Epsilon Energy (EPSN) Q4 2025 Earnings Transcript

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DATE

Wednesday, March 25, 2026 at 11 a.m. ET

CALL PARTICIPANTS

• Chief Executive Officer — Jason P. Stabell
• Chief Financial Officer — Andrew Williamson
• Chief Operating Officer — Henry Nelson Clanton

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TAKEAWAYS

• Adjusted EBITDA Growth -- Adjusted EBITDA rose 75% year over year, driven by production and pricing gains.
• Production Increase -- Production climbed 54% year over year, supported by both development drilling activity and the Peak acquisition.
• Peak Acquisition -- The company closed its Peak companies acquisition in the fourth quarter, adding more than 100 net high-return drilling locations and new Powder River Basin operating capabilities.
• Reserves Growth -- Proved developed producing reserves increased 69%, and total proved reserves rose 86%, following development and the Peak transaction.
• Dividend and Buyback -- The Board declared its seventeenth consecutive quarterly dividend and renewed the share repurchase program to cover up to 10% of shares outstanding.
• Recent Gas Pricing -- In late January, the company recorded Pennsylvania gas sales exceeding $4.8 million in one week, including a day at over $66 per MMBtu.
• Hedging Status -- Current proved developed producing (PDP) production is about 60% hedged for the remainder of the year, while upcoming incremental oil volumes will be unhedged.
• Basin Inventory Acquired -- In addition to Parkman, several hundred net locations were acquired in the Niobrara and Mowry formations in the Powder River Basin at under $250,000 per location.
• Leverage Target -- The company targets an average annual leverage ratio below 1.5x while maintaining a fixed dividend policy.
• Drilling Permits -- Seven drilling permits are now approved in Converse County after resolution of BLM permitting issues.
• Marcellus Realized Price -- Realized natural gas prices in the Marcellus increased by more than $1 per MMBtu year over year.
• Transaction Costs -- Total transaction costs from the Peak acquisition were $6.9 million, with approximately half unrelated to the deal and adjusted in share consideration.
• Asset Sale Outcome -- Sale of Oklahoma assets generated over eight times projected 2026 cash flow, producing positive after-tax impacts and enabling a $5 million debt paydown in the first quarter.
• Adjusted Earnings -- Adjusted for one-off items, the company reported $92 per share in 2025.
• Liquidity Initiatives -- The company is marketing a Marcellus overriding royalty package and has a Colorado office building under contract for $3 million.
• 2026 Powder River Plans -- Completion of two Niobrara DUCs (0.7 net) with $6 million net CapEx is underway, plus plans to drill three Parkman laterals (2.8 net) for $22 million net CapEx beginning in the third quarter.
• Water Facilities Investment -- Construction of water supply and impoundment facilities is planned in preparation for a 2027–2028 Parkman program targeting twelve gross wells.
• Barnett (Permian) Update -- Transition to three-mile laterals with four wells per pad; first three-mile well drilled with approximately $4 million expected net CapEx and completion targeted for midyear.
• Marcellus Drilling -- Five well proposals (0.4 net) received for drilling beginning in early second quarter, with approximately $4 million net CapEx estimated.
• LOE Optimization -- Programs in Wyoming include downsizing gas-lift compressors, chemical treating savings, and power optimization, targeting monthly gross cost reductions of $50,000 to $100,000.
• Total Reserves -- Year-end total reserves rose to 156 Bcfe, with 78 Bcfe added from the Powder River Basin acquisition.
• Development Focus -- Near-term investment focus is approximately 50% Powder, with remaining capital allocated across Marcellus and Barnett assets.
• Return Sensitivities -- At $75 WTI, IRRs and payout periods improve materially for Parkman, Campbell, and Niobrara; for instance, Converse County Parkman exceeds 200% IRR with an eight-month payout.
• Rig Activity -- Currently, twelve rigs operate in Campbell, Converse, and Johnson counties, with ten focused on the Niobrara formation near company acreage.

SUMMARY

Epsilon Energy Ltd. (NASDAQ:EPSN) significantly expanded its asset base and reserve portfolio through the Peak companies acquisition and related drilling activity, bolstering its position in the Powder River Basin and diversifying its sources of production and upside. Recent initiatives to divest non-core assets and improve operational efficiency, such as the announced sale of the Oklahoma properties and cost-reduction programs in Wyoming, have enhanced liquidity and freed up capital for higher-return projects. Management articulated clear visibility into EPS, EBITDA, and production growth, backed by identified drilling inventory and a disciplined capital allocation framework across operated and non-operated assets.

• Specific detail was provided on incremental capital allocation, with $6 million net CapEx for Niobrara DUC completions and $22 million net CapEx committed to the Parkman drilling program, as well as a $4 million net CapEx for the inaugural Barnett three-mile lateral.
• Operational flexibility is emphasized, with management confirming most near-term investments will remain focused on the Parkman formation, while non-operated opportunities in the Niobrara and Woodford are being evaluated in parallel.
• Management outlined in detail how directional changes in oil pricing, particularly above $70 WTI, could significantly improve returns on recently acquired and legacy asset inventories based on recent sensitivity cases.
• Diversification of production and midstream cash flows is highlighted through the accelerated Barnett development under a new operator, and expected throughput expansion on the Auburn Gathering System in upcoming years.
• The company communicated intentions to maintain a fixed dividend and continue opportunistic share repurchases, while also targeting a below-1.5x leverage ratio even as capital expenditures and drilling activity accelerate.

INDUSTRY GLOSSARY

• DUC: Drilled but uncompleted well — a well that has been drilled to target depth but not yet hydraulically fractured or completed for production.
• IRR: Internal Rate of Return — annualized effective compounded return rate that can be earned on invested capital.
• Parkman: A geological formation in the Powder River Basin known for oil development potential; referenced as a core focus for Epsilon's drilling program.
• Niobrara: A major oil- and liquids-rich formation in the Powder River Basin, subject to increased development focus in this and other company portfolios.
• Royalty Interest: A non-operating ownership interest entitling the holder to a share of production or revenue from producing wells, typically without responsibility for costs.
• MMBtu: One million British thermal units, a standard energy measurement for natural gas sales and pricing.
• Bcfe: Billion cubic feet equivalent — a volumetric measure equating various hydrocarbons (oil, gas, and NGLs) into cubic feet of natural gas on an energy-equivalent basis.
• LOE: Lease Operating Expense — the recurring costs of operating and maintaining producing oil and gas properties.

Full Conference Call Transcript

Epsilon Energy Ltd. 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 gas pricing in Pennsylvania, generating over $4,800,000 in net natural gas sales in a single week, including sales one 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 Energy Ltd. 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 will now turn it over to Andrew and Henry for additional comments.

Andrew Williamson: Thanks, Jason. I will start by elaborating on the Peak closing that occurred on 11/14/2025, 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 the BLM resumed their approval of drilling permits in the affected area. As it stands now, we have seven 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 2027 and 2028 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 on our midstream asset over that period.

We had several one-off items that impacted earnings this year: transaction costs from the Peak acquisition, which were $6,900,000 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 12/31/2020, 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 two wellbores—and, finally, well underperformance in Canada.

In Canada, we have spent $11,000,000 over the past two years, including approximately $4,500,000 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. 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, 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 $5,000,000. Adjusting for the items I just described, the company earned $92 per share in 2025. We are doing a couple of things to increase liquidity over the next few months given the capital program this year across the portfolio. In the market, we are selling an overriding royalty interest package in the Marcellus; we believe we can transact at an accretive multiple. We also have the Colorado office building we acquired with Peak under contract for $3,000,000.

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 2027–2028 time frame. We show 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.

Henry Nelson Clanton: Thank you, Andrew, and good morning to everybody. I would 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 two-mile Niobrara DUCs, 0.7 net working interest to Epsilon Energy Ltd. The net CapEx for these two completions is expected to be approximately $6,000,000. This includes the pre-construction buildout 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 are focused on the Parkman drilling inventory with plans to drill three two-mile laterals, 2.8 net, beginning in Q3, with production online in Q4. Net capital for these three wells is expected to be approximately $22,000,000. 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 three-mile laterals with four 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 three-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 $4,000,000.

Based upon preliminary discussions with the new operator, an additional three wells, 0.75 net, are planned in the second half of the year. We expect this to include two Barnett three-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 five wells, 0.4 net, beginning in early Q2. Completions are currently scheduled for the second half of the year. Net CapEx for these five wells is expected to be approximately $4,000,000. 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 costs 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. Finally, to add to what Jason mentioned earlier, the company's total reserves increased to 156 Bcfe due primarily to the 78 Bcfe 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's press release. Now I will turn it back to Jason.

Jason P. Stabell: Thanks, guys. Operator, we can now open the lines for questions.

Operator: At this time, we will begin the question-and-answer session. To withdraw your questions, you may press star, then 2. Please pick up your handset prior to pressing the keys to ensure the best sound quality. Our first question today comes from Anthony Perala from Punch & Associates. Please go ahead with your question.

Anthony Perala: Hey, good morning, guys. Thanks for taking the question here. 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 are looking at it through a lens of today—whether it is the kind of front month or even going back to you—like, the curve is in the mid-seventies going through the back half of 2026. Just curious what returns look like under those oil assumptions rather than $65.

Jason P. Stabell: Anthony, Jason here. Thanks for the question. I will let Andrew address that one.

Andrew Williamson: Yes, thanks for the question, Anthony. So yesterday's forward averaged $77 through year-end 2027. We run price sensitivities on our type curves in $5 increments. So at $75 WTI, returns for our oil-weighted inventory increased meaningfully. I am going to add the Permian stuff alongside the question on the Powder. Barnett three-mile at $65, as mentioned in our corporate presentation, is 45% IRR with a two-year payout, roughly 3.0x multiple on invested capital. 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 is 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 two, the inventory across the two counties. So in Converse, which is the best stuff, a 150% return, 10-month payout, 2.5x. The Campbell County Parkman is in the 45% to 50% range with 20-month payouts. At $75, those increase for Converse to over 200%, eight-month payouts, 3.0x, and in Campbell, increases to 80%, less than 18 months on the payout, and over 2.0x. The largest component of the inventory in the basin in the Powder is the Upper Nio.

We are at $65—that is in the 25% to 30% range, three-year payouts, and 2.0x. At $75, that increases to 40%–45%, two-year payout, and 2.5x. We have 46 net locations there in the Nio.

Anthony Perala: That is really helpful. Interesting, I guess. Between those you can see, but obviously, the Parkman stands out. I am curious—it is 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.

Jason P. Stabell: Yes, I mean, it is going to go highest and best use. Right now, kind of looking at the portfolio, Anthony, we think about it as about 50% of our investment over the next two years is going to be Powder-focused, and then the remainder split between Marcellus and Barnett. So I think, with pricing doing what they do, I do not see a huge change to that. As we mentioned on the call, we are excited about the new operator that we have in the Barnett oil play. It is 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. As Andrew quoted, the returns—you know, in a world $65-plus—those Barnett investments are quite attractive. I think we get more excited thinking about a three-mile lateral world in the Barnett. We had our first well drilled there that we are going to complete, as we mentioned, mid this year. I think it is all shaping up how we would have liked. We have got options. We have got our operated position that we can flex up and down depending on macro.

We have got a lot of inventory there, Parkman-focused certainly, but as I mentioned, we want to remind people we have also got this pretty deep Nio inventory, which is where most of the industry in the PRB is currently focused its capital.

Anthony Perala: So, yeah, it is kind of funny looking back on when you first took the role, the difference in just investment opportunities from primarily the Marcellus now to having a lot of different plays that compete for capital. On that Nio piece, which, as you lay out, it is probably 2028 before that really competes for capital given just the Parkman inventory. I am curious—like you had said—it seems like people are getting more active there, and it is being proved out more by larger scaled operators. I am curious what you are seeing and hearing from those that are really committing capital to the Nio and Mowry right now in the PRB.

Jason P. Stabell: Sure. I will start maybe with some general comments, and Henry can fill in anywhere that he sees fit. Yes, around us in Campbell and Converse, there are a number of rigs right now. The big operators—and I will just name a few—Devon, EOG, Continental, Oxy. They are really focusing their capital on the Nio. I think what you are seeing there is similar to what you are seeing in other basins. We are going from a two-mile lateral world to—the standard right now in the Nio, I think, for this year and forward—is three- to 3.5-mile laterals, which enhances economics quite a bit.

We even have an offset operator that we know is planning a four-mile lateral in the Nio, or a DSU of four-miler. So I think the economics there, as you start to extend laterals and batch drill wells, you are going to see that the Nio in the PRB is competing for capital in much larger portfolios of the companies I mentioned. We are encouraged by that. As we said, we are watching closely. I think our near-term focus is going to remain the Parkman probably over the next two 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 would be interested in.

I will stop there and let Henry add.

Henry Nelson Clanton: The only thing I could add to that is we have got 12 rigs running in Campbell, 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.

Anthony Perala: Great. Thanks, Henry. That is very helpful. Just one final one for me here. Just if you could add a little bit more color—you had mentioned you are in the market looking at selling an overriding royalty package on the Marcellus assets. Just if you could give some more color to that and just how best to think about that for potential proceeds.

Jason P. Stabell: Yes. I am not going to guide on proceeds, but it is a small amount of production. We are talking somewhere, I think, less than 1,000,000 cubic feet a day of production. It represents a pretty small overall piece of our production. It sits outside of our core Auburn area. These are some overrides we have picked up over the years due to acreage trades with some other area operators. There is pretty robust interest, as we understand it, for override mineral interests, so we are doing a market test to see. We believe, as Andrew mentioned, we are 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 is something of interest to us or not. So 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 after-tax impacts for us. That office building that came in the Peak deal—we thought it made sense to explore sale of that, and as Andrew said, that is $3,000,000 that we have got under contract. I expect that will close in the second quarter.

So as we have expanded the portfolio, we are trying to make sure that it is optimized as best as possible, and we are creating opportunities to reinvest in what we think are our best sources of inventory. Feel good about it.

Anthony Perala: That is great. Thanks for the color. I will hop back in the queue.

Operator: Thanks, Anthony. To withdraw your questions, you may press 2. It is showing no questions at this time. I would like to turn the conference call back over to Jason for any closing comments.

Jason P. Stabell: Nothing to add, Operator, other than to thank everybody for joining us today. As always, if people have additional questions, feel free to contact us here at the Houston office. Everybody have a good day. Thank you.

Operator: With that, ladies and gentlemen, we will conclude today's conference call and presentation. We thank you for joining. You may now disconnect your lines.

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