Riley Exploration Permian swings to $2.4M Q3 loss
Q4 2026 guidance lists oil production of 25.5–26.5 MBbls/d and total capital expenditures of $74–$86 million.
Sentiment and the balance of points
Rhea-AI Sentiment reads the wording of the document, how positive or negative its language is on a 1 to 5 scale. The balance of points shown with the takes weighs what the document actually discloses, so the two can disagree, for example when a trial that missed its main goal is described in upbeat language.
Form Type
8-K
Rhea-AI Filing Summary
Riley Exploration Permian, Inc. (REPX) reported third-quarter 2026 revenue of $201 million, versus $107 million a year earlier, and a net loss of $2.4 million compared with net income of $16.3 million. Operating cash flow was $111 million and Adjusted EBITDAX was $117 million. The company recorded a $99.8 million net derivative loss, including realized settlements and non-cash fair-value changes.
Oil production averaged 25.4 MBbls/d and total equivalent production was 42.0 MBoe/d. Total Free Cash Flow was $42 million, with $53 million in accrued capital expenditures. On October 5, 2026, the company prepaid $130 million of Senior Notes using its revolving credit facility. An amended agreement dated October 29, 2026 raised the borrowing base from $425 million to $450 million and elected commitments from $400 million to $450 million, extended maturity to October 2030, and reduced required hedge tenor to 18 months from 24 months. Borrowings were $245 million, with $205 million available, as of October 29, 2026. The quarterly dividend increased 5% to $0.42 per share; initial San Andres development is planned for the second quarter of 2027.
3 points · 0 major0 major · 2 points
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Moderate pointRevenue: $201 million in Q3 2026 versus $107 million a year earlier.
- Moderate pointOperating cash flow: $111 million, up 75% year over year.
- Minor pointQuarterly dividend: $0.42 per share, a 5% increase.
Negative
- Moderate pointNet loss: $2.4 million, versus $16.3 million net income in Q3 2025.
- Minor pointNet derivative loss: $99.8 million, including non-cash fair-value losses.
Filing Explained
Under the October 29 restated facility, prior credit-facility obligations were not discharged; they continue, secured by substantially all of the company’s and its subsidiaries’ oil and gas properties and other assets, and guaranteed by the company.
8-K Event Classification
5 items: 1.01, 2.02, 2.03, 7.01, 9.01
5 items
Item 1.01
Entry into a Material Definitive Agreement
Business
The company signed a significant contract such as a merger agreement, credit facility, or major partnership.
Item 2.02
Results of Operations and Financial Condition
Financial
Disclosure of earnings results, typically an earnings press release or preliminary financials.
Item 2.03
Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement
Financial
The company incurred a new significant debt or off-balance-sheet obligation.
Item 7.01
Regulation FD Disclosure
Disclosure
Material non-public information disclosed under Regulation Fair Disclosure, often investor presentations or guidance.
Item 9.01
Financial Statements and Exhibits
Exhibits
Financial statements, pro forma financial information, or exhibit attachments filed with this report.
Key Figures
Revenue: $201 million
Net income (loss): −$2.4 million
Operating cash flow: $111 million
+5 more
8 metrics
Revenue
$201 million
Third quarter 2026; versus $107 million in third quarter 2025
Net income (loss)
−$2.4 million
Third quarter 2026; compared with $16.3 million net income in third quarter 2025
Operating cash flow
$111 million
Third quarter 2026; up 75% year over year
Adjusted EBITDAX
$117 million
Third quarter 2026
Total Free Cash Flow
$42 million
Third quarter 2026
Oil production
25.4 MBbls/d
Third quarter 2026 average daily production
Borrowing base
$450 million
Amended credit agreement dated October 29, 2026
Quarterly dividend
$0.42 per share
Increased 5% in October 2026
Key Terms
Adjusted EBITDAX, Total Free Cash Flow, borrowing base, rolling hedging requirement, +1 more
5 terms
Adjusted EBITDAX financial
"Adjusted EBITDAX(1) was $117 million"
Adjusted EBITDAX is a measure of a company’s operating profit that adds back interest, taxes, depreciation, amortization and specific recurring costs (often exploration or similar project expenses), then removes one‑time or unusual items to show recurring cash profitability. Investors use it like a clean yardstick—ignoring financing choices, accounting rules and one‑off events—to compare core performance across periods or peers and assess a business’s ability to generate cash from operations.
Total Free Cash Flow financial
"Total Free Cash Flow(1) was $42 million"
Total free cash flow is the amount of cash a company generates from its normal business after paying everyday operating costs and necessary investments in equipment or facilities, summed for the reporting period. It shows the real, spendable cash available to pay down debt, return money to shareholders, or fund growth — think of it like a household’s money left after paying bills and doing essential repairs, a key measure of financial strength for investors.
borrowing base financial
"increases the borrowing base to $450 million"
A borrowing base is the amount a lender will allow a company to borrow based on the value of assets the company offers as security, typically things like accounts receivable and inventory. It matters to investors because it sets a practical ceiling on short-term financing and influences a company’s liquidity and risk: if the borrowing base falls, the company may lose access to cash or be forced to sell assets, which can affect operations and share value.
rolling hedging requirement financial
"rolling hedging requirement to 18-months from 24-months"
drilled-but-uncompleted wells technical
"17.3 net drilled-but-uncompleted wells"
Earnings Snapshot
Revenue: $201 million · Guidance included
Third quarter ended September 30, 2026
Revenue
$201 million
Versus $107 million in third quarter 2025
Net income (loss)
−$2.4 million
Versus $16.3 million net income in third quarter 2025
Operating cash flow
$111 million
Up 75% year over year
Guidance
For Q4 2026, oil production of 25.5–26.5 MBbls/d, total equivalent production of 42.5–43.5 MBoe/d, and total capital expenditures of $74–$86 million, based on currently scheduled development activity and current market conditions.
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
What were REPX's third-quarter 2026 revenue and earnings?
REPX reported $201 million of revenue in Q3 2026, versus $107 million in Q3 2025. It recorded a net loss of $2.4 million, compared with net income of $16.3 million in the prior-year quarter.
What is REPX's aggregate maximum credit amount under its amended agreement?
The amended agreement sets an aggregate maximum credit amount of $1.0 billion. Elected commitments are $450 million; as of October 29, 2026, Riley Exploration – Permian, LLC, the borrower, had $245 million outstanding and $205 million available.
What is REPX's Q4 2026 production and capital expenditure guidance?
REPX's Q4 2026 guidance lists oil production of 25.5–26.5 MBbls/d, total equivalent production of 42.5–43.5 MBoe/d, and total capital expenditures of $74–$86 million, based on currently scheduled development activity and current market conditions.
When did REPX's New Mexico infrastructure enter service?
The Targa natural gas pipeline system in Eddy County, New Mexico, was placed in service on October 1, 2026. The in-service date for the water management services agreement was September 15, 2026.
AI-generated analysis. How Rhea-AI works. Not financial advice.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): October 29, 2026
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||||||
Address of Principal Executive Offices, Including Zip Code)
(Registrant’s Telephone Number, Including Area Code)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Trading Symbol(s) | Name of each exchange on which registered | |||||||||||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Item 1.01 Entry into a Material Definitive Agreement.
On October 29, 2026, Riley Exploration Permian, Inc. (the "Company"), as parent guarantor, and its wholly owned subsidiary, Riley Exploration – Permian, LLC (the "Borrower"), entered into an Amended and Restated Credit Agreement (the "A&R Credit Agreement") with Truist Bank, as administrative agent and issuing bank, and the lenders party thereto. The A&R Credit Agreement amends and restates in its entirety the Company's Credit Agreement dated as of September 28, 2017 (as previously amended, the "Prior Credit Agreement"). Obligations outstanding under the Prior Credit Agreement continue under the A&R Credit Agreement and were not discharged.
Among other things, the A&R Credit Agreement increases the borrowing base to $450 million from $425 million and the aggregate elected commitments to $450 million from $400 million (with an aggregate maximum credit amount of $1.0 billion), extends the maturity date from December 2028 to October 2030, and reduces the tenor for required hedges under the rolling hedging requirement to 18-months from 24-months.
Borrowings under the A&R Credit Agreement remain secured by substantially all of the Company's and its subsidiaries' oil and natural gas properties and other assets, and remain guaranteed by the Company. As of October 29, 2026, the Borrower had $245 million of borrowings outstanding under the A&R Credit Agreement, leaving $205 million of availability.
The foregoing description is a summary and is qualified in its entirety by reference to the full text of the A&R Credit Agreement, which is filed as Exhibit 10.1 incorporated herein by reference.
Item 2.02 Results of Operations and Financial Condition.
On November 4, 2026, Company announced its financial condition and results of operations for the nine months ended September 30, 2026. In connection with this announcement, the Company issued an earnings press release (the “Earnings Release”). A copy of this document is furnished as Exhibit 99.1 to this Form 8-K and is available on the Company’s website at www.rileypermian.com.
In accordance with General Instructions B.2. of Form 8-K, the information described in this Item 2.02, including the matters discussed on the Company’s earnings conference call, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such a filing.
Item 2.03 Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.
The information set forth under Item 1.01 of this Current Report on Form 8-K is incorporated herein by reference into this Item 2.03.
Item 7.01 Regulation FD Disclosure.
On November 4, 2026, the Company made available an investor presentation (the "Presentation") that includes certain operational updates regarding the Company. A copy of the Presentation is furnished as Exhibit 99.2 to this Current Report on Form 8-K.
The information in this Item 7.01, including Exhibit 99.2, is being furnished pursuant to Item 7.01 of Form 8-K and shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as expressly set forth by specific reference in such filing.
Item 9.01 Financial Statements and Exhibits
(d) Exhibits
| Exhibit No. | Description | ||||
10.1 | Amended and Restated Credit Agreement dated as of October 29, 2026, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto. | ||||
99.1 | Press Release dated November 4, 2026. | ||||
99.2 | Investor Presentation dated November 4, 2026. | ||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | ||||
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| RILEY EXPLORATION PERMIAN, INC. | |||||||||||
| Date: | November 4, 2026 | By: | /s/ Philip Riley | ||||||||
| Philip Riley | |||||||||||
| Chief Financial Officer and Executive Vice President of Strategy | |||||||||||
Exhibit 99.1
Riley Permian Reports Third Quarter 2026 Results
OKLAHOMA CITY, November 4, 2026 -- Riley Exploration Permian, Inc. (NYSE American: REPX) (“Riley Permian” or the “Company”), today reported financial and operating results for the third quarter ended September 30, 2026.
THIRD QUARTER 2026 HIGHLIGHTS
•Increased oil production by 20% quarter-over-quarter (+38% year-over-year) to 25.4 MBbls/d, with total equivalent production of 42.0 MBoe/d
•Grew operating cash flow 75% quarter-over-quarter (+75% year-over-year) to $111 million and $42 million of Total Free Cash Flow(1)
•Incurred total accrual capital expenditures before acquisitions of $53 million and cash capital expenditures before acquisitions of $66 million
•Reduced debt by 10% quarter-over-quarter (-35% year-over-year) to $245 million
ADDITIONAL UPDATES
•Commenced operations over the past seven weeks on new third-party water and gas infrastructure in New Mexico, including natural gas gathering and high pressure trunkline system developed over the past year
•Progressed organic resource expansion initiatives across the Red Lake asset, including evaluation of the San Andres formation with planned development activity beginning in the second quarter of 2027
•Retired 10.5% unsecured senior notes (“Senior Notes”) in October 2026
•Increased quarterly dividend by 5% to $0.42 per share in October 2026
MANAGEMENT COMMENTARY
The Company reported strong results across operating and financial metrics. Production growth was driven by new development well volumes from capital invested in prior quarters, as well as the return to production of select New Mexico wells following disruptions during the second quarter. Stronger natural gas and NGL realizations resulted in a $22 million positive swing in revenue compared to the second quarter, when we experienced negative revenue on those products. Core operating costs also improved on a per unit basis, contributing to stronger margins.
Bobby Riley, CEO and Chairman of the Board, stated, “Going forward, and based on current market conditions, we plan to continue investing significantly in the development of our assets, supported by our large and growing base of undeveloped inventory, improving third-party infrastructure conditions, and the currently supportive commodity price environment.”
___________________
(1)A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company’s website at www.rileypermian.com.
Exhibit 99.1
THIRD QUARTER 2026 OPERATIONS AND DEVELOPMENT ACTIVITY RESULTS
Average Daily Production by State
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| Total Equivalent Production (MBoe/d) | ||||||||||||||||||||||||||
| Texas | 27.7 | 17.2 | 24.1 | 17.0 | ||||||||||||||||||||||
| New Mexico | 14.3 | 15.1 | 13.2 | 10.1 | ||||||||||||||||||||||
| Total | 42.0 | 32.3 | 37.3 | 27.1 | ||||||||||||||||||||||
| Oil Production (MBbls/d) | ||||||||||||||||||||||||||
| Texas | 18.5 | 10.5 | 15.7 | 11.2 | ||||||||||||||||||||||
| New Mexico | 6.9 | 7.9 | 6.6 | 5.2 | ||||||||||||||||||||||
| Total | 25.4 | 18.4 | 22.3 | 16.4 | ||||||||||||||||||||||
Development Activity by State
| Three Months Ended September 30, 2026 | Nine Months Ended September 30, 2026 | |||||||||||||||||||||||||
Gross(1) | Net(2) | Gross(1) | Net(2) | |||||||||||||||||||||||
Wells Drilled | ||||||||||||||||||||||||||
| Texas | 5 | 4.1 | 30 | 28.5 | ||||||||||||||||||||||
| New Mexico | 8 | 4.5 | 24 | 15.6 | ||||||||||||||||||||||
| Total | 13 | 8.6 | 54 | 44.1 | ||||||||||||||||||||||
Wells Completed | ||||||||||||||||||||||||||
| Texas | 7 | 6.5 | 38 | 36.6 | ||||||||||||||||||||||
| New Mexico | 2 | 1.4 | 2 | 1.4 | ||||||||||||||||||||||
| Total | 9 | 7.9 | 40 | 38.0 | ||||||||||||||||||||||
| Wells Turned to Sales | ||||||||||||||||||||||||||
| Texas | 12 | 11.9 | 35 | 33.8 | ||||||||||||||||||||||
| New Mexico | — | — | — | — | ||||||||||||||||||||||
| Total | 12 | 11.9 | 35 | 33.8 | ||||||||||||||||||||||
(1)Gross wells are the total number of operated wells in which the Company has an interest
(2)Net wells are gross wells multiplied by our fractional working interest
Production increased in Texas for both the three months and nine months periods ending September 30, 2026, primarily from the contribution of new wells turned to sales. Year-to-date, all of the Company’s new wells turned to sales have been in Texas.
Production increased in New Mexico quarter-over-quarter primarily from the return to normal operations in most areas following shut-ins from third-party midstream constraints experienced in the second quarter. Production decreased in New Mexico year-over-year for the three months ended September 30, 2026, due to natural decline, as zero new wells were turned to sales since July 2025, while production increased year-over-year for the nine months ended September 30, 2026 as a result of workover activity and the acquisition of Silverback Exploration II, LLC and its subsidiaries on July 1, 2025.
Year-to-date, the Company drilled 44.1 net wells, completed 38.0 net wells and turned to sales 33.8 net wells. The Company exited the third quarter with 17.3 net drilled-but-uncompleted wells, including 2.6 net wells in Texas and 14.7 net wells in New Mexico, with an additional 5.9 net completed wells not yet turned to sales. Wells are scheduled to turn to sales in the coming quarters across both regions.
Exhibit 99.1
THIRD QUARTER 2026 FINANCIAL RESULTS
Revenues totaled $201 million, operating income was $107 million, operating cash flow was $111 million and net loss was $2 million, or $(0.11) per diluted share.
On a non-GAAP basis, Adjusted EBITDAX(1) was $117 million, cash flow from operations before changes in working capital(1) was $108 million, Total Free Cash Flow(1) was $42 million and Adjusted Net Income(1) was $56 million, or $2.66 per diluted share.
Average realized prices, before derivative settlements, were $83.63 per barrel of oil, $0.27 per Mcf of natural gas and $5.08 per barrel of natural gas liquids (“NGL”). Total revenues increased $35 million or 21% quarter-over-quarter, as higher volumes and positive natural gas and NGL revenue more than offset a $10.65/Bbl decline in realized oil price before derivative settlements.
The Company reported a $28 million realized loss on derivative settlements, reflecting cash settlements on financial contracts linked to crude oil prices, and a $72 million non-cash loss due to the changes in the fair value of derivatives that will settle in future periods for a combined $100 million net loss on derivatives. Unrealized derivatives reflect the accounting remeasurement of the Company’s derivative portfolio based on changes in the market value of contracts that remain open and do not represent current-period cash inflows or outflows.
Revenue net of derivative settlements increased $43 million or 33% quarter-over-quarter to $173 million, with oil accounting for 31% of the positive variance, natural gas and NGL accounting for 51% of the variance, and derivative settlements accounting for 18%.
Operating expenses included lease operating expense of $34 million, or $8.84 per Boe, which included $11 million in workover expense. Administrative costs were $9 million, or $2.27 per Boe and production and ad valorem taxes were $13 million or $3.30 per Boe.
The Company incurred $53 million in total accrued capital expenditures. On a cash basis, the Company had total capital expenditures of $66 million. The Company invested $2 million in its power-focused joint venture, RPC Power.
The Company reduced total debt by $28 million, including a $23 million decrease on the Credit Facility and $5 million reduction on the Senior Notes. As of September 30, 2026, the Company had $115 million of borrowings outstanding on its Credit Facility and $130 million principal value of its Senior Notes, for a combined principal value of debt of $245 million. Interest expense, net was $7 million.
The Company paid a cash dividend of $0.40 per share, for a total of $8 million. Subsequent to quarter-end, the Company declared a cash dividend of $0.42 per share, a 5% increase from the prior quarter. The Company completed zero buybacks during the quarter. As of September 30, 2026, there were 22.15 million shares outstanding, including unvested shares, a year-over-year increase of 0.7%.
INFRASTRUCTURE UPDATES
In December of 2025, we contracted with Targa Northern Delaware LLC (“Targa”) to construct new gathering and high-pressure trunkline infrastructure in Eddy County, New Mexico pursuant to the A&R Gas Purchase Agreement, to mitigate processing and takeaway constraints. On October 1, 2026, the new Targa pipeline system was placed in service.
In January of 2026, the Company entered into a 15-year water management services agreement with Waterbridge Stateline LLC to deliver a portion of its New Mexico produced water for disposal purposes within a specified dedicated area. The in-service date occurred on September 15, 2026.
The additional natural gas infrastructure and water management services agreement are expected to improve natural gas flow assurance and expand water handling capacity to support increased development of the Company’s New Mexico acreage position.
___________________
(1)A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company’s website at www.rileypermian.com.
Exhibit 99.1
DEBT FINANCING UPDATES
On October 5, 2026, the Company voluntarily prepaid in full all of its outstanding Senior Notes, which was $130 million plus $0.2 million of accrued interest through the prepayment date. The Company funded the prepayment with borrowings under its existing revolving credit facility (“Credit Facility”).
On October 29, 2026, the Company entered into an amended and restated credit agreement to the Credit Facility, which among other things, increased the Company's borrowing base from $425 million to $450 million and increased the elected commitments from $400 million to $450 million. The maturity date was extended to October 2030, and the minimum hedging requirement was reduced to a rolling 18-month basis, down from 24 months.
POTENTIAL RESOURCE EXPANSION
The Company continues to advance geological and reservoir evaluation of the San Andres formation across its Red Lake asset, a productive interval located above the Blinebry and Paddock formations, where modern horizontal development has historically been concentrated. The Company’s evaluation incorporates well logs, seismic and other subsurface data, reservoir performance and depletion analysis, as well as recent results from industry development activity in the San Andres. Based on this work, the Company plans to allocate capital to initial development of the San Andres during the second quarter of 2027.
Exhibit 99.1
| Selected Operating and Financial Data | ||||||||||||||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||
| September 30, 2026 | June 30, 2026 | September 30, 2025 | September 30, 2026 | September 30, 2025 | ||||||||||||||||||||||||||||
Selected Financial Data (in thousands): | ||||||||||||||||||||||||||||||||
Oil and natural gas sales, net | $ | 201,203 | $ | 165,850 | $ | 106,852 | $ | 480,934 | $ | 294,703 | ||||||||||||||||||||||
Income from operations | $ | 106,725 | $ | 87,232 | $ | 28,862 | $ | 237,627 | $ | 107,118 | ||||||||||||||||||||||
| Net income (loss) | $ | (2,400) | $ | 87,370 | $ | 16,340 | $ | 14,536 | $ | 75,443 | ||||||||||||||||||||||
Adjusted EBITDAX(1) | $ | 117,287 | $ | 80,107 | $ | 64,041 | $ | 258,327 | $ | 194,514 | ||||||||||||||||||||||
Cash flow from operations | $ | 111,303 | $ | 63,500 | $ | 63,650 | $ | 221,979 | $ | 147,671 | ||||||||||||||||||||||
Upstream accrual capital expenditures | $ | 53,114 | $ | 86,599 | $ | 13,129 | $ | 186,800 | $ | 54,581 | ||||||||||||||||||||||
Upstream cash capital expenditures | $ | 65,446 | $ | 67,931 | $ | 14,893 | $ | 163,507 | $ | 56,467 | ||||||||||||||||||||||
Total accrual capital expenditures | $ | 53,114 | $ | 86,599 | $ | 18,019 | $ | 186,800 | $ | 69,805 | ||||||||||||||||||||||
Total cash capital expenditures | $ | 65,581 | $ | 68,287 | $ | 29,027 | $ | 165,052 | $ | 76,895 | ||||||||||||||||||||||
Upstream Free Cash Flow(1) | $ | 42,486 | $ | 6,613 | $ | 39,441 | $ | 73,653 | $ | 99,998 | ||||||||||||||||||||||
Total Free Cash Flow(1) | $ | 42,351 | $ | 6,257 | $ | 25,307 | $ | 72,108 | $ | 79,570 | ||||||||||||||||||||||
| Production Data, net: | ||||||||||||||||||||||||||||||||
| Oil (MBbls) | 2,340 | 1,933 | 1,690 | 6,087 | 4,478 | |||||||||||||||||||||||||||
| Natural gas (MMcf) | 3,898 | 3,241 | 3,380 | 10,920 | 7,821 | |||||||||||||||||||||||||||
NGLs (MBbls) | 876 | 645 | 722 | 2,281 | 1,609 | |||||||||||||||||||||||||||
Total equivalent (MBoe) | 3,866 | 3,118 | 2,975 | 10,188 | 7,391 | |||||||||||||||||||||||||||
Daily equivalent production (Boe/d) | 42,022 | 34,264 | 32,337 | 37,319 | 27,073 | |||||||||||||||||||||||||||
Daily oil production (Bbls/d) | 25,435 | 21,242 | 18,370 | 22,297 | 16,403 | |||||||||||||||||||||||||||
Average Realized Prices:(2) | ||||||||||||||||||||||||||||||||
| Oil ($ per Bbl) | $ | 83.63 | $ | 94.28 | $ | 63.94 | $ | 82.62 | $ | 65.33 | ||||||||||||||||||||||
| Natural gas ($ per Mcf) | $ | 0.27 | $ | (4.12) | $ | (0.21) | $ | (1.71) | $ | 0.00 | ||||||||||||||||||||||
NGLs ($ per Bbl) | $ | 5.08 | $ | (4.71) | $ | (0.66) | $ | (1.46) | $ | 1.34 | ||||||||||||||||||||||
Average Realized Prices, including the effects of derivative settlements:(2)(3) | ||||||||||||||||||||||||||||||||
| Oil ($ per Bbl) | $ | 71.61 | $ | 74.25 | $ | 65.17 | $ | 69.70 | $ | 67.28 | ||||||||||||||||||||||
| Natural gas ($ per Mcf) | $ | 0.26 | $ | (3.33) | $ | (0.16) | $ | (1.48) | $ | (0.02) | ||||||||||||||||||||||
| NGLs ($ per Bbl) | $ | 5.08 | $ | (4.71) | $ | (0.66) | $ | (1.46) | $ | 1.34 | ||||||||||||||||||||||
Basic weighted average common shares outstanding (in thousands)(4) | 20,945 | 20,937 | 21,164 | 20,918 | 21,139 | |||||||||||||||||||||||||||
Diluted weighted average common shares outstanding (in thousands)(5) | 20,945 | 21,255 | 21,263 | 21,221 | 21,178 | |||||||||||||||||||||||||||
(1)A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company’s website at www.rileypermian.com.
(2)The Company's oil, natural gas and NGL sales are presented net of gathering, processing and transportation costs. These costs, related to natural gas and NGLs, at times exceeded the price received and resulted in negative average realized prices.
(3)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of our commodity derivative contracts. These realized gains (losses), along with unrealized gains (losses) from changes in the fair value of derivatives, are included under other income (expense) on the Company’s condensed consolidated statements of operations.
(4)Excludes all unvested shares.
(5)Excludes potentially dilutive shares that would have been anti-dilutive. Performance shares are included based on performance achieved through September 30, 2026. For periods with a net loss, all potentially dilutive securities are excluded, as their effect would be anti-dilutive.
Exhibit 99.1
2026 GUIDANCE
Riley Permian is providing fourth quarter detailed guidance based on currently scheduled development activity and current market conditions. The average working interest on gross operated wells drilled is subject to change and may have corresponding impacts on net production volumes and investing expenditures.
| Activity and Production | Q4 2026 | |||||||
| Net Operated Well Activity | ||||||||
| Drilled (#) | 13 - 17 | |||||||
| Completed (#) | 13 - 17 | |||||||
| Turned to Sales (#) | 14 - 18 | |||||||
| Non-Operated, Net (#) | 0 - 1 | |||||||
| Net Production | ||||||||
| Oil (MBbls/d) | 25.5 - 26.5 | |||||||
| Total Equivalent (MBoe/d) | 42.5 - 43.5 | |||||||
Capital Expenditures and Investments (in millions)(1) | ||||||||
| Upstream | $60 - $70 | |||||||
| Infrastructure and Other | $14 - $16 | |||||||
| Total Capital Expenditures | $74 - $86 | |||||||
| Power JV Investment | $2 | |||||||
| Total Investments | $76 - $88 | |||||||
| Operating and Corporate Costs | Q4 2026 | |||||||
Lease Operating Expenses ($ per Boe) | $8.75 - $9.75 | |||||||
| Production and Ad Valorem Taxes (% of Revenue) | 7.5% - 8.5% | |||||||
Administrative Costs ($ per Boe) | $2.00 - $2.50 | |||||||
___________________
(1)Accrual (activity-based) investing expenditures before acquisitions
Exhibit 99.1
CONFERENCE CALL
In connection with the earnings release, Riley Permian management will host a conference call for investors and analysts on November 5, 2026 at 9:00 a.m. CT to discuss the Company's results and to host a Q&A session. Interested parties are invited to participate by calling:
In connection with the earnings release, Riley Permian management will host a conference call for investors and analysts on November 5, 2026 at 9:00 a.m. CT to discuss the Company's results and to host a Q&A session. Interested parties are invited to participate by calling:
•Toll Free Dial-In, +1 (833) 461-5787
•Toll Dial-in, +1 (585) 542-9983
•Meeting ID number 124 912 180
An updated company presentation, which will include certain items to be discussed on the call, will be posted prior to the call on the Company's website (www.rileypermian.com).
A replay of the call will be available until November 19, 2026 by calling:
•Toll Free Dial-In, +1 (833) 309-1852
•Meeting ID number 124 912 180
About Riley Exploration Permian, Inc.
Riley Permian is a growth-oriented upstream oil and gas company operating in Texas and New Mexico with infrastructure projects that complement our operations. For more information, please visit www.rileypermian.com.
Riley Permian is a growth-oriented upstream oil and gas company operating in Texas and New Mexico with infrastructure projects that complement our operations. For more information, please visit www.rileypermian.com.
Investor Contact:
Ben McQueen
405-438-0126
IR@rileypermian.com
Exhibit 99.1
Cautionary Statement Regarding Forward Looking Information and Guidance
This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements contained in this release that are not historical facts are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position and potential growth opportunities. Our forward-looking statements do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the words “believes,” “intends,” “may,” “should,” “anticipates,” “expects,” “could,” “plans,” “estimates,” “projects,” “targets,” “forecasts” or comparable terminology or by discussions of strategy or trends. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this release are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.
Among the factors that could cause actual future results to differ materially are the risks and uncertainties the Company is exposed to. While it is not possible to identify all factors, we continue to face many risks and uncertainties including, but not limited to: the volatility of oil, natural gas and NGL prices, including basis differentials between published indices and the prices we actually receive for our production; regional supply and demand factors, any delays, curtailment delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits; cost and availability of gathering, pipeline, refining, transportation, power and other midstream and downstream activities, which could result in a prolonged shut-in of our wells that may adversely affect our reserves, financial condition and results of operations; severe weather and other risks that lead to a lack of any available markets; our ability to successfully complete mergers, acquisitions or divestitures; the inability or failure of the Company to successfully integrate the acquired assets into our operations and development activities; the potential delays in the development, construction or start-up of planned projects; failure to realize any of the anticipated benefits of our joint ventures or other equity investments; risks relating to our operations, including development drilling and testing results and performance of acquired properties and newly drilled wells, including uncertainties in San Andres development, well spacing and the applicability of offset-well results to our acreage; inability to prove up undeveloped acreage and maintain production on leases; any reduction in our borrowing base on our Credit Facility from time to time and our ability to repay any excess borrowings as a result of such reduction; the impact of our derivative strategy and the results of future settlement; our ability to comply with the financial covenants contained in our Credit Facility and Senior Notes; changes in general economic, business or industry conditions, including changes in inflation rates, interest rates and foreign currency exchange rates; conditions in the capital, financial and credit markets and our ability to obtain capital needed to fund our exploration and development on favorable terms or at all; the loss of certain tax deductions; risks associated with executing our business strategy, including any changes in our strategy; risks associated with concentration of operations in one major geographic area; legislative or regulatory changes, including initiatives related to hydraulic fracturing, regulation of greenhouse gases, water conservation, seismic activity, weatherization, or protection of certain species of wildlife, or of sensitive environmental areas; the ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be restricted by governmental regulation and legislation; restrictions on the use of water, including limits on the use of produced water and any potential moratorium on new produced water well permits recently imposed by the Railroad Commission of Texas or New Mexico Oil Conservation Division in an effort to control induced seismicity in the Permian Basin; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; public health crisis, such as pandemics and epidemics, and any related government policies and actions and the effects of such public health crises on the oil and natural gas industry, pricing and demand for oil and natural gas and supply chain logistics; general domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries and changes to the current political environment under the current administration; risks related to litigation; and cybersecurity threats, technology system failures and data security issues.
The estimates and guidance presented in this release are based on assumptions of current and future capital expenditure levels, prices for oil, natural gas and NGLs, available liquidity, indications of supply and demand for oil, well results, operating costs and the timing and completion of pending projects and acquisitions. The guidance provided in this release does not constitute any form of guarantee or assurance that the matters indicated will be achieved. While we believe these estimates and the assumptions on which they are based are reasonable as of the date on which they are made, they are inherently uncertain and are subject to, among other things, significant business, economic, operational, and regulatory risks, and uncertainties, some of
Exhibit 99.1
which are not known as of the date of the statement. Guidance and estimates, and the assumptions on which they are based, are subject to material revision. Actual results may differ materially from estimates and guidance.
Please read the "Risk Factors" in our annual report on Form 10-K and our quarterly reports on Form 10-Q, which are incorporated herein. Additional factors that could cause results to differ materially from those described above can be found in Riley Permian’s Annual Report on Form 10-K for the year ended December 31, 2025 filed with the SEC and available from the Company’s website at www.rileypermian.com under the “Investor” tab, and in other documents the Company files with the SEC.
The forward-looking statements in this press release are made as of the date hereof and are based on information available at that time. The Company does not undertake, and expressly disclaims, any duty to update or revise our forward-looking statements based on new information, future events or otherwise.
Exhibit 99.1
| RILEY EXPLORATION PERMIAN, INC. | ||||||||||||||
CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||||||||
| (Unaudited) | ||||||||||||||
| September 30, 2026 | December 31, 2025 | |||||||||||||
| (In thousands, except share amounts) | ||||||||||||||
| Assets | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash | $ | 26,833 | $ | 17,889 | ||||||||||
| Accounts receivable, net | 92,010 | 41,045 | ||||||||||||
| Prepaid expenses | 3,591 | 7,763 | ||||||||||||
| Inventory | 5,305 | 7,929 | ||||||||||||
| Current derivative assets | 89 | 19,141 | ||||||||||||
| Total Current Assets | 127,828 | 93,767 | ||||||||||||
| Oil and natural gas properties, net (successful efforts) | 1,109,695 | 995,539 | ||||||||||||
| Other property and equipment, net | 23,623 | 21,872 | ||||||||||||
| Non-current derivative assets | 829 | 5,117 | ||||||||||||
| Equity method investment | 44,184 | 36,188 | ||||||||||||
| Funds held in escrow | — | 1,196 | ||||||||||||
| Other non-current assets, net | 14,450 | 15,899 | ||||||||||||
| Total Assets | $ | 1,320,609 | $ | 1,169,578 | ||||||||||
| Liabilities and Shareholders' Equity | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Accounts payable | $ | 36,025 | $ | 5,083 | ||||||||||
| Accrued liabilities | 52,475 | 37,690 | ||||||||||||
| Revenue payable | 91,447 | 59,606 | ||||||||||||
| Current derivative liabilities | 85,481 | 37 | ||||||||||||
| Current portion of long-term debt | 20,000 | 20,000 | ||||||||||||
| Other current liabilities | 24,016 | 34,089 | ||||||||||||
| Total Current Liabilities | 309,444 | 156,505 | ||||||||||||
| Non-current derivative liabilities | 8,821 | 112 | ||||||||||||
| Asset retirement obligations | 64,089 | 59,977 | ||||||||||||
| Long-term debt | 220,316 | 227,855 | ||||||||||||
| Deferred tax liabilities | 87,897 | 86,119 | ||||||||||||
| Other non-current liabilities | 3,859 | 4,768 | ||||||||||||
| Total Liabilities | 694,426 | 535,336 | ||||||||||||
| Commitments and Contingencies | ||||||||||||||
| Shareholders' Equity: | ||||||||||||||
Preferred stock, $0.0001 par value, 25,000,000 shares authorized; 0 shares issued | — | — | ||||||||||||
Common stock, $0.001 par value, 240,000,000 shares authorized; 22,153,785 and 21,718,800 shares issued at September 30, 2026 and December 31, 2025, respectively | 22 | 22 | ||||||||||||
| Additional paid-in capital | 310,138 | 306,660 | ||||||||||||
| Retained earnings | 316,023 | 327,560 | ||||||||||||
| Total Shareholders' Equity | 626,183 | 634,242 | ||||||||||||
| Total Liabilities and Shareholders' Equity | $ | 1,320,609 | $ | 1,169,578 | ||||||||||
Exhibit 99.1
| RILEY EXPLORATION PERMIAN, INC. | ||||||||||||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||
| Oil and natural gas sales, net | $ | 201,203 | $ | 106,852 | $ | 480,934 | $ | 294,703 | ||||||||||||||||||
| Total Revenues | 201,203 | 106,852 | 480,934 | 294,703 | ||||||||||||||||||||||
| Costs and Expenses: | ||||||||||||||||||||||||||
| Lease operating expenses | 34,173 | 26,874 | 87,677 | 64,085 | ||||||||||||||||||||||
| Production and ad valorem taxes | 12,764 | 8,278 | 33,226 | 21,074 | ||||||||||||||||||||||
| Exploration costs | 2,086 | 217 | 3,519 | 273 | ||||||||||||||||||||||
| Depletion, depreciation, amortization and accretion | 32,478 | 27,214 | 82,849 | 65,915 | ||||||||||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | 1,214 | ||||||||||||||||||||||
| General and administrative: | ||||||||||||||||||||||||||
| Administrative costs | 8,784 | 9,922 | 25,624 | 23,559 | ||||||||||||||||||||||
| Stock-based compensation expense | 4,169 | 2,688 | 10,388 | 6,742 | ||||||||||||||||||||||
| Transaction costs | 24 | 2,797 | 24 | 4,723 | ||||||||||||||||||||||
| Total Costs and Expenses | 94,478 | 77,990 | 243,307 | 187,585 | ||||||||||||||||||||||
| Income from Operations | 106,725 | 28,862 | 237,627 | 107,118 | ||||||||||||||||||||||
| Other Income (Expense): | ||||||||||||||||||||||||||
| Interest expense, net | (6,731) | (9,606) | (19,858) | (23,438) | ||||||||||||||||||||||
| Gain (loss) on derivatives, net | (99,838) | 1,920 | (193,573) | 14,790 | ||||||||||||||||||||||
| Loss from equity method investment | (181) | (19) | (504) | (267) | ||||||||||||||||||||||
| Loss on acquisitions and divestitures, net | (3,254) | — | (4,990) | — | ||||||||||||||||||||||
| Total Other Income (Expense) | (110,004) | (7,705) | (218,925) | (8,915) | ||||||||||||||||||||||
| Net Income (Loss) from Operations before Income Taxes | (3,279) | 21,157 | 18,702 | 98,203 | ||||||||||||||||||||||
| Income tax benefit (expense) | 879 | (4,817) | (4,166) | (22,760) | ||||||||||||||||||||||
| Net Income (Loss) | $ | (2,400) | $ | 16,340 | $ | 14,536 | $ | 75,443 | ||||||||||||||||||
| Net Income (Loss) per Share: | ||||||||||||||||||||||||||
| Basic | $ | (0.11) | $ | 0.77 | $ | 0.69 | $ | 3.57 | ||||||||||||||||||
| Diluted | $ | (0.11) | $ | 0.77 | $ | 0.68 | $ | 3.56 | ||||||||||||||||||
| Weighted Average Common Shares Outstanding: | ||||||||||||||||||||||||||
| Basic | 20,945 | 21,164 | 20,918 | 21,139 | ||||||||||||||||||||||
| Diluted | 20,945 | 21,263 | 21,221 | 21,178 | ||||||||||||||||||||||
Exhibit 99.1
| RILEY EXPLORATION PERMIAN, INC. | ||||||||||||||||||||||||||
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Cash Flows from Operating Activities: | ||||||||||||||||||||||||||
| Net income (loss) | $ | (2,400) | $ | 16,340 | $ | 14,536 | $ | 75,443 | ||||||||||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||||||
| Exploration costs | 2,086 | 202 | 3,465 | 212 | ||||||||||||||||||||||
| Depletion, depreciation, amortization and accretion | 32,478 | 27,214 | 82,849 | 65,915 | ||||||||||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | 1,214 | ||||||||||||||||||||||
| (Gain) loss on derivatives, net | 99,838 | (1,920) | 193,573 | (14,790) | ||||||||||||||||||||||
| Settlements on derivative contracts | (28,195) | 2,263 | (76,080) | 8,529 | ||||||||||||||||||||||
| Amortization of deferred financing costs and discount | 1,193 | 1,197 | 3,560 | 3,570 | ||||||||||||||||||||||
| Stock-based compensation expense | 4,169 | 2,688 | 10,388 | 6,742 | ||||||||||||||||||||||
| Deferred income tax (benefit) expense | (3,147) | 6,331 | 1,778 | 9,371 | ||||||||||||||||||||||
| Loss from equity method investment | 181 | 19 | 504 | 267 | ||||||||||||||||||||||
| Loss on acquisitions and divestitures, net | 1,729 | — | 2,587 | — | ||||||||||||||||||||||
| Other | — | — | — | (8) | ||||||||||||||||||||||
| Changes in operating assets and liabilities | 3,371 | 9,316 | (15,181) | — | (8,794) | |||||||||||||||||||||
| Net Cash Provided by Operating Activities | 111,303 | 63,650 | 221,979 | 147,671 | ||||||||||||||||||||||
| Cash Flows from Investing Activities: | ||||||||||||||||||||||||||
| Additions to oil and natural gas properties | (65,163) | (14,292) | (162,027) | (55,230) | ||||||||||||||||||||||
| Additions to midstream property and equipment | (135) | (14,134) | (1,545) | (20,428) | ||||||||||||||||||||||
| Additions to other property and equipment | (283) | (601) | (1,480) | (1,237) | ||||||||||||||||||||||
| Net assets acquired in business combination | — | (117,827) | — | (117,827) | ||||||||||||||||||||||
| Acquisitions of oil and natural gas properties | (515) | (23) | (5,339) | (2,161) | ||||||||||||||||||||||
| Acquisitions of land | (422) | — | (970) | — | ||||||||||||||||||||||
| Proceeds from divestitures | — | — | 8,206 | — | ||||||||||||||||||||||
| Contributions to equity method investment | (2,000) | (8,500) | (8,500) | (14,750) | ||||||||||||||||||||||
| Distributions from equity method investment | — | — | 1,487 | — | ||||||||||||||||||||||
| Funds held in escrow | 319 | 13,005 | 319 | (1,196) | ||||||||||||||||||||||
| Net Cash Used in Investing Activities | (68,199) | (142,372) | (169,849) | (212,829) | ||||||||||||||||||||||
| Cash Flows from Financing Activities: | ||||||||||||||||||||||||||
| Deferred financing costs | (69) | (79) | (177) | (243) | ||||||||||||||||||||||
| Proceeds from credit facility | 6,000 | 125,000 | 83,000 | 155,000 | ||||||||||||||||||||||
| Repayments under credit facility | (29,000) | (29,000) | (78,000) | (45,000) | ||||||||||||||||||||||
| Repayments of senior notes | (5,000) | (5,000) | (15,000) | (15,000) | ||||||||||||||||||||||
| Payment of earnout liability | (350) | — | (660) | — | ||||||||||||||||||||||
| Payment of cash dividends | (8,401) | (8,719) | (25,439) | (24,840) | ||||||||||||||||||||||
| Repurchase of common shares | — | — | (4,902) | — | ||||||||||||||||||||||
| Repurchase of common shares for tax withholding and other | (137) | (1,047) | (2,008) | (1,424) | ||||||||||||||||||||||
| Net Cash (Used in) Provided by Financing Activities | (36,957) | 81,155 | (43,186) | 68,493 | ||||||||||||||||||||||
| Net Increase in Cash | 6,147 | 2,433 | 8,944 | 3,335 | ||||||||||||||||||||||
| Cash, Beginning of Period | 20,686 | 14,026 | 17,889 | 13,124 | ||||||||||||||||||||||
| Cash, End of Period | $ | 26,833 | $ | 16,459 | $ | 26,833 | $ | 16,459 | ||||||||||||||||||
Exhibit 99.1
DERIVATIVE INSTRUMENTS
The Company’s oil and natural gas derivative contracts consisted of fixed price swaps, costless collars and basis swaps. The following table summarizes the open financial derivatives as of November 2, 2026, related to our future oil and natural gas production:
2026 (1) | 2027 | 2028 | ||||||||||||||||||||||||||||||||||||||||||
| Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | First Quarter | Second Quarter | ||||||||||||||||||||||||||||||||||||||
| Oil | ||||||||||||||||||||||||||||||||||||||||||||
| WTI Oil Swaps | ||||||||||||||||||||||||||||||||||||||||||||
| Volume (Bbl) | 820,000 | 725,000 | 690,000 | 630,000 | 605,000 | 330,000 | ||||||||||||||||||||||||||||||||||||||
| Weighted average price ($/Bbl) | $ | 61.42 | $ | 61.48 | $ | 62.72 | $ | 61.38 | $ | 61.62 | $ | 70.18 | ||||||||||||||||||||||||||||||||
| WTI Oil Collars | ||||||||||||||||||||||||||||||||||||||||||||
| Volume (Bbl) | 550,000 | 475,000 | 537,000 | 530,000 | 465,000 | 270,000 | 90,000 | |||||||||||||||||||||||||||||||||||||
| Weighted average floor price ($/Bbl) | $ | 57.75 | $ | 57.15 | $ | 55.84 | $ | 55.57 | $ | 58.23 | $ | 56.67 | $ | 60.00 | ||||||||||||||||||||||||||||||
| Weighted average ceiling price ($/Bbl) | $ | 69.59 | $ | 66.42 | $ | 67.97 | $ | 70.51 | $ | 76.92 | $ | 75.77 | $ | 80.65 | ||||||||||||||||||||||||||||||
| Natural Gas | ||||||||||||||||||||||||||||||||||||||||||||
Henry Hub Natural Gas Swaps | ||||||||||||||||||||||||||||||||||||||||||||
| Volume (MMBtu) | 500,000 | 600,000 | ||||||||||||||||||||||||||||||||||||||||||
| Weighted average price ($/MMBtu) | $ | 4.07 | $ | 4.19 | ||||||||||||||||||||||||||||||||||||||||
Henry Hub Natural Gas Collars | ||||||||||||||||||||||||||||||||||||||||||||
| Volume (MMBtu) | 600,000 | 450,000 | ||||||||||||||||||||||||||||||||||||||||||
| Weighted average floor price ($/MMBtu) | $ | 3.43 | $ | 3.80 | ||||||||||||||||||||||||||||||||||||||||
| Weighted average ceiling price ($/MMBtu) | $ | 4.79 | $ | 5.84 | ||||||||||||||||||||||||||||||||||||||||
| Waha Basis Swaps | ||||||||||||||||||||||||||||||||||||||||||||
| Volume (MMBtu) | 3,450,000 | 3,150,000 | 3,150,000 | 3,150,000 | 3,150,000 | 1,800,000 | ||||||||||||||||||||||||||||||||||||||
| Weighted average price ($/MMBtu) | $ | (1.58) | $ | (0.94) | $ | (0.95) | $ | (0.95) | $ | (0.95) | $ | (1.01) | ||||||||||||||||||||||||||||||||
___________________
(1)Q4 2026 derivative positions shown include 2026 contracts, some of which have settled as of November 2, 2026.
Interest Rate Contracts
The following table summarizes the open interest rate derivative positions as of November 2, 2026:
| Open Coverage Period | Position | Notional Amount | Fixed Rate | |||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| November 2026 - April 2027 | Long | $ | 45,000 | 3.90 | % | |||||||||||||||
3Q’26 Investor Presentation November 2026
2 Forward-Looking Statements This presentation contains projections and other forward-looking statements within the meaning of federal securities laws. These projections and statements reflect Riley Exploration Permian, Inc.’s (“Riley Permian”) current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in Riley Permian’s periodic reports filed with the U.S. Securities and Exchange Commission (“SEC”). All statements, other than historical facts, that address activities that Riley Permian assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events, including the volatility of oil, natural gas and NGL prices, including basis differentials between published indices and the prices we actually receive for our production; regional supply and demand factors, any delays, curtailment delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits; cost and availability of gathering, pipeline, refining, transportation, power and other midstream and downstream activities, which could result in prolonged shut-in of our wells that may adversely affect our reserves, financial condition and results of operations; severe weather and other risks that lead to a lack of any available markets; our ability to successfully complete mergers, acquisitions or divestitures; the inability or failure of the Company to successfully integrate the acquired assets into its operations and development activities; the potential delays in the development, construction or start-up of planned projects; failure to realize any of the anticipated benefits of our joint ventures or other equity investments; risks relating to our operations, including development drilling and testing results and performance of acquired properties and newly drilled wells, including uncertainties in San Andres development, well spacing and the applicability of offset-well results to our acreage; inability to prove up undeveloped acreage and maintain production on leases; any reduction in our borrowing base on our revolving credit facility from time to time and our ability to repay any excess borrowings as a result of such reduction; the impact of our derivative strategy and the results of future settlement; our ability to comply with the financial covenants contained in our credit facility; changes in general economic, business or industry conditions, including changes in inflation rates, interest rates and foreign currency exchange rates; conditions in the capital, financial and credit markets and our ability to obtain capital needed to fund our exploration and development on favorable terms or at all; the loss of certain tax deductions; risks associated with executing our business strategy, including any changes in our strategy; risks associated with concentration of operations in one major geographic area; legislative or regulatory changes, including initiatives related to hydraulic fracturing, regulation of greenhouse gases, water conservation, seismic activity, weatherization, or protection of certain species of wildlife, or of sensitive environmental areas; the ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be restricted by governmental regulation and legislation; restrictions on the use of water, including limits on the use of produced water and any potential moratorium on new produced water well permits imposed by the RRC or NMOCD in an effort to control induced seismicity in the Permian Basin; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; public health crises, such as pandemics and epidemics, and any related government policies and actions and the effects of such public health crises on the oil and natural gas industry, pricing and demand for oil and natural gas and supply chain logistics; general domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries and changes to the current political environment under the current administration; risks related to litigation; and cybersecurity threats, technology system failures and data security issues. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Riley Permian. These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Riley Permian encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, Riley Permian assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances. For additional discussion of the factors that may cause us not to achieve our financial projections and/or production estimates, see Riley Permian’s filings with the SEC, including its forms 10-K, 10-Q and 8-K and any amendments thereto. We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective data or to update this prospective data to reflect events or circumstances after the date of this presentation. Therefore, you are cautioned not to place undue reliance on this information. None of the information contained in this presentation has been audited by any independent auditor. This presentation is prepared as a convenience for securities analysts and investors and may be useful as a reference tool. Riley Permian may elect to modify the format or discontinue publication at any time, without notice to securities analysts or investors. Use of non-GAAP Financial Information This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). These measures include (i) Adjusted Net Income, (ii) Adjusted EBITDAX, and (iii) Free Cash Flow (including Upstream Free Cash Flow and Total Free Cash Flow). These non-GAAP financial measures are not measures of financial performance prepared or presented in accordance with GAAP and may exclude items that are significant in understanding and assessing our financial results. Therefore, these measures should not be considered in isolation, and users of any such information should not place undue reliance thereon. See the Company’s website, www.rileypermian.com, for the descriptions and reconciliations of non-GAAP measures presented in this presentation to the most directly comparable financial measures calculated in accordance with GAAP. Oil & Gas Reserves The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, Riley Permian may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to Riley Permian’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by Riley Permian to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by Riley Permian to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on Riley Permian’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential or “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from Riley Permian’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of Riley Permian’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of Riley Permian’s core assets provides additional data. In addition, Riley Permian’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. We use terms such as “reserve inventory,” “inventory,” “development locations,” “locations,” “potential development locations,” and “potential upside locations” in this presentation to describe estimated volumes of hydrocarbon resources potentially recoverable through additional drilling or recovery techniques but which may not have been demonstrated to be commercially or technically recoverable or are not contemplated to be developed within five years of being booked. We also caution you that the SEC views such estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the oil and gas industry. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. Investors are urged to consider closely the disclosure in our form 10-K that is available at www.sec.gov. Forward-Looking Statements
3 Riley Permian Overview Riley Permian is a growth-oriented upstream company operating in the Northwest Shelf of Texas and New Mexico, with infrastructure projects that complement our operations Applying modern horizontal drilling and completion techniques to conventional, oil-saturated and liquids-rich formations Prioritizing long-term value creation and resilience through commodity cycles ~$1.3 B Enterprise Value(1) 42.0 MBoe/d 3Q’26 Daily Equivalent Production ~$1.1 B Market Capitalization(1) 0.8x LTM Leverage(3) ~400 Development Locations(2) Riley Permian by the Numbers (1) Enterprise Value, Market Capitalization and Dividend Yield based on share price and shares outstanding as of 11/2/26, debt balance and cash balance as of 9/30/26 (2) Company prepared estimates as of 9/30/26; Potential San Andres locations and spacing remain subject to evaluation and do not establish proved reserves or commercial viability. Actual development may differ based on drilling results, economics, capital, infrastructure and approvals. There is no assurance any location will be drilled (3) Leverage calculated as debt as of 9/30/26 divided by Last Twelve Months Adjusted EBITDAX as of 9/30/26 (4) A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company’s website at www.rileypermian.com (5) Future dividends subject to approval by the Board of Directors (6) Based on SEC filings. Insiders include Yorktown (including direct fund entities and Riley Exploration Group LLC), Management, Directors & Other Unvested awards 3.5% Dividend Yield(1)(5) 61% 3Q’26 % Oil Production 25.4 MBbls/d 3Q’26 Daily Oil Production 19% Debt / Enterprise Value(1) 17% Insider Ownership(6) $324 MM LTM Adjusted EBITDAX(4)
4 Riley Permian Asset Overview (1) Company prepared estimates as of 9/30/26 (2) Represents net operated producing horizontal wells as of 9/30/26 (3) Potential San Andres locations and spacing remain subject to evaluation and do not establish proved reserves or commercial viability. Actual development may differ based on drilling results, economics, capital, infrastructure and approvals. There is no assurance any location will be drilled Riley Permian operates in the Northwest Shelf of the Permian Basin in Yoakum County, TX and Eddy County, NM Champions Field – Yoakum County, TX Primary Formation Target: ▪ San Andres Net Acres (% HBP)(1): ▪ ~31,000 Net Acres (88% HBP) Net Operated Hz Wells(2): ▪ ~152 Undeveloped Net Locations(1): ▪ ~70 Red Lake Field – Eddy County, NM Primary Formation Targets: ▪ Blinebry and Paddock (Yeso) Additional Formation Targets: ▪ San Andres Net Acres (% HBP)(1): ▪ ~62,000 Net Acres (97% HBP) Net Operated Hz Wells(2): ▪ ~59 Undeveloped Net Locations(1)(3): ▪ ~330 Yoakum Co. Delaware Basin Yeso Trend Central Basin Platform Eddy Co. N E W M E X I C O T E X A S Red Lake Acquisitions: Pecos (2023) Undisclosed Seller (2024) Silverback (2025) Red Lake Champions Northwest Shelf 30 MilesTexasNew Mexico 3Q’26 Total Prod. 42.0 MBoe/d 3Q’26 Oil Prod. 25.4 MBbls/d ~400 Net Locs. Net Locations(1)(3)
5 San Andres Activity Supports Potential Additional Red Lake Inventory San Andres Development ActivitySan Andres Development Opportunity ▪ Multiple industry San Andres horizontal wells traverse the REPX footprint with active industry permits showing continued momentum ▪ Internal Riley Permian geologic analysis identifies up to 4 San Andres wells per square mile for horizontal development ▪ REPX plans for 6 San Andres horizontal wells in its 2027 drilling program in co-development alongside Paddock and Blinebry staggered horizontals 1-Mile San Andres ▪ Emerging development target Paddock ▪ Established development target Blinebry ▪ Established development target Deeper Targets ▪ Future prospective targets 1-MileRed Lake Development Column C o- de ve lo pm en t Yeso Trend Eddy County REPX Red Lake Acreage Offset Operator Producing / Completed Hz Offset Operator DUC Hz Offset Operator Permitted Hz Note: Potential San Andres locations and spacing remain subject to evaluation and do not establish proved reserves or commercial viability. Actual development may differ based on drilling results, economics, capital, infrastructure and approvals. There is no assurance any location will be drilled Delaware Basin NM TX Illustrative Development Concept
6 Riley Permian Has a Deep, High-Value Inventory Base Oil Production Rates over Time Bbls/d per 1,000’ of Lateral Length il Production Rates Over Time(1) l / r , ’ f t r l t Wells to date have experienced lower relative declines versus Midland and Delaware Basin wells Cumulative Oil Prod. Over Time(1) Bbls Produced per Foot of Lateral Length Wells to date have outperformed Midland and Delaware Basin wells on a 5-year basis Riley Permian Midland Delaware Net Locations by DROI(2)(3) Net Undeveloped Location Count >1.0x DROI ~400(3) high, cash-on-cash return, undeveloped drilling locations (1) Riley Permian, Midland Basin and Delaware Basin production characteristics are a composite of horizontal wells with first production from 2019-2025. Data sourced from Enverus (2) DROI refers to discounted return on investment, which is defined as the present value at a 10% discount rate of future net cash flows excluding capital expenditures divided by the net capital expenditures associated with the development of a horizontal well. Location count based on Company prepared estimates as of 9/30/26. Cash flows for DROI of undeveloped locations calculated using strip as of 9/30/26 (3) Potential San Andres locations and spacing remain subject to evaluation and do not establish proved reserves or commercial viability. Actual development may differ based on drilling results, economics, capital, infrastructure and approvals. There is no assurance any location will be drilled Riley Permian wells benefit from high production rates, shallow declines and low well costs 1 10 100 12 24 36 48 60 Av er ag e D ai ly P ro du ct io n Ra te Months from First Production 20 40 60 12 24 36 48 60 C um ul at iv e O il Pr od uc tio n Months from First Production
7 Scaling the Business While Limiting Dilution and Reducing Debt Oil Production (MBbls/d) Shares Outstanding (MM)(2) Total Debt ($MM)(3)Adjusted EBITDAX ($MM)(1) (1) A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company’s website at www.rileypermian.com (2) Represents common shares outstanding as of 9/30/23 and 9/30/26, respectively (3) Represents total principal value of debt outstanding as of 9/30/23 and 9/30/26, respectively
8 Track Record of Returning Capital to Shareholders Notes: Dividend Yield based on share price as of 11/2/26. Future dividends subject to approval by the Board of Directors. On 10/14/26, Riley announced 3Q’26 dividend to be paid on 11/11/26 History of paying a fixed dividend every quarter as a public company ▪ Track record of raising dividend annually ▪ 3.5% current dividend yield Share Repurchases ▪ Announced $100MM share repurchase authorization in December 2025 Debt Reduction ▪ Value accrues directly to equity holders 1 2 3
9 Notes: The non-GAAP financial measures include Adjusted EBITDAX, Total Free Cash Flow and Cash Provided by Operating Activities before changes in working capital are defined in the supplemental financial tables available on the company’s website at www.rileypermian.com. Accrual based capex excludes the impact of acquisitions and contributions to equity method investments (Power JV). LTM Leverage calculated as Debt as of 9/30/26 divided by Last Twelve Months Adjusted EBITDAX as of 9/30/26. Last Twelve Months (LTM) represents a sum of 10/1/25 through 9/30/26. Future dividends subject to approval by the Board of Directors; Potential San Andres locations and spacing remain subject to evaluation and do not establish proved reserves or commercial viability. Actual development may differ based on drilling results, economics, capital, infrastructure and approvals. There is no assurance any location will be drilled 3Q’26 and Recent Highlights Total Daily Production 42.0 MBoe/d Daily Oil Production 25.4 MBbls/d Total Free Cash Flow Adjusted EBITDAX $117 $MM Total Accrual Capex $53 $MM Operating Cash Flow $111 $MM $42 $MM Key Results 3Q’26 Completion activity and wells turned to sales focused in TX in 3Q’26 ▪ Texas: 4.1 net wells drilled, 6.5 net wells completed and 11.9 net wells turned to sales ▪ New Mexico: 4.5 net wells drilled, 1.4 net wells completed and no wells turned to sales Total production and oil production +30% YoY and +38% YoY, respectively Incurred $53MM of accrual basis capital expenditures (with $66MM on a cash basis) ▪ Invested $2MM in our power-focused joint venture, RPC Power Reported $111MM of Operating Cash Flow or $108MM before changes in working capital ▪ Generated $42MM of Total Free Cash Flow Increased cash dividend by 5% to $0.42 per share to be paid in November ▪ Paid cash dividend of $0.40 per share, for a total of $8MM during 3Q’26 Debt decreased by $28MM with a quarter-end debt-to-LTM Adjusted EBITDAX ratio of 0.8x ▪ In October, the Company prepaid in full all outstanding 10.5% unsecured senior notes In October new gathering and high-pressure trunkline infrastructure constructed by Targa in Eddy County, New Mexico was placed in service and commenced receiving natural gas volumes Advanced organic resource expansion initiatives across the Red Lake asset, including evaluation of the San Andres formation and planned development activity beginning in 2Q’27
10 4Q’26 Guidance (1) Accrual (activity-based) investing expenditures before acquisitions; Total accrual capex and total cash capex year to date are $187MM and $165MM, respectively Q4 2026 Metric Guidance Activity and Production Net Operated Well Activity Drilled # 13 - 17 Completed # 13 - 17 Turned to Sales # 14 - 18 Non-Operated, Net # 0 - 1 Net Production Oil MBbls/d 25.5 - 26.5 Total Equivalent MBoe/d 42.5 - 43.5 Capital Expenditures and Investments(1) Upstream $MM $60 - $70 Infrastructure and Other $MM $14 - $16 Total Capital Expenditures $MM $74 - $86 Power JV Investment $MM $2 Total Investments $MM $76 - $88 Operating and Corporate Costs Lease Operating Expenses $/Boe $8.75 - $9.75 Production and Ad Valorem Taxes % of Revenue 7.5% - 8.5% Administrative Costs $/Boe $2.00 - $2.50
11 Quarterly Oil Production (MBbls/d) Quarterly Accrual Capex ($MM) Continuation of Growth into 2027 Illustrative Company Estimates at $70 to $90 WTI Note: Forecasted metrics based on management estimates and 4Q’26 guidance. $70 WTI $90 WTIIllustrative Production Range $70 WTI $90 WTIIllustrative Capex Range
12 Quarterly Adjusted EBITDAX ($MM) Last Twelve Months (LTM) Adjusted EBITDAX ($MM) 4Q’26 and Full-Year 2027 Oil Price Sensitivities Illustrative Company Estimates at $70 to $90 WTI $70 WTI $90 WTIIllustrative EBITDAX Range $70 WTI $90 WTIIllustrative LTM EBITDAX Range Note: Forecasted metrics based on management estimates. Price sensitivity for WTI uses actual prices through October 2026 and the respective flat oil price case thereafter. Each case uses NYMEX forward monthly pricing as of 10/27/26 for Henry Hub and Waha basis differentials. Realized NGL prices based on management estimates. Includes the impact of hedges; Adjusted EBITDAX is a non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company’s website at www.rileypermian.com
13 Multiple Catalysts to Drive Continued Value Creation Resource Expansion Additional Red Lake formation targets extend potential inventory depth across the existing acreage position Improved Price Realizations Declining legacy derivatives exposure provides greater participation in prevailing commodity prices Reduced New Mexico infrastructure constraints supporting increased development activityImproved Infrastructure Backdrop Converting undeveloped inventory into producing volumes, accelerating cash flow and value realizationDifferentiated Growth Up to $60MM in future earnouts as New Mexico gas volumes rampEarnout Potential Note: Potential San Andres locations and spacing remain subject to evaluation and do not establish proved reserves or commercial viability. Actual development may differ based on drilling results, economics, capital, infrastructure and approvals. There is no assurance any location will be drilled
14 Appendix
15 REPX Capitalization and Leverage Debt Maturity Profile(4) Capitalization and Debt Maturity Profile (1) Includes 1.1MM of unvested and contingent stock awards across all employees and directors, including 414K of performance-based awards at a maximum payout potential of 200%; actual payout could range from 0% to 200%, at which time the number of actual shares outstanding will be adjusted (2) Leverage calculated as Debt as of 9/30/26 divided by Last Twelve Months Adjusted EBITDAX as of 9/30/26 (3) Liquidity consists of cash of $27MM, and $205MM undrawn on the credit facility as of 9/30/26 pro forma for senior notes repayment and amended and restated credit facility with an elected commitment of $450MM (4) Debt maturity profile pro forma as of 9/30/26 for amended and restated credit agreement and senior notes repayment $450MM Elected Commitments $MM RBL utilization RBL availability ▪ On October 29, 2026 the Company entered into an amended and restated credit agreement to the Credit Facility, which: − Increased the borrowing base and elected commitments to $450 million, from $425 million and $400 million, respectively − Extended the maturity date for the Credit Facility to October 2030, from December 2028 $245 $205 2026 2027 2028 2029 2030 MM, except share price Total Common Stock Outstanding (11/2/26)(1) 22.1 Share Price (11/2/26) $47.66 Market Capitalization $1,054 Plus: Total Debt $245 Less: Cash $27 Enterprise Value $1,272 Debt to Enterprise Value 19% LTM Leverage(2) 0.8x LTM Adjusted EBITDAX $324 Elected Commitment $450 Liquidity(3) $232
16 Equity Ownership Equity Ownership and Research Analyst Coverage Note: Based on SEC filings (1) Insiders include Yorktown, Management, Board of Directors, and other unvested shares (2) Includes affiliated entity holdings aggregated from Form 4 filings. Excludes amounts held directly by Yorktown individuals included in Management, Directors & Other Unvested awards (3) Includes 1.1MM of unvested and contingent stock awards across all employees and directors, including 414K of performance-based awards at a maximum payout potential of 200%; actual payout could range from 0% to 200%, at which time the number of actual shares outstanding will be adjusted Research Analyst Coverage Energy Prospectus Daniel Steffens dmsteffens@comcast.net Freedom Broker Sergey Pigarev sergey.pigarev@fbroker.kz Roth Capital Nick Pope npope@roth.com Texas Capital Derrick Whitfield derrick.whitfield@texascapital.com Truist Gabe Daoud gabe.daoud@truist.com Tuohy Brothers Noel Parks nparks@tuohybrothers.com Water Tower Jeff Robertson jeff@watertowerresearch.com William Blair Neal Dingmann ndingmann@williamblair.com Shares (MM) Ownership % ◉ Yorktown Energy Partners(2) 2.09 9.4% ◉ Mgmt, Directors & Other Unvested Awards(3) 1.63 7.4% 3.71 16.8% ◉ Balmon Investments(2) 2.24 10.1% ◉ BlackRock 1.13 5.1% ◉ Estimated Public Float 15.04 68.0% 22.12 100.0% >5% Holders & Insiders as of 11/2/26 (1) Total Insider Ownership Total
17 Hedging Summary Positions as of 11/2/26 Note: Q4 2026 derivative positions shown include 2026 contracts, some which have settled as of 11/2/26; Gas daily volumes are converted from MMBtu to Mcf using an assumed heat rate of 1.037 2026 2027 2028 4Q 1Q 2Q 3Q 4Q 1Q 2Q Crude Oil (WTI) Fixed Swap - Volumes MBbls 820 725 690 630 605 330 - Weighted Average Price $/Bbl $61.42 $61.48 $62.72 $61.38 $61.62 $70.18 - Collar - Volumes MBbls 550 475 537 530 465 270 90 Weighted Average Floor Price $/Bbl $57.75 $57.15 $55.84 $55.57 $58.23 $56.67 $60.00 Weighted Average Ceiling Price $/Bbl $69.59 $66.42 $67.97 $70.51 $76.92 $75.77 $80.65 Total Oil Volumes MBbls 1,370 1,200 1,227 1,160 1,070 600 90 Downside (Floor) Weighted Average Price $/Bbl $59.95 $59.77 $59.71 $58.72 $60.14 $64.10 $60.00 Upside (Ceiling) Weighted Average Price $/Bbl $64.70 $63.44 $65.02 $65.55 $68.27 $72.69 $80.65 Natural Gas (HH) Fixed Swap - Volumes BBtu 500 600 - - - - - Weighted Average Price $/MMBtu $4.07 $4.19 - - - - - Collar - Volumes BBtu 600 450 - - - - - Weighted Average Floor Price $/MMBtu $3.43 $3.80 - - - - - Weighted Average Ceiling Price $/MMBtu $4.79 $5.84 - - - - - Total Natural Gas Volumes BBtu 1,100 1,050 - - - - - Downside (Floor) Weighted Average Price $/MMBtu $3.72 $4.02 - - - - - Upside (Ceiling) Weighted Average Price $/MMBtu $4.46 $4.89 - - - - - Waha Basis Waha Basis Swap Volumes BBtu 3,450 3,150 3,150 3,150 3,150 1,800 - Weighted Average Price $/MMBtu ($1.58) ($0.94) ($0.95) ($0.95) ($0.95) ($1.01) - Total Hedged Volumes Per Day Total Oil Volumes (WTI) MBbls/d 14.9 13.3 13.5 12.6 11.6 6.6 1.0 Total Gas Volumes (HH) MMcf/d 11.5 11.3 - - - - - Total Gas Basis Volumes (Waha) MMcf/d 36.2 33.8 33.4 33.0 33.0 19.1 -