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 investor 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 investor 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 are thinking about the path forward.

Over the last 7 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-operated working interest base through acquisitions like TexMex, 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 per day, 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 TexMex 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 12 cents 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 level 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 on 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 onto 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 are expected to be producing within 1 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 7 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 30 net BOE per day 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 TexMex, 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 TexMex 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 per day 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 6 days during the quarter, and the CO2 recycle compressor, which was down for most of the prior quarter, remained down for 40 days during fiscal Q3, negatively affecting production. These issues 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 per day. 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 per day. However, these had 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, and 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 26 cents per diluted share, compared to a net loss of $2.2 million, or 7 cents 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 for the 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 year 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 TexMex properties and incremental workover activity 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 12 cents 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 7 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.

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, as you alluded to in the press release, to do anything different with respect to marketing your equity production from that field?

Hey, yeah, Jeff, I'm going to flip that actually, I know you asked me, but I'm going to flip it over to Ryan to answer.

That's part of the thing we've actually been kind of actively looking at, and 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 Denbury to Exxon.

The ultimate contract with Plains hasn't changed that much other than that they're now trucking where in the past they had a pipeline that went down, so that's really the biggest difference in kind of charges. To direct 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 GPT charges to be similar to what they were last year as opposed to obviously the I'm sorry, the in previous quarters as opposed to what they were in the in your second fiscal quarter?

In gathering, there's nothing that's been out of the ordinary that I'm aware of in the past quarter. Those have been relatively constant.

There are some contracts we've mentioned in the past like Barnett that is tied a little bit to natural gas pricing, it will move a bit. Overall, it's more volume driven, right?

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?

Jeff, this is Mark. Our operators are all working towards that.

In fact, we actually mentioned one in particular, TexMex, 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. Everybody's looking at making sure that they keep as much oil production on as possible.

Jeff, hey, this is Kelly. I'll just add on.

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, but if you do a workover that takes a week and things are back up producing, we evaluate these. 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, so. Then

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?

It's interesting. On the non-op side, I would almost argue it's kind of a dearth of availability.

There isn't a whole lot that we've seen out there. On the mineral side, again, working with some folks that we have a whole lot of confidence and trust in, we've been able to do sort of, I don't know if you want to call it bespoke, but deals we put together and along with them and go execute on.

Minerals in general, especially when you're able to build them in little onesies and twosies like we have been, they're more liquid and 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. We expect to see that continuing.

There will be a flip. At some point the non-op will come back in vogue and we'll start seeing better returns, but when you only have a couple deals and a bunch of people bidding on them, last couple quarters, it really hasn't been super attractive.

Thanks, I'll jump back in the queue.

Thanks, Jeff.

Thanks for taking my call. I'm trying to figure out what your run rate is for the June quarter right now.

You reported 6,700 BOE. You talked about 300 300 BOE of impact on production from storms and other things.

Are you above 7,000 right now as a run rate for the June quarter? Or can you just help me calibrate that?

Sure. Hey, Poe, this is Kelly.

Thanks for calling. I think we made it clear.

I don't want to speak out of school or Ryan will slap me, but the 300 is almost substantially all back online and was starting to get there before the end of the quarter, and 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 per day in TexMex.

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 and we don't want to aggregate if we have no data, we don't just guess. We have type curves, but you need to actually get data before you put it on there.

We've got 12 wells that were 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 could guess off my type curve, Poe, but that wouldn't be appropriate.

Again, we've got the 300 back online. We've got another 100 we fully expect and is in progress and working towards at TexMex, plus additionals from new wells that we don't have data on that were either already producing or getting there very shortly,

so. Poe, this is Ryan, it's probably helpful just sometimes to remind you guys on how from the non-op perspective how it works.

There are some wells in some areas where 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, 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 what production actually was for April yet.

From the royalty side, Poe, it's even more delayed just because you're further removed from the operator. Those in Oklahoma can be somewhat delayed by 180 days.

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'm not going to hold you to any guesses, but it sounds like the SCOOP/STACK you might get some data maybe 2 months would potentially hit the production for the June quarter.

Then the Haynesville and the Bossier is, probably, 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, yeah. I'm probably Is it 50?

Is it 50, 25, sort of just I'm not going to hold you to any guesses that you make, but I'm just trying to calibrate.

I understand. I don't think I'm comfortable speculating on that, so.

Okay. I'm not going to beat the dead horse then.

You talked about Chaveroo that 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, or is it more December quarter with potential impact in calendar '27?

As the operator there has undergone a merger, and it is our understanding that they are prioritizing assets and coming up with schedules. We're working with them closely, and 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 capital needs exactly when this is going to work out. I don't want to speculate and answer for them, I'm going to wait for that, Poe.

Okay.

We will update you when we know. How about that?

I guess so, but from a conceptual standpoint, those are shorter-term, shorter lead time, they're permitted, generally you can drill a lot quicker there than you can in other places. Okay.

Then on Delhi, is there any legal recourse that you have? There's quite a delay between the time that the contract went in place and then it hit the quarter.

Did I read in between the lines that you may have legal recourse?

I'm officially not going to answer that.

Okay. I think that's it.

Thank you.

I appreciate it. Thanks, Poe.

Really appreciate it, Poe. Thanks.

Thanks. There's no L in there.

That's Christmas time. Thank you.

It's Bair, B-A-I-R. Thanks.

Appreciate you're taking my call, and touched on a number of aspects of my questions. Is it fair to say that 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 so I'm just wondering was there any impact that is known as to flow rates or any reservoir damage, anything like that while these wells were shut in?

No, there weren't any damages. It's just the typical thing we have happen in the wintertime when we have bad weather.

Pardon me, getting over a cold. Typically we see at Barnett, which is the one that's slowest to come back, but it comes back.

It just takes it a few weeks to get back up to full rate.

Back to your perfect storm, we had one area where a lightning strike blew up a tank battery, right?

Oh, wow.

Yeah. Again, all covered by insurance, all fixed, but caused downtime for sure.

Then one thing, John, and it's Kelly by the way, thanks for calling, on the West Coast, we talk about some of the impacts of differentials from our Jonah gas, and how far from normal it was. Ryan talked about it a little bit.

Once in a 100 years plus kind of winter. What did they draw on the West Coast for gas, Ryan?

It was probably about 60 65 Bcf, which is pretty much the lowest I can find for a long period of time, right?

If

I recall right, I was going to say that it went the other way I think not long after you purchased that.

It did,

for

sure. Yeah.

That was kind of another follow-on question. I was going to say, okay, you got impacted because of warmer winter, but if it's a more hotter or more severe summer and there's higher demand, then this could flip the other way.

Is that a fair way of looking at it?

For sure. Ryan and I were 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, 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 plus kind of Bcf a day of natural gas usage. There will be a bounce back effect that's to our favor on this during the summer.

We think there's definitely potential for the differentials that we see right now in the summer months might be overstating kind of the potential high storage that we're going into right now in the injection season, so, with kind of a normal-to-warm summer, low snowpack, could set up for hopefully a little bit better demand on the summer cooling.

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, they're kind of in a bad spot there

as far

as I'm

We talked about elevated storage there. Honestly, they have so few days of coverage.

Just happened this particular winter, there was no sort of 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,

so. They've got around, 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, of the last 5 years, which is kind of increased the volatility. As you mentioned, John, we're not benefiting from this winter, but we've definitely been a beneficiary of in our 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.

That was a little disconcerting as I think it was referenced in an earlier questioner, the kind of 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, so that you're a little bit better aware of what's going on and what they anticipate.

Realize that as a non-op, it's perhaps a little more difficult, but still.

John, just FYI on that, we really actually have a very good relationship with Exxon, in my opinion, for I've worked with Exxon before and it's tough because they're a big company,

and

big companies do different things differently. We actually have a good relationship with them, I think, and they do talk to us.

It's just, they've had some difficult maintenance issues going on, and we treat them pretty much like the rest of our partners. Actually, I'd say they're definitely not the worst, which is a big plus because I was kind of afraid they could have been.

We've been really happy with them what they're doing.

Okay. That's good to hear, and I suppose that this field is kind of somewhat off their radar in the grand scheme of things for their size and so forth.

Thanks very much for taking the calls.

Thanks, John. Bye.

Morning, guys.

Good morning, Nick.

Kelly, I think you made a comment that the market for kind of non-op assets has been a little tight right now. I thought it was kind of encouraging that you sold what is it, $3.3 million of SCOOP/STACK non-op assets post quarter end.

Can I give you a little color on that?

That's exactly what I wanted. Go ahead.

Yeah.

Just to be clear, It is SCOOP/STACK, but it was from our minerals package, right? If you recall, we paid $17 million post-effective date what was the ultimate adjusted price?

16.1. $16.1 million for that package of royalties, but 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 has borne out to be a very good, high-return project at 16.1, if you knock another $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 going to be more near term at also very attractive rates which we were buying it.

That was the process there, Nick.

I think it makes total sense. I think you all have been active in the past with 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 know you all are always active kind of looking at your own assets and high-grading stuff.

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.

Then 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 would call that, as the Cajuns say, lagniappe, right?

Got it. All right, Kelly, I appreciate the time.

Thanks for the question.

Thank you, Nick.

Thank you. Ryan, on CapEx, do you have much visibility into the rest of calendar '26 from your operating partners?

No. I think at this point, it's going to be probably that we don't really on the SCOOP/STACK, which is the majority, as kind of our CapEx other than Chaveroo.

At that, 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. We'll come out with our official kind of '27 budget here probably on our next fiscal '27, that is, 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 obviously the activity we've talked about on the mineral side, that doesn't impact our capital budget, which is the nice thing about it.

All those wells coming on for SCOOP/STACK are not going to 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 have a high-margin addition to cash flow.

Yep, absolutely. We're excited about it, but again, we're going to 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.

Thanks for taking the follow-up here. Just a quick question.

Are you looking at any adjustments or any ways that you can adjust your hedging program given the current elevated prices and whatever? Is there any way that you can kind of high-grade that and my personal take is these prices, even if some solution to the Persian Gulf Straits 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 doing any high-grading of the hedging program?

John, this is Ryan. 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 isn't really that beneficial to create upside.

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 continue to start adding hedges in calendar '27, we're able to get $70-plus swaps and floors in some instances with higher collars, and so those prices into calendar '27 are pretty attractive, right?

To us, adding hedges out in the future at good prices is really what we're doing for the most part with this kind of spike. The other point I'd make is we are not completely hedged out on our crude, right?

We've still got for this kind of 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 kind of the heavier parts of the barrel for the NGLs.

We're still going to see some of that upside, as Kelly kind of mentioned in his comments, but really near term, there's not a lot of restructuring opportunities. We're just going to take advantage of adding stuff in '27.

Very good. All right.

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, but just kind of food for thought there. Thanks again for taking my questions.

Hey, John, really appreciate your interest in your call, and we agree. I think good old USA's the place to be, so.

Yep. Very good.

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.