RILEY EXPLORATION PERMIAN, INC., 10-K filed on 3/5/2025
Annual Report
v3.25.0.1
Cover - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Feb. 28, 2025
Jun. 30, 2024
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2024    
Current Fiscal Year End Date --12-31    
Document Transition Report false    
Entity File Number 001-15555    
Entity Registrant Name Riley Exploration Permian, Inc.    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 87-0267438    
Entity Address, Address Line One 29 E. Reno Avenue    
Entity Address, Address Line Two Suite 500    
Entity Address, City or Town Oklahoma City    
Entity Address, State or Province OK    
Entity Address, Postal Zip Code 73104    
City Area Code 405    
Local Phone Number 415-8699    
Title of 12(b) Security Common stock, par value $0.001    
Trading Symbol REPX    
Security Exchange Name NYSEAMER    
Entity Well-known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Accelerated Filer    
Entity Small Business true    
Entity Emerging Growth Company false    
Document Financial Statement Error Correction false    
Entity Shell Company false    
ICFR Auditor Attestation Flag true    
Entity Public Float     $ 254.5
Entity Common Stock, Shares Outstanding   21,505,338  
Documents Incorporated by Reference The information required by Part III of this Annual Report on Form 10-K ("Annual Report"), to the extent not set forth herein, is incorporated herein by reference from the registrant's definitive proxy statement relating to the Annual Meeting of Stockholders to be held in 2025, which definitive proxy statement shall be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report relates.    
Entity Central Index Key 0001001614    
Amendment Flag false    
Document Fiscal Year Focus 2024    
Document Fiscal Period Focus FY    
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Audit Information
 12 Months Ended
Dec. 31, 2024
Audit Information [Abstract]  
Auditor Name BDO USA, P.C.
Auditor Location Houston, Texas
Auditor Firm ID 243
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CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Current Assets:    
Cash $ 13,124 $ 15,319
Accounts receivable, net 44,411 35,126
Prepaid expenses 1,592 1,631
Inventory 5,734 6,177
Current derivative assets 3,264 5,013
Total Current Assets 68,125 63,266
Oil and natural gas properties, net (successful efforts) 860,797 846,901
Other property and equipment, net 30,477 20,653
Non-current derivative assets 585 2,296
Equity method investment 22,811 5,620
Other non-current assets, net 10,706 6,975
Total Assets 993,501 945,711
Current Liabilities:    
Accounts payable 13,937 3,855
Accrued liabilities 33,918 33,159
Revenue payable 34,786 30,695
Current derivative liabilities 0 360
Current portion of long-term debt 20,000 20,000
Other current liabilities 20,123 6,276
Total Current Liabilities 122,764 94,345
Non-current derivative liabilities 414 0
Asset retirement obligations 32,706 19,255
Long-term debt 249,494 335,959
Deferred tax liabilities 76,547 73,345
Other non-current liabilities 961 1,212
Total Liabilities 482,886 524,116
Commitments and Contingencies (Note 15)
Shareholders' Equity:    
Preferred stock, $0.0001 par value, 25,000,000 shares authorized; 0 shares issued and outstanding 0 0
Common stock, $0.001 par value, 240,000,000 shares authorized; 21,482,555 and 20,405,093 shares issued and outstanding at December 31, 2024 and December 31, 2023, respectively 21 20
Additional paid-in capital 310,232 279,112
Retained earnings 200,362 142,463
Total Shareholders' Equity 510,615 421,595
Total Liabilities and Shareholders' Equity $ 993,501 $ 945,711
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CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - $ / shares
Dec. 31, 2024
Dec. 31, 2023
Statement of Financial Position [Abstract]    
Preferred stock, par value (USD per Share) $ 0.0001 $ 0.0001
Preferred stock, shares authorized (in Shares) 25,000,000 25,000,000
Preferred stock, shares issued (in Shares) 0 0
Preferred stock, shares outstanding (in Shares) 0 0
Common stock, par value (USD per Share) $ 0.001 $ 0.001
Common stock, shares authorized (in Shares) 240,000,000 240,000,000
Common stock, shares issued (in Shares) 21,482,555 20,405,093
Common stock, shares outstanding (in Shares) 21,482,555 20,405,093
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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Revenues:    
Total Revenues $ 410,181 $ 375,047
Costs and Expenses:    
Lease operating expenses 71,463 58,817
Production and ad valorem taxes 29,428 25,559
Exploration costs 2,595 4,165
Depletion, depreciation, amortization and accretion 74,900 65,055
Impairment of oil and natural gas properties 11,317 9,760
Other impairments 30,158 0
General and administrative:    
Administrative costs 26,551 26,569
Share-based compensation expense 8,138 6,833
Transaction costs 1,573 5,817
Total Costs and Expenses 256,486 203,154
Income from Operations 153,695 171,893
Other Income (Expense):    
Interest expense, net (34,338) (31,816)
Gain (loss) on derivatives, net (1,665) 6,193
Loss from equity method investment (721) (218)
Total Other Income (Expense) (36,724) (25,841)
Net Income from Operations Before Income Taxes 116,971 146,052
Income tax expense (28,074) (34,461)
Net income $ 88,897 $ 111,591
Net Income per Share:    
Basic (USD per Share) $ 4.29 $ 5.66
Diluted (USD per Share) $ 4.26 $ 5.58
Weighted Average Common Shares Outstanding:    
Basic (in Shares) 20,712 19,705
Diluted (in Shares) 20,875 20,000
Related Party    
General and administrative:    
Cost of contract services - related parties $ 363 $ 579
Oil and natural gas sales, net    
Revenues:    
Total Revenues 409,801 372,647
Contract services - related parties    
Revenues:    
Total Revenues $ 380 $ 2,400
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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Cash Flows from Operating Activities:    
Net income $ 88,897 $ 111,591
Adjustments to reconcile net income to net cash provided by operating activities:    
Exploratory well costs and lease expirations 2,560 4,143
Depletion, depreciation, amortization and accretion 74,900 65,055
Impairment of oil and natural gas properties 11,317 9,760
Other impairments 28,850 0
(Gain) loss on derivatives, net 1,665 (6,193)
Settlements on derivative contracts 1,849 (17,221)
Amortization of deferred financing costs and discount 5,299 4,161
Share-based compensation expense 8,138 6,978
Deferred income tax expense 3,202 27,589
Loss from equity method investment 721 218
Other 0 (25)
Changes in operating assets and liabilities    
Accounts receivable (9,285) (9,575)
Prepaid expenses and other current assets (53) (717)
Inventory 1,512 (546)
Other non-current assets (994) (1,179)
Accounts payable and accrued liabilities 9,877 3,200
Revenue payable 4,000 11,470
Other current liabilities 13,819 (1,514)
Net Cash Provided by Operating Activities 246,274 207,195
Cash Flows from Investing Activities:    
Additions to oil and natural gas properties (98,490) (134,796)
Additions to midstream property and equipment (10,964) 0
Additions to other property and equipment (875) (1,065)
Acquisitions of oil and natural gas properties (19,597) (5,443)
Net assets acquired in business combination 0 (324,686)
Contributions to equity method investment (17,912) (3,566)
Net Cash Used in Investing Activities (147,838) (469,556)
Cash Flows from Financing Activities:    
Deferred financing costs (2,783) (7,406)
Proceeds from Credit Facility 15,000 185,000
Repayments under Credit Facility (85,000) (56,000)
Proceeds from Senior Notes, net of issuance costs 0 188,000
Repayments of Senior Notes (20,000) (15,000)
Payment of common share dividends (30,831) (27,706)
Proceeds from issuance of common shares, net 25,415 2
Common stock repurchased for tax withholding (2,432) (2,511)
Net Cash Provided by (Used in) Financing Activities (100,631) 264,379
Net Increase (Decrease) in Cash and Cash Equivalents (2,195) 2,018
Cash, Beginning of Year 15,319 13,301
Cash, End of Year 13,124 15,319
Cash Paid For:    
Interest, net of capitalized interest 31,582 27,140
Income taxes, net of refunds 18,084 9,949
Non-cash Investing and Financing Activities:    
Changes in capital expenditures in accounts payable and accrued liabilities 1,058 (5,850)
Right-of-use assets obtained in exchange for operating lease liability 632 1,277
Assets contributed to equity method investment 0 2,272
Asset retirement obligations assumed in acquisitions 9,727 19,359
Revision of estimated obligations $ 1,856 $ 0
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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($)
$ in Thousands
Total
Common Stock
Additional Paid-in Capital
Retained Earnings
Beginning balance (in Shares) at Dec. 31, 2022   20,161,000    
Beginning balance at Dec. 31, 2022 $ 333,446 $ 20 $ 274,643 $ 58,783
Increase (Decrease) in Stockholders' Equity [Roll Forward]        
Share-based compensation expense (in Shares)   315,000    
Share-based compensation expense 6,978   6,978  
Repurchased shares for tax withholding (in Shares)   (80,000)    
Repurchased shares for tax withholding (2,511)   (2,511)  
Issuance of common shares, net (in Shares)   9,000    
Issuance of common shares, net 2   2  
Dividends declared (27,911)     (27,911)
Net income $ 111,591     111,591
Ending balance (in Shares) at Dec. 31, 2023 20,405,093 20,405,000    
Ending balance at Dec. 31, 2023 $ 421,595 $ 20 279,112 142,463
Increase (Decrease) in Stockholders' Equity [Roll Forward]        
Share-based compensation expense (in Shares)   155,000    
Share-based compensation expense 8,138   8,138  
Repurchased shares for tax withholding (in Shares)   (92,000)    
Repurchased shares for tax withholding (2,432)   (2,432)  
Issuance of common shares, net (in Shares)   1,015,000    
Issuance of common shares, net 25,415 $ 1 25,414  
Dividends declared (30,998)     (30,998)
Net income $ 88,897     88,897
Ending balance (in Shares) at Dec. 31, 2024 21,482,555 21,483,000    
Ending balance at Dec. 31, 2024 $ 510,615 $ 21 $ 310,232 $ 200,362
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Nature of Business
 12 Months Ended
Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Nature of Business 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 the 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.
For further information regarding the 2023 New Mexico Acquisition and the 2024 New Mexico Asset Acquisition (the "2023 and 2024 New Mexico Acquisitions"), see Note 4 - Acquisitions of Oil and Natural Gas Properties.
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.
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Basis of Presentation
 12 Months Ended
Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Basis of Presentation 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.
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Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies 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 did not have cash equivalents as of December 31, 2024, and 2023.
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, if failure to collect is expected to occur. 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:
December 31,
20242023
(In thousands)
Oil, natural gas and NGL sales$38,374 $31,135 
Joint interest accounts receivable4,884 1,630 
Allowance for credit losses
(62)— 
Other accounts receivable1,215 2,361 
Total accounts receivable, net
$44,411 $35,126 
As of December 31, 2022, the Company had accounts receivables, net from oil, natural gas and NGL sales of $24.1 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 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 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.
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 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 consists of midstream property and equipment, computer equipment, computer software, office furniture, tools and equipment, buildings and improvements, and vehicles. Midstream property and equipment was not in service as of December 31, 2024.
Other property and equipment, net is summarized below:
December 31,
20242023
(In thousands)
Midstream property and equipment
$11,297 $— 
Furniture, fixtures and other
5,882 6,605 
Land
16,673 16,673 
$33,852 $23,278 
Accumulated depreciation and amortization
(3,375)(2,625)
Total other property and equipment, net
$30,477 $20,653 
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:
December 31,
20242023
(In thousands)
Deferred financing costs, net$4,949 $3,844 
Right-of-use assets
1,398 1,890 
Other
4,359 1,241 
Total other non-current assets, net$10,706 $6,975 
The Company incurred $2.7 million and $2.8 million in financing costs related to the amendments of the Credit Facility during the year ended December 31, 2024, and 2023, respectively.
Accrued Liabilities
Accrued liabilities consisted of the following:
December 31,
20242023
(In thousands)
Accrued capital expenditures$10,441 $15,851 
Accrued lease operating expenses7,676 6,038 
Accrued general and administrative costs8,123 4,655 
Accrued inventory1,709 — 
Accrued ad valorem tax5,396 5,269 
Other accrued expenditures573 1,346 
Total accrued liabilities$33,918 $33,159 
Other Current Liabilities
Other current liabilities consisted of the following:
December 31,
20242023
(In thousands)
Advances from joint interest owners$11,278 $259 
Income taxes payable5,233 561 
Current ARO liabilities2,562 3,789 
Other1,050 1,667 
Total other current liabilities
$20,123 $6,276 
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:
December 31,
20242023
(In thousands)
ARO, beginning balance$23,044 $3,038 
Liabilities incurred78 45 
Liabilities assumed in acquisitions
9,727 19,359 
Revision of estimated obligations1,856 — 
Liability settlements and disposals(2,291)(1,039)
Accretion2,854 1,641 
ARO, ending balance$35,268 $23,044 
Less: current ARO (1)
(2,562)(3,789)
ARO, long-term$32,706 $19,255 
_____________________
(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 from one to ten 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, 2024, and 2023, 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:
Year Ended December 31,
20242023
(In thousands)
Oil and natural gas sales:
Oil$408,935 $363,125 
Natural gas(1,412)2,612 
NGLs
2,278 6,910 
Total oil and natural gas sales, net (1)
$409,801 $372,647 
_____________________
(1) The Company's oil, natural gas and NGL sales are presented net of gathering, processing and transportation costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.
Contract Services with Related Parties
The Company had contracts with related parties to provide certain contract operating, accounting and back-office support services. 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 payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel, 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 are no unrecorded liabilities for uncertain tax positions related to the Company as of December 31, 2024, and 2023. 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 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 $34.3 million and $31.8 million for the years ended December 31, 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.
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, 2024, and 2023, one purchaser accounted for 70% of our revenue purchased. For the year ended December 31, 2024, and 2023, an additional 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 $38.4 million at December 31, 2024) 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 $4.9 million at December 31, 2024).
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. 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, 2024, and 2023, 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, 2024, and 2023, 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 weighted-average discount rate was 7.79% and 9.56%, respectively, at December 31, 2024, and 2023. The weighted average remaining lease term was 2.2 years and 2.3 years, respectively, at December 31, 2024, and 2023. Lease expense was $1.2 million and $0.8 million, respectively, for the years ended December 31, 2024, and 2023.
December 31,
20242023
(In thousands)
ROU asset$1,398 $1,890 
Current lease liability$758 $985 
Long-term lease liability$673 $938 
The ROU asset, current lease liability and non-current lease liability are included in other non-current assets, net, other current liabilities and other non-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 the Company's fiscal year 2025. Early adoption is permitted. The Company does not expect this standard to have a material impact on our 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.
v3.25.0.1
Acquisitions of Oil and Natural Gas Properties
 12 Months Ended
Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]  
Acquisitions of Oil and Natural Gas Properties Acquisitions of Oil and Natural Gas Properties
2023 New Mexico Acquisition
On April 3, 2023, the Company completed an acquisition of oil and natural gas properties (the "2023 New Mexico Acquisition") from Pecos Oil & Gas, LLC, a Delaware limited liability company and an affiliate of Cibolo Energy Partners 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 assets acquired are located in Eddy County, New Mexico, and included approximately 10,600 total contiguous net acres of leasehold. The acquisition also included 18 net horizontal wells and 250 net vertical wells.
The 2023 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 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 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 2023 New Mexico Acquisition to the identified assets acquired and liabilities assumed based on estimated fair value as of the Closing Date:
Purchase price allocation as of December 31, 2023 (in thousands):
Total cash consideration$324,686 
Assets acquired:
Inventory$2,980 
Oil and natural gas properties342,308 
Other
149 
Amount attributable to assets acquired$345,437 
Fair value of liabilities assumed:
Revenue payable$1,475 
Asset retirement obligations19,276 
Amount attributable to liabilities assumed$20,751 
Net assets acquired$324,686 
Transaction costs associated with the 2023 New Mexico Acquisition were approximately $5.8 million 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 2023 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 2023 New Mexico Acquisition. These adjustments reflect such costs, as described above, that would have been recognized had the Company acquired the assets on January 1, 2022. In addition, the pro forma information has been effected for taxes with a 23% tax rate for the years ended December 31, 2023, and 2022.
Year Ended December 31,
2023
2022
(In thousands, except per share amounts)
Total revenues
$405,642 $435,157 
Net income
$121,466 $129,741 
Basic net income per common share
$6.16 $6.64 
Diluted net income per common share
$6.07 $6.59 
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 2023 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.
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 ("2024 New Mexico Asset Acquisition"), which added 13,900 contiguous net acres to the Company's existing acreage in Eddy County, 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.
v3.25.0.1
Oil and Natural Gas Properties
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Oil and Natural Gas Properties Oil and Natural Gas Properties
Oil and natural gas properties are summarized below:
December 31,
20242023
(In thousands)
Proved$1,027,183 $895,783 
Unproved100,974 100,216 
Work-in-progress21,318 57,004 
$1,149,475 $1,053,003 
Accumulated depletion, amortization and impairment(288,678)(206,102)
Total oil and natural gas properties, net$860,797 $846,901 
As of December 31, 2024, and 2023, the Company had no exploratory wells included in work-in-progress.
Depletion and amortization expense for proved oil and natural gas properties was $71.3 million and $62.5 million for the years ended December 31, 2024, and 2023, respectively.
Exploration costs were $2.6 million and $4.2 million for the years ended December 31, 2024, and 2023, respectively, and were primarily attributable to expiration of oil and natural gas leases in 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, 2024. 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 and New Mexico outside of the Company's acreage in the Champions and Red Lake fields 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 an $11.3 million non-cash impairment of proved properties comprised of a $9.5 million impairment in Texas, outside of the Champions field, and $1.8 million impairment in New Mexico, outside of the Red Lake field related to historical properties, for the year ended December 31, 2024. The impairments were primarily driven by a reduction in reserve volume due to lower well performance assessments based on historical trends. The affected areas included nine operated producing wells. The Company recognized an impairment of $9.8 million on proved properties in Texas, outside of the Champions field, for the year ended December 31, 2023. 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 be zero and the Company recorded a non-cash impairment loss of $28.9 million and a cash impairment loss of $1.3 million related to the termination of the Kinder Morgan CO2 contract. The total $30.2 million impairment is included in other impairments in our consolidated statements of operations.
v3.25.0.1
Derivative Instruments
 12 Months Ended
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments Derivative Instruments
Oil and Natural Gas Contracts
The Company uses commodity based derivative contracts to reduce exposure to fluctuations in oil and natural gas prices. While the use of these contracts partially limits the downside risk for adverse price changes, their use also partially limits future revenues from favorable price changes. We have not designated our derivative contracts as hedges for accounting purposes and therefore changes in the fair value of derivatives are included and recognized in other income (expense) in our consolidated statements of operations.
As of December 31, 2024, the Company's oil and natural gas derivative instruments consisted of the following types:
•Fixed Price Swaps – the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
•Costless collars – the combination of a put option (fixed floor) and call option (fixed ceiling), with the options structured so that the premium paid to purchase the put option is offset by the premium received from the sale of the call option. If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike price, no payments are due from either party.
The following table summarizes the open financial derivative positions as of December 31, 2024, related to oil and natural gas production:
Weighted Average Price
Calendar Quarter / YearNotional VolumeFixedPutCall
($ per unit)
Oil Swaps (Bbl)
Q1 2025375,000 $74.31 
Q2 2025345,000 $71.32 
Q3 2025165,000 $68.53 
Q4 2025120,000 $66.99 
Natural Gas Swaps (Mcf)
Q1 2025965,000 $3.61 
Q2 2025495,000 $3.34 
Q3 2025480,000 $3.30 
Q4 20251,165,000 $3.82 
20262,555,000 $3.92 
2027600,000 $4.19 
Oil Collars (Bbl)
Q1 2025468,000 $60.48 $77.04 
Q2 2025300,000 $66.50 $78.77 
Q3 2025452,000 $64.23 $74.19 
Q4 2025480,000 $63.10 $77.07 
20261,107,000 $58.89 $76.99 
Natural Gas Collars (Mcf)
Q1 2025555,000 $3.46 $4.38 
Q2 20251,080,000 $3.04 $3.65 
Q3 20251,110,000 $3.12 $3.76 
Q4 2025400,000 $3.30 $4.00 
20262,675,000 $3.15 $3.82 
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 for the year ended December 31, 2024, on a notional amount of $80 million, and is included in our consolidated statements of operations.
The following table summarizes the open interest rate derivative positions as of December 31, 2024:
Open Coverage Period
Position
Notional AmountFixed Rate
(In thousands)
January 2025 - April 2026
Long
$30,000 3.18 %
January 2025 - April 2026
Long
$50,000 3.04 %
April 2026 - April 2027
Long
$45,000 3.90 %
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 as of December 31, 2024, and 2023:
December 31, 2024
Balance Sheet ClassificationGross Fair ValueAmounts NettedNet Fair Value
(In thousands)
Current derivative assets$9,817 $(6,553)$3,264 
Non-current derivative assets6,661 (6,076)585 
Current derivative liabilities(6,553)6,553 — 
Non-current derivative liabilities(6,490)6,076 (414)
Total$3,435 $— $3,435 
December 31, 2023
Balance Sheet ClassificationGross Fair ValueAmounts NettedNet Fair Value
(In thousands)
Current derivative assets$8,948 $(3,935)$5,013 
Non-current derivative assets6,687 (4,391)2,296 
Current derivative liabilities(4,295)3,935 (360)
Non-current derivative liabilities(4,391)4,391 — 
Total$6,949 $— $6,949 
The following table presents the components of the Company's gain (loss) on derivatives, net for the periods presented below:
Year Ended December 31,
20242023
(In thousands)
Settlements on derivative contracts
$1,849 $(17,221)
Non-cash gain (loss) on derivatives(3,514)23,414 
Gain (loss) on derivatives, net$(1,665)$6,193 
v3.25.0.1
Fair Value Measurements
 12 Months Ended
Dec. 31, 2024
Fair Value Disclosures [Abstract]  
Fair Value Measurements 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 both the 2023 New Mexico Acquisition and the 2024 New Mexico Asset 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, 2024, and 2023, by level within the fair value hierarchy:
December 31, 2024
Level 1Level 2Level 3Total
(In thousands)
Financial assets:
Commodity derivative assets$— $15,301 $— $15,301 
Interest rate assets$— $1,177 $— $1,177 
Financial liabilities:
Commodity derivative liabilities$— $(13,043)$— $(13,043)
December 31, 2023
Level 1Level 2Level 3Total
(In thousands)
Financial assets:
Commodity derivative assets$— $14,766 $— $14,766 
Interest rate assets$— $869 $— $869 
Financial liabilities:
Commodity derivative liabilities$— $(8,686)$— $(8,686)
The following table summarizes the fair value and carrying amount of the Company's financial instruments.
December 31, 2024December 31, 2023
Carrying AmountFair ValueCarrying AmountFair Value
(In thousands)
Credit Facility (Level 2)$115,000 $115,000 $185,000 $185,000 
Senior Notes (Level 2)(1)
$154,494 $172,864 $170,959 $185,346 
_____________________
(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
New York Mercantile Exchange ("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, 2024, and 2023, totaled approximately $9.8 million and $19.4 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, 2024, the Company recognized non-cash impairment losses to our oil and natural gas properties 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 salvageable assets 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 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.
v3.25.0.1
Equity Method Investment
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Equity Method Investment Equity Method Investment
In January 2023, the Company formed a joint venture, RPC Power LLC, a Delaware limited liability company ("RPC Power"), with Conduit Power LLC for the purpose of constructing, owning and operating power generation assets. RPC Power's initial scope and assets use the Company’s produced natural gas to power a portion of our operations in Yoakum County, Texas which became fully operational in September 2024. 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 the Electric Reliability Council of Texas ("Merchant Deal"). Upon signing the A&R LLC Agreement, the Company invested an additional $9.5 million and also increased our equity ownership in RPC Power from 35% to 50%. 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, 2024, the Company had invested $23.8 million in the joint venture, comprised of $21.5 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. The Company also had a remaining commitment to invest up to an additional $27.7 million to fund our portion of the remaining 2025 capital budget for the RPC Power joint venture.
On February 28, 2025, the Company contributed an additional $6.3 million to RPC Power, which increased our total capital contributions to $30 million.
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:
Year Ended December 31,
20242023
(In thousands)
Equity method investment, beginning balance$5,620 $— 
Contributions17,912 5,838 
Loss from equity method investment(721)(218)
Equity method investment, ending balance
$22,811 $5,620 
v3.25.0.1
Transactions with Related Parties
 12 Months Ended
Dec. 31, 2024
Related Party Transactions [Abstract]  
Transactions with Related Parties 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 Yoakum County, Texas ("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 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 occur beginning in late 2025 through 2026.
The Company incurred LOE from RPC Power of approximately $4.3 million and $0.2 million for the year ended December 31, 2024, and 2023, respectively. As of December 31, 2024, and December 31, 2023, the Company had approximately $1.2 million and zero 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
The Company and Combo Resources, LLC (“Combo”) own interests in six established units in Lee and Fayette Counties, Texas, which were jointly developed by the parties pursuant to participation agreements (collectively, the "Combo PA") and are currently operated by Riley Permian Operating Company, LLC ("RPOC"). RPOC also 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 until the Combo MSA was terminated on January 31, 2024. Separately, the Combo PA was also terminated as of December 31, 2023, and pursuant to a letter agreement effective as of December 31, 2023, the Company agreed to relinquish our right to acquire additional working interests within a specified area. The rights of the Company in the six jointly owned units are not affected by this letter agreement and remain subject to the existing joint operating agreements between the parties.
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 of $100 thousand through January 2024 and $60 thousand through April 2024, and reimbursement of all third party expenses until the REG MSA was terminated effective May 31, 2024. The $60 thousand fee was waived for the month of May 2024.
The following table presents revenues from and related cost for contract services for related parties:
Year Ended December 31,
20242023
(In thousands)
Combo$100 $1,200 
REG280 1,200 
Contract services - related parties$380 $2,400 
Cost of contract services$363 $579 
The Company had no amounts payable to Combo at December 31, 2024, and $0.7 million payable at December 31, 2023, which is reflected in other current liabilities in our consolidated balance sheets. Amounts due to Combo reflect the revenue, net of any expenditures, for Combo's net working interest in wells that RPOC operates on Combo's behalf. The Company had no amounts receivable from Combo at December 31, 2024, and December 31, 2023.
The Company also had no amounts receivable from REG at December 31, 2024, and 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.
The Company incurred legal fees from di Santo Law of approximately $1.4 million, and $1.2 million, for the years ended December 31, 2024, and 2023, respectively. As of December 31, 2024, and 2023, the Company had approximately $0.3 million and $0.6 million in amounts accrued for di Santo Law, which were included in other current liabilities in our consolidated balance sheets.
Other Related Party Transactions
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 the year ended December 31, 2024, we paid the charter company $0.1 million for flights chartered by our employees.
v3.25.0.1
Long-Term Debt
 12 Months Ended
Dec. 31, 2024
Debt Disclosure [Abstract]  
Long-Term Debt Long-Term Debt
The following table summarizes the Company's outstanding debt:
December 31,
20242023
(In thousands)
Credit Facility$115,000 $185,000 
Senior Notes
Principal$165,000 $185,000 
Less: Unamortized discount(1)
7,547 10,117 
Less: Unamortized deferred financing costs(1)
2,959 3,924 
Total Senior Notes$154,494 $170,959 
Total debt
$269,494 $355,959 
Less: Current portion of long-term debt(2)
20,000 20,000 
Total long-term debt$249,494 $335,959 
_____________________
(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, 2024, and 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, 2024, excluding unamortized deferred financing costs, are as follows:
Year Ending December 31,
(In thousands)
2025$20,000 
202620,000 
2027 (1)
135,000 
2028105,000 
2029— 
Thereafter
— 
Total
$280,000 
_____________________
(1)The credit facility amount outstanding of $115 million as of December 31, 2024, 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 of two new lenders and the exit of one 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, resulting in the addition of one new lender to the lending group. 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 our 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 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 and natural gas based on our proved developed producing projected volumes on a rolling 24-month basis. The following table summarizes the Credit Facility balances:
December 31,
20242023
(In thousands)
Outstanding borrowings$115,000 $185,000 
Available under the borrowing base$285,000 $190,000 
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, 2024, 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 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 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:
Year Ended December 31,
20242023
(In thousands)
Interest expense
$31,411 $30,464 
Interest income
(866)(233)
Capitalized interest(2,350)(3,187)
Amortization of deferred financing costs
2,730 2,278 
Amortization of discount on Senior Notes
2,569 1,883 
Unused commitment fees on Credit Facility
844 611 
Total interest expense, net$34,338 $31,816 
As of December 31, 2024, and 2023, the weighted average interest rate on outstanding borrowings under the Credit Facility was 7.79% and 8.68%, respectively.
As of December 31, 2024, the Senior Notes had $7.5 million of unamortized discount and $3.0 million of unamortized deferred financing costs, resulting in an effective interest rate of 13.38% during the year ended December 31, 2024.
As of December 31, 2024, and 2023, the Company was in compliance with all covenants contained in the Credit Agreement and the Note Purchase Agreement.
v3.25.0.1
Shareholders' Equity
 12 Months Ended
Dec. 31, 2024
Equity [Abstract]  
Shareholders' Equity Shareholders' Equity
Dividends
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:
Quarter Ended
Per Share Distribution
Total Distribution
(In thousands)
2024
December 31, 2024$0.38 $7,795 
September 30, 2024$0.36 $8,104 
June 30, 2024$0.36 $7,770 
March 31, 2024$0.36 $7,329 
2023
December 31, 2023$0.36 $7,477 
September 30, 2023$0.34 $6,737 
June 30, 2023$0.34 $6,846 
March 31, 2023$0.34 $6,851 
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 920,951 shares available as of December 31, 2024.
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 183,605 and 346,869 restricted shares to executives, employees and independent directors of the Company during the years ended December 31, 2024, and 2023, respectively. 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 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 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, 2024, under the A&R LTIP:
2021 Long-Term Incentive Plan
Restricted Shares
Weighted Average Grant Date Fair Value
Unvested at December 31, 2023
521,997 $24.37 
Granted(1)
183,605 $28.75 
Vested(2)
(288,757)$24.43 
Forfeited(28,930)$27.83 
Unvested at December 31, 2024
387,915 $26.57 
_____________________
(1)For the year ended December 31, 2023, the weighted average fair value of restricted shares granted during the year was $28.68.
(2)For the years ended December 31, 2024, and 2023, the total fair value of restricted shares vested during the year was $7.1 million and $6.4 million, respectively.
For the years ended December 31, 2024, and 2023, the total share-based compensation expense was $8.1 million and $7.0 million, respectively. For the years ended December 31, 2024, and 2023, share based compensation expense also included expense associated with equity awards attributable to separation agreements with former Company executives. Share-based compensation expense is included in general and administrative costs in the Company's consolidated statements of operations for the restricted share awards granted under the A&R LTIP. If shares are subject to forfeiture, the Company will recognize any forfeited shares as a reduction to share-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. Approximately $7.8 million of additional share-based compensation expense will be recognized over the weighted average life of 22 months for the unvested restricted share awards as of December 31, 2024, granted under the A&R LTIP.
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 in shares of the Company's common stock through our agents. During the year ended December 31, 2024, the Company did not execute any sales under the ATM program. As of December 31, 2024, 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.
v3.25.0.1
Income Taxes
 12 Months Ended
Dec. 31, 2024
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
The components of the Company's consolidated provision for income taxes are as follows:
Year Ended December 31,
20242023
(In thousands)
Current income tax expense:
Federal$22,814 $5,852 
State2,058 1,020 
Total current income tax expense$24,872 $6,872 
Deferred income tax expense:
Federal$1,666 $24,305 
State1,536 3,284 
Total deferred income tax expense
$3,202 $27,589 
Total income tax expense
$28,074 $34,461 
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:
Year Ended December 31,
20242023
(In thousands)
Intangibles$146 $163 
Share-based compensation 1,129 772 
Interest expense limitation19 3,861 
Accruals and other 1,893 1,123 
Net operating loss2,639 2,700 
Total deferred tax assets$5,826 $8,619 
Oil and natural gas assets(80,972)(79,761)
Other fixed assets(628)(661)
Unrealized gain on derivatives(773)(1,542)
Total deferred tax liabilities$(82,373)$(81,964)
Net deferred tax liabilities$(76,547)$(73,345)
A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:
Year Ended December 31,
20242023
Tax at statutory rate21.0 %21.0 %
Nondeductible compensation0.7 %0.7 %
Share-based compensation(0.1)%(0.5)%
State income taxes, net of federal benefit2.4 %2.4 %
Effective income tax rate24.0 %23.6 %
The Company's federal income tax returns for the years subsequent to December 31, 2020 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, 2019. 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 $12.6 million of which $3.8 million will expire beginning in 2025 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.
v3.25.0.1
Net Income Per Share
 12 Months Ended
Dec. 31, 2024
Earnings Per Share [Abstract]  
Net Income Per Share 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:
Year Ended December 31,
20242023
(In thousands, except per share amounts)
Net income
$88,897 $111,591 
Basic weighted-average common shares outstanding
20,712 19,705 
Restricted shares
163 295 
Diluted weighted-average common shares outstanding
20,875 20,000 
Basic net income per common share
$4.29 $5.66 
Diluted net income per common share
$4.26 $5.58 

The following shares were excluded from the calculation of diluted net income per share due to their anti-dilutive effect for the periods presented:
Year Ended December 31,
20242023
Restricted shares
226,742 294,817 
v3.25.0.1
Segments
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Segments 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 into one 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:
Year Ended December 31,
20242023
(In thousands)
Total Revenues
$410,181 $375,047 
Less:
Lease operating expenses
71,463 58,817 
Production and ad valorem taxes
29,428 25,559 
Exploration costs
2,595 4,165 
Depletion, depreciation, amortization and accretion
74,900 65,055 
Impairment of oil and natural gas properties
11,317 9,760 
Other impairments
30,158 — 
Administrative Costs
26,551 26,569 
Share-based compensation expense
8,138 6,833 
Other segment items(1)
1,936 6,396 
Interest expense, net of capitalized interest(2)
35,204 32,049 
Interest income
(866)(233)
(Gain) loss on derivatives, net1,665 (6,193)
Loss from equity method investment721 218 
Income tax expense
28,074 34,461 
Segment net income(3)
$88,897 $111,591 
Total assets$993,501 $945,711 
Capital expenditures$108,320 $135,804 
Equity method investment$22,811 $5,620 
_____________________
(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.
v3.25.0.1
Commitment and Contingencies
 12 Months Ended
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies 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, 2024, and December 31, 2023. 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 had no material environmental liabilities as of December 31, 2024, or December 31, 2023.
Contractual Commitments
In August 2022, the Company entered into a second amendment on our gas gathering, treating and processing agreement with our 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 with less than seven years remaining as of December 31, 2024.
In January 2023, the Company entered into the Tolling Agreement which uses the Company's produced natural gas to power a portion of our oilfield operations in Yoakum County, Texas. Under the Tolling Agreement, 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. In June 2024, the Company entered into the A&R Tolling Agreement which superseded the Tolling Agreement to change the new in-service date to September 2024. The Company also entered into the 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 a 10-year natural gas supply agreement (“Supply Agreement”) with RPC Merchant LLC 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 occur beginning in late 2025 through 2026.
In May 2024, the Company increased our ownership interest in RPC Power from 35% to 50%. The Company also has a remaining commitment to invest up to an additional $27.7 million to fund our portion of the 2025 capital budget for the RPC Power joint venture.
See Note 8 - Equity Method Investment and Note 9 - Transactions with Related Parties for additional information related to RPC Power.
Gas Purchase Agreement
On December 31, 2024, the Company signed a long-term gas purchase agreement for our New Mexico field with a new midstream counterparty, which includes dedicated acreage for a significant portion of the Company’s oil and gas assets in New Mexico, reimbursement by the Company of construction costs incurred by the midstream counterparty to connect to the Company’s pipeline (subject to a monetary cap of $18.7 million) and an initial 15-year term from the in-service date followed by a year-to-year continuation until terminated by either party upon 180 days written notice. In conjunction with the agreement, the Company intends to construct, own and operate low and high-pressure gathering lines and compression facilities that will connect to our new high capacity 20-inch natural gas pipeline to be constructed by the Company and designed to handle gas volumes of up to 150 MMcf per day. We currently anticipate the in-service date will be before the end of 2026.
v3.25.0.1
Subsequent Events
 12 Months Ended
Dec. 31, 2024
Subsequent Events [Abstract]  
Subsequent Events Subsequent Events
Dividend Declaration
On January 9, 2025, the Board of Directors of the Company declared a cash dividend of $0.38 per share of common stock paid on February 6, 2025, to our shareholders of record at the close of business on January 23, 2025.
Equity Contribution to RPC Power
On February 28, 2025, the Company contributed an additional $6.3 million to RPC Power, which increased our total capital contributions to $30 million.
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited)
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Supplemental Oil and Gas Information (Unaudited) 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:
Year Ended December 31,
20242023
(In thousands)
Acquisition of properties
Proved$4,592 $228,147 
Unproved16,641 102,742 
Exploration costs— — 
Development costs106,773 152,309 
Total costs incurred$128,006 $483,198 
Results of Operations
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.
Year Ended December 31,
20242023
(In thousands)
Oil, natural gas and NGL sales$409,801 $372,647 
Lease operating expenses71,463 58,817 
Production and ad valorem taxes29,42825,559
Exploration costs2,5954,165
Depletion, accretion and amortization74,02564,471
Impairment of oil and natural gas properties11,317 9,760 
Other impairments30,158 — 
Results of operations$190,815 $209,875 
Income tax expense (1)
(43,105)(44,493)
Results of operations, net of income tax expense$147,710 $165,382 
_____________________
(1)    The statutory combined federal and state tax rate of 22.59% and 21.20% is used for the years ended December 31, 2024, and 2023, respectively.
Oil, Natural Gas and NGL Quantities
Our reserve report for the year ended December 31, 2024, and 2023, was 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:
OilNatural GasNGLsTotal
(MBbl)(MMcf)(MBbl)(MBoe)
December 31, 202248,882 86,018 14,454 77,673 
Acquisitions
12,810 39,261 6,711 26,064 
Extensions and discoveries14,822 22,945 4,224 22,870 
Revisions(5,403)(18,411)(3,634)(12,106)
Production(4,803)(5,865)(1,006)(6,786)
December 31, 202366,308 123,948 20,749 107,715 
Acquisitions
1,989 6,624 1,176 4,269 
Extensions and discoveries8,894 17,218 3,837 15,600 
Revisions(5,137)21,933 5,751 4,270 
Production(5,519)(7,484)(1,486)(8,252)
December 31, 202466,535 162,239 30,027 123,602 
Proved Developed Reserves, Included Above
December 31, 202229,632 59,314 9,604 49,122 
December 31, 202336,731 71,671 11,502 60,178 
December 31, 202440,111 103,337 19,312 76,646 
Proved Undeveloped Reserves, Included Above
December 31, 202219,250 26,704 4,850 28,551 
December 31, 202329,577 52,277 9,247 47,537 
December 31, 202426,424 58,902 10,715 46,956 
As of December 31, 2024, proved reserves were comprised of 53.8% oil, 21.9% natural gas and 24.3% NGL. 2024 proved reserves were estimated based on average realized prices of $74.27 per Bbl of oil, $(0.43) per Mcf of natural gas and $(3.56) per Bbl of NGL. Prices used in the 2024 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 2024 through December 2024. For oil and NGL volumes, the average WTI SEC price of $76.32 per Bbl was adjusted for quality, transportation fees, and market differentials which were included as a deduction to oil revenue. For gas volumes, the average Henry Hub SEC price of $2.13 per MMBtu is adjusted for energy content, transportation fees and market differentials which were included as a deduction to natural gas revenue.
As of December 31, 2023, proved 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 January 2023 through December 2023. For oil and NGL volumes, the average 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.
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 and the 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. 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, 2023, the Company had 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:
Year Ended December 31,
20242023
(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)
$4,764,599 $5,244,927 
Future production costs(1,638,032)(1,896,397)
Future development costs(325,414)(362,218)
Future income tax expense (524,581)(538,926)
Future net cash flows2,276,572 2,447,386 
10% annual discount(1,034,771)(1,186,921)
Standardized measure of discounted future net cash flows$1,241,801 $1,260,465 
_____________________
(1)    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.
(2)    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:
Year Ended December 31,
20242023
(In thousands)
Balance, beginning of period$1,260,465 $1,108,376 
Sales of crude oil, natural gas and NGLs, net(308,907)(288,270)
Net change in prices and production costs(238,938)(618,441)
Net changes in future development costs9,976 21,423 
Extensions and discoveries253,381 385,482 
Acquisition of reserves47,020 613,295 
Revisions of previous quantity estimates71,800 (188,364)
Previously estimated development costs incurred38,858 31,124 
Net change in income taxes(2,035)(5,976)
Accretion of discount158,406 140,115 
Other(48,225)61,701 
Balance, end of period$1,241,801 $1,260,465 
v3.25.0.1
Pay vs Performance Disclosure - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Pay vs Performance Disclosure    
Net income $ 88,897 $ 111,591
v3.25.0.1
Insider Trading Arrangements
 3 Months Ended 12 Months Ended
Dec. 31, 2024
shares
Dec. 31, 2024
shares
Trading Arrangements, by Individual    
Non-Rule 10b5-1 Arrangement Adopted false  
Rule 10b5-1 Arrangement Terminated false  
Non-Rule 10b5-1 Arrangement Terminated false  
Corey Riley [Member]    
Trading Arrangements, by Individual    
Material Terms of Trading Arrangement  
On November 13, 2024, Corey Riley, our Chief Information Officer and Chief Compliance Officer, adopted a trading plan intended to satisfy the affirmative defense of Rule 10b5-1(c) providing for the sale of up to 14,000 shares of Common Stock. The expiration date for Mr. Riley's plan is November 12, 2025.
Name Corey Riley  
Title Chief Information Officer and Chief Compliance Officer  
Rule 10b5-1 Arrangement Adopted true  
Adoption Date November 13, 2024  
Expiration Date November 12, 2025  
Arrangement Duration 364 days  
Aggregate Available 14,000 14,000
v3.25.0.1
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.0.1
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
Riley Permian recognizes the importance of assessing, identifying, and managing material risks associated with cybersecurity threats, as is defined in Item 106 (a) of Regulation S-K. These risks include, among other things: operational risks, harm to our employees, suppliers or industry partners, intellectual property theft, fraud, extortion, and violation of data
privacy or security laws. We use a risk management framework based on applicable laws and regulations and informed by industry standards and industry-recognized practices for identifying and managing cybersecurity risks within our operations, infrastructure and corporate resources.
Our cybersecurity program is built upon internationally recognized frameworks and maps to standards published by The National Institute of Standards and Technology ("NIST CSF"), which develops cybersecurity standards, guidelines, best practices and other resources to meet the needs of U.S. industry, federal agencies and the broader public. Utilizing monitoring technologies in conjunction with a well-established framework of policies, procedures and controls, our processes provide us with the structure to detect and respond to cyber threats, thereby mitigating the risk of potential cybersecurity issues. In addition, we conduct reoccurring security awareness training, penetration tests, and vulnerability assessments to identify any potential threats or vulnerabilities in our systems. Our processes to assess, identify and manage material risks from cyber threats include the risks arising from threats associated with third party service providers, including cloud-based platforms.
We have developed a robust cyber incident response plan which provides a documented framework for handling high severity security incidents and facilitates coordination across a cross-disciplinary team of employees, legal counsel and third party service providers. Our information security team, which is part of our IT department, constantly monitors threat intelligence feeds, handles vulnerability management, responds to incidents and reports to the Information Security Coordinator. Upon detection of an event that meets certain assessment thresholds, the Information Security Coordinator reports such matters to the Incident Response Team, who then review the event and report to senior management, the cyber committee or our Board as appropriate. Cybersecurity events and data incidents are evaluated, ranked by severity and prioritized for response and remediation. Incidents are evaluated to determine materiality as well as operational and business impact, and reviewed for privacy impact.
Internally, we have developed a cybersecurity awareness program which includes training that reinforces our information technology and security policies, standards and practices, and we require that our employees comply with these policies. The cybersecurity awareness program offers training on how to identify potential cybersecurity risks and protect our resources and information. Finally, our privacy program requires all employees to take periodic awareness training on data privacy. This training includes information about confidentiality and security, as well as responding to unauthorized access to or use of information.
From time to time, we engage third-party service providers to enhance our risk mitigation efforts. For example, we have engaged a multifaceted cybersecurity advisory firm specializing in risk management and compliance, to perform annual cybersecurity risk assessments utilizing industry standard cybersecurity frameworks.
We also purchase insurance to protect us against the risk of cybersecurity breaches. Our Vice President of Finance and Treasurer is responsible for our insurance policies and reviews on a regular basis our cyber insurance policy with management to ensure we have appropriate coverage. We have business continuity, contingency and disaster recovery plans and procedures in place in the event of a cybersecurity incident. These plans are tested in conjunction with the Company’s annual testing of our cybersecurity incident response readiness and reporting through tabletop exercises.
To date, risks from cybersecurity threats have not previously materially affected us, and we currently do not expect that the risks from cybersecurity threats are reasonably likely to materially affect us, including our business, strategy, results of operations or financial condition. That said, as discussed more fully under “Item 1A – Risk Factors”, the sophistication of cyber threats continues to increase, and the preventative actions we take to reduce the risk of cyber incidents and protect our systems and information may be insufficient. Accordingly, no matter how well designed or implemented our controls are, we will not be able to anticipate all security breaches of these types, including security threats that may result from third parties improperly employing AI technologies, and we may not be able to implement effective preventive measures against such security breaches in a timely manner.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block]
Riley Permian recognizes the importance of assessing, identifying, and managing material risks associated with cybersecurity threats, as is defined in Item 106 (a) of Regulation S-K. These risks include, among other things: operational risks, harm to our employees, suppliers or industry partners, intellectual property theft, fraud, extortion, and violation of data
privacy or security laws. We use a risk management framework based on applicable laws and regulations and informed by industry standards and industry-recognized practices for identifying and managing cybersecurity risks within our operations, infrastructure and corporate resources.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
The Nominating and Corporate Governance Committee of the Board of Directors is primarily responsible for the oversight of our information security programs and cybersecurity incident response plans. We established a cyber subcommittee comprised of our senior management team that reports directly to the Board and its Committees regarding our cyber risks and threats, the status of initiatives strengthens our information security systems, assessments of our cybersecurity program and incident response plan, and our views of the emerging threat landscape. Our Chief Information and Compliance Officer and our head of Internal Audit report directly to the Nominating and Corporate Governance Committee as well as the Audit Committee regarding these matters and are responsible for reporting to the Committees on our company-wide enterprise risk assessment, and that assessment also includes an evaluation of cyber risks and threats. The Chair of the Nominating and Corporate Governance Committee regularly reports to the Board of Director on cybersecurity risks and other matters reviewed by the
Nominating and Corporate Governance Committee in conjunction with the management team. All materials or presentations on cybersecurity provided to the Nominating and Corporate Governance Committee are provided to all Board members.
As a matter of process, the Nominating and Corporate Governance Committee annually reviews, and recommends to the Board of Directors its approval of, our information security policy and cybersecurity program and our incident response plans. Furthermore, on an annual basis, the Board of Directors and its Committees review and discuss our technology strategy with our Chief Information and Compliance Officer and approve our technology strategic plan.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Nominating and Corporate Governance Committee of the Board of Directors is primarily responsible for the oversight of our information security programs and cybersecurity incident response plans. We established a cyber subcommittee comprised of our senior management team that reports directly to the Board and its Committees regarding our cyber risks and threats, the status of initiatives strengthens our information security systems, assessments of our cybersecurity program and incident response plan, and our views of the emerging threat landscape.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] Our Chief Information and Compliance Officer and our head of Internal Audit report directly to the Nominating and Corporate Governance Committee as well as the Audit Committee regarding these matters and are responsible for reporting to the Committees on our company-wide enterprise risk assessment, and that assessment also includes an evaluation of cyber risks and threats.
Cybersecurity Risk Role of Management [Text Block]
Our Chief Information and Compliance Officer is responsible for the day-to-day management of our cybersecurity risks and for recommending the strategies and technologies used by the organization to collect, integrate and analyze business information to support the organization's strategic decisions. He is supported by a cross-disciplinary team from the Company’s accounting, legal and risk oversight functions and our internal audit group. This incident response team meets quarterly and as needed to review the Company’s cybersecurity risk management initiatives and progress and cybersecurity metrics. On an annual basis, the incident response team coordinates a cybersecurity risk assessment. In the event of a suspected cybersecurity incident, the team will coordinate the Company’s evaluation, subsequent response and any updates to the cybersecurity risk management program with executive management and the cyber subcommittee.
We have a security incident response framework in place. We use this incident response framework as part of the process we employ to keep our management and Board of Directors informed about and monitor the prevention, detection, mitigation, and remediation of cybersecurity incidents. The framework is a set of coordinated procedures and tasks that our incident response team, under the direction of the Information Security Officers, executes with the goal of ensuring timely and accurate resolution of cybersecurity incidents. Our cybersecurity framework includes regular compliance assessments with our policies and standards and applicable state and federal statutes and regulations. In addition, we validate compliance with our internal data security controls through the use of security monitoring utilities and internal and external audits.
Our Information Security Coordinator, members of our incident response team and our third party consultants each have extensive experience in the information technology area. The Chief Information and Compliance Officer has over 11 years of experience in the information technology area and holds a Master of Business Administration with a focus in Technology from Oklahoma Christian University. Additionally, our Vice President of Technology and Analytics has 11 years of professional experience in the information security area.
Additionally, our management team's internal cybersecurity risk management and strategy processes are supported with third party consultants with extensive work experience in various roles involving information technology, including security, auditing, compliance, systems and programming. These individuals are informed about, and monitor the prevention, mitigation, detection and remediation of cybersecurity incidents through their management of, and participation in, the cybersecurity risk management and strategy processes described above, including the operation of our incident response plan, and report to the Board of Directors, Nominating and Corporate Governance Committee and Audit Committee, as the case may be, on any appropriate items.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
Our Chief Information and Compliance Officer is responsible for the day-to-day management of our cybersecurity risks and for recommending the strategies and technologies used by the organization to collect, integrate and analyze business information to support the organization's strategic decisions. He is supported by a cross-disciplinary team from the Company’s accounting, legal and risk oversight functions and our internal audit group. This incident response team meets quarterly and as needed to review the Company’s cybersecurity risk management initiatives and progress and cybersecurity metrics. On an annual basis, the incident response team coordinates a cybersecurity risk assessment. In the event of a suspected cybersecurity incident, the team will coordinate the Company’s evaluation, subsequent response and any updates to the cybersecurity risk management program with executive management and the cyber subcommittee.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] The Chief Information and Compliance Officer has over 11 years of experience in the information technology area and holds a Master of Business Administration with a focus in Technology from Oklahoma Christian University. Additionally, our Vice President of Technology and Analytics has 11 years of professional experience in the information security area.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] Additionally, our management team's internal cybersecurity risk management and strategy processes are supported with third party consultants with extensive work experience in various roles involving information technology, including security, auditing, compliance, systems and programming. These individuals are informed about, and monitor the prevention, mitigation, detection and remediation of cybersecurity incidents through their management of, and participation in, the cybersecurity risk management and strategy processes described above, including the operation of our incident response plan, and report to the Board of Directors, Nominating and Corporate Governance Committee and Audit Committee, as the case may be, on any appropriate items.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.0.1
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Consolidation 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.
Reclassification 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
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.
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, if failure to collect is expected to occur. 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.
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 valued at the lower of cost or net realizable value.
Proved Oil and Natural Gas Properties, Unproved Oil and Natural Gas Properties and Impairment of 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.
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.
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 consists of midstream property and equipment, computer equipment, computer software, office furniture, tools and equipment, buildings and improvements, and vehicles.
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 Cost
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.
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.
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 from one to ten 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.
Contract Services with Related Parties The Company had contracts with related parties to provide certain contract operating, accounting and back-office support services. 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.
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 payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel, 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.
Interest Expense, net
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 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.
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.
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, 2024, and 2023, one purchaser accounted for 70% of our revenue purchased. For the year ended December 31, 2024, and 2023, an additional 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.
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. 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, 2024, and 2023, 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, 2024, and 2023, 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 ROU asset, current lease liability and non-current lease liability are included in other non-current assets, net, other current liabilities and other non-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 the Company's fiscal year 2025. Early adoption is permitted. The Company does not expect this standard to have a material impact on our 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.
v3.25.0.1
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2024
Accounting Policies [Abstract]  
Schedule of Accounts Receivable
Accounts receivable, net is summarized below:
December 31,
20242023
(In thousands)
Oil, natural gas and NGL sales$38,374 $31,135 
Joint interest accounts receivable4,884 1,630 
Allowance for credit losses
(62)— 
Other accounts receivable1,215 2,361 
Total accounts receivable, net
$44,411 $35,126 
Schedule of Other Property and Equipment
Other property and equipment, net is summarized below:
December 31,
20242023
(In thousands)
Midstream property and equipment
$11,297 $— 
Furniture, fixtures and other
5,882 6,605 
Land
16,673 16,673 
$33,852 $23,278 
Accumulated depreciation and amortization
(3,375)(2,625)
Total other property and equipment, net
$30,477 $20,653 
Schedule of Other Non-current Assets, Net
Other non-current assets, net consisted of the following:
December 31,
20242023
(In thousands)
Deferred financing costs, net$4,949 $3,844 
Right-of-use assets
1,398 1,890 
Other
4,359 1,241 
Total other non-current assets, net$10,706 $6,975 
Schedule of Accrued Liabilities
Accrued liabilities consisted of the following:
December 31,
20242023
(In thousands)
Accrued capital expenditures$10,441 $15,851 
Accrued lease operating expenses7,676 6,038 
Accrued general and administrative costs8,123 4,655 
Accrued inventory1,709 — 
Accrued ad valorem tax5,396 5,269 
Other accrued expenditures573 1,346 
Total accrued liabilities$33,918 $33,159 
Schedule of Other Current Liabilities
Other current liabilities consisted of the following:
December 31,
20242023
(In thousands)
Advances from joint interest owners$11,278 $259 
Income taxes payable5,233 561 
Current ARO liabilities2,562 3,789 
Other1,050 1,667 
Total other current liabilities
$20,123 $6,276 
Schedule of Asset Retirement Obligations
Components of the changes in ARO consisted of the following and is shown below:
December 31,
20242023
(In thousands)
ARO, beginning balance$23,044 $3,038 
Liabilities incurred78 45 
Liabilities assumed in acquisitions
9,727 19,359 
Revision of estimated obligations1,856 — 
Liability settlements and disposals(2,291)(1,039)
Accretion2,854 1,641 
ARO, ending balance$35,268 $23,044 
Less: current ARO (1)
(2,562)(3,789)
ARO, long-term$32,706 $19,255 
_____________________
(1)Current ARO is included within other current liabilities in our consolidated balance sheets.
Summary of Disaggregation of Revenue
The following table presents oil and natural gas sales disaggregated by product:
Year Ended December 31,
20242023
(In thousands)
Oil and natural gas sales:
Oil$408,935 $363,125 
Natural gas(1,412)2,612 
NGLs
2,278 6,910 
Total oil and natural gas sales, net (1)
$409,801 $372,647 
_____________________
(1) The Company's oil, natural gas and NGL sales are presented net of gathering, processing and transportation costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.
Schedule of Assets And Liabilities, Lessee
December 31,
20242023
(In thousands)
ROU asset$1,398 $1,890 
Current lease liability$758 $985 
Long-term lease liability$673 $938 
v3.25.0.1
Acquisitions of Oil and Natural Gas Properties (Tables)
 12 Months Ended
Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]  
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed
The following presents the allocation of the total purchase price of the 2023 New Mexico Acquisition to the identified assets acquired and liabilities assumed based on estimated fair value as of the Closing Date:
Purchase price allocation as of December 31, 2023 (in thousands):
Total cash consideration$324,686 
Assets acquired:
Inventory$2,980 
Oil and natural gas properties342,308 
Other
149 
Amount attributable to assets acquired$345,437 
Fair value of liabilities assumed:
Revenue payable$1,475 
Asset retirement obligations19,276 
Amount attributable to liabilities assumed$20,751 
Net assets acquired$324,686 
Schedule of Business Acquisition, Pro Forma Information
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 2023 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 2023 New Mexico Acquisition. These adjustments reflect such costs, as described above, that would have been recognized had the Company acquired the assets on January 1, 2022. In addition, the pro forma information has been effected for taxes with a 23% tax rate for the years ended December 31, 2023, and 2022.
Year Ended December 31,
2023
2022
(In thousands, except per share amounts)
Total revenues
$405,642 $435,157 
Net income
$121,466 $129,741 
Basic net income per common share
$6.16 $6.64 
Diluted net income per common share
$6.07 $6.59 
v3.25.0.1
Oil and Natural Gas Properties (Tables)
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Schedule of Oil and Gas Properties
Oil and natural gas properties are summarized below:
December 31,
20242023
(In thousands)
Proved$1,027,183 $895,783 
Unproved100,974 100,216 
Work-in-progress21,318 57,004 
$1,149,475 $1,053,003 
Accumulated depletion, amortization and impairment(288,678)(206,102)
Total oil and natural gas properties, net$860,797 $846,901 
v3.25.0.1
Derivative Instruments (Tables)
 12 Months Ended
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Notional Amounts of Outstanding Derivative Positions
The following table summarizes the open financial derivative positions as of December 31, 2024, related to oil and natural gas production:
Weighted Average Price
Calendar Quarter / YearNotional VolumeFixedPutCall
($ per unit)
Oil Swaps (Bbl)
Q1 2025375,000 $74.31 
Q2 2025345,000 $71.32 
Q3 2025165,000 $68.53 
Q4 2025120,000 $66.99 
Natural Gas Swaps (Mcf)
Q1 2025965,000 $3.61 
Q2 2025495,000 $3.34 
Q3 2025480,000 $3.30 
Q4 20251,165,000 $3.82 
20262,555,000 $3.92 
2027600,000 $4.19 
Oil Collars (Bbl)
Q1 2025468,000 $60.48 $77.04 
Q2 2025300,000 $66.50 $78.77 
Q3 2025452,000 $64.23 $74.19 
Q4 2025480,000 $63.10 $77.07 
20261,107,000 $58.89 $76.99 
Natural Gas Collars (Mcf)
Q1 2025555,000 $3.46 $4.38 
Q2 20251,080,000 $3.04 $3.65 
Q3 20251,110,000 $3.12 $3.76 
Q4 2025400,000 $3.30 $4.00 
20262,675,000 $3.15 $3.82 
The following table summarizes the open interest rate derivative positions as of December 31, 2024:
Open Coverage Period
Position
Notional AmountFixed Rate
(In thousands)
January 2025 - April 2026
Long
$30,000 3.18 %
January 2025 - April 2026
Long
$50,000 3.04 %
April 2026 - April 2027
Long
$45,000 3.90 %
Schedule of Derivative Instruments Location and Fair Value
The following tables present the location and fair value of the Company’s derivative contracts included in our consolidated balance sheets as of December 31, 2024, and 2023:
December 31, 2024
Balance Sheet ClassificationGross Fair ValueAmounts NettedNet Fair Value
(In thousands)
Current derivative assets$9,817 $(6,553)$3,264 
Non-current derivative assets6,661 (6,076)585 
Current derivative liabilities(6,553)6,553 — 
Non-current derivative liabilities(6,490)6,076 (414)
Total$3,435 $— $3,435 
December 31, 2023
Balance Sheet ClassificationGross Fair ValueAmounts NettedNet Fair Value
(In thousands)
Current derivative assets$8,948 $(3,935)$5,013 
Non-current derivative assets6,687 (4,391)2,296 
Current derivative liabilities(4,295)3,935 (360)
Non-current derivative liabilities(4,391)4,391 — 
Total$6,949 $— $6,949 
Schedule of Derivative Instruments, Gain (Loss), Net
The following table presents the components of the Company's gain (loss) on derivatives, net for the periods presented below:
Year Ended December 31,
20242023
(In thousands)
Settlements on derivative contracts
$1,849 $(17,221)
Non-cash gain (loss) on derivatives(3,514)23,414 
Gain (loss) on derivatives, net$(1,665)$6,193 
v3.25.0.1
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2024
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2024, and 2023, by level within the fair value hierarchy:
December 31, 2024
Level 1Level 2Level 3Total
(In thousands)
Financial assets:
Commodity derivative assets$— $15,301 $— $15,301 
Interest rate assets$— $1,177 $— $1,177 
Financial liabilities:
Commodity derivative liabilities$— $(13,043)$— $(13,043)
December 31, 2023
Level 1Level 2Level 3Total
(In thousands)
Financial assets:
Commodity derivative assets$— $14,766 $— $14,766 
Interest rate assets$— $869 $— $869 
Financial liabilities:
Commodity derivative liabilities$— $(8,686)$— $(8,686)
The following table summarizes the fair value and carrying amount of the Company's financial instruments.
December 31, 2024December 31, 2023
Carrying AmountFair ValueCarrying AmountFair Value
(In thousands)
Credit Facility (Level 2)$115,000 $115,000 $185,000 $185,000 
Senior Notes (Level 2)(1)
$154,494 $172,864 $170,959 $185,346 
_____________________
(1)The carrying value reported for the Senior Notes is shown net of unamortized discount and unamortized deferred financing costs.
v3.25.0.1
Equity Method Investment (Tables)
 12 Months Ended
Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]  
Schedule of Equity Method Investment
The following table presents the Company's equity method investment activity:
Year Ended December 31,
20242023
(In thousands)
Equity method investment, beginning balance$5,620 $— 
Contributions17,912 5,838 
Loss from equity method investment(721)(218)
Equity method investment, ending balance
$22,811 $5,620 
v3.25.0.1
Transactions with Related Parties (Tables)
 12 Months Ended
Dec. 31, 2024
Related Party Transactions [Abstract]  
Schedule of Related Party Transactions
The following table presents revenues from and related cost for contract services for related parties:
Year Ended December 31,
20242023
(In thousands)
Combo$100 $1,200 
REG280 1,200 
Contract services - related parties$380 $2,400 
Cost of contract services$363 $579 
v3.25.0.1
Long-Term Debt (Tables)
 12 Months Ended
Dec. 31, 2024
Debt Disclosure [Abstract]  
Schedule of Debt
The following table summarizes the Company's outstanding debt:
December 31,
20242023
(In thousands)
Credit Facility$115,000 $185,000 
Senior Notes
Principal$165,000 $185,000 
Less: Unamortized discount(1)
7,547 10,117 
Less: Unamortized deferred financing costs(1)
2,959 3,924 
Total Senior Notes$154,494 $170,959 
Total debt
$269,494 $355,959 
Less: Current portion of long-term debt(2)
20,000 20,000 
Total long-term debt$249,494 $335,959 
_____________________
(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, 2024, and 2023, the current portion of long-term debt reflects $20 million due on the Senior Notes over the next twelve months.
Schedule of Maturities of Long-Term Debt
Debt maturities as of December 31, 2024, excluding unamortized deferred financing costs, are as follows:
Year Ending December 31,
(In thousands)
2025$20,000 
202620,000 
2027 (1)
135,000 
2028105,000 
2029— 
Thereafter
— 
Total
$280,000 
_____________________
(1)The credit facility amount outstanding of $115 million as of December 31, 2024, 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.
Schedule of Credit Facility The following table summarizes the Credit Facility balances:
December 31,
20242023
(In thousands)
Outstanding borrowings$115,000 $185,000 
Available under the borrowing base$285,000 $190,000 
Schedule of Components of Interest Expense
The following table summarizes the Company's interest expense:
Year Ended December 31,
20242023
(In thousands)
Interest expense
$31,411 $30,464 
Interest income
(866)(233)
Capitalized interest(2,350)(3,187)
Amortization of deferred financing costs
2,730 2,278 
Amortization of discount on Senior Notes
2,569 1,883 
Unused commitment fees on Credit Facility
844 611 
Total interest expense, net$34,338 $31,816 
v3.25.0.1
Shareholders' Equity (Tables)
 12 Months Ended
Dec. 31, 2024
Equity [Abstract]  
Schedule of Cash Distributions Declared
The table below summarizes the following cash distributions declared to common shareholders during the periods presented below:
Quarter Ended
Per Share Distribution
Total Distribution
(In thousands)
2024
December 31, 2024$0.38 $7,795 
September 30, 2024$0.36 $8,104 
June 30, 2024$0.36 $7,770 
March 31, 2024$0.36 $7,329 
2023
December 31, 2023$0.36 $7,477 
September 30, 2023$0.34 $6,737 
June 30, 2023$0.34 $6,846 
March 31, 2023$0.34 $6,851 
Schedule of Restricted Stock, Activity
The following table presents the Company's restricted stock activity during the year ended December 31, 2024, under the A&R LTIP:
2021 Long-Term Incentive Plan
Restricted Shares
Weighted Average Grant Date Fair Value
Unvested at December 31, 2023
521,997 $24.37 
Granted(1)
183,605 $28.75 
Vested(2)
(288,757)$24.43 
Forfeited(28,930)$27.83 
Unvested at December 31, 2024
387,915 $26.57 
_____________________
(1)For the year ended December 31, 2023, the weighted average fair value of restricted shares granted during the year was $28.68.
(2)For the years ended December 31, 2024, and 2023, the total fair value of restricted shares vested during the year was $7.1 million and $6.4 million, respectively.
v3.25.0.1
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2024
Income Tax Disclosure [Abstract]  
Schedule of Components of Income Tax Expense
The components of the Company's consolidated provision for income taxes are as follows:
Year Ended December 31,
20242023
(In thousands)
Current income tax expense:
Federal$22,814 $5,852 
State2,058 1,020 
Total current income tax expense$24,872 $6,872 
Deferred income tax expense:
Federal$1,666 $24,305 
State1,536 3,284 
Total deferred income tax expense
$3,202 $27,589 
Total income tax expense
$28,074 $34,461 
Schedule of Deferred Tax Assets and Liabilities The Company's net deferred tax position is as follows:
Year Ended December 31,
20242023
(In thousands)
Intangibles$146 $163 
Share-based compensation 1,129 772 
Interest expense limitation19 3,861 
Accruals and other 1,893 1,123 
Net operating loss2,639 2,700 
Total deferred tax assets$5,826 $8,619 
Oil and natural gas assets(80,972)(79,761)
Other fixed assets(628)(661)
Unrealized gain on derivatives(773)(1,542)
Total deferred tax liabilities$(82,373)$(81,964)
Net deferred tax liabilities$(76,547)$(73,345)
Schedule of Effective Income Tax Rate Reconciliation
A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:
Year Ended December 31,
20242023
Tax at statutory rate21.0 %21.0 %
Nondeductible compensation0.7 %0.7 %
Share-based compensation(0.1)%(0.5)%
State income taxes, net of federal benefit2.4 %2.4 %
Effective income tax rate24.0 %23.6 %
v3.25.0.1
Net Income Per Share (Tables)
 12 Months Ended
Dec. 31, 2024
Earnings Per Share [Abstract]  
Schedule of Computation of Basic and Diluted Net Income Per Share The table below sets forth the computation of basic and diluted net income per share for the periods presented below:
Year Ended December 31,
20242023
(In thousands, except per share amounts)
Net income
$88,897 $111,591 
Basic weighted-average common shares outstanding
20,712 19,705 
Restricted shares
163 295 
Diluted weighted-average common shares outstanding
20,875 20,000 
Basic net income per common share
$4.29 $5.66 
Diluted net income per common share
$4.26 $5.58 
Schedule of Anti-Dilutive Shares
The following shares were excluded from the calculation of diluted net income per share due to their anti-dilutive effect for the periods presented:
Year Ended December 31,
20242023
Restricted shares
226,742 294,817 
v3.25.0.1
Segments (Tables)
 12 Months Ended
Dec. 31, 2024
Segment Reporting [Abstract]  
Schedule of Segment Reporting Information, by Segment
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:
Year Ended December 31,
20242023
(In thousands)
Total Revenues
$410,181 $375,047 
Less:
Lease operating expenses
71,463 58,817 
Production and ad valorem taxes
29,428 25,559 
Exploration costs
2,595 4,165 
Depletion, depreciation, amortization and accretion
74,900 65,055 
Impairment of oil and natural gas properties
11,317 9,760 
Other impairments
30,158 — 
Administrative Costs
26,551 26,569 
Share-based compensation expense
8,138 6,833 
Other segment items(1)
1,936 6,396 
Interest expense, net of capitalized interest(2)
35,204 32,049 
Interest income
(866)(233)
(Gain) loss on derivatives, net1,665 (6,193)
Loss from equity method investment721 218 
Income tax expense
28,074 34,461 
Segment net income(3)
$88,897 $111,591 
Total assets$993,501 $945,711 
Capital expenditures$108,320 $135,804 
Equity method investment$22,811 $5,620 
_____________________
(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.
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Schedule of Exploration Expenses
The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the periods presented below:
Year Ended December 31,
20242023
(In thousands)
Acquisition of properties
Proved$4,592 $228,147 
Unproved16,641 102,742 
Exploration costs— — 
Development costs106,773 152,309 
Total costs incurred$128,006 $483,198 
Schedule of Results of Operations for Oil and Gas Producing Activities Disclosure
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.
Year Ended December 31,
20242023
(In thousands)
Oil, natural gas and NGL sales$409,801 $372,647 
Lease operating expenses71,463 58,817 
Production and ad valorem taxes29,42825,559
Exploration costs2,5954,165
Depletion, accretion and amortization74,02564,471
Impairment of oil and natural gas properties11,317 9,760 
Other impairments30,158 — 
Results of operations$190,815 $209,875 
Income tax expense (1)
(43,105)(44,493)
Results of operations, net of income tax expense$147,710 $165,382 
_____________________
(1)    The statutory combined federal and state tax rate of 22.59% and 21.20% is used for the years ended December 31, 2024, and 2023, respectively.
Oil and Gas, Proved Reserve, Quantity
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:
OilNatural GasNGLsTotal
(MBbl)(MMcf)(MBbl)(MBoe)
December 31, 202248,882 86,018 14,454 77,673 
Acquisitions
12,810 39,261 6,711 26,064 
Extensions and discoveries14,822 22,945 4,224 22,870 
Revisions(5,403)(18,411)(3,634)(12,106)
Production(4,803)(5,865)(1,006)(6,786)
December 31, 202366,308 123,948 20,749 107,715 
Acquisitions
1,989 6,624 1,176 4,269 
Extensions and discoveries8,894 17,218 3,837 15,600 
Revisions(5,137)21,933 5,751 4,270 
Production(5,519)(7,484)(1,486)(8,252)
December 31, 202466,535 162,239 30,027 123,602 
Proved Developed Reserves, Included Above
December 31, 202229,632 59,314 9,604 49,122 
December 31, 202336,731 71,671 11,502 60,178 
December 31, 202440,111 103,337 19,312 76,646 
Proved Undeveloped Reserves, Included Above
December 31, 202219,250 26,704 4,850 28,551 
December 31, 202329,577 52,277 9,247 47,537 
December 31, 202426,424 58,902 10,715 46,956 
Summary of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure
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:
Year Ended December 31,
20242023
(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)
$4,764,599 $5,244,927 
Future production costs(1,638,032)(1,896,397)
Future development costs(325,414)(362,218)
Future income tax expense (524,581)(538,926)
Future net cash flows2,276,572 2,447,386 
10% annual discount(1,034,771)(1,186,921)
Standardized measure of discounted future net cash flows$1,241,801 $1,260,465 
_____________________
(1)    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.
(2)    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:
Year Ended December 31,
20242023
(In thousands)
Balance, beginning of period$1,260,465 $1,108,376 
Sales of crude oil, natural gas and NGLs, net(308,907)(288,270)
Net change in prices and production costs(238,938)(618,441)
Net changes in future development costs9,976 21,423 
Extensions and discoveries253,381 385,482 
Acquisition of reserves47,020 613,295 
Revisions of previous quantity estimates71,800 (188,364)
Previously estimated development costs incurred38,858 31,124 
Net change in income taxes(2,035)(5,976)
Accretion of discount158,406 140,115 
Other(48,225)61,701 
Balance, end of period$1,241,801 $1,260,465 
v3.25.0.1
Nature of Business (Details)
May 07, 2024
a
Apr. 03, 2023
a
Apr. 03, 2023
horizontal_well
Apr. 03, 2023
vertical_well
New Mexico Asset Acquisition, 2023        
Schedule of Asset Acquisition [Line Items]        
Net acres of leasehold targeting acquired   10,600    
Number of wells acquired, producing     18 250
2024 New Mexico Asset Acquisition        
Schedule of Asset Acquisition [Line Items]        
Net acres of leasehold targeting acquired 13,900      
v3.25.0.1
Summary of Significant Accounting Policies - Narrative (Details) - USD ($)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Property, Plant and Equipment [Line Items]      
Cash equivalents $ 0 $ 0  
Receivables from oil, natural gas and NGL sales 38,374,000 31,135,000 $ 24,100,000
Unrecognized tax benefits 0 0  
Interest expense 34,338,000 31,816,000  
Joint interest accounts receivable $ 4,884,000 $ 1,630,000  
Weighted average discount rate 7.79% 9.56%  
Weighted average remaining lease term 2 years 2 months 12 days 2 years 3 months 18 days  
Lease expense $ 1,200,000 $ 800,000  
ROU asset [Extensible Enumeration] Other non-current assets, net Other non-current assets, net  
Current lease liability [Extensible Enumeration] Other current liabilities Other current liabilities  
Long-term lease liability [Extensible Enumeration] Other non-current liabilities Other non-current liabilities  
One Purchaser | Revenue from Contract with Customer Benchmark | Customer Concentration Risk      
Property, Plant and Equipment [Line Items]      
Concentration risk, percentage 70.00% 70.00%  
Revolving Credit Facility | Line of Credit      
Property, Plant and Equipment [Line Items]      
Additional financing costs $ 2,700,000 $ 2,800,000  
Minimum      
Property, Plant and Equipment [Line Items]      
Accounts receivable, due payment period 30 days    
Property and equipment, useful life 5 years    
Contract term 1 year    
Maximum      
Property, Plant and Equipment [Line Items]      
Accounts receivable, due payment period 60 days    
Property and equipment, useful life 39 years    
Contract term 10 years    
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Accounts Receivable (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Accounting Policies [Abstract]      
Oil, natural gas and NGL sales $ 38,374 $ 31,135 $ 24,100
Joint interest accounts receivable 4,884 1,630  
Allowance for credit losses (62) 0  
Other accounts receivable 1,215 2,361  
Accounts receivable, net $ 44,411 $ 35,126  
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Other Property and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, costs $ 33,852 $ 23,278
Accumulated depreciation and amortization (3,375) (2,625)
Total other property and equipment, net 30,477 20,653
Midstream property and equipment    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, costs 11,297 0
Furniture, fixtures and other    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, costs 5,882 6,605
Land    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, costs $ 16,673 $ 16,673
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Other Non-current Assets, Net (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Accounting Policies [Abstract]    
Deferred financing costs, net $ 4,949 $ 3,844
Right-of-use assets 1,398 1,890
Other 4,359 1,241
Total other non-current assets, net $ 10,706 $ 6,975
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Accounting Policies [Abstract]    
Accrued capital expenditures $ 10,441 $ 15,851
Accrued lease operating expenses 7,676 6,038
Accrued general and administrative costs 8,123 4,655
Accrued inventory 1,709 0
Accrued ad valorem tax 5,396 5,269
Other accrued expenditures 573 1,346
Total accrued liabilities $ 33,918 $ 33,159
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Other Current Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Accounting Policies [Abstract]    
Advances from joint interest owners $ 11,278 $ 259
Income taxes payable 5,233 561
Current ARO liabilities 2,562 3,789
Other 1,050 1,667
Total other current liabilities $ 20,123 $ 6,276
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
ARO, beginning balance $ 23,044 $ 3,038
Liabilities incurred 78 45
Liabilities assumed in acquisitions 9,727 19,359
Revision of estimated obligations 1,856 0
Liability settlements and disposals (2,291) (1,039)
Accretion 2,854 1,641
ARO, ending balance 35,268 23,044
Less: current ARO (2,562) (3,789)
ARO, long-term $ 32,706 $ 19,255
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]    
Total Revenues $ 410,181 $ 375,047
Oil and natural gas sales, net    
Disaggregation of Revenue [Line Items]    
Total Revenues 409,801 372,647
Oil    
Disaggregation of Revenue [Line Items]    
Total Revenues 408,935 363,125
Natural Gas    
Disaggregation of Revenue [Line Items]    
Total Revenues (1,412) 2,612
NGLs    
Disaggregation of Revenue [Line Items]    
Total Revenues $ 2,278 $ 6,910
v3.25.0.1
Summary of Significant Accounting Policies - Schedule of ROU Assets and Lease Liability (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Accounting Policies [Abstract]    
ROU asset $ 1,398 $ 1,890
Current lease liability 758 985
Long-term lease liability $ 673 $ 938
v3.25.0.1
Acquisitions of Oil and Natural Gas Properties - Narrative (Details)
 12 Months Ended
May 07, 2024
USD ($)
a
Apr. 03, 2023
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Apr. 03, 2023
a
Apr. 03, 2023
horizontal_well
Apr. 03, 2023
vertical_well
Feb. 22, 2023
USD ($)
Dec. 31, 2022
Business Acquisition [Line Items]                  
Transaction costs     $ 1,573,000 $ 5,817,000          
2024 New Mexico Asset Acquisition                  
Business Acquisition [Line Items]                  
Net acres of leasehold targeting acquired | a 13,900                
Payments for asset acquisitions $ 19,100,000                
Aggregate purchase price, transaction cost $ 500,000                
Senior Notes | 10.50% Senior Unsecured Notes due 2028                  
Business Acquisition [Line Items]                  
Debt instrument, face amount   $ 200,000,000           $ 200,000,000  
New Mexico Asset Acquisition, 2023                  
Business Acquisition [Line Items]                  
Aggregate purchase price   324,700,000              
Net acres of leasehold targeting acquired | a         10,600        
Number of wells acquired           18 250    
Transaction costs       $ 5,800,000          
Tax rate       23.00%         23.00%
Net acres of leasehold targeting acquired | a         10,600        
New Mexico Asset Acquisition, 2023 | Senior Notes | 10.50% Senior Unsecured Notes due 2028                  
Business Acquisition [Line Items]                  
Debt instrument, face amount   $ 200,000,000              
v3.25.0.1
Acquisitions of Oil and Natural Gas Properties - Schedule of Recognized Identified Assets Acquired and Liabilities Assumed (Details) - New Mexico Asset Acquisition, 2023
$ in Thousands
 12 Months Ended
Dec. 31, 2023
USD ($)
Business Acquisition [Line Items]  
Total cash consideration $ 324,686
Assets acquired:  
Inventory 2,980
Oil and natural gas properties 342,308
Other 149
Amount attributable to assets acquired 345,437
Fair value of liabilities assumed:  
Revenue payable 1,475
Asset retirement obligations 19,276
Amount attributable to liabilities assumed 20,751
Net assets acquired $ 324,686
v3.25.0.1
Acquisitions of Oil and Natural Gas Properties - Schedule of Business Acquisition, Pro Forma Information (Details) - New Mexico Asset Acquisition, 2023 - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2023
Dec. 31, 2022
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]    
Total revenues $ 405,642 $ 435,157
Net income $ 121,466 $ 129,741
Basic net income per common share (USD per Share) $ 6.16 $ 6.64
Diluted net income per common share (USD per Share) $ 6.07 $ 6.59
v3.25.0.1
Oil and Natural Gas Properties - Schedule of Properties (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Extractive Industries [Abstract]    
Proved $ 1,027,183 $ 895,783
Unproved 100,974 100,216
Work-in-progress 21,318 57,004
Total oil and natural gas properties, gross 1,149,475 1,053,003
Accumulated depletion, amortization and impairment (288,678) (206,102)
Total oil and natural gas properties, net $ 860,797 $ 846,901
v3.25.0.1
Oil and Natural Gas Properties - Narrative (Details)
 12 Months Ended
Dec. 31, 2024
USD ($)
well
Dec. 31, 2023
USD ($)
well
Oil and Gas, Full Cost Method, Capitalized Cost Excluded from Amortization [Line Items]    
Number of exploratory drilled | well 0 0
Depletion and amortization $ 71,300,000 $ 62,500,000
Exploration costs 2,595,000 4,165,000
Impairment of oil and natural gas properties 11,317,000 9,760,000
Other impairments 30,158,000 0
Champions and Red Lake fields    
Oil and Gas, Full Cost Method, Capitalized Cost Excluded from Amortization [Line Items]    
Non-cash impairment of oil and natural gas properties 11,300,000  
Champions Field    
Oil and Gas, Full Cost Method, Capitalized Cost Excluded from Amortization [Line Items]    
Non-cash impairment of oil and natural gas properties 9,500,000  
Impairment of oil and natural gas properties 9,500,000 $ 9,800,000
Redlake Field    
Oil and Gas, Full Cost Method, Capitalized Cost Excluded from Amortization [Line Items]    
Non-cash impairment of oil and natural gas properties 1,800,000  
Impairment of oil and natural gas properties 1,800,000  
Enhanced Oil Recovery EOR Project    
Oil and Gas, Full Cost Method, Capitalized Cost Excluded from Amortization [Line Items]    
Non-cash impairment of oil and natural gas properties 28,900,000  
Project fair value 0  
Cash impairment of oil and natural gas properties 1,300,000  
Other impairments $ 30,200,000  
Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | Champions and Red Lake fields    
Oil and Gas, Full Cost Method, Capitalized Cost Excluded from Amortization [Line Items]    
Oil and gas properties, measurement input 10.00%  
v3.25.0.1
Derivative Instruments - Schedule of Notional Amounts, Crude Oil and Natural Gas (Details)
bbl in Thousands, Mcf in Thousands
 12 Months Ended
Dec. 31, 2024
$ / bbl
$ / Mcf
Mcf
bbl
Crude Oil Swap Q1 2025  
Derivative [Line Items]  
Notional Volume | bbl 375
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 74.31
Crude Oil Swap Q2 2025  
Derivative [Line Items]  
Notional Volume | bbl 345
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 71.32
Crude Oil Swap Q3 2025  
Derivative [Line Items]  
Notional Volume | bbl 165
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 68.53
Crude Oil Swap Q4 2025  
Derivative [Line Items]  
Notional Volume | bbl 120
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 66.99
Natural Gas Swaps Q1 2025  
Derivative [Line Items]  
Notional Volume | Mcf 965
Weighted average price (in usd per bbl/mmbtu) 3.61
Natural Gas Swaps Q2 2025  
Derivative [Line Items]  
Notional Volume | Mcf 495
Weighted average price (in usd per bbl/mmbtu) 3.34
Natural Gas Swaps Q3 2025  
Derivative [Line Items]  
Notional Volume | Mcf 480
Weighted average price (in usd per bbl/mmbtu) 3.30
Natural Gas Swaps Q4 2025  
Derivative [Line Items]  
Notional Volume | Mcf 1,165
Weighted average price (in usd per bbl/mmbtu) 3.82
Natural Gas Swaps 2026  
Derivative [Line Items]  
Notional Volume | Mcf 2,555
Weighted average price (in usd per bbl/mmbtu) 3.92
Natural Gas Swaps 2027  
Derivative [Line Items]  
Notional Volume | Mcf 600
Weighted average price (in usd per bbl/mmbtu) 4.19
Crude Oil Collars Q1 2025  
Derivative [Line Items]  
Notional Volume | bbl 468
Crude Oil Collars Q1 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 60.48
Crude Oil Collars Q1 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 77.04
Crude Oil Collars Q2 2025  
Derivative [Line Items]  
Notional Volume | bbl 300
Crude Oil Collars Q2 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 66.50
Crude Oil Collars Q2 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 78.77
Crude Oil Collars Q3 2025  
Derivative [Line Items]  
Notional Volume | bbl 452
Crude Oil Collars Q3 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 64.23
Crude Oil Collars Q3 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 74.19
Crude Oil Collars Q4 2025  
Derivative [Line Items]  
Notional Volume | bbl 480
Crude Oil Collars Q4 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 63.10
Crude Oil Collars Q4 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 77.07
Crude Oil Collars 2026  
Derivative [Line Items]  
Notional Volume | bbl 1,107
Crude Oil Collars 2026 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 58.89
Crude Oil Collars 2026 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) | $ / bbl 76.99
Natural Gas Collars Q1 2025  
Derivative [Line Items]  
Notional Volume | Mcf 555
Natural Gas Collars Q1 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.46
Natural Gas Collars Q1 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 4.38
Natural Gas Collars Q2 2025  
Derivative [Line Items]  
Notional Volume | Mcf 1,080
Natural Gas Collars Q2 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.04
Natural Gas Collars Q2 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.65
Natural Gas Collars Q3 2025  
Derivative [Line Items]  
Notional Volume | Mcf 1,110
Natural Gas Collars Q3 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.12
Natural Gas Collars Q3 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.76
Natural Gas Collars Q4 2025  
Derivative [Line Items]  
Notional Volume | Mcf 400
Natural Gas Collars Q4 2025 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.30
Natural Gas Collars Q4 2025 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 4.00
Natural Gas Collars 2026  
Derivative [Line Items]  
Notional Volume | Mcf 2,675
Natural Gas Collars 2026 | Short  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.15
Natural Gas Collars 2026 | Long  
Derivative [Line Items]  
Weighted average price (in usd per bbl/mmbtu) 3.82
v3.25.0.1
Derivative Instruments - Narrative (Details) - Interest Rate Swap
$ in Millions
 1 Months Ended
Mar. 31, 2024
USD ($)
Derivative [Line Items]  
Gain on derivative $ 1
Notional amount $ 80
v3.25.0.1
Derivative Instruments - Schedule of Notional Amounts, Interest Rate Contracts (Details)
$ in Thousands
Dec. 31, 2024
USD ($)
January 2025 - April 2026  
Derivative [Line Items]  
Notional Amount $ 30,000
Fixed Rate 3.18%
January 2025 - April 2026  
Derivative [Line Items]  
Notional Amount $ 45,000
Fixed Rate 3.90%
April 2026 - April 2027  
Derivative [Line Items]  
Notional Amount $ 50,000
Fixed Rate 3.04%
v3.25.0.1
Derivative Instruments - Statement of Financial Position (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Derivative [Line Items]    
Derivative asset, net, gross fair value $ 3,435 $ 6,949
Derivative assets, net, net fair value 3,435 6,949
Current derivative assets    
Derivative [Line Items]    
Derivative asset, gross fair value 9,817 8,948
Derivative asset, amounts netted (6,553) (3,935)
Derivative assets, net fair value 3,264 5,013
Non-current derivative assets    
Derivative [Line Items]    
Derivative asset, gross fair value 6,661 6,687
Derivative asset, amounts netted (6,076) (4,391)
Derivative assets, net fair value 585 2,296
Current derivative liabilities    
Derivative [Line Items]    
Derivative liability, gross fair value (6,553) (4,295)
Derivative liability, amounts netted 6,553 3,935
Derivative liability, net fair value 0 (360)
Non-current derivative liabilities    
Derivative [Line Items]    
Derivative liability, gross fair value (6,490) (4,391)
Derivative liability, amounts netted 6,076 4,391
Derivative liability, net fair value $ (414) $ 0
v3.25.0.1
Derivative Instruments - Schedule of Derivative Activities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]    
Settlements on derivative contracts $ 1,849 $ (17,221)
Non-cash gain (loss) on derivatives (3,514) 23,414
Gain (loss) on derivatives, net $ (1,665) $ 6,193
v3.25.0.1
Fair Value Measurements - Schedule of Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt $ 269,494 $ 355,959
Senior Notes    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 154,494 170,959
Revolving Credit Facility | Line of Credit    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 115,000 185,000
Level 2 | Carrying Amount | Senior Notes | 10.50% Senior Unsecured Notes due 2028    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 154,494 170,959
Level 2 | Fair Value | Senior Notes | 10.50% Senior Unsecured Notes due 2028    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 172,864 185,346
Level 2 | Revolving Credit Facility | Carrying Amount | Line of Credit    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 115,000 185,000
Level 2 | Revolving Credit Facility | Fair Value | Line of Credit    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Long-term debt 115,000 185,000
Commodity derivative    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 15,301 14,766
Financial liabilities (13,043) (8,686)
Commodity derivative | Level 1    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 0 0
Financial liabilities 0 0
Commodity derivative | Level 2    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 15,301 14,766
Financial liabilities (13,043) (8,686)
Commodity derivative | Level 3    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 0 0
Financial liabilities 0 0
Interest rate    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 1,177 869
Interest rate | Level 1    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 0 0
Interest rate | Level 2    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets 1,177 869
Interest rate | Level 3    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Financial assets $ 0 $ 0
v3.25.0.1
Fair Value Measurements - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Asset retirement obligation, fair value disclosure $ 9,800 $ 19,400
Impairment of oil and natural gas properties 11,317 9,760
Enhanced Oil Recovery EOR Project    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Non-cash impairment of oil and natural gas properties 28,900  
Champions Field    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Impairment of oil and natural gas properties 9,500 9,800
Non-cash impairment of oil and natural gas properties 9,500  
Carrying value, oil and gas, property with unproved and proved reserves 21,100 33,700
Fair value, oil and gas, property with unproved and proved reserves 11,600 $ 23,900
Redlake Field    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Impairment of oil and natural gas properties 1,800  
Non-cash impairment of oil and natural gas properties 1,800  
Carrying value, oil and gas, property with unproved and proved reserves 1,300  
Fair value, oil and gas, property with unproved and proved reserves 3,100  
EOR Project    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Impairment of oil and natural gas properties 28,900  
Carrying value, oil and gas, property with unproved and proved reserves 41,700  
Fair value, oil and gas, property with unproved and proved reserves $ 12,800  
v3.25.0.1
Equity Method Investment - Narrative (Details) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Feb. 28, 2025
Dec. 31, 2024
Nov. 30, 2024
Oct. 31, 2024
May 31, 2024
Dec. 31, 2024
Dec. 31, 2023
Jan. 31, 2023
Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]                  
Contributions to equity method investment           $ 17,912 $ 3,566    
Equity method investment   $ 22,811       22,811 5,620   $ 0
Assets contributed to equity method investment           0 $ 2,272    
RPC Power, LLC                  
Schedule of Equity Method Investments [Line Items]                  
Contributions to equity method investment   21,500 $ 51,500 $ 42,500 $ 9,500        
Equity method investment, ownership percentage         50.00%     35.00%  
Equity method investment   23,800       23,800      
Assets contributed to equity method investment   2,300              
Equity method investments, remaining commitment amount   $ 27,700       $ 27,700      
RPC Power, LLC | Subsequent Event                  
Schedule of Equity Method Investments [Line Items]                  
Contributions to equity method investment $ 6,300                
Equity method investment $ 30,000                
v3.25.0.1
Equity Method Investment - Schedule of Equity Method Investment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Equity Method Investments [Roll Forward]    
Equity method investment, beginning balance $ 5,620 $ 0
Contributions 17,912 5,838
Loss from equity method investment (721) (218)
Equity method investment, ending balance $ 22,811 $ 5,620
v3.25.0.1
Transactions with Related Parties - Narrative (Details)
 1 Months Ended 12 Months Ended
May 31, 2024
USD ($)
Apr. 30, 2024
USD ($)
Jan. 31, 2024
USD ($)
unit
Jan. 31, 2023
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Related Party Transaction [Line Items]            
Lease operating expenses         $ 71,463,000 $ 58,817,000
Accrued liabilities         33,918,000 33,159,000
Other current liabilities         20,123,000 6,276,000
Accounts receivable, net         44,411,000 35,126,000
RPC Power, LLC            
Related Party Transaction [Line Items]            
Contractual obligation, monthly fee       $ 20,000    
Equity Method Investee | RPC Power, LLC | Tolling Agreement            
Related Party Transaction [Line Items]            
Long-term purchase commitment, period       10 years    
Contractual obligation, monthly fee       $ 20,000    
Equity Method Investee | RPC Power, LLC | Asset Optimization Agreement            
Related Party Transaction [Line Items]            
Long-term purchase commitment, period       10 years    
Equity Method Investee | RPC Power, LLC | Supply Agreement            
Related Party Transaction [Line Items]            
Long-term purchase commitment, period 10 years          
Equity Method Investee | RPC Power, LLC | Lease Operating Expenses            
Related Party Transaction [Line Items]            
Lease operating expenses         4,300,000 200,000
Accrued liabilities         1,200,000 0
Related Party | Private Aircraft Charter            
Related Party Transaction [Line Items]            
Amounts of transaction         100,000  
Related Party | Combo Resources, LLC | Contract Services Agreement            
Related Party Transaction [Line Items]            
Number of established units owned jointly | unit     6      
Monthly servicing fee     $ 100,000      
Other current liabilities         0 700,000
Accounts receivable, net         0 0
Related Party | Riley Exploration Group, Inc | Contract Services Agreement            
Related Party Transaction [Line Items]            
Monthly servicing fee   $ 60,000 $ 100,000      
Monthly servicing fee, waived $ 60,000          
Accounts receivable, net         0 0
Related Party | di Santo Law PLLC | Director | Legal Services            
Related Party Transaction [Line Items]            
Other current liabilities         300,000 600,000
Amounts of transaction         $ 1,400,000 $ 1,200,000
v3.25.0.1
Transactions with Related Parties - Schedule of Related Party Transactions (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Related Party Transaction [Line Items]    
Contract services $ 410,181 $ 375,047
Related Party    
Related Party Transaction [Line Items]    
Cost of contract services - related parties 363 579
Contract Services Agreement | Related Party    
Related Party Transaction [Line Items]    
Contract services 380 2,400
Combo Resources, LLC | Contract Services Agreement | Related Party    
Related Party Transaction [Line Items]    
Contract services 100 1,200
Riley Exploration Group, Inc | Contract Services Agreement | Related Party    
Related Party Transaction [Line Items]    
Contract services $ 280 $ 1,200
v3.25.0.1
Long-Term Debt - Schedule of Outstanding Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Line of Credit Facility [Line Items]    
Total debt $ 269,494 $ 355,959
Principal 280,000  
Less: Current portion of long-term debt 20,000 20,000
Total long-term debt 249,494 335,959
Line of Credit | Revolving Credit Facility    
Line of Credit Facility [Line Items]    
Total debt 115,000 185,000
Senior Notes    
Line of Credit Facility [Line Items]    
Total debt 154,494 170,959
Principal 165,000 185,000
Less: Unamortized discount 7,547 10,117
Less: Unamortized deferred financing costs 2,959 3,924
Less: Current portion of long-term debt $ 20,000 $ 20,000
v3.25.0.1
Long-Term Debt - Schedule of Debt Maturity (Details) - USD ($)
$ in Thousands
Dec. 13, 2024
Dec. 31, 2024
Dec. 31, 2023
Line of Credit Facility [Line Items]      
2025   $ 20,000  
2026   20,000  
2027   135,000  
2028   105,000  
2029   0  
Thereafter   0  
Long-term debt   280,000  
Senior Notes      
Line of Credit Facility [Line Items]      
2027   115,000  
Long-term debt   $ 165,000 $ 185,000
Extended maturity earlier period term 181 days    
v3.25.0.1
Long-Term Debt - Narrative (Details)
 12 Months Ended
Dec. 13, 2024
USD ($)
lender
Apr. 03, 2023
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Nov. 14, 2023
USD ($)
lender
Apr. 02, 2023
USD ($)
Feb. 22, 2023
USD ($)
Sep. 28, 2017
USD ($)
Line of Credit Facility [Line Items]                
Long-term debt, current maturities     $ 20,000,000 $ 20,000,000        
Senior Notes                
Line of Credit Facility [Line Items]                
Extended maturity earlier period term 181 days              
Long-term debt, current maturities     20,000,000 20,000,000        
Unamortized discount     7,547,000 10,117,000        
Unamortized deferred financing costs     2,959,000 $ 3,924,000        
Senior Notes | 10.50% Senior Unsecured Notes due 2028                
Line of Credit Facility [Line Items]                
Face amount   $ 200,000,000         $ 200,000,000  
Stated interest rate   10.50%            
Discount, percentage   6.00%            
Periodic payment, principal percentage   2.50%            
Periodic principal payment   $ 5,000,000            
Long-term debt, current maturities     20,000,000          
Hedging requirement minimum, term   18 months            
Unamortized discount     7,500,000          
Unamortized deferred financing costs     $ 3,000,000          
Interest rate, effective percentage     13.38%          
Senior Notes | 10.50% Senior Unsecured Notes due 2028 | Maximum                
Line of Credit Facility [Line Items]                
Leverage ratio   3.0            
Debt instrument, covenant, leverage ratio, restricted payments   2.0            
Senior Notes | 10.50% Senior Unsecured Notes due 2028 | Minimum                
Line of Credit Facility [Line Items]                
Asset coverage ratio   1.50            
Asset coverage ratio for restricted payments after pro forma effect   1.50            
Outstanding balance percentage   15.00%            
Senior Notes | 10.50% Senior Unsecured Notes due 2028 | On or prior to April 3, 2026                
Line of Credit Facility [Line Items]                
Redemption price, percentage   100.00%            
Premium, percentage   5.25%            
Senior Notes | 10.50% Senior Unsecured Notes due 2028 | After April 3, 2026, but on or prior to October 3, 2026                
Line of Credit Facility [Line Items]                
Redemption price, percentage   100.00%            
Senior Notes | 10.50% Senior Unsecured Notes due 2028 | After October 3, 2026                
Line of Credit Facility [Line Items]                
Redemption price, percentage   100.00%            
Revolving Credit Facility | Line of Credit                
Line of Credit Facility [Line Items]                
Borrowing base $ 400,000,000 $ 325,000,000     $ 375,000,000 $ 225,000,000   $ 25,000,000
Maximum facility amount   $ 1,000,000,000           $ 500,000,000
Number of new lenders | lender 1       2      
Number of exiting lenders | lender         1      
Cash balance threshold, borrowing base     10.00%          
Hedging requirement ratio for proved developed producing volumes, term     24 months          
Weighted average interest rate     7.79% 8.68%        
Revolving Credit Facility | Line of Credit | Maximum                
Line of Credit Facility [Line Items]                
Unused capacity, commitment fee percentage     0.50%          
Leverage ratio     3.0          
Leverage ratio for restricted payments     2.50          
Cash balance threshold, prepayment of lines of credit     $ 15,000,000          
Revolving Credit Facility | Line of Credit | Minimum                
Line of Credit Facility [Line Items]                
Unused capacity, commitment fee percentage     0.375%          
Current ratio     1.0          
Leverage ratio for restricted payments after pro forma effect     2.0          
Revolving Credit Facility | Line of Credit | Secured Overnight Financing Rate (SOFR) | Maximum                
Line of Credit Facility [Line Items]                
Basis spread on variable rate     3.75%          
Revolving Credit Facility | Line of Credit | Secured Overnight Financing Rate (SOFR) | Minimum                
Line of Credit Facility [Line Items]                
Basis spread on variable rate     2.75%          
Revolving Credit Facility | Line of Credit | Base Rate | Maximum                
Line of Credit Facility [Line Items]                
Basis spread on variable rate     2.75%          
Revolving Credit Facility | Line of Credit | Base Rate | Minimum                
Line of Credit Facility [Line Items]                
Basis spread on variable rate     1.75%          
v3.25.0.1
Long-Term Debt - Summary of Credit Facility Balances (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Line of Credit Facility [Line Items]    
Outstanding borrowings $ 249,494 $ 335,959
Revolving Credit Facility | Line of Credit    
Line of Credit Facility [Line Items]    
Outstanding borrowings 115,000 185,000
Available under the credit facility $ 285,000 $ 190,000
v3.25.0.1
Long-Term Debt - Schedule of Components of Interest Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Line of Credit Facility [Line Items]    
Interest expense $ 31,411 $ 30,464
Interest income (866) (233)
Capitalized interest (2,350) (3,187)
Amortization of deferred financing costs 2,730 2,278
Total interest expense, net 34,338 31,816
Senior Notes | 10.50% Senior Unsecured Notes due 2028    
Line of Credit Facility [Line Items]    
Amortization of discount on Senior Notes 2,569 1,883
Line of Credit | Revolving Credit Facility    
Line of Credit Facility [Line Items]    
Unused commitment fees on Credit Facility $ 844 $ 611
v3.25.0.1
Shareholders' Equity - Schedule of Distributions (Details) - USD ($)
$ / shares in Units, $ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2024
Sep. 30, 2024
Jun. 30, 2024
Mar. 31, 2024
Dec. 31, 2023
Sep. 30, 2023
Jun. 30, 2023
Mar. 31, 2023
Dec. 31, 2024
Dec. 31, 2023
Equity [Abstract]                    
Per Share Distribution (USD per Share) $ 0.38 $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 0.34 $ 0.34 $ 0.34    
Total Distribution $ 7,795 $ 8,104 $ 7,770 $ 7,329 $ 7,477 $ 6,737 $ 6,846 $ 6,851 $ 30,998 $ 27,911
v3.25.0.1
Shareholders' Equity - Narrative (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Apr. 08, 2024
Dec. 31, 2024
Dec. 31, 2023
Sep. 01, 2023
Apr. 21, 2023
Apr. 20, 2023
Dec. 31, 2022
Class of Stock [Line Items]              
Common stock, par value (USD per Share)   $ 0.001 $ 0.001        
Common stock outstanding post merger (in Shares)   21,482,555 20,405,093        
Share-based compensation expense   $ 8,138 $ 6,833        
Common Stock              
Class of Stock [Line Items]              
Common stock outstanding post merger (in Shares)   21,483,000 20,405,000       20,161,000
General and Administrative Expense              
Class of Stock [Line Items]              
Share-based compensation expense   $ 8,100 $ 7,000        
ATM Equity Program              
Class of Stock [Line Items]              
Sale of stock, maximum aggregate offering price       $ 50,000      
Sale of stock, currently available for issuance under current program   $ 49,700          
2024 Equity Offering | Common Stock              
Class of Stock [Line Items]              
Sale of stock, number of shares issued in transaction (in Shares) 1,015,000            
Sale of stock, price per share (USD per Share) $ 27.00            
Sale of stock, received on transaction $ 25,400            
Restricted Stock | Minimum              
Class of Stock [Line Items]              
Granted service period   3 months          
Restricted Stock | Maximum              
Class of Stock [Line Items]              
Granted service period   36 months          
A&R Long-Term Investment Plan              
Class of Stock [Line Items]              
Common stock, par value (USD per Share)         $ 0.001    
Increase in common stock reserved for future issuance (in Shares)         950,000    
Common stock reserved for future issuance (in Shares)         2,337,022 1,387,022  
Common stock outstanding post merger (in Shares)   920,951          
2021 Long-Term Incentive Plan | Restricted Stock              
Class of Stock [Line Items]              
Granted (in Shares)   183,605 346,869        
Additional share based compensation to be recognized   $ 7,800          
Weighted average life   22 months          
v3.25.0.1
Shareholders' Equity - Schedule of Restricted Stock Activity (Details) - Restricted Stock - 2021 Long-Term Incentive Plan - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Restricted Shares    
Unvested, beginning balance (in Shares) 521,997  
Granted (in Shares) 183,605 346,869
Vested (in Shares) (288,757)  
Forfeited (in Shares) (28,930)  
Unvested, ending balance (in Shares) 387,915 521,997
Weighted Average Grant Date Fair Value    
Unvested, beginning balance (USD per Share) $ 24.37  
Granted (USD per Share) 28.75 $ 28.68
Vested (USD per Share) 24.43  
Forfeited (USD per Share) 27.83  
Unvested, ending balance (USD per Share) $ 26.57 $ 24.37
Vested in period $ 7.1 $ 6.4
v3.25.0.1
Income Taxes - Schedule of Components of Income Tax Expense (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Current income tax expense:    
Federal $ 22,814 $ 5,852
State 2,058 1,020
Total current income tax expense 24,872 6,872
Deferred income tax expense:    
Federal 1,666 24,305
State 1,536 3,284
Total deferred income tax expense 3,202 27,589
Total income tax expense $ 28,074 $ 34,461
v3.25.0.1
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2024
Dec. 31, 2023
Income Tax Disclosure [Abstract]    
Intangibles $ 146 $ 163
Share-based compensation 1,129 772
Interest expense limitation 19 3,861
Accruals and other 1,893 1,123
Net operating loss 2,639 2,700
Total deferred tax assets 5,826 8,619
Oil and natural gas assets (80,972) (79,761)
Other fixed assets (628) (661)
Unrealized gain on derivatives (773) (1,542)
Total deferred tax liabilities (82,373) (81,964)
Net deferred tax liabilities $ (76,547) $ (73,345)
v3.25.0.1
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details)
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Effective Income Tax Rate Reconciliation, Percent [Abstract]    
Tax at statutory rate 21.00% 21.00%
Nondeductible compensation 0.70% 0.70%
Share-based compensation (0.10%) (0.50%)
State income taxes, net of federal benefit 2.40% 2.40%
Effective income tax rate 24.00% 23.60%
v3.25.0.1
Income Taxes - Narrative (Details)
$ in Millions
Dec. 31, 2024
USD ($)
Income Tax Disclosure [Abstract]  
Operating loss carryforwards $ 12.6
Operating loss carryforwards, subject to expiration 3.8
Operating loss carryforwards, not subject to expiration $ 8.8
v3.25.0.1
Net Income Per Share - Schedule of Computation of Basic and Diluted Net Income Per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share [Abstract]    
Net income $ 88,897 $ 111,591
Basic weighted-average common shares outstanding (in Shares) 20,712 19,705
Restricted shares (in Shares) 163 295
Diluted weighted-average common shares outstanding (in Shares) 20,875 20,000
Basic net income per share (USD per Share) $ 4.29 $ 5.66
Diluted net income per share (USD per Share) $ 4.26 $ 5.58
v3.25.0.1
Net Income Per Share - Schedule of Anti-Dilutive Shares (Details) - shares
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Restricted shares    
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]    
Anti-dilutive securities (in Shares) 226,742 294,817
v3.25.0.1
Segments - Narrative (Details)
 12 Months Ended
Dec. 31, 2024
segment
Segment Reporting [Abstract]  
Number of operating segment 1
Number of reportable segment 1
v3.25.0.1
Segments - Schedule of Segment Reporting Information, by Segment (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Revenue, Major Customer [Line Items]      
Total Revenues $ 410,181 $ 375,047  
Less:      
Lease operating expenses 71,463 58,817  
Production and ad valorem taxes 29,428 25,559  
Exploration costs 2,595 4,165  
Depletion, depreciation, amortization and accretion 74,900 65,055  
Impairment of oil and natural gas properties 11,317 9,760  
Other impairments 30,158 0  
Administrative costs 26,551 26,569  
Share-based compensation expense 8,138 6,833  
(Gain) loss on derivatives, net 1,665 (6,193)  
Loss from equity method investment (721) (218)  
Income tax expense (28,074) (34,461)  
Net income 88,897 111,591  
Total assets 993,501 945,711  
Equity method investment 22,811 5,620 $ 0
Reportable Segment      
Revenue, Major Customer [Line Items]      
Total Revenues 410,181 375,047  
Less:      
Lease operating expenses 71,463 58,817  
Production and ad valorem taxes 29,428 25,559  
Exploration costs 2,595 4,165  
Depletion, depreciation, amortization and accretion 74,900 65,055  
Impairment of oil and natural gas properties 11,317 9,760  
Other impairments 30,158 0  
Administrative costs 26,551 26,569  
Share-based compensation expense 8,138 6,833  
Other segment items 1,936 6,396  
Interest expense, net of capitalized interest 35,204 32,049  
Interest income (866) (233)  
(Gain) loss on derivatives, net (1,665) 6,193  
Loss from equity method investment 721 218  
Income tax expense 28,074 34,461  
Net income 88,897 111,591  
Total assets 993,501 945,711  
Capital expenditures 108,320 135,804  
Equity method investment $ 22,811 $ 5,620  
v3.25.0.1
Commitment and Contingencies (Details)
 1 Months Ended
Dec. 31, 2024
USD ($)
in
MMcf
May 31, 2024
Jan. 31, 2023
USD ($)
Aug. 31, 2022
Dec. 31, 2023
USD ($)
Other Commitments [Line Items]          
Environmental liabilities $ 0       $ 0
RPC Power, LLC          
Other Commitments [Line Items]          
Contractual obligation, monthly fee     $ 20,000    
Equity method investment, ownership percentage   50.00% 35.00%    
Equity method investments, remaining commitment amount $ 27,700,000        
Stakeholder          
Other Commitments [Line Items]          
Contractual obligation, delivery period       7 years  
Tolling Agreement | RPC Power, LLC          
Other Commitments [Line Items]          
Long-term purchase commitment, period     10 years    
Supply Agreement | RPC Power, LLC          
Other Commitments [Line Items]          
Long-term purchase commitment, period   10 years      
Gas Purchase Agreement          
Other Commitments [Line Items]          
Long-term purchase commitment, period 15 years        
Long-term purchase commitment, reimbursable construction costs $ 18,700,000        
Long-term purchase commitment, termination notice period 180 days        
Long-term purchase commitment, size of pipeline | in 20        
Long-term purchase commitment, daily volume of pipeline | MMcf 150        
v3.25.0.1
Subsequent Events (Details) - USD ($)
$ / shares in Units, $ in Thousands
 1 Months Ended 3 Months Ended 12 Months Ended
Feb. 28, 2025
Jan. 09, 2025
Dec. 31, 2024
Nov. 30, 2024
Oct. 31, 2024
May 31, 2024
Dec. 31, 2024
Sep. 30, 2024
Jun. 30, 2024
Mar. 31, 2024
Dec. 31, 2023
Sep. 30, 2023
Jun. 30, 2023
Mar. 31, 2023
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Subsequent Event [Line Items]                                  
Cash dividend declared (USD per Share)             $ 0.38 $ 0.36 $ 0.36 $ 0.36 $ 0.36 $ 0.34 $ 0.34 $ 0.34      
Contributions to equity method investment                             $ 17,912 $ 3,566  
Equity method investment     $ 22,811       $ 22,811       $ 5,620       22,811 $ 5,620 $ 0
RPC Power, LLC                                  
Subsequent Event [Line Items]                                  
Contributions to equity method investment     21,500 $ 51,500 $ 42,500 $ 9,500                      
Equity method investment     $ 23,800       $ 23,800               $ 23,800    
Subsequent Event                                  
Subsequent Event [Line Items]                                  
Cash dividend declared (USD per Share)   $ 0.38                              
Dividends payable (USD per share)   $ 0.38                              
Subsequent Event | RPC Power, LLC                                  
Subsequent Event [Line Items]                                  
Contributions to equity method investment $ 6,300                                
Equity method investment $ 30,000                                
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) - Schedule of Costs Incurred for Property Acquisition, Exploration and Development (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Acquisition of properties    
Proved $ 4,592 $ 228,147
Unproved 16,641 102,742
Exploration costs 0 0
Development costs 106,773 152,309
Total costs incurred $ 128,006 $ 483,198
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) - Schedule of Results of Operations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Extractive Industries [Abstract]    
Oil, natural gas and NGL sales $ 409,801 $ 372,647
Lease operating expenses 71,463 58,817
Production and ad valorem taxes 29,428 25,559
Exploration costs 2,595 4,165
Depletion, accretion and amortization 74,025 64,471
Impairment of oil and natural gas properties 11,317 9,760
Other impairments 30,158 0
Results of operations 190,815 209,875
Income tax expense (43,105) (44,493)
Results of operations, net of income tax expense $ 147,710 $ 165,382
Combined federal and state statutory income tax rate, percent 22.59% 21.20%
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) - Schedule of Oil, Natural Gas and NGL Quantities (Details)
bbl in Thousands, Mcf in Thousands, Boe in Thousands, MMBoe in Millions
 12 Months Ended
Dec. 31, 2024
Boe
bbl
Mcf
Dec. 31, 2024
Boe
Mcf
bbl
Dec. 31, 2024
Boe
Mcf
bbl
Dec. 31, 2024
MMBoe
Boe
Mcf
bbl
Dec. 31, 2023
Boe
bbl
Mcf
Dec. 31, 2023
Boe
Mcf
bbl
Dec. 31, 2023
Boe
bbl
Mcf
Dec. 31, 2023
Boe
MMBoe
bbl
Mcf
Dec. 31, 2022
Boe
bbl
Mcf
Oil and Gas, Proved Reserve, Quantity, Energy [Roll Forward]                  
Beginning balance | Boe     107,715       77,673    
Acquisitions     4,269 4.3     26,064 26.1  
Extensions and discoveries     15,600 15.6     22,870 22.9  
Revisions     4,270 4.3     (12,106) (12.1)  
Production | Boe     (8,252)       (6,786)    
Ending balance | Boe     123,602       107,715    
Proved Developed Reserves, Included Above | Boe 76,646 76,646 76,646 76,646 60,178 60,178 60,178 60,178 49,122
Proved Undeveloped Reserves, Included Above | Boe 46,956 46,956 46,956 46,956 47,537 47,537 47,537 47,537 28,551
Oil                  
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]                  
Beginning balance 66,308       48,882        
Acquisitions 1,989       12,810        
Extensions and discoveries 8,894       14,822        
Revisions (5,137)       (5,403)        
Production (5,519)       (4,803)        
Ending balance 66,535       66,308        
Proved Developed Reserves, Included Above 40,111 40,111 40,111 40,111 36,731 36,731 36,731 36,731 29,632
Proved Undeveloped Reserves, Included Above 26,424 26,424 26,424 26,424 29,577 29,577 29,577 29,577 19,250
Natural Gas                  
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]                  
Beginning balance | Mcf   123,948       86,018      
Acquisitions | Mcf   6,624       39,261      
Extensions and discoveries | Mcf   17,218       22,945      
Revisions | Mcf   21,933       (18,411)      
Production | Mcf   (7,484)       (5,865)      
Ending balance | Mcf   162,239       123,948      
Proved Developed Reserves, Included Above | Mcf 103,337 103,337 103,337 103,337 71,671 71,671 71,671 71,671 59,314
Proved Undeveloped Reserves, Included Above | Mcf 58,902 58,902 58,902 58,902 52,277 52,277 52,277 52,277 26,704
NGLs                  
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]                  
Beginning balance 20,749       14,454        
Acquisitions 1,176       6,711        
Extensions and discoveries 3,837       4,224        
Revisions 5,751       (3,634)        
Production (1,486)       (1,006)        
Ending balance 30,027       20,749        
Proved Developed Reserves, Included Above 19,312 19,312 19,312 19,312 11,502 11,502 11,502 11,502 9,604
Proved Undeveloped Reserves, Included Above 10,715 10,715 10,715 10,715 9,247 9,247 9,247 9,247 4,850
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) - Narrative (Details)
Boe in Thousands, MMBoe in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2024
Boe
Dec. 31, 2024
$ / bbl
Dec. 31, 2024
$ / Mcf
Dec. 31, 2024
$ / MMBTU
Dec. 31, 2024
MMBoe
Dec. 31, 2023
Dec. 31, 2023
Boe
Dec. 31, 2023
$ / bbl
Dec. 31, 2023
$ / Mcf
Dec. 31, 2023
$ / MMBTU
Dec. 31, 2023
MMBoe
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                        
Additions           15.9           30.0
Acquisitions   4,269       4.3   26,064       26.1
Extensions and discoveries   15,600       15.6   22,870       22.9
Result of drilling successful wells that were previously classified as unproved locations           7.7           8.3
Result of drilling successful wells offsetting locations that were previously unproven locations           7.9           14.6
Revisions   (4,270)       (4.3)   12,106       12.1
Negative revision of previous estimate           15.3           19.3
Positive revision of previous estimate           11.0           7.2
Improved well performance           9.2            
Positive revisions           6.1            
PUD reserves, forecast           4.2           6.7
PUD reserves, forecast period 5 years           5 years          
Type curve           2.6            
Interest changes           2.0            
Lower commodity prices           1.5           2.9
Negative revision of reserve category           0.7            
Lower forecasted natural gas                       6.3
Increase in operating expenses                       2.4
Removal of uneconomic locations                       0.7
Other minor revisions                       0.3
West Texas Intermediate (WTI)                        
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                        
Oil and natural gas liquids, average WTI intermediate spot price (USD per bbl) | $ / bbl     76.32           78.22      
Henry Hub                        
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                        
Gas, average henry hub spot price (USD per mmbtu) | $ / MMBTU         2.13           2.64  
Oil                        
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                        
Percentage of reserves 53.80% 53.80% 53.80% 53.80% 53.80% 53.80% 61.50% 61.50% 61.50% 61.50% 61.50% 61.50%
Price (USD per bbl/mcf) | $ / bbl     74.27           76.02      
Natural Gas                        
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                        
Percentage of reserves 21.90% 21.90% 21.90% 21.90% 21.90% 21.90% 19.20% 19.20% 19.20% 19.20% 19.20% 19.20%
Price (USD per bbl/mcf) | $ / Mcf       (0.43)           0.46    
NGLs                        
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]                        
Percentage of reserves 24.30% 24.30% 24.30% 24.30% 24.30% 24.30% 19.30% 19.30% 19.30% 19.30% 19.30% 19.30%
Price (USD per bbl/mcf) | $ / bbl     (3.56)           7.11      
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
USD ($)
$ / bbl
$ / Mcf
Dec. 31, 2023
USD ($)
$ / bbl
$ / Mcf
Dec. 31, 2022
USD ($)
Extractive Industries [Abstract]      
Future crude oil, natural gas and NGLs sales $ 4,764,599 $ 5,244,927  
Future production costs (1,638,032) (1,896,397)  
Future development costs (325,414) (362,218)  
Future income tax expense (524,581) (538,926)  
Future net cash flows 2,276,572 2,447,386  
10% annual discount (1,034,771) (1,186,921)  
Standardized measure of discounted future net cash flows $ 1,241,801 $ 1,260,465 $ 1,108,376
Oil      
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]      
Price (USD per bbl/mcf) | $ / bbl 74.27 76.02  
Natural Gas      
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]      
Price (USD per bbl/mcf) | $ / Mcf (0.43) 0.46  
NGLs      
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]      
Price (USD per bbl/mcf) | $ / bbl (3.56) 7.11  
v3.25.0.1
Supplemental Oil and Gas Information (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves Rollforward (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2023
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Roll Forward]    
Balance, beginning of period $ 1,260,465 $ 1,108,376
Sales of crude oil, natural gas and NGLs, net (308,907) (288,270)
Net change in prices and production costs (238,938) (618,441)
Net changes in future development costs 9,976 21,423
Extensions and discoveries 253,381 385,482
Acquisition of reserves 47,020 613,295
Revisions of previous quantity estimates 71,800 (188,364)
Previously estimated development costs incurred 38,858 31,124
Net change in income taxes (2,035) (5,976)
Accretion of discount 158,406 140,115
Other (48,225) 61,701
Balance, end of period $ 1,241,801 $ 1,260,465