Good day, everyone, and welcome to the Evolution Petroleum Second Quarter Fiscal Year 2023 Earnings Release Conference Call. Please also note today's event is being recorded. At this time, I would like to turn the floor over to Ryan Stash, Chief Financial Officer. Please go ahead.

Thank you, and good afternoon, everyone. Welcome to our earnings call for the second quarter of fiscal 2023. Joining me today is Kelly Lloyd, our President and Chief Executive Officer and a member of our Board of Directors. After I cover the forward-looking statements, Kelly will review key highlights along with our operational results. I will then return to provide a more detailed financial review. And then Kelly will provide some closing comments before we open it up and take your questions. Please note that any statements and information provided today are time-sensitive and 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 risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. As detailed numbers are readily available to everyone in yesterday's earnings release, this call will primarily focus on our strategy as well as key operational and financial results and how these affect us moving forward. Please note that this conference call is being recorded. If you wish to listen to a webcast replay of today's call, it will be available by going to the company's website. With that, I'll turn the call over to Kelly.

Thank you, Ryan. Good afternoon, everyone, and thanks for joining us on today's call. Our results in the second quarter of fiscal 2023 were solid and continued to demonstrate our assets' ability to generate strong free cash flow. We used our cash flow to once again fund operations. We used it on capital spending and shareholder dividends. In addition, I'm pleased to report that we have delivered on our commitment to eliminate our remaining debt position during the period. We have now fully integrated multiple acquisitions, paid off our debt and are generating meaningful free cash flow to fund our strategic objectives. Of course, none of this would have been possible without the hard work of our team. I want to thank all of our team members for their continued dedication and strong execution as we remain focused on driving near- and long-term value for shareholders. During the second quarter, we paid a cash dividend of $0.12 per common share. This was 60% higher than the same period for fiscal 2022, which we view as a clear indicator of the growth and strength of our business. Our Board recently declared a cash dividend for the third quarter of fiscal 2023 of $0.12 per share. This will mark the 38th consecutive quarterly cash dividend paid by the company since we began our return of capital program in December of 2013. Since the inception of the program, we have returned more than $94 million or $2.85 per share of capital to shareholders. As we have discussed in the past, there are very few small-cap E&P companies that can say they have consistently paid a dividend for that length of time throughout several tumultuous commodity price cycles. We believe this reinforces the strategic view our Board takes as we prudently grow the business through the targeted acquisition of solid, long-life and low-decline assets that will continue to support a sustainable quarterly dividend for the immediate long term. In short, maintaining and ultimately growing the payment of a quarterly cash dividend remains front and center for our Board and management team. Turning now to operations. Second quarter fiscal 2023 production of 7,250 net BOE per day was down around 5% from the 7,598 net BOE per day for the first quarter of fiscal 2023. In large part, this was due to downtime associated with the severe winter storms we experienced and, to a lesser extent, some temporary compression issues and downtime in the Barnett associated with offset operator activity. As of now, and barring any future extreme weather circumstances, operations are back on track. Looking at our second quarter results in more detail, net production at Jonah Field for the second quarter was 1,902 BOE per day. Slightly impacting production levels in the second quarter was the decision to maximize natural gas production, thus reducing NGL recoveries during the period to capitalize on relatively higher natural gas prices, which averaged $11 per Mcf for the quarter. The Jonah Field is our most recent acquisition, and we remain pleased with its performance. Similar to our other assets, the field is highlighted by long-life, low-decline reserves that generate significant cash flow. In addition, the asset base provides access to attractive Western markets. Second quarter net production for our Williston Basin was quite flat to the first quarter at 489 BOE per day, of which approximately 76% was oil. The Williston Basin oil production was impacted by the winter storms during the quarter. However, this was offset by the reactivation of the gas pipeline. We are pleased to see the ONEOK gas pipeline come back online in late September for the first time since our acquisition. This has led to increased optionality for natural gas and NGL sales. In early January, we, along with the operator, Foundation Energy Management, began operations on one of our Bakken recompletions and continue to work closely with them on high-grading opportunities in the field such as expense workovers, additional recompletions and sidetrack drilling opportunities. Also, technical evaluations remain underway to assess our Pronghorn and Three Forks drilling locations. Net production for the Barnett Shale for the second quarter was 3,304 BOE per day, of which approximately 76% was natural gas. As discussed previously, impacting sequential production volumes were severe winter storms, temporary issues at select compression stations and certain offset operator activities, all of which have been addressed. Hamilton Dome Field net production was substantially flat for the second quarter at 413 BOE per day. We continue to support the operator, Merit Energy, in their efforts to restore production at previously shut-in wells, adjust water injection locations and volumes and execute on other targeted maintenance projects. Additionally, in the quarter, we and Merit began upgrading facilities to proactively reduce emissions throughout the field. Second quarter net production at Delhi Field was approximately 1,131 BOE per day. Denbury, the operator at Delhi, took steps to minimize the severe weather impacts, which resulted in only minor downtime during the second quarter despite the storms. They are continuing to perform conformance workovers and upgrades to the facilities. With that, I'll now turn the call over to Ryan to discuss our financial highlights.

Thanks, Kelly. As mentioned earlier, please refer to our press release from yesterday afternoon for additional information concerning our second quarter fiscal 2023 results. My comments today will primarily focus on financial highlights and comparative results between the second and first quarter of fiscal 2023. A key highlight of the second quarter was our continued solid generation of cash flow, including adjusted EBITDA of $16.4 million. This was $24.66 on a per BOE basis, which was an increase from the first quarter. We have now generated $33.5 million in adjusted EBITDA for the first two quarters of fiscal 2023. As Kelly discussed, during the second quarter, we continued to fund our operations, development capital expenditures, and dividends out of operating cash flow while also repaying all of our remaining debt. Supported by our continued strong operational and cash flow outlook, we paid a dividend of $0.12 per share in the second quarter and declared a dividend of $0.12 per share for the third quarter of fiscal 2023, payable on March 31 to shareholders of record as of March 15. Our cash dividend program has and will continue to be a top priority as we clearly recognize the strategic importance of returning value to our shareholders. During the second quarter, we enhanced our already strong balance sheet delivering on our commitment to paying off our debt in the second quarter. We eliminated our remaining debt position of $12.3 million. Our borrowing base remained at $50 million, and we had cash and cash equivalents of $3.7 million and working capital of $2.9 million as of December 31, 2022. The result was growth in our liquidity to $53.7 million, a 45% increase from only 6 months ago. This is a direct result of our targeted and immediately accretive acquisitions over the past couple of years as well as our continued focus on cost control. We are ideally positioned for the continued execution of targeted future growth opportunities that meet our strategic vision. As a result of eliminating our outstanding debt position, we are not currently required to maintain any hedges on our production, and our existing hedge positions are set to expire next month. Looking at the second quarter financials in more detail, our total revenue of $33.7 million was 15% lower than the first quarter due to a combination of factors, including lower oil revenue associated with 1% lower sales volumes and a 13% decrease in realized pricing. Lower natural gas revenue due to a 5% decrease in sales volumes and 8% lower realized pricing despite declines of almost 30% in Henry Hub pricing. Decreased NGL revenue due to 8% lower sales volumes and a 27% decrease in realized pricing. The result was an average realized price per BOE decrease of 11% to $50.49. Lease operating expenses decreased 21% quarter-over-quarter to $15 million in the second quarter. On a per BOE basis, lease operating expenses were $22.55 for the second quarter compared to $27.35 in the first quarter. Primarily contributing to the decrease in LOE were changes in estimates from prior periods and reduced ad valorem and production taxes due to lower revenues in the current period. Also contributing to the decrease was lower work-over expense in the Williston Basin and reduced CO2 costs at Delhi Field associated with the decrease in crude oil prices from the prior quarter. As a reminder, our CO2 costs at Delhi Field are directly impacted by the price of oil. Therefore, lower oil prices result in lower CO2 costs. General and administrative expenses were $2.6 million for the second quarter versus $2.5 million for the first quarter. The slight sequential increase was primarily due to higher noncash stock-based compensation in the second quarter that was partially offset by lower professional services fees compared to the first quarter. The end result is that on a cash basis, second quarter G&A was essentially flat with the first quarter. Net income for the second quarter was $10.4 million or $0.31 per diluted share versus $10.7 million or $0.32 per diluted share in the first quarter. Adjusted net income for the second quarter was $9.6 million or $0.28 per diluted share versus $10 million or $0.30 per diluted share in the first quarter. During the second quarter, we invested $1.1 million in development and maintenance capital expenditures. For fiscal 2023, we continue to expect total development capital expenditures of $6.5 million to $9.5 million. This estimate includes upgrades to the Delhi Field central facility, workovers at Hamilton Dome field, the Barnett Shale, and the Jonah Field and sidetrack drilling opportunities and low-risk development projects in the Williston Basin, excluding the development of Pronghorn and Three Forks locations. We expect capital spending on our existing properties will continue to be met from cash flows from operations and current working capital. Of course, our spending outlook may change depending on conversations with our operating partners, commodity pricing, and other considerations. After repaying our outstanding debt and upon emerging from blackout, we entered into a Rule 10b5-1 share repurchase plan in December that authorized up to $5 million in buybacks, subject to limitations on trading volume and stock price. The plan is effective through June 30 and can be extended or renewed by the Board. The plan also had a 30-day cooling off period, so there were no repurchases made until January. We plan to provide an update on our buyback activity in our third quarter 10-Q to be filed in May. I will now turn the call back over to Kelly for his closing remarks.

Thanks, Ryan. We continue to benefit from the targeted acquisitions that we have completed over the past few years, including two in just the last 12 months. As a result, we enjoy a larger and more geographically diverse asset base and commodity mix. This provides us with a solid platform for significant cash flow generation that we will continue to use to support and enhance our well-established shareholder capital return program. Our shareholders expect a consistent and meaningful cash return on their investment, and we remain committed to maintaining and, as appropriate, increasing our dividend payout over time. Another component of our capital return strategy is the share repurchase program that we put in place and began making purchases through after having fully repaid our revolving credit facility at the end of the second quarter. This provides the optionality to opportunistically repurchase our shares from time to time through open market transactions, privately negotiated transactions or by other means in accordance with federal securities laws. As in the past, we will maintain a conservative balance sheet and remain disciplined in our management of capital as we fully recognize the cyclicality of our business. Our ongoing commitment to remaining fiscally prudent was evidenced by our prompt pay down of our debt position following the closing of our most recent acquisitions. We are well positioned to execute on targeted high-rate of return and immediately accretive growth opportunities as appropriate. We will continue to execute our strategic plan, focused on maximizing total shareholder returns and optimizing every dollar that we invest. Our approach of building a targeted asset base of PDP reserves capable of supporting cash payments to shareholders has served us well over the past decade and will continue to benefit our shareholders for many years to come. As we've discussed in the past, we will closely evaluate and only execute on targeted acquisition opportunities that are immediately accretive, provide long-life established production, strategically expand our base of assets, and do not result in material dilution. Any transaction must also clearly support our long-standing thesis of providing a significant total shareholder return for our shareholders. With that, we are ready to take questions.

Our first question today comes from John White from Roth Capital.

Very nice results this quarter. Kelly, are you settling into your CEO Chair?

Yes, is the answer. Again, with the outstanding team we have here, it's made a good smooth transition. So I appreciate you asking me that.

On the CapEx issues, the press release and as Ryan just reiterated, provides a range of $6.5 million to $9.5 million. And then you explain what that capital spending is going to be directed to. And then there's a phrase in the remainder of that, where it says does not include any CapEx for the Pronghorn and Three Forks locations in the Williston. Could you give us a ballpark idea of the potential magnitude that some of those wells might add to the fiscal 2023 CapEx?

Sure. It all depends on the pricing in that area, and one of the reasons we've been considering this is that prices have risen significantly and are starting to ease a bit. So it's about a range per well, a fully completed well. I don't want to provide an exact figure, but to be cautious, I would say anywhere from $7.5 million to $10 million.

Yes, that's on an basis, right?

Right. Each of them are working in different locations, every location is different. So some of them may be around 50 percent, some of them may be more like around 30 percent, depending on the ultimate location.

So you're saying that would change the top end of the range from 9.5% to 10%.

I'm saying you would add another depending on the working interest, right, gross $7.5-ish to $10 million per well.

Yes. That would assume that we would drill and complete the well this fiscal year, John, right? So, I mean, that would obviously require a decision.

That's correct, but it's important to note that the situation varies by location due to different working interests. Prices for services are fluctuating significantly, and the timing of the permitting process introduces additional complexities. However, regarding the cost on a per well basis, we've provided a general range, but we're not prepared to be too specific at this moment.

No. That's perfectly acceptable and I understand. And what's the status of some of these locations? Have wells been proposed by the operator, and have they sent you an AFE?

We are closely collaborating with Pronghorn on the Three Forks wells, but they have not suggested any wells at this time. Instead, they have proposed AFEs for the recompletions in the Bakken, specifically focusing on vertical recompletions in some older Bakken wells, and we've recently initiated one of those. We have discussed various aspects before, and essentially, each option has its advantages, disadvantages, costs, expected outcomes, and risks. We are evaluating all these factors together to determine the best course of action at this moment. Currently, we are most excited about the recompletion of the up hole vertical well that was drilled deeper than the Bakken. This project has moved to the forefront of our priorities given all the variables we are considering. That is our main focus with the operator right now.

Yes. We can get some production growth from those sidetracks and the recompletion. Okay. Well, thanks for all that detail and putting some numbers around it. I really appreciate it. And I'll pass it on to the operator.

Okay. I appreciate your time and your interest, as always, John. Thanks.

And our next question comes from Donovan Schafer from Northland Capital.

Congratulations on the quarter. I want to start by discussing the average daily production decline of about 5% quarter-over-quarter and go through the causes of that. I know it was mentioned on the call, but here's my thinking on it. Oil production was down just 1%, while gas and NGLs declined more significantly at 5% and 8%, respectively. This aligns with my understanding that natural gas can be more affected by pressure changes, which can lead to liquids freezing out. This makes gas somewhat more vulnerable compared to oil. Additionally, there was the compressor issue in the Barnett. So my first question is whether I'm correct about the general effect of freezing weather on oil versus gas. I understand that operations are challenging regardless, especially when drilling a new well. But I'm seeking clarity on whether my assessment about oil being different from gas is accurate. For my follow-up, would production have increased quarter-over-quarter or remained flat without these disruptions, like the weather and compressor issues? Would you be able to quantify what your trajectory looked like, and should we anticipate an uptick in production next quarter?

So I'll talk a little bit about the first part of your question. In general, oil is liquids, right? And they have a tendency to be able to freeze. However, it depends on where you are, like our operator Foundation in the Williston, they're very used to and very good at handling and winterizing the wells. Now the biggest impact there on the oil side, honestly, was if you get 3 feet of snow, you can't drive down the road to get to the well, right? But as far as their equipment goes, they've done a great job of . So it wasn't affected too much. And in Delhi, there were some problems in Delhi, as we alluded to in the first quarter. So the fact that we're flat some of those recovering the issues in the first quarter, we did have to shut down because things were there a little bit in the Delhi side. So I would actually argue probably oil, which is liquids, is more impacted by the freezing storms. But everything you can freeze a valve. When you get storms that bad and everything goes up, it can impact anything you're doing.

Okay. That's helpful. Can you give me an estimate of whether we would have seen increases this quarter based on your current trajectory? If we hadn't experienced the weather issues or the compressor shutdown, do you anticipate a rebound next quarter with things returning to normal and the compressor back in operation? I'm trying to get a clearer idea of how to approach production moving forward.

Yes, I don't want to say too much about the future. Looking back, I can say the overall net impact was around 5%. Our corporate decline rate is lower than 5% each quarter. So you can understand the impact there. I prefer not to be too specific or provide guidance, but we performed below expectations due to these factors.

Yes, it's hard to say, Don, if the Barnett was, as you can probably see, the most impacted quarter-to-quarter or to say with any degree of complete certainty where we would have been if this hadn't occurred, right? We certainly would have been closer to last quarter than we are today, but it is on decline. And Diversified has done a great job reactivating wells. And at this point, they've reacted most of what they're probably going to. And so we're probably going to expect to see some decline going forward, but we would certainly hope that there would be some bump, to your point, next quarter from this quarter with some of these issues having been rectified. Assuming nothing else crops up, right, as you know, can happen in this field.

That's helpful. I want to explore the production costs further because I believe that was a major factor influencing the EBITDA. Can we discuss this in more detail and consider how to model it for the future? One key element appears to be the changes in estimates from previous periods. You mentioned that this is related to a lag in commodity price changes and their effect on lease operating expenses, particularly when gas is used on-site to power compressors. This means that the associated costs will closely follow commodity prices, and the billing cycle causes a delay. Is it a simple one-quarter lag? If I performed a correlation analysis using commodity prices with a one-quarter lag for forecasting, would that provide an accurate prediction, or might it lead me to incorrect conclusions?

There are a few important points to consider. We market our gas primarily through operators, selling most of it based on inside FERC pricing, which is typically set at the start of each month. However, this pricing information can be difficult to access unless you subscribe to a specific publication or have Bloomberg. A portion of our gas is sold daily, but the majority is sold based on the month's average. For example, if prices rise at the end of December, we would benefit from that increase in daily pricing for December, but the baseload volume we sold wouldn’t reflect the increase as much. However, in January, if prices continue to rise, we would see the advantages of those higher month prices.

Okay. Yes, that's interesting. And then the last is just I was feeling the need to kind of check in on the conventional assets, Delhi, Jonah, and Hamilton. When you're in a sort of sustained higher price environment, I know gas has come down a lot, but a lot of times, the operators will sort of circle back around and think or ask themselves, can we turn this up somehow to another level or another phase or anything like that. And so I know there's the heat exchange project at Delhi, but just have there been any sort of incremental conversations or incremental interest in doing other types of additional phases or investments or things in those fields, maybe not a decision yet, but just increased interest in like, hey, we might want to do that?

That's a great question. I had an answer in mind, but it's not really something we've done in the past. The pipeline coming online has been beneficial for our natural gas and NGL sales, and we're just starting to experience the advantages of that. It hasn't been fully operational since we acquired it, so it’s not classified as a capital expenditure; it was down but is now functioning. We expect to see some benefits from that. Regarding Hamilton Dome, Merit has excelled at managing their production and injection rates, maintaining a stable flow. It's not just one aspect; it's a continuous process of adjusting and monitoring. Overall, we've observed significant advantages from this. At Delhi, our primary focus is to get project 5 back on track. We believe this project has strong economic potential and should definitely be included in our plans, which would be a major positive impact.

And ladies and gentlemen, at this time, and showing no additional questions, I'd like to turn the conference call back over to Kelly Lloyd for any closing remarks.

Great. Thank you. Thanks again to everyone for taking the time to listen and participate in today's call. As always, please contact us if you have any additional questions. We appreciate your continued support and look forward to updating you on our ongoing efforts when we report our third-quarter results in May. Have a good day.

Ladies and gentlemen, that does conclude today's conference call. We do thank you for joining. You may now disconnect your lines.