Good day, and welcome to the Epsilon Energy Full Year and Fourth Quarter 2024 Earning Conference Call. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. 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'd like to welcome all of you to today's conference call to review Epsilon's full year and fourth quarter 2024 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 might 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 2024 year end 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. I am pleased to report that in 2024, we achieved our main strategic objectives to continue to develop our Permian business, add a new project area with meaningful upside potential, and weather an oversupplied gas market. In the Permian, we added additional production and undeveloped acreage through a bolt-on acquisition in the first quarter. That deal, followed by an incremental investment in two gross wells during the year, led to our 180% year-on-year increase in oil production. The Permian contributed more than 60% to our cash flows in 2024. We also established a new project area in Alberta, Canada with the joint venture announced in October that we believe adds multi-year economic inventory for approximately a $7 million drilling carry. The operator has committed to five gross wells on the position before the end of the first quarter 2026. The project is underway with two wells now on flowback. In 2025, we will further delineate this position with two gross wells, 0.5 net, and expect to have four gross wells, one net on production in the Garrington area by year end. Finally, in the Marcellus, we survived a challenging natural gas market with sub $2 per Mcf net wellhead pricing, production curtailments estimated at 20% to 25% of our net total in the basin, and deferred turn in lines. The environment started to change in the fourth quarter of last year and we are off to a great start to 2025 in the basin. Andrew can elaborate further there. Today our business is more diversified with multiple avenues available for capital allocation and organic growth across the commodity mix. We remain committed to our fixed dividend while keeping an eye out for attractive opportunities to reduce our share count. I'll now turn it over to Andrew and then Henry to provide further details on our plans and activities, including an early comment on the strength of our first quarter 2025 performance.

Thanks, Jason. As mentioned, the tides have shifted in the Marcellus and we're off to a great start there in 2025. The remaining deferred wells came online in the second week of January. We now have essentially all of our previously curtailed production back online. To put some details to it, through the first two months of the quarter, our net revenue interest production in PA is approximately 30 million cubic feet a day, up 85% from our daily average during 2024. Over the same period, we realized over $3.90 per Mcf net to the wellhead, which is up 100% over the same two-month period last winter. That pricing came in above the index as we market our own gas and we were able to take advantage of a strong cash market during some of the winter weather we've experienced in the Northeast. The lifting of curtailments also benefits the gathering system, where our current throughput is up over 50% from the average in the third quarter of 2024. It's still early, but we expect 2025 upstream and midstream cash flows in the Marcellus to be up substantially year-over-year. We built the Permian business up over 2024, investing $24 million between the February acquisition and the two wells drilled in the second and third quarter. As I mentioned last quarter, we expect development to pick back up in Ector County in the second half of the year. We've talked about this several times before, but I'll reiterate that the runway there is significant with 14,000 gross undeveloped acres and up to 40 remaining two-mile barnett locations. Most of this is not included in our reserve report, as there are no producing wells in the southern, undeveloped portion of our leasehold. However, we have observed values for inventory leasehold in the immediate area, well above our entry costs, which speaks to the market's view of the potential. We have a multi-year runway here and look forward to participating in that development, and we'll make sure we are in position to do so. It's too early to speak to initial results in our recent JV in Alberta. Our partner is a reputable U.S. sponsor-backed operator, and we are excited about the runway and the 30,000 gross acre position in the Garrington area. We expect to have roughly $10 million of CapEx there this year, including our drilling carry in favor of the operator. Our expectation is to open a third major project area here for an attractive entry cost, with a $7 million drilling carry, which will be part of our capital allocation matrix going forward. Finally, we have over $50 million of liquidity, including our undrawn credit facility and strong free cash flows in our two primary project areas. That puts us in a strong position to continue to invest for growth, while also returning cash to our shareholders. Now to Henry.

Thanks, Jason and Andrew. I would like to add some comments on our year-end reserves. Against pricing headwinds, the company grew proved reserves approximately 20% year-over-year. In the Marcellus, updated development scheduling provided by the operator has added approximately 10 Bcf proved undeveloped reserves with drilling set to commence in 2026. We are also reporting that the Auburn Gas Gathering System operating pressure has been lowered to 450 psi from 550 psi. While there was no impact to the end of year reserves, the company will benefit from improved production and throughput in 2025 from wells gathered on that system as a result. We estimate a 15% uplift to Auburn production relative to production under the higher suction pressure. In the Permian, the company added 11.5 Bcf equivalent to our proved reserves. Additional interests were acquired in the Barnett play, which added both proved producing and undeveloped reserves. Additionally, seasoning of the existing production has supported higher recovery projections. The extensive development fairway in Barnett remains, as previously reported. Worthy to highlight, the potential for multi-well pad drilling and infrastructure build-out offers scaled economies expected to drive future development costs down significantly. Also, while current development identified is for two-mile laterals, recent industry participants are extending lateral lengths to three miles and beyond, indicating further economies have been targeted. As previously reported, we believe the Woodford potential remains worthy of appraisal. Coupled with core results on our currently held acreage position, recent analogous wells in the play are exhibiting good early life results. Regarding our recently announced JV in Canada, the activity to date was not included in the end-of-year reserves reporting due to timing. That aside, two horizontal glauconitic wells, 0.5 net, have been drilled and completed to date and flowback operations have commenced. Under the JV terms, at least three additional horizontal wells, 0.75 net, are scheduled to be developed over the next 12 months. Thank you. Now back to Jason.

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

We will now begin the question-and-answer session. The first question today comes from John White with ROTH Capital. Please go ahead.

Good morning, gentlemen, and congratulations on the nice year.

Thanks, John.

I think you covered this, but I missed it. In 2024, regarding Alberta, how many wells were drilled and completed?

Well, to remind you, we've got the small project we call Killam, which we drilled 2 gross wells, 1 net. We announced in the last quarter that we had one commercially successful well. These are small producers. Those wells cost about $700,000 per well. And we had one well that was commercially unsuccessful. And then following that, we signed up the much larger project in the Garrington area. And we've drilled and completed now two gross wells there and are on flowback on those two wells. We have a quarter interest in those two wells.

And how many wells in the larger area will be drilled in 2025?

Right now, with our initial discussions, we've got some planning meetings in April with the operator. But what we understand is, there'll likely be another two wells drilled in that larger area over the remainder of 2025. That likely is at earliest of summer. We're going to break up soon in that area in Canada. So most of the drilling operations start to slow down and come back to life in the early part of summer.

Yes, of course. Thanks for that additional detail, and I'll turn it back to the operator.

Thanks, John.

The next question comes from Anthony Perala with Punch & Associates. Please go ahead.

Hey, guys. Thanks for taking my question this morning.

Yes. Thank you.

Could you provide some insight into the discussions with the Marcellus operator, particularly regarding the expectations for 2026 that relate to the proved reserves mentioned by Henry?

Sure. Hey, you want to take that?

Yes, thank you for the question. We have clarity now from the operator on their multi-year plan, which includes 2026, 2027, and 2028. So that defined plan is what we have included in our reserve report and reflected as proved undeveloped.

There is no incremental activity expected in 2025 based on our current understanding from the operator, and drilling is set to resume in 2026. Is that correct?

Yes.

Okay. Excellent. That's great. It seems like a great improvement in the relationship there versus a couple of years ago. And then, could you have a sense of just how you feel about your hedge position for natural gas today, kind of what percentage roughly it is of expected 2025 production? And if you plan on being active on the hedge side, given the strength in the forward curve?

I'm sure you want to take that, Andrew.

Yes, thanks, Anthony. We're hedged through October of this year at roughly 30% of our gas production. That position is out of the money based on where the strip is now. So we haven't added to that position. I think we want to be aggressive in the winter months. We're contemplating putting on some more protection in the summer of next year, but we're fairly tactical about it. Now with no debt and a CapEx program that's well covered by cash flows, we're fairly tactical. So you could see us add something marginal in 2026, but right now our protection rolls off in October of this year.

That's great. It's nice to see the recent press release regarding the expanded share repurchase program. I'm curious if you've been active this year in terms of share repurchases.

We have not been active to date. We look at it as another option for us on the capital allocation framework. As you kind of look at how we've handled that in the past, Anthony, we've been pretty opportunistic. Last year we made two block purchases at what we thought were attractive prices for our shareholders, and we haven't done the same if an opportunity presented itself again.

That's great. That's it for me. I'll pass it back to the operator. Look forward to seeing the progress this year.

Thanks, Anthony.

There are no further questions at this time, which concludes our question-and-answer session. I would like to turn the conference back over to Jason Stabell for any closing remarks.

Thank you, operator. Yes, I want to thank everyone for joining us today and appreciate your interest and support in Epsilon. And as I always say, if you have any questions, please reach out to us here via phone or email. But have a nice day. Thank you.

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