Evolution Petroleum Corporation (AMEX:EPM) Q2 2024 Earnings Call Transcript

Evolution Petroleum Corporation (AMEX:EPM) Q2 2024 Earnings Call Transcript February 7, 2024

Evolution Petroleum Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning and welcome to the Evolution Petroleum Second Quarter Fiscal Year 2024 Earnings Release Conference Call. All 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. Welcome to Evolution Petroleum’s fiscal Q2, 2024 earnings call. I’m joined by Kelly Lloyd, 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 2024 second 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, February 7, 2024, 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 some opening comments. Mark will provide an update on our properties and plans as they relate to our ongoing strategy of maximizing shareholder returns, and Ryan will provide a brief review of our fiscal quarter 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 Investor section of our website. With that, I will turn the call over to Kelly.

Kelly Loyd: Thanks, Brandi. Over the past few years, our industry has evolved, and fittingly, so has Evolution. The need for increased scale and economic efficiency has become more and more obvious. With the breakdown of the price correlation among commodities and the outsized effect of regionalized pricing, having exposure to multiple commodities in multiple markets has proven superior, to the pure play, single-basin, single-commodity strategy of the past. Similarly, the shortening and the heightening of the commodity price cycle has increased the urgency of adding investment flexibility to portfolios. Being able to nimbly make accretive acquisitions and having an organic growth component to protect and enhance our dividend and share valuation, while commodity price volatility remains elevated, has become crucial.

From October of 2019, through February of 2024, with the expected close of our latest three acquisitions, collectively we call this the SCOOP/STACK. Evolution will have participated in six major transactions, putting over $119 million to work for our shareholders. During that time, we’ve paid down over $41 million of borrowings, while our share count has remained virtually unchanged. Since we began paying dividends 10 years ago, we have returned over $3.33 per share, to shareholders in cash and another $0.24 per share in share repurchases. These six major transactions have added oil, natural gas and NGLs, all of which gain us exposure into different, largely uncorrelated markets, both by product and locations, many of which recently have experienced outsized favorable pricing versus other sales points.

These six major transactions also provide Evolution with hundreds of undrilled upside locations. We can either choose to participate in, or sell many of these undeveloped locations, depending on which will bring the most value to our shareholders at the time. As an example, we have already drilled three producing wells in the Chaveroo field and two in our Delhi field. So, while our methods to execute our strategy have evolved and will continue to be enhanced, our goal remains the same as it has been since 2013, the year we paid our first of 41 and counting consecutive dividends. That goal is to maximize total shareholder returns by carefully evaluating every dollar we use to drive dividend payments, share repurchases, and replenishing and/or growing our cash flow producing asset base, all while avoiding significant deletion, or over leveraging our balance sheet.

I’ll hand it over to Mark now, who will give you an update from an operational standpoint on some of our recent actions supporting our strategy.

Mark Bunch: Thanks Kelly. I won’t bother to repeat what you read in the press release and we’ll just focus on notable items. For our Williston Basin assets, production was impacted by reduced gas sales due to the ONEOK Grassland System being shut down for almost three weeks and down time of a few wells in November. Currently, the wells and the Grassland System are back online, resulting in average rate for December of more than 500 BOE per day. At our Barnett asset, although inlet continued to experience issues with some of the gathering facilities, production was not significantly impacted and production for the Barnett has flattened back, to its normal historical decline rate. At the Hamilton Dome field, our current quarter production was affected somewhat by well work, but we expected all these wells to be back online during our fiscal third quarter.

Overall, we can see strong performance from this field. At Delhi, the ongoing transition from Denbury to Exxon as field operator, has felt largely seamless to us. We continue to believe Exxon’s priorities align with ours and that Delhi will be a certified carbon capture utilization storage site, designated for enhanced oil recovery, with this process expected to become official, coinciding with the end of our fiscal year. We will provide updates on this when appropriate. Delhi production increased, despite more downtime than expected at the NGL plant. The heat exchanger installed last year performed very well, during the recent pull of war-tank that hit Northern Louisiana, and we did not experience any cold weather interruptions at the plant.

As mentioned on the last earnings call, we brought on two new infill wells at Delhi and are very pleased with the results, and hope to see more future proposed locations. In the Chaveroo field, we were pleased to announce we drilled, fracked and modified existing facilities for our first three wells, before the end of the second quarter. In February, we finished drilling out the plugs and installing artificial lift on all three wells. The 504H was brought online first and is currently in the process of cleaning up. Even though it is early in the cleanup process, we are encouraged by its performance. After some additional minor facility modifications, we expect to begin producing the 502H and the 503H very soon. We will provide information on this important project as it becomes available.

Finally, on January 5, we announced the acquisition of non-operating working interest in the SCOOP/STACK in Central Oklahoma with a November 1 effective date. As of the effective date, the assets consist of 231 producing wells with an average 3% working interest producing roughly 1,550 BOE per day. 21 ducts to be paid for by their seller, and up to 300 gross drilling locations. Currently, 18 ducts have been converted to approved, developed producing and two are in process. In addition, 12 puds that the EPM will pay the CapEx on have been sputted. We have also begun reviewing other drilling proposals so we do shortly after closing. This asset is a perfect fit for our evolving strategy of both adding on long life production based on current commodity pricing during the downswings and adding undeveloped locations by making acquisitions through the drill business.

We view this as crucial to enhancing our ability to credibly maintain or increase production, at an attractive rate of return, for years to come. I’ll turn it over to Ryan to discuss the highlights of the quarter.

Ryan Stash: Thanks Mark. As Brandi mentioned earlier, we released our earnings yesterday, which contains more information on our results. My comments will focus mainly on the highlights of the current quarter. This quarter, we had total revenues of $21 million, net income of $1 million and adjusted EBITDA of $6.8 million. Negatively impacting this quarter, were approximately $500,000 adjustments related to ownership updates, received from the operator over Barnett properties covering 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 approximately $500,000. Earnings per share was also negatively impacted by $0.01.

We don’t expect to see further impacts from these non-recurring ownership adjustments. On the development side, we spent $3.9 million in CapEx, primarily related to the drilling and completion of the three wells at Chaveroo. We ended the quarter with liquidity of $58.5 million, between cash on hand and an undrawn $50 million credit facility. Going forward, we expect to use borrowings under our credit facility, to close on our SCOOP/STACK acquisitions and for working capital needs related to the acquisition and timing of capital expenditures in our Chaveroo asset and SCOOP/STACK acquisition. We plan to remain below our leverage target of one times pro forma EBITDA. We entered into oil hedges at the end of January during a brief uptick in prices and plan to enter into additional hedges to fully comply with the terms of our credit facility.

We expect to be required to hedge 25% of our oil and gas production on a rolling 12-month basis once we complete the SCOOP/STACK acquisitions. However, depending on the hedging terms available, we may consider hedging beyond 12 months to capitalize on contango structures, such as is currently available in the natural gas market. Our goal for our hedging program will continue to be to reduce downside commodity price risks, while maintaining the maximum amount of upside available. On the shareholder return front, we paid a $0.12 dividend in December and declared another $0.12 dividend to be paid in March, which will mark our 41st and 42nd consecutive quarterly dividends and 6th and 7th consecutive dividends at the current level. I’ll hand it over to Kelly now for closing comments.

Kelly Loyd: 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 for many years to come. We have a track record of paying dividends with stronger yields than the S&P 500 and our peers, returning cash to shareholders of over $3.33 per share over the last 10 years. We are building our company, into one which can cover our dividend, and our capital spending in a much lower commodity price environment, like we see today, while maintaining ample capacity to return cash to shareholders. We have built and continue to build a diverse, resilient set of assets strategically designed to facilitate and complement our consistent approach to returning cash to shareholders.

In building this base, our balance sheet has remained rock solid, and we’ve had no material dilution. With that, I’ll turn it over to the moderator to begin the Q&A session. Thank you very much.

Operator: [Operator Instructions] And our first question will come from Donovan Schafer of Northland Capital. Please go ahead.

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Q&A Session

Donovan Schafer: Hi guys. Thanks for taking the questions. So first, just in my own modeling, I made the mistake of giving you additional revenue in the second fiscal quarter, for November and December production from the SCOOP/STACK acquisition based on the November 1 effective date. That’s why I had you at $25 million in revenue versus the $21 million you reported. And when I go back and correct for that, it looks like your results are right in line. So, I just want to acknowledge my error there. But now that it’s clear that you’ll be accounting for this incremental production as a discount to the purchase price when you do close, do you have any rough, can you just give us any rough sense, for what that discount might be? And kind of related, could you share with us how much you expect you might need to draw on your revolver in order to close the transaction?

Kelly Loyd: So Donovan, yes, thanks for calling. And I appreciate you mentioning the modeling correction you made. So honestly, the way this works is, a lot of times what happens is, if the companies that you’re acquiring accrue, right, then you can do a preliminary settlement statement. And then later on, you sort of true it up with the finals. Not all of the three companies that we’re acquiring actually do accruals. So some of it, will sort of be real time coming in. So I mean, ultimately, we have a very solid estimate, for what the reduced purchase price will be. But when the timing of that comes in will be a little different amongst the entities. So the actual draw, it may go up and down a little bit between preliminary closing settlement statement and the actual final one, which would be, I mean, it takes 60 days for gas production. So, it’s how many days out there is it Ryan?

Ryan Stash: Yes, I mean, look, so Donovan, we’re reviewing the settlement statement now to be honest. So, as Kelly mentioned, we may not have an answer quite yet for you, unfortunately, but we are still set to close likely next week. And so, we’ll have a better answer then. And it’s just going to depend on what revenue they’ve received versus, the month. It’s generally going to be 60-day lag for all their operators. So, if you’re looking at sitting here in February, through the end of January, they probably would have only gotten through November production. So there may be a couple of months of production. They’re some orders. So you just may not be as big as the preliminary is on the final. Hopefully that’s not too confusing. But net-net when it washes out, I don’t think your number was way off. It could be a little bit either way, one way or the other.

Donovan Schafer: Okay. And then I want to talk about turning to third fiscal quarter. So in mid-January there was some fairly severe winter freeze weather conditions that hit North Dakota and also Texas and Louisiana. I don’t think they were as extreme as some maybe we’ve seen in the past, but there were, Reuters and some other, outlets talking about impacts. I think actually at the Bakken, kind of almost shockingly, but it was only, I think, for a couple of days, but like statewide Bakken production fell like 50% for a couple of days, because the freeze was so bad and effected the LNG processing, I think, or something. So I’m just curious if you can talk through what kind of impacts, those events may have, or what we kind of, how we should expect that to impact production for F Q3?

Mark Bunch: Hi, Donovan. Thanks for the question. This is Mark Bunch. An actually, this year the winter storm, like that you’re referring to it was – it didn’t affect us as much as the winter storms have in the past. Like at Delhi, because we had the new heat exchanger in, we didn’t have any issues with the plant at all. So that was great. At Williston, there was some shutdown, but it was only for about five days and everything came was brought back online very quickly. So, I’d say the reaction time of that was pretty good. And then in the Barnett, there was about the same amount of time, about four or five days, but everything came back online real quickly. In past years, one of the problems that has been in the Barnett is, they were unable to get production back on as fast, but this time they got everything back on really quickly. So, I’d say the effect is fairly minimal.

Donovan Schafer: Okay. And then I’ll just, if I can squeeze in one last question. You guys have relatively lower exposure to the Bakken. It doesn’t say some of your peers. I mean there are some pure play Bakken companies out there, another one said, you know. So it’s a smaller piece of the pie for you guys, all things considered, but it’s still relevant. So I want to talk about the trans-non-pipeline in Canada. In the past, I’ve asked some folks about, gee, when this new capacity comes online, could it actually improve Bakken pricing, by alleviating some congestion from the Alberta production in Canada? And the answer I usually got was like, no, we don’t really think that’s going to have any kind of impact or positive impact for us.

But now we’re seeing sort of just the opposite, where that capacity was expected to come online? So the producers in Alberta started ramping production, but then that pipeline capacity got delayed. And so, you got this like excess Canadian production that’s actually seems like it’s put some downward pressure on the regional pricing in North Dakota. So I’m just curious, can you talk about those impacts as you guys are seeing them and how you expect it to unfold going forward? Do you think this is a case, where things would just normalize back to whatever the historical, discount was for crude production in that region? Or do we actually get, at the end of the day, once the capacity comes online and that benefit the pricing in the area? Just any color there would be helpful.

And I’ll take that offline?

Kelly Loyd: Sure. So this is Kelly. Thanks, Donovan, for the question. In the Williston, I think you framed it correctly. I think, a lot of people thought that Trans Mountain was supposed to have been on in December. I mean, they talked about it for years. Then there was, I think, a mile and a half section, where I think they ran into some First Nations issue, which caused a delay. But obviously for some of these larger projects in Canada, it takes a while to ramp them up. So people had been ramping up production in expectation that the Trans Mountain would be on in December. So, you have seen increased flows going into that area with really nowhere to go. So yes, our Williston differential was affected this quarter a little bit versus past quarters.

I think it was a couple bucks a barrel. We do expect as Trans Mountain comes on, which I think will be June, that should alleviate that issue. And then the other effect that Trans Mountain should have for us would be on our Hamilton Dome property. Again, the oil from Canada was really not a whole lot of place to go. Hamilton Dome trades on WCS, Western Canadian Select. So with the Canadian market and Trans Mountain opening up and being able to move oil East and throughout the system versus having to go down towards our system. It should absolutely, we think it will have a positive effect on the differentials for Hamilton Dome. I read somewhere as much as some people thought $4 or $5 a barrel of incremental, better differential there. So anyway, we’re excited about that.

Donovan Schafer: Okay. Thanks, guys.

Operator: The next question comes from John White of ROTH Capital. Please go ahead.

John White: Good morning, everyone.

Kelly Loyd: Good morning, John.

Ryan Stash: Hi, John.

John White: Yes, so it’s good to see Chaveroo going well. Have you talked about the number of potential locations in connection with that prospect?

Kelly Loyd: Yes. Right now we have roughly about 80 total locations – including the three that we just drilled. They’re spread out over basically to averages, kind of close to eight wells – seven or eight wells per year. So it’s kind of a measured drilling program.

John White: That’s quite a bit of potential it sounds like?

Kelly Loyd: Yes. Yes, that’s actually the biggest reason why we were so interested in the project, because it gives us a lot of running room and the operator is like us, doesn’t want to like race out there and drill everything up in one year. They want to, they’d like to see it, brought on slowly and that kind of fits our capital program.

John White: Right. And on this carbon capture designation, is that going to have any positive income tax benefits?

Ryan Stash: So John, that’s something, it’s a sticky wicket as they say across the pond. We’re trying to figure it out and we have some time. We don’t expect this to happen until, the end of June is what they’re telling us. Either it will have a direct impact to us, or more likely what will happen is, it’ll affect the price of CO2 that we get there. So we, I don’t know, still to be researched. I can’t think of anything negative that would happen because of it. So, I think there’s only upside potential with that.