Vitesse Energy (VTS) 10-K 16 Feb 23 2022 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 01, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-41546
Entity Registrant Name	Vitesse Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	88-3617511
Entity Address, Address Line One	9200 E. Mineral Avenue,
Entity Address, Address Line Two	Suite 200
Entity Address, City or Town	Centennial,
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80112
City Area Code	(720)
Local Phone Number	361-2500
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	VTS
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float	$ 0
Entity Common Stock, Shares Outstanding		28,524,435
Documents Incorporated by Reference	None.
Entity Central Index Key	0001944558
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Deloitte & Touche LLP
Auditor Location	Denver, Colorado
Auditor Firm ID	34

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021
Current Assets
Cash	$ 10,007,000	$ 5,356,000	$ 2,801,000
Revenue receivable	41,393,000	30,629,000	31,959,000
Commodity derivatives	2,112,000	0	1,513,000
Prepaid expenses and other current assets	841,000	138,000	148,000
Total current assets	54,353,000	36,123,000	36,421,000
Oil and Gas Properties-Using the successful efforts method of accounting
Proved oil and gas properties	985,751,000	893,920,000	890,788,000
Less accumulated DD&A and impairment	(382,974,000)	(319,675,000)	(314,292,000)
Total oil and gas properties	602,777,000	574,245,000	576,496,000
Other Property and Equipment—Net	114,000	215,000	223,000
Other Assets
Commodity derivatves	1,155,000	0	0
Other noncurrent assets	2,085,000	943,000	988,000
Total other assets	3,240,000	943,000	988,000
Total assets	660,484,000	611,526,000	614,128,000
Current Liabilities
Accounts payable	7,207,000	7,940,000	4,593,000
Accrued liabilities	25,849,000	15,610,000	18,617,000
Commodity derivatives	3,439,000	16,466,000	8,672,000
Other current liabilities	184,000	316,000	318,000
Total current liabilities	36,679,000	40,332,000	32,200,000
Long-term Liabilities
Revolving credit facility	48,000,000	68,000,000	68,000,000
Unit-based compensation	0	10,980,000	8,352,000
Asset retirement obligation	6,823,000	6,156,000	6,132,000
Other noncurrent liabilities	0	194,000	221,000
Total liabilities	91,502,000	125,662,000	114,905,000
Commitments and Contingencies
Redeemable Management Incentive Units	4,559,000	5,790,000	4,831,000
Members' Equity	564,423,000	480,074,000	494,392,000
Total liabilities, redeemable units, and members' equity	660,484,000	$ 611,526,000	$ 614,128,000
Vitesse Energy, Inc.
Current Assets
Cash	0
Other Assets
Total assets	0
Long-term Liabilities
Total liabilities	0
Commitments and Contingencies
Common stock, $0.01 par value, 1,000 shares authorized; 1,000 shares issues and outstanding at December 31, 2022	10
Stock subscription receivable	(10)
Total Stockholders' Equity	0
Total liabilities, redeemable units, and members' equity	$ 0

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2022 $ / shares shares
Common units, outstanding (in units)	450,000,000
Vitesse Energy, Inc.
Par value (in USD per share) | $ / shares	$ 0.01
Shares authorized (in shares)	1,000
Shares issued (in shares)	1,000
Shares outstanding (in shares)	1,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Revenue
Total revenue	$ 17,988,000	$ 300,070,000	$ 185,178,000	$ 97,230,000
Operating Expenses
Production expense	3,794,000	49,313,000	43,910,000	41,731,000
Production taxes	1,340,000	24,092,000	14,535,000	9,173,000
General and administrative	950,000	19,833,000	10,581,000	9,196,000
Depletion, deprecation, amortization, and accretion	5,417,000	63,732,000	60,846,000	58,307,000
Impairment of proved oil and gas properties	0	0	0	13,200,000
Unit-based compensation	2,628,000	(10,766,000)	1,409,000	(544,000)
Total operating expenses	14,129,000	146,204,000	131,281,000	131,063,000
Operating Income (Loss)	3,859,000	153,866,000	53,897,000	(33,833,000)
Other (Expense) Income
Commodity derivative (loss) gain, net	(10,982,000)	(30,830,000)	(32,590,000)	29,633,000
Interest expense	(237,000)	(4,153,000)	(3,207,000)	(4,679,000)
Other income	1,000	20,000	14,000	22,000
Total other (expense) income	(11,218,000)	(34,963,000)	(35,783,000)	24,976,000
Net Income (Loss)	$ (7,359,000)	$ 118,903,000	$ 18,114,000	$ (8,857,000)
Net income (loss) per common unit, basic (in USD per share)	$ (0.02)	$ 0.26	$ 0.04	$ (0.02)
Net income (loss) per common unit, diluted (in USD per share)	(0.02)	0.26	0.04	(0.02)
Net income (loss) per non-founder MIUs classified as temporary equity, basic (in USD per share)	0	0	0	0
Net income (loss) per non-founder MIUs classified as temporary equity, diluted (in USD per share)	$ 0	$ 0	$ 0	$ 0
Oil
Revenue
Total revenue	$ 15,241,000	$ 242,467,000	$ 151,838,000	$ 91,542,000
Natural gas
Revenue
Total revenue	$ 2,747,000	$ 57,603,000	$ 33,340,000	$ 5,688,000

Consolidated Statements of Memb

Consolidated Statements of Members' Equity $ in Thousands	USD ($)
Beginning balance at Nov. 30, 2019	$ 497,632
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	8,857
Fair market value MIU adjustment	1,033
Ending balance at Nov. 30, 2020	489,808
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(18,114)
Fair market value MIU adjustment	(1,530)
Distribution to common unit holders	(12,000)
Ending balance at Nov. 30, 2021	494,392
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	7,359
Fair market value MIU adjustment	(959)
Distribution to common unit holders	(6,000)
Ending balance at Dec. 31, 2021	480,074
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(118,903)
Fair market value MIU adjustment	1,446
Distribution to common unit holders	(36,000)
Ending balance at Dec. 31, 2022	$ 564,423

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Cash Flows from Operating Activities
Net Income (Loss)	$ (7,359,000)	$ 118,903,000	$ 18,114,000	$ (8,857,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, deprecation, amortization, and accretion	5,417,000	63,732,000	60,846,000	58,307,000
Unrealized loss (gain) on derivative instruments	9,307,000	(16,294,000)	18,687,000	(2,472,000)
Unit-based compensation	2,628,000	(10,766,000)	1,409,000	(544,000)
Amortization of debt issuance costs	27,000	472,000	276,000	362,000
Impairment of proved oil and gas properties	0	0	0	13,200,000
Changes in operating assets and liabilities that provided (used) cash:
Revenue receivable	1,330,000	(10,764,000)	(15,959,000)	18,663,000
Prepaid expenses and other current assets	11,000	(842,000)	1,921,000	(1,303,000)
Accounts payable	669,000	(147,000)	(997,000)	(524,000)
Accrued liabilities	493,000	2,739,000	2,700,000	(548,000)
Other	(3,000)	8,000	(26,000)	25,000
Net cash provided by Operating Activities	12,520,000	147,041,000	86,971,000	76,309,000
Cash Flows from Investing Activities
Acquisition of oil and gas properties	(117,000)	(28,547,000)	(6,210,000)	(9,234,000)
Development of oil and gas properties	(3,837,000)	(56,024,000)	(36,986,000)	(61,486,000)
Purchase of property and equipment	(2,000)	(12,000)	(121,000)	(113,000)
Other	0	0	0	25,000
Net cash used in Investing Activities	(3,956,000)	(84,583,000)	(43,317,000)	(70,808,000)
Cash Flows from Financing Activities
Proceeds from revolving credit facility	0	16,000,000	1,000,000	10,000,000
Repayments of revolving credit facility	0	(36,000,000)	(31,500,000)	(15,500,000)
Distributions	(6,000,000)	(36,000,000)	(12,000,000)	0
Debt issuance costs	(9,000)	(1,807,000)	(87,000)	(28,000)
Net cash used in Financing Activities	(6,009,000)	(57,807,000)	(42,587,000)	(5,528,000)
Net Increase (Decrease) in Cash	2,555,000	4,651,000	1,067,000	(27,000)
Cash—Beginning of year	2,801,000	5,356,000	1,734,000	1,761,000
Cash—End of year	5,356,000	10,007,000	2,801,000	1,734,000
Supplemental Disclosure of Cash Flow Information—Cash paid for interest	182,000	3,595,000	2,896,000	4,376,000
Supplemental Disclosure of Noncash Activity
Oil and gas properties included in accounts payable and accrued liabilities	14,352,000	21,266,000	15,174,000	15,690,000
Asset retirement obligations capitalized to oil and gas properties	0	347,000	192,000	338,000
Unit-based compensation liability transferred to redeemable management incentive units	$ 0	$ 481,000	$ 636,000	$ 655,000

Nature of Business

Nature of Business	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of BusinessVitesse Energy, LLC (the “Company”), a Delaware limited liability company, was formed on April 29, 2014 and is currently governed by the Second Amended and Restated Limited Liability Company Agreement of Vitesse Energy, LLC dated July 1, 2018, as amended by the First Amendment to the Second Amended and Restated Limited Liability Company Agreement of Vitesse Energy, LLC dated February 18, 2020. The membership interests in the Company are held approximately 97.5% by affiliates of Jefferies Financial Group (“JFG”) and approximately 2.5% by 3B Energy, LLC (“3B”), an entity whose members are comprised of certain executives of the Company. On January 13, 2023, JFG completed a spin-off transaction ("Spin-Off") in which the Company was contributed to Vitesse Energy, Inc. ("VTS"), and the securities of VTS held by JFG or its affiliates were distributed pro rata to the shareholders of JFG and VTS became an independent, publicly traded entity.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 acquiring nonoperated 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 nonoperated interests in oil and gas properties in the Central Rockies, including the Denver-Julesburg Basin and the Powder River Basin

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Significant Accounting Policies	Significant Accounting Policies Principles of Consolidation The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, Vitesse Management Company LLC (“Vitesse Management”) and Vitesse Oil, Inc. Intercompany balances and transactions have been eliminated in consolidation. Segment and Geographic Information The Company operates in a single reportable segment. The Company’s chief operating decision maker is the Chief Executive Officer. All of the Company’s operations are conducted in the continental United States. 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 crude oil and natural gas revenues and expenses, fair value of assets acquired and liabilities assumed in business combinations, valuation of unit-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. Change in Fiscal Year End On November 30, 2022, the Board of Managers approved a change in the Company's fiscal year end from November 30 to December 31. The Company's 2022 fiscal year began on January 1, 2022 and ended on December 31, 2022. As a result of this change, the Company has also presented financial statements as of and for the month ended December 31, 2021 ("Transition Period"). 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, 2022, December 31, 2021 and November 30, 2021 the Company held no 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, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, the Company recorded depletion expense of $63.3 million, $60.4 million, $58.0 million and $5.4 million, respectively. The Company’s depletion rate per BOE for the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021 was $16.71, $16.73, $16.40 and $16.97, 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 commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures, 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 were no proved oil and gas property impairments during the years ended December 31, 2022 and November 30, 2021 and the month ended December 31, 2021. Proved oil and gas property impairments during the year ended November 30, 2020 were $13.2 million and were related to the Company’s Wyoming properties. 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. Unit-based Compensation In 2020, the Company amended the Limited Liability Company Agreement (the “Company Agreement”) which modified certain terms and conditions related to management incentive units (“MIUs”) (see Note 13) and common units held by the founding members of management. The Company is accounting for MIUs granted to employees (which excludes the founding members of management) as liability instruments under accounting guidance related to share-based compensation, whereby vested awards are recognized as liabilities, with changes in the estimated value of the awards recorded in earnings, until the holders have borne the risk of unit ownership, at which point the liability associated with the employee MIUs is reclassified to temporary equity, and changes in the estimated value of the employee MIUs are recorded as an adjustment to members’ equity. Incentive compensation is also recognized for in-substance call options granted to the founding members of management which are classified as liabilities, recorded at estimated fair market value at each period end. Changes in the estimated fair value are recorded in earnings. As the Company is a private entity whose units are not traded, we consider the average volatility of comparable entities to develop an estimate of expected volatility for our awards of unit-based compensation which results in a reasonable estimate of fair value. Refer to Note 13 for further information regarding these awards. Revenue Recognition The Company’s revenue is derived from the sale of its produced oil and natural gas from wells in which the Company has nonoperated revenue or royalty interests. The Company’s oil and natural gas are produced and sold primarily in the core of the Williston Basin in North Dakota and Montana. The sales of produced oil and natural gas are made under contracts that the operators of the wells have negotiated with customers, which typically include variable consideration based on monthly pricing tied to local indices and volumes delivered. Revenue is recorded at the point in time when control of the produced oil and natural gas transfers to the customer. Statements and payment may not be received via the operator of the wells for one to three months after the date the produced oil and natural gas is delivered, and, as a result, the amount of production delivered to the customer and the price that will be received for the sale of the product is estimated utilizing production reports, market indices, and estimated differentials. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated, and revenue due to the Company is recorded within revenue receivable in the accompanying consolidated balance sheet until payment is received. Differences between the estimated amounts and the actual amounts received from the sale of the produced oil and natural gas are recorded when known, which is generally when statements and payment are received. Such differences have historically been immaterial. For the oil and natural gas produced 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, 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 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. Concentrations of Credit Risk For the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, four, three, two and three operators accounted for 54 percent , 37 percent, 30 percent and 42 percent of oil and natural gas revenue, respectively. As of December 31, 2022, December 31, 2021 and November 30, 2021, four, three and four operators accounted for 65 percent, 42 percent and 52 percent, respectively, of oil and natural gas revenue receivable. The Company’s oil and natural gas revenue receivable is generated from the sale of oil and natural gas by operators on its behalf. The Company monitors the financial condition of its operators. Income Taxes The Company is a limited liability company (“LLC”). Accordingly, no provision for income taxes has been recorded, as the income, deductions, expenses, and credits of the Company are reported on the income tax returns of the Company’s members. The Company accounts for uncertainty in income taxes in accordance with GAAP, which prescribe a comprehensive model for recognizing, measuring, presenting, and disclosing in the consolidated financial statements tax positions taken or expected to be taken in a tax return, including a decision on whether to file in a particular jurisdiction. Only tax positions that meet a more-likely- than-not recognition threshold at the effective date may be recognized or continue to be recognized. If taxing authorities were to disallow any tax positions taken by the Company, the additional income taxes, if any, would be imposed on the members rather than the Company, subject to IRS rules, which provide that adjustments resulting from IRS audit of the LLC will be assessed at the LLC level. Deferred Finance Charges Costs associated with the revolving credit facility are deferred and amortized to interest expense over the term of the related financing. The amount of deferred financing costs incurred, and the amortization of deferred financing costs, was immaterial for all periods presented. 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 (loss) gain, net on the consolidated statements of operations. GAAP requires recognition of all derivative instruments on 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. Gains and losses on derivative hedging instruments must be recorded in either other comprehensive income or current earnings, depending on the nature and designation of the instrument. The Company has elected to not designate any derivative instruments as accounting hedges, and therefore marks all commodity derivative instruments to fair value and records 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). New Accounting Pronouncements In August 2018, the FASB issued ASU No. 2018-13, Disclosure Framework—Changes to Disclosure Requirements for Fair Value Measurement. ASU No. 2018-13 modifies the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. The Company adopted ASU 2018-13 on December 1, 2021. The guidance did not have a significant impact on the consolidated financial statements or notes accompanying the consolidated financial statements. In June 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-13, Financial Instruments—Credit Losses: Measurement of Credit Losses on Financial Instruments. The ASU includes changes to the accounting and measurement of financial assets, including the Company’s accounts receivable, by requiring the Company to recognize an allowance for all expected credit related losses over the life of the financial asset at origination. This is different from the current practice, where an allowance is not recognized until the losses are considered probable. The new guidance will be effective for the Company’s year ending December 31, 2023. Upon adoption, the ASU will be applied using a modified retrospective transition method to the beginning of the earliest period in which the new guidance is effective. Early adoption is permitted. The Company does not believe the new guidance will have a material impact on its consolidated financial statements and related disclosures. Subsequent Events On January 13, 2023, JFG completed the legal and structural separation of the Company from JFG. To affect the separation, first, JFG and Jefferies Capital Partners ("JCP"), among others, undertook certain Pre-Spin-Off Transactions described below: ■ Certain members of management transferred all of their equity interest in the Company to JFG as repayment for prior loans; ■ JFG and other holders of the Company's equity interests transferred all of their interest in the Company to Vitesse in exchange for newly issued shares of VTS common stock; ■ Vitesse Oil, LLC ("VO") equity holders transferred their interests to VTS in exchange for newly issued shares of VTS common stock (the "VO Transaction"); ■ For accounting purposes, the VO Transaction will be accounted for as an asset acquisition by the Company as VO and the Company are not under common control; ■ Previous compensation agreements and compensation plans were eliminated and replaced with new compensation plans including the LTIP; ■ VTS entered into a Revolving Credit Facility, which amended and restated the Company's Credit Facility, and used the proceeds to repay in full and terminate the VO Revolving Credit Facility and repay the Company's Credit Facility. Borrowings under the Revolving Credit Facility were $53 million as of January 13, 2023.

Asset Acquisitions

Asset Acquisitions	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Asset Acquisitions	Asset AcquisitionsDuring the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, the Company purchased a number of proved oil and gas properties and proved leaseholds for an aggregate purchase price of $28.5 million, $6.2 million, $9.2 million, and $0.1 million, respectively. The 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, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021 were immaterial. The purpose of the acquisitions was to acquire proved developed and proved undeveloped oil and gas properties that were proximate and complementary to existing properties and leases for strategic purposes.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurements	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, 2022, the Company’s derivative financial instruments are composed of commodity swaps. The fair value of the swap agreements is determined under the income valuation technique using a discounted cash flow model. The fair values of options are determined under the income valuation technique using an option pricing model along with the stated amount of deferred premiums if applicable. 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). Nonrecurring Fair Value Measurements Nonrecurring measurements include the fair value of impaired proved oil and gas properties. The Company determines the estimated fair value of the impaired proved oil and gas properties by using a discounted cash flow approach with unobservable Level 3 inputs (see Note 2) at the time of impairment. Significant inputs utilized in determining the fair value of its Wyoming proved oil and gas properties of $26.9 million during the year ended November 30, 2020 included commodity futures prices adjusted for basis differentials, wellbore-only reserves, and a discount rate commensurate with the risk associated with realizing the projected cash flows of 10 percent. 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 (see Note 5) has a recorded value that approximates fair market value, as it bears interest at a floating rate that approximates a current market rate. The fair values of derivative instruments are estimated based on market conditions in effect at the end of each reporting period.

Credit Facility

Credit Facility	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Credit Facility	Credit Facility In May 2015, the Company entered into a credit facility (the “Credit Facility”) with a syndicate of banks (the “Lenders”) led by Wells Fargo Bank, N.A. (the “Administrative Agent”) with the Company as the borrower (the “Borrower”), which originally matured in May 2020. The Credit Facility has been subsequently amended, and the maturity date has been extended to April 2026. The most recent amendment was executed in April 2022 ("the April 2022 amendment"). The Credit Facility specifies an aggregate maximum credit amount equal to $500.0 million and a maximum borrowing base, as determined by the Lenders. The determination of the borrowing base takes into consideration the estimated value of the Company’s oil and gas properties in accordance with the Lenders’ customary practices for oil and gas loans. The borrowing base is subject to scheduled redeterminations on a semiannual basis. The amount available for borrowing could be increased or decreased as a result of such redeterminations. Under certain circumstances, the Borrower and the Lenders shall each have the option to request one unscheduled borrowing base redetermination per fiscal year. As of December 31, 2022 and 2021, the Company’s borrowing base was $200.0 million with an elected commitment of $170.0 million and $140.0 million, respectively, of which $48.0 million and $68.0 million, respectively, was outstanding. Prior to the April 2022 amendment, the Company had the option to request borrowings under either a eurodollar loan or an Alternative Base Rate loan. Eurodollar loans bear interest at the adjusted LIBOR plus an applicable margin ranging from 2.75 percent to 3.75 percent depending on the borrowing base utilization percentage. Alternative Base Rate loans bear interest at the higher of (a) the prime rate in effect on such day, (b) the federal funds effective rate in effect on such day plus 0.5 percent, or (c) the adjusted LIBOR for a one-month interest period on such day plus an applicable margin ranging from 1.75 percent to 2.75 percent depending on the borrowing base utilization percentage. With the April 2022 amendment, at the Company’s option, borrowings under the Credit Facility bear interest at either an adjusted forward-looking term rate based on the Secured Overnight Financing Rate (“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 SOFR rate plus 1.0%), plus a spread ranging from 1.75% to 2.75% with respect to Base Rate borrowings and 2.75% to 3.75% with respect to SOFR borrowings, in each case based on the borrowing base utilization percentage. Interest is calculated and paid monthly in arrears. Additionally, the Company incurs an unused credit facility fee of 0.50 percent regardless of the borrowing base utilization percentage. As of December 31, 2022, the interest rate on the outstanding balance under the Credit Facility was 7.42 percent. The Credit Facility includes customary terms and covenants that place limitations on certain types of activities, including the payment of dividends and distributions, and requires satisfaction of certain financial covenants, such as minimum leverage and current ratios. The Credit Facility also requires excess cash at any point in time over $10.0 million to be repaid to the Borrowers (under certain defined conditions), subject to the terms in the Credit Facility. The Company was in compliance with all financial covenants of the Credit Facility at December 31, 2022, December 31, 2021 and November 30, 2021. The Credit Facility is guaranteed by the Company’s subsidiaries and is collateralized with a minimum of 85 percent of the proved PV10 reserve value of the Company’s oil and gas properties. In addition, the Credit Facility places additional conditions on the ability of the founding members of management to put their common units back to the Company (see Note 13). These conditions include the establishment of maximum percentages of debt outstanding relative to the existing borrowing base and pro forma debt to earnings before interest, taxes, depletion, depreciation, amortization, and exploration expense (“EBITDAX”) ratios, as defined in the Credit Facility, at the date of the permitted exercise.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	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. The following table summarizes the location and fair value amounts of commodity derivative instruments in the consolidated balance sheet as of December 31, 2022, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet: (in thousands) GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES GROSS AMOUNTS OFFSET NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES Commodity derivative assets: Current derivative assets $ 2,856 $ (744) $ 2,112 Noncurrent derivative assets 1,721 (566) 1,155 Total $ 4,577 $ (1,310) $ 3,267 Commodity derivative liabilities: Current derivative liabilities $ 4,183 $ (744) $ 3,439 Noncurrent derivative liabilities 566 (566) — Total $ 4,749 $ (1,310) $ 3,439 The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of December 31, 2021, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet: (in thousands) GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES GROSS AMOUNTS OFFSET NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES Commodity derivative assets: Current derivative assets $ 224 $ (224) $ — Total $ 224 $ (224) $ — Commodity derivative liabilities: Current derivative liabilities $ 16,690 $ (224) $ 16,466 Total $ 16,690 $ (224) $ 16,466 The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of November 30, 2021, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet: (in thousands) GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES GROSS AMOUNTS OFFSET NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES Commodity derivative assets: Current derivative assets $ 1,513 $ — $ 1,513 Total $ 1,513 $ — $ 1,513 Commodity derivative liabilities: Current derivative liabilities $ 8,672 $ — $ 8,672 Total $ 8,672 $ — $ 8,672 As of December 31, 2022, the Company had the following crude oil swaps: CONTRACT TYPE TERM VOLUME HEDGED (Bbls) INDEX ROUNDED FIXED PRICE 1 Swap January 2023 - November 2023 165,000 WTI-NYMEX $ 88 2 Swap January 2023 - November 2023 165,000 WTI-NYMEX 86 3 Swap January 2023 - November 2023 330,000 WTI-NYMEX 78 4 Swap January 2023 - November 2023 330,000 WTI-NYMEX 70 5 Swap January 2023 - November 2023 110,000 WTI-NYMEX 82 6 Swap January 2023 - December 2023 180,000 WTI-NYMEX 75 7 Swap December 2023 - November 2024 360,000 WTI-NYMEX 72 8 Swap December 2023 - November 2024 180,000 WTI-NYMEX 79 9 Swap December 2023 - November 2024 180,000 WTI-NYMEX 81 Due to the volatility of oil prices, the estimated fair values of the Company’s commodity derivative instruments are subject to large fluctuations from period to period. The counterparties in the Company’s derivative instruments also participate in the Company’s Credit Facility; accordingly, the Company is not required to post collateral, as the counterparties have the right of offset for any derivative liabilities, and the Credit Facility is 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.

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2022
Payables and Accruals [Abstract]
Accrued Liabilities	Accrued Liabilities Accrued liabilities at December 31, 2022, December 31, 2021 and November 30, 2021 are summarized as follows: DECEMBER 31, NOVEMBER 30, (in thousands) 2022 2021 2021 Accrued capital expenditures $ 15,500 $ 8,000 $ 11,500 Accrued lease operating expenses, net 2,740 2,391 1,270 Accrued compensation 3,524 2,935 2,714 Accrued derivative settlement 189 1,685 2,450 Other accrued liabilities 1,068 599 683 Accrued spin related expenditures 2,828 — — Total $ 25,849 $ 15,610 $ 18,617

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations A rollforward of AROs for the years ended December 31, 2022 and November 30, 2021 and the month ended December 31, 2021 are presented below. DECEMBER 31, NOVEMBER 30, (In thousands) 2022 2021 2021 Balance—Beginning of period $ 6,156 $ 6,132 $ 5,666 Liabilities incurred 347 — 123 Accretion expense 320 24 274 Revisions — — 69 Balance—End of year $ 6,823 $ 6,156 $ 6,132

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions 3B acquired common units in the Company which were funded by two Initial Loans with related parties (see Note 13). As part of the funding of the Company, 3B entered into two different promissory notes with VE Holding LLC, an entity owned by JFG. The promissory notes allowed 3B to borrow up to $7.875 million and $3.5 million, initially accruing interest at 10.0 percent and 3.5 percent, respectively, and had maturity dates of May 7, 2021 (the “Initial Loans”). Initially, repayment of the $3.5 million promissory note was fully guaranteed by one of the members of 3B. Each of the two Initial Loans are collateralized by all of the common units held by 3B. In 2021 the $3.5 million promissory note was amended to remove the guarantee, change the interest rate to 10.0 percent and extend the maturity date to December 31, 2023. At the same time the $7.875 million promissory note was amended to extend the maturity date to December 31, 2023. The Initial Loans between 3B and VE Holding LLC are held outside of the Company and are not a liability of the Company. During 2022, there were $36.0 million of ratable distributions made to the common unit holders. The 3B distribution of $0.9 million was used to pay down a pro rata portion of the outstanding interest on the Initial Loans. In connection with the Company Agreement, in July 2018 certain executives entered into two separate promissory notes aggregating to $10.0 million with VE Holding LLC (the “2018 Notes”), which are collateralized by the MIUs granted to the respective executive. The 2018 Notes accrue interest at 3.0 percent per annum payable annually on December 31 and mature the earlier of July 1, 2024, an MIU exchange, or an acceleration event (as defined). The 2018 Notes may be prepaid at any time but are subject to mandatory prepayment upon the issuance of any distributions from the Company related to the MIUs held by such executives. Additionally, the 2018 Notes were considered full recourse to each respective executive for a limited time, with such recourse reduced by one-third each December 31 through 2020. As the 2018 Notes are between VE Holding LLC and the executives, they do not represent liabilities of the Company. The Company has entered into an amended and restated services agreement (the “Services Agreement”) by and between the Company, Vitesse Management, and Vitesse Oil, LLC (“Vitesse Oil”) on May 7, 2014. Vitesse Oil is an entity with management common to that of the Company. Per the Services Agreement, costs incurred by Vitesse Management was to be allocable between the Company and Vitesse Oil initially at 50 percent each and adjusted automatically each quarter, such that the Company’s share of allocable costs shall be the greater of 50 percent or the quotient of the total contributed capital to the Company made by its members and the sum of the total contributed capital to the Company and Vitesse Oil by their respective members. As such, the Company incurred 90 percent of the Vitesse Management costs for the years ended December 31, 2022, November 30, 2021, November 30, 2020 and the month ended December 31, 2021, respectively. The amount of costs reimbursed from Vitesse Oil to the Company for management services was $1.1 million, $1.1 million, $1.0 million, and $0.1 million for each of the years ended December 31, 2022, November 30, 2021, November 30, 2020 and the month ended December 31, 2021, respectively. The amount due to the Company from Vitesse Oil as of December 31, 2022, November 30, 2021, November 30, 2020 and the month ended December 31, 2021, respectively was immaterial. On July 1, 2016, the Company entered into a separate services agreement between 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, 2022, November 30, 2021, November 30, 2020 , respectively, the Company recorded its net share of fees from JETX of approximately $2.4 million and $0.2 million for the month ended December 31, 2021, which is classified as a reduction to general and administrative expenses on the accompanying consolidated statements of operations. On July 1, 2016, the Company implemented the Employee Participation Plan (“EPP”) pursuant to which employees, consultants, or independent contractors of the Company may be invited to personally acquire a working interest in new oil and gas wells in which the Company elects to participate. The EPP was subsequently amended on January 1, 2018. The tranches are not to exceed a maximum of $2.0 million of capital expenditures in the aggregate for each year. Participants in the EPP are required to fund their proportion of development costs and ongoing operating expenses of those specific wellbores. Compensation expense is measured by the allocable amount of the value of the assigned wellbore leasehold costs which has historically been immaterial. In 2018, the Company authorized a $2.0 million retention bonus, of which $1.5 million is paid by funding participants’ development and operating expenses under the EPP. Participants vest ratably in their interests in the underlying wells at December 31, 2018, 2019, and 2020 if still employed; thus, the Company recognized compensation expense of $0.4 million in 2020 as the interests of the remaining participants vested or were deemed to vest. On November 30, 2022, the Company repurchased the outstanding EPP working interest for $4.9 million in accordance with the terms of the plan and terminated the EPP.

Employee Agreements

Employee Agreements	12 Months Ended
	Dec. 31, 2022
Employment Agreements [Abstract]
Employee Agreements	Employment Agreements The Company has executed employment agreements with two executives. The term of each agreement is through December 31, 2023, with an automatic renewal clause on a year-to-year basis. Both executives and Vitesse Management had the right to terminate the agreement effective December 31, 2022 if notice was given prior to December 31, 2021. Such notice was not given. Under the employment agreements, the executives have rights to minimum salaries and certain compensation agreements upon termination of employment, including executive base salary, accrued vacation pay earned, and unreimbursed expenses incurred up to the date of termination. In addition, for fiscal 2019 and thereafter, the executives qualify for defined minimum annual bonuses. Under the terms of the employment agreements, the executives also are subject to noncompetition and nonsolicitation agreements. Also, as part of amendments to the respective employment agreements made in July 2018, the previously vested Founder MIUs (Note 13) were subjected to forfeiture if the executive were to terminate employment for any reason other than Good Reason (as defined). However, the forfeiture provision were reduced over time such that if the executive remained employed through December 31, 2020 the Founder MIUs are no longer subject to forfeiture.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	Leases The Company is obligated under noncancelable leases primarily for facilities and equipment. Total expense under these operating leases was $0.4 million, $0.4 million, $0.4 million and immaterial for the years ended December 31, 2022, November 30, 2021, November 30, 2020 and the month ended December 31, 2021, respectively. Leases with an initial term of 12 months or less are not recorded on 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 for the purpose of determining the present value of lease payments. The right-of-use assets of $0.2 million and $0.5 million as of December 31, 2022 and 2021, respectively, are recorded within Other noncurrent assets Other current liabilities Other noncurrent liabilities

Commitment and Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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.

Members' Equity and Unit-Based

Members' Equity and Unit-Based Compensation	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Members' Equity and Unit Based Compensation	Members’ Equity and Unit-Based Compensation The Company has two classes of membership units, with the following units authorized, issued, and outstanding as of December 31, 2022, December 31, 2021 and November 30, 2021: AUTHORIZED ISSUED AND OUTSTANDING Common units 450,000,000 450,000,000 Management incentive units 1,000,000 953,750 Common Units Common units issued to date have been issued at $1 per unit, with an aggregate capital commitment from all common members of $450 million. There initially shall be five managers on the board of managers, with three managers designated by JFG (such designated managers are each a “Jefferies Manager”) and two managers designated by 3B. For voting purposes, each manager is entitled to one vote, and the affirmative vote of a majority of the board of managers, including at least one Jefferies Manager, is required to ratify any significant decisions of the Company. Certain executives of the Company, as a result of their ownership of 3B, were granted the right to put all of their common units back to the Company in exchange for their pro rata share of the oil and gas interests then owned by the Company beginning in May 2017 (the “Common Unit Exchange Option”). In connection with the Company Agreement, the terms of the Common Unit Exchange Option were modified, where it may only be exercised on January 1, 2021 or on the annual anniversary thereafter and subject to additional conditions. Such conditions include, but are not limited to, that the Company is not in the process of an initial public offering; common unit holders have either received distributions resulting in, or the fair value of the Company’s net assets are such that the Company would achieve, a specified rate of return (“Flip Threshold”); and 3B reimburses the common unit holders for its pro rata share of liabilities in excess of cash balances at the time of exercise. Further, 3B must discharge any principal and interest outstanding related to the Initial Loans. As a result of the Common Unit Exchange Option resulting in the transfer of a portion of the oil and gas interests in proportion to 3B’s percentage holding of the common units, the Common Unit Exchange Option is considered to be a transaction that does not occur at fair market value. In addition to the Common Unit Exchange Option, in the event of termination of any or both of the executives that hold common units, the Company has the option to repurchase the common units held by 3B in exchange for cash (the “Common Unit Call Option”). The Common Unit Call Option would be executed at fair market value on the date of the transaction. As a result of 3B’s receipt of in-substance nonrecourse notes (the “Initial Loans”) that are each collateralized by all of the common units held by 3B, for accounting purposes the Company has granted 3B an in-substance call option that is within the scope of accounting guidance related to share-based compensation (the “Common Unit Option Grant”), which was fully vested on the date of grant in 2014. Due to the nature and terms of the Common Unit Exchange Option described above, the Common Unit Option Grant is classified as a liability award, remeasured at fair market value at each reporting date with the change in fair market value recorded to earnings. As of December 31, 2022, the aggregate intrinsic value of the Common Unit Option Grant was de minimis, as the optionality was forfeited due to these executives agreeing to settle their common units in exchange for JFG forgiving the Initial Loans and any accrued interest upon completion of the Spin-Off on January 13, 2023. Management Incentive Units Management incentive units may be issued by the Company to eligible employees and/or consultants. All MIUs are nonvoting and provide the MIU holders the opportunity to participate in distributions after the common unit holders have received a return equal to the Flip Threshold (as defined). In connection with the Company Agreement, the terms and conditions of the MIUs were modified from the Company’s original LLC agreement. Such modifications included, but were not limited to, a reset and change in the Flip Threshold, as well as changes to specific terms and conditions of MIU holder put rights and Company call rights. MIUs have been granted to the founding members of management (“Founder MIUs”) and certain other employees of the Company (“Non-Founder MIUs”). Holders of Non-Founder MIUs may put at least 25% percent of their vested MIUs to the Company for cash at estimated fair market value as of the date of the transaction, on or after January 1, 2022, subject to conditions that include, but are not limited to, continued employment and no pending initial public offering (the “Non-Founder MIU Put Option”). Holders of the Founder MIUs may put at least 10% percent of their vested MIUs to the Company on or after January 1, 2021 for either (1) cash at estimated fair market value as of the date of the transaction or (2) interests in the Company’s oil and gas properties with a fair market value equal to the fair market value of the MIU as of the date of the transaction, subject to conditions that include, but are not limited to, the Company is not in the process of an initial public offering; common unit holders have either received distributions resulting in, or the fair value of the Company’s net assets are such that the common unit holders would achieve the Flip Threshold, and the 2018 Notes have been repaid or are to be repaid out of proceeds from the exercise of the put option (the “Founder MIU Put Option”). In addition, the Company has the right to repurchase Founder MIUs and Non-Founder MIUs at fair market value upon the termination of employment for any reason (the “MIU Call Option”). With respect to the Flip Threshold, as of April 2018 management determined that the achievement of the Flip Threshold was probable. MIUs are subject to vesting requirements and forfeiture provisions specific to the Founder MIUs and Non-Founder MIUs, as outlined in the Company Agreement, employment agreement, grant letters, and other supporting MIU documentation. All unvested MIUs vest upon a final exit event (as defined), and are cancelled in the event of termination of the grantee. In the event of termination for Cause (as defined) all vested MIUs are forfeited for no consideration. The Company accounts for Non-Founder MIUs as liability-based awards until the respective holder has borne the risk of unit ownership, at which point the value of the liability is reclassified outside of permanent equity. While the awards are classified as liabilities, compensation expense is recorded through the vesting period, and changes in the estimated fair market value of the liability, are recorded in earnings. Once reclassified outside of permanent equity increases in the estimated fair market value of the award are recorded through members’ equity. During the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, the Company recorded an increase of $1.5 million, a reduction of $1.5 million, an increase of $1.0 million and an reduction of $1.0 million respectively, through members’ equity to adjust the Non-Founder MIUs to fair market value. A summary of the Company’s activity related to Non-Founder MIUs for the years ended the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, is presented below: FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, 2022 2021 2021 2020 Nonvested at period end 28,750 45,000 45,000 82,500 Granted during the period — — — 50,000 Vested during the period 16,250 — 37,500 50,000 Forfeited during the period — — — — Fair value of MIUs vested during the period $0.2 million $ — $ 0.7 million $ 0.7 million As of December 31, 2022, there was no unrecognized compensation cost related to nonvested unit-based compensation arrangements. As a result of each of the management founders’ receipt of an in-substance nonrecourse note (the “2018 Notes”) that are each collateralized by all of Founder MIUs held by the respective executive, for accounting purposes the Company has granted each of the management founders an in-substance call option that is within the scope of accounting guidance related to share-based compensation (the “Founder MIU Option Grant”). Due to the nature and terms of the Founder MIU Put Option described above, the Founder MIU Option Grant is classified as a liability award, remeasured at fair market value at each reporting date with the change in fair market value recorded to earnings. Total compensation cost (income) recognized in the consolidated statements of operations within Unit-based compensation for the years ended the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021 is as follows: FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, (in thousands) 2022 2021 2021 2020 Common Unit Option Grant $ (2,089) $ 383 $ (569) $ (1,308) Founder MIU Option Grant (8,680) 2,170 1,625 700 Non-Founder MIUs 3 75 353 64 Total $ (10,766) $ 2,628 $ 1,409 $ (544) As of December 31, 2022, the intrinsic value of the Founder MIU Option Grant and the Common Unit Option Grant, was determined to be de minimis given the limited amount of time until the instruments were settled and prevailing economic factors. The Option Grants were forfeited on January 13, 2023 with these executives agreeing to settle their common units and Founder MIUs in exchange of JFG forgiving the 2018 Notes and the Initial Notes and any accrued interest. The December 31, 2022 liability and the factors considered in valuing the liability at December 31, 2022 are excluded from the following tables due to the immaterial nature of these items. The liability recorded in the consolidated balance sheets within Unit-based compensation as of December 31, 2021and November 30, 2021 is as follows: DECEMBER 31, NOVEMBER 30, (in thousands) 2021 2021 Common Unit Option Grant $ 2,090 $ 1,706 Founder MIU Option Grant 8,679 6,510 Non-Founder MIUs 211 136 Total $ 10,980 $ 8,352 Measurement of unit-based compensation The Company records the Non-founder MIUs, Founder MIU Option Grant, and Common Unit Option Grant at fair value at the date of grant and at each balance sheet date, which results in compensation cost being measured at fair value. As noted above, vested Non-founder MIUs, where the respective holder has borne the risk of ownership, are recorded within temporary equity, with changes in fair value recorded within members’ equity. The fair value of each of the Founder MIU Option Grant and the Common Unit Option Grant (collectively “the Options”) are estimated using a Black Scholes Model that uses the assumptions noted in the following tables. As the Company doesn’t have publicly-traded equity we incorporated data from a group of publicly-traded peer companies when estimating fair value, and because when estimating fair value management incorporates ranges of assumptions for inputs, those ranges are disclosed. Expected volatilities are based on the historical volatility of our identified peer group of companies. The expected term of the Options is determined based on the Time to Exit/Liquidity Event. The risk-free rate for periods within the expected life of the option is interpolated from the US constant maturity treasury rate, for a term corresponding to the expected term. DECEMBER 31, NOVEMBER 30, Founder MIU Option Grant 2021 2021 2020 Expected volatility 105% - 140% 125% - 170% 130% - 145% Weighted-average volatility 140% 150% 137.5% Expected dividends/distributions 0% 0% 0% Expected term (in years) 0.5 1 2 Risk-free rate 0.69% 0.24% 0.16% DECEMBER 31, NOVEMBER 30, Common Unit Option Grant 2021 2021 2020 Expected volatility 55% 50% 60% - 65% Weighted-average volatility 50% 50% 62.5% Expected dividends/distributions 0% 0% 0% Expected term (in years) 0.5 1 2 Risk-free rate 0.69% 0.24% 0.16% Distributions Distributions of funds associated with common units follow a prescribed framework, which is outlined in detail in the Company Agreement. In general, distributions are first allocated to those unitholders based on their allocable share, as defined in the Company Agreement. Each unitholder will then receive a distribution in accordance with the tiered waterfall, as defined in the Company Agreement. The Company made $36.0 million, $12.0 million, $0.0 million and $6.0 million of distributions on common units during the years ended December 31, 2022, November 30, 2021, November 30, 2020 and the month ended December 31, 2021, respectively. Earnings Per Unit We have two classes of equity in the form of common units and MIUs that are vested and where the holder has borne the risks and rewards of ownership at which point the MIU is reclassified from liabilities to outside of permanent equity. Both common units and temporary equity classified MIUs are considered common units, and distributions are made in accordance with the Company Agreement. As such, we present earnings per unit (“EPU”) for both classes of equity. In calculating EPU we apply the two-class method. Under the two-class method net income (loss) attributable to common units is allocated to common units and other participating securities in proportion to the claim on earnings of each participating security after giving effect to distributions declared during the period, if any. The following table sets forth the computation of basic and diluted net income (loss) per unit: FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, 2022 2021 2021 2020 Common Units Net income (loss) 118,903 (7,359) 18,114 (8,857) less: income allocable to participating securities In-substance options on common units (Common Unit Option Grant) (3,006) — (458) — In-substance options on Founder MIUs (Founder MIU Option Grant) — — — — Non-Founder MIUs classified as temporary equity — — — — Non-Founder MIUs classified as liabilities — — — — Net income (loss) attributable to common unitholders 115,897 (7,359) 17,656 (8,857) Weighted Average Common Units Outstanding (in 000s) 450,000 450,000 450,000 450,000 less: Common Units accounted for as in-substance options (11,375) (11,375) (11,375) (11,375) Weighted Average Common Units Outstanding (in 000s) 438,625 438,625 438,625 438,625 Basic and Diluted EPU $ 0.26 $ (0.02) $ 0.04 $ (0.02) Temporary Equity Classified MIUs Income allocable to Non-Founder MIUs classified as temporary equity $ — $ — $ — $ — MIUs classified in temporary equity (in 000s) 250 234 234 196 Basic and Diluted EPU $ — $ — $ — $ —

Stockholder's Equity - Vitesse

Stockholder's Equity - Vitesse Energy, Inc	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Stockholder's Equity	Stockholder’s EquityAs of December 31, 2022, the Company had 1,000 issued and outstanding shares of common stock, which were held by Vitesse Energy Finance LLC, an affiliate of Jefferies.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 13, 2023, JFG completed the legal and structural separation of the Vitesse Energy from JFG. To affect the separation, first, JFG and Jefferies Capital Partners ("JCP"), among others, undertook certain Pre-Spin-Off Transactions described below: ■ Certain members of management of Vitesse Energy transferred all of their equity interest in Vitesse Energy to JFG as repayment for prior loans; ■ JFG and other holders of Vitesse Energy's equity interests transferred all of their interest in Vitesse Energy to the Company in exchange for newly issued shares of the Company's common stock; ■ Vitesse Oil, LLC ("VO") equity holders transferred their interests to the Company in exchange for newly issued shares of our common stock (the "VO Transaction"); ■ For accounting purposes the VO Transaction will be accounted for as an asset acquisition by the Company as VO and the Company are not under common control; ■ Previous compensation agreements and compensation plans were eliminated and replaced with new compensation plans including the LTIP; ■ The Company' entered into a Revolving Credit Facility, which amended and restated Vitesse Energy's Credit Facility, and used the proceeds to repay in full and terminate the VO Revolving Credit Facility and repay Vitesse Energy's Credit Facility. Borrowings under the Revolving Credit Facility were $53 million as of January 13, 2023. JFG then distributed all of our outstanding common stock held by JFG to JFG shareholders, and we became an independent, publicly traded company. Prior to completion of the Spin-Off, we entered into a Separation and Distribution Agreement and Tax Matters Agreement with JFG related to the Spin-Off.
Basis of Accounting	Basis of Presentation and Accounting The balance sheet is presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Separate statements of operations, comprehensive income, changes in stockholder’s equity, and cash flows have not been presented because there have been no operations since the Company was formed. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the balance sheet. Actual results could differ from those estimates.
Nature of Operations	Background and Nature of OperationsVitesse Energy, Inc. (the “Company” or "VTS") was incorporated as a corporation under the General Corporation Law of the State of Delaware on August 5, 2022. The Company was formed for the purpose of effecting a “spin-off” transaction by Jefferies Financial Group Inc. (“Jefferies" or "JFG”). Prior to the spin-off, the Company will acquire all of the issued and outstanding equity interests of Vitesse Energy, LLC (“Vitesse Energy”) and Vitesse Oil, LLC, which together represent substantially all of those businesses or investments of Jefferies that acquire, develop, manage and monetize non-operated oil and natural gas working, royalty and mineral interests in the United States. Immediately prior to the completion of the spin-off, the Company will succeed to the operations of its predecessor, Vitesse Energy, and will become an independent, publicly traded company.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
Supplemental Oil and Gas Information	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, 2022, December 31, 2021 and November 30, 2021 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. FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, (In thousands) 2022 2021 2021 2020 Costs Incurred for the Year: Proved Property Acquisition and Other $ 28,547 $ 117 $ 6,210 $ 9,234 Development 63,284 3,015 36,769 36,859 Total $ 91,831 $ 3,132 $ 42,979 $ 46,093 Oil and Natural Gas Reserve Data The following tables present the Company’s net proved crude oil and natural gas reserves as prepared by 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. NATURAL GAS (MMcf) OIL (MBbl) MBoe Proved Developed and Undeveloped Reserves at November 30, 2019 87,324 41,271 55,825 Revisions of Previous Estimates (5,723) (8,094) (9,048) Extensions, Discoveries and Other Additions 2,199 729 1,096 Acquisition of Reserves 6,638 1,799 2,905 Production (5,609) (2,599) (3,534) Proved Developed and Undeveloped Reserves at November 30, 2020 84,829 33,106 47,244 Revisions of Previous Estimates (4,181) (2,998) (3,695) Extensions, Discoveries and Other Additions 2,648 899 1,340 Acquisition of Reserves 1,793 959 1,258 Production (7,065) (2,436) (3,614) Proved Developed and Undeveloped Reserves at November 30, 2021 78,024 29,530 42,534 Revisions of Previous Estimates 231 80 119 Extensions, Discoveries and Other Additions — — — Acquisition of Reserves 8 7 8 Production (582) (220) (317) Proved Developed and Undeveloped Reserves at December 31, 2021 77,681 29,397 42,344 Revisions of Previous Estimates 1,959 (100) 226 Extensions, Discoveries and Other Additions 2,561 1,419 1,846 Acquisition of Reserves 5,187 2,304 3,168 Production (7,274) (2,575) (3,787) Proved Developed and Undeveloped Reserves at December 31, 2022 80,114 30,445 43,797 NATURAL GAS (MMcf) OIL (MBbl) MBoe Proved Developed Reserves: November 30, 2019 39,059 18,928 25,438 November 30, 2020 47,418 17,841 25,744 November 30, 2021 58,437 17,764 27,504 December 31, 2021 58,058 17,612 27,288 December 31, 2022 58,897 17,290 27,106 Proved Undeveloped Reserves: November 30, 2019 48,264 22,342 30,386 November 30, 2020 37,410 15,265 21,500 November 30, 2021 19,586 11,765 15,030 December 31, 2021 19,623 11,785 15,055 December 31, 2022 21,217 13,155 16,691 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, 2022 included the following: ■ Acquisitions . In 2022, total acquisitions of of 3.2 MMBoe were primarily attributable to asset acquisitions of oil and gas properties (see Note 3). ■ Revisions to previous estimates. In 2022, revisions to previous estimates increased proved reserves by a net amount of 0.2 MMBoe. Included in these revisions were 1.3 MMBoe of upward adjustments caused by higher crude oil and natural gas prices, 0.3 MMBoe of downward adjustments related to the removal of undeveloped drilling locations related to the SEC 5-year development rule, 0.3 MMBoe of downward adjustments related to changes in development plan, and 0.5 MMBoe of downward adjustments attributable to well performance when comparing the Company’s reserve estimates at December 31, 2022 to December 31, 2021. ■ Extensions and discoveries . In 2022, total extensions and discoveries of 1.8 MMBoe were attributable to additions of 1.6 MMBoe of proved developed reserves and 0.2 MMBoe of proved undeveloped reserves, respectively, in the Williston Basin. Notable changes in proved reserves for the month ended December 31, 2021 included the following: ■ Revisions to previous estimates . In the month ended December 31, 2021, revisions to previous estimates increased proved reserves by a net amount of 0.1 MMBoe that were primarily related to upward adjustments caused by higher crude oil and natural gas prices. Notable changes in proved reserves for the year ended November 30, 2021 included the following: ■ Revisions to previous estimates . In 2021, revisions to previous estimates increased proved developed and decreased proved undeveloped reserves by a net amount of 3.7 MMBoe. Included in these revisions were 4.3 MMBoe of upward adjustments caused by higher crude oil and natural gas prices and 6.9 MMBoe of downward adjustments related to the removal of undeveloped drilling locations due to a slower recovery of rig activity than expected in the Williston Basin, 0.5 MMBoe of downward adjustments related to the removal of drilled uncompleted wells in the Central Rockies related to the SEC 5-year development rule and 0.6 MMBoe of downward adjustments attributable to well performance when comparing the Company’s reserve estimates at November 30, 2021 to November 30, 2020. ■ Extensions and discoveries . In 2021, total extensions and discoveries of 1.3 MMBoe were attributable to additions of proved undeveloped locations in the Williston Basin. Notable changes in proved reserves for the year ended November 30, 2020 included the following: ■ Revisions to previous estimates . In 2020, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 9.0 MMBoe. Included in these revisions were 9.7 MMBoe of downward adjustments caused by lower crude oil and natural gas prices largely attributable to the impacts of the global coronavirus pandemic, a 1.2 MMBoe upward adjustment attributable to well performance when comparing the Company’s reserve estimates at November 30, 2020 to November 30, 2019 and 0.6 MMBoe of downward adjustments related to the removal of undeveloped drilling locations related to the SEC 5-year development rule. ■ Extensions and discoveries . In 2020, total extensions and discoveries of 1.0 MMBoe were attributable to additions of proved undeveloped locations 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. Income taxes for the Company are zero due to the Company’s tax status as a pass-through entity. 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. DECEMBER 31, NOVEMBER 30, (in thousands) 2022 2021 2021 2020 Future Cash Inflows $ 3,420,665 $ 2,206,162 $ 2,151,098 $ 1,405,418 Future Production Costs (965,151) (823,223) (816,329) (713,495) Future Development Costs (276,399) (244,913) (230,101) (245,128) Future Income Tax Expense — — — — Future Net Cash Inflows $ 2,179,115 $ 1,138,026 $ 1,104,668 $ 446,795 10% Annual Discount for Estimated Timing of Cash Flows $ (999,131) $ (509,625) $ (503,055) $ (255,617) Standardized Measure of Discounted Future Net Cash Flows $ 1,179,984 $ 628,401 $ 601,613 $ 191,178 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: NATURAL GAS OIL December 31, 2022 $ 6.36 $ 94.14 December 31, 2021 $ 3.60 $ 66.55 November 30, 2021 $ 3.46 $ 64.81 November 30, 2020 $ 1.94 $ 40.45 Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: DECEMBER 31, NOVEMBER 30, (in thousands) 2022 2021 2021 2020 Beginning of Period $ 628,401 $ 601,613 $ 191,178 $ 504,029 Sales of Oil and Natural Gas Produced, Net of Production Costs (226,666) (12,854) (126,733) (49,948) Extensions and Discoveries 41,373 — 17,911 2,332 Previously Estimated Development Cost Incurred During the Period 714 — 16,924 22,308 Net Change of Prices and Production Costs 575,120 32,271 415,685 (322,506) Change in Future Development Costs (3,758) (11,048) 22,606 79,816 Revisions of Quantity and Timing Estimates 18,140 2,153 (17,833) (115,228) Accretion of Discount 62,840 5,013 19,118 50,403 Change in Income Taxes — — — — Purchases of Minerals in Place 122,421 117 23,272 17,304 Other (38,601) 11,136 39,485 2,668 End of Period $ 1,179,984 $ 628,401 $ 601,613 $ 191,178

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Principles of Consolidation	Principles of ConsolidationThe accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, Vitesse Management Company LLC (“Vitesse Management”) and Vitesse Oil, Inc. Intercompany balances and transactions have been eliminated in consolidation
Segment and Geographic Information	Segment and Geographic Information The Company operates in a single reportable segment. The Company’s chief operating decision maker is the Chief Executive Officer. All of the Company’s operations are conducted in the continental United States.
Use of Estimates	Use of EstimatesThe preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the balance sheet. Actual results could differ from those estimates 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 crude oil and natural gas revenues and expenses, fair value of assets acquired and liabilities assumed in business combinations, valuation of unit-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.
Change in Fiscal Year End	Change in Fiscal Year End On November 30, 2022, the Board of Managers approved a change in the Company's fiscal year end from November 30 to December 31. The Company's 2022 fiscal year began on January 1, 2022 and ended on December 31, 2022. As a result of this change, the Company has also presented financial statements as of and for the month ended December 31, 2021 ("Transition Period").
Cash and Cash Equivalents	Cash and Cash EquivalentsThe 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.
Oil and Gas Properties	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, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, the Company recorded depletion expense of $63.3 million, $60.4 million, $58.0 million and $5.4 million, respectively. The Company’s depletion rate per BOE for the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021 was $16.71, $16.73, $16.40 and $16.97, 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.
Asset Retirement Obligations (AROs)	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
Unit-based Compensation	Unit-based Compensation In 2020, the Company amended the Limited Liability Company Agreement (the “Company Agreement”) which modified certain terms and conditions related to management incentive units (“MIUs”) (see Note 13) and common units held by the founding members of management. The Company is accounting for MIUs granted to employees (which excludes the founding members of management) as liability instruments under accounting guidance related to share-based compensation, whereby vested awards are recognized as liabilities, with changes in the estimated value of the awards recorded in earnings, until the holders have borne the risk of unit ownership, at which point the liability associated with the employee MIUs is reclassified to temporary equity, and changes in the estimated value of the employee MIUs are recorded as an adjustment to members’ equity. Incentive compensation is also recognized for in-substance call options granted to the founding members of management which are classified as liabilities, recorded at estimated fair market value at each period end. Changes in the estimated fair value are recorded in earnings. As the Company is a private entity whose units are not traded, we consider the average volatility of comparable entities to develop an estimate of expected volatility for our awards of unit-based compensation which results in a reasonable estimate of fair value. Refer to Note 13 for further information regarding these awards.
Revenue Recognition	Revenue Recognition The Company’s revenue is derived from the sale of its produced oil and natural gas from wells in which the Company has nonoperated revenue or royalty interests. The Company’s oil and natural gas are produced and sold primarily in the core of the Williston Basin in North Dakota and Montana. The sales of produced oil and natural gas are made under contracts that the operators of the wells have negotiated with customers, which typically include variable consideration based on monthly pricing tied to local indices and volumes delivered. Revenue is recorded at the point in time when control of the produced oil and natural gas transfers to the customer. Statements and payment may not be received via the operator of the wells for one to three months after the date the produced oil and natural gas is delivered, and, as a result, the amount of production delivered to the customer and the price that will be received for the sale of the product is estimated utilizing production reports, market indices, and estimated differentials. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated, and revenue due to the Company is recorded within revenue receivable in the accompanying consolidated balance sheet until payment is received. Differences between the estimated amounts and the actual amounts received from the sale of the produced oil and natural gas are recorded when known, which is generally when statements and payment are received. Such differences have historically been immaterial. For the oil and natural gas produced 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, 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 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.
Concentrations of Credit Risk	Concentrations of Credit Risk For the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, four, three, two and three operators accounted for 54 percent , 37 percent, 30 percent and 42 percent of oil and natural gas revenue, respectively. As of December 31, 2022, December 31, 2021 and November 30, 2021, four, three and four operators accounted for 65 percent, 42 percent and 52 percent, respectively, of oil and natural gas revenue receivable. The Company’s oil and natural gas revenue receivable is generated from the sale of oil and natural gas by operators on its behalf. The Company monitors the financial condition of its operators.
Income Taxes	Income Taxes The Company is a limited liability company (“LLC”). Accordingly, no provision for income taxes has been recorded, as the income, deductions, expenses, and credits of the Company are reported on the income tax returns of the Company’s members. The Company accounts for uncertainty in income taxes in accordance with GAAP, which prescribe a comprehensive model for recognizing, measuring, presenting, and disclosing in the consolidated financial statements tax positions taken or expected to be taken in a tax return, including a decision on whether to file in a particular jurisdiction. Only tax positions that meet a more-likely- than-not recognition threshold at the effective date may be recognized or continue to be recognized. If taxing authorities were to disallow any tax positions taken by the Company, the additional income taxes, if any, would be imposed on the members rather than the Company, subject to IRS rules, which provide that adjustments resulting from IRS audit of the LLC will be assessed at the LLC level.
Deferred Finance Charges	Deferred Finance Charges Costs associated with the revolving credit facility are deferred and amortized to interest expense over the term of the related financing. The amount of deferred financing costs incurred, and the amortization of deferred financing costs, was immaterial for all periods presented.
Derivative Financial Instruments	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 (loss) gain, net on the consolidated statements of operations.
New Accounting Pronouncements	New Accounting Pronouncements In August 2018, the FASB issued ASU No. 2018-13, Disclosure Framework—Changes to Disclosure Requirements for Fair Value Measurement. ASU No. 2018-13 modifies the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. The Company adopted ASU 2018-13 on December 1, 2021. The guidance did not have a significant impact on the consolidated financial statements or notes accompanying the consolidated financial statements. In June 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-13, Financial Instruments—Credit Losses: Measurement of Credit Losses on Financial Instruments. The ASU includes changes to the accounting and measurement of financial assets, including the Company’s accounts receivable, by requiring the Company to recognize an allowance for all expected credit related losses over the life of the financial asset at origination. This is different from the current practice, where an allowance is not recognized until the losses are considered probable. The new guidance will be effective for the Company’s year ending December 31, 2023. Upon adoption, the ASU will be applied using a modified retrospective transition method to the beginning of the earliest period in which the new guidance is effective. Early adoption is permitted. The Company does not believe the new guidance will have a material impact on its consolidated financial statements and related disclosures.
Subsequent Events	Subsequent Events On January 13, 2023, JFG completed the legal and structural separation of the Company from JFG. To affect the separation, first, JFG and Jefferies Capital Partners ("JCP"), among others, undertook certain Pre-Spin-Off Transactions described below: ■ Certain members of management transferred all of their equity interest in the Company to JFG as repayment for prior loans; ■ JFG and other holders of the Company's equity interests transferred all of their interest in the Company to Vitesse in exchange for newly issued shares of VTS common stock; ■ Vitesse Oil, LLC ("VO") equity holders transferred their interests to VTS in exchange for newly issued shares of VTS common stock (the "VO Transaction"); ■ For accounting purposes, the VO Transaction will be accounted for as an asset acquisition by the Company as VO and the Company are not under common control; ■ Previous compensation agreements and compensation plans were eliminated and replaced with new compensation plans including the LTIP; ■ VTS entered into a Revolving Credit Facility, which amended and restated the Company's Credit Facility, and used the proceeds to repay in full and terminate the VO Revolving Credit Facility and repay the Company's Credit Facility. Borrowings under the Revolving Credit Facility were $53 million as of January 13, 2023.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table summarizes the location and fair value amounts of commodity derivative instruments in the consolidated balance sheet as of December 31, 2022, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet: (in thousands) GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES GROSS AMOUNTS OFFSET NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES Commodity derivative assets: Current derivative assets $ 2,856 $ (744) $ 2,112 Noncurrent derivative assets 1,721 (566) 1,155 Total $ 4,577 $ (1,310) $ 3,267 Commodity derivative liabilities: Current derivative liabilities $ 4,183 $ (744) $ 3,439 Noncurrent derivative liabilities 566 (566) — Total $ 4,749 $ (1,310) $ 3,439 The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of December 31, 2021, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet: (in thousands) GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES GROSS AMOUNTS OFFSET NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES Commodity derivative assets: Current derivative assets $ 224 $ (224) $ — Total $ 224 $ (224) $ — Commodity derivative liabilities: Current derivative liabilities $ 16,690 $ (224) $ 16,466 Total $ 16,690 $ (224) $ 16,466 The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of November 30, 2021, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet: (in thousands) GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES GROSS AMOUNTS OFFSET NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES Commodity derivative assets: Current derivative assets $ 1,513 $ — $ 1,513 Total $ 1,513 $ — $ 1,513 Commodity derivative liabilities: Current derivative liabilities $ 8,672 $ — $ 8,672 Total $ 8,672 $ — $ 8,672
Crude Oil Swaps	As of December 31, 2022, the Company had the following crude oil swaps: CONTRACT TYPE TERM VOLUME HEDGED (Bbls) INDEX ROUNDED FIXED PRICE 1 Swap January 2023 - November 2023 165,000 WTI-NYMEX $ 88 2 Swap January 2023 - November 2023 165,000 WTI-NYMEX 86 3 Swap January 2023 - November 2023 330,000 WTI-NYMEX 78 4 Swap January 2023 - November 2023 330,000 WTI-NYMEX 70 5 Swap January 2023 - November 2023 110,000 WTI-NYMEX 82 6 Swap January 2023 - December 2023 180,000 WTI-NYMEX 75 7 Swap December 2023 - November 2024 360,000 WTI-NYMEX 72 8 Swap December 2023 - November 2024 180,000 WTI-NYMEX 79 9 Swap December 2023 - November 2024 180,000 WTI-NYMEX 81

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	Accrued liabilities at December 31, 2022, December 31, 2021 and November 30, 2021 are summarized as follows: DECEMBER 31, NOVEMBER 30, (in thousands) 2022 2021 2021 Accrued capital expenditures $ 15,500 $ 8,000 $ 11,500 Accrued lease operating expenses, net 2,740 2,391 1,270 Accrued compensation 3,524 2,935 2,714 Accrued derivative settlement 189 1,685 2,450 Other accrued liabilities 1,068 599 683 Accrued spin related expenditures 2,828 — — Total $ 25,849 $ 15,610 $ 18,617

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	A rollforward of AROs for the years ended December 31, 2022 and November 30, 2021 and the month ended December 31, 2021 are presented below. DECEMBER 31, NOVEMBER 30, (In thousands) 2022 2021 2021 Balance—Beginning of period $ 6,156 $ 6,132 $ 5,666 Liabilities incurred 347 — 123 Accretion expense 320 24 274 Revisions — — 69 Balance—End of year $ 6,823 $ 6,156 $ 6,132

Members' Equity and Unit-Base_2

Members' Equity and Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Schedule of Classes of Membership Units	The Company has two classes of membership units, with the following units authorized, issued, and outstanding as of December 31, 2022, December 31, 2021 and November 30, 2021: AUTHORIZED ISSUED AND OUTSTANDING Common units 450,000,000 450,000,000 Management incentive units 1,000,000 953,750
Share-Based Payment Arrangement, Outstanding Award, Activity, Excluding Option	A summary of the Company’s activity related to Non-Founder MIUs for the years ended the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021, is presented below: FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, 2022 2021 2021 2020 Nonvested at period end 28,750 45,000 45,000 82,500 Granted during the period — — — 50,000 Vested during the period 16,250 — 37,500 50,000 Forfeited during the period — — — — Fair value of MIUs vested during the period $0.2 million $ — $ 0.7 million $ 0.7 million
Schedule of Basic and Diluted Net Income (Loss)	The following table sets forth the computation of basic and diluted net income (loss) per unit: FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, 2022 2021 2021 2020 Common Units Net income (loss) 118,903 (7,359) 18,114 (8,857) less: income allocable to participating securities In-substance options on common units (Common Unit Option Grant) (3,006) — (458) — In-substance options on Founder MIUs (Founder MIU Option Grant) — — — — Non-Founder MIUs classified as temporary equity — — — — Non-Founder MIUs classified as liabilities — — — — Net income (loss) attributable to common unitholders 115,897 (7,359) 17,656 (8,857) Weighted Average Common Units Outstanding (in 000s) 450,000 450,000 450,000 450,000 less: Common Units accounted for as in-substance options (11,375) (11,375) (11,375) (11,375) Weighted Average Common Units Outstanding (in 000s) 438,625 438,625 438,625 438,625 Basic and Diluted EPU $ 0.26 $ (0.02) $ 0.04 $ (0.02) Temporary Equity Classified MIUs Income allocable to Non-Founder MIUs classified as temporary equity $ — $ — $ — $ — MIUs classified in temporary equity (in 000s) 250 234 234 196 Basic and Diluted EPU $ — $ — $ — $ —
Disclosure of Share-Based Compensation Arrangements by Share-Based Payment Award	Total compensation cost (income) recognized in the consolidated statements of operations within Unit-based compensation for the years ended the years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the month ended December 31, 2021 is as follows: FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, (in thousands) 2022 2021 2021 2020 Common Unit Option Grant $ (2,089) $ 383 $ (569) $ (1,308) Founder MIU Option Grant (8,680) 2,170 1,625 700 Non-Founder MIUs 3 75 353 64 Total $ (10,766) $ 2,628 $ 1,409 $ (544) DECEMBER 31, NOVEMBER 30, (in thousands) 2021 2021 Common Unit Option Grant $ 2,090 $ 1,706 Founder MIU Option Grant 8,679 6,510 Non-Founder MIUs 211 136 Total $ 10,980 $ 8,352
Schedule of Share-Based Payment Award, Stock Options, Valuation Assumptions	DECEMBER 31, NOVEMBER 30, Founder MIU Option Grant 2021 2021 2020 Expected volatility 105% - 140% 125% - 170% 130% - 145% Weighted-average volatility 140% 150% 137.5% Expected dividends/distributions 0% 0% 0% Expected term (in years) 0.5 1 2 Risk-free rate 0.69% 0.24% 0.16% DECEMBER 31, NOVEMBER 30, Common Unit Option Grant 2021 2021 2020 Expected volatility 55% 50% 60% - 65% Weighted-average volatility 50% 50% 62.5% Expected dividends/distributions 0% 0% 0% Expected term (in years) 0.5 1 2 Risk-free rate 0.69% 0.24% 0.16%

Supplemental Oil and Gas Info_2

Supplemental Oil and Gas Information (Tables)	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. FOR THE YEAR ENDED DECEMBER 31, FOR THE MONTH ENDED DECEMBER 31, FOR THE YEARS ENDED NOVEMBER 30, (In thousands) 2022 2021 2021 2020 Costs Incurred for the Year: Proved Property Acquisition and Other $ 28,547 $ 117 $ 6,210 $ 9,234 Development 63,284 3,015 36,769 36,859 Total $ 91,831 $ 3,132 $ 42,979 $ 46,093
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The following tables present the Company’s net proved crude oil and natural gas reserves as prepared by 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. NATURAL GAS (MMcf) OIL (MBbl) MBoe Proved Developed and Undeveloped Reserves at November 30, 2019 87,324 41,271 55,825 Revisions of Previous Estimates (5,723) (8,094) (9,048) Extensions, Discoveries and Other Additions 2,199 729 1,096 Acquisition of Reserves 6,638 1,799 2,905 Production (5,609) (2,599) (3,534) Proved Developed and Undeveloped Reserves at November 30, 2020 84,829 33,106 47,244 Revisions of Previous Estimates (4,181) (2,998) (3,695) Extensions, Discoveries and Other Additions 2,648 899 1,340 Acquisition of Reserves 1,793 959 1,258 Production (7,065) (2,436) (3,614) Proved Developed and Undeveloped Reserves at November 30, 2021 78,024 29,530 42,534 Revisions of Previous Estimates 231 80 119 Extensions, Discoveries and Other Additions — — — Acquisition of Reserves 8 7 8 Production (582) (220) (317) Proved Developed and Undeveloped Reserves at December 31, 2021 77,681 29,397 42,344 Revisions of Previous Estimates 1,959 (100) 226 Extensions, Discoveries and Other Additions 2,561 1,419 1,846 Acquisition of Reserves 5,187 2,304 3,168 Production (7,274) (2,575) (3,787) Proved Developed and Undeveloped Reserves at December 31, 2022 80,114 30,445 43,797 NATURAL GAS (MMcf) OIL (MBbl) MBoe Proved Developed Reserves: November 30, 2019 39,059 18,928 25,438 November 30, 2020 47,418 17,841 25,744 November 30, 2021 58,437 17,764 27,504 December 31, 2021 58,058 17,612 27,288 December 31, 2022 58,897 17,290 27,106 Proved Undeveloped Reserves: November 30, 2019 48,264 22,342 30,386 November 30, 2020 37,410 15,265 21,500 November 30, 2021 19,586 11,765 15,030 December 31, 2021 19,623 11,785 15,055 December 31, 2022 21,217 13,155 16,691
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	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. Income taxes for the Company are zero due to the Company’s tax status as a pass-through entity. 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. DECEMBER 31, NOVEMBER 30, (in thousands) 2022 2021 2021 2020 Future Cash Inflows $ 3,420,665 $ 2,206,162 $ 2,151,098 $ 1,405,418 Future Production Costs (965,151) (823,223) (816,329) (713,495) Future Development Costs (276,399) (244,913) (230,101) (245,128) Future Income Tax Expense — — — — Future Net Cash Inflows $ 2,179,115 $ 1,138,026 $ 1,104,668 $ 446,795 10% Annual Discount for Estimated Timing of Cash Flows $ (999,131) $ (509,625) $ (503,055) $ (255,617) Standardized Measure of Discounted Future Net Cash Flows $ 1,179,984 $ 628,401 $ 601,613 $ 191,178
Proved Developed and Undeveloped Price for Reserve Estimates	The prices for the Company’s reserve estimates were as follows: NATURAL GAS OIL December 31, 2022 $ 6.36 $ 94.14 December 31, 2021 $ 3.60 $ 66.55 November 30, 2021 $ 3.46 $ 64.81 November 30, 2020 $ 1.94 $ 40.45
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: DECEMBER 31, NOVEMBER 30, (in thousands) 2022 2021 2021 2020 Beginning of Period $ 628,401 $ 601,613 $ 191,178 $ 504,029 Sales of Oil and Natural Gas Produced, Net of Production Costs (226,666) (12,854) (126,733) (49,948) Extensions and Discoveries 41,373 — 17,911 2,332 Previously Estimated Development Cost Incurred During the Period 714 — 16,924 22,308 Net Change of Prices and Production Costs 575,120 32,271 415,685 (322,506) Change in Future Development Costs (3,758) (11,048) 22,606 79,816 Revisions of Quantity and Timing Estimates 18,140 2,153 (17,833) (115,228) Accretion of Discount 62,840 5,013 19,118 50,403 Change in Income Taxes — — — — Purchases of Minerals in Place 122,421 117 23,272 17,304 Other (38,601) 11,136 39,485 2,668 End of Period $ 1,179,984 $ 628,401 $ 601,613 $ 191,178

Nature of Business (Details)

Nature of Business (Details) - Vitesse Energy, LLC	Feb. 18, 2020
Jefferies Financial Group
Entity Information [Line Items]
Membership interest (as a percent)	97.50%
3B Energy, LLC
Entity Information [Line Items]
Membership interest (as a percent)	2.50%

Significant Accounting Polici_3

Significant Accounting Policies - Cash and Cash Equivalents (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021
Accounting Policies [Abstract]
Cash equivalents	$ 0	$ 0	$ 0

Significant Accounting Polici_4

Significant Accounting Policies - Oil and Gas Properties (Details)	1 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($) $ / bbl	Dec. 31, 2022 USD ($) $ / bbl	Nov. 30, 2021 USD ($) $ / bbl	Nov. 30, 2020 USD ($) $ / bbl
Accounting Policies [Abstract]
Depletion expense	$ 5,400,000	$ 63,300,000	$ 60,400,000	$ 58,000,000
Depletion rate (in dollars per barrels of oil equivalent) | $ / bbl	16.97	16.71	16.73	16.40
Impairment of proved oil and gas properties	$ 0	$ 0	$ 0	$ 13,200,000

Significant Accounting Polici_5

Significant Accounting Policies - Concentrations of Credit Risk (Details) - Operator Concentration Risk				1 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Revenue | Three Operators
Concentration Risk [Line Items]
Concentration risk (as a percent)				42%		37%
Revenue | Two Operators
Concentration Risk [Line Items]
Concentration risk (as a percent)							30%
Revenue | Four Operators
Concentration Risk [Line Items]
Concentration risk (as a percent)					54%
Accounts Receivable | Three Operators
Concentration Risk [Line Items]
Concentration risk (as a percent)		42%
Accounts Receivable | Four Operators
Concentration Risk [Line Items]
Concentration risk (as a percent)	65%		52%

Significant Accounting Polici_6

Significant Accounting Policies - Subsequent Events (Details) - Revolving Credit Facility - Credit Facility - Line of Credit - USD ($) $ in Millions	Feb. 13, 2023	Dec. 31, 2022	Dec. 31, 2021
Subsequent Event [Line Items]
Revolving credit facility		$ 48	$ 68
Subsequent Event
Subsequent Event [Line Items]
Revolving credit facility	$ 53

Asset Acquisitions (Details)

Asset Acquisitions (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Business Combination and Asset Acquisition [Abstract]
Payments to acquire oil and gas properties	$ 117	$ 28,547	$ 6,210	$ 9,234

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Nonrecurring - Fair Value, Inputs, Level 3 - Impaired Proved Oil and Gas Property $ in Millions	Nov. 30, 2020 USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Fair value of proved oil and gas properties	$ 26.9
Measurement Input, Discount Rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Projected cash flow percentage	0.10

Credit Facility (Details)

Credit Facility (Details) - Credit Facility - Line of Credit - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Apr. 30, 2022	May 31, 2015	Dec. 31, 2022	Dec. 31, 2021
Revolving Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity		$ 500
Current borrowing capacity			$ 200
Elected commitment			170	$ 140
Revolving credit facility			$ 48	$ 68
Commitment fee percentage (as a percent)		0.50%
Interest rate at the end of the period (as a percent)			7.42%
Excess cash requiring repayment, threshold amount		$ 10
Minimum percentage of proved PV10 reserve value			85%
Revolving Credit Facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)	0.50%
Revolving Credit Facility | Secured Overnight Financing Rate (SOFR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)	1%
Revolving Credit Facility | Minimum | Adjusted Base Rate
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)	1.75%
Revolving Credit Facility | Minimum | Secured Overnight Financing Rate (SOFR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)	2.75%
Revolving Credit Facility | Maximum | Adjusted Base Rate
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)	2.75%
Revolving Credit Facility | Maximum | Secured Overnight Financing Rate (SOFR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)	3.75%
Eurodollar Loan | Minimum | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)		2.75%
Eurodollar Loan | Maximum | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)		3.75%
Alternative Base Rate Loan | Federal Funds Rate
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)		0.50%
Alternative Base Rate Loan | Minimum | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)		1.75%
Alternative Base Rate Loan | Maximum | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Spread on margin rate (as a percent)		2.75%

Derivative Instruments - Fair V

Derivative Instruments - Fair Value (Details) - Commodity Contract - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021
Commodity derivative assets:
GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	$ 4,577	$ 224	$ 1,513
GROSS AMOUNTS OFFSET	(1,310)	(224)	0
NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	3,267	0	1,513
Commodity derivative liabilities:
GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	4,749	16,690	8,672
GROSS AMOUNTS OFFSET	(1,310)	(224)	0
NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	3,439	$ 16,466	$ 8,672
Current derivative assets
Commodity derivative assets:
GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	2,856
GROSS AMOUNTS OFFSET	(744)
NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	2,112
Noncurrent derivative assets
Commodity derivative assets:
GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	1,721
GROSS AMOUNTS OFFSET	(566)
NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	1,155
Current derivative liabilities
Commodity derivative liabilities:
GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	4,183
GROSS AMOUNTS OFFSET	(744)
NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	3,439
Noncurrent derivative liabilities
Commodity derivative liabilities:
GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	566
GROSS AMOUNTS OFFSET	(566)
NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES	$ 0

Derivative Instruments - Swaps

Derivative Instruments - Swaps (Details) - Designated as Hedging Instrument bbl in Thousands	12 Months Ended
	Dec. 31, 2022 $ / bbl bbl
Crude Oil Swap January 2023 to November 2023, 1
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	165
Rounded swap fixed rate | $ / bbl	88
Crude Oil Swap January 2023 to November 2023, 2
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	165
Rounded swap fixed rate | $ / bbl	86
Crude Oil Swap January 2023 to November 2023, 3
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	330
Rounded swap fixed rate | $ / bbl	78
Crude Oil Swap January 2023 to November 2023, 4
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	330
Rounded swap fixed rate | $ / bbl	70
Crude Oil Swap January 2023 to November 2023, 5
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	110
Rounded swap fixed rate | $ / bbl	82
Crude Oil Swap January 2023 to December 2023, 1
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	180
Rounded swap fixed rate | $ / bbl	75
Crude Oil Swap December 2023 to November 2024, 1
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	360
Rounded swap fixed rate | $ / bbl	72
Crude Oil Swap December 2023 to November 2024, 2
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	180
Rounded swap fixed rate | $ / bbl	79
Crude Oil Swap December 2023 to November 2024, 3
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount, volume | bbl	180
Rounded swap fixed rate | $ / bbl	81

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021
Payables and Accruals [Abstract]
Accrued capital expenditures	$ 15,500	$ 8,000	$ 11,500
Accrued lease operating expenses, net	2,740	2,391	1,270
Accrued compensation	3,524	2,935	2,714
Accrued derivative settlement	189	1,685	2,450
Other accrued liabilities	1,068	599	683
Accrued spin related expenditures	2,828	0	0
Total	$ 25,849	$ 15,610	$ 18,617

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance—Beginning of period	$ 6,132	$ 6,156	$ 5,666
Liabilities incurred	0	347	123
Accretion expense	24	320	274
Revisions	0	0	69
Balance—End of year	$ 6,156	$ 6,823	$ 6,132

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands

1 Months Ended

12 Months Ended

Nov. 30, 2022

Jan. 01, 2018

Jul. 01, 2016

May 07, 2014

Dec. 31, 2021

May 31, 2017

Dec. 31, 2022

Dec. 31, 2021

Nov. 30, 2021

Nov. 30, 2020

Dec. 31, 2018

Nov. 30, 2018

Jul. 31, 2018

Related Party Transaction [Line Items]

Payments of distributions

$ 6,000

$ 36,000

$ 12,000

$ 0

Affiliated Entity

Related Party Transaction [Line Items]

Monthly service provider fee

$ 200

Retention bonus

$ 2,000

Purchases from related party

$ 1,500

Affiliated Entity | Services Agreement

Related Party Transaction [Line Items]

Related party, services agreement, allocation of costs percent

50%

90%

90%

90%

90%

Revenue from related parties

$ 100

$ 1,100

$ 1,100

$ 1,000

Affiliated Entity | Fees from JETX

Related Party Transaction [Line Items]

Related party transaction, expenses from transactions with related party

200

2,400

$ 2,400

2,400

Affiliated Entity | Capital Expenditure

Related Party Transaction [Line Items]

Related party transaction, expenses from transactions with related party

$ 2,000

Affiliated Entity | Compensation Expense

Related Party Transaction [Line Items]

Related party transaction, expenses from transactions with related party

$ 400

Affiliated Entity | Employee Participation Plan

Related Party Transaction [Line Items]

Related party transaction, expenses from transactions with related party

$ 4,900

3B Energy, LLC

Related Party Transaction [Line Items]

Payments of distributions

$ 900

VE Holding LLC | 2018 Notes | Affiliated Entity

Related Party Transaction [Line Items]

Notes payable, related party

$ 10,000

Related party transaction, rate

3%

3B Energy, LLC | VE Holdings LLC | Initial Loans, Promissory Note 1 | Affiliated Entity

Related Party Transaction [Line Items]

Notes payable, related party

7,875

$ 7,875

$ 7,875

Related party transaction, rate

10%

3B Energy, LLC | VE Holdings LLC | Initial Loans, Promissory Note 2 | Affiliated Entity

Related Party Transaction [Line Items]

Notes payable, related party

$ 3,500

$ 3,500

$ 3,500

Related party transaction, rate

3.50%

10%

Vitesse Oil | Affiliated Entity | Services Agreement

Related Party Transaction [Line Items]

Related party, services agreement, allocation of costs percent

50%

Leases (Details)

Leases (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Leases [Abstract]
Operating lease expense	$ 0	$ 0.4	$ 0.4	$ 0.4
Right-of-use assets	0.5	0.2
Lease obligations	$ 0.5	$ 0.2
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other noncurrent liabilities	Other noncurrent liabilities

Members' Equity and Unit-Base_3

Members' Equity and Unit-Based Compensation - Units Authorized, Issued, and Outstanding (Details) - shares	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021
Share-Based Payment Arrangement [Abstract]
Common units, authorized (in units)	450,000,000	450,000,000	450,000,000
Common units, issued (in units)	450,000,000	450,000,000	450,000,000
Common units, outstanding (in units)	450,000,000	450,000,000	450,000,000
Management incentive units, authorized (in shares)	1,000,000	1,000,000	1,000,000
Management incentive units, issued (in shares)	953,750	953,750	953,750
Management incentive units, outstanding (in shares)	953,750	953,750	953,750

Members' Equity and Unit-Base_4

Members' Equity and Unit-Based Compensation - Narrative (Details) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) vote manager $ / shares	Nov. 30, 2021 USD ($)	Nov. 30, 2020 USD ($)
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Common units, issued, value per unit (in dollars per share) | $ / shares		$ 1
Common unit, aggregate issuance value		$ 450,000
Fair market value MIU adjustment	$ (959)	1,446	$ (1,530)	$ 1,033
Payments of distributions	6,000	$ 36,000	12,000	0
Number of managers | manager		5
Number of votes each manager is entitled to | vote		1
Non Founder MIUs
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Fair market value MIU adjustment	$ (1,000)	$ 1,500	$ (1,500)	$ 1,000
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage		25%
Founder MIU Option Grant
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage		10%

Members' Equity and Unit-Base_5

Members' Equity and Unit-Based Compensation - Non-Founder MIUs (Details) - Non Founder MIUs - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Nonvested at period end (in shares)	45,000	28,750	45,000	82,500
Granted (in shares)	0	0	0	50,000
Vested (in shares)	0	16,250	37,500	50,000
Forfeited (in shares)	0	0	0	0
Fair value of MIUs vested during the period	$ 0	$ 0.2	$ 0.7	$ 0.7

Members' Equity and Unit-Base_6

Members' Equity and Unit-Based Compensation - Compensation Cost (Income) and Liability (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Total compensation cost (income)	$ 2,628	$ (10,766)	$ 1,409	$ (544)
Unit-based compensation	10,980	0	8,352
Common Unit Option Grant
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Total compensation cost (income)	383	(2,089)	(569)	(1,308)
Unit-based compensation	2,090		1,706
Founder MIU Option Grant
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Total compensation cost (income)	2,170	(8,680)	1,625	700
Unit-based compensation	8,679		6,510
Non Founder MIUs
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Total compensation cost (income)	75	$ 3	353	$ 64
Unit-based compensation	$ 211		$ 136

Members' Equity and Unit-Base_7

Members' Equity and Unit-Based Compensation - Fair Value Assumptions (Details)	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Nov. 30, 2021	Nov. 30, 2020
Founder MIU Option Grant
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Expected volatility, minimum	105%	125%	130%
Expected volatility, maximum	140%	170%	145%
Weighted-average volatility	140%	150%	137.50%
Expected dividends/distributions	0%	0%	0%
Expected term (in years)	6 months	1 year	2 years
Risk-free rate	0.69%	0.24%	0.16%
Common Unit Option Grant
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Expected volatility, minimum			60%
Expected volatility, maximum			65%
Expected volatility	55%	50%
Weighted-average volatility	50%	50%	62.50%
Expected dividends/distributions	0%	0%	0%
Expected term (in years)	6 months	1 year	2 years
Risk-free rate	0.69%	0.24%	0.16%

Members' Equity and Unit-Base_8

Members' Equity and Unit-Based Compensation - Basic and Diluted Net Income (Loss) Per Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Common Units
Net Income (Loss)	$ (7,359)	$ 118,903	$ 18,114	$ (8,857)
In-substance options on common units (Common Unit Option Grant)	0	(3,006)	(458)	0
In-substance options on Founder MIUs (Founder MIU Option Grant)	0	0	0	0
Non-Founder MIUs classified as temporary equity	0	0	0	0
Non-Founder MIUs classified as liabilities	0	0	0	0
Net income (loss) attributable to common unitholders	$ (7,359)	$ 115,897	$ 17,656	$ (8,857)
Weighted Average Common Units Outstanding (in shares)	450,000,000	450,000,000	450,000,000	450,000,000
Less: Common Unites accounted for as in-substance options (in shares)	(11,375,000)	(11,375,000)	(11,375,000)	(11,375,000)
Weighted Average Common Units Outstanding (in shares)	438,625,000	438,625,000	438,625,000	438,625,000
Net income (loss) per common unit, basic (in USD per share)	$ (0.02)	$ 0.26	$ 0.04	$ (0.02)
Net income (loss) per common unit, diluted (in USD per share)	$ (0.02)	$ 0.26	$ 0.04	$ (0.02)
Temporary Equity Classified MIUs
Income allocable to Non-Founder MIUs classified as temporary equity	$ 0	$ 0	$ 0	$ 0
MIUs classified in temporary equity (in shares)	234,000	250,000	234,000	196,000
Net income (loss) per non-founder MIUs classified as temporary equity, basic (in USD per share)	$ 0	$ 0	$ 0	$ 0
Net income (loss) per non-founder MIUs classified as temporary equity, diluted (in USD per share)	$ 0	$ 0	$ 0	$ 0

Stockholder's Equity - Vitess_2

Stockholder's Equity - Vitesse Energy, Inc (Details) - Vitesse Energy, Inc.	Dec. 31, 2022 shares
Class of Stock [Line Items]
Shares issued (in shares)	1,000
Shares outstanding (in shares)	1,000

Subsequent Events (Details)

Subsequent Events (Details) - Revolving Credit Facility - Credit Facility - Line of Credit - USD ($) $ in Millions	Feb. 13, 2023	Jan. 13, 2023	Dec. 31, 2022	Dec. 31, 2021
Subsequent Event [Line Items]
Revolving credit facility			$ 48	$ 68
Subsequent Event
Subsequent Event [Line Items]
Revolving credit facility	$ 53
Subsequent Event | Vitesse Energy, Inc.
Subsequent Event [Line Items]
Revolving credit facility		$ 53

Supplemental Oil and Gas Info_3

Supplemental Oil and Gas Information - Costs Incurred (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Extractive Industries [Abstract]
Proved Property Acquisition and Other	$ 117	$ 28,547	$ 6,210	$ 9,234
Development	3,015	63,284	36,769	36,859
Total	$ 3,132	$ 91,831	$ 42,979	$ 46,093

Supplemental Oil and Gas Info_4

Supplemental Oil and Gas Information- Reserves (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	1 Months Ended	12 Months Ended												13 Months Ended
	Dec. 31, 2021 MMBoe Boe Mcf bbl	Dec. 31, 2022 Mcf	Dec. 31, 2022 bbl	Dec. 31, 2022 Boe	Dec. 31, 2022 MMBoe	Nov. 30, 2021 Mcf	Nov. 30, 2021 bbl	Nov. 30, 2021 Boe	Nov. 30, 2021 MMBoe	Nov. 30, 2020 Mcf	Nov. 30, 2020 bbl	Nov. 30, 2020 Boe	Nov. 30, 2020 MMBoe	Dec. 31, 2021 Boe Mcf bbl
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed and Undeveloped Reserve, (Energy), Beginning Balance | Boe	42,534			42,344				47,244				55,825		47,244
Revisions of Previous Estimates	0.1			226	0.2			(3,695)	(3.7)			(9,048)	(9)	119
Extensions, Discoveries and Other Additions				1,846	1.8			1,340	1.3			1,096	1	0
Acquisition of Reserves				3,168	3.2			1,258				2,905		8
Production | Boe				(3,787)				(3,614)				(3,534)		(317)
Proved Developed and Undeveloped Reserve, (Energy), Ending Balance | Boe	42,344			43,797				42,534				47,244		42,344
Natural gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning balance | Mcf	78,024	77,681				84,829				87,324				84,829
Revisions of Previous Estimates | Mcf		1,959				(4,181)				(5,723)				231
Extensions, Discoveries and Other Additions | Mcf		2,561				2,648				2,199				0
Acquisition of Reserves | Mcf		5,187				1,793				6,638				8
Production | Mcf		(7,274)				(7,065)				(5,609)				(582)
Proved Developed and Undeveloped Reserves, Ending Balance | Mcf	77,681	80,114				78,024				84,829				77,681
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning balance | bbl	29,530		29,397				33,106				41,271			33,106
Revisions of Previous Estimates | bbl			(100)				(2,998)				(8,094)			80
Extensions, Discoveries and Other Additions | bbl			1,419				899				729			0
Acquisition of Reserves | bbl			2,304				959				1,799			7
Production | bbl			(2,575)				(2,436)				(2,599)			(220)
Proved Developed and Undeveloped Reserves, Ending Balance | bbl	29,397		30,445				29,530				33,106			29,397

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information - Proved Developed and Undeveloped Reserves (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	Dec. 31, 2022 Boe bbl Mcf	Dec. 31, 2021 Boe Mcf bbl	Nov. 30, 2021 Boe Mcf bbl	Nov. 30, 2020 Boe Mcf bbl	Nov. 30, 2019 Boe bbl Mcf
Reserve Quantities [Line Items]
Proved developed reserves (Energy) | Boe	27,106	27,288	27,504	25,744	25,438
Proved undeveloped reserves (Energy) | Boe	16,691	15,055	15,030	21,500	30,386
Natural gas
Reserve Quantities [Line Items]
Proved developed reserves (Volume) | Mcf	58,897	58,058	58,437	47,418	39,059
Proved undeveloped reserve (Volume) | Mcf	21,217	19,623	19,586	37,410	48,264
Oil
Reserve Quantities [Line Items]
Proved developed reserves (Volume) | bbl	17,290	17,612	17,764	17,841	18,928
Proved undeveloped reserve (Volume) | bbl	13,155	11,785	11,765	15,265	22,342

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information - Narrative (Details) Boe in Thousands	1 Months Ended	12 Months Ended						13 Months Ended
	Dec. 31, 2021 MMBoe	Dec. 31, 2022 Boe	Dec. 31, 2022 MMBoe	Nov. 30, 2021 Boe	Nov. 30, 2021 MMBoe	Nov. 30, 2020 Boe	Nov. 30, 2020 MMBoe	Dec. 31, 2021 Boe
Reserve Quantities [Line Items]
Acquisition of Reserves		3,168	3.2	1,258		2,905		8
Revisions of Previous Estimates	0.1	226	0.2	(3,695)	(3.7)	(9,048)	(9)	119
Upward (downward) adjustments,crude oil and natural gas prices			1.3		4.3		(9.7)
Upward (downward) adjustments, removal of drilling locations			(0.3)				(0.6)
Upward (downward) adjustments, development plan			(0.3)
Upward (downward adjustments, well performance			(0.5)		(0.6)		1.2
Extensions, Discoveries and Other Additions		1,846	1.8	1,340	1.3	1,096	1	0
Proved developed reserves, additions (Energy)			1.6
Proved undeveloped reserves, additions (Energy)			0.2
Williston Basin
Reserve Quantities [Line Items]
Upward (downward) adjustments, removal of drilling locations					(6.9)
Central Rockies
Reserve Quantities [Line Items]
Upward (downward) adjustments, removal of drilling locations					(0.5)

Supplemental Oil and Gas Info_7

Supplemental Oil and Gas Information - Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2021	Nov. 30, 2020	Nov. 30, 2019
Extractive Industries [Abstract]
Future Cash Inflows	$ 3,420,665	$ 2,206,162	$ 2,151,098	$ 1,405,418
Future Production Costs	(965,151)	(823,223)	(816,329)	(713,495)
Future Development Costs	(276,399)	(244,913)	(230,101)	(245,128)
Future Income Tax Expense	0	0	0	0
Future Net Cash Inflows	2,179,115	1,138,026	1,104,668	446,795
10% Annual Discount for Estimated Timing of Cash Flows	(999,131)	(509,625)	(503,055)	(255,617)
Standardized Measure of Discounted Future Net Cash Flows	$ 1,179,984	$ 628,401	$ 601,613	$ 191,178	$ 504,029

Supplemental Oil and Gas Info_8

Supplemental Oil and Gas Information - Price of Reserves (Details)	Dec. 31, 2022 $ / MMcf $ / bbl	Dec. 31, 2021 $ / MMcf $ / bbl	Nov. 30, 2021 $ / MMcf $ / bbl	Nov. 30, 2020 $ / MMcf $ / bbl
Natural gas
Reserve Quantities [Line Items]
Price used to calculate reserves (USD per Mcf/Bbl) | $ / MMcf	6.36	3.60	3.46	1.94
Oil
Reserve Quantities [Line Items]
Price used to calculate reserves (USD per Mcf/Bbl) | $ / bbl	94.14	66.55	64.81	40.45

Supplemental Oil and Gas Info_9

Supplemental Oil and Gas Information - Changes in Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022	Nov. 30, 2021	Nov. 30, 2020
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of Period	$ 601,613	$ 628,401	$ 191,178	$ 504,029
Sales of Oil and Natural Gas Produced, Net of Production Costs	(12,854)	(226,666)	(126,733)	(49,948)
Extensions and Discoveries	0	41,373	17,911	2,332
Previously Estimated Development Cost Incurred During the Period	0	714	16,924	22,308
Net Change of Prices and Production Costs	32,271	575,120	415,685	(322,506)
Change in Future Development Costs	(11,048)	(3,758)	22,606	79,816
Revisions of Quantity and Timing Estimates	2,153	18,140	(17,833)	(115,228)
Accretion of Discount	5,013	62,840	19,118	50,403
Change in Income Taxes	0	0	0	0
Purchases of Minerals in Place	117	122,421	23,272	17,304
Other	11,136	(38,601)	39,485	2,668
End of Period	$ 628,401	$ 1,179,984	$ 601,613	$ 191,178