Evolution Petroleum Corporation, Inc.

Good morning and welcome to the Evolution Petroleum first quarter fiscal year 2024 earnings release conference call. All the participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. To withdraw your question, please press star then 2. Please note this event is being recorded. I would now like to turn the conference over to Brandi Hudson, Investor Relations Manager. Please go ahead.

Thank you, and welcome to Evolution Petroleum's Fiscal First Quarter 2024 Earnings Call. I'm joined by Kelly Lloyd, President and Chief Executive Officer, and Ryan Stash, Senior Vice President, Chief Financial Officer, and Treasurer. We released our Fiscal 2024 First Quarter financial results after the market closed yesterday. Please refer to our earnings press release for additional information concerning 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, November 8, 2023, 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. Brian will begin today's call with a brief review of our fiscal quarter highlights, and then we'll turn over the call to Kelly for an update on our properties and plans as they relate to our ongoing strategy of maximizing total shareholder returns. 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 Ryan.

Thanks, Brandi. As Brandi just mentioned, we released our earnings yesterday, which contains more information on our results. My comments will focus mainly on the highlights of the current quarter. In September, we entered into a participation agreement to horizontally develop a portion of the Chavarru oil field in the Permian Basin in New Mexico. This is exciting to us for a number of reasons. It provides evolution with over 80 gross and 40 net locations to horizontally developed an enormous proven oil field with an estimated 700 million barrels of original oil in place, with only 5% having been recovered to date. Of all of our development opportunities, we expect the Shavaroo field to provide the most economic and largest upside opportunity. Additionally, the deal was structured in a way where Evolution only pays upfront acreage costs for locations to be drilled within the upcoming development block, and the majority of the money we spend on this project goes where it will benefit shareholders the most, into the ground and towards producing oil. This quarter, we had total revenues of $20.6 million, net income of $1.5 million, and adjusted EBITDA of $6.7 million, all significantly higher than last quarter, primarily as a result of improved commodity prices and also due to improved operations at most of our properties. Negatively impacting this quarter was $500,000 in adjustments related to ownership updates received from the operator of our Barnett properties. These adjustments covered a 22-month period beginning in September 2021. These adjustments affected the top line and therefore reduced revenue, net income before taxes, and adjusted EBITDA, each by $500,000. For production, we were able to achieve a net 0% decline in production from the previous quarter to this quarter. We saw operational improvements in our Williston and Delhi assets from last quarter, offsetting declines in the Barnett Shale properties due to some continued operational challenges there. On the development side, we brought on two new producing wells at Delhi at the end of the current quarter, and subsequent to quarter end, drilled, encased one well, and spud another at our Chavarri field in the Permian Basin. Our second fiscal quarter will benefit from a full quarter production from the two new wells at Delhi, while the Chavarri wells are expected to begin impacting financial results by the end of the third fiscal quarter and be more fully reflected in the fourth fiscal quarter. After fully funding our operations, field development expenditures, and paying our dividends, we ended the quarter with increased working capital and maintained liquidity of approximately $60 million between cash on hand and $50 million in borrowing capacity. On the shareholder return front, we paid $0.12 dividend in September and declared another $0.12 dividend to be paid in December, which will mark our 40th and 41st consecutive quarterly dividends and 5th and 6th consecutive dividends at the current level. I'll hand it over to Kelly now.

Thanks Ryan. At Evolution, we accomplish our strategy of maximizing total shareholder returns by carefully weighing the use of every dollar we put to work for all of our stakeholders, always with an eye towards increasing or extending the runway of our dividend. In order to generate The return on capital we use to fund our dividend program while maintaining our asset base for years to come, we have assembled a group of producing assets that is diverse, both in terms of commodity mix and in terms of regionality. If oil is selling for a premium near the Gulf Coast, we have assets that will benefit from that. If natural gas is selling for a premium on the West Coast, we have assets that will benefit from that, and so on. We have always sought and will continue to seek acquisitions of accretive, strategic producing properties that meet our criteria to allow us to support our dividend for years to come. As announced earlier this quarter, through our participation agreement in the Permian Basin to horizontally develop the Chevroo field, we now have an additional strategic property that we expect will bring organic growth to the company, further diversify our asset base, and be very supportive of our dividend for many years. Now we will give you a bit of the State of the Union on our various properties. We'll discuss the state of our properties as we stand today, where appropriate, versus during our fiscal year 24 first quarter and versus our fiscal year 23 fourth quarter. Since Mark Bunch, our CEO, is traveling today, Ryan will cover the Jonah Field, Williston Basin, and Barnett Shale properties, and I'll discuss our Hamilton Dome Field, Del High Field, and Shavaroo Field properties.

Thanks, Kelly. At our Jonah field, production for this first quarter of fiscal year 24 was slightly stronger than it was for the fourth quarter of fiscal year 23, and current operations as of today are continuing as expected. For our Williston Basin, as we previously disclosed, during our fiscal year 23 fourth quarter, our production was subdued due to certain wells having production issues and needing workovers as well as downtime related to the compressor station at Roughrider. The workovers that were completed during the fourth quarter of fiscal year 23 and continued into the first quarter of fiscal year 24 led to increased oil production during the current quarter versus last quarter. The compressor station issues that began last quarter continued during this quarter, affecting our natural gas and NGO production. As we stand today, these issues are largely resolved. At our Barnett shale properties, beginning in April 2023 and continuing to varying degrees through October of 2023, our production suffered from the ill effects of compressor-related issues due to the extreme heat experienced this summer. excessive downtime within Inlink's gathering and processing system, pipeline rerouting and optimization, and our operator's decision to temporarily shut in low margin wells that were largely brought on to take advantage of the high natural gas prices realized during the second half of 2022. These effects were felt during the last and current quarters and led to an overall production decline that was well above the natural production decline. As of today, NLINK has finished their major overhaul at the Corvette processing plant. The summer heat has abated and the pipeline optimization project has been completed. We were glad to see production remain relatively flat from last quarter to this quarter, and we will continue to closely monitor this, but we believe the large declines are substantially done and things should begin to normalize there. Now, Kelly will discuss our Hamilton Dome field, Delhi field, and Shavaroo field properties.

Thanks, Ryan. At Hamilton Dome Field, our current quarter production remained very flat relative to last quarter, and we're continuing to see strong performance from this field. At Del High, as stated previously, our fourth quarter fiscal year 23 production was impacted by downtime associated with the installation of the heat exchanger project, a full field shutdown for maintenance, heat-related compression issues, and downtime at the NGL plant due to turbine issues. During our first fiscal quarter, we began to see benefits from our heat exchanger project and didn't experience a full field shutdown for maintenance. Oil production was impacted by the extreme summer temperatures, somewhat limiting the heat exchanger's ability to cool the CO2. We believe that the heat exchanger was still key to preventing a larger impact on the field as seen in previous summers. Del High NGLs were up 40% from the previous quarter. However, we did continue to be affected by turbine issues at the NGL plant, which led to downtime and a lessened ability to optimize it. Overall, we saw a sequential production increase of roughly 6% at Del High, and as we stand today, the NGL plant is fully operational and being optimized to achieve higher rates as a result of the heat exchanger and increased run time. As Ryan mentioned in the highlights, at the end of Q1, we were able to bring on two newly drilled wells, the Delhi 11910 and the Delhi 12323. While these did not have much of an impact on Q1, given the short amount of time that they were on during the quarter, the early results of these wells are positive and we are encouraged with them going forward. Regarding the future of Del High, I'm sure many of you saw that the Exxon acquisition of Denbury was finalized. I was able to speak with some of the operator's Del High team and they are very positive about the outlook for Del High going forward. Their priorities seem to align with ours and they are already working to get improved contracts for the area. Continuing Denberry's previous efforts, Exxon is moving fully forward through the process of getting Delhi certified as a carbon capture utilization and storage site and have every reason to believe that they will be successful. We will report more on this as developments occur. Lastly, our newest venture, the Chevroo field. We finalized the participation agreement during the current quarter only about a month and a half ago, and we are pleased to report that we have already drilled and cased the first partnership well and are well underway drilling the second well of a three-well pad with a third well to follow. Completion work on the three wells is expected to commence at the end of this calendar year with first production expected in early 2024. For now, we can say that we are very pleased with the progress we've made with our partner, Pedevco, and look forward to sharing our results with you at the appropriate time. With that, I'll hand it over to the moderator to begin the Q&A session. Thank you very much.

We will now begin the question and answer session. To ask a question, you may press star, then 1 on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble the roster. And our first question will come from Jonathan Schaffer of Ross Capital. Please go ahead.

Hi, guys. This is Donovan Schaffer with Northland Capital Markets. sorry if I had a part in any confusion there in name and company. I want to first ask about, just because it's been an important part of things in the recent past, I want to ask about West Coast natural gas prices for the Jonah field didn't have major upside. And that's not what we should expect per se going forward. In general, like the 20 plus per MCF prices we had a couple quarters ago. But it does seem like there's still maybe a $2 premium or something the last time I checked versus East Coast prices. But again, I know you've got first day of the month pricing. So I'm just curious if Ryan or Kelly, if either of you guys can kind of talk about how the influence of West Coast natural gas pricing with you guys and the way that all gets contracted maybe for the, you know, the current quarter, just how that's looking.

Yeah, sure. I'll take that. I appreciate it. Thanks for the question, Donovan. So, you know, as you mentioned, clearly prices have been not quite as high yet as we saw in last winter, but I would say, you know, I was looking back last year, too. October, really, and then going to November was a little soft, too. I mean, we're still just getting into winter, so we haven't really seen, I don't think, a lot of hopefully what we're going to see in pricing. But we have seen a little bit of early sort of winter, I would say, strength here. We saw a little bit of a spike at the end of October into November, which should help our November price out there, where it was trading you know, probably close to, you know, $5 in MMCF. So, and if you remember, too, we also get an uplift in Jonah because we're selling a little bit richer gas. So, it's about, you know, 1.1, you know, 110% kind of of the Henry Hub price you see. So, we get that uplift, too. So, you know, we're a little encouraged what we've seen this early winter, and I will say the differentials are still know still relatively strong so december i just looked december and january are still probably at five dollar premiums to henry hub at least in the futures market um so we're hopeful that we're going to see some strong pricing here again this winter probably not what we saw last winter but hopefully some strong pricing okay that's very helpful and then uh kelly you made an interesting comment around the exxon mobil acquisition of denberry that

the team you spoke with, they're already working to get improved contracts for the Delhi area. I guess one, I'd just be curious, you know, what are the, like, for ExxonMobil, you know, who are the service providers they're trying to contract with? I mean, is it as just sort of basic as electric utilities and maybe service rigs if they don't have their own? Yeah, how much can that move the needle and is it, do you think there's a meaningful chance that ExxonMobil, I mean, Denberry was already, you know, fairly large size player, but of course ExxonMobil is the biggest by certain measures. So is there a potential for a real meaningful increase there if ExxonMobil can come in and, you know, have better sort of bargaining power with service providers? If you can just talk through or give us some more color, that would be great. Sure.

And thanks, Donovan. You will see there's always activity going on at Delhi, right? So there are plenty of service providers on a continual basis from a contract basis. Electricity is a big thing. Additionally, for the NGL pricing we receive there, Denbury had a nice contract. It went off, and during the transition, during the time from which they signed the deal to close, like any normal deal, they weren't gonna enter into any new meaningful contracts. From speaking with them, I understand that that is already underway, which I think could have a really nice impact for us going forward. Additionally, like you said, with service equipment, frankly, the rental turbines in particular. I know it was mentioned to me that Exxon actually has a whole team dedicated to contracts with GE. So I certainly think we have a real good chance of getting a better deal on the turbine from there. So just across the board, bigger company, bigger leverage, better contracts.

Okay, that's helpful. And then Uh, I, I kinda, I thought of this question ahead of time for Mark Bunch, but I, I, you know, heard that he is not on the call, but maybe, uh, Kelly, you may, uh, or Ryan, uh, both of you may have some knowledge of this. Uh, you know, you, you sputted the two wells, uh, in the Shavaro field. One of them's already been drilled and cased. The other one is currently being drilled. You know, I know, uh, I know the way guys like Mark are, and he's probably getting a daily update. You guys might be getting a daily update as well. Um, you know, where you could see details like, uh, you know, it's the first drilled in case. Well, if you pulled a wireline log on it, getting some data there, if you're getting live updates from, from mud logging, or if you're doing, you know, measurement while drilling. Is there anything that you guys are seeing that is either incrementally positive that you're excited about or the opposite? And if there is kind of measurement while drilling, are you able to have a good sense of where you've landed the laterals? And are you kind of happy with where those laterals are coming in to the formation? I think you were targeting kind of the top of the formation. So any color updates?

So a couple of things. The second well, actually this morning, I think it was down to measured depth of over 8,400 feet. So it's coming along nicely. And I can tell you that on both wells, the target zone that we're going for is about 40 feet thick. And there is a particular sort of window in there of about 20 foot thickness, which We do all the logging while drilling and geo-steering. The first well was 97% in the 20-foot window, and the rest of it was just a couple feet outside, so all well within the 40-foot window. The second well is looking very similar. The mud logs, you're getting a little bit of gas show up, a little bit of oil show up, but in this sort of dolomite here, it's not going to be hugely telling it's a known field we know the lithology we know there's oil there so it'll really be the completion activity where you get to see more results as opposed to hoping you get some huge kick on a mud log but it's anyway like I said in the note we're very pleased 97% within a 20 foot window in the first one and it's looking similar if not better in the second one so far so happy with that for sure

Yeah, that is – I mean, if anything highlights, you know, the technology improvements and being able to go into an old field like this with horizontal drilling within that accuracy of a 20-foot window, you know, 8,000 feet below the ground is pretty incredible. And it makes – it helps kind of see the – it makes it compelling that you could really get some – have a meaningful extra extraction from that kind of improvement. So that sounds great.

Just quick clarification. I think you probably noticed and just misspoke, but it's about 44 feet below the desert.

Oh, sorry.

Total length of laterals, you know, going to go out about a mile from there.

Right, right. My apologies. Okay. I'll go ahead and I'll take the rest of my questions offline.

Perfect. Thanks again, Donovan.

The next question comes from David Locke of Old Mammoth Investments. Please go ahead.

Hey, guys. How you doing this morning? We're doing all right. How about you? I'm doing all right. Can't complain. So just quickly on sort of like production levels, would it be fair to say, given new wells drilled and resolution of problems, that your exit rate was a little bit higher in the September quarter than the average for the 90 days?

So I can say things that you can draw your own conclusion. There were issues that affected us throughout the quarter that exiting the quarter had less of an effect on us. How about that? Okay.

And what the heck is going on with all your compression stations? I mean, not yours necessarily, but is this an industry-wide problem at this point?

Well, some of it and some of it I think is more specific. InLink took over in Barnett, I don't know, about a year ago. So one of the things they did is they evaluated all their lines and all their plants and processors and they did some overhauls and they tried to optimize and brought things down and move things around. You combine that with trying to do new projects in addition to what you would normally do to optimize to help with some of the compression. I just think it's been a challenge for them. We do expect that will get better as they go forward. And I think on that front, that pretty much covers it. Like I said, there were several projects that they had and they should be finished with most of those so they can focus more on day-to-day operations and getting back to where they're more efficient going along those lines. In Delhi, I mean, you've seen in the past, right, in the extreme heat and the extreme cold, It's affected the density of the CO2, which gets injected, which has ramifications. This summer in particular was, I would say, a standard deviation higher than normal on the heat front, which is one of the main reasons we wanted to put in the heat exchanger. We do think it has had a nice effect already. We think in the winter you'll be able to see some real benefits there. And just quickly, the heat exchanger at Doha is meant to accomplish four primary functions. First, to reduce LOE by removing a lot of the prior equipment they needed for cooling that was a lot less efficient. You get swamp coolers and literally plugging in fans and running cold water over things. The heat exchanger will help with that and really should improve LOE. You can use more gas and electricity. You can have... less gas used to cool things, less electricity for heating and cooling, and less chemicals, etc. Second, really cooling the CO2 during the summer heat to allow for better injectability. We saw some of this effect. It's hard to know how much different it really would have been, but we do feel there was definitely an effect. And then the third, when you look at the heat, you need to heat up the inlet stream in the winter. This prevents hydrates from forming and freezing issues. And lastly, The fourth one, really, it allows for us to optimize the NGL production. More of it can go to the plant versus being used to warm the inlet stream. So there's a couple benefits from that capital project that we've been working on the last couple years yet to be seen. But anyway, it's in place, and we're hopeful for the effects there.

Excellent. Sort of switching gears a little bit, the Pedevco wells, What sort of initial rates are you guys expecting those to come in on, and what does the decline curve look like on those?

We have a bit of that in our presentation, but the IPs that we're using, we're trying to be fairly conservative, but they want to gross about 300 barrels a day per well, and then it's going to decline hyperbolically until it becomes exponential and then until it becomes linear at the end of its life.

Right.

And just so I get my... It should not be as steep of a decline as, say, like a Delaware well, right? It's a different rock formation, so we expect it to be a B factor of one or so.

And just And just so I sort of keep my math straight, when you say 300, that's like gross to the well, so not net to your interest.

That is correct.

Okay.

And this first batch of wells is about an 83% NRI, so pretty good on the royalty front, and we're obviously half of that.

Okay. And then lastly on Delhi, you mentioned growth. um quickly in the prepared remarks about exxon proceeding forward with that potentially being a carbon capture and sequestration site to what extent if any does that accrue to you guys as an interest owner or is that all just exxon's money and project no i mean i think you know

Based on our initial discussions with our tax folks, I mean, as long as they take industrial CO2, right, into the field, we should be able to get our proportionate share of the 45Q credit. So, I mean, I think it would do two things for us, right? One is it could potentially reduce our LOE, right, if they're not going to take CO2 from Jackson Dome, which is our biggest expense there. And then two, you know, whatever they inject, you know, from industrial side, you know, we should be able to get a proportionate credit of that.

The other thing to consider there, the line that goes to Delhi is connected to the line that goes to all of the other fields along the green line. The expectation is it will be considered fungible and Delhi should get its proportion and we should get our proportion of that.

That was going to be my next question, which is how do you apportion what comes from Jackson Dome and what comes from industrial sources? Or is that, again, sort of like an Exxon accounting thing and they'll figure out a way to allocate stuff to take the most money themselves?

Well, let's be honest. It remains to be seen. But again, when I spoke to the folks over there, they were, again, had every expectation that that it will get certified.

And any sort of like round expectations on when that might happen?

The latest I heard was by the end of the calendar year. Now, whether this finalizing of the merger affects that at all one way or the other, I'm not sure, but I don't have any reason to change that expectation as of now.

Okay. Perfect. Thanks a lot, gentlemen. Thank you.

The next question comes from John Baer of Ascend Wealth Advisors. Please go ahead.

Good morning.

Good morning to you, John.

How are you all doing? A couple of my questions have been answered, asked and answered. One I had was on Chavarru Wells. What's the cost per well on those? What's your AFE cost on that?

AFE is $3 million.

Okay, so half of that to you.

Gross, correct.

Yep, okay. And then you also mentioned there were two down-dip Bedeli wells that you indicated were working favorably. What kind of rates are you – what kind of increase in production on that?

Yeah, so – Like I said, it's not going to be a huge number. We think the two combined will ultimately peak at around 250-ish barrels a day gross, so call it a quarter of that for us. Again, the economics on it, though, for what they cost and the return, we think these are very nice return projects, but more importantly, One of them was more of an infill well, sort of within a pattern, trying to see if you could get a little bit of additional unswept area. And the other one was more down dip, which goes along with some of our belief that the CO2 injection over the years may have pushed some oil down dip. And like I said, it's early days, but we're pretty happy with the results, and I know that the team over there is as well. So this could certainly lead to more locations. We don't have any on the books. We don't have any scheduled. I'm not going to be able to get into that, but we do hope it can lead to some more down-depth locations.

Well, I know there's an area that's been out there, I forget if it's Section 5 or something like that, that had some potential, and So – This is not that, John.

To be clear, this is elsewhere. Right, right. No, I understand.

What I was getting at is that you've got some area on Delhi that was perspective that has not been addressed, I guess, for various reasons with Denberry's issue and so forth. Do you sense that Exxon will continue to work – Maybe to do those kind of infills, or is that too small for them to really expend capital?

First of all, I think what Exxon is going to do is what makes the most sense, and I think they have to look at fields in a myopic sort of sense. I do think they will try and optimize each of the fields they have. With regards to Test Site 5, I can say this. When Denbury was the operator, they were resistant towards going there. We've all done the work, and we all think it's a very economic project, but for reasons related to past issues, Denbury was reluctant to go there. All I know is there's a... It could be exactly the same chance or a better chance with Exxon going there. And we have not yet had the chance to sit down with them in a formal capacity and go through plans regarding Test Site 5. Obviously, that is in the works, and we're going to try and do that as soon as we can. But, yeah, I would just say, look, if it was a super low percent chance before, it's either the same or better now.

Okay. Fair enough. Last quick question. Did you have any CapEx obligation for that Corvette processing plan, or is that all?

No, that is not associated. That's all third parties, not us.

That's all in. That's what I thought. And the same thing, yeah, with the other compressor station in the Wilson. That's actually one of the stations in the Wilson that has had issues in the past. Right. Okay.

Very good. Thank you for taking my questions.

Absolutely.

Thank you.

Once again, if you would like to ask a question, please press star, then one. This concludes our question and answer session. I would like to turn the conference back over to Kelly Lloyd for any closing remarks.

Thank you. I want to tell everybody we really appreciate you joining us today and we are available if you need us. Please give us a call. Our number is on the website. Thanks again.

The conference is now concluded. Thank you for attending today's presentation and you may now disconnect.