Riley Permian (REPX) Q3 2026 earnings review
Riley Permian cash flow jumps, but its drilling bill climbs
Riley Permian, a Texas and New Mexico oil and gas producer, saw its cash flow rebound as local gas prices turned positive and shut-in wells returned. Oil output grew 38% from a year ago and free cash flow reached $42 million, allowing chief executive Bobby Riley to cut debt and retire the company's 10.5% senior notes in October. However, the fourth-quarter outlook calls for $80 million of capital spending at the middle of the range, well above what the prior full-year plan pointed to.
| Daily oil production | 25.4 MBbls/d +38% from a year ago (first like-for-like quarter after Silverback) |
|---|---|
| Total Free Cash Flow | $42.4M $6.3M last quarter and $25.3M a year ago |
| Principal debt | $245M -10% from last quarter; 10.5% notes paid off in October |
| Q4 accrual capital spending plan | $74–$86M pushes implied full-year spending to ~$267M by our math |
⚖️ Verdict: 🟢 Bullish
The story got better because the New Mexico gas and water pipelines opened on schedule at the start of October and the 2028 debt refinancing risk is gone. One caution: the company missed its third-quarter well hookup plan and raised its implied full-year capital budget for a third time to about $267 million, by our math, while oil hedges still took $12 per barrel off its realized price.
The question now is whether the $80 million fourth-quarter spending surge turns the 14.7 uncompleted New Mexico wells into high-margin oil sales or just extends a year of rising capital bills. If the new Targa pipeline clears the backlog cleanly, oil growth will outpace spending in 2027; if hookups lag again, the extra capital earns hedged returns. Fourth-quarter New Mexico well hookups and the 2027 capital budget will settle it.
🐂 Bull Case
New Mexico Pipes Open and Refinancing Clears 2028 Debt
Riley Permian operates oil and gas wells in Texas and New Mexico, where limited pipeline space has repeatedly forced it to shut in wells and delay completions. Those delays also threatened a volume-based cash payout from Targa Northern Delaware LLC, which bought the company's pipeline subsidiary last December. Meanwhile, $130 million of 10.5% senior notes carried a 2028 maturity date.
Both hurdles cleared in early October. Targa placed its new New Mexico gas gathering and trunkline system in service on October 1 to "mitigate processing and takeaway constraints", two weeks after Waterbridge Stateline LLC started up a 15-year produced-water disposal system. Four days later, the oil producer paid off all $130 million of its 10.5% senior notes using an expanded $450 million credit line.
This matters because the credit agreement now runs until October 2030, cuts required oil hedging from 24 months to 18 months, and lowers interest costs. With the pipes open, the fourth-quarter outlook calls for 14 to 18 net wells turned to sales, up from 11.9 in the third quarter.
What to watch: New Mexico net wells turned to sales in the fourth-quarter report. Turning a large share of the state's 14.7 drilled-but-uncompleted net wells to sales would prove the new pipes can handle the backlog.
Gas Price Recovery and Volume Lift Free Cash Flow
For four straight quarters, pipeline bottlenecks in the Permian Basin forced Riley Permian to pay buyers to take its natural gas and natural gas liquids (NGLs), which are ethane and propane separated from gas. In the second quarter, gas prices after transport costs hit negative $4.12 per thousand cubic feet (Mcf). At the same time, second-quarter volumes suffered from third-party plant outages in New Mexico.
In the third quarter, gas and NGL prices turned positive, creating a $22 million revenue rebound from the prior quarter. Oil volumes also climbed 38% from a year ago on the first comparison that fully includes the July 2025 Silverback acquisition in both periods.
- Total Free Cash Flow (cash from operations minus cash capital spending): $42.4 million, up from $6.3 million last quarter
- Realized natural gas price before hedges: positive $0.27 per Mcf, versus negative $4.12 in the second quarter
- Realized NGL price: positive $5.08 per barrel, versus negative $4.71 in the second quarter
- Texas oil production: 18.5 thousand barrels per day, up 76% from a year ago
Because cash flow jumped, a single quarter of third-quarter free cash flow beat the $29.8 million generated across the entire first half of 2026. The company used that cash to cut debt by $28 million and raise its quarterly dividend 5% to $0.42 per share.
What to watch: fourth-quarter realized gas prices before hedges. A drop back below zero would show that regional Permian pipeline bottlenecks still outweigh the new local Targa connection.
Operating Margin Climbed 26 Points on Lower Unit Costs
In the second quarter, lease operating expenses—the day-to-day cost of running wells and repairing equipment—rose to $9.44 per barrel of oil equivalent (Boe), which combines oil, gas, and NGLs into one volume measure. That figure missed the company's own cost target because it spent $11 million on well maintenance, known as workovers, while New Mexico pipes were shut down.
The oil producer spent another $11 million on workovers in the third quarter, but higher production and a "return to normal operations in most areas following shut-ins from third-party midstream constraints" spread those costs over more barrels. Operating profit margin rose 26 percentage points from a year ago to 53.0% of revenue, by our math. Depletion and depreciation—the accounting cost of draining underground reserves—fell 9.3 percentage points of revenue, lease operating expenses dropped 8.2 points to $8.84 per Boe, and overhead fell 4.9 points to $2.27 per Boe.
What to watch: fourth-quarter lease operating expenses per Boe against the $8.75 to $9.75 target. Staying below $9.00 during the first full quarter of paying Waterbridge for water disposal would show that volume growth covers the new fee.
🐻 Bear Case
Fourth-Quarter Spending Plan Pushes Full-Year Budget Up Again
"Going forward, and based on current market conditions, we plan to continue investing significantly in the development of our assets," chief executive Bobby Riley said. Across the first two quarters of 2026, the company twice raised its full-year accrual capital budget—which counts drilling work as it happens rather than when bills are paid—from an initial $200 million midpoint to $236 million.
Third-quarter accrual spending landed at the bottom of the company's $53 million to $65 million plan at $53.1 million, though cash capital spending was $65.6 million as older bills came due. However, the fourth-quarter outlook sets accrual capital spending at $74 million to $86 million, far above the roughly $43 million implied by the prior full-year budget, by our math.
- Implied 2026 accrual capital spending: $266.8 million at the fourth-quarter midpoint, by our math
- Total budget increase since the start of 2026: $66.8 million, or 33% above the original $200 million midpoint, by our math
- Implied 2026 oil production: 23.2 thousand barrels per day by our math, up 8% from the original 21.5 midpoint
That fourth-quarter spending jump cuts against the earlier promise of a quiet year-end capital budget. Because capital spending has grown four times as fast as the full-year oil production target this year, a large share of 2026 cash is paying for wells that will not produce until 2027.
What to watch: fourth-quarter accrual capital spending against the $74 million to $86 million plan. A reading near or above the top end would confirm that completing the New Mexico well backlog costs more than planned.
Oil Hedges Still Take $12 a Barrel Off the Top
Riley cited "the currently supportive commodity price environment" as a pillar of its investment plan. To protect its cash flow when oil prices fall, the producer uses financial contracts called swaps and collars, which lock in fixed prices or price bands for future oil and gas sales.
When oil prices sit above those contract ceilings, the company pays out cash. In the third quarter, market oil fetched $83.63 per barrel before hedges, but cash payouts of $28.2 million on settled contracts cut the price the company kept to $71.61 per barrel, or 86% of the market rate by our math. Another $71.6 million in non-cash accounting losses on future contracts pushed the bottom line to a $2.4 million net loss.
This matters because the hedge table through 2027 still locks in roughly 605,000 to 725,000 barrels per quarter in swaps near $61.50 per barrel, plus Waha gas basis swaps—contracts that lock in the discount between local Permian gas and the national benchmark—at negative $0.94 to negative $1.58 per million British thermal units.
What to watch: how fast management adds late-2027 and 2028 oil swaps now that its bank agreement requires only 18 months of hedges instead of 24. Leaving more 2027 barrels unhedged would let the business keep more cash if oil stays above $75.
Well Hookups Missed the Plan and Left a Backlog
Turning a drilled well into oil revenue takes two more steps: completing the well by fracturing the rock, and turning it to sales by hooking it up to a pipeline. After missing its second-quarter hookup target because of pipeline delays, Riley Permian set a third-quarter plan to turn 15.2 to 17.2 net wells to sales.
The company turned only 11.9 net wells to sales, all in Texas, missing the bottom of its range by 22% by our math. In New Mexico, it has not turned a single new well to sales since July 2025, so natural decline pushed New Mexico oil output down 13% from a year ago to 6.9 thousand barrels per day. Quarter-end inventory stood at 17.3 drilled-but-uncompleted net wells—14.7 of them in New Mexico—plus 5.9 completed net wells waiting for pipeline hookups.
What to watch: total net wells turned to sales in the fourth quarter against the 14 to 18 plan. A third straight miss after the Targa pipeline opened would show that field execution, not just third-party pipe space, is slowing growth.
👓 Other Themes
San Andres Evaluation Sets Up Second-Quarter 2027 Drilling
At its Red Lake acreage in New Mexico, Riley Permian has historically drilled horizontal wells in the deeper Blinebry and Paddock rock layers. The company is now studying well logs, seismic data, and nearby rival wells in the shallower San Andres layer right above them, and plans to put money into its first San Andres drilling there during the second quarter of 2027.
💲 Other KPIs
Principal debt fell by $28 million from last quarter, or 10%, reversing the second quarter's $26 million borrowing increase. Compared with a year ago—right after the company borrowed to buy Silverback—principal debt is down $130 million, or 35%. Lower debt cut quarterly net interest costs to $6.7 million from $9.6 million a year ago.
Money owed by oil and gas buyers has more than doubled from $41.0 million at the end of 2025, up 124% by our math, outpacing the rise in sales. That buildup was offset on the balance sheet by higher unpaid drilling bills in accounts payable ($36.0 million versus $5.1 million at year-end) and royalties owed to landowners ($91.4 million).
Diluted weighted average shares fell 1.5% from 21.26 million a year ago, partly because the third-quarter GAAP net loss excluded unvested stock awards from the diluted count. Including unvested awards, total shares rose 0.7% from a year ago to 22.15 million as management bought back zero shares in the quarter and raised the quarterly dividend 5% to $0.42.
🔮 Guidance
Raised against the prior implied fourth-quarter rate. The plan calls for 26.0 thousand barrels per day at the middle of the range, up 2.2% from the third quarter and 29.3% from a year ago, by our math. That beats the 24.9 midpoint implied by last quarter's full-year outlook, lifting the implied 2026 average to 23.2 thousand barrels per day.
Raised against the prior implied fourth-quarter rate. Total output is set to grow 2.3% from the third quarter and 21.0% from a year ago at the 43.0 midpoint, by our math. The step-up rests on Targa's New Mexico gas line running for the full quarter, which allows wet-gas wells to flow without shut-ins.
Raised sharply against the prior implied fourth-quarter count. The 16.0 midpoint is nearly triple the 5.7 net wells implied by the prior full-year plan, by our math, and pushes the implied 2026 total to 49.8 net wells. The jump catches up on the 5.9 completed wells left waiting at the end of September and starts draining the New Mexico backlog.
New. Both drilling and completions are planned at a 15.0 net well midpoint, stepping up from 8.6 net wells drilled and 7.9 completed in the third quarter. By our math, that puts full-year drilling at 59.1 net wells and completions at 53.0, both well above the 51.6–53.6 drilled and 41.1–43.1 completed ranges issued last quarter.
Raised against the prior implied fourth-quarter budget. Spending is planned at $80 million at the middle of the range—$60–$70 million for wells and $14–$16 million for infrastructure, plus $2 million for the power joint venture. By our math, that is up 51% from the third quarter and lifts full-year accrual spending to $266.8 million, the third budget increase this year.
New. Lease operating expenses are planned at a $9.25 per Boe midpoint, up $0.41 from the third quarter's $8.84 as the new Waterbridge water disposal contract runs for a full quarter. Administrative costs are set at a $2.25 per Boe midpoint, flat with $2.27 in the third quarter, while production taxes stay at the usual 7.5% to 8.5% of revenue band.
❓ Key Questions
How many New Mexico backlog wells convert in Q4?
The company exited September with 14.7 drilled-but-uncompleted net wells in New Mexico and plans 14 to 18 total hookups in Q4. Management did not split the Q4 hookup plan between Texas and New Mexico now that Targa's pipe is open.
Why did full-year implied capital spending rise by $31 million?
Nine-month accrual spending of $186.8 million plus the $80 million Q4 midpoint equals $266.8 million, by our math, above last quarter's $230 million to $242 million full-year target. How much of the increase is cost inflation versus extra 2027 drilling?
What are the minimum volume commitments on the new pipes?
Both the 15-year Waterbridge water contract and the Targa gas agreement went live over the past seven weeks. The release still does not state the annual minimum volume thresholds or the cash penalties if New Mexico drilling slows.
Are the remaining RPC Power sites online in Texas?
Riley Permian put another $2 million into its RPC Power joint venture ($8.5 million year-to-date) and plans $2 million more in Q4, but gave no update on whether the remaining merchant power sites finished ERCOT grid commissioning.