Epsilon Energy Ltd. Aktie

Good day, and thank you for standing by. Welcome to the Epsilon Energy First Quarter 2026 Earnings Conference Call. [Operator Instructions] Please note that today's event is being recorded. I would now like to turn the conference over to Andrew Williamson, the company's CFO. Please go ahead.

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 first quarter 2026 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 press release that we issued yesterday for disclosures on forward-looking statements and reconciliations of non-GAAP measures.

With that, I would like to turn the call over to Jason Stabell, our Chief Executive Officer.

Thank you, Andrew, and good morning, everyone. Joining me today are Andrew Williamson, our CFO; and Henry Clanton, COO. We'll be available for questions after our remarks. We're off to a solid start in 2026 and remain firmly on track with the development plan we outlined earlier this year. The key message today is simple. We are in execution mode, and we expect to deliver meaningful production growth year-over-year, with the oil-weighted ramp in the Permian and Powder River basins beginning in the second quarter and building through the back half of the year.

Across the portfolio, activity is progressing as planned. In the Permian, our ninth well in the project and our first 3-plus mile Barnett well is expected online in the second quarter. In the Powder River Basin, 2 Niobrara DUCs, which we acquired in last year's acquisition will be completed in June and turn to sales in the third quarter, followed by a 3-well Parkman development in the fourth quarter. This activity sets up material oil-weighted production growth in both basins starting in the second half of the year and carrying into 2027. These new volumes will have full exposure to higher oil prices.

From a financial standpoint, the first quarter reflects a combination of strong gas pricing and a full quarter of contribution from our Powder River Basin assets. We have also recently taken steps during the second quarter to strengthen the balance sheet, including further debt reduction and monetizing noncore assets at attractive values. Looking ahead, the path forward is clear, a focus on production growth in our oily assets while maintaining a strong balance sheet. We believe we are well positioned to deliver a strong year.

I'll now turn it over to Andrew and Henry for additional comments.

Thanks, Jason. I'll provide more commentary on the quarter, starting with CapEx. We spent just under $5 million through March, primarily through our participation in the drilling of the 3-mile Barnett well in Ector County and some facilities work preparing for Parkman drilling this summer on our Campbell County position in the PRB. We plan to invest at a higher clip over the next 3 quarters of the year, driving the oil-weighted growth Jason mentioned. Those full year investment plans are rightsized to maintain our target leverage profile of 1 to 1.5x net debt to adjusted EBITDA. We expect unit operating costs and G&A to trend down over the remainder of the year as we add incremental volumes and roll off some of the integration costs associated with last year's Peak acquisition. I provided some additional color there in the press release issued yesterday.

Earnings for the quarter were materially impacted by unrealized or noncash hedge losses driven by the dramatic move in oil prices during the quarter. The revenue impact of higher pricing will primarily fall in subsequent quarters, so a bit of a mismatch on the P&L. Adjusting for that item, we earned $0.29 per share for the quarter. Since closing the acquisition in November of last year, we've paid down the outstanding debt balance by $10 million to $40.5 million currently. As mentioned, we have a disciplined approach to the balance sheet.

We've made several moves to help fund our investment plans by selling noncore assets. Earlier this month, we sold an overriding royalty interest package in PA for $3.9 million to a private buyer, which was approximately 6x expected next 12 months cash flow coming from those assets. The overrides accounted for just 1.5% of the company's upstream revenue over the last 4 quarters. We also have the office building we acquired from Peak under contract for $3 million with closing expected in the next 30 days.

Now to Henry to provide more detail on the operations side.

Thank you, Andrew, and good morning to everyone. Exciting times for Epsilon as we continue the integration of our newly acquired operating assets in the Powder River Basin in Wyoming. We have several initiatives underway, including both capital projects and optimization programs. Completion of 2 2-mile Niobrara laterals are underway with pressure pumping services scheduled for the first week of next month. The facility construction has been completed and ready for service following flowback operations. The company has a combined 0.7 net revenue interest in the 2 wells with a type curve-based pre-completion peak net production rate estimated to be 475 BOE per day in July.

Total net CapEx for the completion of the 2 wells is $6.8 million. Drilling-wise, first up in our development of the Parkman formation inventory is a 3-well development program in Campbell County with high working interest. Well planning has been completed with drilling rig and service providers being engaged in anticipation of an August spud. Gross CapEx is estimated to be $23 million. Similar to the 2 Niobrara wells mentioned above, preconstruction of the production facilities has been completed and ready for service.

Completion operations are planned for October with forecasted peak rates of 1,060 BOE per day in December. In preparation for our 2027 development of the highly attractive Parkman inventory in the Inot unit in Converse County, we are finalizing the facility design and beginning construction planning for a multi-well water supply facility in the unit. This $3.5 million CapEx facility will include water supply with surface impoundment sized to handle the planned 6-well development in the unit next year. This facility will ensure cost-efficient and timely development of our near-term plans in the unit, then serve multiple well programs thereafter.

Also in Wyoming, the operating team has been diligently working on several production enhancement and cost improvement initiatives worthy of highlighting. First, a review of the 40-plus rental gas lift compressors in use today have identified multiple wells greater than 10 that are candidates for downsizing the compressors, capturing significant monthly savings, approximately 35%. They will be replaced with brand-new units that are fit for purpose in this application. Current productivity of these wells will not be impacted.

Second, several remaining gas-lifted wells have been identified for conversion to rod pump. Based upon results of the first pilot test earlier this year, conversion to rod pump will increase daily production rates on average greater than 10% per well and also lower lifting cost. And lastly, building from a detailed review of the production chemical program for every operated well, optimization of the program is underway with reductions to per unit treatment costs expected to begin next month. As previously reported in our Permian Basin project in the Barnett play, discussions with the new operator confirm transition from 2-mile to 3-mile laterals, including 4 wells per pad development.

These locations will be along the development corridor, including the design and predrilling build-out of a multi-well source and production facility. We are fully aligned with these program changes and expect significant capital efficiencies as a result. 2026 activity to date includes the recently drilled and completed 3-plus mile Barnett lateral. Drillout operations will commence in a few days with flowback to follow.

Net forecasted production from this new well is 226 BOE per day. Two additional 3-mile laterals offsetting this well are planned for later this year. Similar initial production rates are forecasted for these 2 wells. Additionally, appraisal of a second interval in the Woodford Shale has been proposed by the new operator. This Woodford test is set to spud this month. While the company has elected to sell the wellbore-only interest in this well proposal, we remain ready to invest in future wells after the formation has been better delineated.

A successful result would increase our inventory meaningfully. The company has a 25% working interest across the project. In the Marcellus, the operator has completed drilling of the scheduled 5 wells, 0.4 net epsilon. Completion operations are planned for the second half of this year. First production from this development is scheduled in December and forecasted to add 6.5 million cubic foot a day rate. $3.8 million of CapEx was preapproved for this program with drilling costs below AFE. 4 of the new drills will gather through the Auburn system and are forecasted to increase throughput of the midstream system by approximately 86 million cubic foot a day upon initial completion.

Thank you. And now I'll turn it back over to Jason.

Thanks, guys. Operator, we can now open the lines for questions.

[Operator Instructions] And today's first question comes from Anthony Perala with Punch & Associates.

First question, I'd be curious some of the discussions among you guys and at the Board level. You've seen some operators respond to the higher oil prices that we've seen persist and as the back half end of the curve has raised a little bit here since the Q4 call. Your guys' development schedule definitely is already busy as is. But just curious if there are any discussions in kind of what the tenor of them are like about potentially stepping on the gas a little bit more. And besides capital and leverage, maybe what other impediments there might be to that if the opportunity did arise?

Great. Thanks for the question, Anthony. Before I dive into that, I think there's one point we'd like to clarify on the prepared remarks and it relates to the Parkman CapEx that we had. I think Henry quoted $23 million of gross CapEx, and then he quoted a rate of close to 1,100 BOE per day on the rate. We're actually looking, as we always do, at the possibility of selling down some of that 95% working interest. And so Henry, do you want to talk about the rate, what it assumes now.

Right. So the $23 million is our current ownership and what would be the capital expectations for that 3-well development. Should we keep all of that interest, the peak rates are estimated to be 1,600 barrels a day equivalent, not the lower 1,060 as was recorded in our comments.

Yes, that 1,060 assumes about a 33% sell-down. We're looking at that option, something in the 20% to 30% sell-down. If it's attractive, we might do it. If not, I think we'd also be happy to keep the higher figure there, but I thought that was worthwhile to clarify. All right. Now to your question, yes, the Powder seems to be coming alive, maybe like a number of basins with the oil price move that we've seen. We've now been active there for 6 months roughly since the closing of the transaction. So we've had a number of conversations with offset operators. There are roughly 13 -- at any given time, there have been 12 to 14 rigs running in the basin, and we think there is probably room to add 1 or 2 more based on some conversations that we've had.

One of the ways that, yes, the gas pedal could be hit a little bit harder for us would be to partner on some of the acreage in -- particularly in the shales in Nio and Mowry interest that we have in offset leasehold. We've had some preliminary discussions with a number of operators about ways, things that we might not be getting to in our 5-year development plan until 3, 4, 5, even beyond that window. So I think kind of stay tuned, Anthony, going forward, there could be some opportunities either for us to do drill-to-earn deals and/or partner with some other operators on some opportunities.

I don't see anything on the imminent horizon, but we're working all of those options. And we think there's a number of ways we could potentially provide incremental upside to the base CapEx plan that we have. So hopefully, that answers your question.

Yes. Yes, it absolutely does. And I guess one follow-on to that, it's more probably from naive to on my side. But is there kind of when you're looking at securing rig availability for the 3-well pad in the Parkman this year, is that -- is it tougher and kind of are the rates higher given increased activity? Or is it pretty kind of run-of-the-mill transaction right now?

Henry, do you want to?

Yes. So the rig availability is tightening up. We've seen that in our conversations with probably 3 different providers. We do have access to a couple of rigs that are workable for us that we're working now to fit with the timing of the development. But rig rates are creeping up. And so that's to be expected, yes.

But we feel confident we're going to find a rig that can do the job and do it cost efficiently and deliver those wellbores on time. So right now, as we said, we're targeting that August spud date and don't see an issue with that.

Okay. And then kind of on the flip side of that on funding some of these capital projects, it seems like you've maybe worked through more of the low-hanging fruit of noncore assets to divest. Just curious how you look at the broader portfolio and other areas you might explore similar to the Marcellus overriding royalty interest that you sold in May?

Yes. We're always looking at ways to optimize. I think that override we thought had the potential for some pretty strong interest based on conversations that we had. So we market tested it and got a good result on that deal. As you know, we also sold the Anadarko position at the end of last year. So I think the portfolio is in a pretty good place. The trimming would probably be, yes, do we -- there is a pretty active AFE market. So do we find an attractive opportunity where we might sell down a small piece of some of our working interest in some of the program going forward. I think that will be opportunistic kind of depending on the appetite that we see, but that is a possibility. So I think it would be consistent kind of with what we've been doing, little small things around the edges.

Okay. And then you highlighted in the PR and in the prepared commentary just about getting some scale on the fixed cost on the operating side. I think if you do back of the envelope math before this was roughly $12 per BOE on the LOE expense. And as you get greater scale heading into '27 and maybe beyond, just what expectations do you guys have on the cost side?

Yes, Anthony, this is Andrew. The big driver for the higher unit OpEx in the first quarter was full contribution of the PRB assets. That's all PDP production. They've not had new volumes come online there for over 2 years. So that fixed cost element is overrepresented in that production. As we bring on incremental volumes in the Powder, we expect that to go from where we are now in the high teens to low 20s per BOE in the Powder for that to come into the mid-teens. And so where that washes out total company on a BOE basis, we should see several dollars of drop there and concentrated in the fourth quarter this year when we bring on the volumes in the Powder pad.

And the next question is from Jeff Robertson with Water Tower Research.

A question on the Powder River Basin. Are there any other infrastructure issues or needs that you foresee Epsilon needing to be involved with and fund other than the water facilities that you outlined?

In Converse County, which is where we are describing this Inot unit for development next year, there is some gas takeaway development that will be required beyond what's there. We'll have the option to participate in that should we want to or just have the gatherers come to us. So yes, there'll be some gas takeaway. But the majority of the cost for us will be related to supplying these completions and the frac water is necessary to do that. And that's what's our focus of that design of that facility was for.

In the Permian Basin on the Woodford test that you talked about, how much production -- assuming that well is a success, how much production history would you like to see before Epsilon would elect to participate in a follow-up well.

Yes. I think it's not just -- it's around can they land in the Woodford, what's the cost there? Have they worked out well design? And then obviously, what kind of rate it delivers over time. Hard to say exactly, Jeff, but it's probably at least 180 days of production to get a real good sense of what the productivity looks like there.

And this does conclude our question-and-answer session for today. I would now like to turn the conference back over to Jason Stabell, CEO, for any closing remarks.

Yes. Thank you, Chris. I appreciate everybody taking the time to join us today. Thanks for your interest and support of the company. And as always, please reach out to us in Houston if you have additional comments or questions. If not, have a great day. Thank you for joining.

And the conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.

Good morning, everyone, and welcome to the Epsilon Energy 2025 Year-End Earnings Conference Call. [Operator Instructions] Please also note today's event is being recorded.

At this time, I'd like to turn the floor over to Andrew Williamson, CFO. Please go ahead.

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 full year and fourth 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 would like to turn the call over to Jason Stabell, our Chief Executive Officer.

Thank you, Andrew. Good morning, everyone, and thank you for joining us. With me today are Andrew Williamson, our CFO; and Henry Clanton, our COO. We will be available to answer questions later in the call.

Epsilon delivered a standout year, growing adjusted EBITDA 75% and production 54% year-over-year. In the fourth quarter, we closed the acquisition of the Peak companies, bringing us new production, more than 100 net high rate of return drilling locations, largely held by production undeveloped acreage and a highly experienced Powder River Basin operating team. Through a combination of development drilling and the Peak acquisition, we achieved 69% growth in proved developed producing reserves and an 86% increase in total proved reserves.

The Board recently declared our 17th consecutive quarterly dividend and renewed the share buyback program covering up to 10% of shares outstanding, underscoring our commitment to returning capital to shareholders. Looking at 2026 to date, our portfolio is performing exceptionally well. In late January, we realized extremely favorable natural gas pricing in Pennsylvania, generating over $4.8 million in net natural gas sales in a single week, including sales 1 day at over $66 per MMBtu.

Our current PDP production is approximately 60% hedged for the rest of the year. But importantly, the incremental oil volumes we expect to add through the drill bit starting in the second quarter are unhedged, providing meaningful upside exposure. I would like to add that our past commentary on the acquired Powder River Basin assets has focused on the very attractive high rate of return Parkman inventory, but I need to remind investors that we also acquired several hundred locations in the Niobrara and Mowry formations that are the focus of activity for most of our offset operators in the basin. While the average expected returns in these formations are currently below the Parkman, this inventory represents a material wedge of value that we acquired at less than $250,000 per location.

We expect the returns on this inventory to improve dramatically as we scale operations and extend lateral lengths, particularly if oil prices remain at levels above $70. Epsilon is now positioned as a unique multiyear organic growth story with strong visibility into per share growth in EPS, EBITDA and production over the next few years, while maintaining a fixed dividend and targeting an average annual leverage ratio below 1.5x.

Thank you for your continued support. I'll now turn it over to Andrew and Henry for additional comments.

Thanks, Jason. I'll start by elaborating on the Peak closing that occurred on November 14, 2025, with the release of the contingent consideration occurring a few days later on the 20th. The BLM permitting issues on the acquired acreage in Converse County were resolved right around closing and that the BLM resumed their approval of drilling permits in the affected area. And as it stands now, we have 7 approved drilling permits that provide access to that acreage, which we believe holds some of the best inventory we have in the basin.

We plan to start to develop there next year with some front-end facilities work this year. Now on to the year-end results. Jason mentioned the year-over-year growth in production and cash flow, which was primarily driven by higher volumes, up 65% and better pricing with realized prices up over $1 per MMBtu year-over-year in the Marcellus with wells coming online in the first quarter that were paid for the prior year.

Our operator has additional development planned this year and again, in '27 and '28 at an accelerated pace. We expect the vast majority of these volumes will flow through the Auburn Gathering System when developed, driving strong capital-efficient cash flow growth in our midstream asset over that period. We have several one-off items that impacted earnings this year, transaction costs from the Peak acquisition, which were $6.9 million in total, although half of these were expenses assumed from Peak that were unrelated to the deal and were adjusted for in the share consideration issued at closing. Also impacting the year were some impairments on our wellbores in Canada and New Mexico.

The drivers were the oil strip we were required to use at 12/31/25, which was sub-$60 WTI, downward reserve revisions due to a frac hit in New Mexico. Note, the New Mexico interests are small with 10% in 2 wellbores. And finally, well underperformance in Canada. In Canada, we've spent $11 million over the past 2 years, including approximately $4.5 million to earn into a large acreage position of over 100,000 net acres that we believe has great option value, although based on the results observed to date, the area does not currently compete for capital in our portfolio.

The major adjustment was the loss on our sale of the Oklahoma assets. We also had a large tax basis there. And when you combine cash received at closing with the cash tax savings, the deal generated over 8x the expected cash flow from those assets in 2026. So very accretive on a multiple basis. Also, we had no plans to allocate capital there with the portfolio we have, and it made sense to clear the decks and use those cash proceeds to pay down our debt balance, which we did in the first quarter by $5 million. Adjusting for the items I just described, the company earned $0.92 per share in 2025. We're doing a couple of things to increase liquidity over the next few months given the larger capital program this year across the portfolio.

We're in the market selling an overriding royalty interest package in the Marcellus, where we believe we can transact at an accretive multiple. We also have the Colorado office building we acquired with Peak under contract for $3 million. Overall, this is an exciting time for the company with several value-enhancing developments that are in progress or will be in the next 12 to 18 months. These include our operated high-return Parkman development in the Powder River Basin, accelerated Barnett development in the Permian and steady development in the Marcellus with expected increases in gas production and midstream throughput in the '27, '28 time frame. We showed the potential cash flow impact of some of these things in our first quarter 2026 corporate presentation, which is available on our website.

Now to Henry for more detail on our investment plans this year and a look ahead to the next few years.

Thank you, Andrew, and good morning to everybody. I'd like to share more detail on our development plans for 2026, beginning with our newly acquired operating assets in the Powder River Basin in Wyoming. We have initiated completion operations of 2 2-mile Niobrara DUCs, 0.7 net working interest to Epsilon.

The net CapEx for these 2 completions is expected to be approximately $6 million. This includes the preconstruction build-out of the production facilities to be ready to put the wells into service after flowback. The frac is currently scheduled for Q2. As Jason mentioned earlier, we're focused on the Parkman drilling inventory with plans to drill 3 2-mile laterals, 2.8 net beginning in Q3 with production online in Q4. Net capital for these 3 wells is expected to be approximately $22 million.

In preparation for our 2027 and 2028 development plans in the Parkman in Converse County, Wyoming, 12 gross wells, we will be building out a water supply and impoundment facility to support this program and drive development costs down. In our Permian Barnett asset, project management and operatorship has changed. Based upon discussions with the new operator, the project development will transition to 3-mile laterals with 4 wells per pad development along a development corridor.

In addition to the drilling program, the new operator informs us that planning is underway for a multi-well production battery and a water recycling facility within the main development corridor. We are aligned with the operator and support these changes to the development plan and the facility approach, which is expected to drive cost savings on the wells moving forward. This month, the first 3-mile Barnett well was drilled on the position. The completion planning is in progress, and we expect the well online close to midyear.

Net CapEx for the drilling and completion of this well is expected to be approximately $4 million. Based upon preliminary discussions with the new operator, an additional 3 wells, 0.75 net are planned in the second half of the year. We expect this to include 2 Barnett 3 milers offsetting our recently drilled well to minimize parent-child impacts. The third well is expected to be an appraisal test in the Woodford interval. A successful result there will increase our inventory meaningfully.

Moving to the Marcellus. Development activity is restarting. We have received well proposals for the drilling of 5 wells, 0.4 net beginning in early Q2. Completions are currently scheduled for the second half of the year. Net CapEx for these 5 wells is expected to be approximately $4 million. We have also begun LOE optimization efforts in Wyoming. This program includes downsizing gas lift compressors, 12 planned, focused efforts to reduce the treating cost per barrel from the production chemicals program and reducing and optimizing power usage in the field.

These efforts are expected to remove fixed cost and improve variable costs without impacting production. Monthly savings for these initiatives are estimated to be 50,000 to 100,000 gross per month. Currently, no 2026 activity is planned in Canada. And finally, to add to what Jason mentioned earlier, the company's total reserves increased to 156 Bcf equivalent due primarily to the 78 Bcf of additions related to the acquisition of the Powder River Basin assets. For those interested in more details on the year-over-year changes, I would refer you to the detailed reserves reconciliation information provided in the 10-K and press release.

Now I'll turn it back to Jason.

Thanks, guys. Operator, we can now open the lines for questions.

[Operator Instructions] Our first question today comes from Anthony Perala from Punch & Associates.

Just wanted to ask on -- looking at kind of some of the details you gave around the Peak acquisition timing. And I think you still have referenced like a $65 oil level for returns and IRRs. Just curious if we're looking at it through a lens of today, whether it's the kind of front month or even going back to like the curve is in the mid-70s going through the back half of 2026. Just curious what returns look like under those oil assumptions rather than $65.

Anthony, Jason here. Thanks for the question. I'll let Andrew address that one.

Yes. Thanks for the question, Anthony. So yesterday's forward averaged $77 through year-end '27. We run price sensitivities on our type curves and $5 increments. So at $75 WTI, returns for our oil-rated Inventory increased meaningfully. I'm going to add the Permian stuff alongside the question on the Powder. Barnett, 3-mile at $65, as mentioned in our corporate presentation, is 45% IRR with a 2-year payout, roughly 3x multiple on invested capital.

And at $70, those move into the 60% range, 18-month payouts and 3.5x on the multiple. In the Powder, starting with the Parkman, and that's the focus of our development in the basin over the next 18 to 24 months. Again, in the presentation, we talk about the Parkman split into the inventory across the 2 counties. So in Converse, which is the best stuff, that's 150% return, 10-month payout, 2.5x. The Campbell County Parkman is in the 45% to 50% range of 20-month payouts.

And at $75, those increase for Converse to over 200%, 8-month payouts 3x and then Campbell increases to 80% less than 18 months on the payout and over 2x. The largest component of the inventory in the basin and the powder is the upper Nio. We're at $65, that's in the 25% to 30% range, 3-year payouts and 2x at $75, that increases to 40%, 45%, 2-year payout and 2.5x. And we've got 46 net locations there in the Nio.

That's really helpful. And just thinking, I guess, between those -- you can see that obviously, the Parkman stands out. I'm curious, it's a good problem to have, but just curious on how you guys look at how capital kind of competes with the variance of you controlling your own destiny with the Parkman and PRB locations and then having the non-op working interest and kind of dealing with the operator in the Barnett, the new operator.

Yes. I mean it's going to go highest and best use. Right now, kind of looking at the portfolio, Anthony, we think about it at about 50% of our investment over the next 2 years is going to be Powder focused. And then the remainder is split between Marcellus and Barnett. So I think with pricing doing what they do, I don't see a huge change to that.

As we mentioned on the call, we're excited about the new operator that we have in the Barnett oil play. It's a large scaled private operator that has pretty aggressive plans for ramping this year, but really stepping up next year. So we think in addition to the PRB, that Barnett asset is going to be a nice source of liquids growth for us. And as Andrew quoted, the returns in a world $65 plus, those Barnett investments are quite attractive.

And I think we get more excited, thinking about a 3-mile lateral world in the Barnett. We had our first well drilled there that we're going to complete, as we mentioned, mid this year. But -- so I think it's all shaping up how we would have liked. We've got options. We've got our operated position that we can flex up and down depending on macro. We've got a lot of inventory there, Parkman focused certainly. But as I mentioned, we want to remind people, we've also got this pretty deep Nio inventory, which is where most of the industry in the PRB is currently focused its capital.

Yes. It's kind of funny looking back on when you first took the role, the difference in just investment opportunities from primarily the Marcellus. Now you have a lot of different plays that compete for capital. On that Nio piece, which, as you lay out, is probably 2028 before that really competes for capital given just the Parkman inventory. I'm curious, like you had said, it seems like people are getting more active there, and it's being proved out more by larger scaled operators. I'm curious what you're seeing and hearing from those that are really committing capital to the Nio and [indiscernible] right now in the PRB.

Sure. I'll start maybe with some general comments and Henry can fill in anywhere that he sees fit. Yes, I think around us in Campbell and Converse, there are a number of rigs. Right now, the big operators, and I'll just name a few, Devon, EOG, Continental, Oxy, they're really focusing their capital on the Nio.

I think what you're seeing there is similar to what you're seeing in other basins. We're going from a 2-mile lateral world to the standard right now in the Nio, I think, for this year and forward is 3- to 3.5-mile laterals, which enhances economics quite a bit. We even have an offset operator that we know is planning a 4-mile lateral in the Nio, or a DSU of 4-milers.

So I think the economics there as you start to extend laterals, batch drill wells, you're going to see that the Nio and the PRB is competing for capital in much larger portfolios of the companies I mentioned. So we're encouraged by that. As we said, we're watching closely. I think our near-term focus is going to remain the Parkman. Probably over the next 2 years, we will have some non-op opportunities in some of these Nio wells in some of that offset acreage as well that I think we'd be interested in. So I'll stop there and let Henry add.

Yes. The only thing I could add to that is we've got 12 rigs running in Campbell and Converse and Johnson County around our acreage position. And 10 of those 12 are Niobrara focused. So that gives you some color on how focused the big guys that Jason mentioned are allocating their capital.

That's very helpful. Just one final one for me here. Just if you could add a little bit more color. You had mentioned you're in the market looking at selling an overriding royalty package on some of the Marcellus assets. Just if you could give some more color to that and just how best to think about that for potential proceeds.

Yes, I'm not going to guide on proceeds, but it's a small amount of production. So we're talking somewhere, I think, less than 1 million cubic feet a day of production. So it represents a pretty small overall piece of our production. It sits outside of our core Auburn area. These are some overrides we've picked up over the years due to acreage trades with some other area operators.

There's a pretty robust interest as we understand it for override mineral interest. So we're doing a market test to see. We believe, as Andrew mentioned, that we're going to have an opportunity to potentially sell it at a pretty attractive multiple. Nothing is locked in there until we get some bids next month and decide if it's something of interest to us or not. But so we're just kind of pruning around the edges on the portfolio. As we talked, we moved the Anadarko assets last year.

There was some cash we brought on the balance sheet, but also had some positive tax -- after-tax impacts for us. That office building that came in the Peak deal. We thought it made sense to explore a sale of that. And as Andrew mentioned, that's $3 million that we've got under contract. So I expect that will close in the second quarter. So just as we've expanded the portfolio, we're trying to make sure that it's optimized as best as possible, and we're creating opportunities to reinvest in what we think are our best sources of inventory. So we feel good about it.

[Operator Instructions] And showing no questions at this time, I'd like to turn the conference call back over to Jason for any closing comments.

Nothing to add, operator, other than to thank everybody for joining us today. And as always, if people have additional questions, feel free to contact us here at the Houston office. So everybody, have a good day. Thank you.

And with that, ladies and gentlemen, we'll conclude today's conference call and presentation. We do thank you for joining. You may now disconnect your lines.

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.

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.

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.

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.

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.

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

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

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.

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?

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.

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.

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?

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.

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

That's right.

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?

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.

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?

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 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.

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.

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

Good day, and welcome to the Epsilon Energy Second 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.

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 acquisition of Peak Companies and our second 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.

Thank you, Andrew. Good morning, and thank you for participating in our 2025 second quarter conference call. Joining me today are Andrew Williamson, our CFO; and Henry Clanton, our COO, who will be available to answer questions later in the call.

Today, along with our earnings release, we announced the acquisition of the Peak Companies with assets in the Powder River Basin, PRB. The deal adds a new core area to the company at an attractive price. The acquisition includes key members of the Peak team that bring over 15 years of in-basin operating experience. It adds oil-weighted production and a massive operated inventory of locations across multiple benches.

Importantly, the position is approximately 75% held by production, allowing for returns-driven capital allocation over time as commodity prices dictate. We think this PRB platform provides the opportunity for both organic and inorganic growth. Our near-term activities post closing will focus on the Parkman formation, a semi-conventional reservoir with half-cycle economics that rival anything in our existing portfolio, at a significantly lower implied acquisition cost per location compared to available acreage in the Marcellus or the Permian. We estimate 14 net Parkman 2-mile laterals on the position with opportunities to add incremental interest via pooling and leasing. In addition, the assets add attractive inventory estimated at 90 net 2-mile locations in the Niobrara and Mowry, which offset operators, including EOG and Devon are currently developing on adjacent acreage.

Over time, we expect these intervals to develop into a meaningful percentage of our capital expenditures. They offer a nice balance of oil and gas potential. Approximately 30% of the identified priority inventory is currently affected by a drilling permit moratorium in Converse County, Wyoming. We addressed this issue by making a portion of the consideration contingent on our ability to access this inventory. We are optimistic that given the current regulatory environment, the moratorium will be lifted in the near to medium term.

Post close, we think our high-quality asset mix across the Marcellus, Permian, Barnett and PRB is truly unique in the small-cap space. The addition of this operated asset base gives us enhanced capabilities and control to add per share value. We are also excited to add Yorktown as a large shareholder. I've known and worked with the principles of the firm for over 20 years. They are experienced and successful energy investors that will bring tremendous value as we continue to grow the company.

I want to thank them and the Peak team led by Jack Vaughn for their partnership.

I'll now turn the call over to Andrew and Henry for some comments on the deal and our second quarter results.

Thanks, Jason. I'll start by talking through the mechanics of the transactions. Consideration at closing will be the issuance of 6 million Epsilon common shares and the assumption of approximately $49 million of long-term debt. As Jason mentioned, additional contingent consideration of up to 2.5 million Epsilon common shares is payable when we can access the affected acreage in Converse County. The contingent shares consideration will decrease over time if access is delayed beyond year-end '26. Further details regarding the step down and consideration to be found in the presentation we released today.

We will refinance Peak's term loan with an expanded revolving credit facility at closing, led by our existing lender. The process is underway to add a second bank to the facility with an indicative borrowing base of $95 million in closing. We will be approximately 50% drawn with a forecasted net debt to adjusted EBITDA ratio of approximately 1x, which we believe is conservatively leveraged pro forma business. Importantly, the transaction and associated leverage profile allows us to comfortably maintain our existing per share dividend and have sufficient discretionary cash flow to drive growth through a development plan that covers the Marcellus, Permian and PRB starting next year.

At closing, the Peak shareholders will represent approximately 21% of the equity, which can increase to as much as 28% if the maximum contingent shares are issued. In exchange, our year-end '24 proved reserves increased by over 150% based on Epsilon and Peaks third-party reports, which are subject to change at year-end '25 based on development assumptions in SEC pricing.

Liquids production increased by over 200%, and our priority or premium inventory count increases by over 600%. We defined priority inventory as 2-mile net locations that underwrite returns over 25% at $65 WTI and $4 Henry Hub flat price assumptions.

Our underwriting has 40% of the acquired PRB inventory here exceeding that threshold. This includes the Parkman and some of the Niobrara. Given we plan to issue over 20% of our pre-deal shares outstanding, closing will be subject to a shareholder vote planned for the fourth quarter. We will file a proxy statement this fall with additional detail on the Peak Companies and assets, transaction background and rationale and the financial position of the pro forma business.

Now to the second quarter, production was roughly flat, driven by the new production in the Marcellus, we started to see in the first quarter. Realized pricing was down meaningfully quarter-over-quarter for gas and oil. So cash flows were down roughly 30% quarter-over-quarter.

Now, to Henry, to discuss the PRB assets, the addition of operational control and our preliminary near-term development plans on our legacy assets and the acquired assets for the remainder of this year and next.

Thank you, Jason and Andrew. As mentioned by Jason and Andrew, the acquisition of the Peak Companies is a significant addition to our undeveloped inventory. And not only will it have a meaningful impact on our near-term development, but it also adds a highly experienced operating staff who has drilled 100-plus wells in the Powder River Basin. Currently, the company has 2 2-mile Niobrara DUCs, 0.7 net in inventory that are scheduled for completion in Q4. Initial plans for next year call for the development of 3 high-working interest Parkman wells, approximately 96% working interest in the first quarter subject to the closing time line of the transactions.

This acquisition adds approximately 2,200 net barrels of oil equivalent of daily production, 56% oil with greater than 90% of the PDP value held within the operated wells. This production base has good value diversity spread across 168 wellbores and 5 intervals.

The producing wells are relatively early life with majority of them less than 10 years old and a forecasted base annual decline rate of approximately 15%. Our Marcellus asset, we are pleased to report that based on communications with the operator, we expect drilling activity to start up again in 2026. The operators' plans, which, of course, are subject to change based on market conditions and other factors, include the drilling of 7 gross, 1.2 net wells on 2 pads. Production from both pads is scheduled to come online in Q4 2026.

All of these wells will be gathered through the Auburn Gas Gathering System. On our Permian Barnett project, our operating partner has successfully drilled, completed and placed on production the eighth well in the project, the Irma Unit 1H. The well has a completed lateral length of 10,966 feet. Preliminary development plans for next year includes the drilling of at least 2 additional gross wells, 0.5 net. I would also like to briefly comment on the impairment taken this quarter on our recent investments in our joint venture in the Garrington area of Alberta.

The impairment was driven by a combination of drilling and completion cost overruns and early well inflow performance below expectations. We have had ongoing technical collaboration with the operating partner and we feel confident this robust review effort will lead to improved location selection and better drilling and completion planning moving forward. The JV covers a large acreage position that we believe remains valuable.

Now, back to Jason.

Thanks, guys. Operator, we can now open the lines for questions.

[Operator Instructions] That concludes the question-and-answer session. I'd like to turn the conference back over to Jason Stabell for any closing remarks.

Thank you, operator. I want to thank everybody for joining today. I look forward to talking to you guys about our base business and the exciting new acquisition that we have. Teed up. I think it's a really, really exciting future for the company and appreciate your support, and we'll talk to you soon. Everybody, have a great day. Thank you.

This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.