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DATE

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

CALL PARTICIPANTS

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

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TAKEAWAYS

• Adjusted earnings per share -- $0.29 for the quarter, with noncash hedge losses driving a material impact on reported earnings.
• Capital Expenditures (CapEx) -- Just under $5 million spent in the quarter, mainly on the 3-mile Barnett well and preparatory work for Parkman drilling.
• Debt Reduction -- $10 million paid down since acquisition closing, with a current outstanding balance of $40.5 million.
• Noncore Asset Sale -- Overriding royalty interest package in Pennsylvania sold for $3.9 million, representing roughly 6x projected next 12 months cash flow and 1.5% of upstream revenue over the last four quarters.
• Pending Asset Sale -- Office building acquired from Peak under contract for $3 million, with closing expected within 30 days.
• Powder River Basin CapEx -- $6.8 million net CapEx allocated to complete two Niobrara wells, targeting a combined peak rate of 475 barrels of oil equivalent (BOE) per day in July.
• Upcoming Parkman Development -- Three-well program in Campbell County planned, with $23 million gross CapEx based on current 95% working interest; management may sell down 20%-30% of this interest to manage capital risk.
• Forecasted Parkman Peak Rate -- If a 33% working interest sell-down occurs, forecasted initial production is 1,060 BOE per day; maintaining full interest would lift initial production estimate to 1,600 BOE per day.
• Permian Basin Operations -- The first 3-plus mile Barnett well will come online in the second quarter, projected initial net production of 226 BOE per day, with two offsetting 3-mile laterals planned for later in the year.
• Marcellus Development -- Five-well program drilled (0.4 net), with first production expected in December at an initial 6.5 million cubic feet per day; $3.8 million of CapEx preapproved with drilling costs below authorization for expenditure (AFE).
• Operating Cost Outlook -- CFO Williamson said, "unit operating costs and G&A to trend down over the remainder of the year," driven by higher incremental volumes and post-acquisition integration cost roll-off.
• Production Optimization Initiatives -- Compressor downsizing and conversion of gas-lift wells to rod pump anticipated to lower monthly operating costs by roughly 35% and increase daily production rates greater than 10% per well.
• 2027 Infrastructure Planning -- CapEx of $3.5 million approved for multi-well water supply facility in Converse County, designed for a planned six-well Parkman development next year.
• Potential for Accelerated Growth -- CEO Stabell said, "there could be some opportunities either for us to do drill-to-earn deals and/or partner with some other operators," which could enhance upside to the base CapEx plan.

SUMMARY

Management reported disciplined execution of the development plan, allocating capital toward oil-weighted growth initiatives across multiple basins. Significant proceeds from noncore asset monetization supported ongoing debt reduction and funded new activity without altering leverage targets. Operational updates detailed multi-phase projects in the Powder River, Permian, and Marcellus, each with specific initial production forecasts and timing markers. Strategic discussion highlighted flexibility to adjust working interests in capital-intensive projects and openness to future joint development agreements. Management explicitly expects scaled production volume to drive down per-unit operating costs, particularly after major pads come online in the fourth quarter.

• Operating cost reductions from production optimization projects are expected to begin impacting results next month, as highlighted by specific initiatives involving compressor and rod pump conversions.
• The Marcellus Auburn system throughput is set to increase by approximately 86 million cubic feet per day when four new wells are brought online, directly impacting midstream segment performance.
• Management confirmed rig availability for upcoming Parkman drilling, though noted service costs are increasing as activity in the basin rises.

INDUSTRY GLOSSARY

• DUC (Drilled but Uncompleted): Wells that have been drilled but have not yet undergone completion operations to begin production.
• AFE (Authorization for Expenditure): A formal budget estimate prepared and approved before incurring capital expenses on projects such as well drilling or completion.
• BOE (Barrels of Oil Equivalent): A unit of energy based on the approximate energy released by burning one barrel of crude oil, used to aggregate oil, natural gas, and NGL volumes on a consistent basis.

Full Conference Call Transcript

Jason Stabell: 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.

J. Williamson: 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.

Henry Clanton: 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-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.

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

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

Anthony Perala: 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?

Jason Stabell: 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.

Henry Clanton: 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.

Jason Stabell: 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.

Anthony Perala: 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?

Jason Stabell: Henry, do you want to?

Henry Clanton: 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.

Jason Stabell: 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.

Anthony Perala: 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?

Jason Stabell: 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.

Anthony Perala: 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?

J. Williamson: 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.

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

Jeffrey Robertson: 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?

Henry Clanton: 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.

Jeffrey Robertson: 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.

Jason Stabell: 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.

Operator: 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.

Jason Stabell: 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.

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