Riley Exploration Permian, Inc.
For the period ended Sep 30, 2026. Filed Nov 4, 2026.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Sep 30, 2026 · Filed Nov 4, 2026
REPX$41.23+2.8%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2026-06-30; filed 2026-08-05.
0001001614-26-000051
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-09-30; filed 2026-11-04.
0001001614-26-000063
Item 2. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 98 previous paragraphs and 95 current paragraphs.
60 unchanged; 26 reworded; 9 added; 11 removed; 1 previous and 0 current paragraphs rearranged.
Tables are not compared: 17 previous and 17 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (9)
Current report
New Mexico Financial Assurance Requirements
Current report
In September 2026, the New Mexico Oil Conservation Commission and the New Mexico State Land Office adopted amended financial assurance requirements for oil and gas wells and for leases on state trust lands. The requirements phase in through 2029 and include, beginning May 1, 2029, financial assurance of $150,000 for each low producing well. In 2024, the Bureau of Land Management increased the minimum bond amounts applicable to federal oil and gas leases and in June 2026 proposed to return those minimums to their prior levels, although the proposal has not been finalized and the current requirements remain in effect. We are evaluating the effect of these requirements, which will depend on the status of our wells and leases when each requirement takes effect. The additional financial assurance required beginning May 1, 2029 could be significant. We expect to satisfy these requirements primarily with surety bonds and letters of credit. Surety providers may require collateral, and letters of credit issued under our Credit Facility would reduce the borrowing capacity otherwise available to us.
Current report
The Company evaluated whether the revised New Mexico financial assurance requirements, the related limits on temporary abandonment and the presumption regarding low-volume wells required any change to the estimated timing or amount of its asset retirement obligations. Financial assurance required under the revised rules does not by itself establish or increase an asset retirement obligation. Based on our preliminary assessment of the requirements as currently adopted and their application to our New Mexico assets, we do not expect compliance with these additional bonding and financial assurance requirements to have a material adverse effect on our financial condition, results of operations or liquidity.
Current report
Natural gas revenues increased by $1.8 million driven by higher realized natural gas prices, partially offset by higher GP&T costs. Our realized natural gas prices before GP&T costs increased by $0.89 per Mcf driven by improved basis differentials, partially offset by a $0.16 decrease in the average Henry Hub price. GP&T costs increased due to higher volumes from new wells turned to sales.
Current report
NGL revenues increased by $4.9 million driven by higher realized NGL prices, partially offset by higher GP&T costs. Our realized NGL prices before GP&T costs increased by $4.76 per Bbl due to higher average Mont Belvieu prices. GP&T costs increased due to higher volumes from new wells turned to sales.
Current report
Nine months ended September 30, 2026, compared to nine months ended September 30, 2025
Current report
NGL revenues decreased by $5.5 million driven by higher allocated GP&T costs that more than offset an increase in production from new wells turned to sales and the Silverback Acquisition. Our realized NGL prices before GP&T costs increased by $0.73 per Bbl due to higher average Mont Belvieu prices.
Current report
The increase in the effective tax rate during the three months ended September 30, 2026, was primarily due to the marginal well credit benefit recognized during the quarter following the release of the applicable 2026 credit rate by the Internal Revenue Service in July 2026, as well as a lower level of pretax income (loss) resulting from unrealized derivative losses. The tax credit benefit was recognized against a pretax loss for the quarter, resulting in a disproportionate impact on the effective tax rate relative to periods with higher pretax income.
Current report
Proceeds from our Credit Facility in 2025 were primarily used to fund the Silverback Acquisition. The Company had repurchases of common shares of $5 million during 2026 under the Repurchase Program.
Removed paragraphs (11)
Previous report
Midstream Disruption
Previous report
During the second quarter of 2026, certain portions of our New Mexico operations continued to experience production interruptions and curtailments resulting from third-party midstream and gas processing constraints. Following the unplanned outage at a third-party gas processing facility that began in late March 2026, we continued to experience periodic processing limitations, maintenance-related curtailments, and reduced gas takeaway capacity affecting a portion of our New Mexico production during the quarter. These events resulted in the temporary shut-in of certain wells and reduced production from impacted areas. The temporary shut-in was substantially resolved by the end of May with production resuming to normal levels for June.
Previous report
The effects of these disruptions were partially mitigated by the limited geographic scope of the affected production, our ability to restore certain wells to production as processing capacity became available, and strong operating performance from our Texas assets. As a result, while the curtailments negatively impacted certain production volumes during the quarter, they did not materially affect our overall financial condition or liquidity.
Previous report
We continue to monitor the reliability and capacity of third-party midstream infrastructure serving our New Mexico acreage. To mitigate the risk of future processing and takeaway constraints of the nature experienced during the period, Targa is constructing new gathering and high-pressure trunkline infrastructure in Eddy County, New Mexico pursuant to the A&R Gas Purchase Agreement. Upon completion, this infrastructure is expected to provide increased gathering, processing, and takeaway capacity that reduces our reliance on the affected third-party processing facilities. The in-service date of the new Targa pipeline system is currently expected to occur in the fourth quarter of 2026. See Note 15 – Commitments and Contingencies for additional information.
Previous report
(3)During the periods presented, the Company did not have any NGL derivative contracts in place.
Previous report
NGL revenues decreased by $3.4 million. Our realized NGL prices before GP&T costs increased by $2.98 per Bbl which was the result of an increase in the average Mont Belvieu prices realized. Our realized NGL prices net of GP&T costs decreased by $5.46 primarily due to higher allocated GP&T costs when realized natural gas prices are negative.
Previous report
Six months ended June 30, 2026, compared to six months ended June 30, 2025
Previous report
NGL revenues decreased by $10.4 million. Our realized NGL prices before GP&T costs decreased by $2.24, per Bbl which was the result of a decrease in the average Mont Belvieu prices realized. Our realized NGL prices net of GP&T costs decreased by $8.49 primarily due to higher allocated GP&T costs when realized natural gas prices are negative.
Previous report
Production and ad valorem taxes increased by $7.7 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to higher revenues from increased production volumes, including an increase in volumes from the Silverback Acquisition and higher oil prices, partially offset by the reversal of $0.8 million for a previously accrued liability related to the Environmental Protection Agency’s waste emission charge that was nullified in the first quarter of 2025.
Previous report
The increase in deferred income tax expense during the three months ended June 30, 2026, is primarily due to a higher non-cash benefit on derivatives. The decrease in current income tax expense was primarily attributable to higher capital spending during the six months ended June 30, 2026, compared to the six months ended June 30, 2025.
Previous report
Net borrowings increased by $14 million, partially offset by the repurchase of common shares of $5 million and an increase in repurchases of common shares for tax withholding of 1.5 million.
Reworded paragraphs (26)
Previous wording
Comparison for the three and six months ended June 30, 2026, and 2025:
Current wording
Comparison for the three and nine months ended September 30, 2026, and 2025:
Previous wording
The Company’s total oil and natural gas sales, net increased by $80.5 million or 94%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs:
Current wording
The Company’s total oil and natural gas sales, net increased by $94.4 million or 88%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs:
Previous wording
Oil revenues increased by $96.3 million. Our realized oil prices increased by $32.11 per Bbl, which was the result of a $31.08 increase in the average WTI price. Average daily oil volumes increased by 40%, primarily due to new wells turned to sales and the contribution of the Silverback Acquisition.
Current wording
Oil revenues increased by $87.7 million. Our realized oil prices increased by $19.69 per Bbl, which was the result of a $21.34 increase in the average WTI price. Average daily oil volumes increased by 38%, primarily due to new wells turned to sales.
Previous wording
The Company’s total oil and natural gas sales, net increased by $91.9 million or 49%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs:
Current wording
The Company’s total oil and natural gas sales, net increased by $186.2 million or 63%. The following tables summarize the effects of price, volume and GP&T costs changes on our revenues from oil, natural gas and NGLs:
Previous wording
Oil revenues increased by $122.7 million. Our realized oil prices increased by $15.81 per Bbl, which was the result of a $16.17 increase in the average WTI price. Daily oil volumes increased by 34%, primarily due to new wells turned to sales and the Silverback Acquisition.
Current wording
Oil revenues increased by $210.4 million. Our realized oil prices increased by $17.29 per Bbl, which was the result of a $17.94 increase in the average WTI price. Daily oil volumes increased by 36%, primarily due to new wells turned to sales and the Silverback Acquisition.
Previous wording
Natural gas revenues decreased by $20.4 million driven by negative realized natural gas prices that more than offset an increase in production volumes. Our realized natural gas prices before GP&T costs decreased $3.75 per Mcf, which was the result of an increase in negative Permian basis differentials due to regional pipeline constraints, partially offset by a $0.15 increase in the average Henry Hub price.
Current wording
Natural gas revenues decreased by $18.7 million driven by negative realized natural gas prices that more than offset an increase in production from new wells turned to sales and the Silverback Acquisition. Our realized natural gas prices before GP&T costs decreased $2.05 per Mcf, primarily due to wider negative Permian basis differentials resulting from regional pipeline constraints, partially offset by a $0.04 increase in the average Henry Hub price.
Previous wording
The Company’s LOE increased by $10.6 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to a $6.4 million increase related to the Silverback Acquisition, a $3.0 million increase in workover expenses to return wells to production and a $1.2 million increase in Champions' third-party water disposal costs to align with our increased drilling pace.
Current wording
The Company’s LOE increased by $7.3 million for the three months ended September 30, 2026, compared to the three months ended September 30, 2025, primarily due to a $1.8 million increase in workover expenses to return wells to production, a $1.8 million increase in fluids and third party water disposal costs, a $1.7 million increase in environmental and safety costs, and a $1.5 million increase in electricity costs to align with our increased drilling pace.
Previous wording
The Company’s LOE increased by $16.3 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, primarily due to a $10.8 million increase related to the Silverback Acquisition, a $3.1 million increase in workover expenses to return wells to production and a $1.1 million increase in Champions' third-party water disposal costs to align with our increased drilling pace.
Current wording
The Company’s LOE increased by $23.6 million for the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, primarily due to an $8.7 million increase in workover expenses to return wells to production, a $3.8 million increase in equipment costs and repairs, a $3.2 million increase in fluids and third party water disposal costs, a $2.2 million increase in electricity costs, a $1.7 million increase in payroll and contractor services and a $4.0 million increase across various other LOE costs to align with our increased drilling pace.
Previous wording
Production and ad valorem taxes increased by $5.3 million for the three months ended June 30, 2026, compared to the three months ended June 30, 2025, primarily due to higher revenues from increased production volumes, including an increase in volumes from the Silverback Acquisition and higher oil prices.
Current wording
Production and ad valorem taxes increased by $4.5 million and $12.2 million, respectively, for the three and nine months ended September 30, 2026, compared to the three and nine months ended September 30, 2025, primarily due to higher revenues from increased production volumes and higher oil prices.
Previous wording
DD&A expense increased by $5.1 million and $11.7 million, respectively, for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, primarily due to higher production volumes, including an increase in volumes from the Silverback Acquisition which increased depletion expense by approximately $2.4 million and $6.8 million, respectively.
Current wording
DD&A expense increased by $5.3 million and $16.9 million, respectively, for the three and nine months ended September 30, 2026, compared to the three and nine months ended September 30, 2025, primarily due to higher production volumes.
Previous wording
There was no impairment loss during the three and six months ended June 30, 2026. There was a non-cash impairment loss on proved properties of $1.2 million during the three and six months ended June 30, 2025, which related to a decrease in fair value of certain properties in New Mexico outside of the Company's core acreage in the Red Lake field.
Current wording
There was no impairment loss during the three and nine months ended September 30, 2026. There was no impairment loss during the three months ended September 30, 2025, while the Company recognized a non-cash impairment loss on proved properties of $1.2 million during the nine months ended September 30, 2025, which related to a decrease in fair value of certain properties in New Mexico outside of the Company's core acreage in the Red Lake field.
Previous wording
Total G&A expense increased by $3.8 million and $5.4 million for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, respectively, primarily due to increased headcount and higher incentive compensation.
Current wording
Total G&A expense increased by $0.3 million and $5.7 million, respectively, for the three and nine months ended September 30, 2026, compared to the three and nine months ended September 30, 2025, primarily due to increased headcount, resulting in higher compensation expense, including stock-based compensation.
Previous wording
Transaction costs represent costs incurred on successful or unsuccessful commercial transactions, business combinations or unsuccessful asset acquisitions. There were no transaction costs during the three and six months ended June 30, 2026. During the three and six months ended June 30, 2025, transaction costs of $1.9 million primarily related to the Silverback Acquisition.
Current wording
Transaction costs represent costs incurred on successful or unsuccessful commercial transactions, business combinations or unsuccessful asset acquisitions. Transaction costs were minimal for the three and nine months ended September 30, 2026. During the three and nine months ended September 30, 2025, transaction costs of $2.8 million and $4.7 million, respectively, primarily related to the Silverback Acquisition.
Previous wording
Interest expense, net decreased by $0.4 million and $0.7 million, respectively, for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025, respectively, primarily due to lower interest rates on the Credit Facility and a lower principal balance on the Senior Notes.
Current wording
Interest expense, net decreased by $2.9 million and $3.6 million, respectively, for the three and nine months ended September 30, 2026, compared to the three and nine months ended September 30, 2025, primarily due to lower interest rates on the Credit Facility and a lower principal balance on the Senior Notes.
Previous wording
Cash gains or losses on settled derivative contracts related to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding.
Current wording
Cash gains or losses on settled derivative contracts related to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated volumes for each underlying commodity for our derivative contracts outstanding.
Previous wording
Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. At June 30, 2026, we had $262 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital:
Current wording
Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits. At September 30, 2026, we had $285 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital:
Previous wording
Our working capital deficit increased by $90 million primarily due to higher working capital required to fund our drilling program, revenue payable from higher oil prices and changes in our derivative assets and liabilities.
Current wording
Our working capital deficit increased by $134 million primarily due to higher working capital required to fund our drilling program, revenue payable from higher oil prices and changes in our derivative assets and liabilities.
Previous wording
Net cash provided by operating activities were $110.7 million for the six months ended June 30, 2026, compared to $84.0 million for the six months ended June 30, 2025, and primarily consisted of the following:
Current wording
Net cash flows provided by operating activities were $222.0 million for the nine months ended September 30, 2026, compared to $147.7 million for the nine months ended September 30, 2025, and primarily consisted of the following:
Previous wording
Net cash flows used in investing activities were $101.7 million for the six months ended June 30, 2026, compared to $70.5 million for the six months ended June 30, 2025, and primarily consisted of the following:
Current wording
Net cash flows used in investing activities were $169.8 million for the nine months ended September 30, 2026, compared to $212.8 million for the nine months ended September 30, 2025, and primarily consisted of the following:
Previous wording
Capital expenditures for oil and natural gas properties increased by $55.9 million due to an increase in drilling and completion activity and an increase in infrastructure investments. Funds held in escrow relate to the Silverback Acquisition, which closed on July 1, 2025.
Current wording
Capital expenditures for oil and natural gas properties increased by $106.8 million due to an increase in drilling and completion activity and an increase in infrastructure investments. Net assets acquired in business combination related to the Silverback Acquisition, which closed on July 1, 2025.
Previous wording
Net cash flows used in financing activities were $6.2 million for the six months ended June 30, 2026, compared to $12.7 million for the six months ended June 30, 2025, and primarily consisted of the following:
Current wording
Net cash flows used in financing activities were $43.2 million for the nine months ended September 30, 2026, compared to net cash flows provided by financing activities of $68.5 million for the nine months ended September 30, 2025, and primarily consisted of the following:
Previous wording
The Credit Facility and Senior Notes had a principal balance of $138 million and $135 million, respectively, as of June 30, 2026.
Current wording
The Credit Facility and Senior Notes had a principal balance of $115 million and $130 million, respectively, as of September 30, 2026.
Previous wording
See further discussion in Note 10 - Long-Term Debt for additional information.
Current wording
See further discussion in Note 10 - Long-Term Debt and Note 16 - Subsequent Events for additional information.
Previous wording
For the six months ended June 30, 2026, the Company recognized quarterly dividends totaling approximately $17.3 million, with $17.0 million paid in cash and $0.3 million accrued for the holders of unvested restricted stock awards.
Current wording
For the nine months ended September 30, 2026, the Company recognized quarterly dividends totaling approximately $26.1 million, with $25.4 million paid in cash and $0.7 million accrued for the holders of unvested restricted stock awards.
Previous wording
As of June 30, 2026, the Company had a remaining volume commitment that expires the earlier of achieving a specified quantity of cumulative volumes delivered or by the contract expiration date in 2031 with Targa, formerly Stakeholder Midstream, LLC, in Texas. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. The Company also entered into the A&R Gas Purchase Agreement that required an acreage dedication and a minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement is expected to commence in the fourth quarter of 2026. In addition, the Company entered into the Waterbridge Agreement, which includes minimum produced water volume commitments for a portion of our New Mexico operations and is expected to be in service in the fourth quarter of 2026. See Note 15 - Commitments and Contingencies for additional information.
Current wording
As of September 30, 2026, the Company had a remaining volume commitment that expires the earlier of achieving a specified quantity of cumulative volumes delivered or by the contract expiration date in 2031 with Targa, formerly Stakeholder Midstream, LLC, in Texas. The Company also had natural gas delivery commitments under the Second A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. The Company also entered into the A&R Gas Purchase Agreement that required an acreage dedication and a minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement commenced in October of 2026. In addition, the Company entered into the Waterbridge Agreement, which includes minimum produced water volume commitments for a portion of our New Mexico operations and was placed in service in September 2026. See Note 15 - Commitments and Contingencies for additional information.
Previous wording
The Company's critical accounting estimates are described in "Critical Accounting Estimates" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of the Notes to the Consolidated Financial Statements in the 2025 Annual Report. The accounting estimates used in preparing our interim condensed consolidated financial statements for thesix months ended June 30, 2026, are the same as those described in the 2025 Annual Report.
Current wording
The Company's critical accounting estimates are described in "Critical Accounting Estimates" within "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 3 of the Notes to the Consolidated Financial Statements in the 2025 Annual Report. The accounting estimates used in preparing our interim condensed consolidated financial statements for thenine months ended September 30, 2026, are the same as those described in the 2025 Annual Report.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Natural gas revenues decreased by $12.5 million driven by negative realized natural gas prices that more than offset an increase in production volumes. Our realized natural gas prices before GP&T costs decreased by $4.80 per Mcf, which was the result of an increase in negative Permian basis differentials due to regional pipeline constraints in addition to a $0.24 decrease in the average Henry Hub price.