Riley Exploration Permian, Inc. 2026 Q2 Earnings Call

Welcome to our conference call covering our second quarter 2026 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO, and John Suter, COO. Yesterday, we published a variety of materials which can be found on our website under the Investors section. These materials and today's conference call contain certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website. I'll turn the call over to Bobby.

Thank you, Philip. Earlier this year, we outlined our strategy to accelerate development activity and production growth in 2026. We continued advancing that strategy during the second quarter. Our second quarter development program was the most active in Riley Permian's history. This heightened level of activity, together with production enhancement projects across both assets, helped us deliver oil production near the high end of our guidance range and a June oil production exit rate of 24.4 thousand barrels per day. While the quarter showed 5% sequential oil growth on average, we view the June exit rate as a better representation of the underlying momentum in the business and the foundation for the growth we expect during the second half of the year and into 2027.

Importantly, a significant portion of the operational activity completed during the first half of the year has yet to be fully reflected in production. As a result, based upon our current outlook, we are increasing our full year oil production guidance, which now calls for approximately 30% year-over-year oil production growth. We forecast our largest increase of the year during the third quarter, when we expect oil production to increase more than 20% sequentially. Our strong second quarter results were achieved despite midstream constraints during April and May that required temporary well shut-ins and reduced oil production by approximately 2,000 barrels per day. The disruption reinforces the strategic importance of the new high-pressure gathering and trunk line system being constructed by Targa, which is expected to enter service during the fourth quarter. While these disruptions limited the quarter's full potential, our underlying growth plan remains on track.

The production growth we expect over the coming quarters reflects both the activity executed during the first half of the year and the development activity still ahead of us. As we bring those volumes online, we expect higher production to support stronger cash flows, generation, and improved returns on the capital we've invested. At the same time, continued infrastructure development in New Mexico is expanding our opportunity set and helping unlock a larger portion of our inventory for future development. We are encouraged by the progress made during the first half of the year and remain focused on safely and efficiently converting that activity into production growth during the balance of 2026 and throughout 2027. I'll now turn the call over to John Suter.

Thank you, Bobby, and good morning. I'll cover our operational results for the second quarter, the progress we are seeing across both of our core development areas, and how we are positioning the business for the second half of 2026 and beyond. As always, I'll start with safety, because safe and reliable execution remains the foundation of everything we do. During the second quarter, operations reported a zero total recordable incident rate, and we delivered 98% safe days. That is a strong result in any environment, but especially important given the level of activity our teams managed during the quarter. Development activity increased during the second quarter and was primarily focused in Texas. On a net basis, we drilled 19.9 wells, completed 17.3 wells, and turned 13.9 wells to sales. Total capital spend on an accrual basis was $87 million for the second quarter.

Drilling and completion capital expenditures were $70 million, which was in line with the midpoint of guidance. Infrastructure and other expenditures were approximately $17 million compared to the guidance midpoint of $12.5 million. The variance in infrastructure and other capital expenditures can primarily be attributed to accelerated development and bringing forward costs that would otherwise have been realized in the second half of 2026 or later. Turn-in-lines came in below guidance for the quarter, primarily due to delays in third-party infrastructure needed to support the higher development pace in Texas. Those projects were related to gas, oil, and water takeaway and were a driver of the higher capital spend. The production impact in the second quarter was minimal because these wells were scheduled to come online later in the quarter. They've all since been turned in line, and we expect to see the production contribution again in the third quarter.

From an execution standpoint, the quarter was very strong. In Texas, the drilling team delivered 12 gross wells, plus one SWD, improved average lateral footage per day by 19%, and reduced drilling costs per lateral foot by 7.5% compared to 2025. We also set new Yoakum County records for both one mile and one and a half mile wells. These were not isolated well results. They reflect broader improvement in planning, pad execution, bit and BHA selection, directional performance, and day-to-day coordination across the drilling organization. New Mexico Drilling also made a meaningful step forward after deferring development activity in 2025 while waiting on infrastructure build-outs. Compared with the 2023 and 2024 combined campaigns, we increased average lateral feet per day by 67% and reduced average drilling costs per lateral foot by 32%.

We also successfully executed the first mile and a half lateral in Red Lake, which is an important milestone for the asset. The combination of faster drilling, lower cost per lateral foot, and more complex well designs reflects the operational knowledge we've built over time and gives us confidence in the repeatability of future development. Another important point is that we have continued to mitigate operating cost pressures through disciplined execution, even as several major input costs have moved against us. Total LOE increased $5.4 million quarter-over-quarter, with approximately $1.9 million coming from recurring LOE and $3.5 million from workover expense. That increase came during a period when we were also absorbing pressure from higher water disposal needs, steel and tubular costs, diesel, power, and service activity. Importantly, though, a meaningful portion of the workover spend was intentional and value creating.

Approximately $2.3 million of WOE was associated with production maintenance and optimization projects that added roughly 700 barrels of oil per day of incremental production. We view that as one of the lowest cost sources of production growth available to us. While operating costs were up quarter-over-quarter, a large portion of that increase was tied directly to projects that improved production, enhanced runtime, and created strong returns. At the same time, the team continued to offset broader cost pressure through field level efficiency gains, vendor optimization, chemical program improvements, and lower cost workover execution. There are a few specific examples worth highlighting. In Texas, we successfully trialed 10 surface acid and chemical treatments to avoid costly downhole interventions. Those treatments saved approximately $210,000 per intervention, which represents roughly a 75% reduction compared with the alternative downhole work.

We plan to expand this program more broadly, considering the promising results. With a conservative estimate of 40 of those treatments per year, that could correspond to $8.4 million in annual savings. In New Mexico, changes to the chemical program implemented in January are already showing an approximate 50% reduction in chemical costs. Better chemical surveillance and improved ESP runtimes are also helping reduce workover expenses. On the topic of Silverback, that acquisition has become a strong case study in the type of value we believe Riley can create inside our existing operating footprint. Since closing, we've created value in two primary ways: lowering the cost structure and increasing production. With Silverback properties, monthly per well workover costs have decreased by approximately 59%, driven primarily by fewer short runs and improved chemical program surveillance. On the production side, Silverback has materially outperformed expectations.

Through strategic workovers, return to production work, well bore cleanouts, artificial lift optimization, and conversion activity, production is now approximately double where the buy side case projected it would be at this point, and that's been achieved with no new wells drilled. Despite the midstream related shut-ins Bobby referenced, the underlying operating trend in the second quarter was much stronger than the quarterly average alone would suggest. Volumes were pressured early in the quarter, but as shut-in production returned, new wells came online and workovers contributed across both Texas and New Mexico, production improved materially in quarter end. The broader takeaway from the quarter is that both our Texas and New Mexico assets improved across the areas that matter most operationally: safety, efficiency, cost, and technical execution.

In Texas, we continue to benefit from a more overall mature infrastructure footprint and very high working interests, which allows us to move quickly and efficiently. In New Mexico, we're continuing to prove that the asset can be developed with improving costs and cycle times while we also work through the infrastructure sequencing required to unlock the full value of the acreage. Looking ahead to the third quarter and the remainder of the year, our development sequencing is being influenced by the timing of the Targa Pipeline. We are excited that the construction of the line is well underway. They've successfully completed a key river crossing and now are trenching, stringing pipe, and welding the remainder of the line. The latest forecast projects the new Targa Pipeline to be in service early in the fourth quarter of 2026.

The four-year activity schedule has been updated to reflect that timing by shifting some drilling and completion activity from Texas to New Mexico. Operationally, the way we are managing that timing is straightforward. We do not want to complete New Mexico wells too early and strand capital while waiting on gas takeaway. Instead, we are aligning completions with the expected pipeline in-service date and using the flexibility of the program to manage timing. This is also why Texas remains important to the 2026 plan. Texas infrastructure is more mature today, and those wells can generally be brought online sooner. We've also been preparing for a more unconstrained development model in New Mexico in ways that go beyond gas takeaway. Water handling is a key part of that equation.