Prepared remarks
Good morning, and welcome to the Evolution Petroleum Third Quarter 26 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 call over to Brandi Hudson, Investor Relations Manager. Please go ahead.
Thank you. Welcome to Evolution Petroleum's fiscal Q3 2026 Earnings Call. I am joined today by Kelly W. 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, 05/13/2026, and any time-sensitive information may not be accurate at a later date. Our discussion today will contain forward-looking statements as 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 statement. 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 are 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 the 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 do not reflect any change in the underlying quality of our assets, our cost structure, or our strategy. These were largely timing-related and one-time in nature; 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 6.7 thousand 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 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. 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 11, 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 26. 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 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 31 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 March where spot prices for WTI were over $100 per barrel. No one knows where WTI will be at June 30, 2026, but where we sit today, I 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 will 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 continue 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 interest 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 Chavaroo, 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 approximately 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 six wells and 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 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 six 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 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 the 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 were 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 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, and good morning, everyone. As Brandi mentioned earlier, we released our earnings yesterday, which contains more information on our results. For today, I would 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 dislocation 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 for the quarter was $2.9 million compared to $800 thousand 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 in 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 ten 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, the continued benefit of the cessation of CO2 purchases at Delhi, partially offset by the addition of the Tex Mex 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 benefits us in other periods and will provide more predictable and stable cash flows over time. Turning to the balance sheet: as of March 31, 2026, cash on hand totaled $2.6 million, borrowings under our credit facility stood at $56.5 million, and $800 thousand in letters of credit were 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 will 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 fiscal Q4 and thereafter. We look forward to updating you on our progress. With that, I will turn it over to the operator to begin the Q&A session.
Questions and answers
Thank you. We will now begin the question and answer session. If you are using a speaker phone, 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, at this time, we will pause momentarily to assemble our roster. Our first question comes from Jeffrey 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 whether you want to, as you alluded to in the press release—to do anything different with respect to marketing your equity production from that field?
Jeffrey, I'm going to flip that—excellent. I know you asked me, but I am going to flip it over to Ryan to answer.
Yes. So that is part of the thing we have actually been actively looking at, and we do have a lot of flexibility in the JOA to take the production in kind. We are actively looking at that now. The one point I will make on the actual changes is, obviously, it was a move from Denbury to Exxon. The ultimate contract with Plains has not changed that much other than they are now trucking where in the past they had a pipeline that went down. So that is really the biggest difference in kind of charges. But to directly answer your question, we are definitely looking at that and it is something we are actively considering. We think we probably can do a little 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 what they were in your second fiscal quarter?
Yeah. I mean, in gathering, there is nothing that has been out of the ordinary that I am aware of in the past quarter. Those have been relatively constant. There are some contracts we mentioned in the past like Barnett that are tied a little bit to natural gas pricing, so it will move a bit. But overall, it is more volume-driven, right?
And so I would not expect those to vary much from historical. Can you talk about what kind of communications you are 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 or couple of months?
Yes. So Jeff, our operators are all working towards that. In fact, we mentioned one in particular—Tex Mex—they really accelerated their second round of workovers to bring things online in New Mexico, largely because the prices went up and so the timing was really good. We sped that up somewhat. So yes, everybody's looking at making sure that they keep as much oil production on as possible.
And Jeff, I'll just add on: Mark's right—across the board, we are seeing it. These are simple projects that are fast. 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 high-return projects that can be done quickly and could be meaningful. We have seen a lot of operators try to do that as much as they can. In Hamilton Dome, you are seeing activity increase across the board.
And then lastly, 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?
Yes. It is interesting. On the non-op side, I would almost argue there is a dearth of availability—there is not a whole lot out there. On the mineral side, working with folks we have a lot of confidence and trust in, we have been able to do sort of bespoke deals and execute on them. Minerals, especially when you can build them in small parcels like we have been, are more liquid and we can find real dislocations and opportunities. The folks we are working with have been doing a great job finding those, and we expect to see that continue. There will be a flip, but at some point non-op will come back in vogue and we will start seeing better returns. When you only have a couple of deals and a bunch of people bidding on them, it has not been super attractive in the last couple of quarters.
Thanks. I will jump back in the queue.
Our next question comes from Poe Fratt with Alliance Global Partners. Please go ahead.
Thanks for taking my call. I am trying to figure out what your run rate is for June right now. You reported 6.7 thousand BOE; you talked about 300 BOE of impact on production from storms and other things. Are you above 7 thousand right now? What is your run rate for June or can you just help me calibrate that?
Sure. Poe, thanks for calling. The 300 is almost substantially all back online and we were starting to get there before the end of the quarter. If there was anything left over, it is pretty much there now. We are well underway in our progress on adding about 100 net BOE per day from Tex Mex, and we also have 12 wells in our royalty properties in SCOOP/STACK that we know are on production but we just do not have data yet. In Oklahoma it can take a while to get first production and revenue data, so we expect to get that data and include it in our fourth quarter results. Same thing with our Haynesville and Bossier assets—we have 23 wells that we expect to come online and contribute in fiscal fourth quarter; at least 20 of them have already completed. I cannot give you a precise run-rate number now without actual revenue statements for April and beyond, but the 300 net BOE per day is largely back and the additional 100 in Tex Mex is in progress, plus the wells for which we are awaiting data.
Poe, it might be helpful to remind folks 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 will not probably really know true April production for another week or two until we actually start getting our revenue statements in for the month of April. So as we sit today, we still do not have actual revenue statements yet for April production. From the royalty side, it is even more delayed because you are further removed from the operator—those in Oklahoma can be delayed by many months. So where we get information we start applying and accruing for it, but sometimes we do not know about it until it actually comes on.
Okay. It sounds like SCOOP/STACK might get some data maybe in a couple months and then the Haynesville and Bossier probably in the September period. But what could potentially be the impact from SCOOP/STACK if you do get the data in June? Is it 50, 25? I am not going to hold you to any guesses, I am just trying to calibrate.
I am not comfortable speculating on that number without actual data. We have type curves, but you need actual data before you include it in reported results. So I would not want to guess a specific figure. We expect to get more clarity soon and will report it when we can.
Regarding Chavaroo, you asked if the operator will pull the trigger in September or December for the next six wells. As you know, the operator there has undergone a merger and it is our understanding they are prioritizing assets and working on the schedule. We are working with them closely and trying to get things scheduled as quickly as we can. It is too early to say at this exact point in time, but we are working to understand when this will fit into their plans.
How about Delhi—any legal recourse that you have? There is quite a delay between the time that the contract went in place and when it hit the quarter. Did I read between the lines that you may have legal recourse?
I am not going to answer that.
Okay. Thank you. I appreciate it.
Our next question comes from John Baer with Ascend Wealth Advisors. Please go ahead.
Thanks. Appreciate you taking my call. I have a few questions. First, is it fair to say this was a perfect storm where multiple areas were impacted? Also, are flow rates back and was there any impact to flow rates or reservoir damage while these wells were shut in?
No, there were not any damages. This is the typical effect we see in the wintertime when we have bad weather. Barnett is the slowest to come back, but it does come back—just takes a few weeks to get back up to full rate.
We had an isolated incident where a lightning strike blew up a tank battery—covered by insurance and fixed—but it did cause downtime. Overall, we expect production to return to normal rates as uptime improves. On the West Coast impacts to differentials from Jonah gas: when you have a good snowpack, a wet cold winter means more hydro generation in the summer, which reduces gas demand for power generation. When you have essentially no snowpack, summer cooling demand can require an extra 1.1+ BCF per day of natural gas usage in the region. So there can be a bounce-back effect in the summer that is to our favor.
Out of all regions of the country, the West Coast has the least storage relative to usage—generally around 30 days or less of storage based on typical demand, which increases volatility. We were not able to benefit this past winter, but we have benefited from higher pricing due to this volatility around the asset.
Regarding Delhi, any anticipation that CO2 purchases will need to be resumed or ramped up anytime soon that could be impactful?
No, they do not have plans at the moment to purchase additional CO2. With the reservoir work we have done, we actually think CO2 utilization is improved by reducing the amount of CO2 being put into the system. So we do not have any disagreements with the current approach and it helps our operating costs.
One more thing—communication with the operator appears to have been lacking in some areas. I hope you will be able to improve communication and updates so you are better aware of what is going on.
Just to add, we actually have a good relationship with Exxon. Big companies do things differently, but we have been happy with what they are doing and they do talk to us. They have had some difficult maintenance issues, but we treat them like the rest of our partners and have been satisfied with the interaction.
Thanks, John. We appreciate your interest and call.
Our next question comes from Nicholas Pope with Roth Capital. Please go ahead.
Good morning, guys.
Good morning, Nick. I think you made a comment that the non-op market has been a little tight right now.
I thought it was encouraging that you sold $3.3 million of SCOOP/STACK non-op assets post quarter end. Can you give a little color on that?
Yes. To be clear, that was SCOOP/STACK but it was from our minerals package. We paid $17 million before post-effective-date adjustments for the package of royalties and the ultimate adjusted price was $16.1 million for that package. The difference between effective date and closing date is cash flows. We placed the vast majority of that on the assets we kept. There were some locations that could be viable home-run candidates but were further out in time. We front-loaded our valuation work and sold some of the longer-dated pieces to redeploy capital into positions we believe will be completed more near term and begin to add cash flows. Knock $3.25–$3.3 million off that package and it was a very strong outcome. We expect to redeploy that capital into attractive near-term opportunities.
Makes sense. Is there other opportunity to divest non-op assets in the near term? I know you are always active in high-grading assets.
There are, for sure. A couple need to season a bit more, but there are always smaller pieces you can flip. If I were modeling, I probably would not account for it, but you can call that lagniappe.
Thanks for the question.
Up next, we have a follow-up from Jeffrey 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 our operating partners, no. On SCOOP/STACK, which constitutes a majority of our CapEx other than Chavaroo, we are not getting a lot of drill schedules. We are seeing AFEs and activities but not much visibility on capital. We are not budgeting much more than we have already spent this year right now. We will come out with our official fiscal 2027 budget on our next call, but at this point we have not seen a lot of non-op activity that would materially change our current outlook. The mineral-side activity does not impact our capital budget—that's a nice feature. The wells coming on in SCOOP/STACK are not going to impact our capital budget.
Got it. The mineral interest production you talked about should be a high-margin addition to cash flow as it comes online?
Yes, absolutely. We are excited about it. We will gain more information this quarter and going forward as more wells are completed.
Our next question is a follow-up with John Baer from Ascend Wealth Advisors. Please go ahead.
Thanks for taking the follow-up. Are you looking at any adjustment or ways you can adjust your hedging program given the current elevated prices? Any way to high-grade the hedges?
John, we have looked at restructuring, but near-term restructuring opportunities—like converting collars to swaps—would be expensive given current prices, and would not create meaningful upside without significant cost. What we are doing is adding hedges in calendar 2027 where prices are attractive. We are able to get floors and swaps in 2027 at favorable levels. For the near term, we still have some unhedged crude exposure—roughly 30% unhedged for our fiscal fourth quarter—and all of our NGLs are unhedged, so we will receive upside there. But near-term restructuring of existing hedges is not particularly attractive; adding hedges out in the future at good prices is the approach we are taking.
Very good. Thanks again for taking the question.
Thank you. I would now like to turn the call back over for any closing remarks. Thanks, everybody, for attending. As we move forward, we are excited about the future and appreciate your interest. We look forward to updating you on progress.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.