Oil Output Up 38% in a Year. Hedges Cost $12 on Every $84 Barrel. New Mexico's New Pipe Opened October 1.

Riley Exploration Permian produces oil from two Permian Basin fields: Champions in Yoakum County, Texas, and Red Lake in Eddy County, New Mexico. Third-quarter oil output rose 38% from a year earlier to 25,435 barrels per day, and total production reached 42,022 barrels of oil equivalent per day. The company realized $83.63 a barrel before hedges and $71.61 after them, and its gas sold for $0.27 per thousand cubic feet. Total Free Cash Flow, as the company measures it, was $42.4M. The test is whether new New Mexico pipe and a smaller legacy hedge book turn more of each barrel into cash.

Analysis

Riley Exploration Permian is an Oklahoma City oil and gas producer listed on NYSE American. It works two Permian Basin fields. Champions, in Yoakum County, Texas, targets the San Andres formation on about 31,000 net acres. Red Lake, in Eddy County, New Mexico, targets the Blinebry and Paddock intervals of the Yeso on about 62,000 net acres, assembled through acquisitions in 2023, 2024 and 2025. At the end of 2025 the company held 97,538 net acres and interests in 873 net producing wells, and it operated about 96% of its net production, with an average 85% working interest in its operated wells. It also holds a stake, raised to 50% in 2024, in RPC Power, a gas-fired power joint venture with Conduit Power.

The third quarter of 2026 is why the desk is writing now. In results released November 4, oil production rose 38% from a year earlier to 25,435 barrels per day, and total production rose 30% to 42,022 barrels of oil equivalent per day (Boe/d), above the 40,500 to 41,500 Boe/d the company had guided. Revenue was $201.2M, up 88%. Hedge losses produced a net loss of $2.4M, while adjusted net income, a company measure, was $56M. Operating cash flow was $111.3M. In October the company repaid its 10.5% senior notes, enlarged its credit facility, and raised its quarterly dividend 5% to $0.42 a share.

The Human Translation: Riley Permian pumps oil from two fields, one in West Texas and one in southeastern New Mexico. This summer it pumped 38% more oil than a year earlier, with the gain coming from new wells in Texas. It sold that oil for about $84 a barrel, but contracts it signed earlier, which fixed or capped prices at about $62 to $73, cost it about $12 a barrel. Its natural gas sold for almost nothing because regional pipelines are full. A new pipeline serving its New Mexico field opened October 1.

Texas carried the growth. Texas operations, centered on Champions, produced 27.7 thousand Boe/d in the third quarter, up 61% from 17.2 thousand a year earlier, and its oil output rose 76% to 18.5 thousand barrels per day. Every new well the company turned to sales in the first nine months of 2026 was in Texas: 35 gross, 33.8 net. The field is 88% held by production, which means most leases stay in force as long as wells produce, and the company counts about 70 undeveloped net locations there. Texas acreage is entirely fee and state leasehold. Across 2025, Champions produced 17,371 Boe/d and Red Lake 11,593.

New Mexico is the larger acreage position and the larger open question. Riley bought Silverback Exploration II on July 1, 2025 for about $123M, adding about 40,000 net acres in the Yeso trend, with an earnout of up to $1.875M a quarter in 2026 and 2027 tied to oil prices. The company counts about 330 undeveloped net locations at Red Lake, a company estimate that includes potential San Andres locations it says remain subject to evaluation and do not establish proved reserves. Yet New Mexico produced 14.3 thousand Boe/d in the third quarter, down from 15.1 thousand a year earlier, and its oil output fell 13% to 6.9 thousand barrels per day. No New Mexico well has been turned to sales since July 2025, and the company ended September with 14.7 net drilled but uncompleted wells there.

The constraint is gas. Red Lake wells produce gas with their oil, and the oil cannot flow if the gas has nowhere to go. An unplanned outage at a third-party facility that began in late March forced shut-ins in April and May that the company estimates cut second-quarter oil output by about 1,900 barrels per day. The company reports gas and NGL sales net of gathering, processing and transportation costs. In the second quarter, it said, regional pipeline constraints left realized gas prices negative even before those costs, and higher allocated costs more than offset NGL prices: realized gas was negative $4.12 per Mcf and NGLs negative $4.71 per barrel. Third-quarter realizations of $0.27 and $5.08 swung revenue by $22M, the company said. The quarter's output was 2,340 thousand barrels of oil, 3,898 million cubic feet of gas and 876 thousand barrels of NGLs, about 61% oil by volume, and oil brought in about $195.7M of the $201.2M of revenue, 97% on the desk's arithmetic.

Hedges cut into the oil price. The company realized $83.63 a barrel before derivative settlements and $71.61 after, a difference of $12.02 a barrel, or $28.2M in cash settlements for the quarter. It also booked a $71.6M non-cash loss on contracts that settle later, for a total derivative loss of $99.8M. As of November 2 it had hedged 1.37 million barrels of fourth-quarter oil: 820,000 through swaps at $61.42 and 550,000 through collars with a $57.75 floor and a $69.59 ceiling. That is about 57% of the guided fourth-quarter oil midpoint on the desk's arithmetic. For 2027 it holds 2.65 million barrels of swaps at a weighted $61.81 and 2.0 million barrels of collars with ceilings averaging $70.35, on the desk's weighting.

Unit costs improved with volume. Lease operating expense was $34.2M, or $8.84 per Boe, against $9.44 in the second quarter and $9.03 a year earlier on the desk's arithmetic, and it included $11M of workover expense, about $2.85 per Boe. Production and ad valorem taxes were $12.8M, or $3.30 per Boe. Administrative costs were $8.8M, or $2.27 per Boe, with $4.2M of stock-based compensation reported separately. Depletion, depreciation, amortization and accretion was $32.5M, or $8.40 per Boe. Interest expense fell to $6.7M from $9.6M a year earlier as debt came down. Income from operations was $106.7M, against $28.9M.

Reported earnings swing with the hedge marks. The third-quarter pre-tax loss was $3.3M and, after a $0.9M tax benefit, the net loss was $2.4M, or $0.11 per share, against net income of $16.3M, or $0.77, a year earlier. Net income was negative $70.4M in the first quarter and positive $87.4M in the second as forward oil prices moved. Adjusted net income was $56M, or $2.66 per diluted share, and Adjusted EBITDAX was $117.3M, up 83%; the company defines and reconciles both in supplemental tables. The quarter also carried a $3.3M loss on acquisitions and divestitures, mostly a $2.5M remeasurement of the Silverback earnout as oil prices rose.

Cash flow is the cleaner read. Operating cash flow was $111.3M, up 75% both from a year earlier and from the second quarter, and $108M before working capital changes. Cash capital spending was $65.6M, against accrual spending of $53.1M, as payments for earlier activity came due. Total Free Cash Flow was $42.4M and Upstream Free Cash Flow $42.5M. On the desk's reconciliation, both equal operating cash flow before working capital changes less cash capital spending; the upstream version counts only upstream spending, and neither deducts power joint venture contributions. Second-quarter Total Free Cash Flow was $6.3M. For nine months it was $72.1M, against $79.6M a year earlier.

Guidance has risen through the year. In March the company guided 2026 total production to 35,000 to 37,000 Boe/d, oil to 21,000 to 22,000 barrels per day, and capital spending to $190M to $210M. By August, after a May increase, oil was 22,500 to 23,500 barrels per day and capital spending $230M to $242M, while total production was narrowed to 37,500 to 38,500 Boe/d from May's 37,500 to 39,500. The November release gives fourth-quarter guidance only: oil of 25,500 to 26,500 barrels per day, total production of 42,500 to 43,500 Boe/d, 14 to 18 net wells turned to sales, and capital spending of $74M to $86M. On the desk's arithmetic, that implies full-year oil of about 23,100 to 23,400 barrels per day and accrual capital spending of about $261M to $273M, above the August range.

The annual record shows growth bought through lower prices and an asset sale. Production rose 30% in 2025 to 29,205 Boe/d from 22,546, and oil rose 15% to 17,337 barrels per day, but revenue fell 4% to $392.0M as the realized oil price dropped to $62.95 from $74.10. Net income was $160.8M, or $7.59 per share, against $88.9M, helped by a $71.7M pre-tax gain on selling Dovetail Midstream and a compressor station to Targa in December for about $123M of cash and up to $60M of contingent payments over five years. Adjusted EBITDAX was $260.6M against $284.2M, operating cash flow $212.5M against $246.3M, and Total Free Cash Flow $80.6M against $117.1M.

Proved reserves were 147.4 million Boe at December 31, 2025, up 19%, as estimated by Ryder Scott. Oil was 74.3 million barrels, gas 206.7 billion cubic feet and NGLs 38.6 million barrels. Proved developed producing reserves were 86.7 million Boe, 59% of the total, and proved undeveloped reserves 60.7 million, with estimated future development costs of about $285M, all scheduled within five years. Extensions and discoveries added 23.0 million Boe, and 10.8 million Boe moved from undeveloped to developed for about $56M. The PV-10 was $1.39B and the standardized measure $1.14B, at SEC prices of $65.34 a barrel and $3.39 per Mcf. At the third-quarter rate, proved reserves equal about 9.6 years of output on the desk's arithmetic.

The balance sheet was refinanced in October. Debt was $245M at September 30, $115M on the credit facility and $130M of 10.5% senior notes due April 2028, down from $273M at June 30 and $255M at the end of 2025; the company puts it at 0.8 times trailing Adjusted EBITDAX of $324M. On October 5 it prepaid the notes in full with revolver borrowings. On October 29 it amended the facility: the borrowing base rose to $450M from $425M, commitments to $450M from $400M, and maturity moved to October 2030 from December 2028. The amendment also cut the minimum hedging requirement to a rolling 18 months from 24. The company's presentation puts liquidity at $232M, $27M of cash and $205M undrawn, pro forma for the note prepayment and the amendment.

Capital returns are steady and modest beside the drilling budget. The company has paid a fixed quarterly dividend since going public and raises it annually. It paid $0.40 a share each quarter of 2026, $25.4M in nine months, and raised it to $0.42, payable November 11. That is $1.68 a year, about $37M on the 22.1 million shares outstanding on November 2, on the desk's arithmetic. The board authorized a $100M buyback in late 2025; the company has used $4.9M of it this year, all in the first half. On the same arithmetic, dividends and buybacks took 42% of nine-month Total Free Cash Flow. The power joint venture received $8.5M of contributions, and the stake was carried at $44.2M.

The company's answer to the gas constraint is infrastructure. Under a December 2025 agreement tied to its gas purchase contract, Targa Northern Delaware built gathering and high-pressure trunkline capacity in Eddy County, which entered service October 1 and began receiving gas. A 15-year produced water agreement with Waterbridge Stateline began September 15. The midstream sale carries up to $60M of contingent payments as New Mexico gas volumes rise. The company plans to begin developing the San Andres formation at Red Lake in the second quarter of 2027, with six San Andres wells in the 2027 program. Bobby Riley, chairman and chief executive, said the company plans to keep investing significantly, based on current market conditions.

Leadership and ownership overlap. Bobby D. Riley is chairman and chief executive; Philip Riley is chief financial officer and executive vice president of strategy; John Suter is chief operating officer; Jeffrey Gutman is chief accounting officer; and Corey Riley is chief information officer and chief compliance officer. Director Bryan H. Lawrence is a founder of Yorktown Partners, whose funds hold 9.4% of the shares; Balmon Investments holds 10.1%, and the company counts total insider ownership at 16.8%. The 2026 proxy shows 2025 executive bonuses paid at 170% of target, of which 110 points came from quantitative metrics and 60 from a qualitative assessment of strategic objectives. Bobby Saadati joined the board in February 2026.

The risks the filings name are concrete. Prices cut both ways: the realized oil price fell 15% in 2025, and in the first nine months of 2026 it averaged 26% more than a year earlier, while hedges absorbed $76.1M of settlement losses over those nine months on the desk's arithmetic. Permian gas takeaway, Waha pricing and third-party processing have already produced negative realizations and shut-ins. New Mexico output fell 5% in a year with no new wells turned to sales there and with gas takeaway constrained, and proved undeveloped reserves need about $285M of development spending. About 38% of New Mexico acreage is federal BLM leasehold, and the 10-K, filed in March, cited a New Mexico emissions bill then under legislative consideration. Two purchasers took 90% of 2025 revenue. The release also names borrowing base reductions and a produced water permit moratorium.

The scenario map has three branches. In the first, the Targa system lets the 14.7 net New Mexico DUCs come on, gas and NGL realizations stay positive, and as legacy hedges roll off more of the realized oil price reaches cash flow, so free cash flow rises even with spending above $260M a year. In the second, production meets guidance but Waha pricing weakens again, hedges keep settling at a loss, and higher spending absorbs most of operating cash flow, leaving free cash flow near the second-quarter level. In the third, oil prices fall, hedges turn into gains but revenue drops, and a drilling program sized for higher prices draws on the revolver after the note prepayment.

The checkpoint set, stated fully. First, fourth-quarter oil production against 25,500 to 26,500 barrels per day and total production against 42,500 to 43,500 Boe/d. Second, New Mexico volumes and wells turned to sales now that the Targa system is in service, against 14.3 thousand Boe/d in the third quarter. Third, realized gas and NGL prices against $0.27 per Mcf and $5.08 per barrel. Fourth, cash hedge settlements against $28.2M in the third quarter, and new hedges under the 18-month requirement. Fifth, capital spending against the $74M to $86M fourth-quarter range and the 2027 plan, including the first San Andres wells. Sixth, revolver borrowings after the note prepayment, against $245M of debt. Seventh, year-end 2026 proved reserves against 147.4 million Boe.

The Human Translation

Riley Permian pumps oil from two fields, one in West Texas and one in southeastern New Mexico. This summer it pumped 38% more oil than a year earlier, with the gain coming from new wells in Texas. It sold that oil for about $84 a barrel, but contracts signed earlier, which fixed or capped prices at about $62 to $73, cost it about $12 a barrel. Its natural gas sold for almost nothing because regional pipelines are full. A new pipeline serving its New Mexico field opened October 1.

Bottom Line

Watch fourth-quarter oil against 25,500 to 26,500 barrels per day and total production against 42,500 to 43,500 Boe/d, and whether the Targa system lifts New Mexico volumes and keeps gas realizations positive. Then watch hedge settlements, capital spending against the $74M to $86M range, the 2027 plan with its first San Andres wells, and revolver borrowings after the note prepayment.

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