Evolution Petroleum Corporation (AMEX:EPM) Q1 2024 Earnings Call Transcript

Evolution Petroleum Corporation (AMEX:EPM) Q1 2024 Earnings Call Transcript November 8, 2023

Operator: 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. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] 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.

Brandi Hudson: Thank you, and welcome to Evolution Petroleum’s fiscal first quarter 2024 earnings call. I’m joined by Kelly Loyd, 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 Investor Relations 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 statements. 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 closet comparable GAAP measures can be found in our earnings release. Ryan 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 Investor section of our website. With that, I will turn the call over to Ryan.

Ryan Stash: 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 Chaveroo oilfield in the Permian Basin and 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 develop 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 Chaveroo 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 and cased one well and spud another at our Chaveroo field in the Permian Basin. Our second fiscal quarter will benefit from a full quarter of production from the two new wells at Delhi, while the Chaveroo 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 maintain 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 fifth and sixth consecutive dividends at the current level. I’ll hand it over to Kelly now.

Kelly Loyd: Thanks, Ryan. At Evolution, we accomplished 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 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 Chaveroo 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 2024 first quarter and versus our fiscal year 2023 fourth quarter.

Since Mark Bunch, our COO, is traveling today, Ryan will cover the Jonah field, Williston Basin and Barnett Shale properties, and I’ll discuss our Hamilton Dome Field, Delhi Field and Chaveroo Field properties.

Ryan Stash: Thanks, Kelly. At our Jonah Field, production for this first quarter of fiscal year 2024 was slightly stronger than it was for the fourth quarter of fiscal year 2023 and in current operations as of today are continuing as expected. For our Williston Basin, as we previously disclosed, during our fiscal year 2023 fourth quarter production was subdued due to certain wells having production issues and needing workovers as well as downtime related to the compressor station at [indiscernible]. The workovers that were completed during the fourth quarter of fiscal year 2023 and continued into the first quarter of fiscal year 2024 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 NGL 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 EnLink’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, EnLink has finished their major overhaul at the Corvett 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. We believe the largest declines are substantially done and things should begin to normalize there. Now Kelly will discuss our Hamilton Dome field, Delhi Field and Chaveroo field properties.

Kelly Loyd : 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 Delhi, as stated previously, our fourth quarter fiscal year 2023 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 exchangers 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. Delhi 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 Delhi 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 [ph] and the Delhi 12323 [ph]. 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 Delhi, I’m sure many of you saw that the Exxon acquisition of Denbury was finalized. I was able to speak with some of the operators Delhi team, and they are very positive about the outlook for Delhi going forward. Their priorities seem to align with ours, and they are already working to get improved contracts for the area. Continuing Denbury’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 Chaveroo field. We finalized the participation agreement during the current quarter only about 1.5 months 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 the 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.

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Q&A Session

Operator: We will now begin the question-and-answer session. [Operator Instructions] At this time, we will pause momentarily to assemble the roster. And our first question will come from Jonathan Schaffer of Roth Capital. Please go ahead.

Donovan Schafer: Hi, guys. This is Donovan Schafer with Northland Capital Markets. Sorry, there’s — if I had a part in any confusion there 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? You know, it didn’t have a 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 of 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 like first day of the month pricing. So I’m just curious if Ryan or Kelly, if either 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 current quarter? Just how that’s looking?

Kelly Loyd: Yes, sure, I’ll take that. I appreciate it. Thanks for the question, Donovan. So as you mentioned, clearly, prices have been not quite as high yet as we saw last winter. But I would say — I was looking back last year to October really and in 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 pricing. But we have seen a little bit of early sort of winter, I would say, strength here. You saw — 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 probably close to $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 1.1 — 110% kind of the Henry Hub price you see. So we get that uplift too. So we’re a little encouraged what we’ve seen in this early winter. And I will say the differentials are still relatively strong. So December, I just looked at somewhere in January or so probably at $5 premium to Henry Hub at least in the futures market. So we’re hopeful that we’re going to see some strong pricing here again this one probably not what we saw last winter, but hopefully some stronger pricing.

Donovan Schafer: Okay. That’s very helpful. And then, Kelly, you made an interesting comment around the ExxonMobil acquisition of Denbury that the team you spoke with, they are already working to get improved contracts for the Delhi area. I guess I wanted to just be curious what are the — like for ExxonMobil, who are the service providers they are trying to contract with them at just sort of basic as electric utilities and maybe service rigs if they don’t have their own. How much can that move the needle? And is it — do you think there’s a meaningful chance that Exxon Mobil — I mean, Denbury was already a fairly large-sized player. But of course, ExxonMobil is — or is the biggest by certain measures. So, is there a potential for a real meaningful increase there if ExxonMobil can come in and have better sort of bargaining power with service providers? If you can just talk through or give us some more color there, that would be great.

Kelly Loyd: 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 received there. Denbury had a nice contract. It went off. And during the transition — during the time from which they signed the deal to close, they — like any normal deal, they weren’t going to enter into any new meaningful contracts. From speaking with them, I understand that, that is already underway, which I think could have a really a nice impact for us going forward. Additionally, like you said, with service equipment, frankly, with 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.

Donovan Schafer: Okay, that’s helpful. And then I kind of — I thought of this question ahead of time for Mark Bunch, but I heard that he is not on the call, but maybe Kelly, you may or Ryan, both of you may have some knowledge of this. You spudded the two wells in the Shaver Field. One of them has already been drilled in case. The other one is currently being drilled. I know — 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. Where you could see details like it’s the first drilled in case well if you pulled the wireline log on it, getting some data there if you’re getting live updates from mud logging or if you’re doing 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 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 into the formation. I think you were targeting kind of the top of the formation. So, any color or updates.

Kelly Loyd: So a couple of things. The second well, actually this morning, I think it was down to a 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 the — all the logging well drilling in geosteering. And the first well was 97% in the 20-foot window, and the rest of it was just a couple of feet outside, so all well within the 40-foot window. And the second well is looking very similar. The mud logs, you’re getting say a little bit of gas show up, a little bit oil show up. But it’s in the 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 will really be the completion activity where you get to see more results as opposed to hoping to 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.

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

Kelly Loyd: Just a quick clarification. I think you probably know some just misspoke, but it’s about 44 feet below the debt. Total laterals going to go up bottom out from there. So.

Donovan Schafer: My apologies. Okay. I’ll go ahead and I’ll take the rest of my questions offline.

Kelly Loyd: Great. Thanks again, Donovan.

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

David Locke: Hi, guys. How are you doing this morning?

Kelly Loyd: We’re doing all right. How about you?

David Locke: I am 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?

Kelly Loyd: So I could 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.

David Locke: 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?

Kelly Loyd: Well, some of it and some of it, I think, is more specific. EnLink 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. And 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 covered 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, I mean, the heat exchanger at Delhi 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. We get swap 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 you can have less gas used to call things, less electricity for heating and cooling and less chemicals, et cetera. 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 would 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 of benefits from that capital project that we’ve been working on the last couple of years yet to be seen. But anyway, it’s in place, and we’re hopeful for the effects there.

David Locke: 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?

Kelly Loyd: So we have a bit of that in our presentation. But I mean, the IPs that we’re using, we’re trying to be fairly conservative, but they want to grow about 300 barrels a day per well. And then it’s going to decline hyperbolically, until it becomes exponential. And until it becomes linear at the end of its life. So…

David Locke: And

Kelly Loyd: It should not being as steep of a decline as, say, like a Delaware well, right? It’s not — it’s a different rock formation. So we expect it to be a B factor of…

David Locke: And just so I sort of keep my math straight. When you say 300, that’s like gross to the wells, so not net to your interest

Kelly Loyd: That is correct.

David Locke: Okay.

Kelly Loyd: 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.

David Locke: Okay. And then lastly, on Delhi, you mentioned quickly in the prepared remarks about Exxon proceeding forward with that potentially being a carbon capture and sequestration sites. 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?

Ryan Stash: No. I mean I think based on our initial discussions with our tax folks, I mean, as long as they take industrial CO2 right, into the fuel, we should be able to get our proportionate share of the 45Q credit. So — and I think it would do two things for us, right? One is, it can 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, whatever they inject from industrial side, we can get a — we should be able to get a proportion of credit of that.

Kelly Loyd: And the other thing to consider there, I mean this — the line that goes to Delhi is connected to the line that goes to all of the other fields along the green line. So the expectation is it will be considered fungible and Delhi should get its proportion, and we should get our proportion of that, so.

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

Kelly Loyd: Well, that — look, 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 it will get certified, so.

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

Kelly Loyd: [indiscernible]

David Locke: Thanks.

Operator: The next question comes from John Bair of Ascend Wealth Advisors. Please go ahead.

John Bair: Good morning.

Kelly Loyd: Good morning to you, John.

John Bair: How are you? A couple of my questions have been answered — asked and answered. One I had was on Chaveroo wells. What’s the cost per well on those? What’s your AFE cost on that?

Kelly Loyd: AFE is $3 million.

John Bair: Okay. So half of that…

Kelly Loyd: Growth. Correct.

John Bair: Yes. Okay. And then you also mentioned, there were two down dip wells that you indicated we’re working favorably. What kind of rates are you — what kind of increase in production on that?

Kelly Loyd: Yes. So — like I said, it’s not going to be a huge number, right? We think the two combined will ultimately peak at around 250-ish barrels a day gross. So call it, quarter of that for us on and 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 we’re — 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 when we schedule them to be able to get into that, but we do hope it can lead to some more down-dip locations.

John Bair: So I know there’s an area, it’s been out there, I forget if it’s Section 5 or something

Kelly Loyd: Section 5.

John Bair: Yeah, that had some potential. And – so —

Kelly Loyd: This is not that, John, to be clear, this is elsewhere.

John Bair: Right. No, I understand, what I was getting at is that you’ve got some area on Deli that was prospective that has not been addressed, I guess, for various reasons with Denbury’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 spend capital?

Kelly Loyd: So 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 myopic sort of since. So I do think they will try and optimize each of the fields they have. So — with regards to Test Site 5, I can say this. When Denbury was the operator, they were resistant towards going there. They do 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. Do I 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 yes, I would just say, look, if it was super low percent chance before. It’s either the same or better now.

John Bair: Fair enough.

John Bair: Last quick question. Did you have any CapEx obligation for that core vet processing plant? Or is that all –?

Ryan Stash: No, that is not associated. We don’t — that’s all third parties

John Bair: Okay. That’s all.

Ryan Stash: 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.

John Bair: Very good. Thank you for taking my questions.

Kelly Loyd: Absolutely. Thank you.

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

Kelly Loyd: Thank you. Just want to tell everybody we really appreciate you joining us today, and we are available if you need us. Please give us a call. The numbers on the website. Thanks, again.

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