Evolution Petroleum Corporation (AMEX:EPM) Q3 2025 Earnings Call Transcript

Evolution Petroleum Corporation (AMEX:EPM) Q3 2025 Earnings Call Transcript May 14, 2025

Operator: Good morning, everyone, and welcome to the Evolution Petroleum Fiscal Third Quarter 2025 Earnings Conference Call. All participants are in a listen-only mode. Please also note today’s event is being recorded. At this time, I’d like to turn the call over to Brandi Hudson, the company’s Investor Relations manager. Ma’am, please go ahead.

Brandi Hudson: Thank you. Welcome to Evolution Petroleum’s fiscal third quarter 2025 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 2025 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 14, 2025, 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 statement. During today’s call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA and adjusted net income. Reconciliations of these measures to the closest comparable GAAP measures can be found in our earnings release. Kelly will begin today’s call with opening comments and review of the company’s ongoing plans and strategy. Mark will provide an update on operations during the quarter, and Ryan will provide a brief overview of our fiscal third quarter financial highlights.

After our prepared remarks, the management team will be available to answer any 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.

Kelly Loyd: Thank you, Brandi, and good morning, everybody. Our fiscal third quarter results demonstrated Evolution’s commitment to disciplined capital allocation and strategic execution. We stayed grounded in our core strengths, allocating capital prudently to high-quality, low-decline assets, maintaining our long-standing dividend and generating positive cash flow. Our diversified portfolio, robust hedging strategy and measured approach to development is enabling us to weather market volatility while continuing to deliver long-term value. Subsequent to quarter end, we closed the Tex-Mex acquisition and brought online four new wells in our second Chaveroo development block. Together, these additions are currently contributing more than 850 net barrels of oil equivalent per day and are expected to meaningfully benefit our fiscal fourth quarter production and cash flow, especially when coupled with the recent strength in natural gas pricing.

We also expect to see production adds from ongoing activities in our SCOOP/STACK area. The Tex-Mex acquisition, which closed in April, adds approximately 440 of stable, low decline production with a balanced commodity mix of 60% oil and 40% natural gas. The $9 million transaction was completed at a very attractive valuation of approximately 3.4 times forward adjusted EBITDA based on current strip pricing, underscoring its strong near and long-term accretion even amid recent oil price volatility. The portfolio consists of producing wells across New Mexico, Texas and Louisiana and aligns with our long-term strategy to own cash-generative low-risk assets. Consistent with our disciplined approach, we structured this transaction to preserve the strength of our balance sheet.

The $9 million purchase was funded through a combination of cash on hand and a modest $2 million draw on our credit facility. We are now working closely with the operator to evaluate low-cost reactivation opportunities that could provide additional long-term upside. This marks our seventh highly accretive acquisition in six years, and we continue to see an encouraging M&A market, even more so now amid oil price volatility. In the last six years, we’ve invested $136 million to grow production by more than 3.5 times, all while returning capital to shareholders with our quarterly dividend. With a well-established track record, we remain confident in our ability to source, evaluate and integrate high-quality non-operated assets at incredible value.

Taking a look at the broader energy market, as we all know, oil prices softened during April, falling nearly $12 a barrel in one week to sub-60. However, natural gas prices have strengthened of late, providing a partial offset to the softness in crude prices. Our diversified commodity exposure helped mitigate the impact of weaker oil revenue. Our third quarter natural gas revenue rose 33% year-over-year to $7.8 million and NGL revenue was up 14% to $3 million, partially offsetting a 19% decline in oil revenue. This volatile market environment underscores the value and resiliency of our diversified portfolio. We remain well hedged on oil with approximately 40% of oil volumes hedged at prices above $70 through the fiscal year-end, providing a strong safety net that supports both our CapEx program and dividend.

Operationally, our operators executed well despite some temporary disruptions during the quarter. Total production declined 7.5% year-over-year to 6,667 barrels of oil equivalent per day, primarily due to planned maintenance at Delhi and weather-related downtime in Barnett. Overall, we are maintaining our focus on operational execution and continue to make meaningful progress across our various development programs. As I mentioned earlier, we drilled and completed four new gross wells in the second Chaveroo development block, which were brought online shortly after the quarter ended. While it’s still too early to fully assess how the wells will perform, we’re encouraged by the efficient execution drilling and completing the four wells for less than budget and the highly positive initial results.

Mark will have more updates to share across our portfolio shortly. In terms of capital allocation, dividend sustainability remains a top priority for us. On May 12, our Board declared a cash dividend of $0.12 per share of common stock, marking our 47th consecutive quarter of issuing a dividend and our 12th consecutive quarter at $0.12 per share. It’s important to underscore that this dividend was not declared as a onetime event. Despite the ongoing volatility in commodity prices, the Board’s decision reflects our confidence in Evolution’s ability to sustain dividends at this level over the long-term. Our ability to generate strong operating cash flow driven by our diversified portfolio of assets enables us to meet our capital requirements, repay debt and continue to return capital to shareholders.

To-date, Evolution has returned approximately $131 million or $3.93 per share to shareholders in common stock dividends. Looking ahead, our strategy remains focused on preserving financial flexibility, sustaining our dividend, and pursuing opportunistic growth. The fruits of our disciplined acquisition and development strategy during fiscal Q3 will be made obvious in our fiscal fourth quarter when we will see the effects of our Tex-Mex acquisition and our four new Chaveroo wells begin to contribute to our quarterly results. While we are committed to long-term development, we recognize that there are optimal times to develop new wells and optimal times to acquire new assets. In light of the recent market volatility, we in coordination with our operating partner at Chaveroo, have made the decision to delay the start of our third development block to later into our fiscal year 2026.

We believe it’s prudent to now focus our development activities toward gas-weighted opportunities particularly in the SCOOP/STACK. This disciplined strategy enables us to preserve near-term cash flow, while positioning us to resume development when oil prices are more favorable. By maintaining a measured development approach in a low price environment, we are effectively preserving long-term resource value for our shareholders. In the interim, we’re actively pursuing opportunities in what we view as a highly attractive market to acquire oil-weighted load decline producing assets or natural gas properties with favorable hedging potential. All said, our decision-making will remain grounded in disciplined capital allocation, financial flexibility and a commitment to delivering long-term value for our shareholders.

With that, I’ll turn the call over to our COO, Mark Bunch, to review our operations in more detail. Mark?

Mark Bunch: Thanks 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 details across our asset base. At SCOOP/STACK, 13 gross wells have come online fiscal year-to-date. We have another five gross wells in progress — since the effective date of the acquisition, the total of 35 gross wells are 0.6 net wells have been brought online. At Chaveroo, as Kelly mentioned, we successfully completed and brought online four new gross wells in the second development block of the field. All four wells were drilled and completed on schedule and under budget. Since production commenced about two weeks ago, it is too early to assess production trends, but so far, initial rates have significantly exceeded our expectations.

We will continue to monitor these wells closely and we’ll provide an update on performance in the coming quarter. At Delhi, production was temporarily affected by planned maintenance at both the Delhi central facility, resulting in the shutdown of the entire field for a few days and the NGL plant for approximately two weeks. At the end of the quarter, the decision was made to switch from purchasing of approximately 80 million cubic feet per day of CO2 to injecting additional water instead. Exxon will continue to inject approximately 300 million cubic feet per day of recycled CO2. We believe this will be the most economical way to run the field and will significantly reduce operating costs while maximizing cash flow. In the Williston Basin, we experienced good run time for the quarter.

Production was up quarter-to-quarter due to deferred oil sales and third-party gathering system issues experienced in the prior quarter. The Williston field continues to generate solid returns. At Hamilton Dome, production remained steady throughout the quarter with no notable operational activity or downtime. The field continues to perform reliably delivered consistent oil volumes in line with expectations. Jonah also remained steady during the quarter with a temporary different volumes during February, strong winter natural gas pricing contributed positively to its overall cash flow for the quarter. Barnett Shell delivered consistent cash flow generation in the third quarter. Despite some brief downtime in January due to winter storms, production and steady overall, with improved pricing for natural gas and NGL serving as a tailwind.

These favorable pricing dynamics helped offset broader commodity price weakness and underscore Barnett’s continued role as a valuable contributor to our diversified portfolio. With that, I will turn the call over to our CFO, Ryan Stash, to review our financials in more detail. Ryan?

Ryan Stash: Thank you, Mark, and good morning. As Brandi mentioned earlier, we released our earnings yesterday, which contains more information on our results. Now, I’d like to go through our fiscal third quarter financial highlights. In fiscal Q3, we had total revenues of $22.6 million, down 2% year-over-year. The decline was driven primarily by an 8% decrease in production volumes, partially offset by a 7% increase in average realized commodity prices, driven by stronger natural gas and NGL prices. The decrease in production volumes was largely due to downtime at Barnett in January due to winter storms and one week of planned maintenance at Delhi, partially offset by higher production from a full quarter of contribution from SCOOP/STACK compared to the prior year period.

Net loss for the third quarter was $2.2 million or $0.07 per share compared to net income of $0.3 million or $0.01 per share in the year ago period. After excluding the impact of unrealized hedging losses, adjusted net income for Q3 was $0.8 million, or $0.02 per diluted share compared to $1 million or $0.03 per diluted share for the prior year period. Adjusted EBITDA was $7.4 million compared to $8.5 million in the year ago period. The decrease was primarily due to lower revenue as a result of lower production volumes and higher total operating costs due to CO2 purchases at Delhi, which were suspended in February 2024, but were resumed last October. However, adjusted EBITDA for Q3 was 30% higher than Q2, primarily as a result of higher commodity prices, especially natural gas and NGLs. Our hedging program remains a key pillar of our risk management strategy.

We believe our proactive approach to hedging, coupled with our diversified portfolio, position us well to navigate continued volatility, while sustaining our dividend and meeting capital commitments. We will continue to monitor the markets and opportunistically add hedges as necessary to preserve long-term cash flow stability to support our dividend. We have negotiated with our lender to provide additional flexibility for our hedging program to allow us to hedge additional gas volumes instead of crude oil to meet the hedging obligations under our credit facility. At March 31, 2025, cash and cash equivalents totaled $5.6 million and borrowings outstanding under our revolving credit facility were $35.5 million, giving us total liquidity of $20.1 million.

In fiscal Q3, we paid $4.1 million in common stock dividends, made $4 million in repayments on our senior secured credit facility, paid $1.8 million in deposits for the Tex-Mex acquisition and incurred $4.4 million in capital expenditures. During the quarter, we also sold a total of approximately 0.2 million shares of common stock under our at-the-market sales agreement for net proceeds of approximately $1.1 million after deducting less than $0.1 million in offering costs. In regard to our revolving credit facility, we have received approval from our lender MidFirst Bank to extend the maturity of our facility to April 2028 and increased their total commitments from $50 million to $55 million. Also, we expect to receive $10 million in additional commitments from a new lender, Prism Bank, which will bring our total commitments to $65 million.

We currently expect to close on the additional commitments and the maturity extension during our fiscal fourth quarter. Yesterday, we declared a quarterly cash dividend of $0.12 per share payable on June 30, 2025, to stockholders of record on June 13, 2025. This will be our 47th consecutive quarterly dividend underscoring our commitment to returning capital to shareholders and maintaining a stable and reliable dividend policy. I’ll now hand it back over to Kelly for closing comments.

Kelly Loyd: Thanks, Ryan. Evolution continues to perform well operationally, financially and strategically. Our third quarter results underscore the strength of our diversified long-life asset base and our ability to meet all capital commitments, debt repayment and return capital to shareholders. This reflects the benefits of a balanced portfolio that can both flourish in favorable pricing environments and withstand cyclical lows. As we look ahead, our priorities remain unchanged, maintain and look to grow our long-standing dividend, preserve financial flexibility and grow free cash flow. We will continue to deploy capital with discipline, prioritizing acquisitions and focusing development on natural gas-weighted areas while deferring oil-weighted drilling to optimize value and timing.

Backed by a resilient business model and consistent execution, in addition to the hard work indulgence of our team, and guidance of our Board of Directors, Evolution’s low cost, non-op business model is well positioned to navigate commodity cycles and deliver long-term value to our shareholders. With that, I’ll turn it over to the operator to begin the Q&A session. Thank you very much.

Q&A Session

Operator: We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Jeff Grampp with Northland Capital Markets. Please go ahead.

Jeff Grampp: Good morning, guys. Thanks for the time.

Kelly Loyd: Thank you.

Jeff Grampp: Kelly, you talked about some encouragement in the M&A market. I’m hoping you could touch a bit on bid-ask spreads that you’re seeing as we tend to see oil prices get weaker? I know that, as spreads can kind of widen and that make it challenging to get deals done. But it seems like you’re still encouraged nonetheless. So curious to get your thoughts there? And then just if you’re seeing any divergence in terms of oil versus gas weighted acquisitions, are there any trends or themes you can share in that regard? That would be helpful. Thanks.

Kelly Loyd: Sure, Jeff. Look, the way I kind of look at it, if you go on the oil front, I mean, look, if oil is going to follow the strip, which is sort of what we use in our budgets for, say, the next 12 to 18 months, I think we can all have a very strong estimate that domestic crude oil production is going to decline. And the returns just aren’t enough for enough profitable wells to be drilled at the strip price — the country has got so many new wells with super high declines nationwide. I mean, unless you have a major demand shock, which I don’t think we’re going to, these tariffs seem to be more of a negotiating tool than trade killers you’re going to have to have crude production will go down and then you’re going to have to have it go back up.

And the only way to do that is be the price mechanism, so prices will go higher. So if we’re out there negotiating on the strip, on long life, low to client staff, I really like where we are on that. And again, if it only like tax mix, right? So only declined 7% and you buy it on today’s strip. And if you’re expecting in a couple of years or less, prices to move back up, and it’s a heck of a place to want to go acquire. And so we are seeing stuff out there. We’re seeing — some of this is led by funds coming to the end of their life and needing to monetize. So you’re always going to have that sort of activity and just natural stuff. You’ve seen some acquisitions. Guys need to get rid of their non-core stuff, which is great, right where we want to be.

So you’re seeing that. And on the natural gas side, I mean, it’s the opposite, right? You have a really nice, favorable scrip going forward. So guys are willing to get paid on a discount to that because they know they’re getting a decent price right now. So if we can lock in a reasonable discount to that on low decline stuff for couple of years of hedging or so, then I mean, that fits right in our wheelhouse. So I don’t know if that exactly answers your question, but that’s sort of how we’re looking at the world in M&A right now. And we’re seeing lots of opportunities across both sides.

Ryan Stash: Yes. I would just — Jeff, I would just add, one of the areas we’re seeing activity is SCOOP/STACK, which is nice because we obviously have a position there. But if you’re looking at areas that have a nice mix of oil and gas, I think, you’re still seeing folks go-to-market because there’s optionality throughout there. And so we’re encouraged by seeing some activity at least in SCOOP/STACK for sure.

Jeff Grampp: Got it. That’s super helpful. Thank you, guys. And at Chaveroo, I’m curious, it seems like wells came in cheaper and I know it’s still early but performing better. So good news on both fronts. But — can we quantify at all? How much under budget those wells were? And then on the production side, I know it’s still super early, but is there anything different about either the location of these wells or the completion technique that could explain the early time positive results? Or is this just kind of general bell shape curve, where you’re going to have some wells above type curve, some that sort of thing.

Mark Bunch: Okay. Jeff, it’s Mark. Thanks for calling in, by the way. And so your first question was about how can we quantify how much below AFE. We think we’re a little bit below 5% for AFE, which is really good out here. And on the quantitative — if I can say the word, quantifying the performance of the wells, we’re about 7 miles away from the 500 wells, which is the first two wells we drilled, Jennifer wells are off to the east, and it’s a different part of the reservoir. We didn’t encounter as much fracturing. So part of the issue with being able to drill it within cost was that we didn’t have a lot of drilling problems when caused by fracturing. But honestly, it’s also if you want to know the truth, if you really look around it, it’s kind of like a bell shape.

You’re right. It’s a distribution of performance for these wells, and it’s going to vary throughout the field as you move around. And so you’re really just trying to like do the average of the wells, but these wells have come on really, really good. They’re probably about 50% high right now to what we expected them to be producing on average.

Jeff Grampp: Super helpful, Mark. Thanks. So to be clear, there was nothing different that you guys did on the second batch of wells in terms of completion practices or lateral lengths or anything that would explicitly explain at least the early time results we’re seeing.

Mark Bunch: Not what we think. I mean we did have some lateral lengths on the initial round of wells that were short end like the — the 504 — one of the last we drilled was shortened quite a bit is about half the normal level length. But it also had a really good fraction, which gives a lot of productivity. I mean, really, honestly, the completion technique and the drilling technique was very, very similar to the last time. We did do some things that would optimize cost and help us out there. And especially in the case where we lost a lot of fluid, we were able to reduce our drilling fluid cost by a lot. So — but honestly, it’s really just — it was the same practice, different reservoir rock that we hit.

Jeff Grampp: All right. That’s super helpful. Thank you, guys.

Operator: Thank you. And the next question comes from Chris Degner with Water Tower Research. Please go ahead.

Chris Degner: Hi, yes. Thank you. I’m here for Jeff Robertson today. And I just wanted to — just a quick question on the Delhi EOR project, and it looks like there’s been a shift from CO2 floods into more of like a waterflood type of development. I’m just curious if — do you have any views on what the impact might be on LOE over the longer-term development of the field. Thank you.

Kelly Loyd: Yes. Chris, this is Kelly. Thank you very much. Look, and I’m glad you brought it up because I’m not sure everyone is sort of paying attention to this. When Exxon decided to stop adding purchase CO2 to the field, honestly, we’re kind of like Halleluiah. We’ve been asking Denbury to do this for the last couple of years. No. But I’m sure Exxon didn’t really listen to us at all and came to this decision on their own accord, but this is what we really wanted for the last couple of years. Maximize efficiency of the recycled CO2, replaced the voltage with increased water instead of purchased CO2. It’s on the order of $400,000, $500,000 per month of cost savings to us — and we don’t expect much if any difference in performance.

In the past, when you saw CO2 purchases go down, it wasn’t replaced by more water injection. It was just a loss on pressure — now they’re going to use additional water injections to replace that pressure at a way cheaper cost. I mean it’s just a much more economical way to run the field, and we think this is very exciting.

Chris Degner: That’s great to hear. Thank you.

Ryan Stash: Just to give on the LOE side, when we look at earlier, one thing you could do is obviously look back earlier, last year when the line was down right on the cost side. And we were probably in the $25 per barrel plus or minus category there when that line is down. So — going forward, obviously, production is right because when you’re looking at a per barrel metric. But as Kelly said, we’re looking at about $0.5 million per month or on a go-forward basis, call it in the mid-20s on a dollar per BOE for LOE cost.

Chris Degner: Awesome. Thank you.

Operator: And the next question comes from Poe Fratt with Alliance Global Partners. Please go ahead.

Poe Fratt: Hey, good morning. I just wondered, if you could break out the net increase in production, it looks like you’re citing $850 BOE a day between Tex-Mex and Chaveroo. I thought I heard you say Tex-Mex was running about 440. So does that imply that currently Chaveroo is running about $440 or $410 a day?

Kelly Loyd: So yeah, I mean, the way I would look at it, right? So I think Mark said that we were significantly above our type curve. But look, I’ll just tell you, all four wells. The oil rate is still climbing. Like I think Mark said, we’re sort of at least 50% above where we had these things projected to come on. So again, super exciting, but we put a low ball safe number out there at $850. So I want to cover our bases there.

Poe Fratt: Just to clarify, though, that does include about $440 million from Tex-Mex?

Kelly Loyd: Yes, it does. That’s actually the latest number I have for Tex-Mex is about $440 BOE net. So I think it may be slightly higher than that, but that’s pretty close.

Ryan Stash: And the Chaveroo number that we said would be included at $850 million is only for the new wells. It does not include the first three wells.

Mark Bunch: Yes. And like I said, we don’t know where it’s going to settle out. I mean the wells are still climbing. So again, we want to put some sort of safe out there.

Kelly Loyd: I can tell you right now the two added together is actually higher than $850.

Poe Fratt: That’s helpful. And then you spent $4.4 million in the quarter as far as CapEx. Can you give me a sense on how much you’re going to spend in the fourth quarter? And then — is it too early to expect a ballpark CapEx number for fiscal 2026?

Ryan Stash: On the fiscal 2026, though, it is. I mean, I think we probably saw in our press release and prepared remarks, we’re working right now with our partner, PEDEVCO to figure out when we would start the fact, and obviously, that would be a big driver of CapEx for the next fiscal year. That plus any AFEs we receive at SCOOP/STACK, which we don’t really have a feel for until we get them. I will say we are doing outreach for the operators right now in Oklahoma just as we go for our year-end reserve reports. So maybe we’ll have a better feel for their budgets. So I think it’s a little early for us to put out anything next fiscal year. We’ll likely do that at our fourth quarter call, which is generally when we’ve done it. On the remainder of the year, so we do have some CapEx in the fourth quarter, we expect to spend on the completion side.

But we still think the overall budget that we put out for the full year is still valid. So I think that was, what, 12% to 14.5%. So we still think we’re going to have a little bit remaining for the Chevron wells on the completion side, possibly a little bit in SCOOP/STACK. But outside of that, we certainly don’t expect that much additional capital in the fourth quarter.

Poe Fratt: Okay. And then, the — can you just help me with the rationale for adding a new bank? Prism potentially is going to be added to your capital availability. And can you just talk about that, as far as opposed to even expanding the Midland a little bit larger?

Ryan Stash: Yeah. So I said this in the past, and obviously, I know you’re a little bit new to the name. So I think our credit facility terms are very favorable as you look at the broader market. And so what we were able to do is effectively keep those same terms, which I think — again, I think is favorable to us on both drawn spread and hedging covenants and keep them the same but add another bank. MidFirst, at kind of going from $50 million to $55 million, that’s kind of one of their higher hold levels for the space. So in order to get the additional capacity, which we thought was important just to give us flexibility we had to bring in another bank. And it was a bank that’s familiar with MidFirst, and a smaller bank that was comfortable with us from a credit side and the actual facility terms as well.

So I think that was kind of the reason. And obviously, MidFirst has been a great partner to work with us here. So I mean, if we were to obviously go larger with a larger, more transformative deal, we’d have to bring in some other banks. We’ve also — we’ve talked about that as well, but we think this is kind of an intermediate step in order to push out the facility, keep the terms the same, and increase the size middle essence.

Poe Fratt: Great. Thank you so much.

Ryan Stash: Thank you.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Kelly Loyd, for any closing remarks.

Kelly Loyd: Yeah. Thank you. Like I said, we just want to thank everyone for joining us on our call. And like I said, we’re really excited about the results we began to see from natural gas prices moving up. I think our natural gas revenue was up 34% in the quarter. And we’re excited about the opportunities in front of us and the portfolio we have. So thanks again for joining. Really appreciate it.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.