Riley Exploration Permian Q2 2026 Earnings Call: Complete Transcript

On Thursday, Riley Exploration Permian (AMEX: REPX ) discussed second-quarter financial results during its earnings call. The full transcript is provided below. This transcript is brought to you APIs. For real-time access to our entire catalog, please visit for a consultation.

The full earnings call is available at Summary Riley Exploration Permian Inc. 4 thousand barrels per day, and increased full-year oil production guidance, projecting a 30% year-over-year growth. The company faced midstream constraints causing temporary well shut-ins, but expects future growth supported by new infrastructure, including a high-pressure gathering system by Targa. Capital expenditures were $87 million for Q2, with drilling and completion costs at $70 million.

Infrastructure expenditures exceeded guidance due to accelerated development. Operational highlights include improved drilling performance in Texas and New Mexico, with significant cost reductions and efficiency gains in well operations and chemical programs. The company increased its full-year capital expenditure guidance by 12% to $236 million and expects higher free cash flow in the second half of the year. Riley Exploration Permian Inc.

reported a 35% increase in operating cash flow to $64 million, while free cash flow decreased to $6 million for Q2. Management emphasized a focus on safety, capital efficiency, and strategic flexibility to manage development timing and infrastructure constraints. Full Transcript OPERATOR Good day everyone and welcome to the Riley Exploration Permian Inc. Second Quarter 2026 Earnings Call.

This call is being recorded at this time. I would like to hand the call over to Mr. Philip Riley, CFO. Please go ahead, sir.

Philip Riley, Chief Financial Officer and EVP of Strategy Good morning. 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.

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. Bobby Riley, Chief Executive Officer and Chairman Thank you, Philip. Earlier this year we outlined our strategy to accelerate development activity and production growth in 2026, and we continued advancing that strategy during the second quarter.

Our second quarter development program was the most active in Riley Exploration Permian's history. 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 activities still ahead of us. As we bring those volumes online, we expect higher production to support stronger cash flow 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. John Suter, Chief Operations Officer 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 2H26 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. 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.

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 begin in the third quarter. From an execution standpoint, the quarter was very strong in Texas. 5% compared to 2025.

5-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 buildouts.

Compared with the 2023 and 2024 combined campaigns, we increased average lateral feet per day by 67% and reduced average drilling cost per lateral foot by 32%. 5-mile 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.

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. 3 million of workover 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.

So 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 dollars 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. 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 we 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, wellbore 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 into quarter-end. The broader takeaway from the quarter is that both our Texas and New Mexico assets improved across the areas that matter most: safety, efficiency, cost and technical execution. In Texas, we continue to benefit from a more overall mature infrastructure footprint and very high working interest, 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 full-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.

Our third-party disposal agreement with WaterBridge begins supporting the Red Lake development plan this year with the initial commitment period beginning in September. That solution does come at a higher per-barrel cost than our own disposal system. So we do expect it to create some upward pressure on LOE over time. But the trade-off is very clear.

Additional water takeaway gives us the capacity and flexibility to bring wells online at the pace our development plan requires. With it we can accelerate development, improve cycle times and convert more of the Red Lake inventory into production and cash flow sooner. In that context, we view the incremental disposal cost as a good trade for the development flexibility and long-term value it helps unlock. Putting it all together the operational message for the quarter is positive.

We executed safely. We improved drilling performance in both Champions and Red Lake. In a highly active quarter, we continue to build the necessary infrastructure to support our asset development plans in Texas and New Mexico. Our production growth plan is on track as we move through Q3 and into Q4.

We will remain disciplined. We will continue to prioritize safe operations, capital efficiency and timing wells to infrastructure. Champions gives us near-term flexibility and production visibility while Red Lake gives us an expanded growth platform as the Targa line, WaterBridge solution, saltwater disposal capacity and supporting field infrastructure come together. That combination positions us well for the remainder of 2026 and provides a stronger foundation for 2027 and beyond.

I'll now turn the call to Philip. Philip Riley, Chief Financial Officer and EVP of Strategy Thank you, John. I'll cover a few financial metrics very briefly before turning to our revised outlook. High oil prices drove operating cash flow 35% higher quarter over quarter to $64 million.

Cash capex and other investments increased 153% quarter over quarter to $73 million. Free cash flow, which is calculated before changes in working capital and before acquisitions, decreased to $6 million this quarter. Year to date, free cash flow is approximately $30 million. 0 net undeveloped locations for an average cost of $600,000 per location.

5 million of cash for dividends and buybacks. Quarter-end principal debt balance increased by 11%, or $26 million, to $273 million as we drew on our credit facility to fund our cash uses this quarter. Please see our published materials for a wider discussion of results. Now quickly on our power joint venture: Our first 10-megawatt merchant generation site was placed into commercial service midway through the second quarter, and we began selling into ERCOT's day-ahead and real-time markets.

The second site is finalizing commissioning, currently selling into real-time markets, while a third site is beginning commissioning. This project is very small scale relative to our core business, but we acknowledge the investor interest in the joint venture. Also, summer power prices are at multi-year lows following a surge in solar supply. Large-load interconnections are stuck in the queue, but the long-term thesis remains an interesting option to monetize undervalued Permian gas.

Now a few comments on forward guidance. We plan for a reduction in development activity and accrual capex in the third quarter of 2026 compared to the second quarter, and we're guiding to $59 million of accrual capex. However, consider that second-quarter cash capex was $18 million, or 20%—21% lower than accrual capex, so that cash dynamic could certainly flip in the third quarter as invoices roll in. 6 thousand barrels per day, 5% above June's level and more than 20% above the full second-quarter level.

For full-year capex, we're increasing guidance at the midpoint by 12%, or $26 million, to $236 million. Roughly a third of the increase is associated with upstream activity and two-thirds relates to infrastructure. The upstream increase is primarily driven by increased drilling, partially offset by fewer completions. 2, implying we're carrying drilled but uncompleted wells into next year.

Regarding the increase in infrastructure capital, 60% is associated with saltwater disposal projects, with most of the balance related to oil gathering projects. Both of these are associated with our Champions project in Texas.