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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2026


o			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.)

5619 DTC Parkway, Suite 700 Greenwood Village, Colorado			80111
(Address of Principal Executive Offices)			(Zip Code)

(720) 361-2500

Registrant's telephone number, including area code

N/A

(Former name, former address and former fiscal year, if changed since last report)

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	VTS	New York Stock Exchange

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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes x No o

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


Large accelerated filer	o	Accelerated filer	x
Non-accelerated filer	o	Smaller reporting company	o
		Emerging growth company	x

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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. o

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

The registrant had outstanding 42,104,317 shares of common stock as of July 31, 2026.

Table of Contents

TABLE OF CONTENTS


		Page
	Cautionary Statement Concerning Forward-Looking Statements	4
	Glossary and Presentation of Financial and Operating Data	6
PART I	FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	9
	Condensed Consolidated Balance Sheets	9
	Condensed Consolidated Statements of Operations	10
	Condensed Consolidated Statements of Equity	11
	Condensed Consolidated Statements of Cash Flows	13
	Notes to the Condensed Consolidated Financial Statements	14

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	42

PART II	OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45
	Signatures	46

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

The information in this Form 10-Q 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 programs and extended length three-mile and four-mile lateral wells;

■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 identify, complete and successfully integrate acquisitions and achieve anticipated benefits of such acquisitions;

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

■extreme weather events, natural disasters, fluctuating regional and global weather conditions or patterns, pandemic, war (such as hostilities in the Middle East, including Iran, the conflict in Ukraine and the situation in Venezuela), financial or political instability, casualty losses and other matters beyond our control;

■changes in general economic conditions, including central bank policy actions, inflation and changes in U.S. trade policy and the imposition of and changes in tariffs;

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

■an indemnification obligation to Jefferies in connection with the Distribution or the qualification of the Distribution and certain related transactions as tax-free under the Code;

■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 future litigation;

■cyber-related risks;

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

■financial, regulatory, and political risks associated with societal responses to climate change;

■energy efficiency and technology trends;

■changes in the availability and cost of capital;

■large customer defaults; and

■labor relations.

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 II, Item 1A. Risk Factors in this Form 10-Q and Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2025, filed with the SEC on March 2, 2026.

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

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Any forward-looking statements, express or implied, included in this Form 10-Q 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-Q 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.

Table of Contents

GLOSSARY

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

■“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;

■“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;

■“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;

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

■“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;

■“DD&A” refers to depletion, depreciation, amortization and accretion;

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

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

■“EIA” refers to the Energy Information Administration;

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

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

■“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;

■“Jefferies” or “JFG” 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;

■“LTIP” refers to the Company’s long term incentive plan;

■“Lucero” refers to Lucero Energy Corp., a corporation existing under the Alberta Business Corporations Act except subsequent to April 24, 2025 when it refers to Lucero Energy ULC and PetroShale (US), Inc.;

■“Lucero Acquisition” refers to the strategic business combination transaction that closed on March 7, 2025 whereby Vitesse acquired all of the issued and outstanding Lucero common shares pursuant to the Lucero Plan of Arrangement, with Lucero becoming a wholly owned subsidiary of Vitesse;

■“Lucero Arrangement Agreement” refers to that certain Lucero Arrangement Agreement, dated December 15, 2024, between Vitesse and Lucero, a copy of which is attached to the Current Report on Form 8-K filed with the SEC on December 19, 2024;

■“Lucero Plan of Arrangement” refers to that certain Plan of Arrangement substantially in the form attached as Exhibit B to the Lucero Arrangement Agreement, and any amendments or variations thereto made in accordance with the Lucero Arrangement Agreement and the Plan of Arrangement or upon the direction of the Alberta Court, in the Final Order;

■“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;

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

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

■“NGLs” refer to natural gas liquids;

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

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

■“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;

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

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

■“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” 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;

■“PSU” refers to Performance Stock Units under the LTIP;

■“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 from the date that such undrilled location was initially classified as proved undeveloped unless specific circumstances justify a longer 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;

■“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;

■“RSU” refers to Restricted Stock Units under the LTIP;

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

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

■“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;

■“Stock Repurchase Program” refers to the stock repurchase program approved by the Board in February 2023 authorizing the repurchase of up to $60 million of the Company’s common stock;

■“Vitesse,” “we,” “our,” “us” and the “Company” (1) when used in regard to events prior to the Spin-Off, refer to Vitesse Energy and do not give effect to the consummation of the Pre-Spin-Off Transactions, and (2) when used in regard to events subsequent to the Spin-Off 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” and the “Predecessor” refer to Vitesse Energy, LLC and its consolidated subsidiaries;

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

■“WTI” refers to West Texas Intermediate.

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PRESENTATION OF FINANCIAL AND OPERATING DATA

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.

INDUSTRY AND MARKET DATA

This Form 10-Q 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-Q 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 may involve uncertainties and is subject to change based on various factors, including those discussed in the section entitled “Part II, Item 1A, Risk Factors.”

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PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

VITESSE ENERGY, INC.

Condensed Consolidated Balance Sheets (Unaudited)



	JUNE 30,		DECEMBER 31,
(in thousands, except shares)	2026		2025
Assets
Current Assets
Cash	$	884	$	1,328
Accrued revenue	52,429		30,620
Commodity derivatives	1,768		14,252
Prepaid expenses and other current assets	3,274		5,967
Total current assets	58,355		52,167
Oil and Gas Properties-Using the successful efforts method of accounting
Proved oil and gas properties	1,607,002		1,525,890
Less accumulated DD&A and impairment	(757,363)		(691,963)
Total oil and gas properties, net	849,639		833,927
Other Property and Equipment—Net	99		123
Commodity derivatives	8,950		184
Other noncurrent assets	6,604		6,949
Total assets	$	923,647	$	893,350
Liabilities and Equity
Current Liabilities
Accounts payable	$	11,832	$	11,803
Accrued liabilities	38,764		39,141
Commodity derivatives	4,293		—
Other current liabilities	327		307
Total current liabilities	55,216		51,251
Revolving credit facility	158,500		124,500
Deferred tax liability	64,804		67,493
Asset retirement obligations	15,612		14,022
Commodity derivatives	—		46
Other noncurrent liabilities	5,592		6,721
Total liabilities	$	299,724	$	264,033
Commitments and Contingencies (Note 9)
Equity
Preferred stock, $0.01 par value, 5,000,000 shares authorized; 0 shares issued at June 30, 2026 and December 31, 2025, respectively	$	—	$	—
Common stock, $0.01 par value, 95,000,000 shares authorized; 42,802,648 and 40,615,302 shares issued at June 30, 2026 and December 31, 2025, respectively	428		406
Additional paid-in capital	634,744		630,961
Accumulated deficit	(11,249)		(2,050)
Total equity	623,923		629,317
Total liabilities and equity	$	923,647	$	893,350

See notes to Condensed Consolidated Financial Statements

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VITESSE ENERGY, INC.

Condensed Consolidated Statements of Operations (Unaudited)



	FOR THE THREE MONTHS ENDED				FOR THE SIX MONTHS ENDED
	JUNE 30,				JUNE 30,
(In thousands, except share data)	2026		2025		2026		2025
Revenue
Oil	$	86,507	$	66,611	$	146,524	$	125,535
Natural gas	4,497		15,144		11,891		22,390
Total revenue	91,004		81,755		158,415		147,925
Operating Expenses
Lease operating expense	17,975		19,629		33,310		33,484
Production taxes	8,459		6,180		14,124		11,953
General and administrative	6,150		311		14,736		12,442
Depletion, depreciation, amortization, and accretion	34,809		34,576		65,996		61,139
Equity-based compensation	2,735		2,403		3,460		4,873
Total operating expenses	70,128		63,099		131,626		123,891
Operating Income	20,876		18,656		26,789		24,034
Other (Expense) Income
Commodity derivative gain (loss), net	22,043		18,451		(32,963)		18,279
Interest expense	(3,022)		(2,539)		(5,637)		(5,443)
Other (expense) income, net	(40)		(38)		(77)		126
Total other income (expense)	18,981		15,874		(38,677)		12,962

Income (Loss) Before Income Taxes	$	39,857	$	34,530	$	(11,888)	$	36,996

(Provision for) Benefit from Income Taxes	(6,776)		(9,871)		2,689		(9,669)

Net Income (Loss)	$	33,081	$	24,659	$	(9,199)	$	27,327

Weighted average common shares – basic	42,041,479		39,104,962		41,064,396		36,106,598
Weighted average common shares – diluted	42,852,652		40,967,995		41,064,396		38,043,765
Net income (loss) per common share – basic	$	0.79	$	0.62	$	(0.22)	$	0.76
Net income (loss) per common share – diluted	$	0.77	$	0.60	$	(0.22)	$	0.72

See notes to Condensed Consolidated Financial Statements

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VITESSE ENERGY, INC.

Condensed Consolidated Statements of Equity (Unaudited)



	Common Stock			Preferred Stock
(In thousands, except share data)	Shares	Amount		Shares	Amount		Additional Paid-In Capital		Accumulated Deficit		Total Equity
Balance—January 1, 2026	40,615,302	$	406	—	$	—	$	630,961	$	(2,050)	$	629,317
Net loss	—	—		—	—		—		(42,280)		(42,280)
Issuance of stock units, net of forfeitures	72,320	1		—	—		(893)		—		(892)
Equity-based compensation	—	—		—	—		2,093		—		2,093
Common stock dividends declared ($0.4375 per share)	—	—		—	—		(17,793)		—		(17,793)
Balance—March 31, 2026	40,687,622	$	407	—	$	—	$	614,368	$	(44,330)	$	570,445

Net income	—	—		—	—		—		33,081		33,081
Issuance of stock units, net of forfeitures	179,328	2		—	—		(6)		—		(4)
Issuance of common stock for Powder River Basin Acquisition, net of issuance costs	1,935,698	19		—	—		36,432		—		36,451
Equity-based compensation	—	—		—	—		2,741		—		2,741
Common stock dividends declared ($0.4375 per share)	—	—		—	—		(18,791)		—		(18,791)
Balance—June 30, 2026	42,802,648	$	428	—	$	—	$	634,744	$	(11,249)	$	623,923

See notes to Condensed Consolidated Financial Statements

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VITESSE ENERGY, INC.

Condensed Consolidated Statements of Equity (Unaudited)



	Common Stock			Preferred Stock
(In thousands, except share data)	Shares	Amount		Shares	Amount		Additional Paid-In Capital		Accumulated Earnings (Deficit)		Total Equity
Balance—January 1, 2025	32,650,889	$	326	—	$	—	$	505,133	$	(5,125)	$	500,334
Net income	—	—		—	—		—		2,668		2,668
Issuance of restricted stock units, net of forfeitures	150,165	1		—	—		87		—		88
Issuance of common stock to acquire Lucero	8,169,839	82		—	—		194,197		—		194,279
Equity-based compensation	—	—		—	—		2,469		—		2,469
Common stock dividends declared ($0.5625 per share)	—	—		—	—		(22,991)		—		(22,991)
Stock exchanged for tax withholding and retired	(345,255)	(3)		—	—		(9,154)		—		(9,157)
Balance—March 31, 2025	40,625,638	$	406	—	$	—	$	669,741	$	(2,457)	$	667,690

Net income	—	—		—	—		—		24,659		24,659
Issuance of restricted stock units, net of forfeitures	(8,336)	—		—	—		(182)		—		(182)
Equity-based compensation	—	—		—	—		2,665		—		2,665
Common stock dividends declared ($0.5625 per share)	—	—		—	—		(22,957)		—		(22,957)
Balance—June 30, 2025	40,617,302	$	406	—	$	—	$	649,267	$	22,202	$	671,875

See notes to Condensed Consolidated Financial Statements

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VITESSE ENERGY, INC.

Condensed Consolidated Statements of Cash Flows (Unaudited)



	FOR THE SIX MONTHS ENDED
	JUNE 30,
(in thousands)	2026		2025
Cash Flows from Operating Activities
Net (loss) income	$	(9,199)	$	27,327
Adjustments to reconcile net (loss) income to net cash from changes in operating activities:
Depletion, depreciation, amortization, and accretion	65,996		61,139
Unrealized loss (gain) on commodity derivative instruments	7,964		(12,325)
Equity-based compensation	3,460		4,873
Deferred income taxes	(2,689)		9,122
Amortization of debt issuance costs	469		421
Changes in operating assets and liabilities that provided (used) cash:
Accrued revenue	(21,809)		(2,263)
Prepaid expenses and other current assets	2,691		756
Accounts payable	6		(2,384)
Accrued liabilities	2,588		(3,502)
Other	(9)		341
Net cash provided by operating activities	49,468		83,505
Cash Flows from Investing Activities
Divestiture (Acquisition), net, of oil and gas properties	694		(1,647)
Development of oil and gas properties	(40,074)		(64,467)
Purchase of other property and equipment	(8)		(4)

Net cash used in Investing Activities	(39,388)		(66,118)
Cash Flows from Financing Activities
Proceeds from revolving credit facility	49,000		47,500
Repayments of revolving credit facility	(15,000)		(58,500)
Dividends paid	(44,131)		(47,834)
Cash acquired associated with the Lucero Acquisition	—		49,846
Equity issuance costs for Powder River Basin Acquisition	(131)		—
Stock exchanged for tax withholding	—		(9,157)
Debt issuance costs	(262)		(247)
Net cash used in Financing Activities	(10,524)		(18,392)
Net change in cash	(444)		(1,005)
Cash—Beginning of period	1,328		2,967
Cash—End of period	$	884	$	1,962
Supplemental Disclosure of Cash Flow Information
Cash paid for interest	$	3,625	$	5,169
Cash paid for income taxes	—		—
Supplemental Disclosure of Noncash Activity
Oil and gas properties included in accounts payable and accrued liabilities	$	29,565	$	43,550
Asset retirement obligations capitalized to oil and gas properties	1,025		3,075
Issuance of common stock related to acquisitions	36,582		194,279

See notes to Condensed Consolidated Financial Statements

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VITESSE ENERGY, INC.

Notes to the Condensed Consolidated Financial Statements

Note 1—Nature of Business

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

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

Note 2—Significant Accounting Policies

Principles of Consolidation

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

Interim Financial Statements

These financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, these financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted from these financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three and six months ended June 30, 2026 are not necessarily indicative of the results that may be expected for the year ending December 31, 2026. These financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2025 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025.

Segment and Geographic Information

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

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Depletion, depreciation, and amortization (“DD&A”) and the evaluation of proved oil and gas properties for impairment are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, which includes lack of control over future development plans as a non-operator. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. In addition, significant estimates include, but are not limited to, estimates relating to certain oil and natural gas revenues and expenses, fair value of assets acquired and liabilities

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assumed in business combinations, valuation of share-based compensation, and valuation of commodity derivative instruments. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant adverse impact to the Company’s business, financial condition, results of operations and cash flows.

Cash and Cash Equivalents

The Company considers all investments with an original maturity of three months or less when purchased to be cash equivalents. The Company held no cash equivalents as of June 30, 2026 and December 31, 2025. As of the consolidated balance sheet date and periodically throughout the quarter, balances of cash exceeded the federally insured limit.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas activities. Under this method of accounting, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized and depleted, net of estimated salvage values, using the units-of-production method on the basis of a reasonable aggregation of properties within a common geological structural feature or stratigraphic condition, such as a reservoir or field. The Company’s proved oil and gas reserve information was computed by applying the average first-day-of-the-month oil and gas price during the 12-month period ended on the balance sheet date. During the three and six months ended June 30, 2026, the Company recorded depletion expense of $34.5 million and $65.4 million, respectively. The Company’s depletion rate per Boe for the three and six months ended June 30, 2026 was $21.85 and $21.69, respectively. During the three and six months ended June 30, 2025, the Company recorded depletion expense of $34.3 million and $60.6 million, respectively. The Company’s depletion rate per Boe for the three and six months ended June 30, 2025 was $19.88 and $19.74, respectively.

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

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

The Company reviews its oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates the expected future cash flows of its oil and gas properties and compares such cash flows to the carrying amount of the proved oil and gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust its proved oil and gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future estimated commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures and operating expenses, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks. There were no proved oil and gas property impairments during the three and six months ended June 30, 2026 and 2025.

Asset Retirement Obligations (AROs)

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

Equity-Based Compensation

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

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Revenue Recognition

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

For the sale of produced oil and natural gas from wells in which the Company has non-operated revenue or royalty interests, the Company recognizes revenue based on the details included in the statements received from the operator. Any gathering, transportation, processing, production taxes, and other deductions included on the statements are recorded based on the information provided by the operator. The Company does not disclose the value of unsatisfied performance obligations as it applies the practical exemption for variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

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

Concentrations of Credit Risk

For each of the three and six months ended June 30, 2026, five operators accounted for 61 percent and 60 percent, respectively, of oil and natural gas revenue.

For the three and six months ended June 30, 2025, two and four operators accounted for 48 percent and 61 percent, respectively, of oil and natural gas revenue.

As of June 30, 2026 and December 31, 2025, three operators accounted for 57 percent and 50 percent, respectively, of oil and natural gas accrued revenue.

The Company’s non-operated oil and natural gas revenue is generated from the sale of oil and natural gas by operators on its behalf. The Company monitors the financial condition of its operators.

For operated properties during the three and six months ended June 30, 2026, two and three purchasers accounted for 82 percent and 80 percent, respectively, of the Company’s operated sales. During each of the three and six months ended June 30, 2025, one purchaser accounted for over 80 percent of the Company’s operated sales. The Company believes that the loss of a purchaser would not have a material adverse effect on the Company’s operations, as there are a number of alternative purchasers in the region.

Income Taxes

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

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The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of June 30, 2026.

Commodity Derivative Instruments

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

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

New Accounting Pronouncements

In November 2024, FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses (DISE). The ASU primarily requires companies to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The guidance will be applied on a prospective basis with the option to apply the standard retrospectively. The new guidance will be effective for the Company’s year ending December 31, 2027 and interim periods during the year ending December 31, 2028. The Company is assessing the disclosure implications of this ASU. This ASU is not expected to affect the Company's financial position, results of operations, or liquidity upon adoption.

Note 3—Oil and Gas Properties

Asset Acquisitions

Powder River Basin Acquisition

On April 8, 2026, the Company acquired proved oil and gas properties and proved leaseholds in the Powder River Basin. The purchase price was $35.0 million, with $1.6 million of upward post-effective date purchase price adjustments, for an aggregate preliminary purchase price of $36.6 million, which was settled in exchange for 1,935,698 shares of common stock of the Company. This transaction qualified as an asset acquisition; therefore, the oil and gas properties were recorded based on the value of the aggregate consideration transferred on the close date, plus an additional $0.3 million of transaction costs that were capitalized as a component of the assets acquired. Additionally, post-close cash settlements of $(1.1) million related to pre-close activity were recorded to proved oil and gas properties.

Additionally, during the three and six months ended June 30, 2026, the Company purchased proved oil and gas properties in multiple transactions for an aggregate cash purchase price of $0.7 million and $0.8 million, respectively.

During the six months ended June 30, 2025, the Company purchased proved oil and gas properties and proved leaseholds in multiple transactions for an aggregate cash purchase price of $1.6 million.

Divestitures

During the six months ended June 30, 2026, the Company had divestitures of proved oil and gas properties of $0.4 million.

Lucero Acquisition

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

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

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(in thousands except share and per share amounts)
Common stock issued to acquire Lucero	8,169,839
Vitesse closing stock price on March 6, 2025	$	23.78
Arrangement consideration	$	194,279

	Purchase Price Allocation
Assets Acquired
Cash and cash equivalents	$	49,846
Accrued revenue	4,897
Prepaid expenses and other current assets	1,296
Proved oil and gas properties	134,563
Deferred tax asset	14,306
Other noncurrent assets	160
Total assets acquired	$	205,068
Liabilities Assumed
Accounts payable	$	408
Accrued liabilities	7,148
Commodity derivatives	158
Asset retirement obligations	3,075
Total liabilities assumed	$	10,789

Net Assets Acquired	$	194,279

Unaudited pro forma financial information

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



	FOR THE SIX MONTHS ENDED JUNE 30,
(in thousands)	2025
Total revenue	$	145,914
Income before taxes	41,501

Note 4—Fair Value Measurements

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

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

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

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

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

Recurring Fair Value Measurements

As of June 30, 2026, the Company’s derivative financial instruments are composed of commodity swaps and collars. The fair value of the swap and collar agreements is determined under the income valuation technique using a discounted cash flow model. The valuation models require a variety of inputs, including contractual terms, published forward commodity prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s commodity derivative instruments are included within Level 2 of the fair value hierarchy. See Note 6 (“Commodity Derivative Instruments”).

Nonrecurring Fair Value Measurements

Business Combinations

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

Financial Instruments Not Measured at Fair Value

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

Note 5— Credit Facility

In January 2023, the Company entered into a secured revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of banks, as lenders (the “Revolving Credit Facility”). The Revolving Credit Facility will mature on October 22, 2028. The Revolving Credit Facility permits borrowing on a revolving credit basis with availability equal to the least of (1) the aggregate elected commitments, (2) the then-effective borrowing base and (3) the maximum credit amount of $500 million. The borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of the Company’s proved oil and natural gas reserves, as determined by the lenders in their discretion. As of June 30, 2026 and December 31, 2025, the Company’s borrowing base was $275 million and $295 million with aggregate elected commitments of $275 million and $250 million of which $158.5 million and $124.5 million was outstanding, respectively.

At the Company’s option, borrowings under the Revolving Credit Facility bear interest at a rate, which is either an adjusted forward-looking term rate based on SOFR (“Term SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.50% or the 30-day Term SOFR rate plus 1.00%), plus an applicable margin expected to range from 1.50% to 2.50% with respect to Base Rate borrowings and 2.50% to 3.50% with respect to Term SOFR borrowings in each case based on the current commitment utilization percentage. Interest is calculated and paid monthly in arrears. Additionally, the Company incurs an unused credit facility fee, paid quarterly, of 0.50% of the unutilized commitment regardless of the borrowing base utilization percentage. As of June 30, 2026 and December 31, 2025, the interest rate on the outstanding balance under the Revolving Credit Facility was 6.76% and 6.75%, respectively.

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

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

Under the Revolving Credit Facility, the Company is permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the

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borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500 million (2) then-effective borrowing base, and (3) the then-effective aggregate elected commitments and (b) as of the date of such distribution, the EBITDAX Ratio, as defined under the Revolving Credit Facility, does not exceed 1.50 to 1.00. If the EBITDAX Ratio exceeds 1.50 to 1.00, but does not exceed 2.25 to 1.00, and if total outstanding credit usage does not exceed 80% of the Commitments, the Company may make distributions if free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and the Company has delivered a certificate to lenders attesting to the foregoing.

The Revolving Credit Facility contains covenants requiring us to maintain the following financial ratios tested on a quarterly basis (terms below are as defined in the Revolving Credit Facility): (1) a consolidated Total Funded Debt to consolidated EBITDAX ratio of not greater than 3.0 to 1.0; and (2) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. The Revolving Credit Facility also contains covenants that require that the Company enter into derivative agreements covering not less than 40% of reasonably anticipated PDP production for each fiscal quarter over the following four quarters, but such requirements are increased to 50% for the first eight quarters if both the Utilization Percentage, as defined in the Revolving Credit Facility, is more than 50% and the EBITDAX ratio is more than 1.50 to 1.00. The Revolving Credit Facility contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change in control. If an event of default exists under the Revolving Credit Facility, the lenders will be able to terminate the lending commitments, accelerate the maturity of the Revolving Credit Facility and exercise other rights and remedies with respect to the collateral. The Company was in compliance with all financial covenants of the Revolving Credit Facility at June 30, 2026.

In conjunction with the semi-annual borrowing base redetermination, the Revolving Credit Facility was amended in April 2026 to decrease the borrowing base to $275 million and increase the elected commitments to $275 million. In addition, the derivative compliance requirement was amended to the less restrictive requirement described above.

Note 6—Commodity Derivative Instruments

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

The following table summarizes the location and fair value amounts of all commodity derivative instruments in the consolidated balance sheet as of June 30, 2026 as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheet:



(in thousands)	GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES		GROSS AMOUNTS OFFSET		NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES
Commodity derivative assets:
Current derivative assets	$	5,783	$	(4,015)	$	1,768
Noncurrent derivative assets	9,364		(414)		8,950
Total	$	15,147	$	(4,429)	$	10,718
Commodity derivative liabilities:
Current derivative liabilities	$	8,308	$	(4,015)	$	4,293
Noncurrent derivative liabilities	414		(414)		—
Total	$	8,722	$	(4,429)	$	4,293

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

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(in thousands)	GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES		GROSS AMOUNTS OFFSET		NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES
Commodity derivative assets:
Current derivative assets	$	14,252	$	—	$	14,252
Noncurrent derivative assets	184		—		184
Total	$	14,436	$	—	$	14,436
Commodity derivative liabilities:
Current derivative liabilities	$	—	$	—	$	—
Noncurrent derivative liabilities	46		—		46
Total	$	46	$	—	$	46

As of June 30, 2026, the Company had the following crude oil swaps:



INDEX	SETTLEMENT PERIOD	VOLUME HEDGED (Bbls)	WEIGHTED AVERAGE FIXED PRICE
WTI-NYMEX	Q3 2026	490,679	$65.01
WTI-NYMEX	Q4 2026	457,155	$64.97
WTI-NYMEX	Q1 2027	270,000	$69.25
WTI-NYMEX	Q2 2027	480,000	$68.05
WTI-NYMEX	Q3 2027	495,000	$68.38
WTI-NYMEX	Q4 2027	465,000	$67.88
WTI-NYMEX	Q1 2028	360,000	$70.60
WTI-NYMEX	Q2 2028	360,000	$70.60
WTI-NYMEX	Q3 2028	360,000	$70.60
WTI-NYMEX	Q4 2028	270,000	$70.80

As of June 30, 2026, the Company had the following crude oil collars:

INDEX

SETTLEMENT PERIOD

VOLUME HEDGED (Bbls)

WEIGHTED AVERAGE FLOOR/CEILING PRICE

WTI-NYMEX

Q3 2026

213,000

$61.62 / $72.58

WTI-NYMEX

Q4 2026

168,000

$58.04 / $67.51

WTI-NYMEX

Q1 2027

300,000

$55.75 / $66.44

WTI-NYMEX

Q2 2027

45,000

$60.00 / $64.25

As of June 30, 2026, the Company had the following natural gas collars:

INDEX

SETTLEMENT PERIOD

VOLUME HEDGED (MMBtu)

WEIGHTED AVERAGE FLOOR/CEILING PRICE

Henry Hub-NYMEX

Q3 2026

1,510,800

$3.73 / $4.90

Henry Hub-NYMEX

Q4 2026

1,452,700

$3.73 / $4.90

Henry Hub-NYMEX

Q1 2027

795,000

$4.00 / $5.68

As of June 30, 2026, the Company had the following natural gas basis swaps:

INDEX

SETTLEMENT PERIOD

VOLUME HEDGED (MMBtu)

WEIGHTED AVERAGE FIXED PRICE

Chicago City Gate to Henry Hub

Q3 2026

1,510,800

$(0.100)

Chicago City Gate to Henry Hub

Q4 2026

1,452,700

$(0.100)

Chicago City Gate to Henry Hub

Q1 2027

795,000

$0.300

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As of June 30, 2026, the Company had the following natural gas liquids swaps (presented annually due to lesser significance):



INDEX	SETTLEMENT PERIOD	VOLUME HEDGED (Gallons)	WEIGHTED AVERAGE FIXED PRICE
Mont Belvieu Ethane	2026	1,023,000	$0.26
Conway Propane	2026	2,692,000	$0.71
Conway Propane	2027	3,360,000	$0.67
Mont Belvieu Iso-Butane	2026	222,000	$0.92
Mont Belvieu Iso-Butane	2027	180,000	$0.84
Mont Belvieu Normal Butane	2026	675,000	$0.89
Mont Belvieu Normal Butane	2027	600,000	$0.81
Mont Belvieu Natural Gasoline	2026	837,000	$1.35
Mont Belvieu Natural Gasoline	2027	720,000	$1.29

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

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

Note 7—Accrued Liabilities

Accrued liabilities at June 30, 2026 and December 31, 2025 are summarized as follows:



	JUNE 30,		DECEMBER 31,
(in thousands)	2026		2025
Accrued capital expenditures	$	20,100	$	16,000
Accrued lease operating expenses, net	6,597		7,164
Accrued compensation	1,856		4,014
Accrued dividends	1,946		9,011
Accrued revenue payable	2,355		1,540
Accrued derivative payable	3,576		1
Other accrued liabilities	2,334		1,411
Total	$	38,764	$	39,141

Note 8—Related Party Transactions

On July 1, 2016, the Predecessor entered into a separate services agreement with Vitesse Management and JETX Energy, LLC (“JETX”), formerly known as Juneau Energy, LLC, another entity owned by JFG with common management. Per this services agreement, Vitesse Management is to provide JETX certain administrative services and supervise, administer, and manage the business affairs and operations of JETX and its subsidiaries for a service provider fee of $0.2 million per month. The term of this service agreement extends for an unlimited amount of time; however, it is subject to termination by either Vitesse Management or JETX upon 30 days’ prior written notice, upon dissolution of JETX, upon the consent of the non-breaching party following an uncured material breach, or a final exit event. During each of the three and six months ended June 30, 2026 and 2025, the Company recorded its net share of fees from JETX of $0.7 million and $1.4 million, respectively, which is classified as a reduction to general and administrative expenses on the accompanying consolidated statements of operations.

During the six months ended June 30, 2025, the Company incurred approximately $2.5 million in transaction costs payable to a related party in connection with the Lucero Acquisition. See Note 3 (“Oil and Gas Properties”).

Note 9—Commitments and Contingencies

Litigation

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

As previously disclosed, the Company received a one-time cash payment of $24 million during the three months ended June 30, 2025 in connection with a settlement that resolved claims for recoupment of revenue deductions and reimbursement of legal

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expenses. The Company recorded the payment as follows in the condensed consolidated statements of operations: a $3.3 million increase to oil revenue, a $13.6 million increase to gas revenue and a $7.1 million reduction to general and administrative expenses for reimbursed legal costs.

Note 10—Equity

Authorized Capital Stock

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

Common Stock

During the six months ended June 30, 2026, the following transactions related to our common stock occurred:

■1,935,698 shares of common stock were issued in connection with the Powder River Basin Acquisition. See Note 3 (“Oil and Gas Properties”).

During the six months ended June 30, 2025, the following transactions related to our common stock occurred:

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

■1,129,718 RSUs vested and were released as common stock, of which 345,255 were exchanged for tax withholding and retired by the Company.

Preferred Stock

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

Long-Term Incentive Plan

The Company’s long-term incentive plan (“LTIP”) provides for the granting of various forms of equity-based awards, including stock option awards, stock appreciation rights awards, restricted stock awards, restricted stock unit awards, performance awards, cash awards and other stock-based awards to employees, directors and consultants of the Company. The LTIP was amended and restated in May 2025 to increase the number of shares available to be awarded by 580,500 shares to 4,540,500 shares. As of June 30, 2026, there were 561,611 shares available to be granted.

Restricted Stock Units

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

The following is a summary of RSU activity during the six months ended June 30, 2026:



	Shares of restricted stock unit awards	Weighted-Average Price on Date of Grant
Outstanding at January 1, 2026	1,400,787	$	16.95
Granted	111,000	19.72
Vested	(1,016,999)	15.45
Forfeited	(38,680)	22.63
Outstanding at March 31, 2026	456,108	$	20.51
Granted	156,245	18.46
Vested	(44,738)	21.32
Forfeited	(4,000)	19.72
Outstanding at June 30, 2026	563,615	$	19.88

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During the six months ended June 30, 2026, the Company modified RSU awards totaling 18,052 RSUs, accelerating vesting such that 50% vests on June 30, 2026 and 50% vests on December 31, 2026, subject to continued employment. The modification date fair value was $19.43 per unit based on the closing stock price on March 26, 2026. The modification resulted in no incremental compensation cost.

During the three and six months ended June 30, 2026, the Company recognized $2.0 million and $3.6 million of equity-based compensation expense relating to these restricted stock units, respectively.

During the three and six months ended June 30, 2025, the Company recognized $2.0 million and $4.2 million of equity-based compensation expense relating to these restricted stock units, respectively.

As of June 30, 2026, there is $7.9 million of unrecognized equity-based compensation expense related to unvested restricted stock unit awards. The cost is expected to be recognized through May 2029, over a weighted-average period of 1.82 years.

Performance Stock Units

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

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

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

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



Grant date	February 23, 2024	March 5, 2025	May 1, 2026
Forecast period (years)	2.85	2.82	2.67
Risk-free rates	4.4%	3.9%	3.8%
Expected equity volatility	55%	47%	42%
Stock price on grant date	$21.48	$23.88	$18.77
Grant date fair value	$22.02	$23.54	$11.88

The following is a summary of PSU activity during the six months ended June 30, 2026:



	Shares of performance stock unit awards (at target)	Weighted-Average Price on Date of Grant
Outstanding at January 1, 2026	193,210	$	22.72
Granted	—	—
Vested	—	—
Forfeited	(102,160)	22.69
Outstanding at March 31, 2026	91,050	$	22.75
Granted	170,771	11.88
Vested	(27,083)	22.78
Forfeited	—	—
Outstanding at June 30, 2026	234,738	$	14.84

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During the six months ended June 30, 2026, the Company modified PSU awards previously granted to an executive under the February 23, 2024 and March 5, 2025 grants totaling 54,166 PSUs at target. The modification removed the TSR component, fixed the number of PSUs at target, and accelerated vesting (50% vests on June 30, 2026 and 50% vests on December 31, 2026) subject to continued employment. The fair value of the original awards immediately prior to modification was determined using a Monte Carlo simulation as of March 26, 2026, using risk-free rates of 3.73% and 3.87%, respectively, expected volatility of 33.7% and 34.2%, respectively, and a stock price of $19.43. Total incremental compensation cost resulting from the modification is $0.3 million, to be recognized through December 31, 2026.

During the three and six months ended June 30, 2026, the Company recognized $0.8 million and $(0.2) million of equity-based compensation expense relating to these PSUs, respectively.

During the three and six months ended June 30, 2025, the Company recognized $0.4 million and $0.6 million of equity-based compensation expense relating to these PSUs, respectively.

As of June 30, 2026, there is $2.5 million of unrecognized equity-based compensation expense related to unvested PSU awards. The cost is expected to be recognized through December 2028, over a weighted-average period of 2.13 years.

Transitional Equity Award Adjustment Plan

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

Transitional Plan Options

Each JFG stock option that did not remain an option to purchase shares of only JFG common stock was converted into both a post-Spin-Off option to purchase shares of JFG common stock and an option to purchase shares of Vitesse common stock. The exercise price of such JFG stock option and the exercise price and number of shares subject to such Vitesse stock option was adjusted so that (i) the aggregate intrinsic value of such post-Spin-Off JFG stock option and Vitesse stock option immediately after the Spin-Off equals the aggregate intrinsic value of the JFG stock option as measured immediately before the Spin-Off and (ii) the aggregate exercise price of such post-Spin-Off JFG stock option and Vitesse stock option equals the aggregate exercise price of the JFG stock option immediately before the Spin-Off, subject to rounding. Upon completion of the Spin-Off, 457,866 options were granted and none were exercised during the three and six months ended June 30, 2026. The intrinsic option value of the options was $3.1 million at June 30, 2026 and the maximum number of shares of common stock that could be issued under the plan is 457,866.

Transitional Plan Restricted Units

Each JFG restricted stock unit award and performance stock unit award (other than those that will remain awards denominated in shares of only JFG stock, which includes the portion of any performance stock unit award that may be earned above the designated target level), including any additional stock units accrued as a result of dividend equivalents, was adjusted by the grant of a Vitesse restricted stock unit award. Upon completion of the Spin-Off, restricted stock units were granted in respect of these JFG awards. These restricted stock unit awards are capped at 1,475,613 and at June 30, 2026 none have a remaining performance, service or vesting condition to satisfy. These restricted stock unit awards generally accrue dividends declared on common stock but have deferred issuance dates through January 2, 2099. During the three and six months ended June 30, 2026, 320,072 and 321,073 restricted stock units were released as common stock, net of shares cashed out as fractional units, respectively.

Transitional Plan Restricted Stock Awards

Holders of a JFG restricted stock award received 286,729 shares of our common stock upon completion of the Spin-Off, which shares are subject to the provisions of the Transitional Plan, including generally the same risk of forfeiture and other conditions as applied to the original JFG restricted stock award. These restricted stock awards have no remaining performance or service conditions to satisfy, or any other vesting condition, and are paid dividends on common stock as declared but have deferred issuance dates through September 28, 2029. During the three and six months ended June 30, 2026, 2,915 and 9,034 restricted stock awards were released as common stock, net of shares cashed out as fractional units, respectively.

The remaining restricted stock units and restricted stock awards are scheduled to be released as common stock as follows:

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Year	Restricted stock units	Restricted stock awards	Total
2026	2,065	39,585	41,650
2027	837	54,269	55,106
2028	838	32,988	33,826
2029	114,244	19,793	134,037
2030	2,791	—	2,791
Thereafter	13,949	—	13,949
Total	134,724	146,635	281,359

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

Stock Repurchase Program

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

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

Net Income (Loss) Per Common Share

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



	FOR THE THREE MONTHS ENDED				FOR THE SIX MONTHS ENDED
	JUNE 30,				JUNE 30,
(in thousands except share and per share amounts)	2026		2025		2026		2025
Numerator for earnings per common share:
Net income (loss) attributable to Vitesse Energy, Inc.	$	33,081	$	24,659	$	(9,199)	$	27,327
Allocation of earnings to participating securities(1)	—		(376)		—		—
Net income (loss) attributable to common shareholders	$	33,081	$	24,283	$	(9,199)	$	27,327
Adjustment to allocation of earnings to participating securities related to diluted shares	—		376		—		—
Net income (loss) attributable to common shareholders for diluted EPS	$	33,081	$	24,659	$	(9,199)	$	27,327

Denominator for earnings per common share:
Weighted average common shares outstanding	41,723,856		38,602,875		40,678,560		35,604,506
Weighted average Transitional Share RSUs outstanding with no future service required	317,623		502,087		385,836		502,092
Denominator for basic earnings per common share	42,041,479		39,104,962		41,064,396		36,106,598
LTIP RSUs	572,820		1,461,008		—		1,531,818
LTIP PSUs	12,549		92,929		—		82,710
Transitional Share options	225,804		270,282		—		283,825
Transitional Share RSUs with remaining performance/service obligation	—		38,814		—		38,814
Denominator for diluted earnings per common share	42,852,652		40,967,995		41,064,396		38,043,765

Net income (loss) per common share:
Basic	$	0.79	$	0.62	$	(0.22)	$	0.76
Diluted	$	0.77	$	0.60	$	(0.22)	$	0.72

Shares excluded from diluted earnings per share due to anti-dilutive effect:
LTIP RSUs	—		—		629,035		—
LTIP PSUs	—		—		10,018		—
Transitional Share options	—		—		239,783		—
Transitional Share RSUs with remaining performance/service obligation	—		—		—		—

(1)Certain unvested LTIP RSUs represent participating securities because they participate in nonforfeitable dividends with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. These unvested LTIP RSUs do not participate in undistributed net losses as they are not contractually obligated to do so. As of January 13, 2026, these RSUs are fully vested.

Note 11—Income Taxes

For the three and six months ended June 30, 2026, the Company recorded an income tax expense of $6.8 million and an income tax benefit of $2.7 million, respectively. For the three and six months ended June 30, 2025 the Company recorded income tax expense of $9.9 million and $9.7 million, respectively.

The provision for income taxes for the three and six months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book income (loss) primarily due to (i) §162(m) limitations on certain covered employee compensation, (ii) discrete permanent differences related to vesting of RSUs for non-covered employees and (iii) state income taxes.

Note 12—Subsequent Events

On July 29, 2026, the Board declared a regular quarterly cash dividend for Vitesse’s common stock of $0.4375 per share for stockholders of record as of September 15, 2026, which will be paid on September 30, 2026.

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

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Item 2. 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 Condensed Consolidated Financial Statements and the notes thereto included under Part I – Financial Information. 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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2025 in the section entitled Part I, Item 1A Risk Factors and in this Quarterly Report on Form 10-Q in the sections entitled Part II, Item 1A Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.”

As further described in Note 3 (“Oil and Gas Properties”) to the Condensed Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q, we completed the Lucero Acquisition on March 7, 2025. The financial information presented herein (i) excludes the results of Lucero and its subsidiaries for periods prior to March 7, 2025 and (ii) includes the results of Lucero and its subsidiaries for periods on or after March 7, 2025.

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 that provide an attractive return on invested capital, while maintaining a strong balance sheet and distributing a meaningful dividend to our stockholders. We invest in working and mineral interests in oil and natural gas properties with our core area of focus currently 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 June 30, 2026, we had a working interest in 6,579 gross (237.4 net) productive wells and 278 gross (6.4 net) wells that were being drilled or completed, and an additional 320 gross (13.0 net) wells that had been permitted for development by our operators. In addition, we had a royalty only interest in 1,289 gross (3.1 net) productive wells.

As previously announced, on May 1, 2026, Mr. Jamie Benard joined our team as President and Chief Executive Officer. On the same date, Mr. Brian Cree transitioned from President and Interim Chief Executive Officer to Senior Advisor, a role he will hold until his retirement on December 31, 2026.

Our financial and operating performance for the three months ended June 30, 2026 included the following:

■Paid $20.6 million in dividends to our equity holders.

■Production of 17,354 Boe/d with 60% of production from oil.

■Total revenue of $91.0 million.

■Net income of $33.1 million.

■Cash flows from operations of $25.4 million.

■Invested $20.7 million in capital development and acquisitions, net of divestitures.

■Total debt of $158.5 million at June 30, 2026.

Industry Trends Impacting Our Business

Commodity prices are a significant factor impacting our earnings, operating cash flows and our acquisition and divestiture strategy, as well as the decisions of us and our operators in conducting operations. During the last several years, prices for oil and natural gas have experienced sustained volatility, impacted by general economic and political conditions, the conflict between Russia and Ukraine, conflict in the Middle East, including Iran, the situation in Venezuela, U.S. international trade and tariff policies and responses thereto, supply chain constraints, elevated interest rates and costs of capital, and changes in production by OPEC and its key member, Saudi Arabia, and certain other non-OPEC oil-producing countries. Most recently, the conflict in Iran and disruption of maritime traffic through the Strait of Hormuz has caused significant volatility in commodity prices.

As a result of such commodity price volatility, which we expect to continue throughout 2026, our earnings and operating cash flows can vary substantially. 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, inflationary factors, industry production and inventory levels, the United States Department of Energy’s sales and purchases related to the U.S. strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC and other oil-producing countries, the imposition of and changes in tariffs and other controls on imports and exports and resulting consequences of such, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty, including as a result of the conflict in Iran and disruption of maritime traffic through the Strait of Hormuz. Any of the foregoing can have a substantial impact on the prices of oil and natural gas, which in turn impacts our decisions and the decision of our operators to drill and extract resources.

Source of Our Revenues

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

Commodity derivative gain (loss), 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.

Lease operating expenses. Lease operating 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. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

DD&A. DD&A 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 staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. During the six months ended June 30, 2025, general and administrative expenses included non-recurring costs related to the Lucero Acquisition and an offset for reimbursement of past legal expenses as a result of a settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our 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 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. There were no proved oil and gas property impairments during the three and six months ended June 30, 2026 and 2025.

Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the

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years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Selected Factors That Affect Our Operating Results

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

■the timing and success of our drilling and production activities and those of 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;

■the realized gains and losses on our derivative instruments;

■our ability to continue to identify and acquire producing properties, 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.

Market Conditions

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 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. Worldwide supply in terms of output, especially production from properties within the United States, the production quotas set by OPEC and certain other oil-producing countries, the conflicts in Ukraine and in the Middle East, including Iran, the situation in Venezuela and the strength or weakness of the U.S. dollar can impact oil prices.

Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Future oil prices will be impacted by varying oil supply and demand both regionally and worldwide.

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



	THREE MONTHS ENDED JUNE 30,
Average Daily Prices (1)	2026		2025
WTI Oil (per Bbl)	$	92.38	$	63.55
Natural Gas (per MMBtu)	2.95		3.19

	SIX MONTHS ENDED JUNE 30,
Average Daily Prices (1)	2026		2025
WTI Oil (per Bbl)	$	82.40	$	67.36
Natural Gas (per MMBtu)	3.81		3.63

(1)Based on average daily NYMEX WTI and Henry Hub Spot closing prices reported by FactSet and the EIA, respectively.

The average second quarter 2026 NYMEX oil price was $92.38 per barrel, or 45% higher than the average NYMEX oil price per barrel in the second quarter of 2025. Our settled derivatives decreased our second quarter 2026 realized oil price per barrel by $20.84 and increased our second quarter 2025 realized oil price per barrel by $4.71. Our average second quarter 2026 realized oil price per barrel after reflecting settled derivatives was $71.14 compared to $64.21 during the same period in 2025.

The average second quarter 2026 NYMEX natural gas price was $2.95 per MMBtu, or 8% lower than the average NYMEX price per MMBtu in the second quarter of 2025. In the second quarter of 2026, our settled derivatives increased our realized natural gas price by $0.38 per Mcf, bringing our realized natural gas price after reflecting settled derivatives to $1.55 per Mcf. In the second quarter of 2025, we had no material natural gas price derivatives in place and our realized natural gas price was $4.17 per Mcf.

The average year-to-date 2026 NYMEX oil price was $82.40 per barrel, or 22% higher than the 2025 average year-to-date oil price per barrel. Our settled derivatives decreased our average year-to-date 2026 realized oil price per barrel by $13.06 and

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increased our average year-to-date 2025 realized oil price per barrel by $2.92. Our average year-to-date 2026 realized oil price per barrel after reflecting settled derivatives was $66.60 compared to $64.53 during the same period in 2025.

The average year-to-date 2026 NYMEX natural gas price was $3.81 per MMBtu, or 5% higher than the 2025 average year-to-date price per MMBtu. During the six months ended June 30, 2026, our settled derivatives decreased our realized natural gas price by $0.13 per Mcf, bringing our realized natural gas price after reflecting settled derivatives to $1.55 per Mcf. During the six months ended June 30, 2025, we had no material natural gas price derivatives in place and our realized natural gas price was $3.61 per Mcf.

We employ a hedging program that partially mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part I, Item 3 Quantitative and Qualitative Disclosures about Market Risk and Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements.

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.

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Results of Operations

Three Months Ended June 30, 2026 Compared with Three Months Ended June 30, 2025

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



	THREE MONTHS ENDED JUNE 30,				INCREASE (DECREASE)
($ in thousands, except production and per unit data)	2026		2025		AMOUNT		PERCENT
Financial and Operating Results:
Revenue
Oil	$	86,507	$	66,611	$	19,896	30	%
Natural gas	4,497		15,144		(10,647)		(70	%)
Total revenue	$	91,004	$	81,755	$	9,249	11	%
Operating Expenses
Lease operating expense	$	17,975	$	19,629	$	(1,654)	(8	%)
Production taxes	8,459		6,180		2,279		37	%
General and administrative	6,150		311		5,839		1877	%
Depletion, depreciation, amortization, and accretion	34,809		34,576		233		1	%
Equity-based compensation	2,735		2,403		332		14	%
Interest Expense	$	3,022	$	2,539	$	483	19	%
Commodity Derivative Gain, Net	$	22,043	$	18,451	$	3,592	19	%
Income Tax (Benefit) Expense	$	6,776	$	9,871	$	(3,095)	(31	%)
Production Data:
Oil (MBbls)	940		1,119		(179)		(16	%)
Natural gas (MMcf)	3,832		3,630		202		6	%
Combined volumes (MBoe)	1,579		1,724		(145)		(8	%)
Daily combined volumes (Boe/d)	17,354		18,950		(1,596)		(8	%)
Average Realized Prices before Hedging:
Oil (per Bbl)	$	91.98	$	59.50	$	32.48	55	%
Natural gas (per Mcf)	1.17		4.17		(3.00)		(72	%)
Combined (per Boe)	57.63		47.41		10.22		22	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	71.14	$	64.21	$	6.93	11	%
Natural gas (per Mcf)	1.55		4.17		(2.62)		(63	%)
Combined (per Boe)	46.12		50.47		(4.35)		(9	%)
Average Costs (per Boe):
Lease operating	$	11.38	$	11.38	$	—	—	%
Production taxes	5.36		3.58		1.78		50	%
General and administrative	3.89		0.18		3.71		2061	%
Depletion, depreciation, amortization, and accretion	22.04		20.05		1.99		10	%

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $91.0 million for the three months ended June 30, 2026 from $81.8 million for the three months ended June 30, 2025. The increase in oil and natural gas revenue was due to a 22% increase in the average realized prices per Boe before hedging, partially offset by an 8% decrease in production volumes for the three months ended June 30, 2026. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by $17.6 million, while the decrease in production volumes decreased oil and natural gas revenue by $8.4 million.

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During the three months ended June 30, 2025, $3.3 million and $13.6 million of recoupments of oil and natural gas revenue, respectively, were recognized as part of the settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements.

Our oil price differential to the weighted average benchmark price during the three months ended June 30, 2026 was negative $0.88 per barrel, as compared to a negative $4.17 per barrel during the three months ended June 30, 2025, primarily due to more favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the three months ended June 30, 2026 was $1.17 per Mcf, representing a 40% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $4.17 per Mcf during the three months ended June 30, 2025, representing a 130% realization relative to the weighted average NYMEX natural gas price. The lower realized price was primarily due to the legal settlement increasing the realized price per Mcf in the prior period. Fluctuations in our natural gas 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, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner.

Lease Operating Expense. Lease operating expense decreased to $18.0 million for the three months ended June 30, 2026 from $19.6 million for the three months ended June 30, 2025. The decrease is primarily attributable to an 8% decrease in production volumes between periods.

Production Tax Expense. Total production taxes increased to $8.5 million for the three months ended June 30, 2026 from $6.2 million for the three months ended June 30, 2025. Production taxes are primarily based on oil revenue and natural 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 9.3% and 7.6% for the three months ended June 30, 2026 and 2025, respectively. The production tax rate was lower for the three months ended June 30, 2025 due to a legal settlement increasing revenue in the period.

General and Administrative Expense. General and administrative expense increased to $6.2 million for the three months ended June 30, 2026 from $0.3 million for the three months ended June 30, 2025. During the three months ended June 30, 2025, $7.1 million of litigation costs were reimbursed as a result of a legal settlement. Excluding net litigation costs and Lucero Acquisition transaction costs of $0.3 million, general and administrative expense on a per Boe basis was $3.47 for the three months ended June 30, 2025 compared to $3.89 for the three months ended June 30, 2026.

DD&A. DD&A increased to $34.8 million for the three months ended June 30, 2026 compared with $34.6 million for the three months ended June 30, 2025. The increase was the result of a $1.99 per Boe increase in the DD&A rate for the three months ended June 30, 2026, partially offset by an 8% decrease in production compared with the three months ended June 30, 2025. The increase in the DD&A rate accounted for a $3.4 million increase in DD&A expense while the decrease in production accounted for a $3.2 million decrease in DD&A expense.

For the three months ended June 30, 2026, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $21.85 per Boe compared with $19.88 per Boe for the three months ended June 30, 2025.

Equity-Based Compensation. During the three months ended June 30, 2026, equity-based compensation expense increased to $2.7 million from $2.4 million during the three months ended June 30, 2025. Equity-based compensation expense was higher in 2026 due to additional LTIP RSUs and PSUs awarded to employees and directors.

Interest Expense. Interest expense increased to $3.0 million for the three months ended June 30, 2026 from $2.5 million for the three months ended June 30, 2025. The increase for the three months ended June 30, 2026 was primarily due to a higher average debt balance during the period.

Commodity Derivative Gain, Net. The commodity derivative gain was $22.0 million for the three months ended June 30, 2026 compared with a gain of $18.5 million for the three months ended June 30, 2025. 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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	THREE MONTHS ENDED JUNE 30,
(in thousands)	2026		2025
Realized (loss) gain on commodity derivatives (1)	$	(18,170)	$	5,271
Unrealized gain on commodity derivatives (1)	40,213		13,180
Total commodity derivative gain	$	22,043	$	18,451

(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 statements of operations included in this Form 10-Q. 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 the three months ended June 30, 2026, 84% of our oil volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $19.6 million. In the three months ended June 30, 2026, half of our natural gas volumes were covered by residue gas and NGL financial hedges, which resulted in a realized gain on gas and NGL derivatives of $1.4 million. In the three months ended June 30, 2025, 58% of our oil volumes and no material natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $5.3 million.

At June 30, 2026, all of our derivative contracts were recorded at their fair value, which was a net asset of $6.4 million, an increase in value of $40.2 million from the $33.8 million net liability recorded as of March 31, 2026. Derivative contract fair value is recorded in part based on published forward commodity prices. This increase in fair value was largely driven by the NYMEX WTI price decreasing from $101.38/Bbl at March 31, 2026 to $69.50/Bbl at June 30, 2026 and the corresponding change in forward commodity prices.

Income Tax Expense. During the three months ended June 30, 2026, we recorded an income tax expense of $6.8 million related to federal and state income taxes compared to an income tax expense of $9.9 million for the three months ended June 30, 2025.

The provision for income taxes for the three months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to §162(m) limitations on certain covered employee compensation, other discrete permanent differences related to vesting of RSUs for non-covered employees and state income taxes.

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Six Months Ended June 30, 2026 Compared with Six Months Ended June 30, 2025

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



	SIX MONTHS ENDED JUNE 30,				INCREASE (DECREASE)
($ in thousands, except production and per unit data)	2026		2025		AMOUNT		PERCENT
Financial and Operating Results:
Revenue
Oil	$	146,524	$	125,535	$	20,989	17	%
Natural gas	11,891		22,390		(10,499)		(47	%)
Total revenue	$	158,415	$	147,925	$	10,490	7	%
Operating Expenses
Lease operating expense	$	33,310	$	33,484	$	(174)	(1	%)
Production taxes	14,124		11,953		2,171		18	%
General and administrative	14,736		12,442		2,294		18	%
Depletion, depreciation, amortization, and accretion	65,996		61,139		4,857		8	%
Equity-based compensation	3,460		4,873		(1,413)		(29	%)
Interest Expense	$	5,637	$	5,443	$	194	4	%
Commodity Derivative (Loss) Gain, Net	$	(32,963)	$	18,279	$	(51,242)	(280	%)
Income Tax (Benefit) Expense	$	(2,689)	$	9,669	$	(12,358)	(128	%)
Production Data:
Oil (MBbls)	1,839		2,038		(199)		(10	%)
Natural gas (MMcf)	7,058		6,206		852		14	%
Combined volumes (MBoe)	3,016		3,072		(56)		(2	%)
Daily combined volumes (Boe/d)	16,662		16,971		(309)		(2	%)
Average Realized Prices before Hedging:
Oil (per Bbl)	$	79.66	$	61.61	$	18.05	29	%
Natural gas (per Mcf)	1.68		3.61		(1.93)		(53	%)
Combined (per Boe)	52.53		48.16		4.37		9	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	66.60	$	64.53	$	2.07	3	%
Natural gas (per Mcf)	1.55		3.61		(2.06)		(57	%)
Combined (per Boe)	44.24		50.09		(5.85)		(12	%)
Average Costs (per Boe):
Lease operating	$	11.05	$	10.90	$	0.15	1	%
Production taxes	4.68		3.89		0.79		20	%
General and administrative	4.89		4.05		0.84		21	%
Depletion, depreciation, amortization, and accretion	21.88		19.90		1.98		10	%

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $158.4 million for the six months ended June 30, 2026 from $147.9 million for the six months ended June 30, 2025. The increase in oil and natural gas revenue was due to a 9% increase in the average realized prices per Boe before hedging, which was partially offset by a 2% decrease in production volumes for the six months ended June 30, 2026. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by $13.4 million, while the decrease in production volumes decreased oil and natural gas revenue by $2.9 million.

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During the six months ended June 30, 2025, $3.3 million and $13.6 million of recoupments of oil and natural gas revenue, respectively, were recognized as part of the settlement discussed in Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements.

Our oil price differential to the weighted average benchmark price during the six months ended June 30, 2026 was negative $3.11 per barrel, as compared to a negative $5.32 per barrel during the six months ended June 30, 2025, primarily due to more favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the six months ended June 30, 2026 was $1.68 per Mcf, representing a 44% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $3.61 per Mcf during the six months ended June 30, 2025, representing a 101% realization relative to the weighted average NYMEX natural gas price. The lower realized price was primarily due to a legal settlement increasing the realized price per Mcf in the prior period. Fluctuations in our natural gas 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, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner.

Lease Operating Expense. Lease operating expense decreased to $33.3 million for the six months ended June 30, 2026 from $33.5 million for the six months ended June 30, 2025. The decrease is primarily attributable to a 2% decrease in production between periods.

Production Tax Expense. Total production taxes increased to $14.1 million for the six months ended June 30, 2026 from $12.0 million for the six months ended June 30, 2025. Production taxes are primarily based on oil revenue and natural 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 8.9% and 8.1% for the six months ended June 30, 2026 and 2025, respectively. The production tax rate was lower for the six months ended June 30, 2025 due to the legal settlement increasing revenue in the period.

General and Administrative Expense. General and administrative expense increased to $14.7 million for the six months ended June 30, 2026 from $12.4 million for the six months ended June 30, 2025. During the six months ended June 30, 2026, $2.4 million in separation benefits related to our leadership transition were incurred. During the six months ended June 30, 2025, $7.1 million of litigation costs were reimbursed as a result of a legal settlement and Lucero Acquisition transaction costs of $4.9 million were incurred. Excluding these one-time costs, general and administrative expense on a per Boe basis increased to $4.09 for the six months ended June 30, 2026 from $3.87 for the six months ended June 30, 2025.

DD&A. DD&A increased to $66.0 million for the six months ended June 30, 2026 from $61.1 million for the six months ended June 30, 2025. The increase was the result of a $1.98 per Boe increase in the DD&A rate, partially offset by a 2% decrease in production for the six months ended June 30, 2026 compared with the six months ended June 30, 2025. The increase in the DD&A rate accounted for a $6.1 million increase in DD&A expense while the decrease in production accounted for a $1.2 million decrease in DD&A expense.

For the six months ended June 30, 2026, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $21.69 per Boe compared with $19.74 per Boe for the six months ended June 30, 2025.

Equity-Based Compensation. During the six months ended June 30, 2026, equity-based compensation expense decreased to $3.5 million from $4.9 million during the six months ended June 30, 2025. Equity-based compensation expense was primarily lower in 2026 due to a $1.4 million reversal of expense for forfeited awards during the period.

Interest Expense. Interest expense increased to $5.6 million for the six months ended June 30, 2026 from $5.4 million for the six months ended June 30, 2025. The increase for the six months ended June 30, 2026 was due to a higher average debt balance during the six months ended June 30, 2026 compared to the six months ended June 30, 2025.

Commodity Derivative (Loss) Gain, Net. The commodity derivative loss was $33.0 million for the six months ended June 30, 2026 compared with a gain of $18.3 million for the six months ended June 30, 2025. 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 table below summarizes our commodity derivative gains and losses that were recorded in the periods presented.

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	SIX MONTHS ENDED JUNE 30,
(in thousands)	2026		2025
Realized (loss) gain on commodity derivatives (1)	$	(24,999)	$	5,954
Unrealized (loss) gain on commodity derivatives (1)	(7,964)		12,325
Total commodity derivative (loss) gain	$	(32,963)	$	18,279

In the six months ended June 30, 2026, 72% of our oil volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $24.0 million. In the six months ended June 30, 2026, approximately half of our natural gas volumes were covered by residue gas and NGL financial hedges, which resulted in a realized loss on gas and NGL derivatives of $1.0 million. In the six months ended June 30, 2025, 52% of our oil volumes and no material natural gas volumes were subject to financial hedges, which resulted in a realized gain on oil derivatives of $6.0 million.

At June 30, 2026, all of our derivative contracts were recorded at their fair value, which was a net asset of $6.4 million, a decrease in value of $8.0 million from the $14.4 million net asset recorded as of December 31, 2025. Derivative contract fair value is recorded in part based on published forward commodity prices. This decline in fair value was largely driven by the NYMEX WTI price increasing from $57.42/Bbl at December 31, 2025 to $69.50/Bbl at June 30, 2026 and the corresponding change in forward commodity prices.

Income Tax Expense. During the six months ended June 30, 2026, we recorded an income tax benefit of $2.7 million related to federal and state income taxes compared to an income tax expense of $9.7 million for the six months ended June 30, 2025.

The provision for income taxes for the six months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income (loss) primarily due to §162(m) limitations on certain covered employee compensation, other discrete permanent differences related to vesting of RSUs for non-covered employees and state income taxes.

Liquidity and Capital Resources

Overview. At June 30, 2026, we had $0.9 million of unrestricted cash on hand and $116.5 million available under the elected commitments in our Revolving Credit Facility. At December 31, 2025, we had $1.3 million of unrestricted cash on hand and $125.5 million available under the elected commitments in our Revolving Credit Facility. We expect that our liquidity going forward will be primarily derived from cash flows from our operations, cash on hand, availability under the Revolving Credit Facility and proceeds from equity or debt offerings and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements for the next twelve months, as described below, including our planned capital expenditures program, as well as dividends and our share repurchase program. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings under our Revolving Credit Facility or the issuance of equity or debt. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and dividend payments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of accrued revenue, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments.

At June 30, 2026 and December 31, 2025, we had a working capital surplus of $3.1 million and $0.9 million, respectively. Current assets increased by $6.2 million and current liabilities increased by $4.0 million at June 30, 2026, compared to December 31, 2025. The increase in current assets during the six months ended June 30, 2026 was primarily due to an increase of $21.8 million in accrued revenue, partially offset by a decrease of $12.5 million in current derivative instrument assets due to forward oil price increases as compared to hedged oil prices. The increase in current liabilities during the six months ended June 30, 2026 was primarily due to an increase of $4.3 million in current derivative instrument liabilities due to forward oil price increases as compared to hedged oil prices.

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Cash Flows. Our cash flows for the six months ended June 30, 2026 and 2025 are presented below:



	SIX MONTHS ENDED JUNE 30,
(in thousands)	2026		2025
Cash flows provided by operating activities	$	49,468	$	83,505
Cash flows used in investing activities	(39,388)		(66,118)
Cash flows used in financing activities	(10,524)		(18,392)
Net change in cash	$	(444)	$	(1,005)

During the six months ended June 30, 2026, we generated $49.5 million of cash from operations, a $34.0 million decrease from the six months ended June 30, 2025. Cash flows from operating activities are primarily affected by production volumes, commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. During 2025, we received a one-time $24.0 million legal settlement that impacted cash flows from operating activities. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. A minimum level of derivative coverage is required by certain debt covenants. See Part I, Item 3 Quantitative and Qualitative Disclosures about Market Risk.

One of the primary sources of variability in our cash provided by operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts. For more information on our outstanding derivatives, see Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements.

Cash used in investing activities during the six months ended June 30, 2026 was $39.4 million compared to $66.1 million during the six months ended June 30, 2025. The $26.7 million decrease was primarily related to lower development activity between periods. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. Our cash used in investing activities reflects actual cash spending, which can lag several months from when the related costs were accrued. As a result, our actual cash spending is not always reflective of current levels of development activity. Acquisition and development activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and financial returns. We supplement development activity on our asset base with opportunistic acquisitions of near-term drilling opportunities when development activity by our operators on our existing properties does not meet our development objectives. Our net cash proceeds and spending for divestiture and acquisition activities was $0.7 million and $(1.6) million, during the six months ended June 30, 2026 and 2025, respectively.

Cash used in financing activities was $10.5 million and $18.4 million during the six months ended June 30, 2026 and 2025, respectively. The cash used in financing activities during the six months ended June 30, 2026 was related to $44.1 million in dividends paid, partially offset by $34.0 million of net borrowings under our Revolving Credit Facility. The cash used in financing activities during the six months ended June 30, 2025 was related to $47.8 million in dividends paid, $11.0 million of net repayments under our Revolving Credit Facility and the $9.2 million value of retained shares paid to fund employee tax withholding in connection with the vesting of restricted stock units, which was partially offset by $49.8 million in cash acquired in the Lucero Acquisition.

Revolving Credit Facility. In January 2023, we entered into the secured Revolving Credit Facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of banks, as lenders. The Revolving Credit Facility matures on October 22, 2028.

Under the 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 the aggregate elected 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 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 borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of our proved oil and natural gas reserves, as determined by the lenders in their discretion. As of June 30, 2026, our borrowing base and aggregate elected commitment was $275.0 million of which $158.5 million was outstanding. See Note 5 (“Credit Facility”) to the Condensed Consolidated Financial Statements for further details regarding the Revolving Credit Facility.

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As previously disclosed, in conjunction with the semi-annual borrowing base redetermination, the Revolving Credit Facility was amended in April 2026 to decrease the borrowing base to $275 million and increase the elected commitments to $275 million. In addition, the derivative compliance requirement was amended to the less restrictive requirement described above.

Material Cash Requirements. Our material short-term cash requirements include recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. If commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts. Conversely, working capital requirements would be expected to decrease if commodity prices decline.

Our long-term material cash requirements from currently known obligations include settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating lease obligations. We cannot provide specific timing for repayments of outstanding borrowings on our Revolving Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. We cannot provide specific timing for other current and long-term liability obligations where we cannot forecast with certainty the amount and timing of such payments, including asset retirement obligations, as the plugging and abandonment of wells is primarily at the discretion of the operators and any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. See Note 4 (“Fair Value Measurements”) to the Condensed Consolidated Financial Statements for further information on these contracts and their fair values as of June 30, 2026, which fair values represent the estimated cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date.

Dividends. We paid cash dividends to our equity holders of $44.1 million during the six months ended June 30, 2026. While we believe that our future cash flows from operations will be able to sustain future dividends, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations (the most common of which are limitations set forth in a company’s organizational documents and insolvency), business developments and the judgment of our Board. Future cash dividends to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will be able to pay dividends at current levels or at all or otherwise return capital to our investors in the future.

Capital Expenditures. For the six months ended June 30, 2026, total capital expenditures was $39.4 million, including development expenditures and our acquisition and divestiture activity. We expect to fund future capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditures budget and which may be financed through equity consideration, like the Lucero Acquisition. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity including issuing equity or debt securities and extending maturities. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline or we are otherwise unable to access capital or liquidity. Reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected financial returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, change in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see Part I. Item 3 Quantitative and Qualitative Disclosures About Market Risk.

Effects of Inflation and Pricing. The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put pressure on the economic stability and pricing structure within the industry. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and

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natural gas properties, and values of properties in purchase and sale transactions. Such changes can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.

Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three and six months ended June 30, 2026 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2025.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Note 2 (“Significant Accounting Policies”) to the Condensed Consolidated Financial Statements set forth in Part I, Item 1.

Off Balance Sheet Arrangements

We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and, as a result, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and we believe these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil and natural gas that also increase and decrease along with oil and natural gas prices.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of other comprehensive income or other income (expense).

We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production. We use natural gas basis swaps to complement our natural gas collars, helping mitigate pricing differences between benchmark settlement methods and the local prices we receive for production. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility.

See Note 4 (“Fair Value Measurements”) and Note 6 (“Commodity Derivative Instruments”) to the Condensed Consolidated Financial Statements for further details regarding our commodity derivatives.

Based upon our open commodity derivative positions at June 30, 2026, a hypothetical 10% increase or decrease in the NYMEX WTI strip price would decrease or increase our net commodity derivative position by approximately $29.3 million and $29.0 million, respectively. A hypothetical 10% increase or decrease in the Henry Hub-NYMEX strip price, related basis swaps and NGL prices would decrease or increase our net commodity derivative position by approximately $1.5 million and $1.6 million, respectively. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices increase or decrease.

Interest Rate Risk

Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement. At our option, borrowings under the Revolving Credit Facility bear interest at either an adjusted forward-looking term rate based on SOFR (“Term SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the Federal Funds Rate plus 0.50% or the 30-day Term SOFR rate plus 1.0%), plus a spread ranging from 1.50% to 2.50% with respect to Base Rate borrowings and 2.50% to 3.50% with respect to Term SOFR borrowings, in each case based on the borrowing base utilization percentage. All outstanding principal is due and payable upon termination of the Revolving Credit Facility. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be an approximate $0.7 million increase or decrease in interest expense for the six months ended June 30, 2026.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial and accounting officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2026. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial and accounting officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial and accounting officer concluded that our disclosure controls and procedures were effective as of June 30, 2026 at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the second quarter of 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. 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.

For additional information regarding our legal proceedings, refer to Note 9 (“Commitments and Contingencies”) to the Condensed Consolidated Financial Statements and to Part I, Item 3, Legal Proceedings, in our Annual Report on Form 10-K for the year ended December 31, 2025.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in Part I, Item 1A. Risk Factors, of our Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2025.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

In February 2023, our board of directors approved a Stock Repurchase Program authorizing the repurchase of up to $60 million of our common stock. Under the Stock Repurchase Program, we may repurchase shares of our common stock from time to time in open market transactions or such other means as will comply with applicable rules, regulations and contractual limitations. Our board of directors may limit or terminate the Stock Repurchase Program at any time without prior notice. The extent to which we repurchase shares of our common stock, and the timing of such repurchases, will depend upon market conditions and other considerations as may be considered in our sole discretion.

The table below sets forth the information with respect to purchases made by us or on our behalf, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) of our common stock during the three months ended June 30, 2026.



Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
April 1, 2026 to April 30, 2026	—	$	—	—	$	59.8	million
May 1, 2026 to May 31, 2026	—	—		—	59.8		million
June 1, 2026 to June 30, 2026	—	—		—	59.8		million
Total	—	$	—	—	$	59.8	million

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

Rule 10b5-1 Trading Arrangements

During the three months ended June 30, 2026, no director or officer of the Company adopted, modified or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” within the meaning of Item 408(a) of Regulation S-K.

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6. Exhibits

Exhibit No.

Description

Reference

3.1

Amended and Restated Certificate of Incorporation of Vitesse Energy, Inc.

Incorporated by reference to Exhibit 3.1 to Form 8-K filed January 17, 2023, File No. 001-41546

3.2

Amended and Restated Bylaws of Vitesse Energy, Inc.

Incorporated by reference to Exhibit 3.2 to Form 8-K filed January 17, 2023, File No. 001-41546

4.1

Registration Rights Agreement, dated as of April 8, 2026, by and among Vitesse Energy, Inc., Titan Exploration, LLC and the other parties thereto.

Incorporated by reference to Exhibit 4.1 to Form 8-K filed April 10, 2026, File No. 001-41546

10.1

F ifth A mendment to Second Amended and Restated Credit Agreement

Incorporated by reference to Exhibit 10.4 to Form 10-Q filed May 4, 2026 File No 001-41546

31.1

Certification of the Chief Executive Officer required by Rule 13a, 14(a) or Rule 15d-14(a)

Filed herewith.

31.2

Certification of the Chief Financial Officer required by Rule 13a, 14(a) or Rule 15d-14(a)

Filed herewith.

32.1

Certification of the Chief Executive Officer and Chief Financial Officer required by Rule 13a, 14(a) or Rule 15d-14(a)

Furnished herewith.

101.INS

XBRL Instance Document

Formatted as Inline XBRL and contained in Exhibit 101.

101.SCH

XBRL Schema Document

Furnished herewith.

101.CAL

XBRL Calculation Linkbase Document

Furnished herewith.

101.LAB

XBRL Label Linkbase Document

Furnished herewith.

101.PRE

XBRL Presentation Linkbase Document

Furnished herewith.

101.DEF

XBRL Definition Linkbase Document

Furnished herewith.

104

Cover Page Interactive Data File

Formatted as Inline XBRL and contained in Exhibit 101.

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SIGNATURES

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

Signature

Title

Date

/s/ Jamie Benard

Chief Executive Officer and President

August 3, 2026

Jamie Benard

(Principal Executive Officer)

/s/ James P. Henderson

Chief Financial Officer

August 3, 2026

James P. Henderson

(Principal Financial and Accounting Officer)

Vitesse Energy, Inc. 10-Q