Vitesse Energy, Inc.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:

INDEX TO FINANCIAL STATEMENTS

To the shareholders and the Board of Directors of Vitesse Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Vitesse Energy, Inc. and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of operations, equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/Deloitte & Touche LLP

Denver, Colorado

March 2, 2026

We have served as the Company’s auditor since 2021.

Consolidated Statements of Equity

Notes to the Consolidated Financial Statements

Note 1—Nature of Business

Vitesse Energy, Inc. (“Vitesse” or the “Company”) was incorporated under the General Corporation Law of the State of Delaware on August 5, 2022 as a wholly owned subsidiary of an affiliate of Jefferies Financial Group Inc. (“JFG”) for the purpose of effecting the Spin-Off of Vitesse Energy, LLC (the “Predecessor”) by JFG. On January 13, 2023, JFG completed the legal and structural separation of the Predecessor from JFG. JFG distributed the Vitesse outstanding common stock held by each to their respective shareholders, and Vitesse became an independent, publicly traded company. The Company’s common stock began trading on the New York Stock Exchange on January 17, 2023 under the symbol “VTS.”

The business purpose of the Company is to acquire, own, explore, develop, manage, produce, exploit, and dispose of oil and gas properties. The Company is focused on returning capital to stockholders through owning and acquiring operated and non-operated working interest and royalty interest ownership primarily in the core of the Bakken and Three Forks formations in the Williston Basin of North Dakota and Montana. The Company also owns non-operated interests in oil and gas properties in the Central Rockies, including the Denver-Julesburg Basin and the Powder River Basin.

Note 2—Significant Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries, including the Predecessor, Vitesse Oil, Vitesse Management Company LLC (“Vitesse Management”), Vitesse Oil, Inc., Vitesse Holding Corp., Lucero Energy ULC, and PetroShale (US), Inc. Intercompany balances and transactions have been eliminated in consolidation. Lucero Energy ULC and PetroShale (US), Inc. accounts are only included subsequent to the Lucero Acquisition that closed on March 7, 2025.

Segment and Geographic Information

The chief operating decision maker (CODM) of the Company is the Chief Executive Officer (CEO). The Company operates in a single reportable segment, which is a single operating segment. All of the Company’s operations are managed on a consolidated basis, conducted in the continental United States, and relate to the acquisition, development and production of oil and natural gas assets. The significant segment expenses provided to the CODM for purposes of allocating resources and assessing financial performance include lease operating expense, production taxes, general and administrative expense, depletion, depreciation, amortization, and accretion, equity-based compensation, income taxes and interest expense. These significant expenses are the same as the line items presented in the Consolidated Statements of Operations. Consolidated net income is the measure used by the CODM to assess performance and determine resource allocation.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States (“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 revenue and expenses during the reporting period. Actual results could differ from those estimates.

Depletion, depreciation, and amortization (“DD&A”) and the evaluation of proved oil and gas properties for impairment are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, which includes lack of control over future development plans as a non-operator. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. In addition, significant estimates include, but are not limited to, estimates relating to certain oil and natural gas revenues and expenses, fair value of assets acquired and liabilities assumed in business combinations, valuation of share-based compensation, and valuation of commodity derivative instruments. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant adverse impact to the Company’s business, financial condition, results of operations and cash flows.

Cash and Cash Equivalents

The Company considers all investments with an original maturity of three months or less when purchased to be cash equivalents. As of the consolidated balance sheet date and periodically throughout the year, balances of cash exceeded the federally insured limit. As of December 31, 2025 and 2024 the Company heldno cash equivalents.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas activities. Under this method of accounting, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized and depleted, net of estimated salvage values, using the units-of-production method on the basis of a reasonable aggregation of properties within a common geological structural feature or stratigraphic condition, such as a reservoir or field. The Company’s proved oil and gas reserve information was computed by applying the average first-day-of-the-month oil and gas price during the 12-month period ended on the balance sheet date. During the years ended December 31, 2025, 2024 and 2023, the Company recorded depletion expense of $128.4 million, $99.6 million and $81.1 million, respectively. The Company’s depletion rate per BOE for the years ended December 31, 2025, 2024 and 2023 was $20.16, $20.92 and $18.68, respectively.

Exploration, geological and geophysical costs, delay rentals, and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties.

Costs associated with unevaluated exploratory wells are excluded from the depletable base until the determination of proved reserves, at which time those costs are reclassified to proved oil and gas properties and subject to depletion. If it is determined that the exploratory well costs were not successful in establishing proved reserves, such costs are expensed at the time of such determination.

The Company reviews its oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows of its oil and gas properties and compares such cash flows to the carrying amount of the proved oil and gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust its proved oil and gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future estimated commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures and operating expenses, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks. There wereno proved oil and gas property impairments during the years ended December 31, 2025, 2024 and 2023.

Asset Retirement Obligations (AROs)

AROs relate to estimated plugging and abandonment costs of oil and gas properties, including facilities, and the reclamation of the Company’s well locations. The Company records the fair value of an ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes an estimated cost by increasing the carrying amount of proved oil and gas properties. Over time, the liability is accreted each period toward an estimated future cost, and the capitalized cost is depleted. The Company uses the income valuation technique to estimate the fair value of AROs using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates, and the time value of money. For business combinations, the valuation utilizes a discount rate commensurate with what a market participant would use for AROs recorded. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives or if federal or state regulators enact new requirements regarding the abandonment of wells. Adjustments to the liability are made as these estimates change. Upon settlement of the liability, the Company reports a gain or loss to the extent the actual costs differ from the recorded liability.

Equity-Based Compensation

The Company recognizes equity-based compensation expense associated with its long-term incentive plan (“LTIP”) awards using the straight-line method over the requisite service period, which is generally the vesting period of the award except when provisions are present that accelerate vesting, based on their grant date fair values. The Company has elected to account for forfeitures of equity awards as they occur.

Revenue Recognition

The majority of the Company’s revenue is derived from the sale of produced oil and natural gas from wells in which the Company holds non-operated revenue or royalty interests. For non-operated properties, the Company’s proportionate share of production is marketed at the discretion of the operators under contracts negotiated between the operators and customers. Non-operated revenues are recognized during the month in which production occurs, control of the product transfers to the customer, and it is probable that the Company will collect the consideration to which it is entitled. Due to the nature of non-operated properties, statements and payments from operators may not be received forone tosix months after the date production is delivered to customers. As such, at the end of each month, the Company estimates the amount of production delivered and sold as well as the pricing based on operator-provided production reports, market indices, and estimated quality and transportation differentials. This estimated revenue is recorded in the reporting period in which the performance obligation was satisfied. Once the final statements and payments are received, differences between estimated revenues and actual amounts received are recognized in the month of receipt. Historically, these differences have not been significant.

For the sale of produced oil and natural gas from wells in which the Company has non-operated revenue or royalty interests, the Company recognizes revenue based on the details included in the statements received from the operator. Any gathering, transportation, processing, production taxes, and other deductions included on the statements are recorded based on the information provided by the operator. The Company does not disclose the value of unsatisfied performance obligations as it applies the practical exemption for 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.

For the properties operated by the Company, oil and natural gas revenues are recognized through contracts with customers during the month in which control of the product transfers, typically at the point of delivery when the risk of loss and title pass from the Company to the customer, and it is probable that the Company will collect the consideration to which it is entitled. The Company sells the majority of its operated production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage. Revenue from operated properties is recorded in the month that production is delivered to the customer. However, settlement statements and payments are typically not received for 20 to 45 days after the date production is delivered. Consequently, the Company estimates the volume of production delivered and the price that will be received for the sale of the product using knowledge of its properties, the properties’ historical performance, spot market prices, and other relevant factors. Differences between estimated and actual revenues are adjusted upon receipt of payment, typically in the following reporting period. Historically, these differences have not been significant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not significant for the periods presented.

Concentrations of Credit Risk

For the years ended December 31, 2025, 2024 and 2023, five, four and three operators accounted for 67 percent,64 percent and 49 percent, respectively, of oil and natural gas revenue. As of December 31, 2025 and 2024, three and four operators accounted for 50 percent and 71 percent, respectively, of oil and natural gas accrued revenue. The Company’s non-operated oil and natural gas revenue is generated from the sale of oil and natural gas by operators on its behalf. The Company monitors the financial condition of its operators.

For operated properties during the year ended December 31, 2025, one purchaser accounted for over 90 percent of the Company’s operated sales. The Company believes that the loss of a purchaser would not have a material adverse effect on the Company’s operations, as there are a number of alternative purchasers in the region.

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax liabilities represent the future income tax consequences of those differences, which will be taxable when liabilities are settled. Deferred income taxes may also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of December 31, 2025 and 2024.

Derivative Financial Instruments

The Company enters into derivative contracts to manage its exposure to oil and gas price volatility. Commodity derivative contracts may take the form of swaps, puts, calls, or collars. Cash settlements from the Company’s commodity price risk management activities are recorded in the month the contracts mature. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to Commodity derivative gain (loss), net in the consolidated statements of operations.

GAAP requires recognition of all derivative instruments in the consolidated balance sheets as either assets or liabilities measured at fair value. Subsequent changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company has elected to not designate any derivative instruments as accounting hedges, and therefore reflects all commodity derivative instruments changes in fair value in earnings. Amounts associated with deferred premiums on derivative instruments are recorded as a component of the derivatives’ fair values. See Note 6 (“Derivative Instruments”).

New Accounting Pronouncements

In December 2023, FASB issued ASU 2023-09, Improvements to Income Tax Disclosures. The ASU establishes new income tax disclosure requirements in addition to modifying and eliminating certain existing requirements. The guidance was applied on a retrospective basis. The adoption of the new guidance as of December 31, 2025 did not have a material impact on the Company’s financial statements and related disclosures.

In November 2024, FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses (DISE). The ASU primarily requires companies to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The guidance will be applied on a prospective basis with the option to apply the standard retrospectively. The new guidance will be effective for the Company’s year ending December 31, 2027 and interim periods during the year ended December 31, 2028. The Company does not believe the new guidance will have a material impact on its consolidated financial statements and related disclosures.

Note 3—Oil and Gas Properties

Asset Acquisitions

During the years ended December 31, 2025, 2024 and 2023, the Company purchased a number of proved oil and gas properties and proved leaseholds for an aggregate purchase price of $6.6 million, $21.1 million, and $35.7 million, respectively. In addition, as part of the Spin-Off during the year ended December 31, 2023, $35.6 million of oil and gas properties and $5.0 million of net liabilities of Vitesse Oil were contributed in exchange for 2,120,312 shares of common stock of the Company for total consideration of $30.6 million.

These transactions qualified as asset acquisitions; therefore, the oil and gas properties were recorded based on the fair value of the total consideration transferred on the acquisition dates, and transaction costs were capitalized as a component of the assets acquired. Transaction costs during the years ended December 31, 2025, 2024 and 2023 were immaterial.

Lucero Acquisition

On March 7, 2025, the Company closed the Lucero Acquisition and issued 8,169,839 shares of common stock to Lucero shareholders. Based on the purchase price allocation, the Company recorded the assets acquired and liabilities assumed at their estimated fair value on March 7, 2025. Determining the fair value of the assets and liabilities of Lucero requires judgment and certain assumptions to be made. See Note 4 (“Fair Value Measurements”) for additional information.

The Company used the acquisition method of accounting for this business combination. The tables below present the total consideration transferred and its allocation to the estimated fair value of identifiable assets acquired and liabilities assumed as of the acquisition date of March 7, 2025.

Adjustments to the preliminary purchase price allocation, include a $15.8 million decrease to proved oil and gas properties, a $14.3 million increase to the deferred tax asset, and a $1.5 million decrease to accrued liabilities. The decrease to proved oil and gas properties had a corresponding decrease to depletion, depreciation, amortization, and accretion expense.

Post-closing operating results

The results of operations of Lucero have been included in the Company’s consolidated financial statements since the closing of the Lucero Acquisition on March 7, 2025. The total revenue and loss before income taxes attributable to Lucero included in the consolidated statements of operations are as follows:

Unaudited pro forma financial information

The table below presents unaudited pro forma total revenue and income before income taxes for the periods shown, as if the Lucero Acquisition had occurred on January 1, 2024. The Company believes the assumptions used in preparing this information provide a reasonable basis for estimating the significant effects of the acquisition. This pro forma financial information is not indicative of what the Company’s results would have been had the acquisition occurred on January 1, 2024, nor should it be relied upon as a projection of future results.

Note 4—Fair Value Measurements

Accounting standards require certain assets and liabilities be reported at fair value in the consolidated financial statements and provide a framework for establishing that fair value. The framework for determining fair value is based on a hierarchy that prioritizes the inputs and valuation techniques used to measure fair value.

Fair values determined by Level 1 inputs use quoted prices in active markets for identical assets or liabilities that the Company has the ability to access.

Fair values determined by Level 2 inputs use other inputs that are observable, either directly or indirectly. These Level 2 inputs include quoted prices for similar assets and liabilities in active markets and other inputs, such as interest rates, yield curves, and forward commodity price curves, that are observable at commonly quoted intervals.

Level 3 inputs are unobservable inputs, including inputs that are available in situations where there is little, if any, market activity for the related asset or liability. These Level 3 fair value measurements are based primarily on management’s own estimates using pricing models, discounted cash flow methodologies, or similar techniques taking into account the characteristics of the asset or liability. Significant Level 3 inputs include estimated future cash flows used in determining the fair value of purchased oil and gas properties.

In instances where inputs used to measure fair value fall into different levels in the above fair value hierarchy, fair value measurements in their entirety are categorized based on the lowest level input that is significant to the valuation. The Company’s assessment of the significance of particular inputs to these fair value measurements requires judgment and considers factors specific to each asset or liability.

Recurring Fair Value Measurements

As of December 31, 2025, the Company’s derivative financial instruments are composed of commodity swaps and collars. The fair value of the swap and collar agreements is determined under the income valuation technique using a discounted cash flow model. The valuation models require a variety of inputs, including contractual terms, published forward commodity prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s commodity derivative instruments are included within Level 2 of the fair value hierarchy. See Note 6 (“Derivative Instruments”).

Nonrecurring Fair Value Measurements

Business Combinations

The fair value of the oil and gas properties was determined using the income approach, relying on discounted future net cash flows generated from the properties' reserve reports. The valuation inputs primarily consisted of unobservable inputs, which fall within Level 3 of the fair value hierarchy as defined by ASC 820. Key inputs included estimates of future production volumes from the proved reserves, future commodity prices based on forward strip price curves (adjusted for basis differentials), estimates of lease operating, development and abandonment costs, and the application of a discount rate. The discount rates were adjusted to reflect the risk profile associated with the category of reserves being valued (e.g., proved developed, proved undeveloped).

Asset Retirement Obligations

The Company uses the income valuation technique to estimate the fair value of asset retirement obligations, at initial recognition, arising from the development of proved properties using the amounts and timing of expected future dismantlement costs and credit-adjusted risk-free rates. Accordingly, the fair value is based on unobservable inputs and, therefore, is included within Level 3 of the fair value hierarchy. The significant unobservable inputs include the gross cost of abandoning oil and gas wells; the economic lives of the properties; the inflation rate; and the credit-adjusted risk-free rate of the Company.

Financial Instruments Not Measured at Fair Value

The carrying amounts of the majority of the Company’s financial instruments, namely cash, receivables, accounts payable, and accrued liabilities, approximate their fair values due to the short-term nature of these instruments. The Company’s credit facility as a recorded value that approximates fair market value, as it bears interest at a floating rate that approximates a current market rate. See Note 5 (“Credit Facility”).

Note 5—Credit Facility

In connection with the Spin-Off in January 2023, the Company entered into a secured revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of banks, as lenders (the “Revolving Credit Facility”). The Revolving Credit Facility will mature on October 22, 2028. The Revolving Credit Facility permits borrowing on a revolving credit basis with availability equal to the least of (1) the aggregate elected commitments, (2) the then-effective borrowing base and (3) the maximum credit amount of $500.0 million. The borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of the Company’s proved oil and natural gas reserves, as determined by the lenders in their discretion. As of December 31, 2024 the Company’s borrowing base was $245.0 million with an aggregate elected commitment of $235.0 million of which $117.0 million was outstanding. In conjunction with the closing of the Lucero Acquisition on March 7, 2025, the borrowing base was redetermined at $315 million with an aggregate elected commitment of $250.0 million. As of December 31, 2025 the Company’s borrowing base was $295.0 million with an aggregate elected commitment of $250.0 million of which $124.5 million was outstanding

At the Company’s option, borrowings under the Revolving Credit Facility bear interest at a rate, which is either an adjusted forward-looking term rate based on SOFR (“Term SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.50% or the 30-day Term SOFR rate plus 1.0%), plus an applicable margin expected to range from 1.50% to 2.50% with respect to Base Rate borrowings and 2.50% to 3.50% with respect to Term SOFR borrowings, in each case based on the current commitment utilization percentage. Interest is calculated and paid monthly in arrears. Additionally, the Company incurs an unused credit facility fee, paid quarterly, of 0.50% of the unutilized commitment regardless of the borrowing base utilization percentage. As of December 31, 2025 and 2024, the interest rate on the outstanding balance under the Revolving Credit Facility was 6.75% and 7.21%, respectively.

The Revolving Credit Facility is guaranteed by certain of the Company’s subsidiaries and is collateralized by a first priority lien on substantially all assets of Vitesse and its subsidiaries, including a first priority lien on properties representing a minimum of 85% of the total present value of the Company’s proved oil and natural gas properties.

The Revolving Credit Facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Company’s ability to, among other things, incur or guarantee additional debt, make distributions to equity holders, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets.

Under the Revolving Credit Facility, the Company is permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500.0 million (2) then-effective borrowing base, and (3) the then-effective aggregate elected commitments and (b) as of the date of such distribution, the EBITDAX Ratio, as defined under the Revolving Credit Facility, does not exceed 1.50 to 1.00. If the EBITDAX Ratio exceeds 1.50 to 1.00, but does not exceed 2.25 to 1.00, and if total outstanding credit usage does not exceed 80% of the Commitments, the Company may make distributions if free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and the Company has delivered a certificate to lenders attesting to the foregoing.

The Revolving Credit Facility contains covenants requiring us to maintain the following financial ratios tested on a quarterly basis (terms below are as defined in the Revolving Credit Facility): (1) a consolidated Total Funded Debt to consolidated EBITDAX ratio of not greater than 3.0 to 1.0; and (2) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. The Revolving Credit Facility also contains covenants that require that the Company enter into swap agreements covering not less than 40% of reasonably anticipated PDP production for the following four quarters when the Utilization Percentage, as defined in the Revolving Credit Facility, is less than 50% and covering at least 50% of reasonably anticipated PDP production for the following eight quarters if the Utilization Percentage is 50% or greater. The Revolving Credit Facility contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change in control. If an event of default exists under the Revolving Credit Facility, the lenders will be able to terminate the lending commitments, accelerate the maturity of the Revolving Credit Facility and exercise other rights and remedies with respect to the collateral. The Company was in compliance with all financial covenants of the Revolving Credit Facility at December 31, 2025.

Note 6—Derivative Instruments

The Company periodically enters into various commodity hedging instruments to mitigate a portion of the effect of oil and natural gas price fluctuations. The Company classifies the fair value amounts of commodity derivative assets and liabilities as current or noncurrent commodity derivative assets or current or noncurrent commodity derivative liabilities, whichever the case may be. Commodity derivatives are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement.

The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of December 31, 2025, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet:

The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of December 31, 2024, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet:

As of December 31, 2025, the Company had the following crude oil swaps:

As of December 31, 2025, the Company had the following crude oil collars:

As of December 31, 2025, the Company had the following natural gas collars:

As of December 31, 2025, the Company had the following natural gas basis swaps:

As of December 31, 2025, the Company had the following natural gas liquids swaps (presented annually due to lesser significance):

Due to the volatility of oil, natural gas and natural gas liquids prices, the estimated fair values of the Company’s commodity derivative instruments are subject to significant fluctuations from period to period.

The counterparties in the Company’s derivative instruments either do not require collateral or also participate in the Revolving Credit Facility; and thus have the right of offset for any derivative liabilities, with the Revolving Credit Facility secured by the Company’s oil and gas assets. For further discussion related to the fair value of the Company’s derivatives, see Note 4 (“Fair Value Measurements”).

Note 7—Accrued Liabilities

Accrued liabilities as of December 31, 2025 and 2024 are summarized as follows:

Note 8—Asset Retirement Obligations

A rollforward of AROs for the years ended December 31, 2025 and 2024 are presented below.

Note 9—Related Party Transactions

On July 1, 2016, the Predecessor entered into a separate services agreement with Vitesse Management and JETX Energy, LLC (“JETX”), formerly known as Juneau Energy, LLC, another entity owned by JFG with common management. Per this services agreement, Vitesse Management is to provide JETX certain administrative services and supervise, administer, and manage the business affairs and operations of JETX and its subsidiaries for a service provider fee of $0.2 million per month. The term of this service agreement extends for an unlimited amount of time; however, it is subject to termination by either Vitesse Management or JETX if provided written consent following the first anniversary or a final exit event. During each of the years ended December 31, 2025, 2024, and 2023, the Company recorded its net share of fees from JETX of approximately $2.7 million, which is classified as a reduction to general and administrative expenses in the accompanying consolidated statements of operations.

During the year ended December 31, 2025, the Company paid approximately $2.5 million of transaction costs to a related party in connection with the Lucero Acquisition (see Note 3 (“Oil and Gas Properties”)).

Note 10—Leases

The Company is obligated under noncancelable leases primarily for facilities. Total expense under operating leases was $1.1 million, $0.6 million, and $0.4 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Leases with an initial term of 12 months or less are not recorded in the consolidated balance sheets.

The Company’s lease agreements do not provide an implicit borrowing rate; therefore, an internal incremental borrowing rate is determined based on information available at the lease commencement date, including the current rate on our collateralized revolving credit agreement, for the purpose of determining the present value of lease payments. The right-of-use assets of $4.1 million and $4.4 million as of December 31, 2025 and 2024, respectively, are recorded within Other noncurrent assets in the consolidated balance sheets. The related lease obligations of $4.8 million and $4.8 million as of December 31, 2025 and 2024, respectively, are recorded within Other noncurrent liabilities and Other current liabilities in the consolidated balance sheets.

As of December 31, 2025, maturities of the Company’s lease liabilities were as follows:

As of December 31, 2025, the Company’s operating leases have weighted-average remaining lease terms and discount rates of 9.3 years and 8.4%, respectively.

Note 11—Commitments and Contingencies

Litigation

From time to time, the Company may be involved in litigation relating to claims arising out of its operations in the normal course of business. As of the date of this report, management of the Company was unaware of any material legal proceedings against the Company. The Company maintains insurance to cover certain actions.

As previously disclosed, the Company was the plaintiff in an ongoing dispute in state court in North Dakota with one of its operators related to post-production revenue deductions. Effective as of May 28, 2025, the Company resolved this pending litigation in North Dakota with Hess. As part of the settlement, during the year ended December 31, 2025, the Company received a one-time cash payment of $24 million. The settlement resolved claims for recoupment of revenue deductions and reimbursement of legal expenses. The Company recorded the payment as follows in the consolidated statements of operations: a $3.3 million increase to oil revenue, a $13.6 million increase to gas revenue and a $7.1 million reduction to general and administrative expenses for reimbursed legal costs.

In addition to the one-time cash payment, the Company elected to take virtually all of its gas production from Hess-operated wells in-kind commencing July 1, 2025 and entered into long-term gas gathering, processing and marketing agreements with Hess affiliates.

Note 12—Equity

Authorized Capital Stock

The Amended and Restated Certificate of Incorporation authorized capital stock consisting of 95,000,000 shares of common stock, par value $0.01 per share and 5,000,000 shares of preferred stock, par value $0.01 per share.

Common Stock

During the year ended December 31, 2025 the following transactions related to our common stock occurred:

■8,169,839 shares of common stock were issued to acquire Lucero.

■1,189,718 RSUs vested and were released as common stock, of which 345,255 were exchanged for tax withholding and retired by the Company.

During the year ended December 31, 2024 the following transactions related to our common stock occurred:

■901,998 RSUs vested and were released as common stock, of which 354,069 were exchanged for tax withholding and retired by the Company.

On February 25, 2026, the Company’s Board of Directors declared a regular quarterly cash dividend for the Company’s common stock of $0.4375 per share for stockholders of record as of March 16, 2026, which will be paid on March 31, 2026.

Preferred Stock

Our Amended and Restated Certificate of Incorporation authorizes our board of directors to designate and issue from time to time one or more series of preferred stock without stockholder approval. Our board of directors may fix and determine the designation, relative rights, preferences and limitations of the shares of each such series of preferred stock. There are no present plans to issue any shares of preferred stock and there are currentlyno shares outstanding.

Long-Term Incentive Plan

The Company’s long-term incentive plan (“LTIP”) provides for the granting of various forms of equity-based awards, including stock option awards, stock appreciation rights awards, restricted stock awards, restricted stock unit awards, performance awards, cash awards and other stock-based awards to employees, directors and consultants of the Company. The LTIP was amended and restated in May 2025 to increase the number of shares available to be awarded by 580,500 shares to 4,540,500 shares. As of December 31, 2025, there were 854,787 shares available to be granted.

Restricted Stock Units

For restricted stock units, the Company recognizes the grant date fair-value of awards over the requisite service period as stock-based compensation expense on a straight-line basis except when provisions are present that accelerate vesting. Restricted stock units are considered issued but not outstanding when granted. Accumulated accrued stock based compensation expense and any accrued dividends are reversed in the period when units are forfeited and the units are no longer considered issued.

The following is a summary of RSU activity during the years ended December 31, 2025 and 2024:

During the years ended December 31, 2025 and 2024, the Company recognized $8.8 million and $7.4 million of equity-based compensation expense relating to these restricted stock units, respectively.

As of December 31, 2025, there is $7.4 million of unrecognized equity-based compensation expense related to unvested restricted stock unit awards. The cost is expected to be recognized through February 2028, over a weighted-average period of 1.38 years.

Performance Stock Units

PSUs are contingent shares that may be earned over three-year performance periods. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the applicable performance period. Depending on the Company’s TSR performance relative to the defined peer group, award recipients may earn between 0% and 200% of the target amount of PSUs detailed in the applicable grant notice. As the vesting criterion is linked to changes in the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The Company recognizes the grant date fair-value of PSUs over the requisite service period as equity-based compensation expense on a straight-line basis. Compensation expense for share-settled awards is not reversed if market conditions are not met. Accumulated accrued equity-based compensation expense and dividends are reversed in the period if the units are forfeited.

The grant date fair value of PSUs was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the forecast period, and the volatilities for each of the Company’s peers.

The assumptions used in valuing the PSUs granted were as follows:

The following is a summary of PSU activity during the year ended December 31, 2025 and 2024:

During the years ended December 31, 2025 and 2024, the Company recognized $1.4 million and $0.7 million of equity-based compensation expense relating to these performance stock units, respectively.

As of December 31, 2025, there is $2.3 million of unrecognized equity-based compensation expense related to unvested performance stock unit awards. The cost is expected to be recognized through December 2027, over a weighted-average period of 1.65 years.

Transitional Equity Award Adjustment Plan

JFG’s outstanding compensatory equity awards were adjusted into equity incentive awards denominated in part in shares of Vitesse common stock in connection with the Spin-Off. All adjusted awards are subject to generally the same vesting, exercisability, expiration, settlement and other material terms and conditions as applied to the applicable original JFG award immediately before the Spin-Off, except that equity awards relating to our common stock were subject to accelerated vesting, exercisability and in some cases settlement in the event of a change in control of the Company. All of the Transitional Plan equity awards discussed below were granted by JFG and therefore do not result in any compensation cost to the Company.

Transitional Plan Options

Each JFG stock option that did not remain an option to purchase shares of only JFG common stock was converted into both a post-Spin-Off option to purchase shares of JFG common stock and an option to purchase shares of Vitesse common stock. The exercise price of such JFG stock option and the exercise price and number of shares subject to such Vitesse stock option was adjusted so that (i) the aggregate intrinsic value of such post-Spin-Off JFG stock option and Vitesse stock option immediately after the Spin-Off equals the aggregate intrinsic value of the JFG stock option as measured immediately before the Spin-Off and (ii) the aggregate exercise price of such post-Spin-Off JFG stock option and Vitesse stock option equals the aggregate exercise price of the JFG stock option immediately before the Spin-Off, subject to rounding. Upon completion of the Spin-Off,457,866 options were granted andnone were exercised during the years ended December 31, 2025 and 2024. The intrinsic option value of the options was $4.7 million at December 31, 2025 and the maximum number of shares of common stock that could be issued under the plan is 457,866.

Transitional Plan Restricted Units

Each JFG restricted stock unit award and performance stock unit award (other than those that will remain awards denominated in shares of only JFG stock, which includes the portion of any performance stock unit award that may be earned above the designated target level), including any additional stock units accrued as a result of dividend equivalents, was adjusted by the grant of a Vitesse restricted stock unit award. Upon completion of the Spin-Off, restricted stock units were granted in respect of these JFG awards. These restricted stock unit awards are capped at 1,475,613 and at December 31, 2025 none have a remaining performance, service or vesting condition to satisfy. These restricted stock unit awards generally accrue dividends declared on common stock but have deferred issuance dates through January 2, 2099. During the years ended December 31, 2025 and 2024,86,103 and 115,726 restricted stock units were released as common stock, net of shares cashed out as fractional units, respectively. During the year ended December 31, 2024,7,476 restricted stock units were forfeited.

Transitional Plan Restricted Stock Awards

Holders of a JFG restricted stock award received 286,729 shares of our common stock upon completion of the Spin-Off, which shares are subject to the provisions of the Transitional Plan, including generally the same risk of forfeiture and other conditions as applied to the original JFG restricted stock award. These restricted stock awards have no remaining performance or service conditions to satisfy, or any other vesting condition, and are paid dividends on common stock as declared but have deferred issuance dates through September 28, 2029. During the years ended December 31, 2025 and 2024,17,262 and 57,580 restricted stock awards were released as common stock.

As of December 31, 2025, Transitional Plan Restricted Units and Transitional Plan Restricted Awards are scheduled to be released as follows:

The Transitional Plan governs the terms and conditions of the new Vitesse awards issued as an adjustment to JFG awards at the effective time of the Spin-Off, but will not be used to make any grants following the Spin-Off.

Stock Repurchase Program

In February 2023, the Board approved a stock repurchase program authorizing the repurchase of up to $60 million of the Company’s common stock.

Under the Stock Repurchase Program, the Company may repurchase shares of its common stock from time to time in open market transactions or such other means as will comply with applicable rules, regulations and contractual limitations. The Board of Directors may limit or terminate the Stock Repurchase Program at any time without prior notice. The extent to which the Company repurchases its shares of common stock, and the timing of such repurchases, will depend upon market conditions and other considerations as may be considered in the Company’s sole discretion.

Net Income (Loss) Per Common Share

The Company uses the two-class method of calculating earnings per share because certain of the Company’s unvested LTIP RSUs qualify as participating securities.

Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the adjustment of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented.

The components of basic and diluted net income (loss) per share attributable to common stockholders are as follows:

(1)Certain unvested LTIP RSUs represent participating securities because they participate in nonforfeitable dividends with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. These unvested LTIP RSUs do not participate in undistributed net losses as they are not contractually obligated to do so.

Note 13—Income Taxes

Prior to the Spin Off, Vitesse Energy and Vitesse Oil have been treated as a partnership for U.S. federal applicable state and local income tax purposes. As partnerships, Vitesse Energy and Vitesse Oil were not subject to U.S. federal and certain state and local income taxes, and any taxable income or loss generated by Vitesse Energy and Vitesse Oil was passed through to and included in the taxable income or loss of its members. Following the Spin-Off, the Company is now subject to U.S. federal and applicable state and local income taxes for taxable income or loss.

For the years ended December 31, 2025, 2024 and 2023, the Company recorded a federal and state tax deferred expense of $9.8 million, $7.7 million and $61.9 million, respectively. In January 2023 the Predecessor was contributed into Vitesse resulting in a change in tax status and the recording of $44.1 million federal and state deferred tax expense. In addition, a $2.4 million deferred tax liability was recorded in 2023 related to the acquisition of Vitesse Oil.

Income tax expenses and benefits included in the consolidated statements of operations are detailed below:

A reconciliation of the statutory federal income tax expense, which is calculated at the federal statutory rate of 21% for the years ended December 31, 2025, 2024 and 2023 to the income tax expense from continuing operations provided for the periods presented, is as follows:

(1) The majority of state income tax expense results from North Dakota

The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:

As of December 31, 2025, the Company had $95.7 million and $55.9 million of U.S. federal and state net operating loss carryovers, respectively. Of these amounts, $57.4 million of U.S. federal net operating loss carryovers acquired in connection with the Lucero Acquisition are subject to an IRC §382 annual limitation amount of $7.1 million. In addition, acquired Lucero state net operating losses of $30.2 million are subject to separate return year limitations. U.S. federal net operating loss carryforwards incurred prior to January 1, 2018 of $45.2 million will begin to expire in 2033. U.S. federal net operating loss carryforwards incurred after December 31, 2017 of $50.5 million have no expiration and can only be used to offset 80% of taxable income when utilized. As of December 31, 2024, the Company had $34.6 million and $23.2 million of U.S. federal and state net operating loss carryovers, respectively.

The Company periodically assesses whether it is more-likely-than-not that it will generate sufficient taxable income to realize its deferred income tax assets. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. Based on when the Company expects existing taxable differences to be realized, management determined that sufficient positive evidence exists as of December 31, 2025 to conclude that it is more-likely-than-not that all of its deferred tax assets will be realized with the exception of those in the Canadian jurisdiction. Of the existing valuation allowance, $0.1 million was recorded as part of the Lucero Acquisition.

The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon the examination by the Internal Revenue Service or other taxing authority. As of December 31, 2025 and 2024, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Interest and penalties related to uncertain tax positions are reported in income tax expense.

As of December 31, 2025, the Company has no tax years under audit. The Company remains subject to examination for federal income taxes and state income taxes for tax years 2022 through 2025 and Colorado state taxes for the additional 2021 tax year.

Note 14—Subsequent Events

On March 1, 2026, the Company entered into a definitive agreement to acquire assets, including over 6,000 net acres in Campbell and Converse Counties, WY, for $35 million of Vitesse common stock, subject to customary closing adjustments.

Other than the above disclosure or other subsequent events disclosed elsewhere in the notes to the financial statements, there were no material subsequent events.

Supplemental Oil and Gas Information (Unaudited)

Oil and Natural Gas Exploration and Production Activities

Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for any contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include ad valorem and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s crude oil and natural gas production activities are provided in the Company’s related consolidated statements of operations. Capitalized costs relating the Company’s oil and natural gas producing activities as of December 31, 2025 and 2024 are provided in the Company’s consolidated balance sheets.

Costs Incurred

The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below.

Oil and Natural Gas Reserve Data

The following tables present the Company’s net proved crude oil and natural gas reserves as prepared by our third-party independent reserve engineers, Cawley, and include changes as estimated by the Company’s engineering staff. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.

Notable changes in proved reserves for the year ended December 31, 2025 included the following:

■Acquisitions: We acquired 17,483 MBoe of proved developed and undeveloped reserves in the Williston Basin and Central Rockies during 2025 (See Note 3 (“Oil and Gas Properties”)).

■Revisions to previous estimates: In 2025, revisions to previous estimates decreased proved reserves by a net amount of 7,868 MBoe. 2,309 MBoe of that is attributable to reclassifications from proved to non-proved primarily based on updated information on near term operator drilling plans and continued compliance with the SEC 5-year development rule. In addition, the revisions included decreases in proved reserves of 2,495 MBoe associated with lower commodity prices and higher differentials, a 1,009 MBoe decrease due to non-consenting and interest changes, a 500 MBoe decrease related to higher lease operating expenses, and a 1,555 decrease related to forecast and schedule changes.

■Extensions and discoveries: During 2025, extensions and discoveries of 4,269 MBoe were attributable to additions of 204 MBoe of proved developed reserves and 4,065 MBoe of proved undeveloped reserves in the Williston Basin. The proved undeveloped reserves were reclassified from non‑proved to proved primarily due to updated information regarding near‑term operator drilling plans.

Notable changes in proved reserves for the year ended December 31, 2024 included the following:

■Acquisitions: We acquired 1,518 MBoe of proved undeveloped reserves in the Williston Basin and Central Rockies during 2024 (See Note 3 (“Oil and Gas Properties”)).

■Revisions to previous estimates: In 2024, revisions to previous estimates decreased proved reserves by a net amount of 3,894 MBoe. 1,877 MBoe of that is attributable to reclassifications from proved to non-proved primarily based on updated information on near term operator drilling plans and continued compliance with the SEC 5-year development rule. In addition, the revisions included decreases in proved reserves of 430 MBoe associated with lower commodity prices and higher differentials, a 577 MBoe decrease due to higher lease operating expenses, and a 1,009 MBoe decrease related to forecast/timing/interest changes.

■Extensions and discoveries: During 2024, extensions and discoveries of 6,823 MBoe were attributable to additions of 1,273 MBoe of proved developed reserves and 5,550 MBoe of proved undeveloped reserves in the Williston Basin.

Notable changes in proved reserves for the year ended December 31, 2023 included the following:

■Acquisitions: We acquired 3,932 MBoe of proved undeveloped reserves in the Williston Basin and Central Rockies during 2023 (See Note 3 (“Oil and Gas Properties”)).

■Revisions to previous estimates: In 2023, revisions to previous estimates decreased proved reserves by a net amount of 6,906 MBoe. These revisions were primarily attributable to the reclassification of undeveloped drilling locations totaling 4,184 MBoe of proved reserves from proved to non-proved and were made proactively as a result of lower-than-expected rig activity in the Williston Basin during the year and continued compliance with the SEC 5-year development rule. In addition, the revisions included decreases in proved reserves of 1,072 MBoe related to forecast/timing/interest changes and 1,650 MBoe associated with lower commodity prices and slightly higher lease operating expenses due to increased workover activity.

■Extensions and discoveries: During 2023, extensions and discoveries of 4,112 MBoe were attributable to additions of 1,520 MBoe of proved developed reserves and 2,592 MBoe of proved undeveloped reserves in the Williston Basin.

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves, and the changes in standardized measure of discounted future net cash flows relating to proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities— Oil and Gas. Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year (including asset retirement costs), based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are then discounted at the rate of 10%. Actual future cash inflows may vary considerably, and the standardized measure does not represent the fair value of the Company’s crude oil and natural gas reserves.

The twelve-month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows:

Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: