Riley Permian (REPX) Q1 2026 earnings review
Production Surges, But Negative Gas Pricing Crushes Cash Margins
Riley Permian delivered strong volume growth in Q1 2026, with total production reaching 35.6 MBoe/d (up 45% YoY), fueled by the integration of its Silverback acquisition. However, the volume surge failed to translate to the bottom line. Severe Permian gas egress constraints drove natural gas and NGL realized prices deeply negative, effectively taxing the company's oil revenues. As a result, Adjusted EBITDAX actually declined 14% YoY to $61 million. A massive $127 million derivative loss pushed GAAP Net Income to a $70 million deficit. Despite these headwinds, REPX managed to generate $24 million in Free Cash Flow, reduced debt, and initiated a new share repurchase program. The story for 2026 hinges entirely on H2 infrastructure relief.
🐂 Bull Case
Despite margin compression, REPX generated $24M in Total Free Cash Flow, comfortably covering its $8M dividend, $4M in share buybacks, and an $8M debt reduction. The balance sheet remains healthy at 1.0x leverage.
Oil volumes held stable at 20.2 MBbls/d and are guided to accelerate to 22.0-23.0 MBbls/d for FY26. The company is front-loading CapEx in H1 to set up a massive production ramp in H2 once New Mexico constraints ease.
🐻 Bear Case
Realized natural gas (-$1.68/Mcf) and NGLs (-$6.22/Bbl) are severely negative. Rising gathering, processing, and transportation (GP&T) costs are eating directly into high-margin oil revenues.
The company grew total production by 45% YoY, but Adjusted EBITDAX fell 14%. Simply producing more barrels is destroying corporate return on capital until the midstream bottleneck is resolved.
⚖️ Verdict: ⚪
Neutral. Management is executing well on the things they can control (volumes, drilling costs, debt reduction). However, they are at the mercy of third-party midstream infrastructure. Until the Waha basis normalizes or the new Targa pipeline opens, earnings quality will remain impaired.
Key Themes
Negative Gas and NGL Realizations Bleeding Cash
The Permian takeaway constraint is acute. Realized gas prices before derivatives plummeted to -$1.68/Mcf, and NGLs fell to -$6.22/Bbl. Management noted that lower natural gas revenues forced a greater proportion of GP&T costs onto NGLs. This dynamic is directly responsible for the YoY decline in Adjusted EBITDAX and turns incremental gas/NGL production into a liability.
Front-Loaded CapEx Setup for H2 Acceleration
REPX is heavily back-loading its 2026 production growth. The company plans to spend $200-$220M in FY26 (up significantly from $120M in FY25), with over two-thirds of that budget deployed in H1. This will depress near-term cash flows, but positions the company for over 20% YoY oil volume growth by H2, assuming the New Mexico development pivot aligns with new pipeline capacity.
Dependency on Targa Pipeline Completion
Management's entire H2 2026 growth strategy hinges on shifting activity to New Mexico. Because New Mexico enforces strict zero-flaring regulations, this oil growth cannot happen unless the associated gas can flow. If the third-party Targa pipeline faces construction or regulatory delays past Q3, REPX will be forced to choke back its highest-return oil wells.
Consistent Return of Capital Framework
Despite a massive GAAP net loss, strong working capital management allowed REPX to return $12 million to shareholders in Q1 ($8M in dividends, $4M in share buybacks). The new $100M share repurchase authorization gives management a flexible tool to support the stock if egress constraints continue to weigh on the equity valuation.
Other KPIs
Reversing. Declined from $66.1M in 25Q4 and $71.1M in 25Q1, despite a 45% YoY increase in total equivalent volumes. This metric perfectly encapsulates the damage caused by negative regional gas pricing and highlights that the Silverback acquisition barrels are currently less profitable on a per-unit basis than legacy production.
Severely impacted by a $115 million non-cash unrealized mark-to-market loss on derivatives as benchmark prices fluctuated, alongside a $12 million realized loss on crude oil hedges. Adjusted Net Income, which strips out these non-cash swings, remained positive at $21 million.
Stable/Improving. Down from $8.34/Boe in Q1 2025. Management has successfully integrated the higher-cost Silverback vertical wells without blowing out the corporate cost structure, demonstrating strong field-level execution.
Guidance
Accelerating significantly from $120M in FY25. This sets up a highly capital-intensive year. H1 will be outspend-heavy, generating a lag between capital deployment and revenue realization in H2.
Accelerating. Implies ~30% YoY growth vs FY25's average of 17.3 MBbls/d. The Q2 2026 guidance (20.7-21.3 MBbls/d) shows that the bulk of this growth must materialize in the third and fourth quarters.
Stable. The midpoint (36.0 MBoe/d) implies essentially flat sequential growth compared to the 35.6 MBoe/d delivered in 26Q1, confirming the narrative that material growth is paused until H2 infrastructure arrives.
Key Questions
Targa Pipeline Contingencies
Given that the H2 volume ramp is heavily weighted toward New Mexico and entirely dependent on the new Targa pipeline, what are your immediate contingency plans for capital allocation and DUC inventory if the pipeline faces regulatory or construction delays?
NGL Processing Strategy
With realized NGL prices hitting -$6.22 per barrel due to cost allocation effects, at what point does it become economically necessary to alter or renegotiate processing agreements, or physically reject NGLs into the gas stream?
Capital Allocation: Buybacks vs Organic Growth
You repurchased $4 million in stock this quarter under the new authorization. Given the current severe negative operating leverage caused by Waha basis constraints, why deploy capital to drill new wells in H1 rather than aggressively utilizing the $100M buyback authorization while margins are temporarily impaired?