vitesse-20221231

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to ___________________

Commission File Number: 001-41546

Vitesse Energy, Inc.

(Exact name of registrant as specified in its charter)


Delaware			88-3617511
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

9200 E. Mineral Avenue, Suite 200 Centennial, Colorado			80112
(Address of principal executive offices)			(Zip Code)

(720) 361-2500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.01 per share	VTS	The New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☐

Accelerated filer

☐

Non-accelerated filer

☒

Smaller reporting company

☐

Emerging growth company

☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of June 30, 2022 (the last business day of the registrant’s second fiscal quarter), there was no public market for the registrant's common stock. The registrant's common stock began trading on the New York Stock Exchange on January 17, 2023.

As of February 1, 2023, the registrant had 28,524,435 shares of common stock, $0.01 par value per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

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TABLE OF CONTENTS


		Cautionary Statement Concerning Forward-Looking Statements	4
		Glossary and Presentation	5
PART I
	Item s 1 and 2 .	Business and Properties	9
	Item 1A.	Risk Factors	28
	Item 1B.	Unresolved Staff Comments	52
	Item 3.	Legal Proceedings	52
	Item 4.	Mine Safety Disclosures	52

PART II
	Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53
	Item 6.	Reserved	54
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	54
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	72
	Item 8.	Financial Statements and Supplementary Data	74
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	74
	Item 9A.	Control and Procedures	74
	Item 9B.	Other Information	74
	Item 9C.	Disclosure Regarding Foreign Jurisdiction that Prevent Inspections	74

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	75
	Item 11.	Executive Compensation	81
	Item 12.	Security Ownership of Certain Beneficial Owner and Management and Related Stockholder Matters	86
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	88
	Item 14.	Principal Accounting Fees and Services	92

PART IV
	Item 15.	Exhibits, Financial Statement Schedules	93
	Item 16.	Form 10-K Summary	94

Signatures

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

The information in this Form 10-K contains statements which, to the extent they are not statements of historical or present fact, constitute “forward-looking statements” under the securities laws. These forward-looking statements are intended to provide management’s current expectations or plans for our future operating and financial performance, based on assumptions currently believed to be valid. Forward-looking statements can be identified by the use of words such as “believe,” “expect,” “expectations,” “plans,” “strategy,” “prospects,” “estimate,” “project,” “target,” “anticipate,” “will,” “should,” “see,” “guidance,” “outlook,” “confident” and other words of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements may include, among other things, statements relating to future earnings, cash flow, results of operations, uses of cash, tax rates and other measures of financial performance or potential future plans, strategies or transactions of Vitesse, and other statements that are not historical facts. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks, and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated, or budgeted. Such assumptions, risks, uncertainties and other factors include, but are not limited to, the following:

• the timing and extent of changes in oil and natural gas prices;

• our ability to successfully implement our business plan;

• the pace of our operators’ drilling and completion activity on our properties, including in connection with refrac

campaigns and extended length three-mile lateral infills;

• our operators’ ability to complete projects on time and on budget;

• uncertainties about estimates of reserves, identification of drilling locations and the ability to add reserves in the future;

• our ability to complete acquisitions;

• actions taken by third-party operators, processors, transporters and gatherers;

• natural disasters, adverse weather conditions, war (such as the ongoing military conflict in Ukraine), financial or

political instability, casualty losses and other matters beyond our control;

• the impact of the COVID-19 pandemic and the measures implemented to contain it;

• changes in general economic conditions;

• our ability to achieve the benefits that we expect to achieve as an independent publicly traded company;

• the qualification of the Distribution and certain related transactions as tax-free under the Code;

• inflation;

• infrastructure constraints and related factors affecting our properties;

• competitive conditions in our industry;

• the effects of existing and future laws and governmental regulations;

• the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing

fuels;

• operating hazards and other risks incidental to gathering, storing and transporting oil and natural gas;

• restrictions in our Revolving Credit Facility;

• interest rates;

• the effects of ongoing or future litigation;

• cyber-related risks;

• changes in insurance markets impacting costs and the level and types of coverage available;

• climate change and the physical and financial risks associated with fluctuating regional and global weather conditions or

patterns;

• energy efficiency and technology trends;

• competition from the same and alternative energy sources;

• changes in the availability and cost of capital;

• large customer defaults;

• labor relations; and

• changes in tax status.

The above list of factors is not exhaustive. For additional information on identifying factors that may cause actual results to vary materially from those stated in forward-looking statements, see the discussion under the section Part I, Item 1A. Risk Factors. Any forward-looking statements, express or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Any forward-looking statement that we make in this Form 10-K speaks only as of the date on which it was made. Except as otherwise required by applicable law, we expressly disclaim any obligation to, update or alter our forward-looking statements, whether as a result of new information, subsequent events or otherwise.

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GLOSSARY

In this Form 10-K, unless the context otherwise requires:

■“3B Energy” refers to 3B Energy, LLC, the holder of a minority of the equity interests in Vitesse Energy prior to the Pre-Spin-Off Transactions and an entity owned by Bob Gerrity, our Chief Executive Officer and Chairman of our Board, and Brian Cree, our President;

■“Amended and Restated Bylaws” refers to the bylaws of Vitesse effective as of January 13, 2023;

■“Amended and Restated Certificate of Incorporation” refers to the certificate of incorporation of Vitesse effective as of January 12, 2023;

■“Basin” refers to a large natural depression on the earth’s surface in which sediments generally brought by water accumulate;

■the “Board” refers to our board of directors;

■“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or NGLs;

■"BLM" refers to the Bureau of Land Management;

■“Boe” refers to barrels of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil;

■“Boe/d” refers to one Boe per day;

■“Btu” refers to a British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit;

■“completion” refers to the process of preparing an oil and natural gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production of oil, natural gas and/or NGLs;

■“condensate” refers to a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature;

■“CAA” refers to the Clean Air Act;

■“Cawley” refers to Cawley, Gillespie & Associates, Inc.;

■“CERCLA” refers to the Comprehensive Environmental, Response, Compensation, and Liability Act;

■“CFTC” refers to the Commodities Futures Trading Commission;

■the “Code” refers to the Internal Revenue Code of 1986, as amended;

■the "Corps" refers to the United States Army Corps of Engineers;

■“COVID-19” refers to the SARS-CoV-2 novel coronavirus and known variants;

■“CWA” refers to the Federal Water Pollution Control Act of 1972;

■“DGCL” refers to the General Corporation Law of the State of Delaware;

■“differential” refers to an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas;

■the “Distribution” refers to the transaction on January 13, 2023 in which Jefferies distributed to its shareholders all outstanding shares of our common stock held by Jefferies;

■the “Distribution Date” refers to the date on which the Distribution occurred;

■the “Dodd-Frank Act” refers to the Dodd-Frank Wall Street Reform and Consumer Protection Act;

■the “DOI” refers to the Department of the Interior;

■“dry hole” refers to a well found to be incapable of producing oil and natural gas in sufficient quantities to justify completion;

■the “EPA” refers to the Environmental Protection Agency;

■the “ESA” refers to the Endangered Species Act;

■“ESG” refers to environmental, social and governance;

■“Exchange Act” refers to the Securities Exchange Act of 1934;

■“FERC” refers to the Federal Energy Regulatory Commission;

■“FTC” refers to the Federal Trade Commission;

■“GAAP” refers to accounting principles generally accepted in the United States;

■“Gerrity Bakken” refers to Gerrity Bakken, LLC, the holder of a minority of the equity interests in Vitesse Oil and an entity owned by Bob Gerrity, our Chief Executive Officer and a member of our Board;

■“GHGs” refer to greenhouse gases;

■“gross acres” refers to the total acres in which a working interest is owned;

■“gross wells” refers to the total wells in which a working interest is owned;

■“IPOs” refer to initial public offerings;

■“IRS” refers to the Internal Revenue Service;

■“IRS Ruling” refers to a private letter ruling being sought by Jefferies from the IRS;

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■“Jefferies” refers to Jefferies Financial Group Inc. and its consolidated subsidiaries other than, for all periods following the Spin-Off, Vitesse, unless the context requires otherwise;

■“Jefferies Board” refers to Jefferies’ board of directors;

■“Jefferies Capital Partners” refers to Jefferies Capital Partners V L.P. and Jefferies SBI USA Fund L.P., collectively, the holders of a majority of the equity interests in Vitesse Oil and entities in which Jefferies holds an indirect limited partner interest;

■“Jefferies Parties” refers to Jefferies and certain of its affiliates;

■“MBbls” refers to one thousand barrels of oil or NGLs;

■“MBoe” refers to one thousand barrels of oil equivalent;

■“Mcf” refers to one thousand cubic feet of natural gas;

■“MMBoe” refers to one million barrels of oil equivalent;

■“MMBtu” refers to one million British thermal units;

■“MMcf” refers to one million cubic feet of natural gas;

■“net acres” refers to the sum of the fractional working interests owned in gross acres (e.g., a 10% working interest in a lease covering 1,280 gross acres is equivalent to 128 net acres);

■“net wells” refers to wells that are deemed to exist when the sum of fractional ownership working interests in gross wells equals one;

■"NAAQS" refers to National Ambient Air Quality Standards;

■“NEPA” refers to the National Environmental Policy Act;

■“NGLs” refer to natural gas liquids;

■“NSPS” refers to New Source Performance Standards;

■“NYMEX” refers to the New York Mercantile Exchange;

■“NYSE” refers to the New York Stock Exchange;

■“OPEC” refers to the Organization of Petroleum Exporting Countries;

■“OPA” refers to the Oil Pollution Act of 1990;

■“OTC” refers to the over-the-counter market;

■“PDP” or “proved developed producing” refers to proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods;

■“PDNP” or “proved developed non-producing” refers to proved reserves that are developed behind pipe and are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production;

■“PHMSA” refers to the Pipeline and Hazardous Materials Safety Administration;

■“possible reserves” refers to the additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves;

■“Pre-Spin-Off Transactions” refers to the series of transactions, including Vitesse’s acquisitions of Vitesse Energy and Vitesse Oil, consummated prior to the Distribution;

■“Prior Revolving Credit Facility” refers to Vitesse Energy’s Amended and Restated Credit Agreement, dated as of April 29, 2022, as amended from time to time, among Vitesse Energy, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto;

■“probable reserves” refers to the additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered;

■“productive well” refers to a well that is found to be capable of producing oil and natural gas in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes;

■“proved developed reserves” refers to proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of new equipment or operating methods is relatively minor compared to the cost of a new well;

■“proved reserves” refers to the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time;

■“PUD” or “proved undeveloped” refers to proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years unless specific circumstances justify a longer

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time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty:

■“RCRA” refers the Federal Resource Conservation and Recovery Act;

■“reserves” refers to estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project;

■“Revolving Credit Facility” refers to Vitesse’s Second Amended and Restated Credit Agreement, as amended from time to time, among Vitesse, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto, dated as of January 13, 2023;

■“SDWA” refers to the Safe Drinking Water Act;

■“SEC” refers to the Securities and Exchange Commission;

■“Securities Act” refers to Securities Act of 1933;

■“SOFR” refers to the Secured Overnight Financing Rate;

■the “Spin-Off” refers to our separation on January 13, 2023 from Jefferies and the creation of an independent, publicly traded company, Vitesse, through (1) the Pre-Spin-Off Transactions and (2) the Distribution;

■“Standardized Measure” refers to discounted future net cash flows estimated by applying year-end SEC prices (based on the 12-month unweighted arithmetic average of the first-day-of-the-month oil and natural gas prices for such year-end period) to the estimated future production of year-end proved reserves. Future cash flows are reduced by estimated future production and development costs, including asset retirement obligations, based on year-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash flows over our tax basis in the oil and natural gas properties. Future net cash flows after income taxes are discounted using a 10% annual discount rate;

■“Treasury Regulations” refers to final, temporary, and (to the extent they can be relied upon) proposed regulations under the Code, as promulgated from time to time (including corresponding provisions and succeeding provisions);

■“Two-stream basis” refers to the reporting of production or reserve volumes of oil and wet natural gas, where the NGLs have not been removed from the natural gas stream, and the economic value of the NGLs is included in the wellhead natural gas price;

■“Vitesse,” “we,” “our,” “us” and the “Company” (1) when used in the past tense, refer to Vitesse Energy and do not give effect to the consummation of the Pre-Spin-Off Transactions, and (2) when used in the present tense or future tense, refer to Vitesse Energy, Inc. and its consolidated subsidiaries and give effect to the consummation of the Pre-Spin-Off Transactions, in each case unless the context requires otherwise;

■“Vitesse Energy” refers to Vitesse Energy, LLC and its consolidated subsidiaries;

■“Vitesse Energy Finance” refers to Vitesse Energy Finance LLC, the holder of a majority of the equity interests in Vitesse Energy prior to the Pre-Spin-Off Transactions and an indirect wholly owned subsidiary of Jefferies;

■“Vitesse Energy MIUs” refers to management incentive units with respect to Vitesse Energy;

■“Vitesse Oil” refers to Vitesse Oil, LLC;

■“Vitesse Oil MIUs” refers to management incentive units with respect to Vitesse Oil;

■“Vitesse Oil Revolving Credit Facility” refers to Vitesse Oil’s Credit Agreement, dated as of July 23, 2015, as amended from time to time, among Vitesse Oil, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto;

■“VOCs” refers to volatile organic compounds;

■“WOTUS” refers to the waters of the United States; and

■“WTI” refers to West Texas Intermediate.

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PRESENTATION OF FINANCIAL AND OPERATING DATA

Unless otherwise indicated, the historical financial information presented in this Form 10-K is that of our predecessor, Vitesse Energy. Also, unless otherwise indicated all references to wells, working interest, royalty interest, or acreage are based on the published information available as of the date indicated, which may not be current. In addition, unless otherwise indicated, the reserve and operational data presented in this Form 10-K is with respect to only the assets of Vitesse Energy prior to giving effect to the Spin-Off. On November 30, 2021, our Board and the Board of Managers of our predecessor approved a change in our predecessor and our fiscal year end from November 30 to December 31. As a result, the 2022 fiscal year began on January 1, 2022 and ended on December 31, 2022 and there was a transition period from December 1, 2021 to December 31, 2021. Information covering such transition period is included in this Form 10-K.

INDUSTRY AND MARKET DATA

This Form 10-K includes information concerning our industry and the markets in which we operate that is based on information from public filings, internal company sources, various third-party sources and management estimates. Management’s estimates regarding Vitesse’s position, share and industry size are derived from publicly available information and our internal research, and are based on assumptions we made upon reviewing such data and our knowledge of such industry and markets, which we believe to be reasonable. While we are not aware of any misstatements regarding any industry data presented in this Form 10-K and believe such data to be accurate, we have not independently verified any data obtained from third-party sources and cannot assure you of the accuracy or completeness of such data. Such data involve uncertainties and are subject to change based on various factors, including those discussed in the section entitled “Part I, Item 1A, Risk Factors.”

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PART I

Items 1 and 2. Business and Properties

Overview

We are an independent energy company focused on returning capital to stockholders through owning financial interests as a non-operator in oil and natural gas wells. We engage in the acquisition, development and production of non-operated oil and natural gas properties in the United States that are generally operated by leading oil companies and are primarily in the Bakken and Three Forks formations in the Williston Basin of North Dakota and Montana. We also have properties in the Central Rockies, including the Denver-Julesburg Basin and the Powder River Basin. Since our inception, we have built a strong and diversified asset base through a combination of property acquisitions, development activities and the implementation of proprietary non-operating platforms and processes utilizing our extensive data resources. We believe the location and concentration of our assets in some of North America’s leading unconventional oil and natural gas resource plays, along with our technical and data capabilities, provide us with acquisition and development opportunities that will result in significant long-term value.

Vitesse has historically created value by acquiring non-operated minority working and mineral interests in oil and natural gas properties, comprising producing wells, near-term development opportunities and undeveloped acreage, and partnering with premier operators with significant experience in developing and producing oil and natural gas in our core areas. Over the past eight years, we have executed on our technical, data driven, and financially disciplined acquisition and development strategy to build our core position in the Williston Basin and Central Rockies and grow our oil and natural gas production. During that time, we have focused on limiting our downside by maintaining conservative acquisition guidelines, limiting our debt leverage and opportunistically hedging our oil production. As a result, we have been able to preserve value when many independent energy companies were forced into financial recapitalizations and restructurings when commodity prices collapsed in 2014, 2018 and 2020.

With the current oil and natural gas price environment, we are focused on using our cash flow to provide returns of capital to stockholders and maintain or grow our oil and natural gas production by developing our extensive inventory of drilling locations and acquiring both producing wells and new development opportunities, while maintaining a strong balance sheet,.

We owned an average working interest of 2.6% in 5,338 gross (138.0 net) productive wells and royalty interests in an additional 1,005 productive wells as of December 31, 2022. We engage in oil and natural gas well development by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. As of December 31, 2022, we owned a working interest in 237 gross (5.8 net) wells that were being drilled or completed, and an additional 421 gross (10.0 net) wells that had been permitted for future development by our operating partners. We rely on our operators to propose, permit and initiate the drilling and completion of wells. We assess each drilling and completion opportunity on a case-by-case basis and participate in wells that are expected to meet a desired return based upon estimates of recoverable oil and natural gas reserves, anticipated oil and natural gas prices, the expertise of the operator, and the anticipated completed well cost from each project, as well as other factors.

Our non-operated business model provides us with inherent flexibility regarding the cadence of capital deployment and the agility to allocate a portion of our cash flow to the drilling and completion opportunities that we believe will achieve the highest rate of return. We work with more than 35 experienced operators that provide technical insights and opportunities for additional acquisitions and continued development. In addition, our business model allows us to not be burdened with various contractual arrangements with respect to minimum drilling obligations, and we can avoid exploratory, upfront leasing and infrastructure costs customarily incurred by operators.

Our operators generally market and sell the oil and natural gas extracted from our wells. In addition, these operators coordinate the transportation of oil and natural gas production from wells in which we participate to appropriate pipelines or rail transport facilities pursuant to arrangements that such operators negotiate and maintain with various parties purchasing such production. The price at which our production is sold generally ties to a market spot price, and the differential between the market spot price and our realized sales price represents the embedded transportation and marketing costs of moving the oil and natural gas from the wellhead to the refinery or processing plant. The differential will fluctuate based on availability of pipeline, rail and other transportation methods.

Vitesse is led by a dedicated management team with extensive experience in the energy industry. Our management team includes Bob Gerrity, our Chief Executive Officer, a successful industry leader who was the founder and chief executive officer of Gerrity Oil & Gas Corporation, which pioneered low-cost “reserve manufacturing” in the Wattenberg field of Colorado during the 1990s. Gerrity Oil & Gas Corporation was one of the most active operators in the United States following its IPO in 1990, at times running more than 15 active drilling rigs and completing as many as 500 wells per year. Gerrity Oil & Gas Corporation merged with Snyder Oil Corporation to form Patina Oil & Gas Corporation in 1996, which was later merged with Noble Energy, Inc. in 2005. Today, these former assets comprise a material portion of Chevron Corporation’s position in the Denver-Julesburg Basin.

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Leveraging his prior experience and acknowledging the trend in advances in shale drilling and completion technologies, Mr. Gerrity believed the shale industry would transition to a reserve manufacturing phase marked by well-capitalized and efficient low-cost operators. In 2013, Mr. Gerrity and Brian Cree, our President and Chief Operating Officer, began to seek out non-operated lease and mineral interests with development opportunities in areas of the Williston Basin that were in the core of the field and operated by premier industry leaders, at which time Jefferies Capital Partners made an initial investment in Vitesse Oil to partially fund the acquisition of non-operated working and mineral interests primarily in undeveloped oil and natural gas assets. In 2014, Messrs. Gerrity and Cree began to see a growing number of acquisition and development opportunities in the Williston Basin, and Jefferies made a direct investment in Vitesse to support larger scale acquisition and development efforts. Since that time, Vitesse has completed over 130 acquisitions totaling approximately $530 million and deployed over $400 million in the development of oil and natural gas properties.

The following table provides a summary of certain information regarding our assets as of December 31, 2022, including proved reserves as prepared by our third-party independent reserve engineers, Cawley.



	AS OF DECEMBER 31, 2022
	NET ACRES(1)	PRODUCTIVE WELLS (1) GROSS	NET	AVERAGE DAILY PRODUCTION (2) (Boe/d)	PROVED RESERVES (3) (MBoe)	PV-10 (3) (in thousands)		% OIL		% PROVED DEVELOPED
Williston Basin	46,403	5,255	122	9,123	41,379	$	1,099,090	70	%	60%
Central Rockies (4)	197	83	16	1,253	2,418	80,894		58	%	91%
Total	46,600	5,338	138	10,376	43,797	$	1,179,984	70	%	62%

(1)In addition, we have royalty interests in 1,005 productive wells, on 1,011 net royalty acres.

(2)Represents the average daily production for the twelve months ended December 31, 2022.

(3)Proved reserve quantities and related PV-10 values have been derived from a WTI oil price of $94.14 per Bbl and Henry Hub natural gas price of $6.36 per MMBtu, which were calculated using an average of the first-day-of-the-month price for each month within the 12 months ended December 31, 2022 as required by SEC and FASB guidelines. PV-10 is a non-GAAP financial measure that does not include the effects of income taxes on future net revenues, and are not intended to represent fair market value of our oil and natural gas properties. For a definition of and reconciliation of PV-10 to its nearest GAAP financial measure, see Part II. Item 7 Management Discussion and Analysis —Non-GAAP Financial Information.

(4)Includes Denver-Julesburg and Powder River Basin assets, consisting primarily of wellbore only ownership.

In addition to the proved reserves shown in the table above, we believe our acreage includes over 200 net undeveloped drilling locations not currently classified as proved as of December 31, 2022, using the same pricing as above. We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes current well spacing information per drilling and spacing unit derived from state agencies and our operators. We generally do not have evidence of our operators’ long-term development plans, but we use a deterministic approach to define and allocate locations to proved, probable and possible reserves. While many of our undeveloped drilling locations qualify as geologic and engineering proved reserves, we limit our proved undeveloped reserves to those locations that are reasonably certain to be developed over the next five years.

The Spin-Off

On January 13, 2023, Jefferies completed the legal and structural separation of the Vitesse Energy from Jefferies. To affect the separation, first, Jefferies, 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 Jefferies as repayment for prior loans;

■Jefferies and other holders of Vitesse Energy's equity interests transferred all of their interest in Vitesse Energy to us in exchange for newly issued shares of our common stock;

■Vitesse Oil equity holders transferred their interests to us in exchange for newly issued shares of our common stock (the “VO Transaction”);

■Previous compensation agreements and compensation plans were eliminated and replaced with new compensation plans including the LTIP;

■We entered into a Revolving Credit Facility, which amended and restated the Prior Credit Facility, and used the proceeds to repay in full and terminate the Vitesse Oil Revolving Credit Facility and repay the Prior Credit Facility. Borrowings under the Revolving Credit Facility were $53 million as of January 13, 2023.

Jefferies then distributed all of our outstanding common stock held by Jefferies to Jefferies’ shareholders, and we became an independent, publicly traded company. After the Distribution, Jefferies does not own any shares of our common stock. In connection with the Spin-Off, we entered into certain agreements that governed, and will govern, our relationship with Jefferies,

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including a Separation and Distribution Agreement and a Tax Matters Agreement. See “Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence” for more detail. Also, in connection with the Spin-Off, Vitesse Energy became a wholly owned subsidiary of a taxable entity (Vitesse). Therefore, we will record the effects of income taxes within our consolidated financial statements which will include the consolidated results of operations of Vitesse Energy and Vitesse Oil, as well as reflect the basis differences between tax and financial accounting for the assets and liabilities. We anticipate establishing a deferred tax liability in the first quarter of 2023.

Business Strategy

Our business strategy is focused on creating long-term stockholder value through the acquisition, development and production of oil and natural gas assets at attractive rates of return, while maintaining a strong and conservative balance sheet and distributing a meaningful and growing portion of our free cash flow to our stockholders. The key elements of our business strategy include the following:

■Dividends to Stockholders. Our business plan focuses on building a diversified, low-leverage, free cash flow generating business that can deliver meaningful and growing dividends to our stockholders. We made cash distributions to our members totaling $0.0 million, $12.0 million, and $36.0 million during the fiscal years ended November 30, 2020, November 30, 2021 and December 31, 2022, respectively, and $6.0 million during the month ended December 31, 2021. In addition to the aforementioned cash distribution payments, during 2020, Jefferies realized close to $25.0 million in hedging gains that were attributable to derivatives associated with our oil production, further demonstrating our commitment to returning value to our investors. We expect that Vitesse will initially pay quarterly cash dividends and dividend equivalents totaling approximately $66.0 million per fiscal year.

■Growth through Value-Enhancing Acquisitions. We have been a consolidator and clearing house of non-operated working interests in various leading oil and natural gas shale plays in the United States, and we will continue that strategy and potentially pursue operated asset packages and other acquisition strategies going forward. Our near-term drilling acquisition strategy is centered around building a strong presence in our core basins by acquiring smaller non-operated lease and wellbore positions with direct exposure to near-term drilling activity. By virtue of their smaller footprint, these targeted acquisitions have been completed at a significant discount to the prices paid for contiguous acreage positions typically sought by larger producers and operators of oil and natural gas wells. Acquisitions such as these have been a significant driver of increasing our production. Over the last eight years, we have closed approximately 130 discrete acquisitions totaling more than $530 million, and we intend to continue these activities, while at the same time evaluating and pursuing larger asset packages in both our current area of operations and other areas. We believe our disciplined acquisition strategy can responsibly add production, cash flow and scale to existing operations.

■Built to Last. From our inception, we have focused on creating a durable organization that generates strong financial returns and sustainable free cash flow through commodity cycles. Rather than primarily acquiring producing reserves, we have focused our efforts on acquiring an attractive inventory of undeveloped drilling locations that afford us flexibility in the face of oil and natural gas price fluctuations and taking advantage of technical improvements and cost reductions over time, supporting the sustainable generation of free cash flow. Our management team fosters a culture of innovation and continuous improvement, constantly looking for ways to improve our operations and technical and data analysis, and strengthen our organizational agility and adaptability.

■Risk Diversification. We seek to diversify our capital and operational risk through participation in a large number of oil and natural gas wells with multiple operators across multiple basins. We seek to diversify our risk by operator, formation, value concentration and commodity (oil and natural gas). As of December 31, 2022, we owned an average working interest of 2.6% in 5,338 gross (138.0 net) productive wells and royalty interests in an additional 1,005 productive wells, with more than 35 experienced operators that provide development and production activities on our oil and natural gas properties. We believe we can further diversify our risk over time with acquisitions in additional basins, focusing on accretive acquisitions of high-quality assets with experienced operators in the most prolific basins in the United States. During the twelve months ended December 31, 2022, our average production was 10,376 Boe per day, consisting of approximately 9,123 Boe per day in the Williston Basin and 1,253 Boe per day in the Central Rockies.

■Strong Balance Sheet and Financial Flexibility. We maintain financial strength and flexibility through the prudent management of our balance sheet and free cash flow. During 2020, 2021 and 2022, we were free cash flow positive and reduced our outstanding debt from $104.0 million at November 30, 2019 to $48.0 million at December 31, 2022, while distributing $54.0 million to our investors. We maintain conservative indebtedness and a simple capital structure consisting of our Revolving Credit Facility and common stock. We intend to maintain the flexibility to manage our free cash flow by continuing to adhere to a target Net Debt to Adjusted EBITDA ratio (last twelve months) of less than 1.0. As of December 31, 2022, our Net Debt to Adjusted EBITDA ratio was 0.23. For the year ended December 31, 2022, we generated net income and Adjusted EBITDA of $118.9 million and $167.6 million, respectively. For definitions and reconciliations of Net Debt and Adjusted EBITDA to their most directly comparable

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financial measures in accordance with GAAP, see Part II. Item 7 Management Discussion and Analysis — "Non-GAAP Financial Information.”

■Hedging Strategy. To reduce our exposure to the volatility of oil prices and protect our ability to pay distributions, we have historically entered into hedging derivative instruments for a portion of our expected oil production, which have included swaps, collars, puts and other structures. We have bought oil futures both on an opportunistic basis when WTI prices have allowed us to lock in attractive rates of return on our asset base and upon acquisitions of larger producing assets to protect returns. We have not hedged natural gas production since March 2022 and do not expect to do so in the future due to the mismatch between our operators’ pricing formulas and settlement mechanics on natural gas hedges. Our current hedged position mitigates our exposure to volatile oil prices, with approximately 31% of our expected oil production hedged through December 31, 2024 at an average price of $77.42/Bbl. However, in the past, based on then-existing market conditions, we have hedged significantly higher percentages of our actual oil production. For further information see Part II. Item 7A Quantitative and Qualitative Disclosure about Market Risk ”Commodity Price Risk.”

■Responsible Stewards. We are committed to ESG initiatives and seek a culture of improvement in ESG practices. We work to provide safe, reliable and affordable energy in a responsible manner by partnering with responsible operators in our core areas, while being cognizant of the broader energy transition. The key tenets of our ESG philosophy are to identify opportunities to reduce our environmental impact, improve safety, invest in our employees, and support the communities in which we live and work while improving transparency and accountability. Our Board is majority independent and composed of experienced professionals with a strong background in the energy industry and more broadly in business.

Our Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

■Every Decision is a Financial Decision. Our business culture encourages employees to think like owners and to make decisions with a long-term perspective. We have developed a systematic approach of responsibly reviewing acquisition and development opportunities. As part of our efforts to maximize returns, we have established a capital allocation framework with the objective of allocating capital to acquisitions and development of oil and natural gas properties to drive sustainability and growth in free cash flow, the repayment of debt and payment of stockholder dividends. This framework entails disciplined investment in capital expenditures and acquisitions, allowing us to distribute a significant portion of our cash flow to our stockholders. We also retain flexibility with respect to share repurchases, subject to approval from our Board and as conditions warrant. We will continue to evaluate and pursue profitable and accretive acquisition and consolidation opportunities that enhance stockholder value and build scale. As opportunities arise, we intend to identify and acquire additional acreage and producing assets to supplement our existing operations.

■Data and Technology Driven. Our proprietary data-driven approach allows for rapid multi-disciplinary evaluation to determine the most attractive acquisition and development opportunities. We created customized data systems (vLuminis) that are integrated, centralized and utilized by our employees so that decisions are based on a common base of information. We maintain real-time business intelligence dashboards to monitor operators, rigs, well performance, drilling and completion costs and production results. This data informs model forecasts, type curves and decisions about acquisition and development opportunities. We maintain responsive, basin-wide models that are updated in real time and incorporate historical data by operator and region. These models, along with our proprietary systems and platforms, provide necessary inputs and evaluation metrics, which allow us to make informed investment decisions based on forecasted production, operating expenses, type curves, drilling inventory, cash flow and other operational and financial outputs. As a result, we have the capability to process multiple opportunities quickly with the current team in place.

■Experienced Management and Industry Relationships. Vitesse’s management team has developed deep and longstanding relationships with many of our operators, other working interest and mineral owners, investment banks, acquisition and divestiture companies and investors. A majority of our evaluated and executed acquisitions and transactions are self-sourced. We have become a preferred non-operator to some of the largest companies operating in the Williston Basin and Central Rockies given our track record of evaluating and acquiring non-operated oil and natural gas working interests, and being a responsible financial partner. As a result, we see broad deal flow from single wellbore near-term development acquisition opportunities to packages consisting of both producing and undeveloped assets worth hundreds of millions of dollars. Our management team has an over 30-year track record of creating value together at both private and public oil and natural gas companies.

■Proactive Asset Management Philosophy. Our experienced team of landmen and accountants review acquired assets to unlock incremental value. Many assets we acquire have title defects or other land related issues where deep analysis and consistent, quality diligence adds value in many areas, including increased working interest ownership and working capital management. Our long-term view provides the time to solve issues and find additional well

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interests to increase the velocity of overall returns. This is enabled by strong departmental relationships with operators and accurate data management.

Our Properties

Williston Basin (North Dakota and Montana)

The Williston Basin stretches from western North Dakota into eastern Montana, with the majority of drilling activity conducted by our operators, all of which is horizontal, located in Dunn, McKenzie, Mountrail, and Williams Counties, North Dakota. Approximately 76% of our 46,403 net acres as of December 31, 2022 are in the above counties in the Bakken and Three Forks formations and approximately 99% of our acreage in the Williston Basin is held by production. As of December 31, 2022, we had a working interest in 5,255 gross (122.3 net) productive wells and royalty interests in an additional 1,005 productive wells. In addition to these productive wells, we had 205 gross (3.7 net) working interest wells that were being drilled or completed, and 417 gross (9.9 net) wells that have been permitted for future development by our operating partners. Our estimated proved reserves in North Dakota and Montana as of December 31, 2022 were 41,379 MBoe (70% oil), which represented 94% of our total estimated proved reserves and contributed average production of 9,123 Boe per day for the year ended December 31, 2022.

We have been active in the Williston Basin since 2014 and have seen our thesis for continued growth and expansion of the field come to fruition. The Williston Basin is a world class oil field and we expect to see continued growth in recoverable reserves for many years. We have a significant inventory of remaining undeveloped drilling locations that we expect to see developed over the next 15 to 25 years. In addition, we are seeing the early signs of incremental growth and development throughout the field from successful refrac programs, extended length three-mile lateral infills and consolidation of assets to more active and basin focused operators.

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The map below illustrates our acreage position in the Williston Basin as of December 31, 2022.

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Denver-Julesburg Basin (Colorado and Wyoming)

The Denver-Julesburg Basin is located in Northeast Colorado and Southeast Wyoming, with the majority of operator horizontal drilling activity located in Weld and Broomfield Counties, Colorado, and Laramie County, Wyoming. Our assets in this area primarily consist of wellbore only ownership and target the Codell formation and several productive zones within the Niobrara formation. We owned a working interest in 77 gross (14.7 net) productive wells as of December 31, 2022 operated primarily by Civitas Resources, Inc., PDC Energy, Inc., EOG Resources Inc. and Chevron Corporation. In addition to the productive wells, we have 32 gross (2.1 net) wells that were being completed by our operating partners as of December 31, 2022.

Powder River Basin (Wyoming)

Our Powder River Basin assets primarily target the Parkman, Sussex, Turner and Niobrara formations. We owned a working interest in 6 gross (1.0 net) productive wells as of December 31, 2022. In addition to these productive wells, we have 3 gross (0.1 net) wells that have been permitted for future drilling by our operators as of December 31, 2022.

The diagrams below illustrate, by operator, our net production during the year ended December 31, 2022 and our working interest net acres as of December 31, 2022.

Net Production: 10,376 Boe/d

Working Interest Net Acres: 46,600

Reserves

Estimated Net Proved Reserves

The table below summarizes our estimated net proved reserves for the periods indicated based on reports prepared

by Cawley, our third-party independent reserve engineer, except as otherwise described herein. In preparing its reports, Cawley evaluated properties representing our total proved reserves as of December 31, 2022 and November 30, 2021 and our proved developed reserves and a portion of our proved undeveloped reserves as of November 30, 2020 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. Cawley did not review a portion of our proved undeveloped reserves as of November 30, 2020, which are based on internal reserve estimates. Reserves as of December 31, 2021 represent our reserves as of November 30, 2021, which are based on a report prepared by Cawley, as adjusted for reserve activity during the one month period of December 1, 2021 to December 31, 2021, which reflect internal reserve estimates. Our estimated net proved reserves in the table below do not include probable or possible reserves and do not in any way include or reflect our commodity derivatives.

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	AS OF DECEMBER 31,				AS OF NOVEMBER 30,
	2022		2021		2021		2020
Estimated proved developed:

Oil (MBbls)	17,290		17,612		17,764		17,841
Natural gas (MMcf)	58,897		58,058		58,437		47,418
Total (MBoe)	27,106		27,289		27,504		25,744
Estimated proved undeveloped:
Oil (MBbls)	13,155		11,785		11,765		15,265
Natural gas (MMcf)	21,217		19,623		19,586		37,410
Total (MBoe)	16,691		15,055		15,030		21,500
Estimated total proved reserves:
Oil (MBbls)	30,445		29,397		29,530		33,106
Natural gas (MMcf)	80,114		77,681		78,023		84,829
Total (MBoe)	43,797		42,344		42,534		47,244
Percent proved developed	61.9	%	64.4	%	64.7	%	54.5	%

Estimated net proved reserves as of December 31, 2022 were 43,797 MBoe, and we held working interests in 35.8 net proved undeveloped drilling locations included in such reserves as of December 31, 2022.

The table below sets forth summary information by reserve category with respect to estimated proved reserves volumes and related PV-10 values as of December 31, 2022.



	SEC PRICING PROVED RESERVES (1)
	RESERVES VOLUMES					PV-10 (3)
RESERVE CATEGORY	OIL (MBbls)	NATURAL GAS (MMcf)	TOTAL (MBoe) (2)	%		AMOUNT (in thousands)		%
PDP Properties	17,149	58,778	26,945	62	%	$	786,959	67	%
PDNP Properties	141	119	161	—	%	6,577		—	%
PUD Properties	13,155	21,217	16,691	38	%	386,448		33	%
Total	30,445	80,114	43,797	100	%	$1,179,984		100	%

(1)Oil and natural gas reserve quantities and related discounted future net cash flows are valued as of December 31, 2022 based on average prices of $94.14 per barrel of oil and $6.36 per MMBtu of natural gas. Under SEC guidelines, these prices represent the average prices per barrel of oil and per MMBtu of natural gas at the beginning of each month in the twelve-month period prior to the end of the reporting period.

(2)MBoe are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6 Mcf of natural gas.

(3)PV-10 is a non-GAAP financial measure that does not include the effects of income taxes on future net revenues, and are not intended to represent fair market value of our oil and natural gas properties. For a definition of and reconciliation of PV-10 to its nearest GAAP financial measure, see Part II. Item 7 Management Discussion and Analysis ”Non-GAAP Financial Information.”

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Estimated Net Proved Undeveloped Reserves

As of December 31, 2022, we had approximately 16,691 MBoe of estimated net proved undeveloped reserves. Changes in estimated net proved undeveloped reserves that occurred from December 31, 2021 to December 31, 2022 were due to:



			MBoe
Balance at December 31, 2021			15,055
Acquisitions			414
Extensions, discoveries and other additions			1,810
Transfers to estimated proved developed reserves			(793)
Revisions			205
Balance at December 31, 2022			16,691

Notable changes in proved undeveloped reserves for the year ended December 31, 2022 included the following:

■Acquisitions: We acquired 0.4 MMBoe of proved undeveloped reserves related to 56 gross (1.3 net) uncompleted wells in the Williston Basin and Central Rockies during 2022.

■Extensions, discoveries and other additions: Total extensions and discoveries of 1.8 MMBoe were attributable to additions of proved undeveloped locations in the Williston Basin.

■Transfers to estimated proved developed reserves: Development costs of approximately $15.1 million were incurred in connection with the development of locations that were classified as proved undeveloped reserves as of December 31, 2022, and 0.8 MMBoe of proved undeveloped reserves were converted to proved developed reserves during the period.

■Revisions: In 2022, revisions to previous estimates increased proved reserves by a net amount of 0.2 MMBoe. Included in these revisions were 0.2 MMBoe of upward adjustments caused by higher crude oil and natural gas prices, 0.3 MMBoe of upward adjustments attributable to well performance when comparing the Company’s reserve estimates at December 31, 2022 to December 31, 2021, and 0.3 MMBoe of downward adjustments related to the removal of undeveloped drilling locations related to the SEC 5-year development rule.

We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled on our acreage. All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our development plan.

As of December 31, 2022, the PV-10 value of our proved undeveloped reserves amounted to approximately 33% of the PV-10 value of our total proved reserves. There are numerous uncertainties regarding undeveloped reserves. The development of these reserves is dependent upon a number of factors which include but are not limited to: financial targets such as drilling within cash flow or reducing debt, satisfactory rates of return on proposed drilling projects, and the level of drilling activity by operators in areas where we hold leasehold interests. With 67% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan. PV-10 is a non-GAAP financial measure that does not include the effects of income taxes on future net revenues and is not intended to represent the fair market value of our oil and natural gas properties. For a definition of and reconciliation of PV-10 to its nearest GAAP financial measure, see Part II. Item 7 Management Discussion and Analysis "Non-GAAP Financial Information.”

Independent Petroleum Engineers

We have engaged Cawley to prepare our estimated proved reserves. Cawley is an independent reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States. Cawley has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and, as such, we believe Cawley has sufficient experience to appropriately determine our reserves. Cawley utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience. The reports of our estimated proved reserves in their entirety are based on the information we provide to them. Cawley is a Texas Registered Engineering Firm (F-693). The technical person at Cawley who is primarily responsible for overseeing the preparation of our reserves estimates is Todd Brooker, President. Mr. Brooker is a state of Texas Licensed Professional Engineer (License # 83462). He is also a member of the Society of Petroleum Engineers and has over 25 years of experience in oil and natural gas reservoir studies and evaluations.

In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties.

The reserves set forth in the Cawley report for our properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis

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which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.

To estimate economically recoverable oil and natural gas reserves and related future net cash flows, Cawley considers many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic productivity from a reservoir is to be determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.

The reserve data set forth in the Cawley report represents only estimates, and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. See “Risk Factors—Risks Relating to our Business—Our estimated proved, probable and possible reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our total reserves.”

Internal Controls Over Reserves Estimation Process

We utilize Cawley, a third-party reservoir engineering firm, as our independent reserves evaluator for 100% of our proved reserves base. In addition, we employ an internal reserve engineering department, which is led by our Chief Engineer, who is responsible for overseeing the preparation of our reserves estimates. Our Chief Engineer has a B.S. in petroleum engineering from Texas A&M University, over twenty years of oil and gas experience, including 15 years with a focus on reserve evaluation, and additional experience with acquisitions, operations and production engineering in multiple basins.

Our reserve engineering department meets with our independent third-party engineering firm to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data, as well as management review, such as, but not limited to the following:

■comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input;

■review of working interests and net revenue interests in our reserves database against our well ownership system;

■review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;

■review of updated capital costs based on information from our operators and actual drilling and completion costs on recent activity;

■review of internal reserve estimates by well and by area by our internal reservoir engineer;

■discussion of material reserve variances among our internal reservoir engineer and our executive management; and

■review of a preliminary copy of the reserve report by executive management.

Production, Price and Production Expenses

The price that we receive for the oil and natural gas produced from wells in which we hold interests is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Oil supply in the United States has grown over the past few years, and the supply of oil could impact oil prices in the United States if the supply outstrips domestic demand. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

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The table below sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated.



	YEAR ENDED DECEMBER 31,		MONTH ENDED DECEMBER 31,		YEAR ENDED NOVEMBER 30,
	2022		2021		2021		2020
Net Production:
Oil (MBbls)
Williston Basin	2,257		199		2,226		2,446
Central Rockies(1)	318		22		210		153
Total	2,575		221		2,436		2,599
Natural gas (MMcf)
Williston Basin	6,441		519		6,409		5,161
Central Rockies(1)	833		63		656		448
Total	7,274		582		7,065		5,609
Total (MBoe)
Williston Basin	3,331		285		3,295		3,306
Central Rockies(1)	457		32		319		228
Total	3,788		317		3,614		3,534
Oil (Bbl) per day
Williston Basin	6,182		6,408		6,097		6,683
Central Rockies(1)	872		699		576		418
Total	7,054		7,107		6,673		7,101
Natural gas (Mcf) per day
Williston Basin	17,646		16,754		17,560		14,101
Central Rockies(1)	2,283		2,020		1,797		1,224
Total	19,929		18,774		19,357		15,325
Total (Boe) per day
Williston Basin	9,123		9,200		9,024		9,033
Central Rockies(1)	1,253		1,036		875		622
Total	10,376		10,236		9,899		9,655

Average Sales Prices:
Oil (per Bbl)	$	94.16	$	69.18	$	62.34	$	35.22
Effect of gain (loss) on realized oil derivative on average price (per Bbl)	(18.07)		(7.65)		(5.37)		10.45
Oil Net of Realized Oil Derivatives (per Bbl)	76.09		61.53		56.97		45.67
Natural gas and NGLs (per Mcf)	7.92		4.72		4.72		1.01
Effect of gain (loss) on realized natural gas derivatives on average price (per Mcf)	(0.08)		0.02		(0.12)		—
Natural gas and NGLs net of realized natural gas derivative (per Mcf)	7.84		4.74		4.60		1.01
Realized price on a Boe basis excluding realized commodity derivatives	79.24		56.69		51.25		27.51
Effect of gain (loss) on realized commodity derivatives on average prices (per Boe)	(12.45)		(5.28)		(3.85)		7.69
Realized price on a Boe basis net of realized commodity derivatives	66.79		51.41		47.40		35.20
Average Costs:
Production expenses (per Boe)	$	13.02	$	11.95	$	12.15	$	11.81
Production taxes (per Boe)	$	6.36	$	4.22	$	4.02	$	2.60

(1) Includes Denver-Julesburg and Powder River Basin wells.

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Drilling and Development Activity

The table below sets forth the number of gross and net productive and non-productive wells in which we owned a working interest drilled in the periods indicated. The number of wells drilled refers to the number of wells completed at any time during the period, regardless of when drilling was initiated.



	YEAR ENDED DECEMBER 31,		MONTH ENDED DECEMBER 31,		YEAR ENDED NOVEMBER 30,
	2022		2021		2021		2020
	GROSS	NET	GROSS	NET	GROSS	NET	GROSS	NET
Exploratory Wells:
Productive Oil	—	—	—	—	—	—	—	—
Productive Natural gas	—	—	—	—	—	—	—	—
Non-productive	—	—	—	—	—	—	—	—
	—	—	—	—	—	—	—	—
Development Wells:
Productive Oil (1)	295	7.53	28	0.97	243	6.55	241	3.96
Productive Natural gas	—	—	—	—	—	—	—	—
Non-productive	—	—	—	—	—	—	—	—
	—	—	—	—	—	—	—	—
Total productive exploratory and development wells (1)	295	7.53	28	0.97	243	6.55	241	3.96

(1) Includes royalty interests in 45 gross (0.09 net) wells drilled in the year ended December 31, 2022, 0 gross (0 net) wells drilled in the month ended December 31, 2021, 57 gross (0.08 net) wells drilled in the year ended November 30, 2021 and 39 gross (0.11 net) wells drilled in the year ended November 30, 2020.

The table below sets forth summary information by location with respect to estimated productive wells in which we owned a working interest as of December 31, 2022.



	AS OF DECEMBER 31, 2022
	PRODUCTIVE WORKING INTEREST OIL WELLS		AVERAGE WORKING INTEREST
	GROSS	NET
Combined Total:
Williston Basin	5,255	122	2.3	%
Central Rockies (1)	83	16	19.3	%
Total	5,338	138	2.6	%

	AS OF DECEMBER 31, 2022
	PRODUCTIVE ROYALTY INTEREST OIL WELLS		AVERAGE ROYALTY INTEREST
	GROSS	NET
Combined Total:
Williston Basin	1,005	3	0.3	%
Central Rockies (1)	—	—	—	%
Total	1,005	3	0.3	%

(1)Includes Denver-Julesburg and Powder River Basin wells.

As of December 31, 2022, we owned a working interest in 237 gross (5.8 net) wells that were being drilled or completed, and an additional 420 gross (10.0 net) wells that had been permitted for development by our operating partners.

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Acreage

The table below sets forth our estimated gross and net undeveloped acreage by geographic area as of December 31, 2022.



	DEVELOPED ACREAGE		UNDEVELOPED ACREAGE		TOTAL ACREAGE		ROYALTY ACRES
	GROSS	NET	GROSS	NET	GROSS	NET	GROSS	NET
Williston Basin	1,591,712	44,008	60,157	2,395	1,651,869	46,403	107,227	1,010
Central Rockies (1)	3,042	105	11,520	92	14,562	197	640	1
Total	1,594,754	44,113	71,677	2,487	1,666,431	46,600	107,867	1,011

(1)Includes Denver-Julesburg and Powder River Basin acreage.

Approximately 99% of our undeveloped acreage is held by production as of December 31, 2022, with 7,680 gross (41 net) acres and 640 gross (5 net) acres subject to potential expiration in 2024 and 2025, respectively.

Industry Operating Environment

We operate in a highly cyclical industry. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. This is primarily because the industry is driven by commodity demand and corresponding price increases. When oil and natural gas price increases occur, producers generally increase their capital expenditures, which generally results in greater revenues and profits. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices. For these reasons, our results of operations may fluctuate from quarter-to-quarter and from year-to-year, and these fluctuations may distort period-to-period comparisons of our results of operations.

The global energy mix is also transitioning to cleaner lower carbon sources and our business is not immune to these trends. In our view, energy transition will play out over the coming decades and oil and natural gas will still be a dominant source for affordable and reliable energy. We see the quality of our asset base, depth of inventory and competitive economics carrying us profitably through this transition.

Development

We primarily engage in oil and natural gas development and production by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our leasehold interests. In addition, we acquire wellbore interests in wells in which we do not hold the underlying leasehold interests from third parties unable or unwilling to participate in certain well proposals. We typically depend on our operators to propose, permit, and initiate the drilling and completion of wells. Prior to commencing drilling, our operators are required to provide all owners of working interests within the designated spacing unit the opportunity to participate in the drilling and completion costs and net revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. We assess each drilling and completion opportunity on a case-by-case basis and participate in wells that are expected to meet a desired return based upon estimates of recoverable oil and natural gas, anticipated oil and natural gas prices, the expertise of the operator, and the anticipated completed well cost from each project, as well as other factors. Historically, we have participated pursuant to our working interest in a vast majority of the wells proposed to us. However, declines in oil prices typically reduce both the number of well proposals we receive and the proportion of well proposals in which we elect to participate. Our land, engineering and finance teams use our extensive database to make these economic decisions. Vitesse created customized data systems (vLuminis) that are integrated, centralized and utilized by our employees to evaluate development opportunities. These data systems maintain real time dashboards to monitor operators, rigs, well performance and costs. Given our large acreage footprint and substantial number of well participations, we believe we can make accurate economic drilling and completion decisions utilizing our data systems.

Historically, we have not managed our commodities marketing activities internally. Instead, our operators generally market and sell oil and natural gas produced from wells in which we have an interest. Our operators coordinate the transportation of our oil and natural gas production from our wells to appropriate pipelines or rail transport facilities pursuant to arrangements that they negotiate and maintain with various parties purchasing the production. We understand that our operating partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. Although we have historically relied on our operators for these activities, we may in the future seek to take a portion of our production in kind and internally manage the marketing activities for such production; however, this would be costly and inefficient based on our current average working interest ownership. The price at which our production is sold is generally tied to the spot market for oil or natural gas. The price at which our oil production is sold typically reflects a discount to the WTI benchmark price. This differential primarily represents the transportation costs in moving the oil from wellhead to refinery and will fluctuate based on availability of pipeline, rail and other transportation methods. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price.

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Competition

Although we plan to focus on a target asset class and deal size where we believe that competition and costs are reduced as compared to the broader oil and natural gas industry, the acquisition market for non-operated and operated properties remains intensely competitive, and we will compete with other oil and natural gas companies for acquisitions, some of which have substantially greater resources than us and may be able to pay more for properties.

There are currently only two public companies with a focus on acquiring non-operated assets, with an enterprise value of approximately $6 billion as of December 31, 2022. Public companies that directly manage and operate assets are potentially net sellers of non-operated assets, which makes them potential partners and sources of deals for us.

Other sources of competition might come from new IPOs, which is a market that has been largely unavailable to non-operators, as evidenced by the fact that in the last 10 years there has not been a single traditional IPO of a non-operated focused company. Special Purpose Acquisition Companies (“SPACs”) that seek to take advantage of the non-operated market dynamic are another source of potential competition. New sources of capital like asset-backed securitizations and insurance company balance sheet investments have also made the non-operated sector a focus.

We believe our management is particularly suited to capitalize on this opportunity and generate attractive returns given our deep energy acquisition experience and relationships in the non-operated sector, which we believe will help us in deal-sourcing, asset selection, underwriting and financing.

Finally, the emerging impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and technological advances in energy generation devices may result in reduced demand for the oil and natural gas we produce.

Title to Our Properties

Prior to completing an acquisition of non-operated working or royalty interests, we perform a title review on each tract to be acquired. Our title review is meant to confirm the quantum of non-operated working and royalty interest owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related burdens.

In addition to our initial title work, operators often will conduct a thorough title examination prior to drilling a well. Should our title work uncover any further title defects, we will perform curative work with respect to such defects. We believe that the title to our assets is satisfactory in all material respects.

Our oil and natural gas properties are subject to customary royalty and other interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. Indebtedness under our Revolving Credit Facility is secured by liens on substantially all our assets. We do not believe that any of these burdens materially interfere with the use of our properties or the operation of our business.

Seasonality

Winter weather events and conditions, such as ice storms, blizzards and freezing conditions, and lease stipulations can limit or temporarily halt the drilling and producing activities of our operators and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operators and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operators’ operations.

Regulation and Environmental Matters

Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas acquisition, development and production industry as a whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas development, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the development and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, limitations or prohibitions on the venting or flaring of natural gas, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the current presidential administration has indicated that it expects to impose additional federal regulations limiting access to and production from federal lands, although recent executive actions to pause drilling on federal lands have been subject to ongoing litigation. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, many states

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impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market- based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost-of-service filing. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. On January 20, 2022, FERC established a new price index for the five-year period which commenced on July 1, 2021.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the

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environment, and relating to safety and health. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend will likely continue. These laws and regulations may:

■require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

■limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

■impose substantial liabilities for pollution resulting from our operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their rules and regulations, and violations can be subject to fines, injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no known material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.

CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. RCRA, and comparable state statutes, govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although the RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Recent regulation and litigation that has been brought against others in the industry under the RCRA concern liability for earthquakes that were allegedly caused by injection of oil field wastes.

The ESA seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize a covered species or its habitat. The ESA provides for criminal penalties for willful violations of the ESA. Other statutes that provide protection to animal and plant species and that may apply to our operators’ activities include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operators are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered or threatened could subject our company (directly or indirectly through our operators) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.

The CAA controls air emissions from oil and natural gas production and natural gas processing operations, among other sources. EPA regulations under the CAA include NSPS for the oil and natural gas source category to address emissions of sulfur dioxide and VOCs, NAAQS for certain criteria pollutants and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.

On November 2, 2021, EPA proposed to revise and add to the NSPS program rules. These rules, if adopted, could have a significant impact on the upstream and midstream oil and natural gas sectors. The proposed rule would impose further restrictions on methane and VOC emissions for new and modified facilities in the oil and natural gas sector. The proposed rules also would regulate, for the first time under the NSPS program, existing oil and natural gas facilities. Specifically as it concerns existing sources, the EPA’s proposed new rule would require states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. EPA issued a supplemental proposed rule strengthening and expanding the proposed methane regulations on November 11, 2022. Separately, the BLM has proposed its own rules on methane emissions and waste prevention for operations on federal lands. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations-sponsored Paris Agreement calls for parties to set and achieve individually-determined greenhouse gas emission reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021.

These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment or restrictions on operations could have a material adverse impact on our business, results of operations and financial condition.

The CWA imposes restrictions and controls on the discharge of produced waters and other pollutants into WOTUS. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The

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CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The meaning of WOTUS has been heavily litigated and the subject of rulemaking in recent years. EPA and the Corps latest WOTUS definition will take effect on March 20, 2023. The Supreme Court is also expected to rule on certain aspects of the definition in mid-2023. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of our properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of our properties. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The OPA amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. As such, a violation of the OPA has the potential to adversely affect our business.

The CAA, CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the SDWA. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into a wellbore to create cracks in the deep-rock formation to stimulate gas production. Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Congress continues to consider legislation to amend the SDWA to address hydraulic fracturing operations. In addition, in 2020, the Supreme Court held that the CWA requires a discharge permit if the addition of pollutants through groundwater is the “functional equivalent” of a direct discharge from the point source into navigable waters. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans. If in the future CWA permitting is required for saltwater injection wells as a result of the 2020 Supreme Court ruling, the costs of permitting and compliance for injection well operations by the companies that operate the Properties could increase.

Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. Several states, including Montana and North Dakota where our properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states, including Colorado, have enacted bans on hydraulic fracturing. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. However, the Colorado legislature subsequently enacted “SB 101” that gave significant local control over oil and natural gas well head operations. Municipalities in Colorado have enacted local rules restricting oil and natural gas operations based on SB 101. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations.

The NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. Many of the activities of our third-party operators are covered under NEPA. Some activities are subject to robust NEPA review which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. Other activities are covered under categorical exclusions which results in a shorter NEPA review process. In April 2022, the Biden Administration finalized a rule to undue changes to NEPA enacted under the Trump Administration. The April 2022 rule promulgation is considered phase one of a two-phase review of the 2020 NEPA Rule that was announced by the Biden Administration to emphasize the need to review federal actions for climate change and environmental justice impacts, among other factors. These new and (if enacted) additional

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anticipated changes to the NEPA review process would affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.

Climate Change

Significant studies and research have been devoted to climate change, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on our properties. More recently, in January 2023, the Council on Environmental Quality released updated guidance for agency consideration of GHG emissions and climate change impacts in environmental reviews, which includes, among other recommendations, best practices for analyzing and communicating climate change effects.

Congress has from time to time considered legislation to reduce emissions of GHGs. Most recently, in August 2022, Congress passed, and President Biden signed, the Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 establishes a program designed to reduce methane emissions from certain oil and natural gas facilities, which includes a charge on methane emissions above certain thresholds. In addition, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. For example, although EPA regulations implementing the methane charge requirements associated with the Inflation Reduction Act of 2022 have not yet been developed, the future implementation of these requirements could result in direct costs for our operators based on methane emissions above set thresholds or require capital expenditure by our operators to reduce their emissions. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from our properties. For a more detailed discussion of the risks associated with climate change legislation or regulation, see Part I. Item 1A Risk Factors Risks Relating to Legal and Regulatory Matters—The adoption of climate change legislation or regulations restricting emissions of carbon dioxide, methane, and other greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.”

In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. The industry could also be impacted by governmental initiatives aimed at encouraging fuel conservation and a shift to alternative energy sources. For more information, see Part I. Item 1A, Risk Factors, Risks Relating to our Business—Increased attention to ESG matters may impact our business” and “—Fuel conservation measures and related governmental initiatives, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.”

Finally, climate changes may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes and other climatic events; if any of these effects were to occur, they could have an adverse effect on the operations of our operating partners, and ultimately, our business.

Human Capital Management

As of December 31, 2022, we had 40 full time employees. We may hire additional personnel as appropriate. We also may use the services of independent consultants and contractors to perform various professional services. We are focused on attracting, engaging, developing, retaining and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with excellent training and career development opportunities to enable employees to thrive and achieve their career goals.

Corporate Information

The Company’s corporate website can be found at https://vitesse-vts.com/. The Company makes available free of charge at this website (under the “Investor Relations – SEC Filings” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q, and its Current Reports on Form 8-K. In addition to its reports filed or furnished with the SEC, the Company publicly discloses material information from time to time in its press releases and Investor presentations, all of which are accessible through the website under the heading “Investor Relations” and the subheading “News & Events.” The Company’s Code of Business Conduct and

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Ethics, Corporate Governance Guidelines, and the charters of the Audit, Compensation, Nominating, Governance and Environmental and Social Responsibility Committees of the Board of Directors are available on the Company’s website under the heading “Investor Relations”, the subheading “Governance,” and the subheading “Governance Documents.” References to the Company's website in this Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Form 10-K.

Office Locations

Our principal executive offices are located at 9200 E Mineral Ave, Suite 200, Centennial, CO 80112. Our current office space consists of approximately 15,000 square feet of leased space. We entered into a new office lease agreement in December 2022 which commences in October 2023 for approximately 22,000 square feet of leased space located at 5619 DTC Parkway, Suite 150, Greenwood Village, CO 80111. We believe the new office space will be sufficient to meet our needs as well as support future growth as necessary.

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Item 1A. Risk Factors

You should carefully consider the following risks and other information in this Form 10-K. The following risks have generally been separated into five groups: risks relating to our common stock, risks relating to our business, risks relating to our indebtedness, risks relating to the recent Spin-Off and risks relating to legal and regulatory matters. If any of the following events actually occur, our business, financial condition and results of operations could be materially adversely affected, the trading price of our common stock could decline and you could lose all or part of your investment. Additional risks and uncertainties that we do not presently know about or currently believe are not material may also adversely affect our business, financial condition and results of operations.

Summary Risk Factors

We believe that the risks associated with our business, and consequently the risks associated with an investment in our equity or debt securities, fall within the following categories:

Risks Relating to Our Common Stock

■Vitesse is an emerging growth company and the information we provide stockholders may be different from information provided by other public companies, which may result in a less active trading market for our common stock and higher volatility in our stock price.

■Although we expect to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock.

■Certain provisions in our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage takeovers.

■Your percentage ownership in Vitesse may be diluted in the future.

■Our Amended and Restated Certificate of Incorporation designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could may limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.

Risks Relating to Our Business

■Oil and natural gas prices are volatile. Extended declines in oil and natural gas prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.

■Due to previous declines in oil and natural gas prices, we have in the past taken writedowns of our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties in the future.

■Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our total reserves.

■The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

■As a non-operator, the successful development of our assets relies extensively on third parties, which could have an adverse effect on our results of operations.

■We could experience periods of higher costs as activity levels fluctuate or if oil and natural gas prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.

■The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, these undeveloped reserves may not be ultimately developed or produced.

■Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.

■The majority of our producing properties are located in the Williston Basin, making us vulnerable to risks associated with operating in one major geographic area.

■The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.

■Deficiencies of title to our interests could significantly affect our financial condition.

■Inflation could adversely impact our ability to control our costs, including the operating expenses and capital costs of our operators.

■Our derivatives activities could adversely affect our profitability, cash flow, results of operations and financial condition.

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■Asset retirement costs may be difficult to predict and may be substantial. Unplanned costs could divert resources from other projects.

Risks Relating to Our Indebtedness

■Any significant reduction in the borrowing base under our Revolving Credit Facility may negatively impact our liquidity and could adversely affect our business and financial results.

■Our Revolving Credit Facility and other agreements governing indebtedness may contain operating and financial restrictions that may restrict our business and financing activities.

■Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and limited by requirements under our Revolving Credit Facility.

■Variable rate indebtedness could subject us to interest rate risk, which could cause our debt service obligations to increase significantly.

■We may be adversely affected by developments in the SOFR market, changes in the methods by which SOFR is determined or the use of alternative reference rates.

■Our business plan requires the expenditure of significant capital, which we may be unable to obtain on favorable terms or at all.

Risks Relating to the Recent Spin-Off

■If the Distribution does not qualify as a transaction that is tax-free for U.S. federal income tax purposes, Jefferies and holders of Jefferies common stock who received shares of Vitesse common stock in connection with the Spin-Off could be subject to significant tax liability.

■We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, which may reduce our strategic and operating flexibility.

■We could have an indemnification obligation to Jefferies in certain circumstances if the Distribution were determined not to qualify for tax-free treatment for U.S. federal tax purposes, or in certain other circumstances, which could materially adversely affect our business, financial condition and results of operations.

■We may be unable to achieve some or all of the benefits that we expect to achieve from the Spin-Off, which could materially adversely affect our business, financial condition and results of operations.

■Our management and accounting systems may not be adequately prepared to meet the reporting and other requirements to which we have become subject following the Spin-Off, and we have and will continue to incur increased costs as a result of being an independent publicly traded company.

■Certain members of management and directors may face actual or potential conflicts of interest.

Risks Relating to Legal and Regulatory Matters

■The current presidential administration, acting through the executive branch and/or in coordination with Congress, already has ordered or proposed, and could enact additional rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.

■Taxable gain or loss on the sale of our common stock could be more or less than expected.

■The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.

■Our business involves the selling and shipping by rail of oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.

■Some stockholders might be deemed to have received a taxable distribution as a result of our repurchase of our own stock.

■Our derivative activities expose us to potential regulatory risks.

■Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

We describe these and other risks in much greater detail below.

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Risks Relating to Our Common Stock

An active, liquid trading market for our common stock may not develop, which may limit your ability to sell your shares.

The Spin-Off occurred in January 2023. Therefore, there has been a public market for our common stock for a short period of time. Although we have listed our common stock on the NYSE under the symbol “VTS,” an active trading market for our common stock may not be sustained. A public trading market having the desirable characteristics of depth, liquidity and orderliness depends upon the existence of willing buyers and sellers at any given time, such existence being dependent upon the individual decisions of buyers and sellers over which neither we nor any market maker has control. The failure of an active and liquid trading market to develop and continue would likely have a material adverse effect on the value of our common stock. An inactive market may also impair our ability to raise capital to continue to fund operations by issuing shares and may impair our ability to acquire other companies or assets by using our shares as consideration.

We cannot predict the prices at which our common stock may trade. The market price of our common stock may fluctuate widely, depending on many factors, some of which may be beyond our control, including:

■actual or anticipated fluctuations in our business, financial condition and results of operations due to factors related to our business;

■competition in the oil and natural gas industry and our ability to compete successfully;

■success or failure of our business strategies;

■our ability to retain and recruit qualified personnel;

■our quarterly or annual earnings, or those of other companies in our industry;

■our level of indebtedness, our ability to make payments on or service our indebtedness and our ability to obtain financing as needed;

■announcements by us or our competitors of significant acquisitions or dispositions;

■changes in accounting standards, policies, guidance, interpretations or principles;

■the failure of securities analysts to cover our common stock;

■changes in earnings estimates by securities analysts or our ability to meet those estimates;

■the operating and stock price performance of other comparable companies;

■investor perception of our company and the oil and natural gas industry;

■overall market fluctuations, including the cyclical nature of the oil and natural gas market;

■results from any material litigation or government investigation;

■changes in laws and regulations (including tax laws and regulations) affecting our business; and

■general economic conditions, credit and capital market conditions and other external factors.

Furthermore, our business profile and market capitalization may not fit the investment objectives of some Jefferies shareholders and, as a result, these Jefferies shareholders may sell their shares of our common stock. Low trading volume for our stock may occur if, among other reasons, an active trading market does not develop. This would amplify the effect of the above factors on our stock price volatility.

Vitesse is an emerging growth company and the information we provide stockholders may be different from information provided by other public companies, which may result in a less active trading market for our common stock and higher volatility in our stock price.

Vitesse is an “emerging growth company” as defined by the Jumpstart Our Business Startups Act of 2012. We will continue to be an emerging growth company until the earliest to occur of the following:

■the last day of the fiscal year in which our total annual gross revenues first meet or exceed $1.235 billion (as adjusted for inflation);

■the date on which we have, during the prior three-year period, issued more than $1.0 billion in non-convertible debt;

■the last day of the fiscal year in which we (1) have an aggregate worldwide market value of common stock held by non-affiliates of $700 million or more (measured at the end of each fiscal year) as of the last business day of our most recently completed second fiscal quarter and (2) have been a reporting company under the Exchange Act for at least one year (and filed at least one annual report under the Exchange Act); or

■the last day of the fiscal year following the fifth anniversary of the date of the first sale of our common stock pursuant to an effective registration statement under the Securities Act.

For as long as we are an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including, but not limited to:

■not being required to comply with the auditor attestation requirements in the assessment of our internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act of 2002;

■exemption from new or revised financial accounting standards applicable to public companies until such standards are also applicable to private companies;

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■reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements and registration statements; and

■exemptions from the requirement of holding a nonbinding advisory vote on executive compensation and stockholder approval on golden parachute compensation not previously approved.

We may choose to take advantage of some or all of these reduced burdens. For example, we have taken advantage of the reduced disclosure obligations regarding executive compensation in this Annual Report on Form 10-K. For as long as we take advantage of the reduced reporting obligations, the information we provide stockholders may be different from information provided by other public companies. In addition, it is possible that some investors will find our common stock less attractive as a result of these elections, which may result in a less active trading market for our common stock and higher volatility in our stock price.

In addition, we may take advantage of the extended transition period that allows an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. Our election to use the extended transition period permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the extended transition period and who will comply with new or revised financial accounting standards.

Although we expect to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock.

The timing, declaration, amount of and payment of future dividends, if any, to stockholders will fall within the discretion of our Board. Our Board’s decisions regarding the payment of future dividends, if any, will depend upon many factors, including our financial condition, earnings, capital requirements of our business, covenants associated with certain of our debt service obligations, legal requirements or limitations, industry practice, and other factors deemed relevant by our Board. We have not adopted, and do not currently expect to adopt, a separate written dividend policy to reflect our Board’s policy. For more information, see Part II, Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, “Dividend Policy.” For a description of the covenants limiting our ability to pay dividends and distributions, see “—Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and limited by requirements under our Revolving Credit Facility.” There can be no assurance that we will pay a dividend in the future or continue to pay any dividend if we do commence paying dividends.

Certain provisions in our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage takeovers.

Several provisions of our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage, delay or prevent a merger or acquisition that is opposed by our Board. These include provisions that:

■prevent our stockholders from calling a special meeting or acting by written consent;

■require advance notice of any stockholder nomination for the election of directors or any stockholder proposal;

■provide for a plurality voting standard in contested director elections;

■authorize only our Board to fill director vacancies and newly created directorships;

■authorize our Board to adopt, amend or repeal our Amended and Restated Bylaws without stockholder approval; and

■authorize our Board to issue one or more series of “blank check” preferred stock.

In addition, Section 203 of the DGCL, prohibits a Delaware corporation from engaging in a business combination with any interested stockholder for a period of three years following the date the person became an interested stockholder, subject to certain exceptions. In general, Section 203 of the DGCL defines an “interested stockholder” as an entity or person who, together with the entity’s or person’s affiliates, beneficially owns, or is an affiliate of the corporation and within three years prior to the time of determination of interested stockholder status did own, 15% or more of the outstanding voting stock of the corporation. A Delaware corporation may “opt out” of these provisions with an express provision in its certificate of incorporation. We have not opted out of Section 203 of the DGCL in our Amended and Restated Certificate of Incorporation.

These and other provisions of our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage, delay or prevent certain types of transactions involving an actual or a threatened acquisition or change in control of us including unsolicited takeover attempts, even though the transaction may offer our stockholders the opportunity to sell their shares of our common stock at a price above the prevailing market price.

Your percentage ownership in Vitesse may be diluted in the future.

Your percentage ownership in Vitesse may be diluted in the future because of the settlement or exercise of equity-based awards that have been granted and will continue to grant to our directors, officers and other employees under our equity incentive plan. In addition, we may issue equity as all or part of the consideration paid for acquisitions and strategic investments that we may make in the future or as necessary to finance our ongoing operations.

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In addition, our Amended and Restated Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock with respect to dividends and distributions, as our Board may generally determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example, we could grant the holders of preferred stock the right to elect some number of the members of our Board in all events or upon the happening of specified events, or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences that we could assign to holders of preferred stock could affect the residual value of our common stock.

Our Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.

Our Amended and Restated Certificate of Incorporation provides that, in all cases to the fullest extent permitted by law, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for:

■any derivative action or proceeding brought on our behalf;

■any action or proceeding asserting a claim of breach of a fiduciary duty owed by any current or former director, officer or other employee or stockholder of our company to us or our stockholders;

■any action or proceeding asserting a claim arising pursuant to, or seeking to enforce any right, obligation or remedy under, any provision of Delaware law or our Amended and Restated Certificate of Incorporation or our Amended and Restated Bylaws (with respect to each, as may be amended from time to time); or

■any action or proceeding asserting a claim governed by the internal affairs doctrine or any other action asserting an “internal corporate claim” as that term is defined in Section 115 of the DGCL.

However, if the Court of Chancery of Delaware does not have jurisdiction, the action or proceeding may be brought in any other state or U.S. federal court located within the State of Delaware. Further, our Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, to the fullest extent permitted by law, the U.S. federal district courts are the sole and exclusive forum for any complaint asserting a cause of action arising under U.S. federal securities laws.

Any person holding, purchasing or otherwise acquiring any interest in shares of capital stock of us will be deemed to have notice of and have consented to this provision and deemed to have waived any argument relating to the inconvenience of the forum in connection with any action or proceeding described in this provision. This provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits. Alternatively, if a court of competent jurisdiction were to find this provision of our Amended and Restated Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.

Risks Relating to Our Business

Oil and natural gas prices are volatile. Extended declines in oil and natural gas prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.

The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years. The prices we receive for our oil and natural gas production heavily influence our production, revenue, cash flows, profitability, reserve bookings and access to capital. Although we seek to mitigate volatility and potential declines in oil and natural gas prices through derivative arrangements that hedge a portion of our expected production, this merely seeks to mitigate (not eliminate) these risks, and such activities come with their own risks.

The prices we receive for our oil and natural gas production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

■changes in global supply and demand for oil and natural gas;

■changes in NYMEX WTI oil prices and NYMEX Henry Hub natural gas prices;

■the volatility and uncertainty of regional pricing differentials;

■future repurchases (or additional possible releases) of oil from the strategic petroleum reserve by the United States Department of Energy;

■the actions of OPEC and other major oil producing countries;

■worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics (such as the global COVID-19 coronavirus outbreak);

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■the price and quantity of imports of foreign oil and natural gas;

■political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;

■the outbreak or escalation of military hostilities, including between Russia and Ukraine, and the potential destabilizing effect such conflicts may pose for the European continent or the global oil and natural gas markets;

■inflation;

■the level of global oil and natural gas exploration, production activity and inventories;

■changes in U.S. energy policy;

■weather conditions;

■outbreak of disease;

■technological advances affecting energy consumption;

■domestic and foreign governmental taxes, tariffs and/or regulations;

■proximity and capacity of processing, gathering, and storage facilities, oil and natural gas pipelines and other transportation facilities;

■the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and

■the price and availability of alternative fuels.

These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices. A substantial or extended decline in oil or natural gas prices, such as the significant and rapid decline that occurred in 2020, has resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent oil and natural gas prices received from production are insufficient to fund planned capital expenditures, we may be required to reduce spending or borrow or issue additional equity to cover any such shortfall. Lower oil and natural gas prices may limit our ability to comply with the covenants under our Revolving Credit Facility and/or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

Our operators’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including:

■declines in oil or natural gas prices;

■infrastructure limitations, such as the natural gas gathering and processing constraints experienced in the Williston Basin in 2019;

■the high cost, shortages or delays of equipment, materials and services;

■unexpected operational events, pipeline ruptures or spills, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents;

■title problems;

■pipe or cement failures and casing collapses;

■lost or damaged oilfield development and services tools;

■laws, regulations, and other initiatives related to environmental matters, including those addressing alternative energy sources, the phase-out of fossil fuel vehicles and the risks of global climate change;

■compliance with environmental and other governmental requirements;

■increases in severance taxes;

■regulations, restrictions, moratoria and bans on hydraulic fracturing;

■unusual or unexpected geological formations, and pressure or irregularities in formations;

■loss of drilling fluid circulations;

■environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

■fires, blowouts, craterings and explosions;

■uncontrollable flows of oil, natural gas or well fluids;

■pipeline capacity curtailments; and

■demand from investors to return capital to investors and/or conduct share repurchases.

In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us.

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Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Due to previous declines in oil and natural gas prices, we have in the past taken writedowns of our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties in the future.

In 2020, we were required to write down the carrying value of certain of our oil and natural gas properties, and further writedowns could be required in the future. Under the successful efforts 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. 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.

We review our oil and natural gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our oil and natural gas properties and compare such cash flows to the carrying amount of the proved oil and natural gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust our proved oil and natural gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future oil and natural gas 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.

A continued period of low prices may force us to incur further material write-downs of our oil and natural gas properties, which could have a material effect on the value of our properties and cause the value of our securities to decline. Additionally, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. We have in the past and could in the future incur additional impairments of oil and natural gas properties which may be material.

We have incurred net losses in the past, in part due to fluctuations in oil and gas prices, and we may incur such losses again in the future.

We had net income of $118.9 million, net income of $18.1 million, net loss of $8.9 million and net loss of $7.4 million during the years ended December 31, 2022, November 30, 2021 and 2020 and the month ended December 31, 2021, respectively. To the extent our production is not hedged, we are exposed to declines in oil and natural gas prices, and our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. In prior periods, such declines have led to net losses. For example, our net loss for the year ended November 30, 2020 was largely caused by a decrease in oil and natural gas revenue, due primarily to a decrease in the average realized oil and natural gas prices. Unrealized hedging losses on commodity derivatives attributable to significant increases in oil prices may also cause a net loss for a given period.

In addition, fluctuations in oil and natural gas prices have impacted our unit-based compensation expense for prior periods and may impact our stock-based compensation expense. For example, in prior periods we have experienced increases to our unit-based compensation expense primarily due to increased oil and natural gas prices causing the estimated fair value of the liabilities associated with such unit-based compensation to increase, which contributed to net losses recorded during such periods. As a result of the foregoing and other factors, we may continue to incur net losses in the future.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our total reserves.

Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty. No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating, and development costs. Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.

We routinely make estimates of oil and natural gas reserves in connection with managing our business and preparing reports to our lenders and investors, including in some cases estimates prepared by our internal reserve engineers and professionals that are

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not reviewed or audited by an independent reserve engineering firm. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, reserve engineers and other advisors to make accurate assumptions. Any significant variance from these assumptions by actual figures could greatly affect our estimates of total reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based result in the actual quantities of oil and natural gas our operators ultimately recover being different from our reserve estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Form 10-K, subsequent reports we file with the SEC or other company materials.

Our future success depends on our ability to replace reserves.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. We have added significant net wells and production from wellbore-only acquisitions, where we don’t hold the underlying leasehold interest that would entitle us to participate in future wells. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.

We may acquire significant amounts of unproved property to further our development efforts. Development and drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon existing properties. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our capital in our properties and reserves.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

We base the estimated discounted future net cash flows from our proved reserves using Standardized Measure and PV-10, each of which uses specified pricing and cost assumptions. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as the volume, pricing and duration of our hedging contracts; actual prices we receive for oil and natural gas; our actual operating costs in producing oil and natural gas; the amount and timing of our capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. For example, our estimated proved reserves as of December 31, 2022 were calculated under SEC rules by applying year-end SEC prices based on the twelve-month unweighted arithmetic average of the first day of the month oil and natural gas prices for such year end of $94.14 per Bbl and $6.36 per MMBtu, which for certain periods during this time were substantially different from the available market prices. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our business depends on transportation and processing facilities and other assets that are owned by third parties.

The marketability of our oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding the Dakota Access Pipeline), could result in a substantial increase in costs, declines in realized oil and natural gas prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. In recent periods, we experienced significant delays and production curtailments, and declines in realized natural gas prices, that we believe were due in part to natural gas gathering and processing constraints in the Williston Basin. The negative effects arising from these and similar circumstances may last for an extended period of time. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third-party oil trucking to transport a significant portion of our production to third-party transportation pipelines, rail loading facilities and other market access points. In addition, the third

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parties on whom operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting business on our oil and natural gas properties. Further, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development and increased regulation of pipelines by PHMSA. In recent years, PHMSA has increased regulation of onshore gas transmission systems, hazardous liquids pipelines, and gas gathering systems. For example, in November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines, and therefore could result in less capacity to transport our products by pipeline. Further, although we do not expect to incur direct costs as a result of increased PHMSA regulation, additional regulation could impact rates charged by our operators and impact their ability to enter into gathering and transportation agreements, which costs could be passed through to us.

The Dakota Access Pipeline (the “DAPL”), a major pipeline transporting oil from the Williston Basin, is subject to ongoing litigation that could threaten its continued operation. In July 2020, a federal district court vacated the DAPL’s easement to cross the Missouri River at Lake Oahe and ordered the pipeline be shut down pending the completion of an environmental impact statement (“EIS”) to determine whether the DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The shut-down order was later reversed on appeal and the DAPL currently remains in operation while the Corps conducts the review, which is currently anticipated to be completed in the spring of 2023. Following completion of the EIS, the Corps will determine whether to grant the DAPL an easement to cross the Missouri River at Lake Oahe or to shut down the pipeline. Moreover, the EIS or the Corps’ decision with respect to an easement may subsequently be challenged in court. As a result, a shut-down remains possible, and there is no guarantee that the DAPL will be permitted to continue operations following the completion of the EIS. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect our business, results of operations and financial condition.

Seasonal weather conditions, which may be impacted by climate change, may adversely affect our operators’ ability to conduct drilling and completion activities and to sell oil and natural gas for periods of time, in some of the areas where our properties are located.

Seasonal weather conditions can limit drilling and completion activities, selling oil and natural gas, and other operations in some of our operating areas. In the Williston Basin, drilling and other oil and natural gas activities on our properties can be adversely affected during the winter months by severe winter weather and drilling on our properties is generally performed during the summer and fall months. These seasonal constraints can pose challenges for meeting well drilling objectives and increase competition for equipment, supplies and personnel during the summer and fall months, which could lead to shortages and increase costs or delay operations. Additionally, many municipalities impose weight restrictions on the paved roads that lead to jobsites due to the muddy conditions caused by spring thaws. This could limit access to jobsites and operators’ ability to service wells in these areas.

The frequency and severity of severe winter weather conditions which impact our business activities may also be impacted by the effects of climate change. Energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes. Increased energy use due to weather changes may require us to invest in order to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. To the extent the frequency of extreme weather events increases, this could increase our operators’ costs. If any of these results occur, it could have an adverse effect on our assets and cause us to incur costs in preparing for and responding to them. If any such effects were to occur, our financial condition and results of operations would be materially adversely affected.

As a non-operator, the successful development of our assets relies extensively on third parties, which could have an adverse effect on our results of operations.

We have only participated in wells operated by third parties. The success of our business operations depends on the timing of drilling activities and success of our third-party operators. If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operations would be adversely affected.

These risks are heightened in a low oil and natural gas price environment, which may present significant challenges to our operators. The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital. Oil and natural gas prices and/or other conditions have in the past and may in the future cause oil and natural gas operators to file for bankruptcy. The insolvency of an operator of any of our properties, the failure of an operator of any of our properties to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and natural gas leases jointly owned with the operator or another insolvent owner.

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Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations to other owners of working interests), which may not be in our best interests. We may have no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on our operators could prevent us from realizing our target returns for those locations. The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including oil and natural gas prices and other factors generally affecting the oil and natural gas industry’s operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.

The inability of one or more of our operators to meet their obligations to us may adversely affect our financial results.

Our exposures to credit risk are, in part, through receivables resulting from the sale of our oil and natural gas production, which operators market on our behalf to energy marketing companies, refineries and their affiliates. We are subject to credit risk due to the relative concentration of our oil and natural gas receivables with a limited number of operators. This concentration may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. A low oil and natural gas price environment may strain our operators, which could heighten this risk. The inability or failure of our operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We could experience periods of higher costs as activity levels fluctuate or if oil and natural gas prices rise. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.

An increase in oil and natural gas prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operators’ ability to conduct desired or expected operations. In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing oil and natural gas prices as producers seek to increase production in order to capitalize on higher oil and natural gas prices. In situations where cost inflation exceeds oil and natural gas price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and profitability.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, these undeveloped reserves may not be ultimately developed or produced.

Approximately 38% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2022. Development of undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.

We intend to continue to expand our operations in part through acquisitions. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential recoverable reserves. On-site inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an on-site inspection is undertaken. Any acquisition involves other potential risks, including, among other things:

■the validity of our assumptions about reserves, future production, revenues and costs;

■a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;

■a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

■the ultimate value of any contingent consideration agreed to be paid in an acquisition;

■dilution to stockholders if we use equity as consideration for, or to finance, acquisitions;

■the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

■geological risk, which refers to the risk that hydrocarbons may not be present or, if present, may not be recoverable economically;

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■an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

■an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.

We may also acquire multiple assets in a single transaction. Portfolio acquisitions via joint-venture or other structures are more complex and expensive than single project acquisitions, and the risk that a multiple-project acquisition will not close may be greater than in a single-project acquisition. An acquisition of a portfolio of projects may result in our ownership of projects in geographically dispersed markets which place additional demands on our ability to manage such operations. A seller may require that a group of projects be purchased as a package, even though one or more of the projects in the portfolio does not meet our strategic objectives. In such cases, we may attempt to make a joint bid with another buyer, and such other buyer may default on its obligations.

Further, we may acquire properties subject to known or unknown liabilities and with limited or no recourse to the former owners or operators. As a result, if liability were asserted against us based upon such properties, we may have to pay substantial sums to dispute or remedy the matter, which could adversely affect our profitability. Unknown liabilities with respect to assets acquired could include, for example: liabilities for clean-up of undiscovered or undisclosed environmental contamination; claims by developers, site owners, vendors or other persons relating to the asset or project site; liabilities incurred in the ordinary course of business; and claims for indemnification by general partners, directors, officers and others indemnified by the former owners of the asset or project sites.

We may be unable to successfully integrate any assets we may acquire in the future into our business or achieve the anticipated benefits of such acquisitions.

Our ability to achieve the anticipated benefits of any future acquisitions will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including:

■recoverable reserves;

■future oil and natural gas prices and their appropriate differentials;

■availability and cost of transportation of production to markets;

■availability and cost of drilling equipment and of skilled personnel;

■development and operating costs including access to water and potential environmental and other liabilities; and

■regulatory, permitting and similar matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we have performed reviews of the subject properties that we believe to be generally consistent with industry practices. The reviews are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm. Data used in such reviews are typically furnished by the seller or obtained from publicly available sources. Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the acquired properties may differ materially after such data is reviewed by an independent petroleum engineering firm or further by us. On-site inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an on-site inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. We are often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities associated with the assets acquired in our recent acquisitions, we are entitled to indemnification for only certain operational liabilities. The integration process may be subject to delays or changed circumstances, and we can give no assurance that our recently acquired assets will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of such acquisitions will materialize.

The majority of our producing properties are located in the Williston Basin, making us vulnerable to risks associated with operating in one major geographic area.

Our oil and natural gas properties are focused on the Williston Basin, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our oil and natural gas properties are not as diversified geographically as some of our competitors, our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.

The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.

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Our success depends heavily upon the continued contributions of those members of our management team whose knowledge, relationships with industry participants, leadership and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on our management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry and will use our management team’s relationships with industry participants to enter into strategic relationships. The members of our management team may terminate their employment with our company at any time. If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.

Deficiencies of title to our leased interests could significantly affect our financial condition.

We typically do not incur the expense of a title examination prior to acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights. If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights have been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value or be eliminated. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights may be lost. It is generally our practice not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we typically rely upon the judgment of our own oil and natural gas landmen who conduct due diligence and perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the company acting as the operator of the well to obtain a title examination of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of operations. Our failure to obtain perfect title to our leaseholds may adversely affect our current production and reserves and our ability in the future to increase production and reserves.

We conduct business in a highly competitive industry.

The oil and natural gas industry is highly competitive. The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.

Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities.

Our competitors also include those entities with greater technical, physical and financial resources. Finally, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us. If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.

The COVID-19 pandemic has had, and may continue to have, an adverse effect on our financial condition and results of operations.

We face risks related to public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in oil prices in 2020 and had and could in the future continue to have an adverse impact on our financial condition and results of operations. Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, we continue to monitor the effects of the pandemic on our operations. As a result of COVID-19, our operations, and

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those of our operators, have and may continue to experience delays or disruptions and temporary suspensions of operations. In addition, our results of operations and financial condition have been and may continue to be adversely affected by COVID-19.

The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened in the United States, we cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may adversely affect our results of operations and financial condition in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.

The ongoing military conflict between Ukraine and Russia has caused unstable market and economic conditions and is expected to have additional global consequences, such as heightened risks of cyberattacks. Our business, financial condition, and results of operations may be materially adversely affected by the negative global and economic impact resulting from the military conflict in Ukraine or any other geopolitical tensions.

U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions and the start of the military conflict between Russia and Ukraine. On February 24, 2022, a full-scale military invasion of Ukraine by Russian troops began. Although the length and impact of the ongoing military conflict is highly unpredictable, the military conflict in Ukraine has led to market disruptions, including significant volatility in oil and natural gas prices, credit and capital markets, as well as supply chain disruptions. Various of Russia’s actions have led to sanctions and other penalties being levied by the United States, the European Union, and other countries, as well as other public and private actors and companies, against Russia and certain other geographic areas, including restrictions on imports of Russian oil, LNG and coal. These disruptions in the oil and natural gas markets have caused, and could continue to cause, significant volatility in energy prices, which could have a material effect on our business. Additional potential sanctions and penalties have also been proposed and/or threatened.

In addition, the United States and other countries have imposed sanctions on Russia which increases the risk that Russia, as a retaliatory action, may launch cyberattacks against the United States, its government, infrastructure and businesses. On March 21, 2022, the Biden Administration issued warnings about the potential for Russia to engage in malicious cyber activity against the United States in response to the economic sanctions that have been imposed.

Prolonged unfavorable economic conditions or uncertainty as a result of the military conflict between Russia and Ukraine may adversely affect our business, financial condition, and results of operations. Any of the foregoing may also magnify the impact of other risks described in this Form 10-K.

Inflation could adversely impact our ability to control our costs, including the operating expenses and capital costs of our operators.

Although inflation in the United States has been relatively low in recent years, it rose significantly beginning in the second half of 2021 and has continued to rise in 2022. This is believed to be the result of the economic impact from the COVID-19 pandemic, including the effects of global supply chain disruptions and government stimulus packages, among other factors. Global, industry-wide supply chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase as well as scarcity of certain products and raw materials. We have experienced drilling and completion cost increases of approximately 10% between 2021 and 2022, and we cannot predict the extent of any future increases. To the extent elevated inflation remains, our operators may experience further cost increases for their operations, including oilfield services, labor costs, and equipment if drilling activity in our operators’ areas of operations increases. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations.

Our derivatives activities could adversely affect our profitability, cash flow, results of operations and financial condition.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures. See Part II, Item 7A, Quantitative and Qualitative Disclosure About Market Risk, “Commodity Price Risk.” By using derivative instrument contracts to reduce our exposure to adverse fluctuations in the price of oil and natural gas, we could limit the benefit we would receive from increases in the prices for oil and natural gas, which could have an adverse effect on our profitability, cash flow, results of operations and financial condition. Likewise, to the extent our production is not hedged, we are exposed to declines in oil and natural gas prices, and our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our balance sheet as assets or liabilities and in our

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statements of operations as gain (loss) on commodity derivatives, net. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivatives transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater oil and natural gas price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts; our production is less than expected; or there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make it unable to perform under the terms of the contracts, and we may not be able to realize the benefit of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Asset retirement costs may be difficult to predict and may be substantial. Unplanned costs could divert resources from other projects.

We are responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “asset retirement.” We accrue a liability for asset retirement costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. It may be difficult for us to predict such asset retirement costs. If asset retirement is required before economic depletion of our properties or if our estimates of the costs of asset retirement exceed the value of the reserves remaining at any particular time to cover such asset retirement costs, we may have to draw on funds from other sources to satisfy such costs, which may be substantial. The use of other funds to satisfy such asset retirement costs could impair our ability to dedicate our capital to other areas of our business.

We depend on computer and telecommunications systems, and failures in our systems or cyber security threats, attacks or other disruptions could significantly disrupt our business operations.

We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that we, or these third parties, could incur interruptions from cyber security attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. Furthermore, various third-party resources that we rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyber-attacks or similar events that are entirely outside our control, and any such events could significantly disrupt our business operations and/or have a material adverse effect on our results of operations. To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future.

In addition, our operators face various security threats, including cyber security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of their facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to operations and could have a material adverse effect on our financial position, results of operations or cash flows. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject operations on our oil and natural gas properties to increased risks. Any future terrorist attack at our operators’ facilities, or those of their purchasers or vendors, could have a material adverse effect on our financial condition and operations.

Decarbonization measures and related governmental initiatives, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.

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Decarbonization measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

Our business could also be impacted by governmental initiatives to encourage the conservation of energy or the use of alternative energy sources. For example, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; eliminating subsidies provided to the fossil fuel industry; reducing non-CO2 GHG emissions, such as methane and nitrous oxide; and increasing the emphasis on climate-related risks across government agencies and economic sectors. In addition, in August 2022, Congress passed, and President Biden signed, the Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 includes a variety of clean-energy tax credits and establishes a program designed to reduce methane emissions from oil and gas operations. These initiatives or similar state or federal initiatives to reduce energy consumption or encourage a shift away from fossil fuels could reduce demand for hydrocarbons and have a material adverse effect on our earnings, cash flows and financial condition.

Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will continue to rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.

The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected.

Increased attention to ESG matters may impact our business.

Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, and increasing consumer demand for alternatives to oil and natural gas may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change and any related negative public perception regarding our industry, for example, may result in demand shifts for natural gas and oil products, increased litigation risk, and increased regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may, of their own accord, elect not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

Risks Relating to Our Indebtedness

Any significant reduction in the borrowing base under our Revolving Credit Facility may negatively impact our liquidity and could adversely affect our business and financial results.

Availability under our Revolving Credit Facility is subject to a borrowing base, with scheduled semiannual and other elective borrowing base redeterminations based upon, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the Revolving Credit Facility. As a result of these borrowing base redeterminations, the lenders under the Revolving Credit Facility are able to unilaterally determine and adjust the borrowing base and the borrowings permitted to be outstanding under our Revolving Credit Facility. Reductions in estimates of our producing oil and natural gas reserves could result in a reduction of our borrowing base thereunder. The same could also arise from other factors, including but not limited to lower commodity prices or production; operating difficulties; changes in oil and natural gas reserve engineering; increased operating and/or capital costs; lending requirements or regulations; or other factors affecting our lenders’ ability or willingness to

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lend (including factors that may be unrelated to our company). Any significant reduction in our borrowing base could result in a default under current and/or future debt instruments, negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operations and cash flow. Further, if the outstanding borrowings under our Revolving Credit Facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. If we do not have sufficient funds and we are otherwise unable to arrange new financing, we may have to sell significant assets or take other actions. Any such sale or other actions could have a material adverse effect on our business and financial results.

Our Revolving Credit Facility and other agreements governing indebtedness may contain operating and financial restrictions that may restrict our business and financing activities.

Our Revolving Credit Facility contains a number of restrictive covenants that impose operating and financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests; make loans or certain investments; make certain acquisitions; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates. For a description of the covenants limiting our ability to pay dividends and distributions, see “—Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and limited by requirements under our Revolving Credit Facility.” In addition, the Revolving Credit Facility requires us to maintain compliance with certain financial covenants and other covenants. As a result of these covenants, we could be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of these covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Revolving Credit Facility or any other indebtedness could result in an event of default under our Revolving Credit Facility, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our Revolving Credit Facility occurs and remains uncured, the lenders thereunder would not be required to lend any additional amounts to us and could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be immediately due and payable. If the payment of debt were accelerated, cash flows from our operations may be insufficient to repay such debt in full and our stockholders could experience a partial or total loss of their investment. Our Revolving Credit Facility contains customary events of default, including the occurrence of a change in control.

An event of default or an acceleration under our Revolving Credit Facility could result in an event of default and an acceleration under other existing or future indebtedness. Conversely, an event of default or an acceleration under any other existing or future indebtedness could result in an event of default and an acceleration under our Revolving Credit Facility. In addition our obligations under the Revolving Credit Facility are collateralized by perfected liens and security interests on substantially all of our assets and if we default thereunder the lenders could seek to foreclose on our assets.

We may not be able to generate enough cash flow to meet our debt obligations or to pay dividends to our stockholders.

Our earnings and cash flow may vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, or to permit us to pay dividends to our stockholders. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt or dividends. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt; selling assets; reducing or delaying capital investments; or seeking to raise additional capital. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations or pay dividends. Our inability to generate sufficient cash flow to satisfy our debt obligations or pay dividends, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and limited by requirements under our Revolving Credit Facility.

Holders of our common stock are only entitled to receive such cash dividends as our Board, in its sole discretion, may declare out of funds legally available for such payments. We made cash distributions to our members totaling $0.0 million and $12.0 million during the years ended November 30, 2020 and 2021, respectively, and $6.0 million and $36.0 million during the one month and year ended December 31, 2021 and 2022, respectively. We cannot assure you that we will pay dividends in the future. Our Board

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may change the timing and amount of any future dividend payments or eliminate the payment of future dividends to our stockholders at its discretion, without notice to our stockholders. Any future determination relating to our dividend policy will be dependent on a variety of factors, including our financial condition, earnings, legal requirements, our general liquidity needs, and other factors that our Board deems relevant. Our ability to declare and pay dividends to our stockholders is subject to certain laws, regulations, and policies, including minimum capital requirements and, as a Delaware corporation, we are subject to certain restrictions on dividends under the DGCL. Under the DGCL, our Board may not authorize payment of a dividend unless it is either paid out of our surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, it is paid out of our net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. Finally, our ability to pay dividends to our stockholders is limited by covenants in the Revolving Credit Facility and may be limited by covenants in any debt agreements that we may enter into in the future. Under our Revolving Credit Facility, we are permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) our total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500 million, (2) our then-effective borrowing base, and (3) the then-effective aggregate amount of our lenders’ commitments and (b) as of the date of such distribution, the EBITDAX Ratio does not exceed 1.50 to 1.00. If our EBITDAX Ratio does not exceed 2.25 to 1.00, and if our total outstanding credit usage does not exceed 80% of the Commitments, we may also make distributions if our distributable free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and we have delivered a certificate to our lenders attesting to the foregoing. The summaries above do not purport to be complete and you are encouraged to read the Revolving Credit Facility, which is filed as an exhibit to this Annual Report on Form 10-K, for greater detail with respect to these provisions. As a consequence of these various limitations and restrictions, we may not be able to make, or may have to reduce or eliminate at any time, the payment of dividends on our common stock. If as a result, we are unable to pay dividends, investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Any change in the level of our dividends or the suspension of the payment thereof could have a material adverse effect on the market price of our common stock.

Variable rate indebtedness could subject us to interest rate risk, which could cause our debt service obligations to increase significantly.

Our Revolving Credit Facility uses SOFR as a reference rate for borrowings. Borrowings under our Revolving Credit Facility may bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

We may be adversely affected by developments in the SOFR market, changes in the methods by which SOFR is determined or the use of alternative reference rates.

In 2017, the U.K. Financial Conduct Authority announced that it intended to phase out LIBOR, and in 2021, it announced that all LIBOR settings will either cease to be provided by any administrator or no longer be representative immediately after December 31, 2021, in the case of one-week and two-month U.S. Dollar settings, and immediately after June 30, 2023, in the case of the remaining U.S. Dollar settings. The Federal Reserve also has advised banks to cease entering into new contracts that use U.S. Dollar LIBOR as a reference rate. The Alternative Refinance Rate Committee, a committee convened by the Federal Reserve that includes major market participants, has identified SOFR, a new index calculated by short-term repurchase agreements, backed by U.S. Treasury securities, as its preferred alternative rate for LIBOR in the U.S. Although SOFR appears to be the preferred replacement rate for U.S. Dollar LIBOR, it is unclear if other benchmarks may emerge. The consequences of these developments cannot be entirely predicted, and there can be no assurance that they will not result in financial market disruptions, significant increases in benchmark interest rates, substantially higher financing costs or a shortage of available debt financing, any of which could have an adverse effect on our business, financial position and results of operations, and our ability to pay dividends on our common stock.

Our business plan requires the expenditure of significant capital, which we may be unable to obtain on favorable terms or at all.

Our acquisition and development activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities and equity issuances. Cash reserves, cash from operations and borrowings under our Revolving Credit Facility may not be sufficient to fund our continuing operations and business plan and goals. We may require additional capital and we may be unable to obtain such capital if and when required. If our access to capital were limited due to numerous factors, which could include a decrease in operating cash flow due to lower oil and natural gas prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to develop our properties, replace our reserves and pursue our business plan and goals. We may not be able to incur additional debt under our Revolving Credit Facility, issue debt or equity, engage in asset sales or access other methods of financing on acceptable terms or at all. If the amount of capital we are able to raise from financing activities, together with our cash from operations, is not sufficient to satisfy our capital requirements, we may not be able to implement our business

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plan and may be required to scale back our operations, sell assets at unattractive prices or obtain financing on unattractive terms, any of which could adversely affect our business, results of operations and financial condition.

Risks Relating to the Recent Spin-Off

If the Distribution does not qualify as a transaction that is tax-free for U.S. federal income tax purposes, Jefferies and holders of Jefferies common stock who received shares of Vitesse common stock in connection with the Spin-Off could be subject to significant tax liability.

In connection with the Spin-Off, Jefferies’ received (1) the IRS Ruling and (2) an opinion of Morgan, Lewis & Bockius LLP, each substantially to the effect that, subject to the limitations specified therein and the accuracy of and compliance with certain representations, warranties and covenants, the Distribution, together with certain related transactions, qualified as a tax-free “reorganization” for U.S. federal income tax purposes under Section 368(a)(1)(D) of the Code and the Distribution qualified as a tax-free distribution within the meaning of Section 355 of the Code.

Although the IRS Ruling is generally binding on the IRS, the continuing validity of the IRS Ruling is subject to the accuracy of the factual representations made in the ruling request. In addition, Jefferies obtained an opinion of Morgan, Lewis & Bockius LLP as described above. In rendering its opinion, Morgan, Lewis & Bockius LLP relied on (1) customary representations and covenants made by Jefferies and Vitesse and (2) specified assumptions, including an assumption regarding the completion of the Distribution and certain related transactions in the manner contemplated by the transaction agreements. If any of those representations, covenants or assumptions are inaccurate, Morgan, Lewis & Bockius LLP’s opinion may not be valid and the tax consequences of the Distribution and certain related transactions could differ from those described above. Notwithstanding the receipt of the IRS Ruling and tax opinion, there can be no assurance that the IRS or a court will not take a contrary position and the consequences of the Distribution and certain related transactions to Jefferies and the holders of Jefferies common stock could be materially different from, and worse than, the U.S. federal income tax consequences described above.

If it were determined that the Distribution, together with certain related transactions, did not qualify as a tax-free “reorganization” within the meaning of Section 368(a)(1)(D) of the Code and the Distribution did not qualify as a distribution to which Section 355 of the Code applies, Jefferies would generally be subject to tax as if it sold the Vitesse common stock in a transaction taxable to Jefferies, which could result in a material tax liability. In addition, Jefferies shareholders who are U.S. holders would generally, for U.S. federal income tax purposes, be treated as receiving a distribution in an amount equal to the fair market value of our common stock received, which could result in a material tax liability.

We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, which may reduce our strategic and operating flexibility.

We agreed in the Tax Matters Agreement to covenants and indemnification obligations that address compliance with Section 355(e) of the Code. These covenants and indemnification obligations may limit our ability to pursue strategic transactions or engage in new businesses or other transactions that may otherwise maximize the value of our business, and might discourage or delay a strategic transaction that our stockholders may consider favorable, including share repurchases, stock issuances, certain asset dispositions and other strategic transactions. To preserve the tax-free treatment of the Distribution, and in addition to our indemnity obligations described above, the Tax Matters Agreement restricts us, for the two-year period following the Distribution, except in specific circumstances, from: (1) entering into any transaction pursuant to which all or a specified portion of our stock would be acquired, whether by merger or otherwise, (2) issuing equity securities in a manner that could reasonably be expected to have adverse consequences under Section 355(e) of the Code, (3) repurchasing shares of our stock other than in certain open-market transactions, (4) ceasing to actively conduct certain of our businesses or (5) taking or failing to take any other action that prevents the Distribution and certain related transactions from qualifying as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. For more information, see Part III, Item 13, Certain Relationships and Related Transactions, and Director Independence.

We could have an indemnification obligation to Jefferies in certain circumstances if the Distribution were determined not to qualify for tax-free treatment for U.S. federal tax purposes, or in certain other circumstances, which could materially adversely affect our business, financial condition and results of operations.

In connection with the Spin-Off, we entered into a Tax Matters Agreement with Jefferies. The terms of the Tax Matters Agreement require us to indemnify Jefferies and certain related parties for certain taxes and losses that (i) result primarily from, individually or in the aggregate, the breach of certain representations and warranties made by us (including in connection with the receipt by Jefferies of the IRS Ruling or the opinion of Morgan, Lewis & Bockius LLP regarding the tax treatment of the Distribution) or covenants made by us (applicable to actions or failures to act by us and our subsidiaries following the completion of the Distribution), (ii) are attributable to actions we take following the Distribution and result from the failure of the transfer of the Vitesse Energy equity interests to Vitesse, together with the Distribution, to qualify as (a) a reorganization described in Section 355(a) and Section 368(a)(1)(D) of the Code, (b) a transaction in which the stock distributed thereby is “qualified property” for purposes of Sections 355(c) and 361(c) of the Code, or (c) a transaction in which Jefferies, Vitesse and the holders of Jefferies common stock recognize no income or gain for U.S. federal income tax purposes pursuant to Sections 355, 361 and 1032 of the Code, including, as a result of the application of Section 355(e) of the Code to the Distribution as a result of a 50% or

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greater change in ownership as described below, or (iii) are attributable to taxes with respect to Vitesse Energy or Vitesse Oil for tax periods or portions thereof ending before the Distribution, including as may arise on audit.

Even if the Distribution were otherwise to qualify as a tax-free transaction under Section 368(a)(1)(D) and Section 355 of the Code, the Distribution would be taxable to Jefferies (but not to Jefferies’ shareholders) pursuant to Section 355(e) of the Code if there were a 50% or greater change in beneficial ownership of either Jefferies or Vitesse as part of a plan or series of related transactions that included the Distribution. For this purpose, any acquisitions of Jefferies or our common stock during the four-year period beginning on the date that begins two years before the date of the Distribution are presumed to be part of such a plan, although we or Jefferies may rebut that presumption. The U.S. federal income tax rules for determining whether there has been a 50% or greater change in beneficial ownership of Jefferies and Vitesse, and the period during which that change is measured, are complex and include the aggregation and attribution rules of Section 355(e)(4)(C) of the Code. The Distribution itself does not give rise to a change in beneficial ownership, and public trading of the stock of Jefferies or Vitesse by small stockholders does not give rise to a change in beneficial ownership, but many other transactions could do so. Such transactions may include (but are not limited to) acquisitions by Vitesse or Jefferies using its own stock, the merger or consolidation of Vitesse or Jefferies with or into another company, redemptions, recapitalizations, stock dividends, and sales or issuances of stock.

Any such indemnification obligation could materially adversely affect our business, financial condition and results of operations. For more information, see Part III, Item 13, Certain Relationships and Related Transactions, and Director Independence.

We may be unable to achieve some or all of the benefits that we expect to achieve from the Spin-Off, which could materially adversely affect our business, financial condition and results of operations.

We believe that, as an independent, publicly traded company, we are able to, among other things, more effectively articulate a clear investment proposition to attract a long-term investor base suited to our business, growth profile and capital allocation priorities. However, we may not achieve the anticipated benefits from the Spin-Off for a variety of reasons, including, among other things:

■we may be more susceptible to market fluctuations, the risk of takeover by third parties and other adverse events because our business will be less diversified than Jefferies’ businesses prior to the Spin-Off;

■the Spin-Off required us to incur significant costs, including accounting, tax, legal and other professional services costs, recruiting and relocation costs associated with hiring key senior management personnel who are new to our company, costs to retain key management personnel, tax costs and costs to shared systems and other unforeseen dis-synergy costs; and

■under the terms of the Tax Matters Agreement that we entered into with Jefferies, we will be restricted from taking certain actions that could cause the Spin-Off or other related transactions to fail to qualify as a tax-free transaction and these restrictions may limit us for a period of time from pursuing certain strategic transactions and equity issuances or engaging in other transactions that might increase the value of our business.

If we fail to achieve some or all of the benefits that we expect to achieve as an independent company, or do not achieve them in the time we expect, our business, financial condition and results of operations could be materially adversely affected.

Our management and accounting systems may not be adequately prepared to meet the reporting and other requirements to which we have become subject following the Spin-Off, and we have and will continue to incur increased costs as a result of being an independent publicly traded company.

As an independent public company, we are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act and are required to prepare our financial statements according to the rules and regulations required by the SEC. These reporting and other obligations place significant demands on our management and on administrative and operational resources. Moreover, to comply with these requirements, we have had to implement additional financial and management controls, reporting systems and procedures, and may need to hire additional accounting and finance staff. We expect to incur additional annual expenses related to these requirements. If our financial and management controls, reporting systems, information technology and procedures are not adequately prepared, our ability to comply with our financial reporting requirements and other rules that apply to reporting companies under the Exchange Act could be impaired. We have also incurred additional expenses in order to obtain new director and officer liability insurance.

Other significant changes may occur in our cost structure, management, financing and business operations as a result of operating as an independent publicly traded company. As such, our historical financial data may not be indicative of our future performance as an independent, publicly traded company. For additional information about our past financial performance and the basis of presentation of our financial statements, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and our historical consolidated financial statements and the notes thereto included in the section entitled “Index to Financial Statements.”

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Federal and state fraudulent transfer laws and New York and Delaware corporate law may permit a court to void the Distribution and related transactions, which could have a material adverse effect on our business, financial condition and results of operations.

In connection with the Distribution, Jefferies undertook the Pre-Spin-Off Transactions which, along with the Distribution, may be subject to challenge under federal and state fraudulent conveyance and transfer laws as well as under New York or Delaware corporate law. Under applicable laws, any transaction, contribution or distribution contemplated as part of the Distribution could be voided as a fraudulent transfer or conveyance if, among other things, the transferor received less than reasonably equivalent value or fair consideration in return and the transferor was insolvent or rendered insolvent by reason of the transfer.

We cannot be certain as to the standards a court would use to determine whether any entity involved in the Distribution was insolvent at the relevant time. In general, however, a court would look at various facts and circumstances related to the entity in question, including evaluation of whether:

■the sum of its debts, including contingent and unliquidated liabilities, was greater than the fair saleable value of all of its assets;

■the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

■it could pay its debts as they become due.

If a court were to find that any transaction, contribution or distribution involved in the Distribution was a fraudulent transfer or conveyance, the court could void the transaction, contribution or distribution. In addition, the Distribution could also be voided if a court were to find that it is not a legal distribution or dividend under New York or Delaware corporate law. The resulting complications, costs and expenses of either finding could have a material adverse effect on our business, financial condition and results of operations.

Certain members of management and directors may face actual or potential conflicts of interest.

Certain members of the management and directors of each of Jefferies and Vitesse may own common stock in both companies and Ms. Linda Adamany and Messrs. Brian Friedman and Joseph Steinberg, members of our Board, will also continue to serve on the Jefferies Board, and may be required to recuse themselves from deliberations relating to arrangements between us and Jefferies in the future. This ownership and directorship overlap could create, or appear to create, potential conflicts of interest when the management and directors of one company face decisions that could have different implications for themselves and the other company. For example, potential conflicts of interest could arise in connection with the resolution of any dispute regarding the terms of the agreements governing the separation and our relationship with Jefferies. These agreements include the Separation and Distribution Agreement, the Tax Matters Agreement and any commercial or service agreements between the parties or their affiliates. Potential conflicts of interest may also arise out of any commercial arrangements that we or Jefferies may enter into in the future. For more information, see Part III, Item 13, Certain Relationships and Related Transactions, and Director Independence, “Other Transactions and Relationships with Related Persons.”

Risks Relating to Legal and Regulatory Matters

The current presidential administration, acting through the executive branch and/or in coordination with Congress, already has ordered or proposed, and could enact additional rules and regulations that restrict our ability to acquire federal leases in the future and/or impose more onerous permitting and other costly environmental, health and safety requirements.

We are affected by the adoption of laws, regulations and policy directives that, for economic, environmental protection or other policy reasons, could curtail exploration and development drilling for oil and natural gas. For example, in January 2021, President Biden signed an Executive Order directing the DOI to temporarily pause new oil and natural gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and natural gas leasing and permitting program. The order was subsequently blocked by a federal district court within 13 protesting states, including Montana. The DOI’s comprehensive review of the federal leasing program resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate. In addition, in November 2021, the EPA proposed a new rule that would impose more stringent methane emissions standards for new and modified sources in the oil and natural gas industry, and to regulate existing sources in the oil and natural gas industry for the first time. A supplemental proposed rule, strengthened and expanded the proposed rule was published in November 2022. For existing sources, the current proposed rule would require each state to incorporate the emission guidelines proposed by the EPA or to adopt their own standards that achieve the same degree of emissions limitations. Further, in September 2021, President Biden publicly announced the Global Methane Pledge, an international pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030. These efforts, among others, are intended to support the current presidential administration’s stated goal of addressing climate change. Other actions that could be pursued by Congress or the Biden Administration include imposing more restrictive laws and regulations pertaining to permitting, limitations on GHG emissions, increased requirements for financial assurance and bonding for decommissioning liabilities, and carbon taxes. For example, in August 2022, Congress passed, and President Biden signed, the Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 includes a variety of clean-energy tax credits and establishes a program

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designed to reduce methane emissions from certain oil and natural gas facilities. Any of these administrative or Congressional actions could adversely affect our financial condition and results of operations by restricting the lands available for development and/or access to permits required for such development, or by imposing additional and costly environmental, health and safety requirements.

Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of natural gas and oil exploration and development companies and may adversely affect our operations and cash flows.

From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and natural gas companies. Such legislative changes have included, but not been limited to, (1) the repeal of the percentage depletion allowance for natural gas and oil properties, (2) the elimination of current deductions for intangible drilling and development costs, and (3) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the most recent federal tax legislation, certain of these changes were considered for inclusion in the proposed “Build Back Better Act” and Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and natural gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could adversely affect our operations and cash flows.

Taxable gain or loss on the sale of our common stock could be more or less than expected.

If a stockholder sells our common stock, the stockholder will recognize gain or loss equal to the difference between the amount realized and the holder’s tax basis in the shares of common stock sold. A stockholder’s basis in our common stock may be adjusted during the course of its holding for various reasons, including being lowered as a result of certain distributions on our common stock, to the extent such distributions exceed our current and accumulated earnings and profits. In such a case, such excess will be treated as a tax free return of capital and will reduce a stockholder’s tax basis in our common stock. Such reduction in basis, to the extent that it shall occur, will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the stockholder upon the sale of our common stock.

The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.

Distributions we pay with respect to our common stock will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a stockholder’s tax basis in their common stock and then as capital gain realized on the sale or exchange of such stock. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax with respect to distribution amounts that should have been classified as a tax-free return of capital. In such a case, a stockholder generally would have to timely file an amended U.S. tax return or an appropriate claim for refund to obtain a refund of the overpaid tax.

For a U.S. holder of our common stock, the IRS Forms 1099-DIV received from brokers may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a stockholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended U.S. federal, state or local income tax return). We will attempt to timely notify our stockholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our stockholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a stockholder’s tax return.

For a non-U.S. holder of our common stock, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the

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dividends are effectively connected with the conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that constitute a “dividend” for U.S. federal income tax purposes, or a stockholder’s broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a stockholder’s broker or other withholding agent may overwithhold taxes from distributions paid. In such a case, a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.

Some stockholders might be deemed to have received a taxable distribution as a result of our repurchase of our own stock.

Under certain circumstances, where a corporation repurchases its own stock, certain stockholders whose stocks have not been redeemed might be deemed to have received a taxable distribution. We do not currently know if any contemplated repurchase of our stocks would satisfy the circumstances under which such potential tax liability may arise. While we believe that any currently contemplated repurchase of our stocks, even if it were to satisfy such circumstances, would be an “isolated redemption” which would not result in taxable income to the non-redeemed stockholders, we have not requested, nor do we intend to request, a ruling to that effect. The IRS may disagree with this position, and a successful challenge by the IRS may thus result in taxable income to such non-redeemed stockholders.

Our business involves the selling and shipping by rail of oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.

A portion of our oil production is transported to market centers by rail. Derailments in North America of trains transporting oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids. Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport oil could increase our costs of doing business and limit our ability to transport and sell our oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, any derailment of oil involving oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.

Our derivative activities expose us to potential regulatory risks.

The FTC, FERC and the CFTC have statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to derivative activities that we undertake with respect to oil, natural gas or other energy commodities, we are required to observe the market-related regulations enforced by these agencies. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of volatile oil and natural gas price, interest rate and other risks associated with our business.

The Dodd-Frank Act contains measures aimed at increasing the transparency and stability of the OTC derivatives market and preventing excessive speculation. On January 14, 2021, the CFTC published a final rule imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents, though certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC’s requirements for certain enumerated “bona fide” derivative transactions. The CFTC also has adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns ten percent or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, although CFTC staff has granted relief until August 12, 2022 from various conditions and requirements in the final aggregation rules. These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of transactions. Moreover, such changes could materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low oil and natural gas prices.

The CFTC also has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use. If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions. The ultimate effect of these rules and any additional regulations on our business is uncertain.

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The full impact of the Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. In addition, it is possible that the current presidential administration could expand regulation of the OTC derivatives market and the entities that participate in that market through either the Dodd-Frank Act or the enactment of new legislation. Regulations issued under the Dodd-Frank Act (including any further regulations implemented thereunder) and any new legislation also may require certain counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. Such legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. We maintain an active hedging program related to oil and natural gas price risks. Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties. If we reduce our use of derivatives as a result of legislation and regulations or any resulting changes in the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on our debt obligations. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower oil and natural gas prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.

Our business is subject to complex federal, state, and local laws, as well as other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our operational interests, as operated by our third-party operators, are regulated extensively at the federal, state, tribal and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, our company (either directly or indirectly through our operators) could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our business and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we do business includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our business and limit the quantity of natural gas we may produce and sell. A major risk inherent in the drilling plans in which we participate is the need for our operators to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the development of our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff.

Failure to comply with federal, state and local environmental laws and regulations could result in substantial penalties and adversely affect our business.

All phases of the oil and natural gas business can present environmental risks and hazards and are subject to a variety of federal, state and municipal laws and regulations. Environmental laws and regulations, among other things, restrict and prohibit spills, releases or emissions of various substances produced in association with oil and natural gas operations, and require that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. There is risk of incurring significant environmental costs and liabilities as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to our business, and historical operations and waste disposal practices. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the imposition of injunctive relief.Additionally, our operators may be subject to operational restrictions or additional expenses regarding compliance with laws and regulations to protect endangered species, sensitive habitat, or other natural resources, which in turn could adversely impact our results of operations.

Environmental legislation and regulations are evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge, regardless of whether we were responsible for the release or contamination and regardless of

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whether our operators met previous standards in the industry at the time they were conducted. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of operations on our properties. The application of new or more stringent environmental laws and regulations to our business may cause us to curtail production or increase the costs of our production or development activities.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operators. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. However, in April 2012, the EPA issued regulations specifically applicable to the oil and natural gas industry that require operators to significantly reduce VOC emissions from gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into the air. The EPA issued additional regulations in 2016 targeting methane and VOC emissions from new, modified and reconstructed oil and natural gas wells that have been hydraulically fractured. Then in November 2021, the EPA proposed rules to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. From time to time, there have also been various other proposals to regulate hydraulic fracturing at the federal level. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply by us or our third-party operators could have a material adverse effect on our financial condition and results of operations.

In addition, in response to concerns relating to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities (so-called “induced seismicity”), regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

The adoption of climate change legislation or regulations restricting emissions of carbon dioxide, methane, and other greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.

The oil and natural gas industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state and local statutes, rules, orders and regulations that may, in turn, affect the operations and costs of the companies engaged in the oil and natural gas industry. In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which may include operations on the Properties. Additional GHG regulation could also result from the agreement crafted during the United Nations climate change conference in Paris, France in December 2015 (the “Paris Agreement”). Under the Paris Agreement, the United States committed to reducing its GHG emissions by 26-28% by the year 2025 as compared with 2005 levels. Moreover, in November 2021, at the U.N. Framework Convention on Climate Change 26th Conference of the Parties, the United States and the European Union advanced a Global Methane Pledge to reduce global methane emissions at least 30% from 2020 levels by 2030, which over 100 countries have signed. Congress has from time to time considered legislation to reduce emissions of GHGs. Most recently, in August 2022, Congress passed, and President Biden signed, the Inflation Reduction Act of 2022. The Inflation Reduction Act establishes a program designed to reduce methane emissions from certain oil and natural gas facilities, which includes a charge on methane emissions above certain thresholds.

In addition, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us or our operators, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs

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associated with their operations. For example, although EPA regulations implementing the methane charge requirements associated with the Inflation Reduction Act of 2022 have not yet been developed, the future implementation of these requirements could result in direct costs for our operators based on methane emissions above set thresholds or require capital expenditure by our operators to reduce their emissions. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our oil and natural gas properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas that may be imposed at the federal or state level, as well as federal, state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and natural gas assets. Finally, it should be noted that climate changes may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes and other climatic events; if any of these effects were to occur, they could have an adverse effect on us or our operators.

In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. ESG goals and programs, which may include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and stakeholders across the industry, and companies without robust ESG programs may find access to capital and investors more challenging in the future. Further, in March 2022, the SEC issued a proposed rule that would require public companies to disclose certain climate-related information, including climate-related risks, impacts, oversight and management, financial statement metrics and emissions, targets, goals and plans. While the proposed rule is not yet effective and is expected to be subject to a lengthy comment process, compliance with the proposed rule as drafted could result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations.

Wells in the Williston Basin of North Dakota, where we own significant oil and natural gas properties, produce natural gas as well as oil. Constraints in third party natural gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In 2014, the NDI Commission, North Dakota’s chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDI Commission requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. It is possible that other states in which we operate, including Montana, will require gas capture plans or otherwise institute new regulatory requirements in the future to reduce flaring.

Gas capture requirements and other regulatory requirements, in North Dakota or our other locations, could increase our operators’ operational costs and restrict production on our oil and natural gas properties, which could materially and adversely affect our financial condition, results of operations and cash flows. If our interpretation of the applicable regulations is incorrect, or if we receive a non-appealable order to pay royalty on past and future flared volumes in North Dakota, such royalty payments could materially and adversely affect our financial condition and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

From time to time we are subject to legal, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits and pending judicial matters. Based on our current knowledge, we believe that the amount or range of reasonably possible losses will not, either individually or in the aggregate, materially adversely affect our business, financial condition and results of operations.

The results of any litigation cannot be predicted with certainty, and an unfavorable resolution in any legal proceedings could materially affect our business, financial condition and results of operations. Regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources and other factors.

Item 4. Mine Safety Disclosures

None.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock trades on the New York Stock Exchange under the symbol “VTS.” The closing price for our common stock on February 15, 2023 was $18.60 per share.

Authorized Capital Stock

The Company has authorized 95,000,000 shares of common stock, par value $0.01 per share and 5,000,000 shares of preferred stock, par value $0.01 per share.

Shares Outstanding

As of February 1, 2023, we had 28,524,435 shares of our common stock outstanding, held by approximately 1,231 stockholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

Securities Authorized for Issuance Under Equity Compensation Plans

As of December 31, 2022, we did not maintain an equity compensation plan and none of our securities were available for issuance under an equity compensation plan. While the board of directors adopted the Vitesse Energy, Inc. Long-Term Incentive Plan in connection with the Spin-Off, it was not outstanding as of December 31, 2022. Accordingly, no equity compensation plan information table is provided.

Recent Sales of Unregistered Securities

In connection with its incorporation, on August 5, 2022, Vitesse issued 1,000 shares of its common stock at par value to Vitesse Energy Finance pursuant to Section 4(a)(2) of the Securities Act.

In connection with the Pre-Spin-Off Transactions, Vitesse Energy Finance and holders of vested Vitesse Energy MIUs (other than Messrs. Gerrity and Cree) transferred their respective equity interests in Vitesse Energy to Vitesse in exchange for 25,918,163 shares and 163,544 shares, respectively, of common stock of Vitesse. The transfers were consummated shortly before the Distribution. Shares of Vitesse common stock were issued to Vitesse Energy Finance and such holders of vested Vitesse Energy MIUs as consideration for their respective ownership interests in Vitesse Energy pursuant to Section 4(a)(2) of the Securities Act.

In connection with the Pre-Spin-Off Transactions, Jefferies Capital Partners and Gerrity Bakken transferred their respective equity interests in Vitesse Oil to Vitesse in exchange for 1,976,213 shares and 144,099 shares, respectively, of common stock of Vitesse. The transfers were consummated concurrently with the transfer of Vitesse Energy to Vitesse and shortly before the Distribution. Shares of Vitesse common stock were issued to Jefferies Capital Partners and Gerrity Bakken as consideration for their respective ownership interests in Vitesse Oil pursuant to Section 4(a)(2) of the Securities Act.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

Dividend Policy

We expect that we will initially pay quarterly cash dividends and dividend equivalents totaling approximately $66.0 million per fiscal year, of which the first quarterly dividend of approximately $16.5 million was approved by our Board for payment on March 31, 2023. Notwithstanding this current expectation regarding our dividend policy, the timing, declaration, amount of and payment of any dividends will be within the discretion of our Board and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt service obligations, legal requirements or limitations, industry practice, and other factors deemed relevant by our Board. Moreover, if as expected we determine to initially pay a dividend following the Distribution, there can be no assurance that we will continue to pay dividends in the same amounts or at all thereafter. We pay dividends out of distributable cash flow, which we define as Adjusted EBITDA less interest expense and cash taxes. During the year ended December 31, 2022, we generated Adjusted EBITDA of $167.6 million. Historically, we have used our distributable cash flow for multiple purposes, including capital expenditures (which includes acquisitions), repayment of debt and payment of distributions. Due to our strategy to grow oil and natural gas production levels during 2021 and 2022, we incurred levels of capital expenditures above a maintenance level. Given the amount of these capital expenditures and the discretionary amount of debt repaid, we would not have been able to pay a $66.0 million distribution during the year ended November 30, 2021. However, going forward, we expect to prioritize the dividend while sustaining production through maintenance capital expenditures. We have not adopted, and do not currently expect to adopt, a separate written dividend policy to reflect our Board’s policy. For a description of the covenants limiting our ability to pay dividends, see Part I. Item 1A Risk Factors—Risks Relating to Our Common Stock—Our ability to pay dividends to our stockholders is restricted by applicable laws and regulations and may be limited by requirements under our Revolving Credit

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Facility. The covenants under our Prior Revolving Credit Facility have not limited our ability to pay distributions in the amounts declared by our Board.

Item 6. Reserved

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our results of operations and financial condition together with our Audited Consolidated Financial Statements and the notes thereto included under the section entitled “Index to Financial Statements,” as well as the discussion in Part I. Items 1 and 2 Business and Properties.”This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions and projections about the oil and natural gas industry and our business and financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in Part I. Item 1A Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.”

Executive Overview

Our business strategy is focused on creating long-term stockholder value through the profitable acquisition, development and production of oil and natural gas assets at attractive rates of return, while maintaining a strong balance sheet and distributing a meaningful and growing dividend to our stockholders. We invest in non-operated minority working and mineral interests in oil and natural gas properties with our core area of focus in the Bakken and Three Forks formations of the Williston Basin of North Dakota and Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of December 31, 2022, we had a working interest in 5,338 gross (138.0 net) productive wells and 237 gross (5.8 net) wells that were being drilled or completed, and an additional 421 gross (10.0 net) wells that had been permitted for development by our operators. Our estimated proved reserves as of December 31, 2022 were 43,797 MBoe (70% oil) and our average production was 10,376 Boe per day during the year ended December 31, 2022.

Our financial and operating performance for the year ended December 31, 2022 included the following:

■Total revenue of $300.1 million for the year ended December 31, 2022.

■Cash flows from operations of $147.0 million for the year ended December 31, 2022.

■Net income of $118.9 million for the year ended December 31, 2022.

■Adjusted EBITDA of $167.6 million for the year ended December 31, 2022.

■Proved reserves of 43.8 MMBoe and $1.2 billion PV-10 value at December 31, 2022, as estimated by our third-party reserve engineers using SEC guidelines.

■Reduced outstanding indebtedness from $68.0 million at December 31, 2021 to $48.0 million at December 31, 2022.

■Paid $36.0 million in distributions to our equity holders for the year ended December 31, 2022. We discontinued making $6 million monthly distributions to our equity holders at mid-year in anticipation of the Spin-Off.

For a definition and reconciliation of Adjusted EBITDA to its most directly comparable financial measures in accordance with GAAP, see Part II. Item 7 Management Discussion and Analysis “Non-GAAP Financial Information.”

Industry Trends Impacting Our Business

Commodity prices are a significant factor impacting our acquisition and divestiture strategy, as well as the decisions of our operators in conducting their operations. Prices for oil and natural gas can be highly volatile. For instance, the COVID-19 pandemic and efforts to mitigate the spread of the disease, combined with OPEC actions in early 2020, led to spot and future prices of oil and natural gas falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Our operators in the Williston Basin responded by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells. Commodity prices, however, quickly reached pre-pandemic levels in the second half of 2021, and during the first nine months of 2022 only further accelerated upward, in part as a result of the Russian invasion of Ukraine. The ongoing conflict between Russia and Ukraine may have further global economic consequences, including disruptions of the global energy markets and the amplification of inflation and supply chain constraints, partially due to sanctions by the European Union, the United Kingdom and the United States on imports of oil and gas from Russia. On October 5, 2022, OPEC also announced a 2 MMBbl/d reduction in production quotas, the organization’s largest cut since the beginning of the COVID-19 pandemic.

As a result of such commodity price volatility, which we expect to continue into 2023, our earnings and operating cash flows can vary substantially, and are subject to external factors over which we have no control. While we do hedge a substantial portion of our production, we are still significantly subject to movements in commodity prices. Such volatility can make it difficult to predict future effects on our financial results and the decisions of our operators. Factors that we expect will continue to impact commodity prices include product demand connected with global economic conditions, industry production and inventory levels, the United States Department of Energy’s future planned repurchases (or additional possible releases) of oil from the strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC countries, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts (including invasion), civil

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unrest, pandemic or political uncertainty. Any of the foregoing can have a substantial impact on the prices of oil and natural gas, which in turn impacts the decision of our operators to drill and extract resources. Despite such commodity price volatility, we expect that our cash flow from operations and borrowing availability under our Revolving Credit Facility will allow us to meet our liquidity needs for the next twelve months.

Source of Our Revenues

We derive our revenues from the sale of oil and natural gas produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production. We have not hedged natural gas production since March 2022 due to the mismatch between our operators’ pricing formulas and settlement mechanics on natural gas hedges. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.

Principal Components of Our Cost Structure

Commodity price differentials. The price differential between our well head price for oil and the WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and the NYMEX benchmark price is primarily driven by BTU content along with gathering, processing and transportation costs.

Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (1) cash gains and losses we recognize on settled commodity derivatives during the period, and (2) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.

Production expenses. Production expenses are costs incurred to bring oil and natural gas out of the ground and to market, together with the costs incurred to maintain our producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.

Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a successful efforts company, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized. Accretion expense relates to the passage of time of our asset retirement obligations.

General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. For fiscal 2022, general and administrative expenses included non-recurring costs related to the Spin-Off.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Prior Revolving Credit Facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We do not capitalize any portion of the interest paid on applicable borrowings. We include the amortization of deferred financing costs, commitment fees and annual agency fees as interest expense.

Impairment expense. Under the successful efforts method of accounting, we review our oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and natural gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering, processing and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and natural gas properties in each depletion pool to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the aggregated oil and natural gas properties, no impairment is recorded. If the carrying amount of the oil and natural gas properties exceeds the undiscounted future net cash flows, we will record an impairment expense to reduce the carrying value to fair value as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates

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of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Income tax expense. Vitesse Energy, our predecessor, is a limited liability company. Accordingly, no provision for income taxes has been recorded, as the income, deductions, expenses, and credits of Vitesse Energy are reported on the income tax returns of Vitesse Energy’s members.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

■the timing and success of drilling and production activities by our operating partners;

■the prices and the supply and demand for oil, natural gas and NGLs;

■the quantity of oil and natural gas production from the wells in which we participate;

■changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil;

■our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and

■the level of our operating expenses.

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Denver-Julesburg and Powder River Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.

The price of oil can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market, particularly in the Williston Basin where a substantial majority of our revenues are derived. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region.

The price at which our oil production is sold typically reflects a discount to the NYMEX benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the NYMEX benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during the year ended December 31, 2022 was positive $0.04 per barrel, as compared to negative $3.31 per barrel during the year ended December 31, 2021, primarily due to favorable local market pricing as compared to the benchmark price. Our net realized gas price during the year ended December 31, 2022 was $7.92 per Mcf, representing 123% realization relative to average Henry Hub pricing, compared to a net realized gas price of $4.95 per Mcf during the twelve months ended December 31, 2021, representing a 132% realization relative to average Henry Hub pricing. Fluctuations in our price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering, and transportation costs, takeaway capacity relative to production levels, regional storage capacity, and seasonal refinery maintenance temporarily depressing demand.

Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant. During year ended December 31, 2022, the average authorization for expenditure cost for wells we elected to participate in was $7.4 million, compared to $6.9 million for the wells we elected to participate in during the twelve months ended December 31, 2021.

Market Conditions

The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, the war between Russia and Ukraine and the strength of the U.S. dollar can adversely impact oil prices.

Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as the growth in domestic oil production.

Prices for various quantities of oil, natural gas and NGLs that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the periods presented.

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	YEAR ENDED DECEMBER 31,		YEAR ENDED DECEMBER 31,		YEAR ENDED NOVEMBER 30,
Average NYMEX Prices (1)	2022		2021		2021		2020
Oil (per Bbl)	$	94.90	$	68.14	$	65.97	$	40.20
Natural Gas (per MMBtu)	6.45		3.89		3.79		2.00

(1)Based on average daily NYMEX closing prices.

The average calendar 2022 NYMEX oil price was $94.90 per barrel or 39% higher than the average NYMEX price per barrel in calendar 2021. Our settled derivatives decreased our realized oil price per barrel by $18.07 in calendar 2022 and decreased our realized oil price per barrel by $6.58 in calendar 2021. Our average 2022 realized oil price per barrel after reflecting settled derivatives was $76.09 compared to $58.16 in 2021. The average calendar 2022 NYMEX natural gas price was $6.45 per MMBtu, or 66% higher than the average NYMEX price per MMBtu in calendar 2021. Our settled derivatives decreased our realized natural gas price per Mcf by $0.08 in 2022 and by $0.12 in 2021. Our 2022 realized gas price per Mcf after reflecting settled derivatives was $7.84 compared to $4.83 in 2021, which was primarily driven by higher NYMEX pricing for natural gas and gas realization.

We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part II. Item 7A Quantitative and Qualitative Disclosures about Market Risk and Note 6 (“Derivative Instruments”) to the Audited Consolidated Financial Statements.

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Change in Fiscal Year End

On November 30, 2021, our Board and the Board of Managers of our predecessor approved a change in our fiscal year end and that of our predecessor from November 30 to December 31. As a result, Vitesse Energy's 2022 fiscal year began on January 1, 2022 and ended on December 31, 2022 and there was a transition period from December 1, 2021 to December 31, 2021 (the “Transition Period”). For the purposes of this discussion and analysis we have presented the income statement for the year ended December 31, 2021 in order to provide a comparison to the year ended December 31, 2022. The income statement for the year ended December 31, 2021 was derived as follows:


	YEAR ENDED NOVEMBER 30, 2021		PLUS: MONTH ENDED DECEMBER 31, 2021 (TRANSITION PERIOD)		LESS: MONTH ENDED DECEMBER 31, 2020		YEAR ENDED DECEMBER 31, 2021
Revenue
Oil	$	151,838	$	15,241	$	8,679	$	158,400
Natural gas	33,340		2,747		1,041		35,046
Total revenue	185,178		17,988		9,720		193,446
Operating Expenses
Production expense	43,910		3,794		3,143		44,561
Production taxes	14,535		1,340		863		15,012
General and administrative	10,581		950		793		10,738
Depletion, deprecation, amortization, and accretion	60,846		5,417		5,380		60,883
Unit-based compensation	1,409		2,628		—		4,037
Total operating expenses	131,281		14,129		10,179		135,231
Operating Income (Loss)	53,897		3,859		(459)		58,215
Other (Expense) Income
Commodity derivative (loss) gain, net	(32,590)		(10,982)		(3,681)		(39,891)
Interest expense	(3,207)		(237)		(319)		(3,125)
Other income	14		1		1		14
Total other (expense) income	(35,783)		(11,218)		(3,999)		(43,002)
Net Income (Loss)	$	18,114	$	(7,359)	$	(4,458)	$	15,213

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Results of Operations

Year Ended December 31, 2022 Compared with Year Ended December 31, 2021

The following table sets forth selected operating data for the periods indicated.



	YEAR ENDED DECEMBER 31,				INCREASE (DECREASE)
($ in thousands, except per unit data)	2022		2021		AMOUNT		PERCENT
Operating Results:
Revenue
Oil	$	242,467	$	158,400	$	84,067	53	%
Natural gas	57,603		35,046		22,557		64	%
Total revenue	$	300,070	$	193,446	$	106,624	55	%
Operating Expenses
Production	$	49,313	$	44,561	$	4,752	11	%
Production taxes	24,092		15,012		9,080		60	%
General and administrative	19,833		10,738		9,095		85	%
Depletion, depreciation, amortization, and accretion	63,732		60,883		2,849		5	%
Unit-based compensation	(10,766)		4,037		(14,803)		*nm
Interest Expense	$	4,153	$	3,125	$	1,028	33	%
Commodity Derivative Gain (Loss)	$	(30,830)	$	(39,891)	$	9,061	(23)	%
Production Data:
Oil (MBbls)	2,575		2,447		128		5	%
Natural gas (MMcf)	7,274		7,084		190		3	%
Combined volumes (MBoe)	3,787		3,627		160		4	%
Daily combined volumes (Boe/d)	10,376		9,937		439		4	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	94.16	$	64.74	$	29.42	45	%
Natural gas (per Mcf)	7.92		4.95		2.97		60	%
Combined (per Boe)	79.24		53.33		25.91		49	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	76.09	$	58.16	$	17.93	31	%
Natural gas (per Mcf)	7.84		4.83		3.01		62	%
Combined (per Boe)	66.79		48.67		18.12		37	%
Average Costs (per Boe):
Production	$	13.02	$	12.29	$	0.73	6	%
Production taxes	6.36		4.14		2.22		54	%
General and administrative	5.24		2.96		2.28		77	%
Depletion, depreciation, amortization, and accretion	16.83		16.79		0.04		—	%

*Not meaningful

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $300.1 million for the year ended December 31, 2022 from $193.4 million for the year ended December 31, 2021. The increase in oil and natural gas revenue was due to a 49% increase in the average realized prices per Boe before hedging, along with a 4% increase in production volumes for the year ended December 31, 2022. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by approximately $94.0 million, while the increase in production volumes increased oil and natural gas revenue by approximately $12.6 million.

Our oil price differential to the WTI benchmark price during the year ended December 31, 2022 was a favorable $0.04 per barrel, as compared to a negative $3.31per barrel during the year ended December 31, 2021, primarily due to favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2022 was

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$7.92 per Mcf, representing a 123% realization relative to average NYMEX pricing, compared to a net realized natural gas price of $4.95 per Mcf during the year ended December 31, 2021, representing a 132% realization relative to average NYMEX pricing. Fluctuations in our price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators pass through these costs in a different manner. Some operators may deduct these costs directly from our revenues while other operators may invoice them directly to us as lease operating expenses.

Production Expense. Production expense increased to $13.02 per Boe for the year ended December 31, 2022 from $12.29 per Boe for the year ended December 31, 2021. The increase per Boe for the year ended December 31, 2022 compared with the year ended December 31, 2021 was primarily related to higher expense related to workovers and inflationary pressure on service costs.

Production Tax Expense. Total production taxes increased to $24.1 million for the year ended December 31, 2022 from $15.0 million for the year ended December 31, 2021. Production taxes are primarily based on oil revenue and gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 8.0% and 7.8% for the years ended December 31, 2022 and 2021, respectively. The slight increase in the production tax rate for the year ended December 31, 2022 was due to a higher oil tax rate in North Dakota in 2022 triggered by higher oil prices.

General and Administrative Expense. General and administrative expense increased to $19.8 million for the year ended December 31, 2022 from $10.7 million for the year ended December 31, 2021. General and administrative expense on a per Boe basis increased to $5.24 for the year ended December 31, 2022 from $2.96 for the year ended December 31, 2021. The increase in general and administrative expense on a per Boe basis was primarily related to costs related to the Spin-Off of $7.9 million. Excluding cost related to the Spin-Off the per BOE rate in calendar 2022 would have been $3.15 per BOE. The slight increase in general and administrative expense per BOE, excluding the Spin-Off costs, was primarily due to legal fees incurred for our litigation against one operator regarding excessive deductions taken against our revenue.

DD&A. DD&A increased to $63.7 million for the year ended December 31, 2022 compared with $60.9 million for the year ended December 31, 2021. The increase of $2.8 million, or 5% was the result of a 4% increase in production and a minimal increase in the DD&A rate for the year ended December 31, 2022 compared with the year ended December 31, 2021. The increase in production accounted for a $2.7 million increase in DD&A expense while the increase in the DD&A rate accounted for a $0.1 million increase in DD&A expense.

For the year ended December 31, 2022, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $16.83 per Boe compared with $16.79 per Boe for the year ended December 31, 2021.

Unit-based Compensation. Unit-based compensation expense is recorded for in-substance call options granted to the founding members of management which are classified as liabilities and recorded at estimated fair value at each period end. Unit-based compensation expense is also recognized for management incentive units granted to other employees which are classified as liabilities until the holder has borne the risk of unit ownership. Unit-based compensation expense is recorded as these units vest and expense or contra-expense is recognized as the estimated fair value of the liability changes with market conditions. Unit-based compensation expense was a negative $10.8 million for the year ended December 31, 2022 compared to $4.0 million for the year ended December 31, 2021 primarily due to a reduced value of the options due to a shortened time until exercise and lower volatility as these instruments were settled in conjunction with the Spin-Off.

Interest Expense. Interest expense increased to $4.2 million for the year ended December 31, 2022 from $3.1 million for the year ended December 31, 2021. The increase for the year ended December 31, 2022 was due to a higher SOFR interest rate in the year ended December 31, 2022 despite the balance on our Prior Revolving Credit Facility declining to $48.0 million at December 31, 2022 from $68.0 million at December 31, 2021. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve throughout 2022.

Commodity Derivative Gain (Loss). Commodity derivative loss was $30.8 million for the year ended December 31, 2022 compared with a loss of $39.9 million for the year ended December 31, 2021. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

The mark-to-market fair value of the unsettled commodity derivative instruments will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower oil revenues in the future while losses indicate higher future oil revenues.

The table below summarizes our commodity derivative gains and losses that were recorded in the periods presented.

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	YEAR END DECEMBER 31,
	2022		2021
	(in thousands)
Realized gain (loss) on commodity derivatives (1)	$	(47,124)	$	(16,914)
Unrealized gain (loss) on commodity derivatives (1)	16,294		(22,977)
Total commodity derivative gain (loss)	$	(30,830)	$	(39,891)

(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the consolidated statements of operations included in this Form 10-K. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position.

In 2022, approximately 55% of our oil volumes and 6% of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $46.5 million and a realized loss on natural gas derivatives of $0.6 million after settlements. In 2021, approximately 47% of our oil volumes and 11% of our natural gas volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $16.1 million and a realized loss on natural gas derivatives of $0.8 million after settlements.

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Year Ended November 30, 2021 Compared with Year Ended November 30, 2020

The following table sets forth selected operating data for the periods indicated.



	YEAR ENDED NOVEMBER 30,				INCREASE (DECREASE)
($ in thousands, except per unit data)	2021		2020		AMOUNT		PERCENT
Operating Results:
Revenue
Oil	$	151,838	$	91,542	$	60,296	66	%
Natural gas	33,340		5,688		27,652		486	%
Total revenue	$	185,178	$	97,230	$	87,948	90	%
Operating Expenses
Production	$	43,910	$	41,731	$	2,179	5	%
Production taxes	14,535		9,173		5,362		58	%
General and administrative	10,581		9,196		1,385		15	%
Depletion, depreciation, amortization, and accretion	60,846		58,307		2,539		4	%
Impairment of proved oil and gas properties	—		13,200		(13,200)		*nm
Unit-based compensation	1,409		(544)		1,953		*nm
Interest Expense	$	3,207	$	4,679	$	(1,472)	(31)	%
Commodity Derivative Gain (Loss)	$	(32,590)	$	29,633	$	(62,223)	(210)	%
Production Data:
Oil (MBbls)	2,436		2,599		(163)		(6)	%
Natural gas (MMcf)	7,065		5,609		1,456		26	%
Combined volumes (MBoe)	3,613		3,534		79		2	%
Daily combined volumes (Boe/d)	9,899		9,655		244		3	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	62.34	$	35.22	$	27.12	77	%
Natural gas (per Mcf)	4.72		1.01		3.71		367	%
Combined (per Boe)	51.25		27.51		23.74		86	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	56.97	$	45.67	$	11.30	25	%
Natural gas (per Mcf)	4.60		1.01		3.59		355	%
Combined (per Boe)	47.40		35.20		12.20		35	%
Average Costs (per Boe):
Production	$	12.15	$	11.81	$	0.34	3	%
Production taxes	4.02		2.60		1.42		55	%