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.

On April 3, 2023 (the “Closing Date”), the Company completed the acquisition of oil and natural gas assets (the “New Mexico Acquisition”) from Pecos Oil & Gas, LLC (“Pecos”), a Delaware limited liability company and an affiliate of Cibolo Energy Partners LLC. For further information regarding the New Mexico Acquisition, see Note 4 - Acquisitions of Oil and Natural Gas Properties.

Our Properties

Our acreage is primarily located on large contiguous blocks in Yoakum County, Texas, which represents our Champions Field and Eddy County, New Mexico, which represents our Redlake Field acquired in the New Mexico Acquisition. Our activities primarily include the horizontal development of conventional reservoirs on the Northwest Shelf of the Permian Basin. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Eddy County, New Mexico.

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 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 the rising 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

Effective by the Company's Board of Directors written consent on September 23, 2022, the Company's fiscal year is now the period from January 1 to December 31, beginning with the year ended December 31, 2022.

The Company's accompanying 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 the 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 its cash and cash equivalents.

Accounts Receivable

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 the accompanying 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, if failure to collect is expected to occur. Allowances for credit losses are recorded as reductions to the carrying values of the accounts receivables included in the Company’s consolidated balance sheets and are recorded in Administrative costs in the consolidated statements of operations if failure to collect an estimable portion is determined to be probable. The Company hadno allowance for credit losses at December 31, 2023 and 2022.

Accounts receivable is summarized below:

As of December 31, 2021, the Company had accounts receivables from oil, natural gas and NGL sales of $17.6 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 its inventory using the first-in, first-out method and valued at the lower of cost or net realizable value.

Proved Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for its 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 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.

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. 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 its 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 such 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. As of December 31, 2023 and 2022, the Company had capitalized property and equipment costs of $6.6 million and $5.3 million, respectively, with $2.6 million and $2.0 million, respectively, of accumulated depreciation on the consolidated balance sheets. Components of other property and equipment consists of computer equipment, office furniture, tools and equipment, buildings and improvements, and vehicles.

Land purchases are accounted for at cost and are not depreciated. As of both December 31, 2023 and 2022, the Company had capitalized land costs of $16.7 million on the consolidated balance sheets.

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 the 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 on the consolidated statement 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 to the consolidated statement of operations if the issuance is unsuccessful.

Other Non-Current Assets, Net

Other non-current assets consisted of the following:

The Company incurred $2.8 million in financing costs related to the amendments of the Credit Facility in 2023. The Company extended certain existing office leases and entered into new vehicle leases during the year ended December 31, 2023, which resulted in additions to the right of use assets.

Equity method investment. In January 2023, the Company entered into an agreement to form a joint venture created for the purpose of constructing a new power infrastructure for onsite power generation in Yoakum County, Texas using produced natural gas. RPC Power Holdco LLC, a wholly-owned subsidiary of REPX, has a 30% investment in the joint venture, RPC Power LLC ("RPC Power"). The Company contributed its portion of capital for construction of the onsite power generation. As of December 31, 2023, the Company had invested $5.8 million to date in the joint venture, comprised of $3.6 million in cash and $2.3 million of contributed assets, which was reduced by the Company's share of the joint venture's loss during the year ended December 31, 2023.

The Company accounts for its corporate joint ventures under the equity method of accounting in accordance with FASB ASC Topic 323 “Investments — Equity Method and Joint Ventures.” The Company applies the equity method of accounting to investments of less than 50% in an investee over which the Company exercises significant influence but does not have control. Under the equity method of accounting, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statements of operations.

Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings.

Accrued Liabilities

Accrued 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)Primarily relates to ARO assumed in the New Mexico Acquisition.

(2)Current ARO is included within other current liabilities on the accompanying 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 toten 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, 2023 and 2022, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of Revenue

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

Contract Services with Related Parties

The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 - 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 revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue payable in the consolidated balance sheets.

Lease Operating Expenses

Lease operating costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel 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, 2023 and 2022. See further discussion in Note 11- Income Taxes.

Interest Expense

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 and our financing decisions. Interest expense in the consolidated statements of operations reflects interest, unused commitment fees paid to our lender, interest rate swap settlements and the amortization of deferred financing costs (including origination and amendment fees) less amounts allocated to capital expenditures. Interest expense was $31.8 million and $1.1 million for the years ended December 31, 2023 and 2022, respectively.

Capitalized interest represents interest expense related to wells in process 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.

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 years ended December 31, 2023 and 2022, one purchaser accounted for 70% and 89%, respectively, of our revenue purchased. For the year ended December 31, 2023, one other purchaser accounted for 10% or more of our revenues. During the year ended December 31, 2022, no other purchaser accounted for 10% or more of our revenues. 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.

Our primary exposure to credit risk is through receivables from the sale of our oil, natural gas, and NGLs (approximately $31.1 million at December 31, 2023) 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 $1.6 million at December 31, 2023).

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 on 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. 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 asset retirement obligations 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 on the 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 the consolidated balance sheet whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract.

For the years ended December 31, 2023 and 2022, 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 the consolidated statement 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, 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, 2023 and 2022, the Company did not have any finance leases. Operating leases are capitalized on the 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 its 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 weighted-average discount rate was 9.56% and 3.18%, respectively, at December 31, 2023 and 2022. The weighted average remaining lease term was 2.3 years and 2.4 years, respectively, at December 31, 2023 and 2022. Lease expense was $0.8 million and $0.5 million, respectively, for the years ended December 31, 2023 and 2022.

The ROU asset and current lease liability are included inother non-current assets andother current liabilities andnon-current lease liabilities, respectively, on the consolidated balance sheets. Lease expense for the Company is included in general and administrative costs on the consolidated statements of operations.

Recent Accounting Pronouncements

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 the Company's fiscal year 2025. Early adoption is permitted. The Company is currently evaluating income tax disclosures related to its annual report for fiscal year 2025.

(4)Acquisitions of Oil and Natural Gas Properties

New Mexico Acquisition

On April 3, 2023, the Company completed the New Mexico Acquisition from Pecos for approximately $330 million, before customary purchase price adjustments. The assets acquired are located in Eddy County, New Mexico, and include approximately 10,600 total contiguous net acres of leasehold. The acquisition included 18 net horizontal wells and 250 net vertical wells. Additionally, the assets added significant drilling locations to the Company's inventory.

The Company funded the New Mexico Acquisition through a combination of borrowings under the Credit Facility and proceeds from the issuance of $200 million of Senior Notes, including application of a $33 million escrow deposit paid during the three months ended March 31, 2023 with borrowings under the Credit Facility. For further information regarding the financing for the New Mexico Acquisition, see Note 9 - Long-Term Debt.

The New Mexico 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 fair value measurements of the oil and natural gas properties acquired and asset retirement obligations 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 future production volumes, 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 New Mexico Acquisition to the identified assets acquired and liabilities assumed based on estimated fair value as of the Closing Date:

The transaction costs of $5.8 million for the year ended December 31, 2023 relate to the New Mexico Acquisition. During the year ended December 31, 2022, the transaction costs of $2.6 million relate to a potential business combination and related financing that the Company pursued but ultimately chose not to consummate. These costs are included in the consolidated statements of operations.

Post-Acquisition Operating Results

The results of operations attributable to the New Mexico Acquisition since the Closing Date have been included in the consolidated statements of operations and include $79.3 million of total revenue, net and $51.8 million of earnings for the year ended December 31, 2023.

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma combined results for the years ended December 31, 2023 and 2022 reflect the consolidated results of operations of the Company as if the New Mexico Acquisition had occurred on January 1, 2022. The unaudited pro forma information includes adjustments for (i) transaction costs being reclassified to 2022 instead of being recorded during the year ended December 31, 2023 (ii) amortization for the discount and deferred financing costs related to the Senior Notes and Credit Facility, (iii) depletion, depreciation and amortization expense, and (iv) interest expense related to the financing for the New Mexico Acquisition. These adjustments remove such costs, as described above, that would not have been recognized had the Company not acquired the assets. In addition, the pro forma information has been effected for taxes with a 23% tax rate.

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 New Mexico Acquisition been completed as of January 1, 2022 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.

(5)Oil and Natural Gas Properties

Oil and natural gas properties are summarized below:

As of December 31, 2023, the Company hadno exploratory wells included in work-in-progress. In 2022, the Company hadone exploratory well drilled but uncompleted that was included in work-in-progress with associated well costs of $3.8 million. During the year ended December 31, 2023, the Company determined this exploratory well was not capable of producing commercial quantities and, as such, expensed the associated drilling costs.

Depletion and amortization expense for proved oil and natural gas properties was $62.5 million and $31.5 million for the years ended December 31, 2023 and 2022, respectively.

Exploration costs were $4.2 million and $2.0 million for the years ended December 31, 2023 and 2022, respectively, and were primarily attributable to exploratory well expense and the expiration of oil and natural gas leases in 2023 and the expiration of oil and natural gas leases in 2022.

Impairment of Proved Properties

Certain proved oil and natural gas properties were impaired during the year ended December 31, 2023. 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 Texas outside of the Company's acreage in the Champions 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, we recognized a $9.8 million impairment because the carrying value exceeded the estimated fair market value as of the year ended December 31, 2023. The Company recognized an impairment of $7.3 million on proved properties in New Mexico, outside of the Redlake field, for the year ended December 31, 2022. See further discussion of our fair value assumptions in Note 7 - Fair Value Measurements.

(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 limits the downside risk for adverse price changes, their use also 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 the consolidated statements of operations.

As of December 31, 2023, 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, 2023, 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.

The following table summarizes the open interest rate derivative positions as of December 31, 2023:

Balance Sheet Presentation of Derivatives

The following tables present the location and fair value of the Company’s derivative contracts included in the consolidated balance sheets as of December 31, 2023 and 2022:

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 and cash equivalents, 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 revolving line of credit 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 issues with similar maturities and is classified as Level 2 in the fair value hierarchy. The oil and natural gas properties acquired and asset retirement obligations assumed in the New Mexico Acquisition are considered Level 3 measurements.

Assets and Liabilities Measured on a Recurring Basis

The fair value of commodity derivatives and interest rate swaps is estimated using discounted cash flow calculations based upon forward curves and are classified as Level 2 in the fair value hierarchy. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2023 and 2022, by level within the fair value hierarchy:

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 asset retirement obligations 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 asset retirement obligations incurred and acquired during the years ended December 31, 2023 and 2022, totaled approximately $19.4 million and $0.4 million, respectively. The fair value of additions 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 plug and abandonment cost 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, 2023, the Company recognized an impairment charge to its oil and natural gas properties of $9.8 million related to acreage in Texas outside of its Champions Field. In preparing this assessment, 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 West Texas Intermediate ("WTI") and Henry Hub ("HH"), 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 impairment in Note 5 - Oil and Natural Gas Properties.

(8)Transactions with Related Parties

Contract Services

RPOC provides certain administrative services to Combo Resources, LLC ("Combo") and is also the contract operator on behalf of Combo in exchange for a monthly fee of $100 thousand and reimbursement of all third party expenses pursuant to a contract services agreement. Additionally, RPOC provides certain administrative and operational services to Riley Exploration Group, LLC ("REG") in exchange for a monthly fee of $100 thousand pursuant to a contract services agreement. Combo and REG are portfolio companies of Yorktown Energy Partners XI, L.P. ("Yorktown XI"), certain managed funds of which have investments in the Company (all deemed to be related parties). As of December 31, 2023, our Executive Vice President - Business Intelligence was the President of both REG and Combo, as well as a board member of Combo.

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

The Company had amounts payable to Combo of $0.7 million and $0.4 million at December 31, 2023 and 2022, respectively, which are reflected in other current liabilities in the accompanying consolidated balance sheets. Amounts due to Combo reflect the revenue, net of any expenditures for wells and fees due under the contract services agreement, for Combo's net working interest in wells that the Company operates on Combo's behalf. See Note 14 - Subsequent Events for additional information regarding arrangements with Combo occurring after December 31, 2023.

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. For the years ended December 31, 2023 and 2022, the Company incurred legal fees from di Santo Law of approximately $1.2 million, and $0.7 million, respectively. As of December 31, 2023, the Company had approximately $0.6 million in amounts accrued for di Santo Law, which was included in accrued liabilities in the accompanying consolidated balance sheets.

(9)Long-Term Debt

The following table summarizes the Company's outstanding debt:

(1)Unamortized discount on long-term debt is amortized over the life of the respective debt.

(2)As of December 31, 2023, unamortized deferred financing costs are attributable to and amortized over the life of the Senior Notes.

(3)As of December 31, 2023, 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, 2023, excluding unamortized deferred financing costs, are as follows:

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 SunTrust Bank, now Truist Bank as successor by merger, 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 its 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 New Mexico Acquisition, the Company entered into the fourteenth amendment (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, the Credit Facility was amended to increase the borrowing base from $325 million to $375 million. The Credit Agreement is set to mature in April 2026. 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. The Company is also required to limit its cash balance to less than $15 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 its 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 and natural gas based on its 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 New Mexico Acquisition, the Company (as “Issuer”) completed its 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 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, 2023, the Company had $20 million in current liabilities on the consolidated balance sheet related to the quarterly principal payments due within the next 12 months.

The Issuer may, at its 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 Issuer may, at its 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 Issuer 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 Issuer. 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 its 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:

As of December 31, 2023 and 2022, the weighted average interest rate on outstanding borrowings under the Credit Facility was 8.68% and 7.17%, respectively.

As of December 31, 2023, the Senior Notes had $10.1 million of unamortized discount and $3.9 million of unamortized deferred financing costs, resulting in an effective interest rate of 13.38% during the year ended December 31, 2023.

As of December 31, 2023 and 2022, the Company was in compliance with all covenants contained in the Credit Agreement and the Note Purchase Agreement.

(10)Shareholders' Equity

Dividends

Cash dividends for the periods presented were declared for all issued and outstanding common shares, including vested and unvested under the respective 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 on the consolidated balance sheets and will be paid in cash once the unvested restricted shares fully vest. See Note 9 - 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:

Share-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 1,075,626 shares available as of December 31, 2023.

2021 Long-Term Incentive Plan

The A&R LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("ISO's"); (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights, or SARs; (iv) restricted stock awards; (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 will collectively be 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 term or condition of an Award that has been granted, among other responsibilities delegated by the Company's Board.

Restricted Shares: The Company granted 346,869 and 367,420 restricted shares to executives, employees and independent directors of the Company during the years ended December 31, 2023 and 2022, respectively. The holders of these restricted shares receive dividends, in arrears, once the shares vest. The Company has accrued for these dividends which are reported in accrued liabilities and other non-current liabilities. All restricted shares granted have a service period between 3 and 36 months. The Company estimates the fair values of the restricted shares as the closing price of the Company's common stock on the grant date of the award, with the expense amortized on a straight-line basis and recognized over the vesting period.

The following table presents the Company's restricted stock activity during the year ended December 31, 2023 under the A&R LTIP:

(1)For the year ended December 31, 2022, the weighted average fair value of restricted shares granted during the year was $17.63.

(2)For theyears ended December 31, 2023 and 2022, the total fair value of restricted shares vested during the year was$6.4 million and$3.7 million, respectively.

For the years ended December 31, 2023 and 2022, the total share-based compensation expense is $7.0 million and $3.9 million, respectively. For the year ended December 31, 2023, share based compensation expense also includes expense associated with equity awards attributable to a separation agreement with a former Company executive. Share-based compensation expense is included in general and administrative costs on the Company's consolidated statement of operations for the restricted share awards granted under the A&R LTIP. At the time of the forfeiture, the Company will recognize any forfeited shares as a reduction to share-based compensation expense on the consolidated statement of operations and a decrease to shareholders' equity on the consolidated balance sheet. Any unpaid dividends on forfeited shares will be recognized as a decrease to accrued liabilities and an increase to shareholders' equity on the consolidated balance sheet. Approximately $11.1 million of additional share-based compensation expense will be recognized over the weighted average life of 27 months for the unvested restricted share awards as of December 31, 2023 granted under the A&R LTIP.

ATM Program

On September 1, 2023, the Company entered into an Equity Distribution Agreement in connection with an at-the-market equity sales program ("ATM") pursuant to which the Company may offer and sell from time to time up to an aggregate $50 million in shares of the Company's common stock through its agents. The offer and sale of the shares has been registered under the Securities Act of 1933, as amended ("Securities Act"), pursuant to the Company’s registration statement on Form S-3, as amended. A prospectus supplement related to the offering of the shares, as defined in Rule 415(a)(4) promulgated under the Securities Act was filed September 1, 2023. The Company intends to use the net proceeds from any offering for working capital purposes and other general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes.

During the year ended December 31, 2023, the Company executed sales under the ATM program of 8,939 shares which generated proceeds of approximately $280 thousand, net of approximately $278 thousand of fees including expenses associated with establishing the ATM program and filing of the related prospectus supplement. As of December 31, 2023, the Company had remaining capacity to sell up to an additional $49.7 million of common stock under the ATM program.

(11)Income Taxes

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

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of 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:

The Company's federal income tax returns for the years subsequent to December 31, 2019 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, 2018. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the 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 $12.9 million of which $4.1 million will expire beginning in 2024 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 net operating losses 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 differences.

(12)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:

(13)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, 2023 and December 31, 2022. 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, 2023 or December 31, 2022.

Contractual Commitments

In October 2021, the Company executed an agreement related to its EOR project. This agreement is a CO2 purchase agreement that has a daily contract quantity with Kinder Morgan CO2 Company, LLC that has a primary term extending through the earlier of the total contract quantity delivered or December 31, 2025.

In August 2022, the Company entered into a second amendment on its gas gathering and processing agreement with its primary midstream counterparty, Stakeholder Midstream LLC (“Stakeholder”). Stakeholder committed to expand their gathering and processing system with a commitment from the Company to deliver an annual minimum volume to Stakeholder’s gathering system for a minimum ofseven years beginning on the in-service date of the expanded plant.

In January 2023, the Company entered into an agreement to form a joint venture with Conduit Power LLC. The Company is committed to contributing its portion of capital expenditures into the joint venture company, RPC Power. In conjunction with the formation of the joint venture, the Company entered into additional agreements with RPC Power or one of its subsidiaries. These agreements include RPC Power providing operational expertise on the implementation and management of the power generation for a monthly fee of $20 thousand. In addition, the Company entered into a tolling agreement and committed to provide the natural gas needed to fuel onsite power generators for 10 years following the in-service date, with an automatic yearly extension until terminated by either party, for a fee based on a per MMBtu basis adjusted for contractual usage factors.

In October 2023, the Company entered into a purchase agreement for pipe related to its 2024 drilling program. Under the agreement, the Company has commitments to purchase approximately $13.1 million of pipe by December 2024.

(14)Subsequent Events

Dividend Declaration

On January 11, 2024, the Board of Directors of the Company declared a cash dividend of $0.36 per share of common stock payable on February 8, 2024 to its shareholders of record at the close of business on January 25, 2024.

Termination of Agreements between Riley and Combo

As discussed in Note 8 - Transactions with Related Parties, the Company has an MSA with Combo to provide certain services, including management of its assets, and overall company accounting, tax filings, and back-office functions. Each of Combo and Riley desired to terminate such MSA and transitioned the services under the MSA to Combo and its service providers effective as of January 31, 2024.

In addition, certain oil and natural gas properties were developed by Riley and Combo who currently jointly own interests in 6 established units in Lee and Fayette Counties, Texas. Going forward, Riley will no longer have the right to acquire interest in Combo’s leases or earn an interest in the future units formed within defined areas. Riley may participate in any wells or units to the extent Riley owns an interest in oil, gas or minerals attributable to such new well or unit. Further, Riley can continue to participate in wells drilled within each of the established units.

Power Joint Venture

On March 4, 2024, the Company made a capital contribution of $5.6 million to its joint venture RPC Power, which increased the total contribution to $11.5 million and the total ownership from 30% to 35%.

SUPPLEMENTAL OIL AND GAS INFORMATION

(15)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 21.20% and 21.59% is used for the years ended December 31, 2023 and.2022, respectively.

Oil, Natural Gas and NGL Quantities

Our reserve report for the year ended December 31, 2023 was prepared by Ryder Scott Company, L.P. For the year ended December 31, 2022, our reserve report was prepared by Netherland, Sewell & Associates, Inc. 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:

As of December 31, 2023, reserves were comprised of 61.5% oil,19.2% natural gas and 19.3% NGL. 2023 proved reserves were estimated based on average realized prices of $76.02 per Bbl of oil, $0.46 per Mcf of natural gas and $7.11 per Bbl of NGL. Prices used in the 2023 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period ("SEC price") January 2023 through December 2023. For oil and NGL volumes, the average West Texas Intermediate ("WTI") SEC price of $78.22 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub SEC price of $2.64 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of December 31, 2022, reserves were comprised of 62.9% oil,18.5% natural gas and 18.6% NGL. 2022 proved reserves were estimated based on prices of $91.96 per Bbl of oil, $3.16 per Mcf of natural gas and $25.55 per Bbl of NGL. Prices used in the 2022 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2022 through December 2022. For oil and NGL volumes, the average WTI SEC price of $94.14 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub SEC price of $6.36 per MMBtu is adjusted for energy content, transportation fees and market differentials.

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 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, which are primarily attributable to the removal of PUDs due to changes in the Company's development schedule. Consistent with SEC guidelines, PUDs are limited to those locations that are reasonably certain to be developed within five years.

For the year ended December 31, 2022, the Company had downward revisions of previous estimates of 6.3 MMBoe. These revisions are primarily the result of changes in certain well level projections and higher projected operating costs. The Company had extensions and discoveries to proved reserves of 14.8 MMBoe, which consisted of 7.8 MMBoe added to PDP as a result of drilling successful wells that were previously classified as unproved locations, and 7.0 MMBoe added to PUDs as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended December 31, 2022, the Company did not acquire any reserves.

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, 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.

(2) December 31, 2022 proved reserves were derived based on average realized prices of $91.96 per barrel of oil, $3.16 per Mcf of natural gas and $25.55 per barrel of NGL.

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