During the year ended December 31, 2024, the Company identified certain errors in its previously issued financial statements that have now been corrected through cumulative out-of-period adjustments in the financial statements as of and for the year ended December 31, 2024. The errors relate, primarily, to improper classifications of income taxes withheld by the state of New Mexico, from January 2021 through June 2024, that were recorded as production tax expense. As a result, the Company recorded an out-of-period adjustment of approximately $32.1 million in the year ended December 31, 2024 to record an income tax receivable, offset by a reduction in production taxes. Further, in the year ended December 31, 2024, the Company recorded an out-of-period adjustment of approximately $6.7 million to income tax expense, offset by an increase in deferred tax liabilities. These errors understated net income for the fiscal years ended December 31, 2023, 2022, and 2021, by approximately $9.3 million, $11.2 million, and $0.5 million, respectively. Management considered qualitative and quantitative factors and concluded the out-of-period adjustments are immaterial to 2024 and each of the applicable periods.

The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The most significant estimates relate to proved crude oil and natural gas reserves, which includes limited control over future development plans as a non-operator, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, fair value of contingent consideration, acquisition date fair values of assets acquired and liabilities assumed, impairment of crude oil and natural gas properties, asset retirement obligations and deferred income taxes.

Management’s estimates and assumptions were based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, actual results may differ from the estimates and assumptions used, and conditions may change, which could materially affect amounts reported in the financial statements.

The Company considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts. The Company’s cash positions represent assets held in checking and money market accounts. Cash and cash equivalents are generally available on a daily or weekly basis and are highly liquid in nature.

Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net in the balance sheets.

The Company did not have any accounts receivable balances recorded in Other Noncurrent Assets, Net as of December 31, 2024. Conversely, as of December 31, 2023, the Company included accounts receivable of $2.4 million in Other Noncurrent Assets, Net due to their long-term nature.

The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.

Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterment are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets.

The Company follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2024, 2023 and 2022, respectively:


	December 31,
(In thousands)	2024		2023		2022
Capitalized Certain Payroll and Other Internal Costs	$	788	$	1,036	$	1,045
Capitalized Interest Costs	2,383		2,999		3,365
Total	$	3,172	$	4,036	$	4,410

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2024, 2023 and 2022, there were no property sales that resulted in a significant alteration.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the net book value of the oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The oil and natural gas properties, net balance was $5.1 billion as of December 31, 2024. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing twelve-month unweighted average of the first-day-of-

the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded in the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, a non-cash ceiling impairment is required.

The Company did not have any ceiling test impairment for the years ended December 31, 2024, 2023 and 2022. Impairment charges affect the Company’s reported net income but do not reduce the Company’s cash flow. Average commodity prices have declined in recent months. If this downward trend continues, and/or if our proved reserves decrease significantly in future months, the present value of the Company’s future net revenues could decline significantly, which could trigger the need for the Company to record a non-cash ceiling test impairment of its oil and gas property costs in future periods.

The Company computes the provision for depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated for reserves. The following table presents depletion and depletion per BOE sold of the Company’s proved oil and natural gas properties for the periods presented:

The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves.

Capitalized costs associated with impaired unproved properties, which includes leases that have expired or have been deemed uneconomic, and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are included in the depletion calculation. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are evaluated for reserves. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the years ended December 31, 2024, 2023 and 2022, unproved properties of $3.8 million, $5.2 million, and $8.7 million, respectively, were impaired.

The Company records a liability equal to the fair value of the estimated cost to retire an asset upon initial recognition. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is added to the full cost pool and is subject to depletion. Upon settlement of the liability or the sale of the well, the liability is relieved. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. Any variances between the liabilities recorded and the actual cost incurred to retire the assets is recorded as an adjustment to accumulated amortization of the full cost pool.

The Company accounts for its acquisitions that qualify as a business using the acquisition method. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration, and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s derivative instruments assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil price curves, discount rates, volatility factors and credit risk adjustments.

The carrying amount of long-term debt associated with borrowings outstanding under the Company’s Revolving Credit Facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s Senior Notes and Convertible Notes (see Note 4 below) may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the Senior Notes and Convertible Notes bear interest at fixed rates. See Note 11 for additional discussion.

Debt issuance costs related to our Senior Notes and Convertible Notes are included as a deduction from the carrying amount of long-term debt in the balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the Revolving Credit Facility are included in other noncurrent assets and are amortized to interest expense on a straight-line basis over the term of the agreement.

The Company’s revenues are primarily derived from its interests in the sales of oil and natural gas production. The Company recognizes revenue from its interests in the sales of crude oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied when the customer obtains control of the product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which the third-party operators of the wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in trade receivables, net in the balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption, which applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company’s oil is typically sold at delivery points under contract terms that are common in our industry. The Company’s natural gas produced is delivered by the well operators to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in our industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.

The Company’s disaggregated revenue has two primary sources: oil sales and natural gas and NGL sales. Substantially all of the Company’s oil and natural gas sales come from four operating areas in the United States: the Williston Basin, the Permian Basin, the Appalachian Basin, and the Uinta Basin. The following tables present the disaggregation of the Company’s oil revenues and natural gas and NGL revenues for the years ended December 31, 2024, 2023 and 2022.

The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due, indirectly via the third-party operators of the wells, from purchasers of its crude oil and natural gas production. While certain of these customers, as well as third-party operators of the wells, are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations have been immaterial.

As a non-operator, 100% of the Company’s wells are operated by third-party operating partners. As a result, the Company is highly dependent on the success of these third-party operators. If they are not successful in the exploration, development and production activities relating to the Company’s leasehold interests, or are unable or unwilling to perform, the Company’s financial condition and results of operation could be adversely affected. These risks are heightened in a low commodity price environment, which may present significant challenges to these third-party operators. The Company’s third-party operators will make decisions in connection with their operations that may not be in the Company’s best interests, and the Company may have little or no ability to exercise influence over the operational decisions of its third-party operators. For the years ended December 31, 2024, 2023 and 2022, the Company’s top four operators made up 38%, 38% and 39%, respectively, of total oil and natural gas sales.

The Company faces concentration risk due to the fact that substantially all of its oil and natural gas revenue is sourced from a limited number of geographic areas of operations. As a result, the Company is disproportionately exposed to risks that affect one or more of those areas in the Williston Basin, the Permian Basin, the Appalachian Basin, and the Uinta Basin.

The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.

The Company has one reportable segment, which is engaged in the acquisition, exploration, development and production of crude oil and natural gas in the United States. All of the Company’s oil and natural gas sales come from customers in the United States. The segment’s revenues are primarily derived from our interests in the sales of crude oil and natural gas production. The Company’s chief operating decision maker (“CODM”) is our chief executive officer, who manages the Company’s business activities as a single operating and reporting segment.

The accounting policies of the one reportable segment are the same as those described in the summary of significant accounting policies. The CODM uses net income, as reported in our statement of operations, to measure segment profit or loss, assess performance, and make strategic capital resources allocations. The measure of segment assets is reported on our balance sheet as total assets. The significant expense categories regularly provided to the CODM are the expenses as noted on the face of the statements of operations.

The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants, the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. In determining the fair value of performance-based share awards subject to market conditions, the Company utilizes a Monte Carlo simulation prepared by an independent third-party. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of share repurchases under the share repurchase program or from the withholding of shares of stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on their stock-based awards at the employees’ election.

The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid. The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The Company’s only taxing jurisdictions are the United States and the states in which we operate.

Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage its businesses.

Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some components or all of the benefits of deferred tax assets will not be realized. As of December 31, 2024 and 2023, the Company recorded valuation allowances of $1.8 million and $1.9 million, respectively, against certain of the Company’s deferred tax assets.

The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil and natural gas commodities. The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of the applicable commodity without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company may also use exchange traded futures contracts and option contracts to hedge the delivery price of commodities at a future date.

The Company recognizes derivative instruments as assets or liabilities in the balance sheets, measured at fair value and marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net in the statements of operations. See Note 12 for a description of the open derivative contracts into which the Company has entered.

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company offers matching contributions to its employees’ retirement funds. Employees are 100% vested in the employer contributions upon receipt.

Basic earnings per share (“EPS”) are computed by dividing net income attributable to common stockholders (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income attributable to common stockholders by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares issuable upon exercise of stock warrants and vesting of restricted stock awards, and shares issuable upon conversion of the Convertible Notes (see Note 4). The number of potential common shares outstanding are calculated using the treasury stock or if-converted method.

In those reporting periods in which the Company has reported net income available to common stockholders, anti-dilutive shares generally are comprised of the restricted stock that has average unrecognized stock compensation expense greater than the average stock price. In those reporting periods in which the Company has a net loss, anti-dilutive shares are comprised of the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would be anti-dilutive had the company had net income.

Restricted stock awards are excluded from the calculation of basic weighted average common shares outstanding until they vest. For restricted stock awards that vest based on achievement of performance and/or market conditions, the number of contingently issuable common shares included in diluted weighted-average common shares outstanding is based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the performance and/or market conditions were met at the end of the reporting period, assuming the result would be dilutive.


	December 31,
(In thousands)	2024		2023		2022
Supplemental Cash Items:
Cash Paid During the Period for Interest, Net of Amount Capitalized	$	152,061	$	128,943	$	74,933
Cash Paid During the Period for Income Taxes	332		3,826		3,672




Non-cash Investing Activities:
Capital Expenditures on Oil and Natural Gas Properties Included in Accounts Payable and Accrued Liabilities	330,977		236,314		163,059
Capitalized Asset Retirement Obligations	8,028		5,413		3,917
Contingent Consideration	—		—		11,966
Compensation Capitalized on Oil and Natural Gas Properties	786		280		218
Issuance of Common Stock Warrants - Acquisitions of Oil and Natural Gas Properties	—		—		17,870
Accrued Liabilities From Acquisitions of Oil and Natural Gas Properties	—		5,168		—
Issuance of Common Stock - Acquisitions of Oil and Natural Gas Properties	3,737		—		—



Non-cash Financing Activities:


Common Stock Dividends Declared, but not paid	42,156		40,496		19,546




Issuance of Common Stock for Preferred Stock Exchange	—		—		36,627
Issuance of Common Stock Warrants - Acquisitions of Oil and Natural Gas Properties	—		—		17,870
Issuance of Common Stock in Exchange for Warrants	23,338		13,328		76,904



Repurchases of Common Stock - Excise Tax	944		—		—

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued accounting standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.

In November 2023, the FASB issued ASU 2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires the Company to expand the breadth and frequency of segment disclosures to include additional information about significant segment expenses, the chief operating decision maker (CODM) and other items, and also require the annual disclosures on an interim basis. This guidance is effective for annual periods beginning after December 15, 2023, with early adoption permitted. The Company adopted ASU 2023-07 as of December 31, 2024 with no significant impact on its financial statements and related disclosures.

In November 2024, the FASB issued ASU 2024-04 Debt - Debt With Conversion and Other Options (Subtopic 470-20): Induced Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other Options. This standard

will affect entities that settle convertible debt instruments for which the conversion privileges are changed to induce conversion. ASU 2024-04 is effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.

In November 2024, the FASB issued ASU 2024-03 Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard requires disclosure, in the notes to financial statements, of specified information about certain costs and expenses. The objective of the standard is to provide disaggregated information about a public business entity’s expenses to help investors better understand the components of an entity’s expenses, which should enable investors to better assess an entity’s prospects for future cash flows. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.

In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires the Company to disclose disaggregated jurisdictional and categorical information for the tax rate reconciliation, income taxes paid and other income tax related amounts. This guidance is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The adoption is expected to enhance the Company's Notes to the Financial Statements. The Company is currently evaluating the impact the new standard will have on its financial statements and related disclosures.

In October 2023, the FASB issued ASU 2023-06 Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative, which amends GAAP to include 14 disclosure requirements that are currently required under SEC Regulation S-X or Regulation S-K. Each amendment will be effective on the date on which the SEC removes the related disclosure requirement from SEC Regulation S-X or Regulation S-K. The Company is currently evaluating the impact the new standard will have on its financial statements and related disclosure.