the last couple quarters, it really hasn't been super attractive.
Thanks. I'll jump back in the queue.
Thanks, Jeff.
Our next question comes from Poe Fratt with Alliance Global Partners. Please go ahead.
Thanks for taking my call. I'm trying to figure out what your run rate is for the June quarter right now. You reported, you know, 6,700 of BOEPD. You talked about 300 BOEPD of impact on production from storms and other things. Are you above 7,000 BOEPD right now? What's the run rate for the June quarter? Or can you just help me calibrate that?
Sure. Hey, Poe, this is Kelly. Thanks for calling. Yeah, I think we made it clear, I don't wanna speak out of school or Ryan will slap me, we've The 300 BOEPD is almost substantially all back online and was starting to get there before the end of the quarter. If there was anything left over, it's pretty much there now. We are well underway in our progress on adding about 100 net BOE PD in Tex Mex. We also have, you know, I'll be a little cautious here. We have 12 wells in our royalty properties alone in the SCOOP/STACK that we know are on production. They have been completed. We just don't have data yet.
Again, in Oklahoma, it can take a while. We expect to get data. We don't wanna aggregate if we have no data. You don't wanna just guess. We have type curves, you need to actually get data before you put it on there. We've got 12 wells that we're a part of there that we expect to get data on and be able to include in our fourth quarter results. Same thing with our Haynesville and Bossier Shale assets. We've got 24 wells that we expect to get data on and have production from during the fourth quarter. We know that at least 20 of them have already been completed and others are sort of in process. I can't really quantify that number.
I mean, I could guess off my type curve, Poe, but that wouldn't be appropriate. Again, we've got the 300 BOEPD back online. We've got another 100 BOEPD we fully expect and is in progress of working towards at Tex Mex plus additionals from new wells that we don't have data on that we're either already producing or getting there very shortly.
It's probably Poe, this is Ryan. It's probably helpful just sometimes to remind you guys on how from the non-op perspective how it works. You know, there are some wells in some areas we have real-time data, but certainly not all across our portfolio. We won't probably really know true April production for another week or two until we actually start getting our revenue statements in from the month of April, right? As we sit today, you know, we still don't have actual revenue statements yet for April production. We do know of some areas, obviously, as Kelly said, and we do know of things that have returned to normal, but we won't know for a fact, like, what production actually was for April yet.
Yeah. From the royalty side, Poe, it's even more delayed just because you're further removed from the operator. Those, like in Oklahoma, can be, you know, somewhat delayed, like, by 180 days. It's, you know, when we get information, we start applying and accruing for it, but sometimes we don't know about it until it actually comes on.
Okay. I, you know, I'm not going to hold you to any guesses, but is there You know, it sounds like the SCOOP/STACK, you might get some data, maybe two months would potentially hit the production for the June quarter. The Haynesville and the Bossier is, you know, probably, you know, first quarter next year or the September quarter. I guess a short question, what could potentially be the impact from SCOOP/STACK if you do get the data in the June quarter?
Poe.
Is it-
Yeah, I'm.
Is it 50, 25? You know, sort of just, I'm not gonna hold you to any guesses that you make. I'm just trying to calibrate.
I understand. I mean, I don't think I'm comfortable speculating on that.
Okay. I'm not gonna beat the dead horse then. You talked about Chaveroo that, you know, the permits are potentially in place for the next six wells or the next pad there by the end of June. Do you think the operator there will pull the trigger in the September quarter? Is it more, you know, December quarter with potential impact in calendar 2027?
As you know, the operator there has undergone a merger, and it is our understanding that they are prioritizing assets and coming up with schedule. We're working with them closely, I would just It's just too early to say at this exact point in time. We are working on that and trying to get things scheduled as quickly as we can and to understand from our own, you know, capital needs, exactly when this is gonna work out. I, you know, I don't wanna speculate and answer for them, I'm gonna wait for that, Poe.
Okay. Yeah.
We will update you when we know. How about that?
Yeah, I guess so. From a conceptual standpoint, those are shorter term, you know, shorter lead time. They're permitted. There's, you know, generally, you can drill a lot quicker there than you can in other places. Okay. Then on Delhi, is there any legal, you know, recourse that you have? I mean, this is, you know, there's quite a delay between the time that the contract went in place and then, you know, it hit the quarter. Did I read in between the lines that you may have legal recourse?
I'm officially not gonna answer that.
Okay. Okay. I think that's it. Thank you.
I appreciate it. Thanks. Really appreciate it, Poe. Thanks.
Our next question comes from John Bair with Ascend Wealth Advisors. Please go ahead.
Thanks. There's no L in there. That's Christmas time. Thank you. It's Bair. B-A-I-R. Thanks. Appreciate you taking my call, and you touched on a number of aspects of my questions. Is it fair to say that? I mean, this was a quarter, pardon the pun, but a really perfect storm, right? All five of your areas impacted here. Your comments are that the flow rates are back and I'm just wondering, was there any impact that is known as to flow rates or any reservoir damage, anything like that when, while these wells were shut in?
No. This is There weren't any damages. This is the typical thing we have happen in the wintertime when we have bad weather. Yeah, pardon me. Getting over a cold. You know, the We do it Like, typically, we see at Barnett, which is it's the one that's slowest to come back, but it comes back. It just takes it a few weeks to get back, you know, up to full rate.
I mean, yeah. Back to your perfect storm, we had one area where a lightning strike blew up a tank battery, right?
Oh, boy.
Yeah. Again, all covered by insurance, all fixed, you know, caused downtime for sure. One thing, John, it is Kelly, by the way. Thanks for calling. On the West Coast, you know, we talk about some of the impacts of differentials from our, you know, Jonah gas and it how far from normal it was. I mean, it was I mean, Ryan talked about it a little bit. I mean, once in 100 years plus kind of winter. What did they draw on the West Coast for gas, Ryan?
I mean, it was probably about 60, 65 Bcf, which is, you know, pretty much the lowest I can find for a long period of time, right?
Yeah. You know.
As I recall, right. I was gonna say that it went the other way, I think, not long after you purchased that-
It did.
...that property.
Sure. Yeah.
Yeah. I mean, that was kind of another follow-on question I was gonna say is, okay, you got impacted because of warmer winter, if it's a more hotter or more severe summer and there's higher demand, this could flip the other way. Is that a fair way of looking at it?
Yeah, for sure. Ryan and I we're doing some research on this. on the West Coast, right? It's not just California. Let's look at the whole West Coast. When you have a good snowpack, right? A nice, wet, cold winter, in the summer months when it's hot, you get a lot of hydro. Hydro is the cheapest, best, easiest way for them to generate electricity. It can be, you know, in a wet, cold winter, it can be up to 50% of the power in some of those areas. When you have no snowpack, essentially, and you're expecting no hydro, Ryan , I think your research showed it can use an extra 1 .1+ kinda Bc f /d of natural gas usage.
There will be a bounce back effect that's to our favor on this during the summer.
Yeah. No, we think there's definitely potential for, you know The differentials that we see right now in the summer months might be overstating kind of the potential, you know, high storage that we're going into right now in the, in the injection season. You know, with kind of a normal to warm summer, a little snowpack, you know, could set up for hopefully a little bit better demand on the summer heating. Sorry, summer cooling.
Yeah. From what we're seeing out there now, California's in a pretty bad state, given they have to import just about everything, it seems, whether it's energy from Asia, since they've run off the industry internally, their water and their electric.
Yeah.
They're kind of in a bad spot there.
Yeah. Yeah.
I see it.
We talk about elevated storage there. I mean, honestly, they have so few days of coverage. I mean, just happened this particular winter, there was no sort of, you know, gas-on-gas competition because they didn't hardly use any gas. It goes away and switches very quickly. It's very light storage relative to usage there. As a matter of fact, I would say out of all the regions of the country, it has the least sort of storage relative to usage.
Yeah. I mean, they've got around, you know, assuming they wouldn't inject, which they will, they've got generally 30 days or less of storage based on typical demand out there, which is very low. They've also had storage come out of the system, right? Over the past five years, which has kind of increased the volatility. As you mentioned, John, I mean, you know, we're kind of we're not benefiting it from this winter, but we've definitely been a beneficiary of winter pricing due to this volatility since we've owned the asset. We can't complain that much.
Going back to Delhi for just a moment. Is there any anticipation that CO₂ purchases will need to be resumed or ramped up anytime soon that could be impactful?
John, this is Mark. No, they don't have any plans currently to purchase any additional CO₂. Honestly, with the reservoir work that we've done, we actually think CO₂ utilization is probably improved by dropping the amount of CO₂ that's being put in the system. We don't have any disagreements with it, and it helps our operating costs.
Yeah. A little disconcerting is, I think it was referenced in an earlier caller there, questioner, the kinda lack of communication that you've had with or by the operator. Hopefully, in all areas, you'll be able to somehow improve that communication and updates, you know, so that you're a little bit better aware of what's going on and what to anticipate. I realize that as a non-op, it's perhaps a little more difficult, but still.
Well, John, we really actually have a very good relationship with Exxon, in my opinion, for I've worked with Exxon before, and it's, and, you know, it's tough 'cause they're a big company.
Sure.
You know, big companies do different things differently. We actually have a good relation with them, I think, and, you know, they do talk to us. It's just, you know, they've had some difficult maintenance issues going on and, you know, we treat them pretty much like the rest of our partners. Actually, I'd say they're definitely not the worst. That's, you know, which is a big plus 'cause I was kind of afraid they could have been. You know, we've been really happy with them, what they're doing.
Okay. Well, that's good to hear. I suppose that this field is, you know, kind of somewhat off their radar in the grand scheme of things for their size and so forth. Well, thanks very much for taking the calls.
Thanks, John.
Okay.
Bye.
Our next question comes from Nicholas Pope with ROTH. Please go ahead.
Morning, guys.
Good morning, Nick.
Kelly, I think you made a comment that the non-op , the market for kinda non-op assets has been, you know, a little tight right now. I thought it was kind of encouraging that you've sold, was it $3.3 million of SCOOP/STACK non-ops assets post-quarter end.
Can I give you a little color on that?
Yeah, that's exactly what I wanted. Go ahead.
Just to be clear, that is it is SCOOP/STACK, but it was from our minerals package, right? If you recall, we paid $17 million before post-effective date. What was the ultimate adjusted price? $16.1 million for that package of royalties. You know, when you factor in the difference between effective date and closing date cash flows, and we placed the vast majority of that on all the stuff we kept, right? There were some locations that were again, they could absolutely be viable home run candidates, but they were further out in time. When we put most of our valuation work, we front-loaded that.
If you take that evaluation, which again, we think, and, you know, has borne out to be a very good high return project at $16.1 million. If you knock another, you know, $3.25 million, $3.3 million off of that, it's an absolute home run. What do you do with that capital? You go try to redeploy it, right? Sort of high grade that portfolio from stuff that, again, we think is good. It has value. Clearly, we sold it. But into stuff that is going to be completed, in our opinion, more near term and begin to add cash flows, in the near term. That was the sort of process behind that.
Let's see if we can put some of these potentially longer dated to-be-completed stuff, flip that into stuff that we think is gonna be more nearer term, at also, you know, very attractive rates which we were buying it. That was the process there, Nick.
I mean, I think it makes total sense. I mean, it's, I think y'all been active in the past of divestitures, and it sounds like maybe the non-op market is a bit of a seller's market right now just with how quickly commodity prices have moved. Is there other opportunities? I mean, is that something I know y'all are always active kinda looking at your own assets and high grading stuff. I mean, is there other opportunities you think might be possible to divest here in the near term with some non-op stuff?
There are for sure, yes. There are a couple that I would say need to sort of be seasoned a little more, but that could be very impactful. There's always little stuff on the margin that you could flip around with. If I were modeling, I probably wouldn't account for it, but we call that, as the Cajuns say, lagniappe, right?
Got it. All right Kelly. I appreciate the time. Thanks for the question.
Thank you, Nick.
Up next, we have a follow-up from Jeff Robertson with Water Tower Research. Please go ahead.
Thank you. Ryan, on CapEx, do you have much visibility into the rest of calendar 2026 from your operating partners?
No. I mean, I think at this point, you know, it's going to be probably We don't really own the SCOOP/STACK, which is the majority, as you know, kind of our CapEx other than Chaveroo. At that, you know, we're not getting a lot of drill schedules, unfortunately, from them. We're seeing AFEs and activities, but we don't have a ton of insight there as to how much capital. We're not budgeting much more than we've probably spent this year right now. You know, we'll come out with our official kind of 2027 budget here, probably on our next Fiscal 2027, that is, on our, on our next call. At this point, no, we haven't seen a lot of activity or that we would know of for really on the non-op side.
Right now, I will say, as you know, obviously, the activity we've talked about on the mineral side, I mean, that doesn't impact our capital budget, which is the nice thing about it. All those wells coming on for SCOOP/STACK, you know, are not gonna impact our capital budget.
Thank you. I guess into that note, the mineral interest production that you talk about that should come on near term should be a high margin addition to cash flow.
Yep, absolutely. Yeah, we're excited about it. It's again, we're gonna gain more info this quarter and even more going forward as we get more wells being completed over time. Again, very excited about that.
Thank you.
Our next question is a follow-up with John Bair from Ascend Wealth Advisors. Please go ahead.
Thanks for taking the follow-up here. Just a quick question. Are you looking at any adjustments or any ways that you can, you know, adjust your hedging program, given the current elevated prices and whatever? Is there any way that you can kinda high-grade that and, you know what? My personal take is, these prices, even if, you know, some solution to the Persian Gulf, Strait of Hormuz thing was resolved, you got a long lead time to get all that cargo out of there. I know the market response would probably try to reflect it, but, given where we're at right now and all those uncertainties, are you looking at any doing any high grading of that hedging program?
Yeah, John, it's Ryan. You know, unfortunately in the near term, right, we definitely have looked at restructuring, but most of the restructuring opportunities would be things like converting our collars to swaps, which, you know, isn't really that beneficial to create upside. You know, given where the prices are, it'd be too expensive to take a lot of those swaps out or just take them off. What we are doing is we've taken the opportunity to start adding hedges in calendar 2027, so we're able to get, you know, $70+, you know, swaps and floors in some instances with higher collars. Those prices in, into calendar 2027 are pretty attractive, right? To us, you know, adding hedges out in the future at good prices is really what we're doing for the most part with this kinda spike.
You know, the other point I'd make is, you know, we're not completely hedged out on our crude, right? We've still got for our fiscal fourth quarter, at least 30% unhedged on the crude side. All of our NGLs are unhedged, we definitely have upside there from the run and the heavier parts of the barrel for the NGL. We're still gonna see some of that upside, as Kelly mentioned in his comments, really near term, there's not a lot of restructuring opportunities. We're just gonna take advantage of adding stuff in 2027.
Very good. I think one of the big takeaways from what's been going on is domestic production, I think globally you're going to be looking at more cautiously at where you source your crude from, right? I think from that standpoint, being a domestic producer, should be given a little bit of a premium, perhaps, I don't know. Just kind of food for thought there. Thanks again for taking the question.
Hey, John, really appreciate your interest and your call. We agree. I think good old USA is the place to be.
Yep. Very good.
This concludes our question and answer session. I would like to turn the call back over to Kelly Loyd for any closing remarks.
Yes. Thank you. Thank you, everybody, for attending. As we move forward, like I said, we're excited about the future here. Thanks again for your interest. Really appreciate it.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.