Riley Exploration Permian, Inc.

(1)Nature of Business

Organization

Riley Exploration Permian, Inc (the "Company") was formed as a Delaware limited liability company, Riley Exploration – Permian, LLC ("REP LLC"), in 2016. In February 2021, REP LLC consummated a merger pursuant to which REP LLC became a wholly-owned subsidiary of Tengasco, Inc., a Delaware corporation (“Tengasco”), and Tengasco changed its name to Riley Exploration Permian, Inc. (the "Merger"). The Company is a growth-oriented, independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGLs in Texas and New Mexico.

Our Properties

Our acreage is primarily located on large contiguous blocks in Yoakum County, Texas, which represents our Champions field and in Eddy County, New Mexico, which represents our Red Lake field. We are focused on horizontal drilling of conventional oil-saturated and liquids-rich formations that produce long-term stable cash flows in the Permian Basin.

On April 3, 2023, the Company completed an acquisition of oil and natural gas properties in the Yeso trend of the Permian Basin in Eddy County, New Mexico ("2023 New Mexico Acquisition") from Pecos Oil & Gas, LLC. This acquisition included approximately 10,600 total contiguous net acres of leasehold,18 net horizontal wells and 250 net vertical wells, which established our initial position in New Mexico.

On May 7, 2024, the Company completed an acquisition of oil and natural gas properties in the Yeso trend of the Permian Basin in Eddy County, New Mexico ("2024 New Mexico Asset Acquisition"), which added 13,900 contiguous net acres to the Company's existing acreage in Eddy County, New Mexico.

On July 1, 2025, the Company completed the acquisition of 100% of the ownership interests of Silverback Exploration II, LLC and its subsidiaries ("Silverback") which own oil and natural gas assets and operations located primarily in the Yeso trend of the Permian Basin in Eddy County, New Mexico (“Silverback Acquisition”). The acquisition added approximately 40,000 net acres directly adjacent to and overlapping with the Company's existing core acreage primarily in Eddy County, New Mexico.

For further information regarding the 2023 New Mexico Acquisition, the 2024 New Mexico Asset Acquisition, and the Silverback Acquisition, see Note 4 - Acquisitions and Divestitures.

Current Commodity Environment

The U.S. and global economies and markets have experienced heightened volatility following impactful geopolitical events, the effects of widespread inflation and the impact of significantly higher interest rates. Prices for crude oil and condensate ("oil") and natural gas are determined primarily by prevailing market conditions, which have been and could continue to be volatile.

The combination of geopolitical events, inflation and a volatile interest rate environment has led to increasing forecasts of a U.S. or global recession. Any such recession could prolong market volatility or cause a decline in commodity prices, among other potential impacts.

The Company cannot estimate the length or gravity of the future impact these events will have on the Company's results of operations, financial position, liquidity and the value of oil and natural gas reserves.

(2)Basis of Presentation

The Company's consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP"). All intercompany balances and transactions have been eliminated upon consolidation.

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, shareholders' equity, results of operations or cash flows.

(3)Summary of Significant Accounting Policies

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable, accrued capital expenditures and operating expenses, asset retirement obligations ("ARO"), the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the fair value of derivatives.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on our cash and cash equivalents. The Company didnot have cash equivalents as of December 31, 2025, and 2024.

Accounts Receivable, net

Our receivables arise primarily from the sale of oil, natural gas and natural gas liquids ("NGLs") and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for credit losses, if necessary.

Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in our consolidated balance sheets. Oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis.

The Company estimates uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions. Allowances for credit losses are recorded as reductions to the carrying values of the accounts receivable included in the Company’s consolidated balance sheets and are recorded in administrative costs in our consolidated statements of operations if failure to collect an estimable portion is determined to be probable.

Accounts receivable, net is summarized below:

As of December 31, 2023, the Company had accounts receivables, net from oil, natural gas and NGL sales of $31.1 million.

Inventory

The Company's inventory represents tangible assets such as drilling pipe, tubing, casing and operating supplies used in the Company's future drilling or repair operations. The Company accounts for our inventory using the first-in, first-out method and it is valued at the lower of cost or net realizable value. If the cost of inventory exceeds the net realizable value, we will adjust the carrying amount of inventory to the net realizable value, and record the adjustment in the consolidated statements of operations.

Proved Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for our oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized, or suspended, pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs.

Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain the oil and natural gas properties in operating condition are charged to lease operating expenses ("LOE") as incurred.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate. These gains or losses would be recognized as a gain (loss) on sale of oil and gas properties in the consolidated statement of operations.

Unproved Oil and Natural Gas Properties

Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties.

Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. This gain or loss would be recognized as a gain (loss) on sale of oil and gas properties in the consolidated statement of operations. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the oil and natural gas properties are compared to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of future oil, natural gas and NGL prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. See further discussion in Note 7 - Fair Value Measurements.

Business Combinations

The Company accounts for business combinations in accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 805, Business Combinations. The Company accounts for our acquisitions that qualify as a business using the acquisition method in which the Company recognizes and measures identifiable assets acquired, liabilities assumed, and any non-controlling interest in the acquired entity at their fair values as of the acquisition date. If the set of assets and activities acquired is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method, the Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on the estimated fair values. The fair values of identifiable assets acquired and liabilities assumed are determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business, if any, is recorded as a bargain purchase gain. Transaction costs related to the business combination are expensed as incurred.

Other Property and Equipment, net

Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of in use property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 5 to 39 years. Capitalized costs related to leasehold improvements are depreciated over the life of the lease. Land costs are accounted for at cost and are not depreciated. Components of other property and equipment consisted of computer equipment, computer software, office furniture, tools and equipment, land, buildings and improvements, vehicles, and midstream property and equipment that was sold in 2025 in the Midstream Sale.

Other property and equipment, net is summarized below:

Deferred Financing Costs

Deferred financing costs include origination, arrangement, legal and other fees to issue or amend the terms of the revolving credit facility ("Credit Facility") and unsecured senior notes ("Senior Notes"). In our consolidated balance sheets, unamortized deferred financing costs related to the Credit Facility are reported as other non-current assets. For the Senior Notes, such costs are netted against the carrying value of the Senior Notes. Deferred financing costs are recognized in our consolidated statements of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method.

Equity Issuance Costs

Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as additional paid-in capital when related to the issuance of common equity securities. The issuance costs are expensed in our consolidated statements of operations if the issuance is unsuccessful.

Other Non-Current Assets, net

Other non-current assets, net consisted of the following:

The Company incurred $0.4 million and $2.7 million in financing costs related to the amendments of the Credit Facility during the year ended December 31, 2025, and 2024, respectively.

Accrued Liabilities

Accrued liabilities consisted of the following:

Other Current Liabilities

Other current liabilities consisted of the following:

Asset Retirement Obligations

ARO consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Components of the changes in ARO consisted of the following and is shown below:

(1)Current ARO is included within other current liabilities in our consolidated balance sheets.

Revenue Recognition

Oil Sales

Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs in accordance with the pricing provisions in the Company's contracts. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue at the net price received when control transfers to the purchaser.

Natural Gas and NGL Sales

Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers' gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs in accordance with the pricing provisions of the Company's contracts. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The pricing provisions also provide quantity requirements and grade and quality specifications. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process.

Transaction Price Allocated to Remaining Performance Obligations

Based on the Company’s current product sales contracts, with contract terms ranging fromone tofifteen years, each unit of production is considered a separate performance obligation and therefore future production volumes are wholly unsatisfied and do not require allocation or disclosure of the transaction price to remaining performance obligations.

Contract Balances

Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-Period Performance Obligations

Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the years ended December 31, 2025, and 2024, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of Revenue

The Company's oil, natural gas and NGL sales are presented net of gathering, processing and transportation costs ("GP&T costs"). These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.

The following table presents oil and natural gas sales disaggregated by product:

Contract Services with Related Parties

The Company had contracts with related parties to provide certain contract operating, accounting and back-office support services prior to 2025. Revenue related to these contract services was recognized over time as the services were rendered, and the fee was stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services were also recognized as the services were rendered. Refer to Note 9 - Transactions with Related Parties for a more detailed discussion regarding these contracts.

Revenue Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other working interest and royalty owners. Production proceeds that the Company has not yet distributed to other working interest and royalty owners are reflected as revenue payable in our consolidated balance sheets.

Lease Operating Expenses

Lease operating costs, including labor costs for field personnel, electricity, equipment rental, contract services, workovers and other operating expenses are expensed as incurred and included in lease operating expenses in our consolidated statements of operations.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes, which requires the establishment of deferred tax accounts for all temporary differences between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.

Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized. Interest and penalties, if any, related to uncertain tax positions are included in current income tax expense. There areno unrecorded liabilities for uncertain tax positions related to the Company as of December 31, 2025, and 2024. See further discussion in Note 12- Income Taxes.

Interest Expense, net

We have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our Credit Facility as well as the issuance of Senior Notes. We incur interest expense that is affected by both fluctuations in interest rates, our debt balances and our financing decisions. Interest expense, net in our consolidated statements of operations reflects interest, unused commitment fees paid to our lender, interest rate swap settlements, interest income and the amortization of deferred financing costs (including origination and amendment fees) less amounts allocated to capital expenditures, which are capitalized. Interest expense, net was $31.4 million, $34.3 million and $31.8 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Capitalized interest represents interest expense related to capital projects during the period in which the Company is incurring costs and expending resources to get the properties ready for their intended purpose. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset. Capitalized interest was $2.0 million, $2.4 million and $3.2 million, for the years ended December 31, 2025, 2024 and 2023, respectively.

Concentrations of Credit Risk

Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

We sell our production at market prices and to a relatively small number of purchasers, as is customary in the exploration, development and production business. Our purchaser contracts include marketing provisions with our purchasers to market our production. For the year ended December 31, 2025, one purchaser accounted for 60% of our revenue purchased. For the years ended December 31, 2024, and 2023, one purchaser accounted for 70% of our revenue purchased. For the years ended

December 31, 2025, 2024 and 2023, an additional purchaser accounted for 30%,22% and 20%, respectively. Due to the recent acquisition of Stakeholder Midstream, LLC ("Stakeholder") by Targa Northern Delaware LLC ("Targa") and upon commencement of the new gas purchase agreement ("A&R Gas Purchase Agreement"), substantially all of our natural gas and NGLs will be sold to a single purchaser. The loss of either of these purchasers could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil and natural gas are fungible products with well-established markets. Further, the Company has the right to market our oil and natural gas production under these agreements.

Our primary exposure to credit risk is through receivables from the sale of our oil, natural gas, and NGLs (approximately $31.0 million at December 31, 2025) and the collection of receivables from joint interest owners for their proportionate share of expenditures made on properties in which we serve as the operator (approximately $6.3 million at December 31, 2025).

We manage credit risk related to accounts receivable through netting revenues and expenses on properties in which we serve as the operator, credit approvals, escrow accounts and monitoring procedures. Accounts receivable are generally not collateralized. However, we routinely assess the financial strength of our customers and counterparties and, based upon factors surrounding the credit risk, establish an allowance for uncollectible accounts, if required. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited.

Environmental and Other Issues

We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with acquisitions of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation.

We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.

Fair Value Measurements

Certain financial instruments are reported at fair value in our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). These approaches are considered Level 3 in the fair value hierarchy.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of the Senior Notes is based on estimates of current rates available for similar issues with similar maturities and are classified as Level 2 in the fair value hierarchy. The carrying value reported for the Credit Facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates and is considered Level 2 in the fair value hierarchy. The liability associated with the earnout payments related to the Silverback Acquisition is accounted for at fair value on a recurring basis and is considered Level 3 in the fair value hierarchy. Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of ARO and the fair value of oil and natural gas properties when acquired in a business combination or assessed for impairment and are considered Level 3 in the fair value hierarchy.

Derivative Contracts

We report the fair value of derivatives in our consolidated balance sheets in derivative assets and derivative liabilities as either current or non-current based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities in our consolidated balance sheets whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract.

For the years ended December 31, 2025, and 2024, we have not designated our derivative contracts as hedges for accounting purposes and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in our consolidated statements of cash flows. Derivative contracts are settled on a monthly basis.

The fair value of derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently changes as these estimates are revised to reflect actual results, changes in market conditions and other factors.

The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our Credit Facility. Under the terms of the current counterparties' contracts, only those that are lenders under our Credit Facility are secured by the same collateral as outlined in our Credit Facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments.

Leases

The Company's current leases include office space, limited office equipment and field vehicles. The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of December 31, 2025, and 2024, the Company did not have any finance leases. Operating leases are capitalized in our consolidated balance sheets at commencement through a lease right-of-use ("ROU") asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Options to extend or terminate leases are included in the lease term when it is reasonably certain the Company will exercise the option. For operating leases, lease costs are recognized on a straight-line basis over the term of the lease.

The present value of operating lease payments and amortization of the lease liability is calculated using a discount rate. When available, the Company uses the rate implicit in the lease as the discount rate; however, some of the Company’s leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use our incremental borrowing rate ("IBR"). The Company’s IBR reflects the estimated rate of interest that the Company would pay to borrow on a collateralized basis over a similar term and amount equal to the lease payments in a similar economic environment. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The following table presents additional lease information:

Lease expense was $1.4 million, $1.2 million and $0.8 million, respectively, for the years ended December 31, 2025, 2024 and 2023. The ROU asset, current lease liability and non-current lease liability are included inother non-current assets, net, other current liabilities and othernon-current liabilities, respectively, in our consolidated balance sheets. Lease expense for the Company is included in general and administrative costs in our consolidated statements of operations.

Recent Accounting Pronouncements

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. The Company adopted this update effective January 1, 2024. See Note 14 -Segments. The adoption and implementation of this standard did not have a material impact on the Company's disclosures.

In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740) Improvements to Income Tax Disclosures which requires disaggregated information about the Company's effective tax rate reconciliation and income taxes paid. This ASU is effective for fiscal years beginning after December 15, 2024, and may be applied prospectively or retrospectively. The Company adopted this update retrospectively effective January 1, 2025. See Note 12 - Income Taxes. The adoption and implementation of this standard did not have a material impact on the Company's disclosures.

In November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40) Reporting Comprehensive Income-Expense Disaggregation Disclosures, which broadens the disclosures required for certain costs and expenses in the Company’s annual and interim consolidated financial statements. This ASU is effective prospectively for fiscal years beginning after December 15, 2026, and interim reporting periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating disclosures related to our annual report for fiscal year 2027.

(4)Acquisitions and Divestitures

Midstream Sale

On December 3, 2025, the Company sold all of our membership interests in Dovetail Midstream, LLC, a wholly owned subsidiary of the Company that holds certain midstream infrastructure projects in Eddy County, New Mexico, to Targa for an aggregate cash purchase price of approximately $111 million, subject to customary purchase price adjustments (the "Midstream Sale"). The Midstream Sale also provided for the subsequent sale by the Company of certain compressor station assets for an aggregate cash purchase price of approximately $10 million plus reimbursement of $1.4 million of capital improvements; this second transaction closed on December 24, 2025. In connection with the Midstream Sale, the Company recognized a pre-tax gain of $71.7 million, net of $2.6 million of transaction costs, which was recorded in our consolidated statement of operations. The Company also has the right to earn up to an additional $60 million in cash payments contingent upon achieving certain volumetric performance thresholds over a five-year period, beginning after the project in-service date in the A&R Gas Purchase Agreement, which is expected to be in-service before the end of 2026. No amounts were recognized during the year ended December 31, 2025.

Silverback Acquisition

On July 1, 2025, the Company completed the acquisition of 100% of the ownership interests of Silverback which owns oil and natural gas assets and operations located primarily in the Yeso trend of the Permian Basin in Eddy County, New Mexico for approximately $123 million, which included approximately $120 million paid in cash and approximately $3 million of estimated fair value related to potential earnout payments. The purchase price is subject to change pending final purchase price adjustments including the release of $1.2 million remaining in escrow.

The Silverback Acquisition qualified as a business combination using the acquisition method of accounting. The assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. The preliminary purchase price allocation is subject to change for up to one year subsequent to the closing date of the acquisition due to final customary purchase price adjustments. The assets acquired and liabilities assumed were recognized on the consolidated balance sheet at fair value as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and ARO assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future development, future operating costs, future cash flows and the use of weighted average cost of capital. These inputs required the use of significant judgments and estimates at the date of valuation, and use of different estimates and judgments could yield different results.

The following presents the allocation of the total purchase price of the Silverback Acquisition to the identified assets acquired and liabilities assumed based on estimated fair value as of the closing date of the acquisition:

Cash consideration included deposits into escrow of $14.2 million at signing and $6.9 million at closing for title defects. As of December 31, 2025, $4.6 million of the closing escrow was returned to the Company, $1.1 million was paid to the sellers and $1.2 million remains in escrow and is reflected as funds held in escrow in our consolidated balance sheets.

The Company may potentially pay the sellers quarterly earnout payments of up to $1.9 million per fiscal quarter during calendar years 2026 and 2027 if the New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") quarterly average exceeds certain stated amounts set forth in the Purchase Agreement, ranging from $70 to $75 per barrel or higher. See additional information on the fair value measurement of the earnout payments in Note 7 - Fair Value Measurements.

The Company funded the acquisition with cash on hand and borrowings under our Credit Facility. Transaction costs associated with the Silverback Acquisition were approximately $4.6 million for the year ended December 31, 2025.

Post-Acquisition Operating Results

The results of operations attributable to the Silverback Acquisition since the closing date of the acquisition have been included in the consolidated statements of operations and include$27.0 million of total revenues, net and$15.0 million of earnings, which represents total revenues, net less production taxes and LOE, for theyear ended December 31, 2025.

Pro Forma Operating Results (Unaudited)

The results of operations of the Silverback Acquisition have been included in the Company's consolidated financial statements since the closing date of the acquisition. The following supplemental, unaudited pro forma combined financial information for theyears ended December 31, 2025, and 2024 reflect the consolidated results of operations of the Company as if the Silverback Acquisition had occurred on January 1, 2024. The information below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The unaudited pro forma information includes adjustments for (i) transaction costs being reclassified to the first quarter of 2024 instead of being recorded in the year ended December 31, 2025, (ii) depletion, depreciation and amortization expense and (iii) interest expense related to the financing for the Silverback Acquisition. In addition, the pro forma information has been effected for income taxes with a blended statutory rate of 25.7% for the year ended December 31, 2025, and 2024.

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Silverback Acquisition been completed as of January 1, 2024, and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

Viking Sale

On November 21, 2025, the Company sold its interest in oil and natural gas properties in Texas outside of the Company's acreage in the Champions field ("Viking Sale"), which had a net carrying value of $10.4 million to an affiliate of Combo Resources, LLC ("Combo"). The properties consisted of six established units in Lee and Fayette Counties, Texas, which were jointly developed by the Company and Combo. In exchange for the Company's interest in these assets, we received and subsequently retired 250,000 shares of the Company's common stock. The net carrying value of the assets plus cash paid of $0.8 million less the tax impact of the sale resulted in a reduction to additional paid-in capital of $10.2 million.

2024 New Mexico Asset Acquisition

On May 7, 2024, the Company completed the acquisition of oil and natural gas properties in Eddy County, New Mexico, for a cash purchase price of approximately $19.1 million plus $0.5 million in transaction costs. The 2024 New Mexico Asset Acquisition was accounted for as an asset acquisition, with the final purchase price and transaction costs being capitalized to oil and natural gas properties. This acquisition was funded through a combination of proceeds from the 2024 equity issuance ("2024 Equity Offering") discussed in Note 11 - Shareholders' Equity and cash on hand.

2023 New Mexico Acquisition

On April 3, 2023, the Company completed the acquisition of oil and natural gas properties in Eddy County, New Mexico, from Pecos Oil & Gas, LLC for $324.7 million, funded through a combination of proceeds from the issuance of $200 million of Senior Notes and borrowings under the Company's Credit Facility. The 2023 New Mexico Acquisition was accounted for as a business combination.

(5)Oil and Natural Gas Properties

Oil and natural gas properties are summarized below:

As of December 31, 2025, and 2024, the Company hadno exploratory wells included in work-in-progress.

Depletion expense for proved oil and natural gas properties was $84.4 million, $71.3 million and $62.5 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Exploration costs were $0.4 million, $2.6 million and $4.2 million for the years ended December 31, 2025, 2024 and 2023, respectively, and were primarily attributable to expiration of oil and natural gas leases in 2025 and 2024 and exploratory well expense and the expiration of oil and natural gas leases in 2023.

Impairment of Proved Properties

Certain proved oil and natural gas properties were impaired during the year ended December 31, 2025. Our impairment test involved a step assessment to determine if the net book value of our proved oil and natural gas properties is expected to be recovered from the estimated undiscounted future net cash flows. We calculated the expected undiscounted future net cash flows of our long-lived assets using management’s assumptions and expectations.

Certain oil and natural gas properties in New Mexico outside of the Company's acreage in the Red Lake field failed the initial step assessment, which looks at the carrying value compared to undiscounted cash flows for these properties. For these assets, we used a discounted cash flow analysis to estimate fair value. The expected future net cash flows were discounted using a rate of 10.0%, which we believe represents the estimated weighted average cost of capital of a market participant. Based on this assessment of our long-lived assets impairment test, the carrying value exceeded the estimated fair market value, and we recognized a non-cash impairment.

For the year ended December 31, 2025, and 2024, the Company recognized a non-cash impairment of $1.2 million and $1.8 million, respectively, relating to certain properties in New Mexico outside of the Company's acreage in the Red Lake field. Additionally, the Company recognized a non-cash impairment loss on proved properties of $9.5 million for the year ended December 31, 2024, relating to certain properties in Texas outside of the Company's acreage in the Champions field that were sold as part of the Viking Sale. The 2025 and 2024 impairments were primarily driven by a reduction in well results and lower commodity prices. In 2023, the Company recognized an impairment of $9.8 million on proved properties in Texas, outside of the Champions field that were sold as part of the Viking Sale. These impairments are included in our consolidated statements of operations as impairments of oil and natural gas properties. See further discussion of our fair value assumptions in Note 7 - Fair Value Measurements.

Impairment of Enhanced Oil Recovery (EOR) Project

The cost of proved and unproved oil and natural gas properties are assessed for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the undiscounted future cash flows of the oil, natural gas and NGL properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil, natural gas and NGL properties to their estimated fair value which is considered a Level 3 measurement. As part of the impairment review during the third quarter 2024, the Company made the decision to discontinue our EOR Project, which was in work-in-process, in favor of redeploying the required future capital and salvaging the assets for use in our conventional vertical and horizontal development programs. As a result of this decision, the remaining fair value for the EOR Project was determined to bezero, after $1.8 million in compressors and other equipment were transferred to inventory for future use in our consolidated balance sheets. The Company also recorded a non-cash impairment loss of $28.9 million and a cash impairment loss of $1.3 million related to a contract termination payment. The total $30.2 million impairment is included in other impairments in our consolidated statements of operations. In 2025, the Company determined the fair value of the compressors to be zero, and therefore wrote off the cost of the compressors and recorded a non-cash impairment loss of $1.6 million and is included in other impairments in our consolidated statement of operations.

(6)Derivative Instruments

Oil and Natural Gas Contracts

The Company uses commodity based derivative contracts to reduce exposure to fluctuations in oil and natural gas prices. While the use of these contracts partially limits the downside risk for adverse price changes, their use also partially limits future revenues from favorable price changes. We have not designated our derivative contracts as hedges for accounting purposes and therefore changes in the fair value of derivatives are included and recognized in other income (expense) in our consolidated statements of operations.

As of December 31, 2025, the Company's oil and natural gas derivative instruments consisted of the following types:

•Fixed Price Swaps – the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

•Costless collars – the combination of a put option (fixed floor) and call option (fixed ceiling), with the options structured so that the premium paid to purchase the put option is offset by the premium received from the sale of the call option. If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike price, no payments are due from either party.

•Basis Protection Swaps – basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. We receive the fixed price differential and pay the differential between the referenced indexes.

The following table summarizes the open financial derivative positions as of December 31, 2025, related to oil and natural gas production:

Interest Rate Contracts

The Company entered into floating-to-fixed interest rate swaps, in which it will receive a floating market rate equal to one-month Chicago Mercantile Exchange Term Secured Overnight Financing Rate ("SOFR") Rate and will pay a fixed interest rate to manage future interest rate exposure related to the Company’s Credit Facility. In March 2024, the Company entered into a fixed-to-floating interest rate swap for the period from May 2024 to December 2024, to reduce our interest rate exposure, which resulted in a gain of approximately $1 million on a notional amount of $80 million. This gain was realized upon settlement of the contracts throughout 2024.

The following table summarizes the open interest rate derivative positions as of December 31, 2025:

Balance Sheet Presentation of Derivatives

The following tables present the location and fair value of the Company’s derivative contracts included in our consolidated balance sheets:

The following table presents the components of the Company's gain (loss) on derivatives, net for the periods presented below:

(7)Fair Value Measurements

The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The carrying values of financial instruments comprising cash, payables, receivables, and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value reported for the Credit Facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The fair value of the Senior Notes is based on estimates of current rates available for similar issuances with similar maturities and is classified as Level 2 in the fair value hierarchy. The oil and natural gas properties acquired and ARO assumed in the Silverback Acquisition, 2024 New Mexico Asset Acquisition and 2023 New Mexico Acquisition in addition to the fair value of assets and liabilities when considered for impairment are considered Level 3 measurements.

Assets and Liabilities Measured on a Recurring Basis

The fair values of commodity derivatives and interest rate swaps are estimated using discounted cash flow calculations based on forward curves and are classified as Level 2 within the fair value hierarchy. The following table summarizes these instruments that were accounted for at fair value on a recurring basis by level within the fair value hierarchy:

Earnout Payments - Silverback

The earnout payments in connection with the Silverback Acquisition were valued using a Monte Carlo simulation model that incorporated forward strip pricing as of December 31, 2025. The valuation process involved modeling the potential earnout payments over numerous scenarios based on WTI futures prices. The average expected value from the simulations was then discounted using the Company's cost of debt. Based on the forward strip pricing as of December 31, 2025, management determined that no material change in estimates was necessary. The fair value of the earnout payments is considered a Level 3 measurement due to the unobservable inputs including volatility and the discount rate, as well as the detailed modeling required to estimate fair value. See Note 4 - Acquisitions and Divestitures for additional information on the earnout payments.

As of December 31, 2025, $1.0 million is accrued in other current liabilities and $2.1 million is accrued in other long-term liabilities in our consolidated balance sheets.

Liabilities Not Measured on a Recurring Basis

The following table summarizes the fair value and carrying amount of the Company's financial instruments.

(1)The carrying value reported for the Senior Notes is shown net of unamortized discount and unamortized deferred financing costs.

The carrying value reported for the Credit Facility approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The fair value of the Senior Notes was determined utilizing a discounted cash flow approach.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of ARO and the fair value of oil and natural gas properties when acquired in a business combination or assessed for impairment.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

The fair value of ARO incurred and acquired during the years ended December 31, 2025, and 2024, totaled approximately $19.4 million and $9.8 million, respectively. The fair value of additions and revisions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plugging and abandonment costs per well for all oil and natural gas wells and for all disposal wells; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) our average credit-adjusted risk-free rate. These assumptions represent Level 3 inputs.

If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected.

For the year ended December 31, 2025, the Company recognized a non-cash impairment loss to our oil and natural gas properties of $1.2 million related to acreage in New Mexico outside of our Red Lake field as well as a non-cash impairment loss of $1.6 million for the previously repurposed compressors related to the EOR project. At the time of impairment, the oil and natural gas properties in New Mexico outside of our Red Lake field had a net book value of $1.2 million and a fair value of zero resulting in an impairment loss of $1.2 million. The compressors related to the EOR project had a net book value of $1.6 million and a fair value of zero resulting in an impairment loss of $1.6 million.

For the year ended December 31 2024, the Company recognized non-cash impairment losses of $11.3 million related to acreage in Texas and New Mexico outside of our Champions and Red Lake fields as well as a non-cash impairment loss of $28.9 million related to the discontinuation of the EOR project. As of December 31, 2024, the oil and natural gas properties in Texas outside of the Champions field had a net book value of $21.1 million and a fair value of $11.6 million resulting in an impairment loss of $9.5 million and the oil and natural gas properties in New Mexico outside of the Red Lake field had a net book value of $3.1 million and a fair value of $1.3 million resulting in an impairment loss of $1.8 million. The EOR project had a net book value of $41.7 million and a fair value of $12.8 million for repurposed assets (including the EOR compressors) with alternative uses, resulting in an impairment loss of $28.9 million.

For the year ended December 31, 2023, the Company recognized non-cash impairment losses to our oil and natural gas properties of $9.8 million related to acreage in Texas outside of our Champions field. As of December 31, 2023, the oil and natural gas properties in Texas outside of the Champions field had a net book value of $33.7 million and a fair value of $23.9 million.

In preparing these assessments, the Company utilized a discounted cash flow approach to estimate fair value. The assumptions utilized in the discounted cash flow are considered Level 3, consistent with the discussion above. Under the discounted cash flow methodology, the expected future net cash flows were discounted using a weighted average cost of capital rate reflective of a market participant rate. Additionally, the assumptions utilized include the future commodity prices for oil and natural gas based on NYMEX strip pricing for WTI and Henry Hub, as adjusted for differentials (using the Company's historical average of differentials, which approximate a market participant's differentials) and operating cost assumptions based on the Company's historical LOE, which are deemed to estimate a market participant's operating costs. See further discussion of our impairments in Note 5 - Oil and Natural Gas Properties.

(8)Equity Method Investment

RPC Power

RPC Power LLC ("RPC Power") is our power-focused joint venture with Conduit Power LLC, in which we have 50% ownership. The Company is involved in two current projects with RPC Power.

The first project provides a portion of our electric power needs for our field operation in our Champions field. This project consists of two sites located within the Company's operating area. The power generated and delivered by RPC Power is consumed by operating activities and not sold to the electric grid.

The second project is intended to provide power for the sale into the Electric Reliability Council of Texas ("ERCOT"), the primary electric grid of Texas, with none of the generation consumed by Riley Permian. This project consists of four sites located outside of the Company's operating area, but in the west Texas region.

As the Company has significant influence due to our ownership percentage, but lacks control, RPC Power is accounted for as an equity method investment. In November 2024, the Company signed the Second Amendment to the A&R LLC Agreement, which increased the capital commitment for each owner from $42.5 million to $51.5 million. As of December 31, 2025, the

Company had invested $39.5 million in the joint venture, comprised of $37.2 million in cash and $2.3 million of contributed assets, which was reduced by the Company's share of losses and increased by our share of income in the joint venture.

During the year ended December 31, 2025, the Company contributed an additional $15.8 million to RPC Power. The Company has a remaining commitment to invest up to an additional $12.0 million, if required, to fund our portion of the future capital budget for the RPC Power joint venture. On December 31, 2025, RPC Power declared a $3 million dividend, of which $1.5 million was the Company's portion. The dividend was paid in January 2026.

We account for any distributions received from our equity method investment using the nature-of-distribution approach. Under this approach, distributions are classified based on the underlying activity of the investee that generated them. Returns on investment are presented within operating activities, while returns of investment are presented within investing activities in our consolidated statement of cash flows.

See Note 9 - Transactions with Related Parties for further discussion of the contractual agreements between the Company and RPC Power and its affiliates and Note 15 - Commitments and Contingencies for additional information on future commitments.

The following table presents the Company's equity method investment activity:

(9)Transactions with Related Parties

RPC Power

In January 2023, the Company entered into a 10-year agreement with RPC Power, which provides for the conversion of specified quantities of the Company’s produced natural gas to electricity to power a portion of our oilfield operations in our Champions field ("Tolling Agreement"). The Tolling Agreement was amended and restated in June 2024 ("A&R Tolling Agreement") primarily to reflect the new in-service date of September 2024. The Company also entered into a 10-year agreement (“Asset Optimization Agreement”) in January 2023 that requires RPC Power to provide operational expertise on the implementation and management of the power generating assets subject to the A&R Tolling Agreement for a monthly fee of $20 thousand.

In May 2024, the Company entered into the Second Amended and Restated Limited Liability Company Agreement (“A&R LLC Agreement”) to expand the scope of our joint venture to include the constructing, owning and operating of additional new power generation and storage assets, for the sale of energy and ancillary services to ERCOT ("Merchant Deal").

In May 2024, the Company entered into a 10-year natural gas supply agreement ("Supply Agreement") with RPC Merchant LLC, a wholly owned subsidiary of RPC Power ("RPC Merchant"), to supply natural gas to fuel the natural gas generators under the Merchant Deal. The Company's commitment under the Supply Agreement is contingent upon project start-up which is expected to commence in 2026.

The Company incurred LOE from RPC Power of approximately $7.7 million, $4.3 million and $0.2 million for the years ended December 31, 2025, 2024 and 2023, respectively. As of December 31, 2025, and 2024, the Company had approximately $0.7 million and $1.2 million accrued for RPC Power, which was included in accrued liabilities in our consolidated balance sheets.

See additional information related to RPC Power in Note 8 - Equity Method Investment and Note 15 - Commitments and Contingencies for additional information on future commitments.

Contract Services

Prior to January 31, 2024, the Company provided certain administrative and operational services to Combo pursuant to a management services agreement (the "Combo MSA") for a monthly fee of $100 thousand and reimbursement of all third party expenses.

The Company also provided certain administrative services pursuant to a services agreement (the "REG MSA") with Riley Exploration Group, LLC (“REG”) for a monthly fee and reimbursement of all third party expenses until the REG MSA was terminated effective May 31, 2024.

The following table presents revenues from and related cost for contract services for related parties:

The Company hadno revenues from or related costs for contract services for related parties during the year ended December 31, 2025. The Company hadno amounts payable or receivable with Combo or REG as of December 31, 2025, and 2024.

Consulting and Legal Fees

The Company has an engagement agreement with di Santo Law PLLC ("di Santo Law"), a law firm owned by Beth di Santo, a member of our Board of Directors, pursuant to which di Santo Law's attorneys provide legal services to the Company.

The Company incurred legal fees from di Santo Law of approximately $2.2 million, $1.4 million and $1.2 million for the years ended December 31, 2025, 2024 and 2023, respectively. As of December 31, 2025, and 2024, the Company had approximately $1.7 million and $0.3 million in amounts accrued for di Santo Law, which were included in other current liabilities in our consolidated balance sheets.

Other Related Party Transactions

See Note 4 - Acquisitions and Divestitures for a full discussion of the Viking Sale.

In certain instances, business requires our employees to charter privately owned aircraft in furtherance of our business, including accessing remote areas of our field operation. The Company arranges travel through a charter company, which also manages an aircraft in which our Chief Executive Officer holds a time-sharing agreement for a private aircraft. The Company from time to time will use the aircraft in which our Chief Executive Officer has the time-sharing agreement in place as the fees for this aircraft are less than others offered by the charter company. We pay fees incurred for flights directly to the charter company that manages the planes. During each of the years ended December 31, 2025, and 2024, we paid the charter company $0.2 million and $0.1 million, respectively for flights chartered by our employees. The Company didnot pay for the use of a chartered plane during the year ended December 31, 2023.

(10)Long-Term Debt

The following table summarizes the Company's outstanding debt:

(1)Unamortized discount and unamortized deferred financing costs are attributable to and amortized over the term of the Senior Notes.

(2)As of December 31, 2025, and 2024, the current portion of long-term debt reflects $20 million due on the Senior Notes over the next twelve months.

Debt maturities as of December 31, 2025, excluding unamortized deferred financing costs, are as follows:

(1)The credit facility amount outstanding of $110 million as of December 31, 2025, has a stated maturity date of December 2028 which is subject to an earlier maturity date of October 2027 if any Senior Notes are still outstanding as of October 2027. For purposes of this table, the Company used the earlier date of October 2027; however, if the Senior Notes are no longer outstanding before this date, the stated maturity would become December 2028.

Credit Facility

On September 28, 2017, REP LLC entered into a credit agreement (the "Credit Agreement") to establish a senior secured Credit Facility with a syndicate of banks including Truist Bank, as administrative agent. The Credit Facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million. On February 22, 2023, the Company amended our Credit Facility to, among other things, allow for the issuance of unsecured senior notes of up to $200 million. On April 3, 2023, and concurrent with the closing of the 2023 New Mexico Acquisition, the Company entered into the fourteenth amendment to the Credit Facility to, among other things, increase the maximum facility amount to $1.0 billion and the borrowing base from $225 million to $325 million, resulting in the addition of new lenders to the lending group. On November 14, 2023, through the semi-annual redetermination process and fifteenth amendment, the Credit Facility was amended to increase the borrowing base from $325 million to $375 million, resulting in the addition oftwo new lenders and the exit ofone lender. On December 13, 2024, the Company entered into the sixteenth amendment to the Credit Facility to, among other things, extend the stated maturity date from April 2026 to December 2028 (or if any Senior Notes are then outstanding, the date that is 181 days prior to the earliest stated maturity date of such Senior Notes, in this case October 2027) and increase the borrowing base from $375 million to $400 million, which was reaffirmed in December 2025 with the removal of the natural gas hedging requirement. Substantially all of the Company’s assets are pledged to secure the Credit Facility.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. During these redetermination periods, the Company’s borrowing base may be increased or may be reduced in certain circumstances. The Credit Facility allows for SOFR Loans and Base Rate Loans (each as defined in the Credit Agreement). The interest rate on each SOFR Loan will be the adjusted Term SOFR for the applicable interest period plus a margin between 2.75% and 3.75% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan will be the Base Rate for the applicable interest period plus a margin between 1.75% and 2.75% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.500% (depending on the borrowing base utilization percentage).

The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0 and (ii) a minimum current ratio of not less than 1.0 to 1.0 as of the last day of any quarter. The Credit Agreement also contains a total leverage ratio for Restricted Payments, as defined in the Credit Agreement, after giving pro forma effect to such Restricted Payments, which includes payments to any holder of the Company's shares, would not exceed 2.50 to 1.0. If the Company's leverage ratio, after giving pro forma effect to such Restricted Payments (as defined in the Credit Agreement), is above 2.0 to 1.0, then an additional test of free cash flow is applied, and the Company will only be permitted to make such Restricted Payments if such payment does not exceed the Company's free cash flow. In addition to and after giving effect to such Restricted Payments, the availability of funds under the Company's Credit Facility must be greater than or equal to 20% of the elected commitments. The Company is also required to limit our cash balance to less than $32.5 million or 10% of the borrowing base, whichever is greater. If the Company's cash balance exceeds this limit on the last business day of the month, the Company will be required to apply the excess to reduce our Credit Facility borrowings. The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company must maintain a minimum hedging requirement included in the Credit Agreement for oil based on our proved developed producing projected volumes on a rolling 24-month basis. The following table summarizes the Credit Facility balances:

Senior Notes

On April 3, 2023, and concurrent with the closing of the 2023 New Mexico Acquisition, the Company (as “Issuer”) completed our issuance of $200 million aggregate principal amount of 10.50% senior unsecured notes with final maturity April 2028 pursuant to a note purchase agreement (the “Note Purchase Agreement”), with the Senior Notes issued at a 6% discount. The net proceeds from the Senior Notes were used to fund a portion of the purchase price and related fees, costs and expenses for the 2023 New Mexico Acquisition.

Interest is due and payable at the end of each quarter. In addition to interest, the Issuer will repay 2.50% of the original principal amount each quarter resulting in $5 million quarterly principal payments until the maturity of the Senior Notes. As of December 31, 2025, the Company had $20 million in current liabilities in our consolidated balance sheets related to the quarterly principal payments due within the next 12 months.

The Company may, at our option, redeem, at any time and from time to time on or prior to April 3, 2026, some or all of the Senior Notes at 100% of the principal amount thereof plus the make-whole amount plus a premium of 5.25% as set forth in the Note Purchase Agreement plus accrued and unpaid interest, if any. After April 3, 2026, but on or prior to October 3, 2026, the Company may, at our option, redeem, at any time and from time to time some or all of the Senior Notes at 100% of the principal amount thereof plus a premium of 5.25% as set forth in the Note Purchase Agreement plus accrued and unpaid interest, if any. After October 3, 2026, the Company may redeem some or all of the Senior Notes at 100% of the principal amount thereof plus accrued and unpaid interest, if any. The principal remaining outstanding at the time of maturity is required to be paid in full by the Company. Certain note features, including those discussed above, were evaluated and deemed to be remote. Due to the remote nature, the fair value of these features was estimated to be approximately zero.

The Senior Notes contain certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of less than 3.0 to 1.0 and (ii) an asset coverage ratio greater than 1.50 to 1.0. The Senior Notes also contain a total leverage ratio and an asset coverage ratio for Restricted Payments, as defined in the Senior Notes. The leverage ratio, after giving pro forma effect to such Restricted Payments, cannot exceed 2.0 to 1.0, and the asset coverage ratio, after giving effect to such Restricted Payments, must be greater than or equal to 1.50 to 1.0. In addition to and after giving effect to such Restricted Payments, the outstanding balance on the Company's Credit Facility must be greater than or equal to 15% of the lesser of the then effective Borrowing Base and the Aggregate Elected Commitment Amount. Upon issuance of the Senior Notes, the Company must maintain a minimum hedging requirement included within the Senior Notes for oil and natural gas based on our proved developed producing projected volumes for each commodity on a rolling 18-month basis.

The Senior Notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Note Purchase Agreement contains customary terms and covenants, including limitations on the Company’s ability to incur additional secured and unsecured indebtedness.

The following table summarizes the Company's interest expense:

During the year ended December 31, 2025, and 2024, the weighted average interest rate on the Credit Facility was 7.39% and 7.79%, respectively.

As of December 31, 2025, and 2024, the Senior Notes had $5.1 million and $7.5 million of unamortized discount and $2.1 million and $3.0 million of unamortized deferred financing costs, respectively, resulting in an effective interest rate of 13.4% during the years ended December 31, 2025, and 2024.

As of December 31, 2025, and 2024, the Company was in compliance with all covenants contained in the Credit Agreement and the Note Purchase Agreement.

(11)Shareholders' Equity

Cash dividends for the periods presented were declared for all issued and outstanding common shares, including vested and unvested shares under the long-term incentive plan in effect during the period of dividend declaration. The portion of the cash attributable to the unvested restricted shares issued under the Amended and Restated 2021 Long-Term Incentive Plan (the "A&R LTIP") is included in accrued liabilities and other non-current liabilities in our consolidated balance sheets and will be paid in cash once the unvested restricted shares fully vest. See Note 10 - Long-Term Debt for discussion over the Company's restrictions on certain payments, including dividends.

The table below summarizes the following cash distributions declared to common shareholders during the periods presented below:

Stock-Based Compensation

On April 21, 2023, at the Company's annual meeting of stockholders, the Company's stockholders approved the A&R LTIP that increased the total number of shares of common stock, par value $0.001 per share, by 950,000 shares that may be utilized for awards pursuant to the Plan from 1,387,022 to 2,337,022. The A&R LTIP had 346,645 shares available as of December 31, 2025.

The A&R LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("ISOs"); (ii) stock options that do not qualify as ISOs (iii) stock appreciation rights, or SARs; (iv) restricted stock awards, or RSAs; (v) restricted stock units, or RSUs, (vi) stock awards; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards, all of which are collectively referred to as the "Awards".

The A&R LTIP authorizes the Compensation Committee to administer the plan and designate eligible persons as participants, determine the type or types of Awards to be granted to an eligible person, determine the number of shares of stock or amount of cash to be covered by the Awards, approve the forms of award agreements for use under the plan, determine the terms and conditions of any Award, modify, waive or adjust any terms or conditions of an Award that has been granted, among other responsibilities delegated by the Company's Board.

In March 2025, the Company introduced performance-based restricted stock awards in addition to time-based restricted stock awards to further align the compensation of the Company's executive officers with the long-term growth and the interests of its shareholders. Performance-based restricted stock awards represent 30% of total executive award value and may be earned based on the Company’s achievement of total shareholder return ("TSR") relative to its peer group during the applicable three-year performance period. Payouts for the executive officers can range from 0% to 200% of the target and have cliff-vesting after three years, with dividends paid on the number of shares vested. As a result, the Company has reduced the remaining shares available to be granted as awards under the A&R LTIP by 168,406 shares (the full 200%), which assumes the highest percentage payout for the performance-based restricted stock awards. The fair value of performance awards were estimated as of the date of grant using a Monte Carlo simulation with the following assumptions:

Restricted Shares

The Company granted 413,554,183,605 and 346,869 restricted shares to executives, employees and independent directors of the Company during the years ended December 31, 2025, 2024 and 2023, respectively. The Company estimates the fair values of the restricted shares as of the closing price of the Company's common stock on the grant date of the award, with the expense recognized as stock-based compensation on a straight-line basis over the vesting period.

The Company granted 124,418 in performance shares to executives during the year ended December 31, 2025. The grant-date fair value of the awards was determined to be 148% of the expected payout and is recognized as stock-based compensation expense on a straight-line basis over the requisite service period.

The holders of these restricted shares receive dividends, in arrears, once the shares vest. The Company has accrued for these dividends which are recorded in accrued liabilities and other non-current liabilities. All current restricted shares granted have a service period between 3 and 36 months.

The following table presents the Company's restricted stock activity during the year ended December 31, 2025, under the A&R LTIP:

(1)For theyears ended December 31, 2024, and 2023, the weighted average grant date fair value of restricted stock award shares granted during the year was $28.75 and $28.68, respectively.

(2)For theyears ended December 31, 2025, 2024 and 2023, the total fair value of restricted stock award shares vested during the year was$5.6 million, $7.1 million and $6.4 million, respectively.

(3)Performance shares granted during year ended December 31, 2025, are remeasured at the end of each reporting period based on the Company's TSR ranking as of the applicable period-end date.

The following table presents unrecognized stock-based compensation expense expected to be recognized and the related weighted average recognition period associated with unvested shares as of December 31, 2025:

For the years ended December 31, 2025, 2024 and 2023, the total stock-based compensation expense was $9.1 million, $8.1 million and $7.0 million, respectively. For the years ended December 31, 2024, and 2023, stock-based compensation expense also included expense associated with equity awards attributable to separation agreements with former Company executives. Stock-based compensation expense is included in general and administrative costs in the Company's consolidated statements of operations for the restricted stock awards granted under the A&R LTIP. If shares are subject to forfeiture, the Company will recognize forfeitures as they occur as a reduction to stock-based compensation expense in our consolidated statements of operations and a decrease to shareholders' equity in our consolidated balance sheets. Any unpaid dividends on forfeited shares will be recognized as a decrease to accrued liabilities and other non-current liabilities and an increase to shareholders' equity in our consolidated balance sheets.

Share Repurchases

In December 2025, our Board of Directors approved a stock repurchase program (the “Repurchase Program”) authorizing the repurchase of up to $100 million of our common stock from time to time over a period of 24 months, including through open market purchases, through block trades, in privately negotiated transactions, or by other means, including through the use of trading plans, each in accordance with applicable securities laws and other restrictions. The Repurchase Program does not obligate us to purchase any common stock and may be suspended from time to time, modified, extended or discontinued by the Board at any time. During the fourth quarter of 2025, no shares were purchased under the Repurchase Program. The remaining repurchase authority under the Repurchase Program at December 31, 2025 was $100 million.

Share Retirements

On November 21, 2025, the Company retired 250,000 shares of our common stock received as consideration in connection with the Viking Sale. As a result, the Company booked $10.2 million as a reduction to additional paid-in capital. See Note 4 - Acquisitions and Divestitures for a full discussion of the Viking Sale.

At-The-Market Equity Sales Program ("ATM")

On September 1, 2023, the Company entered into an Equity Distribution Agreement in connection with an ATM pursuant to which the Company may offer and sell from time to time up to an aggregate $50 million of our common stock through our agents. During the year ended December 31, 2025, the Company did not execute any sales under the ATM program. As of December 31, 2025, the Company had remaining capacity to sell up to an additional $49.7 million of common stock under the ATM program.

2024 Equity Offering

On April 8, 2024, the Company issued and sold 1,015,000 shares of common stock at a price of $27.00 per share. Net proceeds from the 2024 Equity Offering were approximately $25.4 million, after deducting underwriting discounts and commissions and expenses. The proceeds were used for financing an acquisition, repayment of outstanding debt and general corporate purposes.

(12)Income Taxes

The components of the Company's consolidated provision for income taxes are as follows:

(1)For the year ended December 31, 2025, a book tax benefit of $1.0 million related to the Viking Sale was recognized in additional paid-in capital. See Note 4 - Acquisitions and Divestitures for additional information on the Viking Sale.

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax basis of our assets and liabilities. The Company's net deferred tax position is as follows:

A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:

(1)State taxes in New Mexico and Texas make up the tax effect in this category.

Cash paid for income taxes, net of refunds, was as follows:

The Company's federal income tax returns for the years subsequent to December 31, 2021, remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2020. The Company currently believes that all other significant filing positions are highly certain and that all of our other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

Section 382 of the Internal Revenue Code limits the utilization of U.S. net operating loss ("NOL") carryforwards following a change in control. The Merger caused a stock ownership change for purposes of Section 382 which is subject to an approximate annual limit. The Company has federal NOLs subject to the annual Section 382 limit of $12.3 million of which $3.5 million will expire beginning in 2026 through 2037 with the remaining $8.8 million of the NOLs not expiring. Additionally, the Company has no federal NOLs generated after the Merger that are not limited by Section 382 and are not subject to expiration. We believe it is more likely than not the tax benefit of these NOLs will be fully realized, as such no valuation allowance has been recorded. The deferred tax assets for the net operating losses, along with the other deferred tax assets as shown in the table above, are presented net with deferred tax liabilities, which primarily consist of book and tax depreciation, depletion and amortization differences.

On July 4, 2025, new tax legislation known as the One Big Beautiful Bill Act ("OBBBA") was signed into law. The legislation, among other things, makes permanent, extends or modifies certain provisions under the 2017 Tax Cuts and Jobs Act, including permanent extension of 100% bonus depreciation for certain capital expenditures and the limitation on interest expense deductions. The enactment of the OBBBA resulted in a $3.7 million reduction in our current income tax expense, with an offsetting increase in deferred income tax expense for the year ended December 31, 2025.

(13) Net Income Per Share

The Company calculated net income per share using the treasury stock method. The table below sets forth the computation of basic and diluted net income per share for the periods presented below:

The following shares were excluded from the calculation of diluted net income per share due to their anti-dilutive effect for the periods presented:

(14)Segments

The Company’s oil and gas exploration and production activities are solely focused in the U.S. For financial reporting purposes, the Company aggregates our operating segments intoone reporting segment due to the similar nature of these operations.

The Chief Operating Decision Maker ("CODM") function is a critical aspect of segment reporting, as defined by the FASB under the Accounting Standards Codification (ASC) 280. The CODM is responsible for making key operating decisions and assessing the performance of the Company. The CODM function at the Company is collectively performed by a committee consisting of the Chief Executive Officer ("CEO"), Chief Financial Officer ("CFO"), Chief Operating Officer ("COO"), and Chief Accounting Officer ("CAO").

The CEO is the highest-ranking executive in the Company and is primarily responsible for the overall strategic direction and operational performance. The CEO's role in the CODM function includes setting long-term goals, making high-level decisions about policy and strategy, and ensuring that the Company's activities align with the overall corporate objectives.

The CFO oversees all of the financial activities of the Company, including financial planning, risk management, record-keeping, and financial reporting. In the CODM function, the CFO plays a crucial role in analyzing financial data, assessing financial performance, and making recommendations for resource allocation and investment decisions.

The COO is responsible for the day-to-day operations of the Company. This includes managing the operational aspects of the business, ensuring efficiency, and implementing the strategies set by the CEO. The COO's involvement in the CODM function includes monitoring performance, optimizing operational processes, and addressing any operational challenges that may arise.

The CAO oversees the accounting functions of the Company, ensuring compliance with accounting standards and regulations. In the CODM function, the CAO is responsible for providing accurate and timely financial information for the business, ensuring that the financial data is reliable and consistent and providing insight into the potential accounting complications of transactions. The CAO also plays a key role in internal controls and financial reporting.

Together, the CEO, CFO, COO, and CAO form a collaborative team that functions as the CODM. They meet regularly to review performance, discuss strategic and operational issues, and make informed decisions that drive the Company's success. This collective approach ensures that all aspects of the business are considered, from strategic direction and financial health to operational efficiency and regulatory compliance.

The CODM uses consolidated net income as a key metric to guide decisions regarding capital allocation. By assessing consolidated net income, the CODM gains insight into the overall financial health of the organization, allowing for more informed decisions on where to direct capital expenditures. Additionally, consolidated net income is used to monitor financial performance by comparing budgeted projections to actual results, helping the CODM identify variances, adjust strategies and ensure that resources are being effectively deployed across various operational areas.

The following table presents consolidated net income, the significant measure of profit and loss used by the CODM, as well as total assets, capital expenditures, and our equity method investment for the Company's single reportable segment:

(1)Other segment items include transaction costs and cost of contract services - related parties.

(2)Interest expense is shown gross of, or prior to the effect of interest income.

(3)There are no reconciling items between net income presented in our consolidated statements of operations and segment net income.

(4)Capital expenditures are accrual (activity-based) before acquisitions.

(15)Commitments and Contingencies

Legal Matters

Due to the nature of the Company's business, the Company may at times be subject to claims and legal actions. The Company accrues liabilities when it is probable that future costs will be incurred, and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. The Company did not recognize any material liability for legal matters as of December 31, 2025, and December 31, 2024. Management believes it is remote that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations, or cash flows.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company hadno material environmental liabilities as of December 31, 2025, or December 31, 2024.

Contractual Commitments

The Company is a party to a gas gathering, treating and processing agreement with Stakeholder in Texas. Under the terms of the agreement, the Company agreed to deliver an annual minimum volume during the contract term. As of December 31, 2025, approximately five years remain under the contract.

Under the A&R Tolling Agreement with RPC Power, the Company has committed to provide specified quantities of our natural gas for 10 years following the in-service date of September 2024, for a fee based on a per MMBtu basis adjusted for contractual usage factors. The Company also entered into the Asset Optimization Agreement that requires RPC Power to provide operational expertise on the implementation and management of the power generating assets subject to the A&R Tolling Agreement for a monthly fee of $20 thousand.

Under the Supply Agreement with RPC Merchant, the Company agreed to supply natural gas to fuel the natural gas generators under the Merchant Deal for 10 years. The Company's commitment under the Supply Agreement is contingent upon project start-up which is expected to commence in 2026.

Under the A&R LLC Agreement with RPC Power, the Company agreed to make additional capital contributions to fund its portion of the capital budget for RPC Power. The Company's remaining commitment, if required, is $12 million.

See Note 8 - Equity Method Investment and Note 9 - Transactions with Related Parties for additional information related to RPC Power.

Midstream Gas Purchase Agreement

On December 31, 2024, the Company signed a long-term gas purchase agreement for the Company's New Mexico field with Targa, which was amended and restated as the A&R Gas Purchase Agreement in connection with the Midstream Sale. The agreement has a minimum volume commitment in New Mexico for an initial 15-year term from the in-service date, which is expected to commence before the end of 2026.

(16) Subsequent Events

Dividend Declaration

On January 9, 2026, the Board of Directors of the Company declared a cash dividend of $0.40 per share of common stock paid on February 5, 2026, to our shareholders of record at the close of business on January 22, 2026.

Stock Repurchase Program

The Company began repurchasing outstanding shares of the Company's common stock during the first quarter of 2026 as part of the previously announced stock repurchase program. As of February 28, 2026, the Company has repurchased 152,408 shares for a weighted average price of $26.54, for a total consideration of $4.0 million.

Waterbridge

On January 6, 2026, the Company entered into a 15-year water management services agreement ("Waterbridge Agreement") with Waterbridge Stateline LLC ("Waterbridge") to deliver a portion of its New Mexico produced water for disposal purposes within a specified dedicated area. During the first 7 years of the agreement, the Company has both annual and a cumulative volume commitment to deliver minimum quantities of produced water. The in-service date is expected to be September 2026.

Sale of Non-Operating Interests

On February 10, 2026, the Company sold its interest in a non-operating unit that included 3 producing wells and 5 proposed non-operated wells for approximately $2 million plus reimbursement of $5.7 million in prepaid drilling costs. At December 31, 2025, the $5.7 million prepayment was included in prepaid expenses in our Consolidated Balance Sheet.

SUPPLEMENTAL OIL AND GAS INFORMATION

(17) Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities.

Capitalized costs for unproved properties include costs for acquiring or extending oil and natural gas leaseholds where no proved reserves have been identified. Work in progress include costs of exploratory and development wells that are in the process of drilling or in active completion, and costs of exploratory and development wells suspended or waiting on completion. For a summary of these costs, please refer to Note 5 – Oil and Natural Gas Properties.

Costs Incurred for Property Acquisition, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include ARO established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities.

The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the periods presented below:

The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. They do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.

(1) The statutory combined federal and state tax rate of 22.49%,22.59% and 21.20% is used for the years ended December 31, 2025, 2024 and 2023, respectively.

Oil, Natural Gas and NGL Quantities

Our reserve reports for the years ended December 31, 2025, 2024 and 2023 were prepared by Ryder Scott Company, L.P. All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the periods below with respect to changes in the Company’s proved (i.e., proved developed and undeveloped) reserves:

The following table breaks out the composition of proved reserves by commodity, expressed as a percentage of total proved reserves; the average WTI and Henry Hub prices used in the reserve report; and the average realized prices used to estimate our reserves. The WTI and Henry Hub prices are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period, and then adjusted for quality, energy content, GP&T costs and market differentials to determine our average realized prices.

(1)The Company's oil, natural gas and NGL sales are presented net of GP&T costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.

For the year ended December 31, 2025, the Company added 23.8 MMBoe of proved reserves, with such additions due to extensions and discoveries, acquisitions and positive revisions, partially offset by production and the Viking divestiture. The Company had acquisitions of 11.2 MMBoe primarily as a result of the Silverback Acquisition and extensions and discoveries of proved reserves of 23.6 MMBoe, which consisted of 0.6 MMBoe added to PDPs as a result of drilling successful wells that were previously classified as unproved locations and 23.0 MMBoe added to PUDs as a result of drilling activity during the year, which allowed for the booking of adjacent PUDs for locations that were previously booked as unproved reserves or not at all. The Viking divestiture resulted in a reduction of 1.2 MMBoe. The Company had upward revisions of previous estimates of 0.9 MMBoe, including 7.0 MMBoe of positive revisions which were partially offset by 6.1 MMBoe of negative revisions. Our positive revisions were primarily due to type-curve and production forecast changes for natural gas and NGLs of 5.1 MMBoe in addition to a decrease in operating expenses that caused positive revisions of 1.9 MMBoe. These positive revisions were partially offset by negative revisions which included development plan changes driven by shifting focus to more profitable areas of our assets, which resulted in the removal of PUD locations representing 2.9 MMBoe of PUD reserves from our 5-year forecast,2.3 MMBoe due to lower commodity prices and 0.9 MMBoe due to interest changes. Consistent with Securities and Exchange Commission ("SEC") guidelines, PUDs are limited to those locations that are reasonably certain to be developed within five years.

For the year ended December 31, 2024, the Company added 15.9 MMBoe of proved reserves, with such additions due to extensions and discoveries, positive revisions and acquisitions, partially offset by production. The Company had acquisitions of 4.3 MMBoe primarily as a result of acquired reserves in an acreage swap andthe 2024 New Mexico Asset Acquisition and extensions and discoveries of proved reserves of 15.6 MMBoe, which consisted of 7.7 MMBoe added to PDPs as a result of drilling successful wells that were previously classified as unproved locations and 7.9 MMoe added to PUDs as a result of drilling activity during the year, which allowed for the booking of adjacent PUDs for locations that were previously booked as unproved reserves or not at all. The Company had upward revisions of previous estimates of 4.3 MMBoe, including 15.3 MMBoe of positive revisions which were partially offset by 11.0 MMBoe of negative revisions. Our positive revisions were primarily due to increased forecasted natural gas sales volumes of 9.2 MMBoe based on improved gas processing capacity in addition to a decrease in operating expenses and midstream fees that caused positive revisions of 6.1 MMBoe. These positive revisions were partially offset by negative revisions which included development plan changes driven by shifting focus to more profitable areas of our assets, which resulted in the removal of PUD locations representing 4.2 MMBoe of PUD reserves from our 5-year forecast,2.6 MMBoe due to type curve updates,2.0 MMBoe due to interest changes,1.5 MMBoe due to lower commodity prices and 0.7 MMBoe due to reserve category changes.

For the year ended December 31, 2023, the Company added 30.0 MMBoe of proved reserves, with such additions due to acquisitions and extensions and discoveries, partially offset by negative revisions and production. The Company had acquisitions of 26.1 MMBoe primarily as a result of the 2023 New Mexico Acquisition and extensions and discoveries to proved reserves of 22.9 MMBoe, which consisted of 8.3 MMBoe added to PDP as a result of drilling successful wells that were previously classified as unproved locations, and 14.6 MMBoe added to PUDs as a result of drilling successful wells offsetting locations that were previously unproven locations. The Company had downward revisions of previous estimates of 12.1 MMBoe, including 19.3 MMBoe of negative revisions which were partially offset by 7.2 MMBoe of positive revisions. Our negative revisions included development plan changes, driven by the 2023 New Mexico acquisition, which resulted in the removal of PUD locations representing 6.7 MMBoe of PUD reserves from our 5-year forecast,6.3 MMBoe from lower forecasted natural gas sales volumes due to estimated limitations on processing capacity,2.9 MMBoe due to lower commodity prices,2.4 MMBoe due to increased operating expenses,0.7 MMBoe due to the removal of uneconomic locations and 0.3 MMBoe from other minor revisions. Positive revisions included 7.2 MMBoe due to changes in well forecasts based on improved well performance from producing wells.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The Company follows the guidelines prescribed in ASC Topic 932 Extractive Activities – Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (i) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (ii) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves; (iii) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (iv) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (v) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:

(1) December 31, 2025, proved reserves were derived based on average realized prices of $64.01 per barrel of oil, $0.02 per Mcf of natural gas and $(0.15) per barrel of NGL.

(2) December 31, 2024, proved reserves were derived based on average realized prices of $74.27 per barrel of oil, $(0.43) per Mcf of natural gas and $(3.56) per barrel of NGL.

(3) December 31, 2023, proved reserves were derived based on average realized prices of $76.02 per barrel of oil, $0.46 per Mcf of natural gas and $7.11 per barrel of NGL.

Principal sources of change in the Standardized Measure are shown below: