Epsilon Energy Ltd. (NASDAQ:EPSN) Q3 2025 Earnings Call Transcript

Epsilon Energy Ltd. (NASDAQ:EPSN) Q3 2025 Earnings Call Transcript November 6, 2025

Operator: Good day, and welcome to the Epsilon Energy Third Quarter 2025 Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to Andrew Williamson, Chief Financial Officer. Please go ahead.

J. Williamson: Thank you, operator. And on behalf of the management team, I would like to welcome all of you to today’s conference call to review Epsilon’s third quarter 2025 financial and operational results. Before we begin, I would like to remind you that our comments may include forward-looking statements. It should be noted that a variety of factors could cause Epsilon’s actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. Today’s call may also contain certain non-GAAP financial measures. Please refer to the earnings release that we issued yesterday for disclosures on forward-looking statements and reconciliations of non-GAAP measures. With that, I’d like to turn the call over to Jason Stabell, our Chief Executive Officer.

Jason Stabell: Thank you, Andrew. Good morning, and thank you for participating in our 2025 third quarter conference call. Joining me today are Andrew Williamson, our CFO; and Henry Clanton, our COO. We will be available to answer questions later in the call. This was a big quarter for the company. The announcement of the transactions in the Powder River Basin is a major strategic milestone that positions the company for success and outperformance over both the medium and long term. Before I discuss the deal, I’d like to offer some comments on the quarter results. In the Permian, we participated in the drilling and completion of the eighth well in our project. The well commenced production late in the quarter, and the asset continues to perform well.

Since inception a little over 2 years ago, we’ve invested approximately $42 million in our Texas asset, which has generated more than $18 million in operating cash flow through quarter end. Looking ahead, we expect Permian drilling activity to resume in the first quarter of next year. Turning to the Marcellus. Shoulder season inventory builds drove sub-$2 net gas pricing in the back half of the quarter, which resulted in some operator elected production curtailments during the quarter. However, a colder start to November has strengthened pricing and allowed for a staged return of these volumes. We are actively engaged with the operator regarding forward investment plans. At this time, we do not anticipate any material investments in the first half of 2026.

We’ll provide updates when second half 2026 plans firm up next year. On the transaction, to summarize what we announced in August, we executed definitive agreements to acquire the Peak companies with operated assets in the Powder River Basin. The transaction includes the issuance of up to 8.5 million Epsilon shares and is subject to shareholder approval at the meeting scheduled for November 12. Due diligence and integration planning have progressed as expected, and we anticipate closing shortly after the shareholder vote. Based on recent BLM approvals, we expect the 2.5 million share contingent consideration to be paid at or near closing. A really nice positive surprise that will allow us to begin planning on what we believe to be the best inventory in the combined company portfolio.

The acquisition adds an experienced operating team, oil-weighted production and a significant inventory of economic locations across multiple benches. Our initial focus will be on production optimization and the highly economic conventional Parkman inventory. The pro forma company sits well positioned to capitalize on an oil price recovery. In addition, we expect investment in our Marcellus position to increase meaningfully over the next several years as our operator shifts their focus towards the Auburn area, which we estimate still holds over 15 gross undrilled locations. It has taken us several years to reposition the company, and I am happy to report that post close, our diversified drilling inventory, coupled with our fee-based cash flows from the Auburn Midstream system, leave us in a position to opportunistically increase investment and cash flows while continuing our track record of shareholder returns.

In 2026, our focus will be on integration and execution, setting us up for truly transformational results in 2027 under the right market conditions. With that, I’ll now turn the call over to Andrew.

J. Williamson: Thanks, Jason. I’ll start with the updates we’ve made to the hedge book over the last few months. On a pro forma basis, with peak PDP oil volumes are 60% hedged in 2026. 3/4 of that coverage is swapped at strike prices above the forward strip with a weighted average WTI strike price of $63.30 per barrel. We like the protection that gives us next year with the recent weakness in oil prices. On gas, we’re approximately 50% hedged for 2026, with most of that coverage through costless collars with a weighted average NYMEX floor above $3.30 and a weighted average ceiling above $5, leaving us plenty of upside participation in gas prices next year. We will have protection on for 50% of PDP for WTI and NYMEX for the next 18 months to comply with the terms of our new credit facility.

Last month, we announced a new credit facility, bringing in a new lender alongside Frost and Texas Capital and adding term to Q4 2029. Most importantly, we now have the commitments in place to refinance the Peak term loan with our revolver on substantially better terms with excess liquidity on the revised borrowing base after adding the PRB assets at closing. I’ll reaffirm the point I made last quarter that the pro forma leverage is very manageable and allows us to execute on our capital investment and shareholder return plans over the next few years. On the results, I’ll highlight the year-to-date adjusted earnings of $0.45 per share. The adjustments included the Canadian impairment in the second quarter and transaction expenses in the third quarter related to the Peak transaction.

The intention is to highlight the normal course legacy business performance, which was strong over the 9 months. The driver was the new wells, 1.2 net in Pennsylvania that came on in the first half of this year. This is representative of the earnings power incremental Marcellus development can have to both the upstream and midstream sides of our business. One thing to mention on the acquisition, the stock price movement since we first negotiated the deal has worked in our favor from a valuation perspective on the acquired assets. The deal is for a set number of shares to be issued at closing plus the assumption of debt. Using, for example, $5 per share for Epsilon common, we are acquiring core undeveloped net acreage in the PRB at less than $900 per acre or thought of another way, paying less than $300,000 per priority location.

Both of those metrics, we believe to be discounts to market value. Now to Henry to provide more detail on the operating team and asset base we’re bringing on.

Henry Clanton: Thank you, Andrew, and good morning to everyone. I’d like to begin by highlighting again the attributes of the Powder River Basin assets we are planning to acquire. We are thrilled with the strength of the operating team we are bringing on. They have had significant continuity of personnel in their technical team, which is a testament to Peak’s founder, Jack Vaughn, whom we are pleased to be adding to our Board. This includes their field staff who continue to operate the wells in an efficient manner, coupled with an excellent track record of compliance with all federal and state regulations. The well site facilities have been outfitted with the appropriate technologies for us to continue to optimize production and reduce downtime going forward.

We’re very pleased with the excellent design and condition of the field assets. As mentioned last quarter, the PDP is solid with consistently performing producing interests across multiple horizons. The majority of these wells have been developed in the last 10 years, and the value diversity is spread quite nicely. Recently, we participated in a thorough well review for all operated wells and have identified candidates for lift optimization, which we expect will drive operating cost reductions and an uplift in production. The undeveloped inventory associated with this acquisition is substantial. For those who may not have reviewed the deck posted to our website, summarizing the acquisition, we encourage you to do so. With approximately 75% of the leasehold held by production, we have identified 111 net priority locations, priority meaning locations with laterals greater than 10,000-foot completable lateral length, having greater than 45% working interest that meet our return thresholds at a $65 WTI, $4 NYMEX pricing.

Planning around this inventory will be the main focus of the technical team post closing and offer the ability to drive production growth in the basin for years. Currently, there are 2 2-mile Niobrara DUCs scheduled for completion in 2026. In addition, as Jason mentioned, the initial focus will be on the Parkman inventory, Parkman, which is a conventional reservoir with lower development cost per foot than unconventional targets in the Niobrara and Mowry. With permits recently being issued by the BLM in Converse County, the team is planning some front-end facility work for a multi-well pad development corridor in the area to be able to efficiently execute on the best inventory across the business. Turning to the Marcellus. We continue to be aligned with the operator on the seasonal price-related production curtailments to optimize the economics of those reserves.

At the expected gas price environment, we anticipate development levels to increase over the next several years relative to the last several years in the Auburn area. Our Permian Basin Barnett project continues to be a solid performer. The eighth well in the play is performing very consistently compared with the first 7 wells. We now have 2 net wells making approximately 575 barrels of oil equivalent per day in the project. At least 2 more Barnett wells, 0.5 net are planned for 2026. In our Canadian JV, we are in discussions with the operator on potential plans for the next 18 months. And lastly, the company is in the early stages of exploring a sale of our noncore Mid-Con assets in Oklahoma. Thank you. And now back to Jason.

Jason Stabell: Thanks, guys. We can now open the lines for questions.

Q&A Session

Operator: [Operator Instructions] And the first question will be from Anthony Perala from Punch & Associates.

Anthony Perala: Great news on the BLM permit front. Just first off, any more that you can add to that and kind of the clarity and line of sight it gives to you being able to develop some of those Parkman wells in Converse County and maybe what your time line is over the next couple of years and how much capital you could commit to? I think what you highlighted in the deck was greater than or close to 100% IRR given the 65 for commodity prices.

Jason Stabell: Sure. Yes. Thanks for the question. I’ll maybe start and let Henry fill in where I’m incomplete. So we have been informed and observed that the BLM has started reissuing permits in Converse, which was part of the issue on our contingent share consideration. So as we see it right now, we think we’re going through confirmation, but we think all of the requirements for that consideration have been met. So what that allows us to start doing is really, as Henry mentioned, next year, doing the front-end planning around some infrastructure for — there’s a particular area down there we call [ I Knot ] in Converse. So we’re going to do some initial infrastructure investments. So I’d expect that to really kick off. Earliest would be late next year, but most likely, it’s going to be a first half ’27 where we’re going to roll out a pretty steady program, commodity prices being compliant with us here, but ’27 is going to be a big year for Converse activity.

And as Henry mentioned, ’26, we’ve got Campbell County Parkman that we’re going to focus on that pads have already been built. Infrastructure investments have already been made. So we’re in a great shape there to put that money to work. And then as far as your IRR, yes, the way we modeled the Parkman based on offset data and type curving, we do think the Converse stuff is from a rate of return standpoint, the most attractive. Campbell is a close second, but it is just based on offset data that we have. It’s slightly below that Converse stuff. So I guess the other thing we’d offer, we underwrote the Parkman value at 2 wells per section. We’ve done some incremental work that indicates at least on parts of our acreage based on what other operators have done and are doing, we think we could actually have more sticks in the Parkman than that 14 priority locations that we listed in the deck.

So that’s nice upside that seems to be falling out of this as well. So does that answer all your question? Or Henry, do you have anything to add to that?

Henry Clanton: I’d only add color to the infrastructure that we would be looking to build in Converse County. It ties mainly to water sourcing and storage. and will begin setting us up for future development in the area thereafter that will allow us to drive some economies. But working next year, primarily in the summer months will be the water sourcing and storage that we’ll be looking at.

Jason Stabell: And I think, Anthony, as a placeholder on the Parkman, just kind of a 2-miler, we budget that at somewhere between $7 million to $7.5 million per well. So we’re talking $750 or lower a foot on that. So it’s pretty attractive even at a low 60s oil price.

Anthony Perala: And then could you speak a little bit to just expecting on kind of the existing 2026 activity, what you want to be doing next year?

Jason Stabell: Yes. We’re still finalizing that. We’ve got a Board meeting later this month where we’re going to be laying out firmer plans there. But we put out a preliminary plan last quarter that had nominally $20 million of CapEx in the Peak assets. We provisioned for the 2 wells in the Permian that Henry mentioned. So that’s about $6 million net to our interest. And then the other piece of that was the Marcellus. We had $13 million of CapEx there for the back half of next year, which at this point, as I indicated in my part of the speech, I think there’s some potential that some of that CapEx slides into ’27. We haven’t firmed up plans with the operator there yet. But as we also mentioned, based on our conversations, we’re excited about what seems to be their shifting focus to Auburn over the coming years versus where their focus has been in the last several.

So I’d say that the moving piece probably at this point will be a little bit on that Marcellus, how much of that will actually fall into ’26 versus ’27.

Anthony Perala: That makes a lot of sense. And it was a ’27 kind of cash flow event anyways once it gets into production?

Jason Stabell: That’s right.

Anthony Perala: Okay. And then kind of as you’ve got your kind of focus on the integration and execution here in the next 18 months. If you could speak a little bit more about just the lift it requires to integrate that team, maybe investment to get — hit the ground running and some of the non-drilling investment that you mentioned a little bit on the call, but what you can do to optimize a little bit here maybe in December and in the first half of 2026 once the deal does close?

Jason Stabell: Yes. So we’ve been working closely with the Peak team. So I actually feel — I think we’re going to hit the ground running pretty close after close, Anthony, because we’ve done a lot of front-end work on making sure we have the right team in place post close, making sure we have in the right areas, the transition arrangements with some folks as well. So I’m real happy about how our cultures have fit. We’re 2 small teams coming together that have complementary skill sets. They’ve got a long history of over 100 wells drilled in the Powder. So we’re picking up a really solid team that has the experience and has done it. So I don’t think that’s going to be a real impediment to rolling out what we want to do in the Powder.

Anthony Perala: That’s great. And then just last one here. If you could speak a little bit to what other operators are doing kind of an offset activity in both, I guess, Campbell County and then Converse, if maybe areas where either they already have BLM permits or kind of planned activity around you the next 18 months here?

Jason Stabell: Sure. Yes, we watch offset operators pretty closely. I would say as a general observation, most offset operators with acreage around us have drilled up the Parkman because it is so economic. So what they’re focused on primarily is Niobrara and to some degree, the Mowry. The Mowry is a little gassier. I think as we see gas prices improve, we’ll probably see some increased capital allocation to the Mowry in the PRB. And then as we move a little bit to — I’ve noticed a little bit to our west, there’s still some Turner or what they call frontier development that’s also going on. So there are about 8 rigs active in the basin right now, and that’s been pretty consistent, and that’s with some pretty big name operators that will be familiar to you, Continental, EOG, Devon, a big private company named Anschutz and then a company called WRC, which is a large — has a big position there that’s also a private entity.

They’ve been consistent investors in the basin over the last several years. So we’re pretty happy with how things are going and frankly, think that probably activity levels going forward have more upside from here than where they’ve been in the powder over the last several years. So I wouldn’t be surprised if rig counts increase over the next 18 months.

Operator: [Operator Instructions] Ladies and gentlemen, this concludes today’s question-and-answer session. I would like to turn the conference back to Jason Stabell for any closing remarks.

Jason Stabell: No closing remarks other than to thank everybody for joining us today, and hope you have a great Thursday. And as always, if you’ve got questions, comments, feedback, please reach out to us here in Houston, and I look forward to hearing from everybody.

Operator: Thank you, sir. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.