Good afternoon, and welcome to the Epsilon Energy Third Quarter 2024 Earnings Conference Call. All participants will be in a listen-only mode. 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 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 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, and thank you for participating in our third quarter 2024 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. In the Permian, we brought the seventh Ector well online in the third quarter, driving 19% quarter-over-quarter oil production growth. In the fourth quarter, we will see some quarter-over-quarter declines in liquids production until drilling resumes next year. Henry will discuss specific well performance later in the call. In Pennsylvania, wellhead prices have remained low heading into winter. In October, we have seen a small portion of our curtailed volumes come back online and three of the seven previously announced deferred TILs were put on production last week. So, we expect quarter-over-quarter growth in natural gas volumes in the fourth quarter with a further ramp expected into the first quarter of next year as curtailments are lifted and the remaining deferred TIL wells are brought on. Currently, we do not forecast incremental drilling in Pennsylvania in 2025, but we will keep you updated after discussions with our operator in the fourth quarter. Late last month, we announced our entry into Alberta, Canada through two joint ventures with Calgary-based private operators. In the larger deal, after approximately a $7.5 million development carry is satisfied, we will earn 25% in approximately 160,000 acres. Our initial development focus will be the Garrington area, approximately 30,000 gross acres in the liquids-rich Glauconitic and Ellerslie intervals. Initial plans call for four gross wells in 2025, with operations likely to commence in the fourth quarter of this year. Andrew can provide further details on the projected capital expenditures. Overall, the Company remains well positioned to deliver volume and cash flow growth in 2025. We continue to evaluate opportunities and see the potential for additional investments, particularly in Canada. Meanwhile, we will continue to pay our dividend and monitor opportunities to reduce our share count at attractive prices. Now I would like to turn the call over to Andrew for additional comments.

Thanks, Jason. This quarter was the trough for our Pennsylvania business, both on the midstream and upstream side. Production curtailments continued through the quarter and realized prices were $1.54 per Mcf. We were also impacted by plugging and abandonment activities in the Auburn area, increasing Pennsylvania operating costs by approximately 40% for the quarter. The lifting of curtailments, volumes from the deferred wells that were developed in the first quarter starting to come back on at peak rates and better pricing will start to bring us back from here. As Jason mentioned, the Permian has picked up some of the slack, contributing approximately $8.5 million of adjusted EBITDA year-to-date, which is 70% of the total company figure. On a project level, we've invested approximately $40 million starting in Q2 of 2023, with 20% of that in currently undeveloped leasehold. We received cash flows of approximately $12 million back through the end of the third quarter, with two gross and 0.5 net of the nine gross and two net producing wells coming on in the last four months. We are still not clear on investment activity details for Texas next year as the previously mentioned strategic alternatives review process for the operated interest plays out over the rest of the year. However, we do expect to be active there in 2025 and resume growth. As Jason mentioned, drilling activity is scheduled to start later this quarter in Alberta on our Garrington joint venture position. We expect to have approximately $10 million of capital expenditures there in the 12-month period from this December. We are excited about this deal with our ability to earn into a large acreage position that is underwritten to hold over 25 highly economic locations in the Garrington area in partnership with a premier private operator in the basin. Relative to other opportunities we've seen, Canada stands out due to the cost structure, royalty regime, and large opportunity set of liquids-focused development. Also, as mentioned in the announcement of the joint venture, there are some corporate advantages to us conducting business north of the border. We have added incrementally to our hedge book for 2025, locking in prices above the current strip. We will continue to add opportunistically there if we see the opportunity to do so. On liquidity, our available revolver capacity currently stands at $45 million, leading us well positioned to move on other opportunities while maintaining a strong balance sheet. Now I will turn it over to Henry for operations.

Thank you, Jason and Andrew. I'll begin with comments on our Permian Basin, Mississippian Barnett project. We previously reported the seventh well in the project began production in July. The early life productivity is consistent with the initial six wells and continues to perform well. We'd like to highlight that this well is the southernmost drilled in the project to date. It is providing confirmatory evidence of the prospectivity of the interval on the large acreage development position south of most of the existing production. As Andrew mentioned, a strategic alternatives review process for the operated interest continues. Accordingly, we do not anticipate any additional development to occur while the process is underway, and we'll provide updates on the development plans moving forward as they become available. Moving to Canada and our recently announced Garrington joint venture, we have begun the development planning phase with the operator and will identify the location and targeted intervals of the first group of wells to be drilled. Currently, four 2-mile horizontal wells are anticipated over the next 12 months beginning in December. We will provide updates as well proposals are finalized, including capital expenditures, target interval, and timing. Under the smaller joint venture formed in Alberta in April of this year, the Company participated in two multi-leg horizontal wells, one net in the Lower Mannville formation in two separate oil pools in the Killam area. Results to date have been mixed, and technical reviews of well performance are ongoing. Net drilling and completion costs incurred for the two wells are approximately $1.7 million. No additional capital investment is required. In Northeast Pennsylvania, as Jason mentioned, last week, the operator commenced initial flowback on three, 0.4 net deferred TIL wells, the Clapper pad. We expect these wells to add meaningfully to our net production in the basin, currently producing approximately 8 million a day net. Now back to Jason.

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

Our first question today is from John White with ROTH Capital.

And congratulations on a nice quarter. You said in the press release, three of the seven wells were put on flowback during the last week of October, producing 60 million a day. What is the net production from that?

That's the 8 million a day that I reported in the call. We have a little over 13% net revenue interest in that pad, so it equates to about 8 million a day.

That's great. During the quarter, you had 3 million to 4 million a day offline. In the third quarter, the negative natural gas differential was $0.65, while your realized gas price was $1.46. Looking at the fourth quarter, if we consider Henry Hub at $2.75 with a negative differential of $0.91, the realized gas price would be $1.84, which is a nice increase. Do you think that will encourage the 3 million to 4 million a day to come back online?

John, yes, I think from what we understand from the operator, they're going to be bringing back those curtailed volumes as price dictated. As you mentioned, the forward curve would suggest those volumes come on. We don't have clear visibility. Actually, if we look at it day to day, they're still turning some wells on and off. But the way that we think about it is that will clear out by the beginning of the first quarter. So we're still not entirely clear on the schedule for those curtailed volumes to come back. But we do see some of them already coming back as we've indicated.

Well, that's helpful. And congratulations on West Texas results.

Showing no further questions, this 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. I want to thank everyone for their interest in Epsilon and for joining us today. And as always, if you have additional questions or comments, feel free to contact us here at the Houston office. Have a great day. Thank you.

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