Riley Permian (REPX) Q2 2026 earnings review
Top-Line Surge Masks Free Cash Flow Squeeze and Infrastructure Headwinds
Riley Permian delivered record revenue in Q2, fueled by strong $94/bbl unhedged oil prices and increased Texas production. However, beneath the impressive GAAP Net Income figure—which was heavily inflated by non-cash derivative gains—lies a more complex operational reality. Severe third-party midstream outages in New Mexico choked roughly 1.9 MBbls/d of oil production, while Permian gas bottlenecks drove realized natural gas prices deeply negative. Management responded by accelerating workovers and capital expenditures to maintain volume momentum. Looking ahead, Q3 guidance projects an aggressive 20% sequential spike in oil output, signaling management's commitment to growth, though this comes at the expense of near-term free cash flow, which plummeted to just $6 million this quarter.
🐂 Bull Case
Unhedged oil realizations hit $94.28 per barrel, allowing the company to generate $166M in revenue, almost doubling YoY. If macroeconomic conditions sustain these price levels, operating cash flow will easily fund the aggressive Q3 production ramp.
Management is projecting Q3 oil production of 25.1 to 26.1 MBbls/d. This implies ~20% sequential growth and nearly 40% YoY growth, demonstrating that the operational machinery can scale rapidly once constraints are cleared.
🐻 Bear Case
Despite top-line strength, Total Free Cash Flow compressed to just $6 million. The company is spending heavily ($87 million in accrual capex) to chase growth, leaving little excess cash for aggressive shareholder returns or debt paydown.
Realized natural gas and NGL prices were severely negative, effectively acting as a tax on oil production. Coupled with third-party processing outages in New Mexico, external infrastructure remains the company's largest unmitigated risk.
⚖️ Verdict: ⚪
Neutral. The production growth trajectory is undeniably accelerating and the asset base is performing, but the severe external infrastructure constraints and deteriorating free cash flow conversion warrant near-term caution.
Key Themes
Midstream Outages Throttle New Mexico Growth
A major third-party gas processing outage in April and May forced temporary well shut-ins, reducing Q2 oil production by an estimated 1.9 MBbls/d. This operational bottleneck validates earlier concerns about New Mexico infrastructure fragility and forced total equivalent production to decline sequentially to 34.3 MBoe/d.
Negative Gas and NGL Pricing Continues
The Waha basis blowout continues to severely penalize the company. Realized natural gas prices fell to a staggering $(4.12) per Mcf, and NGL prices dropped to $(4.71) per Bbl. The company is literally paying to transport and sell its associated gas, which acts as a direct drag on operating margins despite high oil prices.
Aggressive Workovers and Texas Drilling Save the Quarter
To offset the 1.9 MBbls/d loss in New Mexico, management rapidly deployed capital toward workovers and accelerated drilling in Texas. The company completed 18 gross wells in Texas during Q2. This agility allowed overall corporate oil production to still grow sequentially by 5% to 21.2 MBbls/d, showcasing the strategic value of maintaining dual-basin optionality.
Targa Pipeline Catalyst Delayed
A subtle but critical shift occurred in the narrative: the Targa Northern Delaware pipeline, previously guided in Q1 to be online by Q3 2026, is now 'currently expected to occur in the fourth quarter of 2026.' This delay risks pushing the turn-in-line cadence of New Mexico DUCs further into the future, potentially impacting Q4 volume targets and earn-out timing.
RPC Power Joint Venture Investment
The company continued to invest in its RPC Power joint venture, allocating $3 million in Q2. This specific infrastructure innovation (behind-the-meter power generation) is vital for bypassing unreliable local grids and avoiding negative gas sales by consuming stranded gas on-site to generate electricity.
Reversing Free Cash Flow Story
Despite generating $87 million in GAAP Net Income, Total Free Cash Flow collapsed to $6 million (down from $23.5 million in Q1). The robust Net Income was propped up by a $69 million non-cash derivative gain. High accrual capital expenditures ($87 million) are vastly outpacing operating cash flow generation before working capital ($75 million), illustrating that aggressive growth is currently outstripping cash conversion.
Other KPIs
Accelerating from $60.9 million in Q1, driven predominantly by a 37% QoQ increase in unhedged realized oil prices (from $68.89 to $94.28 per barrel). This solid operating metric strips out the noise of the $69 million mark-to-market derivative gain that distorted net income.
Reversing the recent trend of cost improvements, LOE spiked to $9.44 per Boe, up from $7.51 in Q1. The company attributes this to $11 million in elevated workover expenses executed to capitalize on high oil prices and substitute for structurally shut-in New Mexico volumes.
Stable. The company increased debt by $26 million during the quarter (drawing $31M on the credit facility while paying down $5M in Senior Notes) to fund the capex shortfall. Total principal debt now sits at $273 million, but the trailing EBITDAX growth kept the leverage ratio perfectly flat at 1.0x.
Guidance
Accelerating aggressively. The midpoint of 25.6 MBbls/d represents a massive 20.7% sequential jump from Q2's 21.2 MBbls/d. Management notes this will be the largest production increase of the year, driven by bringing delayed wells online.
Accelerating. Implies roughly 19.5% sequential growth from Q2's 34.3 MBoe/d, aligning with the return of midstream processing capacity and higher activity levels.
Accelerating. Management raised full-year capex guidance to reflect higher activity levels, higher forecasted oil production, and the heavy rate of workovers deployed in Q2 to maintain volume momentum.
Accelerating. Includes infrastructure and other investments. With $133 million in accrual capex already spent in H1, the back half of the year will require approximately $103 million, indicating a slightly decelerating pace of capital spend in H2 compared to H1, which should theoretically aid free cash flow generation in Q4.
Key Questions
Targa Pipeline Delay Impact
The in-service date for the Targa pipeline in New Mexico shifted from Q3 to Q4. Does this delay directly risk the completion and turn-in-line cadence of the 20+ DUCs waiting in the basin, and does it jeopardize the timing of the $30 million midstream earn-out?
Tolerance for Negative Gas Pricing
With realized natural gas and NGL prices deep in negative territory, how long can Riley Permian stomach paying to flow associated gas before it structurally alters basin-level capital allocation away from the Permian?
Free Cash Flow Inflection
Total Free Cash Flow compressed to $6 million in Q2. Given the Q3 guidance for a 20% sequential production ramp, will the necessary working capital and completion costs drive Q3 FCF negative, or will the volume uplift immediately cover the cash burn?