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.

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 a 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.

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. Looking at the broader energy market, as we all know, oil prices softened during April, falling nearly $12 a barrel in one week to below $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 of 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 one-time 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 low 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?

Thanks, Kelly, and good morning everyone. I will highlight key operational achievements from the quarter and encourage listeners to check our earnings press release and filings for more details about our asset base. At SCOOP/STACK, we have brought online 13 gross wells in the fiscal year to date, with another five in progress. Since the acquisition's effective date, a total of 35 gross wells and 0.6 net wells have been completed. At Chaveroo, we successfully finished and brought online four new gross wells in the second development block of the field. All four were drilled and completed on schedule and under budget. Production began about two weeks ago, and while it is too early to evaluate production trends, initial rates have significantly surpassed our expectations. We will monitor these wells closely and provide a performance update in the coming quarter. At Delhi, production was temporarily impacted by planned maintenance at the Delhi central facility, which caused a field-wide shutdown for a few days, as well as at the NGL plant for about two weeks. By the end of the quarter, we decided to switch from purchasing around 80 million cubic feet per day of CO2 to injecting additional water instead. Exxon will continue to inject around 300 million cubic feet per day of recycled CO2, which we believe is the most economical approach to operating the field and will significantly lower operating costs while maximizing cash flow. In the Williston Basin, we saw good run time for the quarter, with production increasing quarter-to-quarter due to deferred oil sales and issues with third-party gathering systems experienced in the previous quarter. The Williston field continues to deliver solid returns. At Hamilton Dome, production remained steady throughout the quarter with no significant operational activity or downtime. The field continues to perform reliably, providing consistent oil volumes as expected. Jonah also remained stable during the quarter, with temporary volume fluctuations in February, and strong winter natural gas pricing positively impacting its cash flow for the quarter. Barnett Shale provided consistent cash flow generation in the third quarter. Despite some short downtime in January due to winter storms, production remained steady overall, supported by improved pricing for natural gas and NGL. These favorable pricing trends helped to counterbalance broader commodity price weakness and highlight Barnett's ongoing importance to our diversified portfolio. Now, I will turn the call over to our CFO, Ryan Stash, for a more detailed review of our financials. Ryan?

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.

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 and diligence of our team, and the 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.

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

Good morning, guys. Thanks for the time.

Thank you.

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.

Sure, Jeff. Regarding the oil market, if we consider the forward pricing over the next 12 to 18 months, it's likely that domestic crude oil production will decrease. The current strip price isn't sufficient for profitable drilling due to the high decline rates of many new wells across the country. Unless there’s a significant increase in demand, which I don't anticipate, these tariffs appear to serve more as negotiation tactics rather than severe trade barriers. Consequently, crude production will decrease before needing to rebound, which will ultimately result in higher prices. If we're positioning ourselves on long-life, low-decline assets based on the strip pricing, I'm quite optimistic. If there’s only a slight decline, say 7%, and we purchase at today’s strip price with the expectation that prices will recover in a couple of years, it creates a strong acquisition opportunity. We're actively observing the market, especially since some funds are nearing the end of their lifecycle and need to sell assets, creating more activity. We've noted some acquisitions occurring as companies divest non-core assets, which aligns with our strategy. On the natural gas front, the situation is quite favorable, with a positive forward pricing trend. Companies are willing to accept sales at a discount knowing that current prices are decent. Securing low decline assets at a reasonable discount with a couple of years of hedging fits well with our approach. While this may not directly answer your question, it's how we are currently viewing M&A opportunities, and we see plenty across both oil and gas sectors.

Yes, I would just add that one of the areas where we're seeing activity is SCOOP/STACK, which is great because we have a presence there. If you're considering regions with a good balance of oil and gas, there's still a lot of market movement because of the flexibility available. We're encouraged by the activity we're observing in SCOOP/STACK.

Got it. That's really helpful. Thank you, everyone. At Chaveroo, I'm interested to know that the wells came in cheaper and are performing better, which is great news. Can we quantify how much under budget those wells were? Also, regarding production, I understand it's still very early, but is there anything different about the location of these wells or the completion technique that might explain the positive early results? Or is this simply a general trend, where some wells perform better or worse than the expected curve?

Okay, Jeff, it's Mark. Thanks for calling in. Your first question was about quantifying how much below AFE we are. We believe we're slightly below 5% of AFE, which is really good. In terms of quantifying the performance of the wells, we are about 7 miles away from the 500 wells; the first two wells we drilled, the Jennifer wells, are located to the east in a different part of the reservoir. We didn't encounter as much fracturing, which contributed to drilling within budget since we faced fewer drilling problems. Honestly, if you look at it, the performance distribution for these wells resembles a bell curve, varying throughout the field. So, we are trying to determine the average performance, but these wells have performed exceptionally well. They are currently about 50% higher than our initial production expectations on average.

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.

Not what we think. We had some lateral lengths on the initial round of wells that were shorter than usual, one of the last we drilled was significantly shortened and was about half the normal length. However, it also had a very good fraction, which contributes a lot to productivity. Honestly, the completion and drilling techniques were very similar to last time. We did implement some cost optimization measures that helped us out, particularly in cases where we lost a lot of fluid, allowing us to significantly reduce our drilling fluid costs. Ultimately, it was the same practice but a different reservoir rock that we encountered.

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

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

Hi, thank you. I'm standing in for Jeff Robertson today. I have a quick question about the Delhi EOR project. It seems there has been a transition from CO2 flooding to a waterflood development strategy. I'm interested in your thoughts on how this might affect the long-term lease operating expenses for the field. Thank you.

Yes, this is Kelly. Thank you very much. I'm glad you brought it up because I'm not sure everyone is paying attention to this. When Exxon decided to stop adding purchased CO2 to the field, we felt it was a great move. We've been asking Denbury to do this for the past couple of years. While I'm sure Exxon didn't listen to us and made this decision independently, this is exactly what we've wanted for a long time. By maximizing the efficiency of the recycled CO2 and replacing the purchased CO2 with more water, we anticipate saving about $400,000 to $500,000 per month in costs without expecting much, if any, difference in performance. Previously, when CO2 purchases decreased, they were not replaced with increased water injection, resulting in a loss of pressure. Now, they're going to increase water injections to maintain that pressure at a significantly lower cost. This is simply a much more economical way to manage the field, and we find it very exciting.

To provide updates on the LOE side, we can look back to last year when our costs were down, hovering around $25 per barrel. Moving forward, production metrics are crucial, and as Kelly mentioned, we anticipate costs to be about $0.5 million per month, translating to mid-20s per BOE for LOE costs.

Awesome. Thank you.

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

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 410 BOE a day?

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.

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

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.

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.

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.

I can tell you right now the two added together are actually higher than $850.

That's helpful. You spent $4.4 million on capital expenditures in the quarter. Can you share how much you plan to spend in the fourth quarter? Also, is it too soon to anticipate a rough estimate for capital expenditures in fiscal 2026?

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.

Okay. And then, 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?

I mentioned this before, and I know you're relatively new to the company. Our credit facility terms are very favorable compared to the broader market. We managed to maintain those terms, which I believe benefit us regarding both the drawn spread and hedging covenants, while also adding another bank. MidFirst increased their hold from $50 million to $55 million, which is one of their higher levels for this sector. To gain the extra capacity, which we deemed important for flexibility, we needed to involve another bank. This bank is familiar with MidFirst and is comfortable with us in terms of credit and the facility terms. This is the rationale behind the addition. MidFirst has been a great partner. If we pursue a larger, more transformative deal, we would need to involve other banks. We've discussed this, but we see this as an intermediate step to expand the facility, maintain the terms, and increase the size.

Great. Thank you so much.

Thank you.

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

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.

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