Vitesse Energy, Inc.

Overview

We are an independent energy company focused on returning capital to stockholders through owning interests, predominantly as a non-operator, in oil and natural gas wells. We primarily engage in the acquisition, development and production of non-operated oil and natural gas properties in the United States that are generally operated by leading oil companies and are primarily in the Williston Basin of North Dakota and Montana, and we have limited operations in the Williston Basin through the Lucero Acquisition which we closed on March 7, 2025 in an all-stock transaction. We also have non-operated properties in the Central Rockies, including the Denver-Julesburg Basin and the Powder River Basin. Since our inception, we have built a strong and diversified asset base through a combination of property acquisitions, development activities and the implementation of proprietary platforms and processes utilizing our extensive data resources. We believe the location and concentration of our assets in some of North America’s leading unconventional oil and natural gas resource plays, along with our technical and data capabilities, provide us with acquisition and development opportunities that will result in significant long-term value. We are focused on using our cash flow to provide returns of capital to stockholders and maintain or grow our oil and natural gas production by developing our extensive inventory of drilling and completion locations and acquiring both producing wells and new development opportunities, while maintaining a strong balance sheet.

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

We owned an average working interest of 3.5% in 6,402 gross (226.1 net) productive wells and royalty interests in an additional 1,301 productive wells as of December 31, 2025. We develop our oil and natural gas acreage both as an operator and, on a proportionate basis, as a non‑operator alongside third‑party interests in wells within spacing units that include our acreage. As of December 31, 2025, we owned a working interest in 283 gross (6.1 net) wells that were being drilled or completed, and an additional 336 gross (15.9 net) wells that had been permitted for future development by us or our operating partners. With respect to our non-operated assets, we rely on our operators to propose, permit and initiate the drilling and completion of wells. We assess each drilling and completion opportunity on a case-by-case basis and participate in wells that are expected to meet a desired rate of return based upon estimates of recoverable oil and natural gas reserves, anticipated oil and natural gas prices, the expertise of the operator, and the anticipated completed well cost from each project, as well as other factors.

Our business model provides us with inherent flexibility regarding the cadence of capital deployment and the agility to allocate a portion of our cash flow to the drilling and completion opportunities that we believe will achieve the highest rate of return. We work with more than 30 experienced operators that provide technical insights and opportunities for additional acquisitions and continued development.

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

The following table provides a summary of certain information regarding our assets as of December 31, 2025, including proved reserves as prepared by our third-party independent reserve engineers, Cawley.

(1)In addition, we have royalty interests in 1,301 productive wells, on 1,469 net royalty acres.

(2)Represents the average daily production for the twelve months ended December 31, 2025.

(3)Proved reserve quantities and related PV-10 values have been derived from a WTI oil price of $66.01 per Bbl and Henry Hub natural gas price of $3.39 per MMBtu, which were calculated using an average of the first-day-of-the-month price for each month within the 12 months ended December 31, 2025 as required by SEC and FASB guidelines, adjusted for average 2025 differentials. PV-10 is a non-GAAP financial measure that does not include the effects of income taxes on future net revenues, and is not intended to represent fair market value of our oil and natural gas properties. For a definition of and reconciliation of PV-10 to its nearest GAAP financial measure, see Part II. Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations —Non-GAAP Financial Information.

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

In addition to the proved reserves shown in the table above, we believe our acreage also includes undeveloped drilling and completion locations not currently classified as proved as of December 31, 2025. While many of our undeveloped drilling and completion locations qualify as geologic and engineering proved reserves, we limit our proved undeveloped reserves to those locations that are reasonably certain to be developed over the next five years.

The Spin-Off

On January 13, 2023, Jefferies completed the legal and structural separation of the Predecessor of Vitesse from Jefferies. To effect the separation Jefferies distributed all of our outstanding common stock held by Jefferies to Jefferies’ shareholders, and we became an independent, publicly traded company. Our common stock began trading on the New York Stock Exchange on January 17, 2023 under the symbol “VTS.” In connection with the Spin-Off, we entered into certain agreements that governed, and will govern, our relationship with Jefferies, including a Separation and Distribution Agreement and a Tax Matters Agreement.

Business Strategy

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

■Dividends to Stockholders. Our business plan focuses on building a diversified, low-leverage, free cash flow generating business that can deliver meaningful dividends to our stockholders. We made cash distributions to our stockholders/members totaling $92.1 million, $63.6 million, and $58.0 million during the years ended December 31, 2025, 2024 and 2023, respectively.

■Growth through Value-Enhancing Acquisitions. We have been a consolidator and clearing house of non-operated working interests in various leading oil and natural gas shale plays in the United States, and we will continue that strategy and consider operated asset packages, such as the Lucero Acquisition, and other acquisition strategies going forward. Our near-term drilling acquisition strategy is centered around building a strong presence in our core basins by acquiring smaller non-operated lease and wellbore positions with direct exposure to near-term drilling activity. By virtue of their smaller footprint, these targeted acquisitions are generally completed at a significant discount to the prices paid for contiguous acreage positions typically sought by larger producers and operators of oil and natural gas wells. Acquisitions such as these have been a significant driver of increasing our production. In addition to smaller acquisitions, we also consider larger transactions such as the Lucero Acquisition. Since our inception, in 2014, and through December 31, 2025, we have closed approximately 175 discrete acquisitions totaling more than $785 million, and we intend to continue these activities, while at the same time evaluating and pursuing larger asset packages in both our current area of operations and other areas. We believe our disciplined acquisition strategy can responsibly add production, cash flow and scale to existing operations.

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

■Risk Diversification. We seek to diversify our capital and operational risk through participation in a large number of oil and natural gas wells with multiple operators across multiple basins. We seek to diversify our risk by operator, formation, value concentration and commodity (oil and natural gas). As of December 31, 2025, we owned an average working interest of 3.5% in 6,402 gross (226.1 net) productive wells and royalty interests in an additional 1,301 productive wells, with more than 30 experienced operators that provide development and production activities on our oil and natural gas properties. We believe we can further diversify our risk over time with acquisitions in additional basins, focusing on accretive acquisitions of high-quality assets with experienced operators in the most prolific basins in the United States.

■Strong Balance Sheet and Financial Flexibility. We focus on maintaining financial strength and flexibility through the prudent management of our balance sheet and free cash flow. We maintain conservative indebtedness and a simple capital structure consisting of our Revolving Credit Facility and common stock. We intend to maintain the flexibility to manage our free cash flow by continuing to adhere to a target Net Debt to Adjusted EBITDA ratio of less than 1.0.

■Hedging Strategy. To protect our ability to pay dividends, to fund capital investments and to reduce our exposure to the volatility of oil, natural gas and natural gas liquids, we enter into hedging derivative instruments for a portion of our expected oil and natural gas production, which may include swaps, collars, puts and other structures. We buy oil, natural gas and natural gas liquids futures both on an opportunistic basis when prices have allowed us to lock in attractive rates of return on our asset base and upon acquisitions of larger producing assets to protect returns. For further information see Part II. Item 7A. Quantitative and Qualitative Disclosure about Market Risk -”Commodity Price Risk.”

■Responsible Stewards. We work to provide safe, reliable and affordable energy in a responsible manner by partnering with responsible operators in our core areas, while being cognizant of the broader energy transition. We focus on identifying opportunities to reduce our environmental impact, improving safety, investing in our employees, and supporting the communities in which we live and work while improving transparency and accountability. Our Board is majority independent and composed of experienced professionals with a strong background in the energy industry and more broadly in business.

Our Competitive Strengths

We believe the following competitive strengths will support the successful execution of our business strategies:

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

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

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

■Proactive Asset Management Philosophy. Our experienced team of landmen and accountants review acquired assets to unlock incremental value. Many assets we acquire have title defects or other land related issues where deep analysis and consistent, quality diligence adds value in many areas, including increased working interest ownership and working capital management. Our long-term view provides the time to solve issues and find additional well interests to increase the velocity of overall returns. This is enabled by strong departmental relationships with operators and accurate data management.

Our Properties

Williston Basin (North Dakota and Montana)

The Williston Basin stretches from western North Dakota into eastern Montana, with the majority of drilling activity conducted by our operators located in Dunn, McKenzie, Mountrail, and Williams Counties, North Dakota. Approximately 79% of our 53,301 net acres as of December 31, 2025 are in the above counties and target the Bakken and Three Forks formations. Nearly all of our acreage in the Williston Basin is held by production. As of December 31, 2025, we had a working interest in 6,275 gross (210.0 net) productive wells and royalty interests in an additional 1,274 productive wells. In addition to these productive wells, we had 279 gross (4.3 net) working interest wells that were being drilled or completed, and 322 gross (15.5 net) wells that have been permitted for future development by us or our operating partners. Our estimated proved reserves in North Dakota and Montana as of December 31, 2025 were 45,860 MBoe (65% oil), which represented 96% of our total estimated proved reserves and contributed average production of 16,861 Boe per day for the year ended December 31, 2025.

We have been active in the Williston Basin since 2014 and have seen our thesis for continued growth and expansion of the field come to fruition. The Williston Basin is a world-class oil field and we expect to see continued growth in recoverable reserves for many years. We have a significant inventory of remaining undeveloped drilling locations that we expect to see developed over the next 15 to 25 years. In addition, we are seeing incremental growth and development throughout the field utilizing newer technologies including refrac programs and extended length three and four mile lateral wells.

Central Rockies (Colorado and Wyoming)

The Denver-Julesburg Basin is located in Northeast Colorado and Southeast Wyoming, with the majority of operator horizontal drilling activity located in Weld and Adams Counties, Colorado, and Laramie County, Wyoming. Our assets in this area primarily consist of wellbore only ownership and target the Codell formation and several productive zones within the Niobrara formation. We owned a working interest in 121 gross (15.0 net) productive wells as of December 31, 2025 and royalty interests in an additional 27 productive wells. In addition to the productive wells, we have 4 gross (1.8 net) wells that were being completed, and 11 gross (0.4 net) wells that have been permitted for future development by our operating partners as of December 31, 2025.

Our Powder River Basin assets primarily target the Parkman, Sussex, Turner and Niobrara formations. We owned a working interest in 6 gross (1.0 net) productive wells as of December 31, 2025. In addition to these productive wells, we have 3 gross (0.1 net) wells that have been permitted for future drilling by our operators as of December 31, 2025.

Reserves

Estimated Net Proved Reserves

The table below summarizes our estimated net proved reserves for the periods indicated based on reports prepared by Cawley, our third-party independent reserve engineer, except as otherwise described herein. In preparing its reports, Cawley evaluated properties representing our total proved reserves as of December 31, 2025, 2024 and 2023 in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities. Our estimated net proved reserves in the table below do not include probable or possible reserves, do not in any way include or reflect our commodity derivatives and do not reflect the Lucero Acquisition for periods prior to March 7, 2025.

Estimated net proved reserves as of December 31, 2025 were 47,800 MBoe, and we held working interests in 28.6 net proved undeveloped drilling locations included in such reserves as of December 31, 2025.

The table below sets forth summary information by reserve category with respect to estimated proved reserves volumes and related PV-10 values as of December 31, 2025.

(1)Oil and natural gas reserve quantities and related discounted future net cash flows are valued as of December 31, 2025 and are derived from a WTI price of $66.01 per Bbl and Henry Hub natural gas price of $3.39 per MMBtu, adjusted for average 2025 differentials. Under SEC guidelines, these prices represent the average prices per Bbl of oil and per MMBtu of natural gas at the beginning of each month in the twelve-month period prior to the end of the reporting period.

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

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

Estimated Net Proved Undeveloped Reserves

As of December 31, 2025, we had approximately 13,777 MBoe of estimated net proved undeveloped reserves. Changes in estimated net proved undeveloped reserves that occurred from December 31, 2024 to December 31, 2025 were due to:

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

■Acquisitions: We acquired 6,303 MBoe of proved undeveloped reserves in the Williston Basin and Central Rockies during 2025, which includes the Lucero Acquisition.

■Extensions, discoveries and other additions: During 2025, extensions and discoveries associated with proved undeveloped locations in the Williston Basin added 4,065 MBoe of proved undeveloped reserves, which moved from non-proved to proved primarily based on updated information on near term operator drilling plans.

■Transfers to estimated proved developed reserves: Development costs of approximately $74 million were incurred in connection with the conversion of approximately 8.2 net undeveloped locations classified as proved at December 31, 2024, and 4,643 MBoe of proved undeveloped reserves were transferred to proved developed reserves during 2025. In addition to the conversion and transfer of proved reserves, although not included in the table above, 205 MBoe of reserves from 0.4 net undeveloped locations not classified as proved undeveloped at December 31, 2024 were transferred to proved developed reserves during the period.

■Revisions: In 2025, revisions to previous estimates decreased proved undeveloped reserves by a net amount of 4,986 MBoe. These revisions were primarily attributable to the reclassification of undeveloped drilling locations totaling 2,309 MBoe of proved reserves from proved to non-proved primarily based on updated information on near term operator drilling plans and continued compliance with the SEC 5-year development rule. An additional 1,708 MBoe decrease is related to lower commodity prices and 707 MBoe is due to non-consenting and interest changes. In addition, the revisions included decreases in proved undeveloped reserves of 262 MBoe related to higher differentials and LOE, and updated forecasts and scheduling.

We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled on our acreage. We also expect that some component of our undeveloped drilling locations not classified as proved at December 31, 2025 will be converted to proved developed producing reserves. All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with development plans.

As of December 31, 2025, the PV-10 value of our proved undeveloped reserves amounted to approximately 12% of the PV-10 value of our total proved reserves. There are numerous uncertainties regarding undeveloped reserves. The development of these reserves is dependent upon a number of factors which include but are not limited to: financial targets such as drilling within cash flow or reducing debt, satisfactory rates of return on proposed drilling projects, and the timing and level of drilling activity by us and operators in areas where we hold leasehold interests. With 87% of the PV-10 value of our total proved reserves supported by producing wells, we believe we will have sufficient cash flows and adequate liquidity to execute our development plan. PV-10 is a non-GAAP financial measure that does not include the effects of income taxes on future net revenues and is not intended to represent the fair market value of our oil and natural gas properties. For a definition of and reconciliation of PV-10 to its nearest GAAP financial measure, see Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - "Non-GAAP Financial Information.”

Independent Petroleum Engineers

We have engaged Cawley to prepare our estimated proved reserves. Cawley is an independent reservoir-evaluation consulting firm who evaluates oil and natural gas properties and independently certifies petroleum reserves quantities for various clients throughout the United States. Cawley has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and, as such, we believe Cawley has sufficient experience to appropriately determine our reserves. Cawley utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience. The reports of our estimated proved reserves in their entirety are based on the information we provide to them.

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

The reserves set forth in the Cawley report for our properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.

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

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

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. See “Part I. Item 1A. Risk Factors—Risks Relating to our Business—Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our total reserves.”

Internal Controls Over Reserves Estimation Process

We utilize Cawley, a third-party reservoir engineering firm, as our independent reserves evaluator for 100% of our proved reserves base. Cawley is a Texas Registered Engineering Firm (F-693). The technical person at Cawley who is primarily responsible for overseeing the preparation of our reserves estimates is Todd Brooker, President. Mr. Brooker is a state of Texas Licensed Professional Engineer (License # 83462). He is also a member of the Society of Petroleum Engineers and has over 25 years of experience in oil and natural gas reservoir studies and evaluations. In addition, we employ an internal engineering department, with the reserves process led by our Senior Reserves Engineer, who is responsible for overseeing the preparation of our reserves estimates. Our Senior Reserves Engineer has a B.S. in Chemical Engineering from the University of Tulsa, over twenty years of oil and gas experience, including 15 years with a focus on reserve evaluation, and additional experience with operations and production engineering in multiple basins.

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

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

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

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

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

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

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

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

Production, Price and Production Expenses

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

The table below sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. The information included in the following table does not reflect the Lucero Acquisition for periods prior to March 7, 2025. For additional information on price calculations, see the information in "Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Drilling and Development Activity

The table below sets forth the number of gross and net productive and non-productive wells in which we owned a working interest drilled in the periods indicated. The number of wells drilled refers to the number of wells completed at any time during the period, regardless of when drilling was initiated. The following table does not reflect the Lucero Acquisition for periods prior to March 7, 2025.

(1) Includes royalty interests in 75 gross (0.13 net) wells drilled in the year ended December 31, 2025, 49 gross (0.06 net) wells drilled in the year ended December 31, 2024, and 83 gross (0.12 net) wells drilled in the year ended December 31, 2023.

The tables below set forth summary information by location with respect to estimated productive wells in which we owned a working interest or a royalty interest, as applicable as of December 31, 2025.

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

As of December 31, 2025, we owned a working interest in 283 gross (6.1 net) wells that were being drilled or completed, and an additional 336 gross (15.9 net) wells that had been permitted for development by us or our operating partners.

Acreage

The table below sets forth our estimated gross and net developed and undeveloped acreage by geographic area as of December 31, 2025.

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

Approximately 87% of our undeveloped acreage is held by production as of December 31, 2025, with only 162 gross (162 net) acres and 202 gross (88 net) acres subject to potential expiration in 2027 and 2028, respectively.

Industry Operating Environment

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

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

Development

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

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

Competition

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

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

Title to Our Properties

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

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

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

Seasonality

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

Regulation and Environmental Matters

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

Regulation of Oil and Natural Gas Production

Our oil and natural gas development, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, the states in which our operations and properties are located require permits for drilling operations and impose, among other requirements, bonding and reporting obligations related to the development and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, limitations or prohibitions on the venting or flaring of natural gas, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the federal government and its agencies have from time to time, imposed or considered imposing new or more stringent rules or policies that impact oil and gas exploration and production operations, including pausing or withholding acreage from lease sales and increasing royalty rates on federal lands, restricting national oil and gas exports and related infrastructure, and regulating or taxing emissions from production facilities. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their jurisdictions. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC, EPA and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of Transportation and Sales of Oil, Condensate and NGLs

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil, condensate and NGLs (collectively referred to as “oil pipelines”) by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market- based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost-of-service filing. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. FERC issued an order on December 17, 2020 establishing an inflationary adjustment of Producer Price Index for Finished Goods (“PPI-FG”) plus 0.78% (PPI-FG+0.78%) for the five-year period commencing July 1, 2021 (the “December 2020 Order”). Numerous requests for rehearing were filed. On January 20, 2022, FERC issued an order on rehearing in which it modified the methodology used to calculate the inflationary adjustment resulting in a revised inflationary adjustment for the five-year period commencing July 1, 2021, of PPI-FG minus 0.21% (PPI-FG-0.21%) (the “Rehearing Order”). As a result of the Rehearing Order, the index factor for the July 1, 2021 through June 30, 2022 index year provided for a negative percentage change of approximately 1.6%. The Rehearing Order was subsequently challenged and vacated by the D.C. Circuit in LEPA v. FERC, 109 F.4th 543 (D.C. Cir. 2024), reinstating the index level established by the December 2020 Order. On October 17, 2024, FERC issued a supplemental notice of proposed rulemaking in which FERC proposed to prospectively adopt the PPI-FG-0.21% index that was vacated by the D.C. Circuit and instituted a notice-and-comment process. On November 20, 2025, FERC withdrew the October 17, 2024 supplemental notice of proposed rulemaking and confirmed that the PPI-FG-0.78% index established in December 2020 will remain in place through June 30, 2026. On the same day, FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022 to September 17, 2024 but only if such pipelines charged the maximum rate allowed under the applicable index ceiling during the relevant time period. Parties have since filed requests for clarification or rehearing to determine whether pipelines may recover rate differences in other scenarios.

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

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

Regulation of Transportation and Sales of Natural Gas

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

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

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

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend will likely continue. These laws and regulations may:

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

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

■impose substantial liabilities for pollution resulting from our operations.

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

CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. RCRA, and comparable state statutes, govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although the RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Concern over induced seismicity resulting from the injection of oil field wastes has increased regulatory scrutiny of and local opposition to disposal well operations in certain areas of the United States, though primarily not in the regions in which our interests are located.

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

The CAA controls air emissions from oil and natural gas production and natural gas processing operations, among other sources. EPA regulations under the CAA include NSPS for the oil and natural gas source category to address emissions of pollutants, including sulfur dioxide, methane and VOCs, NAAQS for certain ambient levels of criteria pollutants and a separate set of, including ground-level ozone, and emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities, among other monitoring, reporting, and permitting regulations. In recent years there has been considerable focus and uncertainty regarding the regulation of methane emissions from the oil and gas sector. The EPA promulgated new NSPS regulations in 2024 for upstream and midstream oil and gas facilities that impose, among other provisions, enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring technologies, the reduction of emissions by 95% through capture and control system, zero-emission requirements for specific components and equipment and so-called green well completion requirements, and also establish a “super emitter” response program which would allow certified third parties to report large emission events to the EPA, triggering additional investigation, reporting, and repair obligations. The 2024 NSPS regulations further obligate states to impose these requirements on existing sources through their respective State Implementation Plans. In March 2025, however, the EPA announced an intent to reconsider the 2024 NSPS regulations, and in July 2025, issued an interim final rule extending compliance deadlines for most of the 2024 NSPS regulations into late 2026 or early 2027. Because the 2024 NSPS and 2025 deadline extension rules are subject to ongoing litigation and the EPA is currently reconsidering the 2024 NSPS rule, future implementation of these regulations is uncertain at this time. The BLM’s 2024 waste prevention rule, which limits venting, flaring, and methane leaks for oil and gas operations on federal lands, is also currently subject to both legal challenge and reconsideration pursuant to a directive by the Trump Administration. Nevertheless, these requirements and any future regulatory developments have the potential to increase operating costs for production activities on our properties or require capital to install more sophisticated pollution control equipment and thus may have a material adverse impact on our business, results of operations and financial condition.

The CWA imposes restrictions and controls on the discharge of produced waters and other pollutants into WOTUS. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities, the requirements of which may include the implementation of Spill Prevention, Control and Countermeasure plans. There continues to be uncertainty as to the federal government’s jurisdictional reach under the CWA. The definition of WOTUS has been heavily litigated and the subject of multiple rulemakings in recent years. Implementation of the most recent rule is currently split across the country. The rule is subject to an injunction in 27 states, including Montana and North Dakota, resulting in implementation of the pre-2015 rule adjusted to incorporate jurisdictional limitations decided by the U.S. Supreme Court in Sackett v. EPA. The other 23 states are subject to a WOTUS-defining rule published in September 2023. The Corps is currently pursuing a new post-Sackett rulemaking, the ultimate consequence of which cannot be predicted. The applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of our properties, and changes to the WOTUS definition could cause delays in development or increase the cost of development and operation of our properties. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Operations on our properties are also supported by pipelines and other infrastructure that may require permits obtained from the Corps under the CWA, the most common of which is Nationwide Permit 12 (“NWP 12”). NWP 12 is, from time to time, reviewed and modified by the Corps or subject to litigation. NWP 12 is expected to be reissued by the Corps in 2026. To the extent any action expands the scope of the CWA or imposes new or enhanced permitting requirements in areas that include our properties or where our operating partners and their service providers and customers operate, our financial results could be adversely impacted by increased costs of compliance and energy infrastructure project delays or cancellations.

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

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

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

Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. Several states, including Montana and North Dakota where our properties are located, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. Additionally, a number of municipalities in other states, including Colorado, have sought to ban hydraulic fracturing. While the Colorado Supreme Court ruled that such municipal bans were preempted by state law, the Colorado legislature subsequently enacted “SB 101” which gave local governments significant control over oil and natural gas wellhead operations. Municipalities in Colorado have enacted local rules restricting oil and natural gas operations based on SB 101. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations. For more information on risks related to hydraulic fracturing see Part I. Item 1A. Risk Factors—Risks Relating to Legal and Regulatory Matters—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. Many of the activities of us and our third-party operators are covered under NEPA. Some activities are subject to robust NEPA review which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. Other activities are covered under categorical exclusions which results in a shorter NEPA review process. For more information on risks related to NEPA see Part I. Item 1A. Risk Factors— Risks Relating to Legal and Regulatory Matters—Restrictions on our ability to acquire federal leases and more stringent regulations affecting our operators’ exploration and production activities on federal lands may adversely impact our business.

Climate Change

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

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from oil and gas production sources in the United States on an annual basis, which may include operations on our properties. Other federal agencies, including the BLM, and several states have also introduced rules regarding the disclosure or regulation of GHG emissions or have incorporated climate change considerations into their decision-making processes. Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several administrations. The current Trump Administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and has promulgated a final rule repealing the EPA’s 2009 “Endangerment Finding” for GHGs and motor vehicle GHG emission performance standards in February 2026.. The rescission of the “Endangerment Finding” eliminates the basis for the EPA’s authority under the CAA for most of its regulations concerning GHGs. Whether or how such policies and the EPA’s rescission of its “Endangerment Finding” will be implemented and if they survive any potential legal challenges, or whether future administrations will pursue new GHG emissions regulation, cannot be predicted at this time.

Congress has from time to time considered legislation to monitor, limit, or reduce emissions of GHGs, but to date has not passed comprehensive climate legislation. However energy legislation and other regulatory initiatives have been and continue to be proposed that are relevant to climate change and GHG emissions issues. For example, in 2022, the IRA was enacted to advance climate-related objectives and provide significant financial support for alternative or lower GHG-emitting energy production and supporting infrastructure. However, the OBBBA, which was signed into law in 2025, rescinded or eliminated funding for many of these IRA programs. While the OBBBA limits current federal initiatives to address climate change and GHG emissions reductions, whether Congress will pass future legislation to restore funding for certain IRA programs or advance new climate-related proposals cannot be predicted. In addition, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs, direct emissions limitations, or superfund-style strict liability laws. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. For example, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from our properties. For a more detailed discussion of the risks associated with climate change legislation or regulation, see Part I. Item 1A Risk Factors Risks Relating to Legal and Regulatory Matters—”The adoption of climate change legislation or regulations restricting emissions of carbon dioxide, methane, and other greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.”

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

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

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

Human Capital Management

As of December 31, 2025, we had 37 full time employees. We may hire additional personnel as appropriate. We also may use the services of independent consultants and contractors to perform various professional services. We are focused on attracting, engaging, developing, retaining and rewarding top talent. We strive to enhance the economic and social well-being of our employees. We are committed to providing a welcoming environment for our workforce, with excellent training and career development opportunities to enable employees to thrive and achieve their career goals.

Corporate Information

The Company’s corporate website can be found at https://vitesse-vts.com/. The Company makes available free of charge at this website (under the “Investor Relations – SEC Filings” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q, and its Current Reports on Form 8-K. In addition to its reports filed or furnished with the SEC, the Company publicly discloses material information from time to time in its press releases and Investor presentations, all of which are accessible through the website under the heading “Investor Relations” and the subheading “News & Events.” The Company’s Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters of the Audit, Compensation, Nominating, Governance and Environmental and Social Responsibility Committees of the Board are available on the Company’s website under the heading “Investor Relations”, the subheading “Governance,” and the subheading “Governance Documents.” References to the Company's website in this Annual Report on Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Annual Report on Form 10-K.

Office Location

Our principal executive offices are located at 5619 DTC Parkway, Suite 700, Greenwood Village, CO 80111. Our current office space consists of approximately 22,000 square feet of leased space. We believe the office space will be sufficient to meet our needs as well as support future growth as necessary.