EDGAR 10-K Filing

Company CIK: 1944558
Filing Year: 2025
Filename: 1944558_10-K_2025_0001944558-25-000033.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
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, although we have assumed limited operations in the Williston Basin through the Lucero Acquisition. 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 eleven years, we have executed on our technical, data driven, and financially disciplined acquisition and development strategy to build our core position in the Williston Basin and Central Rockies and grow our oil and natural gas production. During that time, we have focused on limiting our downside by maintaining conservative acquisition guidelines, limiting our debt leverage and opportunistically hedging our oil production. As a result, we have been able to preserve value when many independent energy companies were forced into financial recapitalizations and restructurings when commodity prices collapsed in 2014, 2018 and 2020.
We owned an average working interest of 2.8% in 6,071 gross (168.2 net) productive wells and royalty interests in an additional 1,180 productive wells as of December 31, 2024. We have engaged in oil and natural gas development by participating on a proportionate basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. As of December 31, 2024, we owned a working interest in 248 gross (9.7 net) wells that were being drilled or completed, and an additional 362 gross (8.0 net) wells that had been permitted for future development by 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.
On March 7, 2025, the Lucero Acquisition was consummated pursuant to which we acquired Lucero in an all-stock transaction. Lucero shareholders received 0.01239 of a share of Vitesse common stock for each common share of Lucero (other than Lucero common shares with respect to which dissenters’ rights have been validly exercised and not validly withdrawn), with 8,169,368 shares of Vitesse common stock issued. Lucero is an oil and natural gas operator with assets in the Bakken and Three Forks formations in the Williston Basin area of North Dakota. Upon completion of the Lucero Acquisition, prior Vitesse stockholders owned approximately 80% and prior Lucero shareholders owned approximately 20% of the common stock of the Company on a fully diluted basis.
The Lucero Acquisition is expected to strengthen our balance sheet and cash flows and serve to enhance our competitive strengths by increasing the optionality of our capital deployment through adding a limited operating function while maintaining our focus on assets in the Williston Basin.
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, 2024, including proved reserves as prepared by our third-party independent reserve engineers, Cawley.
AS OF DECEMBER 31, 2024
NET ACRES(1)
PRODUCTIVE WELLS (1) GROSS
NET AVERAGE DAILY PRODUCTION (2) (Boe/d)
PROVED RESERVES (3) (MBoe)
PV-10 (3)
(in thousands)
% OIL % PROVED DEVELOPED
Williston Basin 47,840 5,960 152 12,341 38,469 $ 560,598 69 % 66%
Central Rockies (4)
205 111 16 662 1,814 25,992 50 % 92%
Total/Weighted Average 48,045 6,071 168 13,003 40,283 $ 586,590 68 % 68%
(1)In addition, we have royalty interests in 1,180 productive wells, on 1,411 net royalty acres.
(2)Represents the average daily production for the twelve months ended December 31, 2024.
(3)Proved reserve quantities and related PV-10 values have been derived from a WTI oil price of $76.32 per Bbl and Henry Hub natural gas price of $2.13 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, 2024 as required by SEC and FASB guidelines, adjusted for average 2024 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, 2024. 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, first, Jefferies, among others, undertook certain Pre-Spin-Off Transactions described below:
■Certain members of management of the Predecessor transferred all of their equity interest in the Predecessor to Jefferies as repayment for prior loans;
■Jefferies and other holders of the Predecessor's equity interests transferred all of their interest in the Predecessor to us in exchange for newly issued shares of our common stock;
■Vitesse Oil equity holders transferred their interests to us in exchange for newly issued shares of our common stock;
■Previous compensation agreements and compensation plans were eliminated and replaced with new compensation plans including the LTIP; and
■We entered into a Revolving Credit Facility, which amended and restated the Prior Revolving Credit Facility, and used the proceeds to repay in full and terminate the Vitesse Oil Revolving Credit Facility and repay the Prior Revolving Credit Facility.
Jefferies then distributed all of our outstanding common stock held by Jefferies to Jefferies’ shareholders, and we became an independent, publicly traded company. After the Distribution, Jefferies does not own any shares of our common stock. In connection with the Spin-Off, we entered into certain agreements that governed, and will govern, our relationship with Jefferies, including a Separation and Distribution Agreement and a Tax Matters Agreement. Also, in connection with the Spin-Off, the Predecessor became a wholly owned subsidiary of a taxable entity (Vitesse). Therefore, we recorded the effects of income taxes within our consolidated financial statements which include the consolidated results of operations of the Predecessor and Vitesse Oil, as well as reflect the basis differences between tax and financial accounting for the assets and liabilities.
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. We believe the Lucero Acquisition is consistent with and enhances these core strategies. 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 $63.6 million, $58.0 million, and $36.0 million during the years ended December 31, 2024, 2023 and 2022, 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, 2024, we have closed approximately 170 discrete acquisitions totaling more than $570 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, 2024, we owned an average working interest of 2.8% in 6,071 gross (168.2 net) productive wells and royalty interests in an additional 1,180 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 maintain 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 (last twelve months) of less than 1.0.
■Hedging Strategy. To protect our ability to pay distributions, to fund capital investments and to reduce our exposure to the volatility of oil and natural gas prices, we have entered into hedging derivative instruments for a portion of our expected oil and natural gas production, which have included swaps, collars, puts and other structures. We have bought oil futures both on an opportunistic basis when WTI prices have allowed us to lock in attractive rates of return on our asset base and upon acquisitions of larger producing assets to protect returns. Our hedged position mitigates our exposure to volatile oil and natural gas prices, with approximately 2.3 million barrels hedged in 2025 at an average price of $71.16 per Bbl and approximately 0.9 million barrels hedged in 2026 at an average price of $66.95 per Bbl as of December 31, 2024. In the past, based on then-existing market conditions, we have hedged significantly higher percentages of our actual oil production. We entered into a number of costless collars of natural gas in the first quarter of 2025. 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 that we will be able to successfully execute our business strategies because of the following competitive strengths:
■Every Decision is a Financial Decision. Our business culture encourages employees to think like owners and to make decisions with a long-term perspective. We have developed a systematic approach of responsibly reviewing acquisition and development opportunities. As part of our efforts to maximize returns, we have established a capital allocation framework with the objective of allocating capital to acquisitions and development of oil and natural gas properties to drive sustainability and growth in free cash flow, the repayment of debt and payment of stockholder dividends. This framework entails disciplined investment in capital expenditures and acquisitions, allowing us to distribute a significant portion of our cash flow to our stockholders. We also retain flexibility with respect to share repurchases, subject to approval from our Board and as conditions warrant. We will continue to
evaluate and pursue profitable and accretive acquisition and consolidation opportunities that enhance stockholder value and build scale. As opportunities arise, we intend to identify and acquire additional acreage and producing assets to supplement our existing operations.
■Data and Technology Driven. Our proprietary data-driven approach allows for rapid multi-disciplinary evaluation to determine the most attractive acquisition and development opportunities. We created customized data systems 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. Vitesse’s management team has developed deep and longstanding relationships with many of our operators, other working interest and mineral owners, investment banks, acquisition and divestiture companies and investors. A majority of our evaluated and executed acquisitions and transactions are self-sourced. We have become a preferred non-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
The following discussion of our properties reflects the properties owned by Vitesse as of December 31, 2024 and does not give effect to any properties acquired in the Lucero Acquisition unless otherwise indicated.
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 76% of our 47,840 net acres as of December 31, 2024 are in the above counties and target the Bakken and Three Forks formations. All of our acreage in the Williston Basin is held by production. As of December 31, 2024, we had a working interest in 5,960 gross (152.3 net) productive wells and royalty interests in an additional 1,180 productive wells. In addition to these productive wells, we had 239 gross (7.7 net) working interest wells that were being drilled or completed, and 345 gross (7.8 net) wells that have been permitted for future development by our operating partners. Our estimated proved reserves in North Dakota and Montana as of December 31, 2024 were 38,469 MBoe (69% oil), which represented 95% of our total estimated proved reserves and contributed average production of 12,341 Boe per day for the year ended December 31, 2024.
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-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 105 gross (14.9 net) productive wells as of December 31, 2024. In addition to the productive wells, we have 9 gross (1.9 net) wells that were being completed by our operating partners as of December 31, 2024.
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, 2024. 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, 2024.
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, 2024, 2023 and 2022 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 and do not in any way include or reflect our commodity derivatives.
AS OF DECEMBER 31,
2024 2023 2022
Estimated proved developed:
Oil (MBbls) 17,431 18,440 17,290
Natural gas (MMcf) 58,885 60,202 58,897
Total (MBoe) 27,245 28,474 27,106
Estimated proved undeveloped:
Oil (MBbls) 9,924 9,303 13,155
Natural gas (MMcf) 18,679 16,907 21,217
Total (MBoe) 13,038 12,121 16,691
Estimated total proved reserves:
Oil (MBbls) 27,355 27,743 30,445
Natural gas (MMcf) 77,564 77,109 80,114
Total (MBoe) 40,283 40,595 43,797
Percent proved developed 67.6 % 70.1 % 61.9 %
Estimated net proved reserves as of December 31, 2024 were 40,283 MBoe, and we held working interests in 27.5 net proved undeveloped drilling locations included in such reserves as of December 31, 2024.
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, 2024.
SEC PRICING PROVED RESERVES (1)
RESERVES VOLUMES PV-10 (3)
RESERVE CATEGORY OIL (MBbls) NATURAL GAS (MMcf) TOTAL (MBoe) (2)
% AMOUNT (in thousands) %
PDP Properties 16,867 57,247 26,408 66 % $ 438,585 75 %
PDNP Properties 564 1,638 837 2 % 19,731 3 %
PUD Properties 9,924 18,679 13,038 32 % 128,274 22 %
Total 27,355 77,564 40,283 100 % $ 586,590 100 %
(1)Oil and natural gas reserve quantities and related discounted future net cash flows are valued as of December 31, 2024 and are derived from a WTI price of $76.32 per Bbl and Henry Hub natural gas price of $2.13 per MMBtu, adjusted for average 2024 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, 2024, we had approximately 13,038 MBoe of estimated net proved undeveloped reserves. Changes in estimated net proved undeveloped reserves that occurred from December 31, 2023 to December 31, 2024 were due to:
MBoe
Balance at December 31, 2023 12,121
Acquisitions 809
Extensions, discoveries and other additions 5,543
Transfers to estimated proved developed reserves (3,409)
Revisions (2,026)
Balance at December 31, 2024 13,038
Notable changes in proved undeveloped reserves for the year ended December 31, 2024 included the following:
■Acquisitions: We acquired 809 MBoe of proved undeveloped reserves in the Williston Basin and Central Rockies during 2024.
■Extensions, discoveries and other additions: During 2024, extensions and discoveries associated with proved undeveloped locations in the Williston Basin added 5,543 MBoe of proved undeveloped reserves.
■Transfers to estimated proved developed reserves: Development costs of approximately $63 million were incurred in connection with the conversion of approximately seven net undeveloped locations classified as proved at December 31, 2023, and 3,409 MBoe of proved undeveloped reserves were transferred to proved developed reserves during 2024. In addition to the conversion and transfer of proved reserves, although not included in the table above, 1,273 MBoe of reserves from three net undeveloped locations not classified as proved undeveloped at December 31, 2023 were transferred to proved developed reserves during the period.
■Revisions: In 2024, revisions to previous estimates decreased proved undeveloped reserves by a net amount of 2,026 MBoe. These revisions were primarily attributable to the reclassification of undeveloped drilling locations totaling 1,838 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. In addition, the revisions included decreases in proved undeveloped reserves of 188 MBoe related to lower commodity prices, 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, 2024 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 our development plan.
As of December 31, 2024, the PV-10 value of our proved undeveloped reserves amounted to approximately 22% of the PV-10 value of our total proved reserves. There are numerous uncertainties regarding undeveloped reserves. The development of these reserves is dependent upon a number of factors which include but are not limited to: financial targets such as drilling within cash flow or reducing debt, satisfactory rates of return on proposed drilling projects, and the level of drilling activity by operators in areas where we hold leasehold interests. With 66% 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 IA. 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 past few years, and the supply of oil could impact oil prices in the United States if the supply outstrips domestic demand. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.
The table below sets forth information regarding our oil and natural gas production, realized prices and production costs for the periods indicated. 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."
FOR THE YEARS ENDED DECEMBER 31,
2024 2023 2022
Net Production:
Oil (MBbls) 3,291 2,968 2,575
Natural gas (MMcf) 8,809 8,232 7,274
Total (MBoe) 4,759 4,340 3,787
Oil (Bbl) per day 8,992 8,130 7,054
Natural gas (Mcf) per day 24,069 22,553 19,929
Total (Boe) per day 13,003 11,889 10,376
Average Sales Prices:
Oil (per Bbl) $ 69.94 $ 73.59 $ 90.73
Effect of gain (loss) on realized oil derivative on average price (per Bbl) 1.54 0.40 (18.07)
Oil net of realized oil derivatives (per Bbl) $ 71.48 $ 73.99 $ 72.66
Natural gas and NGLs (per Mcf) $ 1.34 $ 1.88 $ 6.64
Effect of gain (loss) on realized natural gas derivatives on average price (per Mcf) - - (0.08)
Natural gas and NGLs net of realized natural gas derivative (per Mcf) $ 1.34 $ 1.88 $ 6.56
Realized price on a Boe basis excluding realized commodity derivatives $ 50.85 $ 53.90 $ 74.43
Effect of gain (loss) on realized commodity derivatives on average prices (per Boe) 1.06 0.27 (12.44)
Realized price on a Boe basis net of realized commodity derivatives $ 51.91 $ 54.17 $ 61.99
Average Costs:
Lease operating expense (per Boe) $ 10.00 $ 9.11 $ 8.22
Production taxes (per Boe) $ 4.52 $ 4.98 $ 6.36
Drilling and Development Activity
The table below sets forth the number of gross and net productive and non-productive wells in which we owned a working interest drilled in the periods indicated. The number of wells drilled refers to the number of wells completed at any time during the period, regardless of when drilling was initiated.
YEAR ENDED DECEMBER 31,
2024 2023 2022
GROSS NET GROSS NET GROSS NET
Exploratory Wells:
Productive Oil - - - - - -
Productive Natural gas - - - - - -
Non-productive - - - - - -
- - - - - -
Development Wells:
Productive Oil (1)
366 9.26 414 9.78 295 7.53
Productive Natural gas - - - - - -
Non-productive - - - - - -
366 9.26 414 9.78 295 7.53
Total productive exploratory and development wells (1)
366 9.26 414 9.78 295 7.53
(1) Includes royalty interests in 49 gross (0.06 net) wells drilled in the year ended December 31, 2024, 83 gross (0.12 net) wells drilled in the year ended December 31, 2023, and 45 gross (0.09 net) wells drilled in the year ended December 31, 2022.
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, 2024.
AS OF DECEMBER 31, 2024
PRODUCTIVE WORKING INTEREST OIL WELLS AVERAGE WORKING INTEREST
GROSS NET
Combined Total:
Williston Basin 5,960 152 2.6 %
Central Rockies (1)
111 16 14.3 %
Total 6,071 168 2.8 %
AS OF DECEMBER 31, 2024
PRODUCTIVE ROYALTY INTEREST OIL WELLS AVERAGE ROYALTY INTEREST
GROSS NET
Combined Total:
Williston Basin 1,180 3 0.2 %
Central Rockies (1)
- - - %
Total 1,180 3 0.2 %
(1)Includes Denver-Julesburg and Powder River Basin wells.
As of December 31, 2024, we owned a working interest in 248 gross (9.7 net) wells that were being drilled or completed, and an additional 362 gross (8.0 net) wells that had been permitted for development by 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, 2024.
DEVELOPED
ACREAGE UNDEVELOPED
ACREAGE TOTAL ACREAGE ROYALTY ACRES
GROSS NET GROSS NET GROSS NET GROSS NET
Williston Basin 1,665,203 45,476 60,129 2,364 1,725,332 47,840 129,163 1,410
Central Rockies (1)
3,070 113 11,520 92 14,590 205 640 1
Total 1,668,273 45,589 71,649 2,456 1,739,922 48,045 129,803 1,411
(1)Includes Denver-Julesburg and Powder River Basin acreage.
Nearly 100% of our undeveloped acreage is held by production as of December 31, 2024, with only 640 gross (5 net) acres subject to potential expiration in 2025.
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 limited operations in the Williston Basin and will assume responsibility for development activities related to those operations going forward. 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 limited operations in the Williston Basin and will assume responsibility for marketing activities related to those operations going forward. 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, North Dakota and Montana require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the development and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, limitations or prohibitions on the venting or flaring of natural gas, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the 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. Subject to a final FERC order following the notice-and-comment period, the lower index of PPI-FG-0.21% may become effective for the remainder of the current five-year period starting from the date of a final FERC order and lasting through June 30, 2026. If the proposed index change becomes effective, then interstate oil pipelines would need to re-file their rates on a prospective basis. The comment period ended on December 20, 2024, with a possible FERC order coming in 2025.
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 on the regulation of methane emissions from the oil and gas sector. The EPA proposed and finalized more stringent methane rules for new, modified, and reconstructed upstream and midstream facilities under NSPS Subpart OOOOb, as well as, for the first time ever, standards for existing sources under NSPS Subpart OOOOc in December 2023. The final rules expand the scope of regulated oil and gas sources beyond those currently regulated under the existing NSPS Subpart OOOOa. Under the final rules, states have two years to prepare and submit plans to impose methane and VOC emission controls for existing sources. The presumptive standards established under the final rules are generally same for both new and existing sources and include 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, so-called green well completion requirements, and the establishment of a “super emitter” response program which would allow certified third parties to report large emission events to EPA, triggering additional investigation, reporting, and repair obligations, among other more stringent operational and maintenance requirements. Fines and penalties for violations of these rules could be substantial. Separately, the BLM has also finalized a rule to limit venting, flaring, and methane leaks for oil and gas operations on federal lands. These
recent final rules are currently subject to litigation, the outcome of which is uncertain. Further, the Trump Administration or Congress could seek to repeal, modify, or otherwise limit the enforcement of the rules, though any timeline for doing, if at all, is uncertain and cannot be predicted at this time. 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. Additionally, the Trump Administration may pursue a new rulemaking to further revise or clarify the extent of federal jurisdiction under the CWA, though the substance and timing of any such action 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. 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, were proposed in recent sessions of Congress. Congress continues to consider legislation to amend the SDWA to address hydraulic fracturing operations. In addition, in 2020, the Supreme Court held that the CWA requires a discharge permit if the addition of pollutants through groundwater is the “functional equivalent” of a direct discharge from the point source into navigable waters. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. 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. A number of municipalities in other states, including
Colorado, have enacted bans on hydraulic fracturing. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. However, the Colorado legislature subsequently enacted “SB 101” that gave significant local control over oil and natural gas 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. NEPA’s implementing regulations have been the subject of frequent revision under the recent Trump and Biden Administrations. CEQ most recently finalized a rule that would expand requirements to analyze the cumulative effects of the project on climate change and consider any disproportionate impact of the project on communities with environmental justice concerns as well enhance certain project obligations for implementing environmental mitigation measures. The extent to which the Trump Administration or Congress pursues reversals of recent NEPA rules or new NEPA rulemakings or legislation cannot be predicted at this time. Further, the Court of Appeals for the D.C. Circuit recently decided that CEQ does not have authority to issue binding NEPA regulations. The ultimate consequences of this judicial decision are not yet clear.
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 specified onshore and offshore 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 SEC and 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. The Trump Administration has announced its intention to seek reversal of GHG and climate-related regulations and initiatives and ordered a review of the GHG endangerment finding. However, the extent to which these regulations are reversed or repealed and the administration’s timeline for doing so, remains uncertain.
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. The IRA also imposed a first-ever federal fee on GHG emissions via a waste methane emissions charge, implementing regulations for which have been finalized by the EPA. In addition, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Whether or how the Trump Administration or Congress may seek to repeal, modify, or otherwise limit these programs and regulations (as well as other climate-related initiatives) cannot be predicted at this time, though the Trump Administration has indicated its intent for doing so. 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.
Human Capital Management
As of December 31, 2024, we had 33 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, inclusive environment for our workforce, with excellent training and career development opportunities to enable employees to thrive and achieve their career goals.
Corporate Information
The Company’s corporate website can be found at https://vitesse-vts.com/. The Company makes available free of charge at this website (under the “Investor Relations - SEC Filings” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q, and its Current Reports on Form 8-K. In addition to its reports filed or furnished with the SEC, the Company publicly discloses material information from time to time in its press releases and Investor presentations, all of which are accessible through the website under the heading “Investor Relations” and the subheading “News & Events.” The Company’s Code of Business Conduct and 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.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
You should carefully consider the following risks and other information in this Annual Report on Form 10-K. The following risks have generally been separated into five groups: risks relating to our common stock, risks relating to our business, risks relating to our indebtedness, risks relating to legal and regulatory matters and risks related to tax matters. If any of the following events actually occur, our business, financial condition and results of operations could be materially adversely affected, the trading price of our common stock could decline and you could lose all or part of your investment. Additional risks and uncertainties that we do not presently know about or currently believe are not material may also adversely affect our business, financial condition and results of operations.
Summary Risk Factors
We believe that the risks associated with our business, and consequently the risks associated with an investment in our equity or debt securities, fall within the following categories:
Risks Relating to Our Common Stock
■Vitesse is an emerging growth company and the information we provide stockholders may be different from information provided by other public companies, which may result in a less active trading market for our common stock and higher volatility in our stock price.
■Although we expect to continue to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock.
■Certain provisions in our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage takeovers.
■Stockholders percentage ownership in Vitesse may be diluted in the future.
■Our Amended and Restated Certificate of Incorporation designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could may limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Risks Relating to Our Business
■Oil and natural gas prices are volatile. Extended declines in oil and natural gas prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.
■Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.
■Due to previous declines in oil and natural gas prices, we have in the past taken writedowns of our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties in the future.
■Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our total reserves.
■The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
■Seasonal weather conditions, extreme climatic events, and shifts in meteorological conditions, which may be impacted by climate change, may adversely affect our and our operators’ ability to conduct drilling and completion activities and to sell oil and natural gas for periods of time or affect demand for oil and gas, in some of the areas where our properties are located.
■The successful development and operation of our non-operated assets relies extensively on third parties, which could have an adverse effect on our financial condition and results of operations.
■The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we anticipate. Therefore, these undeveloped reserves may not be ultimately developed or produced.
■Our business plan requires the expenditure of significant capital, which we may be unable to obtain on favorable terms or at all.
■Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.
■The majority of our producing properties are located in the Williston Basin, making us vulnerable to risks associated with operating in one major geographic area.
■The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely, could diminish our ability to conduct our operations and harm our ability to execute our business plan.
■Deficiencies of title to our interests could significantly affect our financial condition.
■Inflation could adversely impact our ability to control our costs, including the operating expenses and capital costs of our operators.
■Our derivatives activities could adversely affect our profitability, cash flow, results of operations and financial condition.
■Asset retirement costs are difficult to predict and may be substantial. Unplanned costs could divert resources from other projects.
■Increased attention to ESG matters, including climate change, may impact our business and access to capital.
Risks Relating to Our Indebtedness
■Any significant reduction in the borrowing base under our Revolving Credit Facility may negatively impact our liquidity and could adversely affect our business and financial results.
■Our Revolving Credit Facility and other agreements governing indebtedness may contain operating and financial restrictions that may restrict our business and financing activities.
■Our ability to pay dividends to our stockholders is restricted by requirements under our Revolving Credit Facility.
■Variable rate indebtedness could subject us to interest rate risk, which could cause our debt service obligations to increase significantly.
■We may be adversely affected by developments in the SOFR market, changes in the methods by which SOFR is determined or the use of alternative reference rates.
Risks Relating to Legal and Regulatory Matters
■Restrictions on our ability to acquire federal leases and more stringent regulations affecting our and our operators’ exploration and production activities on federal lands may adversely impact our business.
■Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of oil and natural gas exploration and development companies and may adversely affect our operations and cash flows.
■Our business involves the selling and shipping of oil by rail, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
■Our derivative activities expose us to potential regulatory risks.
■Failure to comply with federal, state and local environmental laws and regulations could result in substantial penalties and adversely affect our business.
■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.
Risks Relating to Tax Matters
■If the Distribution does not qualify as a transaction that is tax-free for U.S. federal income tax purposes, Jefferies and holders of Jefferies common stock who received shares of our common stock in connection with the Spin-Off could be subject to significant tax liability.
■Taxable gain or loss on the sale of our common stock could be more or less than expected.
■The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.
■Some stockholders might be deemed to have received a taxable distribution as a result of our repurchase of our own stock.
We describe these and other risks in much greater detail below.
Risks Relating to Our Common Stock
An active, liquid trading market for our common stock may not continue, which may limit your ability to sell your shares.
Although we have listed our common stock on the NYSE under the symbol “VTS,” an active trading market for our common stock may not be sustained. A public trading market having the desirable characteristics of depth, liquidity and orderliness depends upon the existence of willing buyers and sellers at any given time, such existence being dependent upon the individual decisions of buyers and sellers over which neither we nor any market maker has control. The failure of an active and liquid trading market to continue would likely have a material adverse effect on the value of our common stock. An inactive market may also impair our ability to raise capital to continue to fund operations by issuing shares and may impair our ability to acquire other companies or assets by using our shares as consideration.
We cannot predict the prices at which our common stock may trade. The market price of our common stock may fluctuate widely, depending on many factors, some of which may be beyond our control, including:
■actual or anticipated fluctuations in our business, financial condition and results of operations due to factors related to our business;
■competition in the oil and natural gas industry and our ability to compete successfully;
■success or failure of our business strategies;
■whether the Lucero Acquisition is accretive and may be dilutive to our earnings per share;
■the ultimate timing, outcome and results of integrating and executing on Lucero’s operations;
■our ability to retain and recruit qualified personnel;
■our quarterly or annual earnings, or those of other companies in our industry;
■our level of indebtedness, our ability to make payments on or service our indebtedness and our ability to obtain financing as needed;
■announcements by us or our competitors of significant acquisitions or dispositions;
■changes in accounting standards, policies, guidance, interpretations or principles;
■the failure of securities analysts to continue to cover our common stock;
■changes in earnings estimates by securities analysts or our ability to meet those estimates;
■the operating and stock price performance of other comparable companies;
■investor perception of our company and the oil and natural gas industry;
■overall market fluctuations, including the cyclical nature of the oil and natural gas market;
■results from any material litigation or government investigation;
■changes in laws and regulations (including tax laws and regulations) affecting our business; and
■general economic conditions, credit and capital market conditions and other external factors.
Furthermore, low trading volume of and lack of liquidity for our stock may occur if, among other reasons, an active trading market does not continue. This would amplify the effect of the above factors on our stock price volatility.
Vitesse is an emerging growth company and the information we provide stockholders may be different from information provided by other public companies, which may result in a less active trading market for our common stock and higher volatility in our stock price.
Vitesse is an “emerging growth company” as defined by the Jumpstart Our Business Startups Act of 2012. We will continue to be an emerging growth company until the earliest to occur of the following:
■the last day of the fiscal year in which our total annual gross revenues first meet or exceed $1.235 billion (as adjusted for inflation);
■the date on which we have, during the prior three-year period, issued more than $1.0 billion in non-convertible debt;
■the last day of the fiscal year in which we (1) have an aggregate worldwide market value of common stock held by non-affiliates of $700 million or more (measured at the end of each fiscal year) as of the last business day of our most recently completed second fiscal quarter and (2) have been a reporting company under the Exchange Act for at least one year (and filed at least one annual report under the Exchange Act); or
■the last day of the fiscal year following the fifth anniversary of the date of the first sale of our common stock pursuant to an effective registration statement under the Securities Act.
For as long as we are an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including, but not limited to:
■not being required to comply with the auditor attestation requirements in the assessment of our internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act of 2002;
■exemption from new or revised financial accounting standards applicable to public companies until such standards are also applicable to private companies;
■reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements and registration statements; and
■exemptions from the requirement of holding a nonbinding advisory vote on executive compensation and stockholder approval on golden parachute compensation not previously approved.
We may choose to take advantage of some or all of these reduced burdens. To the extent we take advantage of the reduced reporting obligations, the information we provide stockholders may be different from information provided by other public companies. In addition, it is possible that some investors will find our common stock less attractive as a result of these elections, which may result in a less active trading market for our common stock and higher volatility in our stock price.
In addition, we may take advantage of the extended transition period that allows an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. Our election to use the extended transition period may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the extended transition period and who will comply with new or revised financial accounting standards.
Although we expect to continue to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock.
The timing, declaration, amount of and payment of future dividends, if any, to stockholders will fall within the discretion of our Board of Directors. Our Board of Directors may change the timing and amount of any future dividend payments or eliminate the payment of future dividends to our stockholders at its discretion, without advance notice to our stockholders. The decisions of our Board of Directors regarding the payment of future dividends, if any, will depend upon many factors, including our financial condition, earnings, capital requirements of our business, covenants associated with certain of our debt service obligations, legal requirements or limitations, industry practice, and other factors deemed relevant by our Board of Directors. Our ability to declare and pay dividends to our stockholders is subject to certain laws and regulations, including minimum capital requirements and, as a Delaware corporation, we are subject to certain restrictions on dividends under the DGCL. Under the DGCL, our Board of Directors may not authorize payment of a dividend unless it is either paid out of our surplus, as calculated in accordance with the DGCL, or if we do not have a surplus, paid out of our net profits for the fiscal year in which the dividend is declared or the preceding fiscal year. For more information, see Part II. Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, - Dividend Policy. For a description of the covenants limiting our ability to pay dividends, see -Risks Relating to Our Indebtedness -Our ability to pay dividends to our stockholders is restricted by requirements under our Revolving Credit Facility. There can be no assurance that we will pay a dividend in the future or continue to pay any dividend.
Certain provisions in our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage takeovers.
Several provisions of our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage, delay or prevent a merger or acquisition that is opposed by our Board. These include provisions that:
■prevent our stockholders from calling a special meeting or acting by written consent;
■require advance notice of any stockholder nomination for the election of directors or any stockholder proposal;
■provide for a plurality voting standard in contested director elections;
■authorize only our Board of Directors to fill director vacancies and newly created directorships;
■authorize our Board of Directors to adopt, amend or repeal our Amended and Restated Bylaws without stockholder approval; and
■authorize our Board of Directors to issue one or more series of “blank check” preferred stock.
In addition, Section 203 of the DGCL prohibits a Delaware corporation from engaging in a business combination with any interested stockholder for a period of three years following the date the person became an interested stockholder, subject to certain exceptions. In general, Section 203 of the DGCL defines an “interested stockholder” as an entity or person who, together with the entity’s or person’s affiliates, beneficially owns, or is an affiliate of the corporation and within three years prior to the time of determination of interested stockholder status did own, 15% or more of the outstanding voting stock of the corporation. A Delaware corporation may “opt out” of these provisions with an express provision in its certificate of incorporation. We have not opted out of Section 203 of the DGCL in our Amended and Restated Certificate of Incorporation.
These and other provisions of our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware law may discourage, delay or prevent certain types of transactions involving an actual or a threatened acquisition or change in control of us including unsolicited takeover attempts, even though the transaction may offer our stockholders the opportunity to sell their shares of our common stock at a price above the prevailing market price.
Stockholders percentage ownership in Vitesse may be diluted in the future.
Stockholders percentage ownership in Vitesse may be diluted in the future because of the settlement or exercise of equity-based awards that have been granted and that we expect will continue to be granted to our directors, officers and other employees under our equity incentive plan. In addition, we may issue equity as all or part of the consideration paid for acquisitions and strategic investments that we may make in the future, as we did with the Lucero Acquisition, or as necessary to finance our ongoing operations.
In addition, our Amended and Restated Certificate of Incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock with respect to dividends and distributions, as our Board of Directors may generally determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example, we could grant the holders of preferred stock the right to elect some number of the members of our Board of Directors in all events or upon the happening of specified events, or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences that we could assign to holders of preferred stock could affect the residual value of our common stock.
Our Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Our Amended and Restated Certificate of Incorporation provides that, in all cases to the fullest extent permitted by law, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for:
■any derivative action or proceeding brought on our behalf;
■any action or proceeding asserting a claim of breach of a fiduciary duty owed by any current or former director, officer or other employee or stockholder of our company to us or our stockholders;
■any action or proceeding asserting a claim arising pursuant to, or seeking to enforce any right, obligation or remedy under, any provision of Delaware law or our Amended and Restated Certificate of Incorporation or our Amended and Restated Bylaws; or
■any action or proceeding asserting a claim governed by the internal affairs doctrine or any other action asserting an “internal corporate claim” as that term is defined in Section 115 of the DGCL.
However, if the Court of Chancery of Delaware does not have jurisdiction, the action or proceeding may be brought in any other state or U.S. federal court located within the State of Delaware. Further, our Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, to the fullest extent permitted by law, the U.S. federal district courts are the sole and exclusive forum for any complaint asserting a cause of action arising under U.S. federal securities laws.
Any person holding, purchasing or otherwise acquiring shares of our stock will be deemed to have notice of and have consented to this provision and deemed to have waived any argument relating to the inconvenience of the forum in connection with any action or proceeding described in this provision. This provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits. Alternatively, if a court of competent jurisdiction were to find this provision of our Amended and Restated Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.
Risks Relating to Our Business
Oil and natural gas prices are volatile. Extended declines in oil and natural gas prices have adversely affected, and could in the future adversely affect, our business, financial position, results of operations and cash flow.
The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Oil and natural gas prices have fluctuated significantly, including periods of rapid and material decline, in recent years. The prices we receive for our oil and natural gas production heavily influence our production, revenue, cash flows, profitability, reserve bookings and access to capital. Although we seek to mitigate volatility and potential declines in oil and natural gas prices through derivative arrangements that hedge a portion of our expected production, this merely mitigates (and does not eliminate) these risks, and such activities come with their own risks.
The prices we receive for our oil and natural gas production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
■changes in global supply and demand for oil and natural gas;
■changes in NYMEX WTI oil prices and NYMEX Henry Hub natural gas prices;
■the volatility and uncertainty of regional pricing differentials;
■future repurchases (or additional possible releases) of oil from the strategic petroleum reserve by the U.S. Department of Energy;
■the actions of OPEC and other major oil producing countries;
■worldwide and regional economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks including war, terrorism, political unrest, or health epidemics;
■the price and quantity of imports of foreign oil and natural gas;
■political and economic conditions, including embargoes, in oil-producing countries or affecting other oil-producing activity;
■the outbreak or escalation of military hostilities, including between Russia and Ukraine and in the Middle East, and the potential destabilizing effect such conflicts may pose for the global oil and natural gas markets;
■inflation and changes in U.S. trade policy, including the imposition of tariffs and resulting consequences;
■the level of global oil and natural gas exploration, production activity and inventories;
■changes in U.S. energy policy;
■weather conditions;
■outbreak of disease;
■technological advances affecting energy consumption;
■domestic and foreign governmental taxes, tariffs or regulations;
■proximity and capacity of processing, gathering, and storage facilities, oil and natural gas pipelines and other transportation facilities;
■the price and availability of competitors’ supplies of oil and natural gas in captive market areas; and
■the price and availability of alternative fuels.
These factors and the volatility of the energy markets make it extremely difficult to predict oil and natural gas prices. A substantial or extended decline in oil or natural gas prices, such as the significant and rapid decline that occurred in 2020, has resulted in and could result in future impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. To the extent oil and natural gas prices received from production are insufficient to fund planned capital expenditures, we may be required to reduce spending or borrow or issue additional equity to cover any such shortfall. Lower oil and natural gas prices may limit our ability to comply with the covenants under our Revolving Credit Facility or limit our ability to access borrowing availability thereunder, which is dependent on many factors including the value of our proved reserves.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.
Our and our operators’ drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled by our operators as a result of other factors, including:
■declines in oil or natural gas prices;
■infrastructure limitations, such as the natural gas gathering and processing constraints experienced in the Williston Basin in 2019;
■the high cost, shortages or delays of equipment, materials and services;
■unexpected operational events, pipeline ruptures or spills, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents;
■title problems;
■pipe or cement failures and casing collapses;
■lost or damaged oilfield development and services tools;
■laws, regulations, and other initiatives related to environmental matters, including those addressing alternative energy sources, the phase-out of fossil fuel vehicles and the risks of global climate change;
■compliance with environmental and other governmental requirements;
■increases in severance taxes;
■regulations, restrictions, moratoria and bans on hydraulic fracturing;
■unusual or unexpected geological formations, and pressure or irregularities in formations;
■loss of drilling fluid circulations;
■environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;
■fires, blowouts, craterings and explosions;
■uncontrollable flows of oil, natural gas or well fluids; and
■pipeline capacity curtailments.
In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
Due to previous declines in oil and natural gas prices, we have in the past taken writedowns of our oil and natural gas properties. We may be required to record further writedowns of our oil and natural gas properties in the future.
We review our oil and natural gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our oil and natural gas properties and compare such cash flows to the carrying amount of the proved oil and natural gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust our proved oil and natural gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future oil and natural gas prices adjusted for basis differentials, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks.
A continued period of low prices may force us to incur material write-downs of our oil and natural gas properties, which could have a material effect on the value of our properties and cause the value of our securities to decline. Additionally, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period. We have in the past and could in the future incur impairments of oil and natural gas properties which may be material.
We have incurred net losses in the past, in part due to fluctuations in oil and gas prices, and we may incur such losses again in the future.
To the extent our production is not hedged, we are exposed to declines in oil and natural gas prices, and our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. In prior periods, such declines have led to net losses. Unrealized hedging losses on commodity derivatives attributable to significant increases in oil prices may also cause a net loss for a given period.
In addition, fluctuations in oil and natural gas prices have impacted unit-based compensation expense for our Predecessor for prior periods and may impact our stock-based compensation expense. For example, in prior periods we have experienced increases to our unit-based compensation expense primarily due to increased oil and natural gas prices causing the estimated fair value of the liabilities associated with such unit-based compensation to increase, which contributed to net losses recorded during such periods. As a result of the foregoing and other factors, we may continue to incur net losses in the future.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our total reserves.
Determining the amount of oil and natural gas recoverable from various formations involves significant complexity and uncertainty. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating, and development costs. Some of our reserve estimates are made without the benefit of a lengthy production history and are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate.
We routinely make estimates of oil and natural gas reserves in connection with managing our business, including in some cases estimates prepared by our internal reserve engineers and professionals that are not reviewed or audited by an independent reserve engineering firm. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, development schedules, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, reserve engineers and other advisors to make accurate assumptions. Any significant variance from these assumptions by actual figures could greatly affect our estimates of total reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based result in the actual quantities of oil and natural gas our operators ultimately recover being different from our reserve
estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K, subsequent reports we file with the SEC or other company materials.
Our future success depends on our ability to replace reserves.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. We have added significant net wells and production from wellbore-only acquisitions, where we don’t hold the underlying leasehold interest that would entitle us to participate in future wells. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.
We may acquire significant amounts of unproved property to further our development efforts. Development and drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon existing properties. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our capital in our properties and reserves.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
We estimate discounted future net cash flows from our proved reserves using Standardized Measure and PV-10, each of which uses specified pricing and cost assumptions. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as the volume, pricing and duration of our hedging contracts; actual prices we receive for oil and natural gas; our actual operating costs in producing oil and natural gas; the amount and timing of our capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. For example, our estimated proved reserves as of December 31, 2024 were calculated under SEC rules by applying year-end SEC prices based on the twelve-month unweighted arithmetic average of the first day of the month oil and natural gas prices for such year end of $76.32 per Bbl and $2.13 per MMBtu, which for certain periods during this time were substantially different from the available market prices. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Our business depends on transportation and processing facilities and other assets that are owned by third parties.
The marketability of our oil and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, oil trucking fleets and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding the DAPL), could result in a substantial increase in costs, declines in realized oil and natural gas prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. In recent periods, we experienced significant delays and production curtailments, and declines in realized natural gas prices, that we believe were due in part to natural gas gathering and processing constraints in the Williston Basin. The negative effects arising from these and similar circumstances may last for an extended period of time. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third-party oil trucking to transport a significant portion of our production to third-party transportation pipelines, rail loading facilities and other market access points. In addition, the third parties on whom operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting business on our oil and natural gas properties. Further, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development and increased regulation of pipelines by PHMSA. In recent years, PHMSA has increased regulation of onshore gas transmission systems, hazardous liquids pipelines, and gas gathering systems. For example, in November 2021, PHMSA issued a final rule that extended pipeline safety requirements to onshore gas gathering pipelines, and therefore could result in less capacity to transport our products by pipeline. Additional regulation could impact rates charged by our operators and impact their ability to enter into gathering and transportation agreements, which costs could be passed through to us.
The DAPL, a major pipeline transporting oil from the Williston Basin, is subject to ongoing litigation that could threaten its continued operation. In July 2020, a federal district court vacated the DAPL’s easement to cross the Missouri River at Lake Oahe and ordered the pipeline be shut down pending the completion of an EIS to determine whether the DAPL poses a threat to the Missouri River and drinking water supply of the Standing Rock Sioux Reservation. The shut-down order was later reversed on appeal and the DAPL currently remains in operation while the Corps completes the EIS, a draft of which was completed and published for public comment in 2023, The Corps has delayed the release of the final EIS, which is now expected in 2025. Following completion of the EIS, the Corps will issue a final decision whether to grant the DAPL an easement to cross the Missouri River at Lake Oahe or to require the abandonment, removal, or reroute of that section, effectively shutting down the pipeline. Moreover, the EIS or the Corps’ decision with respect to an easement may subsequently be challenged in court. In the interim, the Standing Rock Sioux Tribe has filed suit challenging the continued operation of the DAPL without the easement. As a result, a shut-down remains possible, and there is no guarantee that the DAPL will be permitted to continue operations following the completion of the EIS. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect our business, results of operations and financial condition.
Seasonal weather conditions, extreme climatic events, and shifts in meteorological conditions, which may be impacted by climate change, may adversely affect our and our operators’ ability to conduct drilling and completion activities and to sell oil and natural gas for periods of time or affect demand for oil and gas, in some of the areas where our properties are located.
Seasonal weather conditions can limit drilling and completion activities, selling oil and natural gas, and other operations in some of our operating areas. In the Williston Basin, drilling and other oil and natural gas activities on our properties can be adversely affected during the winter months by severe winter weather and drilling on our properties is generally performed during the summer and fall months. These seasonal constraints can pose challenges for meeting well drilling objectives and increase competition for equipment, supplies and personnel during the summer and fall months, which could lead to shortages and increase costs or delay operations. Additionally, many municipalities impose weight restrictions on the paved roads that lead to jobsites due to the muddy conditions caused by spring thaws. This could limit access to jobsites and our and our operators’ ability to service wells in these areas.
The frequency and severity of severe winter weather conditions and shifts in regional temperature and precipitation patterns, which could result in increases in severity or frequency of droughts, storms, flooding, or wildfires, could cause physical damage to our and our operators’ assets, disrupt supply chains (for example, through water use curtailments imposed during a prolonged drought), or otherwise adversely impact the production activities on our interests. Such climatic events may also be impacted or exacerbated by the effects of climate change. Our ability and the ability of our operators to mitigate the adverse impacts of these events depends in part on the effectiveness of resiliency planning in design and disaster preparedness and response, which may not have considered every eventuality. Additionally, global climate trends and changes in meteorological conditions may result in changes to the amount, timing, or location of demand for energy or its production. To the extent these events occur, our production from our assets and our resulting financial condition and performance could be adversely affected.
The successful development and operation of our non-operated assets relies extensively on third parties, which could have an adverse effect on our financial condition and results of operations.
Prior to the Lucero Acquisition, we have only participated in wells operated by third parties and following the Lucero Acquisition, our business continues to be a predominantly non-operated business model. The success of our business operations depends on the timing of drilling activities and success of our third-party operators. If our operators are not successful in the development, exploitation, production and exploration activities relating to our leasehold interests, or are unable or unwilling to perform, our financial condition and results of operations would be adversely affected.
These risks are heightened in a low oil and natural gas price environment, which may present significant challenges to our operators. The challenges and risks faced by our operators may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments and, if necessary, access additional capital. Oil and natural gas prices or other conditions have in the past and may in the future cause oil and natural gas operators to file for bankruptcy. The insolvency of an operator of any of our properties, the failure of an operator of any of our properties to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue and result in liabilities to Governmental Entities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and natural gas leases jointly owned with the operator or another insolvent owner.
Our operators will make decisions in connection with their operations on our non-operated assets (subject to their contractual and legal obligations to other owners of working interests), which may not be in our best interests. We may have no ability to exercise influence over the operational decisions of our operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on our operators could prevent us from realizing our target returns for those locations. The success and timing of development activities by our operators will depend on a number of factors that will largely be outside of our control, including oil and natural gas prices
and other factors generally affecting the oil and natural gas industry’s operating environment; the timing and amount of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of technology; and the rate of production of reserves, if any.
The inability of one or more of our operators to meet their financial obligations to us may adversely affect our financial results.
Our exposures to credit risk are, in part, through receivables resulting from the sale of our oil and natural gas production, which operators market on our behalf to energy marketing companies, refineries and their affiliates. We are subject to credit risk due to the relative concentration of our oil and natural gas receivables with a limited number of operators. This concentration may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. A low oil and natural gas price environment may strain our operators, which could heighten this risk. The inability or failure of our operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We could experience periods of higher costs as activity levels fluctuate or if oil and natural gas prices rise or as a result of macro-economic factors. These increases could reduce our profitability, cash flow, and ability to complete development activities as planned.
An increase in oil and natural gas prices or other factors could result in increased development activity and investment in our areas of operations, which may increase competition for and cost of equipment, labor and supplies. Global, industry-wide supply chain disruptions have resulted in shortages in labor, materials and services from time to time. Such shortages have resulted in inflationary cost increases for labor, materials and services and could cause future costs to increase as well as scarcity of certain products and raw materials. To the extent inflation is elevated, our operators may experience further cost increases for their operations, including oilfield services, labor costs, and equipment if drilling activity in our operators’ areas of operations increases. In addition, there is currently significant uncertainty about the future relationship between the United States and various other countries, with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Tariffs, if enacted, and any further legislation or actions taken by the U.S. federal government that restrict trade, such as trade barriers, and other protectionist or retaliatory measures taken could increase the cost of operations. Shortages of, or increasing costs for, experienced drilling crews and equipment, labor or supplies could restrict our operators’ ability to conduct desired or expected operations. In addition, capital and operating costs in the oil and natural gas industry have generally risen during periods of increasing oil and natural gas prices as producers seek to increase production in order to capitalize on higher oil and natural gas prices. In situations where cost inflation exceeds oil and natural gas price inflation, our profitability and cash flow, and our operators’ ability to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in drilling or significant increase in drilling costs could reduce our revenues and profitability.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we anticipate. Therefore, these undeveloped reserves may not be ultimately developed or produced.
Approximately 32% of our estimated net proved reserves volumes were classified as proved undeveloped as of December 31, 2024. Development of undeveloped reserves may take longer and require higher levels of capital expenditures than we anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
Our acquisition strategy will subject us to certain risks associated with the inherent uncertainty in evaluating properties for which we have limited information.
We intend to continue to expand our operations in part through acquisitions such as the Lucero Acquisition. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not economically feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential recoverable reserves. On-site inspections are often not performed on properties being acquired, and environmental matters, such as subsurface contamination, are not necessarily observable even when an on-site inspection is undertaken. Any acquisition involves other potential risks, including, among other things:
■the validity of our assumptions about reserves, future production, revenues and costs;
■a decrease in our liquidity by using a significant portion of our cash from operations or borrowing capacity to finance acquisitions;
■a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
■the ultimate value of any contingent consideration agreed to be paid in an acquisition;
■dilution to stockholders if we use equity as consideration for, or to finance, acquisitions;
■the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
■geological risk, which refers to the risk that hydrocarbons may not be present or, if present, may not be recoverable economically;
■an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and
■an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes, or other litigation encountered in connection with an acquisition.
We may also acquire multiple assets in a single transaction. Portfolio acquisitions via joint-venture or other structures are more complex and expensive than single project acquisitions, and the risk that a multiple-project acquisition will not close may be greater than in a single-project acquisition. An acquisition of a portfolio of projects may result in our ownership of projects in geographically dispersed markets which place additional demands on our ability to manage such operations. A seller may require that a group of projects be purchased as a package, even though one or more of the projects in the portfolio does not meet our strategic objectives. In such cases, we may attempt to make a joint bid with another buyer, and such other buyer may default on its obligations.
Further, we may acquire properties subject to known or unknown liabilities and with limited or no recourse to the former owners or operators. As a result, if liability were asserted against us based upon such properties, we may have to pay substantial sums to dispute or remedy the matter, which could adversely affect our profitability. Unknown liabilities with respect to assets acquired could include, for example: liabilities for clean-up of undiscovered or undisclosed environmental contamination; claims by developers, site owners, vendors or other persons relating to the asset or project site; liabilities incurred in the ordinary course of business; and claims for indemnification by general partners, directors, officers and others indemnified by the former owners of the asset or project sites.
Our business plan requires the expenditure of significant capital, which we may be unable to obtain on favorable terms or at all.
Our acquisition and development activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities and equity issuances. Cash reserves, cash flow from operations and borrowings under our Revolving Credit Facility may not be sufficient to fund our continuing operations and business plan and goals. We may require additional capital and we may be unable to obtain such capital if and when required. If our access to capital were limited due to numerous factors, which could include a decrease in operating cash flow due to lower oil and natural gas prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to develop our properties, replace our reserves and pursue our business plan and goals. We may not be able to incur additional debt under our Revolving Credit Facility, issue debt or equity, engage in asset sales or access other methods of financing on acceptable terms or at all. If the amount of capital we are able to raise from financing activities, together with our cash flow from operations, is not sufficient to satisfy our capital requirements, we may not be able to implement our business plan and may be required to scale back our operations, sell assets at unattractive prices or obtain financing on unattractive terms, any of which could adversely affect our business, results of operations and financial condition.
We may be unable to successfully integrate any assets we may acquire in the future into our business or achieve the anticipated benefits of such acquisitions.
We may not be able to integrate the acquired assets into our existing business in an efficient and effective manner or achieve the anticipated benefits of acquisitions such as the Lucero Acquisition. We may not be able to accomplish this integration process successfully. The successful acquisition of properties requires an assessment of several factors, including:
■recoverable reserves;
■future oil and natural gas prices and their appropriate differentials;
■availability and cost of transportation of production to markets;
■availability and cost of drilling equipment and of skilled personnel;
■development and operating costs including access to water and potential environmental and other liabilities; and
■regulatory, permitting and similar matters.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform reviews of the subject properties that we believe to be generally consistent with industry practices. The reviews are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm. Data used in such reviews are typically furnished by the seller or obtained from publicly available sources. Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the acquired properties may differ materially after such data is reviewed by an independent petroleum engineering firm or further by us. On-site inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an on-site inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. We are often not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis, and, as is the case with certain liabilities
associated with the assets acquired in our recent acquisitions, we are entitled to indemnification for only certain operational liabilities. The integration process may be subject to delays or changed circumstances, and we can give no assurance that our acquired assets will perform in accordance with our expectations or that our expectations with respect to integration or the benefits of such acquisitions will materialize.
The majority of our producing properties are located in the Williston Basin, making us vulnerable to risks associated with operating in one major geographic area.
Our oil and natural gas properties are focused on the Williston Basin, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our oil and natural gas properties are not as diversified geographically as some of our competitors, our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.
The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely, could diminish our ability to conduct our operations and harm our ability to execute our business plan.
Our success depends heavily upon the continued contributions of those members of our management team whose knowledge, relationships with industry participants, leadership and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on our management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry and will use our management team’s relationships with industry participants to enter into strategic relationships. The members of our management team may terminate their employment with our company at any time. If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.
Deficiencies of title to our leased interests could significantly affect our financial condition.
We typically do not incur the expense of a title examination prior to acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights. If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights have been purchased in error from a person who is not the owner of the interest desired, our interest would substantially decline in value or be eliminated. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights may be lost. It is generally our practice not to incur the expense of retaining lawyers to examine the title to the interest to be acquired. Rather, we typically rely upon the judgment of our own oil and natural gas landmen who conduct due diligence and perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific interest.
Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the company acting as the operator of the well to obtain a title examination of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Any one or more of the foregoing could require us to reverse revenues previously recognized and potentially negatively affect our cash flows and results of operations. Our failure to obtain perfect title to our leaseholds may adversely affect our production and reserves and our ability in the future to increase production and reserves.
We conduct business in a highly competitive industry.
The oil and natural gas industry is highly competitive. The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment by our operators that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals.
Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships.
Our competitors include entities with greater technical, physical and financial resources. In addition, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us. If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.
The ongoing conflicts in Ukraine and the Middle East have caused unstable market and economic conditions and may have additional global consequences. Our business, financial condition, and results of operations may be materially adversely affected by the negative global and economic impact resulting from such conflicts or any other geopolitical tensions.
U.S. and global markets are experiencing volatility and disruption following the escalation of geopolitical tensions, the ongoing military conflict between Russia and Ukraine and hostilities in the Middle East. Although the length and impact of these ongoing conflicts are highly unpredictable, the conflicts in Ukraine and in the Middle East have led to market disruptions, including significant volatility in oil and natural gas prices, credit and capital markets, as well as supply chain disruptions. These disruptions have caused, and could continue to cause, significant volatility in energy prices, which could have a material effect on our business.
Prolonged unfavorable economic conditions or uncertainty as a result of these conflicts may adversely affect our business, financial condition, and results of operations. Any of the foregoing may also magnify the impact of other risks described in this Annual Report on Form 10-K.
Our derivatives activities could adversely affect our profitability, cash flow, results of operations and financial condition.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the price of oil and natural gas, we enter into derivative instrument contracts for a portion of our expected production, which may include swaps, collars, puts and other structures. See Part II. Item 7A. Quantitative and Qualitative Disclosure About Market Risk - Commodity Price Risk. By using derivative instrument contracts to reduce our exposure to adverse fluctuations in the price of oil and natural gas, we could limit the benefit we would receive from increases in the prices for oil and natural gas, which could have an adverse effect on our profitability, cash flow, results of operations and financial condition. Likewise, to the extent our production is not hedged, we are exposed to declines in oil and natural gas prices, and our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our balance sheet as assets or liabilities and in our statements of operations as gain (loss) on commodity derivatives, net. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. In addition, while intended to mitigate the effects of volatile oil and natural gas prices, our derivatives transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater oil and natural gas price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which a counterparty to our derivative contracts is unable to satisfy its obligations under the contracts; our production is less than expected; or there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make it unable to perform under the terms of the contracts, and we may not be able to realize the benefit of the contracts. We may be unable to predict changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict changes, our ability to negate the risk may be limited depending upon market conditions.
Asset retirement costs are difficult to predict and may be substantial. Unplanned costs could divert resources from other projects.
We are responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves where we have a working interest. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “asset retirement.” We accrue a liability for asset retirement costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. It may be difficult for us to predict such asset retirement costs. If asset retirement is required before economic depletion of our properties or if our estimates of the costs of asset retirement exceed the value of the reserves remaining at any particular time to cover such asset retirement costs, we may have to draw on funds from other sources to satisfy such costs, which may be substantial. The use of other funds to satisfy such asset retirement costs could impair our ability to dedicate our capital to other areas of our business.
We depend on computer and telecommunications systems, and failures in our systems or cybersecurity threats, attacks or other disruptions could significantly disrupt our business operations.
We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed or may develop proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. It is possible that we, or these third parties, could incur interruptions from cybersecurity attacks, computer viruses or malware, or that third-party service providers could cause a breach of our data. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties for our computing and communications infrastructure or any other interruptions to, or breaches of, our information systems could lead to data corruption, communication interruption, loss of sensitive or confidential information or otherwise significantly disrupt our business operations. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. Furthermore, various third-party resources that we rely on, directly or indirectly, in the operation of our business (such as pipelines and other infrastructure) could suffer interruptions or breaches from cyber-attacks or similar events that are entirely outside our control, and any such events could significantly disrupt our business operations or have a material adverse effect on our results of operations. To our knowledge we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer material losses in the future.
In addition, our operators face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of their facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to operations and could have a material adverse effect on our financial position, results of operations or cash flows. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject operations on our oil and natural gas properties to increased risks. Any future terrorist attack at our operators’ facilities, or those of their purchasers or vendors, could have a material adverse effect on our financial condition and operations.
Decarbonization measures and related governmental initiatives, technological advances, 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.
Decarbonization measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.
Our business could also be impacted by governmental initiatives to encourage the conservation of energy or the use of alternative energy sources. In addition, the IRA includes a variety of clean-energy tax credits and establishes a program designed to reduce methane emissions from oil and gas operations. These initiatives or similar state or federal initiatives to reduce energy consumption or encourage a shift away from fossil fuels could reduce demand for hydrocarbons and have a material adverse effect on our earnings, cash flows and financial condition. Whether, the extent to which, or how the Trump Administration or Congress will continue or reverse course on governmental initiatives like these cannot be predicted at this time, though the Trump Administration has indicated it will seek to remove support for such. Regardless of federal support, states and municipalities may continue to encourage and implement decarbonization measures.
Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Some organizations that provide information to investors on corporate governance and related matters have developed ratings for investment and voting decisions. While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and natural gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates may continue to rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Increased attention to ESG matters, including climate change, may impact our business and access to capital.
Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, increasing mandatory ESG disclosures, and increasing consumer demand for alternatives to oil and natural gas may result in increased costs, reduced demand for our products, reduced profits, increased administrative, legislative, and judicial scrutiny, reputational damage, and negative impacts on our access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that the Company could be subject to additional governmental investigations, private litigation or activist campaigns as stockholders may attempt to effect changes to the Company’s business or governance practices.
While we may elect to pursue certain ESG strategies in the future, any such goals are aspirational and may not have the intended impact on our business. We may also receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles. Moreover, failure or a perception (whether or not valid) of failure to pursue or implement ESG strategies or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us, and negatively impact our operations. Additionally, to the extent ESG-related matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. ESG-related matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.
Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies or related infrastructure projects based on climate or other ESG-related concerns, which could affect our access to capital for potential growth projects. In March 2024, the SEC finalized rules mandating extensive disclosure of climate risks for certain registrants. In March 2024, the SEC finalized rules mandating extensive disclosure of climate risks for certain registrants. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges. Moreover, on February 11, 2025, SEC Acting Chairman Mark T. Uyeda requested that the U.S. Court of Appeals for the Eighth Circuit not schedule argument in the case while the SEC reconsiders the finalized rules. While the SEC, under the new presidential administration, may seek to repeal or otherwise modify the rules, we cannot predict whether such action will occur or its timings. Enhanced climate disclosure requirements could result in additional legal and accounting costs and accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. States may pass laws imposing more expansive disclosure requirements for climate-related risks. New laws, regulations, or enforcement initiatives related to the disclosure of climate-related risks could lead to reputational or other harm with customers, regulators, lenders, investors or other stakeholders and could also increase litigation risks. Any material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and results of operations.
Separately, existing public and governmental authorities, as well as other parties, have also heightened scrutiny around climate-change related disclosures in public filings. For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including greenwashing (i.e., misleading information or false claims overstating potential benefits). Certain regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals or standards were misleading, false or otherwise deceptive. Certain employment practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Company’s environmental or social commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Company’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties.
Risks Relating to Our Indebtedness
Any significant reduction in the borrowing base under our Revolving Credit Facility may negatively impact our liquidity and could adversely affect our business and financial results.
Availability under our Revolving Credit Facility is subject to a borrowing base, with scheduled semiannual and other elective borrowing base redeterminations based upon, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the Revolving Credit Facility. As a result of these borrowing base redeterminations, the lenders under the Revolving Credit Facility are able to unilaterally determine and adjust the borrowing base and the borrowings permitted to be outstanding under our Revolving Credit Facility. Reductions in estimates of our producing oil and natural gas reserves could result in a reduction of our borrowing base thereunder. The same could also arise from other factors, including but not limited to lower commodity prices or production; operating difficulties; changes in oil and natural gas reserve engineering; increased operating or capital costs; lending requirements or regulations; or other factors affecting our lenders’ ability or willingness to lend (including factors that may be unrelated to our company). Any significant reduction in our borrowing base could result in a default under current or future debt instruments, negatively impact our liquidity and our ability to fund our operations and, as a result, could have a material adverse effect on our financial position, results of operations and cash flow. Further, if the outstanding borrowings under our Revolving Credit Facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. If we do not have sufficient funds and we are otherwise unable to arrange new financing, we may have to sell significant assets or take other actions. Any such sale or other actions could have a material adverse effect on our business and financial results.
Our Revolving Credit Facility and other agreements governing indebtedness may contain operating and financial restrictions that may restrict our business and financing activities.
Our Revolving Credit Facility contains a number of restrictive covenants that impose operating and financial restrictions on us, including restrictions on our ability to, among other things: declare or pay any dividend or make any other distributions on, purchase or redeem our equity interests; make loans or certain investments; make certain acquisitions; incur or guarantee additional indebtedness or issue certain types of equity securities; incur liens; transfer or sell assets; create subsidiaries; consolidate, merge or transfer all or substantially all of our assets; and engage in transactions with our affiliates. In addition, the Revolving Credit Facility requires us to maintain compliance with certain financial covenants and other covenants. As a result of these covenants, we could be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with these covenants and restrictions may be affected by events beyond our control, including the deterioration of market or other economic conditions. A failure to comply with the covenants, ratios or tests in our Revolving Credit Facility or any other indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our Revolving Credit Facility occurs and remains uncured, the lenders thereunder would not be required to lend any additional amounts to us and could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be immediately due and payable. If the payment of debt were accelerated, cash flows from our operations may be insufficient to repay such debt in full and our stockholders could experience a partial or total loss of their investment. Our Revolving Credit Facility contains customary events of default, including the occurrence of a change in control.
An event of default or an acceleration under our Revolving Credit Facility could result in an event of default and an acceleration under other existing or future indebtedness. Conversely, an event of default or an acceleration under any other existing or future indebtedness could result in an event of default and an acceleration under our Revolving Credit Facility. In addition our obligations under the Revolving Credit Facility are collateralized by perfected liens and security interests on substantially all of our assets and if we default thereunder, the lenders could seek to foreclose on our assets.
We may not be able to generate enough cash flow to meet our debt obligations or to pay dividends to our stockholders.
Our earnings and cash flow may vary significantly due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, or to permit us to pay dividends to our stockholders. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt or dividends. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt; selling assets; reducing or delaying capital investments; or seeking to raise additional capital. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations or pay
dividends. Our inability to generate sufficient cash flow to satisfy our debt obligations or pay dividends, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
Our ability to pay dividends to our stockholders is restricted by requirements under our Revolving Credit Facility.
Holders of our common stock are only entitled to receive such cash dividends as our Board, in its sole discretion, may declare out of funds legally available for such payments. We paid cash dividends of $63.6 million, $58.0 million and $36.0 million to our equity holders during the years ended December 31, 2024, 2023 and 2022, respectively. We cannot assure you that we will pay dividends in the future. Any future determination relating to the payment of dividends will be dependent on a variety of factors, including any limitations imposed by covenants in the Revolving Credit Facility and any debt agreements that we may enter into in the future. Under our Revolving Credit Facility, we are permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) our total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500 million, (2) our then-effective borrowing base, and (3) the then-effective aggregate amount of our lenders’ commitments and (b) as of the date of such distribution, the EBITDAX Ratio does not exceed 1.50 to 1.00. If our EBITDAX Ratio does not exceed 2.25 to 1.00, and if our total outstanding credit usage does not exceed 80% of the Commitments, we may also make distributions if our distributable free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and we have delivered a certificate to our lenders attesting to the foregoing. The summaries above do not purport to be complete and you are encouraged to read the Revolving Credit Facility, which is filed as an exhibit to this Annual Report on Form 10-K, for greater detail with respect to these provisions. As a consequence of these various limitations and restrictions, we may not be able to make, or may have to reduce or eliminate at any time, the payment of dividends on our common stock. If as a result, we are unable to pay dividends, investors may be forced to rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Any change in the level of our dividends or the suspension of the payment thereof could have a material adverse effect on the market price of our common stock. For additional information, please see -Risks Relating to Our Common Stock-. Although we expect to continue to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock.
Variable rate indebtedness could subject us to interest rate risk, which could cause our debt service obligations to increase significantly.
Our Revolving Credit Facility uses SOFR as a reference rate for borrowings. Borrowings under our Revolving Credit Facility may bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash flows may decrease.
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.
Oil and gas exploration and production activities on federal lands are subject to federal requirements, orders, and lease conditions that regulate, among other matters, drilling and related operations on lands covered by federal leases and the calculation and disbursement of royalty payments to the federal government. For example, these regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, including corporate successors of former operators. These requirements may result in significant costs associated with the removal of tangible equipment and other restorative actions. Additionally, under certain circumstances, operations on federal leases may be suspended or terminated as a result of federal executive action, third-party litigation or BLM regulations.
Oil and gas sector activity on federal lands have become subject to increasing regulatory scrutiny. We and our operators are affected by the adoption of new or more stringent laws, regulations and policy directives that, for economic, environmental protection or other policy reasons, could increase the operating costs of, or otherwise curtail exploration and development drilling for oil and natural gas. For example, the IRA legislated changes to the fiscal terms of federal oil and gas leases, increasing fees, rents, royalties, and bonding requirements, all of which have been implemented pursuant to a finalized BLM rule. The BLM has also finalized a rule that would require operators to limit venting and flaring from well sites on federal lands and require operators to submit a methane waste minimization plan or self-certification statement committing the operator to capture 100% of the gas produced from a well and pay royalties on lost gas as part of the permit application process. This rule is currently subject to legal challenge and its implementation is paused in several states, including North Dakota. Though the Trump Administration has announced an intent to reverse regulations that hinder oil and gas production, it is uncertain what actions the administration may take with respect to this rule or otherwise affecting oil and gas leasing on federal lands. Uncertainty over continued implementation of the Biden Administration’s SC-GHGs metric may also impact future regulatory decision- and policy-making regarding oil and gas operations on federal lands. This metric, intended to inform federal agency cost/benefits analyses, has been contested in multiple lawsuits and the Trump Administration is not expected to continue its development or use. The ultimate impacts of these regulatory
initiatives concerning BLM leases and the use of the SC-GHGs metric cannot be predicted at this time, but such could affect the character of new regulations on certain federal oil and gas leases or oil and gas infrastructure on federal lands, which in turn could adversely impact our operators’ and our results of operations.
Additionally, oil and natural gas operations and related infrastructure projects on federal lands may be impacted by recent and ongoing revisions to the NEPA implementing regulations. NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs (“BIA”), to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. NEPA’s implementing regulations, as promulgated by the CEQ, have been subject to multiple revisions in recent years between the Trump and Biden Administrations. CEQ’s latest revisions under the Biden Administration expanded requirements to analyze the cumulative effects of the project on climate change and consider any disproportionate impact of the project on communities with environmental justice concerns as well enhance certain project obligations for implementing environmental mitigation measures. However, these regulations were vacated in February 2025 by a federal district court and the Court of Appeals for the D.C. Circuit recently held similarly that CEQ does not have authority to issue binding NEPA regulations. The ultimate consequences of this judicial decision are not yet clear and the actions the Trump Administration may take, if any, in the aftermath of these decisions cannot be predicted at this time.
Operations on federal lands also face litigation risks. From time to time, legal challenges have been filed relating to federal leasing decisions, such as for failure to adequately assess the impact of any increase of GHG emissions resulting from increased production on federal lands. Historically, such challenges have sought the cancellation or pause of lease sales and obligations to redo environmental assessments. For example, in April 2023 an environmental organization filed suit against the DOI, seeking to force the agency to develop and promulgate a regulation that would phase out all oil and gas development on federal lands by 2035.
Any of these administrative, legislative or judicial actions could adversely affect our financial condition and results of operations by restricting the lands available for development or by imposing additional and costly regulations. Additionally, depending on the results and mitigation recommendations presented in environment assessments or environmental impact statements required under NEPA, we and our operators and related service providers could incur added costs, and be subject to delays, limitations or prohibitions in the scope of crude oil and natural gas projects or performance of midstream services.
Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of oil and natural gas exploration and development companies and may adversely affect our operations and cash flows.
From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal and state income tax provisions currently applicable to oil and natural gas companies. Such proposed legislative changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the most recent federal tax legislation, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and natural gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and natural gas development or increase costs, or result in other tax-related changes, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could increase our future tax liabilities and adversely affect our operations and cash flows.
In addition, the IRA includes, among other things, a 1% non-deductible excise tax on the fair market value of any stock repurchased by a publicly traded domestic corporation during any taxable year, with the fair market value of such repurchased stock reduced by the fair market value of certain stock issued by such corporation during such taxable year (such excise tax, the “Stock Buyback Tax”). In the past, there have been proposals to increase the amount of the Stock Buyback Tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect. Although we were not subject to the Stock
Buyback Tax in 2024, share repurchases in the future under our stock repurchase program may result in us becoming subject to Stock Buyback Tax.
The U.S. Department of the Treasury and the Internal Revenue Service have released proposed and final regulations and other interpretive guidance relating to the Stock Buyback Tax. Any significant variance from our current interpretation of such regulations and interpretive guidance could result in a change in our analysis of the application of the Stock Buyback Tax to us and its impact on our operations and cash flows.
Our business involves the selling and shipping of oil by rail, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
A portion of our oil production is transported to market centers by rail. Derailments in North America of trains transporting oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids. Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport oil could increase our costs of doing business and limit our ability to transport and sell our oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, any derailment of oil involving oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.
Our derivative activities expose us to potential regulatory risks.
The FTC, FERC and the CFTC have statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to derivative activities that we undertake with respect to oil, natural gas or other energy commodities, we are required to observe the market-related regulations enforced by these agencies. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.
Legislative and regulatory developments could have an adverse effect on our ability to use derivative instruments to reduce the effect of volatile oil and natural gas price, interest rate and other risks associated with our business.
The Dodd-Frank Act contains measures aimed at increasing the transparency and stability of the OTC derivatives market and preventing excessive speculation. On January 14, 2021, the CFTC published a final rule imposing position limits for certain futures and options contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents, though certain types of derivative transactions are exempt from these limits, provided that such derivative transactions satisfy the CFTC’s requirements for certain enumerated “bona fide” derivative transactions. The CFTC also has adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns ten percent or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, although CFTC staff has granted relief until August 12, 2025 from various conditions and requirements in the final aggregation rules. These rules may affect both the size of the positions that we may hold and the ability or willingness of counterparties to trade with us, potentially increasing the costs of transactions. Moreover, such changes could materially reduce our access to derivative opportunities, which could adversely affect revenues or cash flow during periods of low oil and natural gas prices.
The CFTC also has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use. If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions. The ultimate effect of these rules and any additional regulations on our business is uncertain.
The full impact of the Dodd-Frank Act and related regulatory requirements on our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. In addition, it is possible that regulation of the OTC derivatives market and the entities that participate in that market could be expanded through either the Dodd-Frank Act or the enactment of new legislation. Regulations issued under the Dodd-Frank Act (including any further regulations implemented thereunder) and any new legislation also may require certain counterparties to our derivative instruments to spin off some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty. Such legislation and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our
available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. We maintain an active hedging program related to oil and natural gas price risks. Such legislation and regulations could reduce trading positions and the market-making activities of our counterparties. If we reduce our use of derivatives as a result of legislation and regulations or any resulting changes in the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on our debt obligations. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower oil and natural gas prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.
Our business is subject to complex federal, state, and local laws, as well as other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our operational interests, as operated by our third-party operators, are regulated extensively at the federal, state, tribal and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, our company (either directly or indirectly through our operators) could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our business and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Part of the regulatory environment in which we do business includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our business and limit the quantity of natural gas we may produce and sell. A major risk inherent in the drilling plans in which we participate is the need for our operators to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the development of our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff.
Failure to comply with federal, state and local environmental laws and regulations could result in substantial penalties and adversely affect our business.
All phases of the oil and natural gas business can present environmental risks and hazards and are subject to a variety of federal, state and municipal laws and regulations. Environmental laws and regulations, among other things, restrict and prohibit spills, releases or emissions of various substances produced in association with oil and natural gas operations, and require that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. There is risk of incurring significant environmental costs and liabilities as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to our business, and historical operations and waste disposal practices. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, loss of our leases, incurrence of investigatory or remedial obligations and the imposition of injunctive relief. Additionally, our operators may be subject to operational restrictions or additional expenses regarding compliance with laws and regulations to protect endangered species, sensitive habitats, or other natural resources, which in turn could adversely impact our results of operations. See Part I. Items 1 and 2. Business and Properties-Regulation and Environmental Matters for additional discussion of the environmental laws and regulations that affect our business and the production activities of our operators.
Environmental legislation and regulations are evolving in a manner we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge, regardless of whether we were responsible for the release or contamination and regardless of whether our operators met previous standards in the industry at the time they were conducted. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of operations on our properties. The application of new or more stringent environmental laws and regulations to our business may cause us to curtail production or increase the costs of our production or development activities.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is used extensively by our third-party operators. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions though the EPA has published permitting guidance and regulations covering certain hydraulic fracturing activities and investigated impacts of hydraulic fracturing on water resources. State regulation of hydraulic fracturing typically imposes permitting, public disclosure, and well construction requirements. For example, North Dakota requires operators to disclose the amount of water and chemicals used in hydraulic fracturing, subject to certain trade-secret exemptions. From time to time, there have also been various proposals to regulate hydraulic fracturing at the federal level or restrict hydraulic fracturing operations on federal lands. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply by us or our third-party operators could have a material adverse effect on our financial condition and results of operations.
In addition, in response to concerns relating to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities (so-called “induced seismicity”), regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.
Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
The adoption of climate change legislation or regulations restricting emissions of carbon dioxide, methane, and other greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.
The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, climate-related disclosure obligations, superfund-style mitigation funds, and regulations that directly limit GHG emissions from certain sources. International climate commitments made by political, industrial and financial stakeholders may also impact commercial, regulatory and consumer trends related to climate change. As a result, our operations are subject to a series of regulatory, political, litigation, and financial risks associated with emissions of GHGs from the oil and natural gas industry.
In recent years Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. While it presently appears unlikely that comprehensive climate change legislation will be passed by Congress in the near future, certain federal laws, like the IRA, have been enacted to advance numerous climate-related objectives. The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, supporting infrastructure and carbon capture and sequestration, among other provisions. Moreover, various federal agencies have adopted climate change considerations into their rulemaking and decision-making processes and have promulgated regulations that seek to restrict, monitor or otherwise limit GHG emissions. For example, in December 2023, the EPA finalized rules establishing more stringent methane and volatile organic compound emissions performance standards for oil and gas facilities. The IRA also included a first-ever fee on waste methane emissions, for which the EPA has finalized regulations to implement. These regulatory initiatives could increase operating costs within the oil and gas industry and the IRA’s funding provisions could accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. The Trump Administration announced its intent to seek reversal and eliminate support for such regulations and initiatives, though the extent to which and the timeline for doing so remains uncertain. Whether Congress elects to pursue legislation to repeal, revise, or otherwise limit the enforcement of these regulations and certain of the IRA’s provisions cannot be predicted at this time. Several states have also implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring, or otherwise regulating GHG emissions. See Part I. Items 1 and 2. Business and Properties-Regulation and Environmental Matters, for additional discussion of regulatory matters affecting and resulting from risks related to climate change and GHGs.
At the international level, the Paris Agreement requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. The international community continues to meet annually at Conferences
of the Parties to deliberate on global emissions reduction and climate-related initiatives. Recent Conferences of the Parties have resulted in reaffirmations of the goals of the Paris Agreement, calls for parties to eliminate fossil fuel subsidies, agreements to transition away from fossil fuels in energy systems and increase renewable energy capacity, financial commitments to fund energy transition efforts in developing countries, and similar initiatives, though none legally binding. While non-binding, agreements arising from any Conference of the Parties could result in increased pressure on politicians, regulators, financial institutions, consumers, and other stakeholders to reduce the use of, impose more stringent limitations on, increase opposition against, or reduce funding for, fossil fuels. The United States’ most recent goal under the Paris Agreement was to reduce its net economy-wide GHG emissions by 61-66 percent from 2005 levels by 2035. However, in January 2025, President Trump issued an executive order calling for the withdrawal of the United States from the Paris Agreement and revocation of any financial commitments thereunder as apart of a broader series of executive orders announcing a deregulatory approach with respect to climate change-related matters. Nevertheless, state or local governments may elect to continue participation in international climate change initiatives and pursue state- or regional-level climate-related regulations. Although it appears unlikely in the near-term that new federal climate-related measures will be imposed, and such new or more stringent regulations limiting or taxing the emission of GHGs, legislation restricting the production of oil and gas, or other climate-related policies having the effect of reducing the availability or attractiveness of fossil-fuel energy could reduce demand for the oil and gas we and our operators produce and sell and adversely impact our results of operations.
Increased regulatory scrutiny on emissions and related climate change matters has also led to increased litigation risks for fossil fuel companies. A number of states, municipalities and other plaintiffs have sought to bring suit against various oil and gas companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to climate change and its effects, such as rising sea levels, and therefore, are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. We are not currently a defendant in any of these lawsuits, but it could be named in actions in the future making similar allegations. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors. Involvement in such a case could have adverse reputational impacts and an unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations.
Wells in the Williston Basin of North Dakota, where we own significant oil and natural gas properties, produce natural gas as well as oil. Constraints in third party natural gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In 2014, the NDIC, North Dakota’s chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The NDIC requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. It is possible that other states in which we operate, including Montana, will require gas capture plans or otherwise institute new regulatory requirements in the future to reduce flaring.
Gas capture requirements and other regulatory requirements, in North Dakota or our other locations, could increase our operators’ operational costs and restrict production on our oil and natural gas properties, which could materially and adversely affect our financial condition, results of operations and cash flows. If our interpretation of the applicable regulations is incorrect, or if we receive a non-appealable order to pay royalty on past and future flared volumes in North Dakota, such royalty payments could materially and adversely affect our financial condition and cash flows.
Risks Relating to Tax Matters
If the Distribution does not qualify as a transaction that is tax-free for U.S. federal income tax purposes, Jefferies and holders of Jefferies common stock who received shares of our common stock in connection with the Spin-Off could be subject to significant tax liability.
In connection with the Spin-Off, Jefferies’ received (1) a ruling from the IRS and (2) a tax opinion from legal counsel, each substantially to the effect that, subject to the limitations specified therein and the accuracy of and compliance with certain representations, warranties and covenants, the Distribution, together with certain related transactions, qualified as a tax-free “reorganization” for U.S. federal income tax purposes under Section 368(a)(1)(D) of the Code and the Distribution qualified as a tax-free distribution within the meaning of Section 355 of the Code.
Although the IRS ruling is generally binding on the IRS, the continuing validity of the IRS ruling is subject to the accuracy of the factual representations made in the ruling request. In addition, in rendering its tax opinion, legal counsel relied on (1) customary representations and covenants made by Jefferies and Vitesse and (2) specified assumptions, including an assumption regarding the completion of the Distribution and certain related transactions in the manner contemplated by the transaction agreements. If any of those representations, covenants or
assumptions are inaccurate, the tax opinion may not be valid and the tax consequences of the Distribution and certain related transactions could differ from those described above. Notwithstanding the receipt of the IRS ruling and tax opinion, there can be no assurance that the IRS or a court will not take a contrary position and the consequences of the Distribution and certain related transactions to Jefferies and the holders of Jefferies common stock could be materially different from, and worse than, the U.S. federal income tax consequences described above.
If it were determined that the Distribution, together with certain related transactions, did not qualify as a tax-free “reorganization” within the meaning of Section 368(a)(1)(D) of the Code and the Distribution did not qualify as a distribution to which Section 355 of the Code applies, Jefferies would generally be subject to tax as if it sold the Vitesse common stock in a transaction taxable to Jefferies, which could result in a material tax liability. In addition, Jefferies shareholders who are U.S. holders would generally, for U.S. federal income tax purposes, be treated as receiving a distribution in an amount equal to the fair market value of our common stock received, which could result in a material tax liability.
We agreed to numerous restrictions to preserve the non-recognition treatment of the Distribution, which may reduce our strategic and operating flexibility.
We agreed in the Tax Matters Agreement to covenants and indemnification obligations that address compliance with Section 355(e) of the Code. These covenants and indemnification obligations may limit our ability to pursue strategic transactions or engage in new businesses or other transactions that may otherwise maximize the value of our business, and might discourage or delay a strategic transaction that our stockholders may consider favorable, including share repurchases, stock issuances, certain asset dispositions and other strategic transactions. To preserve the tax-free treatment of the Distribution, and in addition to our indemnity obligations described above, the Tax Matters Agreement restricts us, for the two-year period following the Distribution, except in specific circumstances, from: (1) entering into any transaction pursuant to which all or a specified portion of our stock would be acquired, whether by merger or otherwise, (2) issuing equity securities in a manner that could reasonably be expected to have adverse consequences under Section 355(e) of the Code, (3) repurchasing shares of our stock other than in certain open-market transactions, (4) ceasing to actively conduct certain of our businesses or (5) taking or failing to take any other action that prevents the Distribution and certain related transactions from qualifying as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code.
We could have an indemnification obligation to Jefferies in certain circumstances if the Distribution were determined not to qualify for tax-free treatment for U.S. federal tax purposes, or in certain other circumstances, which could materially adversely affect our business, financial condition and results of operations.
In connection with the Spin-Off, we entered into a Tax Matters Agreement with Jefferies. The terms of the Tax Matters Agreement require us to indemnify Jefferies and certain related parties for certain taxes and losses that (i) result primarily from, individually or in the aggregate, the breach of certain representations and warranties made by us (including in connection with the IRS ruling or the tax opinion regarding the tax treatment of the Distribution) or covenants made by us (applicable to actions or failures to act by us and our subsidiaries following the completion of the Distribution), (ii) are attributable to actions we take following the Distribution and result from the failure of the transfer of the Vitesse Energy equity interests to Vitesse, together with the Distribution, to qualify as (a) a reorganization described in Section 355(a) and Section 368(a)(1)(D) of the Code, (b) a transaction in which the stock distributed thereby is “qualified property” for purposes of Sections 355(c) and 361(c) of the Code, or (c) a transaction in which Jefferies, Vitesse and the holders of Jefferies common stock recognize no income or gain for U.S. federal income tax purposes pursuant to Sections 355, 361 and 1032 of the Code, including, as a result of the application of Section 355(e) of the Code to the Distribution as a result of a 50% or greater change in ownership as described below, or (iii) are attributable to taxes with respect to Vitesse Energy or Vitesse Oil for tax periods or portions thereof ending before the Distribution, including as may arise on audit.
Even if the Distribution were otherwise to qualify as a tax-free transaction under Section 368(a)(1)(D) and Section 355 of the Code, the Distribution would be taxable to Jefferies (but not to Jefferies’ shareholders) pursuant to Section 355(e) of the Code if there were a 50% or greater change in beneficial ownership of either Jefferies or Vitesse as part of a plan or series of related transactions that included the Distribution. For this purpose, any acquisitions of Jefferies or our common stock during the four-year period beginning on the date that begins two years before the date of the Distribution are presumed to be part of such a plan, although we or Jefferies may rebut that presumption. The U.S. federal income tax rules for determining whether there has been a 50% or greater change in beneficial ownership of Jefferies and Vitesse, and the period during which that change is measured, are complex and include the aggregation and attribution rules of Section 355(e)(4)(C) of the Code. The Distribution itself does not give rise to a change in beneficial ownership, and public trading of the stock of Jefferies or Vitesse by small stockholders does not give rise to a change in beneficial ownership, but many other transactions could do so. Such transactions may include (but are not limited to) acquisitions by Vitesse or Jefferies using its own stock, the merger or consolidation of Vitesse or Jefferies with or into another company, redemptions, recapitalizations, stock dividends, and sales or issuances of stock.
Taxable gain or loss on the sale of our common stock could be more or less than expected.
If a stockholder sells our common stock, the stockholder will recognize gain or loss equal to the difference between the amount realized and the holder’s tax basis in the shares of common stock sold. A stockholder’s basis in our common stock may be adjusted during the course of its holding for various reasons, including being lowered as a result of certain distributions on our common stock, to the extent such distributions exceed our current and accumulated earnings and profits. In such a case, such excess will be treated as a tax free return of capital and will reduce a stockholder’s tax basis in our common stock. Such reduction in basis, to the extent that it shall occur, will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the stockholder upon the sale of our common stock.
The IRS Forms 1099-DIV that our stockholders receive from their brokers may over-report dividend income with respect to our common stock for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax. In addition, failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a stockholder’s U.S. federal income tax return. For non-U.S. holders of our common stock, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund to claim a refund of the overwithheld taxes.
Distributions we pay with respect to our common stock will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Distributions we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a stockholder’s tax basis in their common stock and then as capital gain realized on the sale or exchange of such stock. We may be unable to timely determine the portion of our distributions that is a “dividend” for U.S. federal income tax purposes, which may result in a stockholder’s overpayment of tax with respect to distribution amounts that should have been classified as a tax-free return of capital. In such a case, a stockholder generally would have to timely file an amended U.S. tax return or an appropriate claim for refund to obtain a refund of the overpaid tax.
For a U.S. holder of our common stock, the IRS Forms 1099-DIV received from brokers may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a stockholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended U.S. federal, state or local income tax return). We will attempt to timely notify our stockholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our stockholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a stockholder’s tax return.
For a non-U.S. holder of our common stock, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate (or such lower rate as may be specified by an applicable income tax treaty) unless the dividends are effectively connected with the conduct of a U.S. trade or business. In the event that we are unable to timely determine the portion of our distributions that constitute a “dividend” for U.S. federal income tax purposes, or a stockholder’s broker or withholding agent chooses to withhold taxes from distributions in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a stockholder’s broker or other withholding agent may overwithhold taxes from distributions paid. In such a case, a stockholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.
Some stockholders might be deemed to have received a taxable distribution as a result of our repurchase of our own stock.
Under certain circumstances, where a corporation repurchases its own stock, certain stockholders whose stocks have not been redeemed might be deemed to have received a taxable distribution. We do not currently know if any repurchase of our stock under the Stock Repurchase Program or any other contemplated repurchase of our stocks would satisfy the circumstances under which such potential tax liability may arise. While we believe that the repurchase of our stock under the Stock Repurchase Program and any other possible contemplated repurchase of our stocks, even if it were to satisfy such circumstances, would be an “isolated redemption” which would not result in taxable income to the non-redeemed stockholders, we have not requested, nor do we intend to request, a ruling to that effect. The IRS may disagree with this position, and a successful challenge by the IRS may thus result in taxable income to such non-redeemed stockholders.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
From time to time we are subject to legal, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits and pending judicial matters. Based on our current knowledge, we believe that the amount or range of reasonably possible losses will not, either individually or in the aggregate, materially adversely affect our business, financial condition and results of operations.
The results of any litigation cannot be predicted with certainty, and an unfavorable resolution in any legal proceedings could materially affect our business, financial condition and results of operations. Regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources and other factors.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the New York Stock Exchange under the symbol “VTS.” The closing price for our common stock on March 10, 2025 was $23.77 per share.
Comparison Performance Chart
The following information in this Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) or to the liabilities of Section 18 of the Exchange Act, and will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such a filing.
The following graph compares the cumulative total stockholder return on our common stock since January 17, 2023 (VTS’s first trading day following the Spin-Off), and the cumulative total returns of Standard & Poor’s 500 Index (“S&P 500”) and the S&P Oil & Gas Exploration & Production Select Industry Index (“S&P O&G E&P”) for the same period. This graph tracks the performance of a $100 investment in our common stock and in each index (including reinvestment of all dividends) from January 17, 2023 to December 31, 2024.
The stock price performance included in this graph is not necessarily indicative of future stock price performance.
Authorized Capital Stock
The Company has authorized 95,000,000 shares of common stock, par value $0.01 per share and 5,000,000 shares of preferred stock, par value $0.01 per share.
Shares Outstanding
Immediately prior to the closing of the Lucero Acquisition on March 7, 2025, we had 30,409,973 shares of our common stock outstanding, held by approximately 1,141 stockholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
In conjunction with the Lucero Arrangement, on March 7, 2025, we issued 8,169,368 shares of our common stock to close the transaction.
Securities Authorized for Issuance Under Equity Compensation Plans
See the information incorporated by reference under Part III. Item 12. Security Ownership of Certain Beneficial Owners and Management regarding securities authorized for issuance under our equity compensation plans.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Issuer Purchases of Equity Securities
In February 2023, our 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, Vitesse 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. Our Board 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.
The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) of our common stock during the quarter ended December 31, 2024.
Period Total Number of Shares Purchased(1)
Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or
Programs(1)
Approximate Dollar Value of Shares
that May Yet be Purchased Under
the Plans or Programs
October 1, 2024 to October 31, 2024 - $ - - 59.8 million
November 1, 2024 to November 30, 2024 - - - 59.8 million
December 1, 2024 to December 31, 2024 - - - 59.8 million
Total - $ - - $ 59.8 million
(1) In February 2023, our Board approved a Stock Repurchase Program authorizing the repurchase of up to $60 million of the Company’s common stock.
During 2024, 852,000 restricted stock units of certain executive officers vested with the Company retaining 354,069 of the vested shares to fund employee tax withholding of $7.5 million with the retained shares subsequently retired by the Company. These retained and retired shares are not included in the above table because they do not constitute a repurchase of equity securities.
In January 2025, 792,000 restricted stock units of certain executive officers vested with the Company retaining 335,797 of the vested shares to fund employee tax withholding of $8.9 million with the retained shares subsequently retired by the Company.
In February 2025, 23,136 restricted stock units of certain executive officers vested with the Company retaining 9,458 of the vested shares to fund employee tax withholding of $0.2 million with the retained shares subsequently retired by the Company.
Dividend Policy
The timing, declaration, amount of and payment of any dividends will be within the discretion of our Board and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt service obligations, legal requirements or limitations, industry practice, and other factors deemed relevant by our Board. We paid cash dividends of $63.6 million to our equity holders during the year ended December 31, 2024. While we believe that our future cash flows from operations will be able to sustain the current level of dividends, 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 stockholders in the future. We have not adopted, and do not expect to adopt, a separate written dividend policy. For factors that could affect our ability to pay dividends, see Part I. Item 1A. Risk Factors, including -Risks Relating to Our Common Stock-Although we expect to continue to pay dividends, we cannot provide assurance that we will pay dividends on our common stock, and our indebtedness may limit our ability to pay dividends on our common stock and-Risks Relating to Our Indebtedness-Our ability to pay dividends to our stockholders is restricted by requirements under our Revolving Credit Facility.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion of our results of operations and financial condition together with our Audited Consolidated Financial Statements and the notes thereto included under the section entitled “Index to Financial Statements,” as well as the discussion in Part I. Items 1 and 2. Business and Properties. This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions and projections about the oil and natural gas industry and our business and financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in Part I. Item 1A. Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.”
This section generally discusses certain 2024 and 2023 items and certain year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are not included in this Form 10-K can be found in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed on February 24, 2024 which is incorporated herein by reference.
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 have historically invested in non-operated minority 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, although we have assumed limited operations in the Williston Basin through the Lucero Acquisition. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of December 31, 2024, we had a working interest in 6,071 gross (168.2 net) productive wells and 248 gross (9.7 net) wells that were being drilled or completed, and an additional 362 gross (8.0 net) wells that had been permitted for development by our operators. In addition, we had a royalty only interest in 1,180 gross (2.8 net) productive wells.
Our financial and operating performance for the year ended December 31, 2024 included the following:
■Paid $63.6 million in dividends to our equity holders.
■Production of 13,003 Boe/d with 69% of production from oil.
■Total revenue of $242.0 million.
■Net income of $21.1 million.
■Cash flows from operations of $155.0 million.
■Invested $115.2 million in capital development and acquisitions.
■Proved reserves of 40.3 MMBoe and $587 million PV-10 value at December 31, 2024, as estimated by our third-party reserve engineers using SEC guidelines.
■Total debt of $117.0 million at December 31, 2024.
See Non-GAAP Financial Information for additional information about PV-10.
On December 15, 2024, Vitesse and Lucero entered into the Lucero Arrangement Agreement, pursuant to which, on the terms and subject to the conditions set forth therein, Vitesse would acquire all of the issued and outstanding Lucero common shares, in an all stock transaction, pursuant to a Plan of Arrangement, with Lucero becoming a wholly owned subsidiary of Vitesse. The Arrangement was subject to the approval by the Alberta Court, Vitesse and Lucero equity holders and certain other customary conditions precedent. On March 7, 2025, the Lucero Acquisition was consummated pursuant to which we acquired Lucero in an all-stock transaction. Lucero shareholders received 0.01239 of a share of Vitesse common stock for each common share of Lucero with 8,169,368 shares of Vitesse common stock issued. Lucero is an oil and natural gas operator with assets in the Bakken and Three Forks formations in the Williston Basin area of North Dakota. Upon completion of the Lucero Acquisition, prior Vitesse stockholders owned approximately 80% and prior Lucero shareholders owned approximately 20% of the common stock of the Company on a fully diluted basis.
The Lucero Acquisition is expected to strengthen our balance sheet and cash flows and serve to enhance our competitive strengths by increasing the optionality of our capital deployment through adding a limited operating function while maintaining our focus on assets in the Williston Basin. This acquisition is expected to increase future revenue, expenses, cash flows and capital expenditures.
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 periodic downturns and sustained volatility, impacted by the COVID-19 pandemic and recovery, the ongoing military conflict between
Russia and Ukraine, conflict in the Middle East, supply chain constraints, elevated interest rates and costs of capital, and reductions in production by OPEC and its key member, Saudi Arabia, and certain other non-OPEC oil-producing countries.
As a result of such commodity price volatility, which we expect to continue throughout 2025, 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 planned repurchases (or possible releases) of oil from the strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC and other oil-producing countries, the imposition of tariffs and resulting consequences, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. 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
We derive our revenues from the sale of oil and natural gas produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production. We also entered into a number of costless collars for natural gas in the first quarter of 2025. 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 derivatives 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 (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) 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 corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. For fiscal 2024 and 2023, general and administrative expenses included non-recurring costs related to the Lucero Acquisition and the Spin-Off, respectively.
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 years ended December 31, 2024, 2023 and 2022.
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 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;
■changes in the fair value of the derivative instruments;
■our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
■the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Denver-Julesburg and Powder River Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
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 and the strength of the U.S. dollar can adversely impact oil prices.
The price at which our oil production is sold typically reflects a discount to the WTI benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the Henry Hub benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the weighted average WTI benchmark price during the year ended December 31, 2024 was negative $5.90 per Bbl, as compared to a negative $4.19 per Bbl during the year ended December 31, 2023, primarily due to less favorable local market pricing, including gathering and transportation costs, as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2024 was $1.34 per Mcf, representing a 62% realization relative to average Henry Hub pricing, compared to a net realized natural gas price of $1.88 per Mcf during the year ended December 31, 2023, representing a 74% realization relative to average Henry Hub pricing. 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 costs, 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 pass through these costs in a different manner.
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.
YEAR ENDED DECEMBER 31,
Average Daily Prices (1)
2024 2023 2022
WTI Oil (per Bbl) $ 75.69 $ 77.58 $ 94.90
Natural Gas (per MMBtu) 2.19 2.53 6.45
(1)Based on average daily NYMEX WTI and Henry Hub Spot closing prices reported by FactSet and the EIA, respectively.
The average calendar 2024 WTI oil price was $75.69 per Bbl or 2% lower than the average WTI price per Bbl in calendar 2023. Our settled derivatives increased our realized oil price per Bbl by $1.54 in calendar 2024 and increased our realized oil price per Bbl by $0.40 in calendar 2023. Our average 2024 realized oil price per Bbl after reflecting settled derivatives was $71.48 compared to $73.99 in 2023. The average calendar 2024 NYMEX natural gas price was $2.19 per MMBtu, or 13% lower than the average NYMEX price per MMBtu in calendar 2023. We had no gas price derivatives in place in calendar 2024 and 2023. Our 2024 realized natural gas price per Mcf was $1.34 compared to $1.88 in 2023, which was primarily driven by lower NYMEX pricing for natural gas and gas realization.
We employ a hedging program that partially mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Notes to Consolidated Financial Statements-Note 6-Derivative Instruments.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant.
Results of Operations
Year Ended December 31, 2024 Compared with Year Ended December 31, 2023
The following table sets forth selected operating data for the periods indicated.
YEAR ENDED
DECEMBER 31, INCREASE
(DECREASE)
($ in thousands, except per unit data) 2024 2023 AMOUNT PERCENT
Operating Results:
Revenue
Oil $ 230,164 $ 218,396 $ 11,768 5 %
Natural gas 11,834 15,509 (3,675) (24 %)
Total revenue $ 241,998 $ 233,905 $ 8,093 3 %
Operating Expenses
Lease operating expense $ 47,599 $ 39,514 $ 8,085 20 %
Production taxes 21,500 21,625 (125) (1 %)
General and administrative 23,510 23,934 (424) (2 %)
Depletion, depreciation, amortization, and accretion 100,308 81,745 18,563 23 %
Equity-based compensation 8,110 32,233 (24,123) (75 %)
Interest Expense $ 9,980 $ 5,276 $ 4,704 89 %
Income Tax Expense $ 7,672 $ 61,946 $ (54,274) (88 %)
Commodity Derivative (Loss) Gain $ (2,348) $ 12,484 $ (14,832) (119 %)
Production Data:
Oil (MBbls) 3,291 2,968 323 11 %
Natural gas (MMcf) 8,809 8,232 577 7 %
Combined volumes (MBoe) 4,759 4,340 419 10 %
Daily combined volumes (Boe/d) 13,003 11,889 1,114 9 %
Average Realized Prices before Hedging:
Oil (per Bbl) $ 69.94 $ 73.59 $ (3.65) (5 %)
Natural gas (per Mcf) 1.34 1.88 (0.54) (29 %)
Combined (per Boe) 50.85 53.90 (3.05) (6 %)
Average Realized Prices with Hedging:
Oil (per Bbl) $ 71.48 $ 73.99 $ (2.51) (3 %)
Natural gas (per Mcf) 1.34 1.88 (0.54) (29 %)
Combined (per Boe) 51.91 54.17 (2.26) (4 %)
Average Costs (per Boe):
Lease operating expense $ 10.00 $ 9.11 $ 0.89 10 %
Production taxes 4.52 4.98 (0.46) (9 %)
General and administrative 4.94 5.52 (0.58) (11 %)
Depletion, depreciation, amortization, and accretion 21.08 18.84 2.24 12 %
Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $242.0 million for the year ended December 31, 2024 from $233.9 million for the year ended December 31, 2023. The increase in oil and natural gas revenue was due to a 10% increase in production volumes, and was partially offset by a 6% decrease in the average realized prices per Boe before hedging for the year ended December 31, 2024. The increase in production volumes increased oil and natural gas revenue by approximately $21.3 million, while the decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $13.2 million.
The decreases in realized oil and natural gas prices were primarily due to lower benchmark commodity prices in the year ended December 31, 2024 as compared to the year ended December 31, 2023, as well as increased differentials. Our oil price differential to the weighted average benchmark price during the year ended December 31, 2024 was negative $5.90 per Bbl, as compared to a negative $4.19 per Bbl during the year ended December 31, 2023, primarily due to less favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2024 was $1.34 per Mcf, representing a 62% realization relative to the weighted
average NYMEX natural gas price, compared to a net realized natural gas price of $1.88 per Mcf during the year ended December 31, 2023, representing a 74% realization relative to the weighted average NYMEX natural gas price. 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 increased to $10.00 per Boe for the year ended December 31, 2024 from $9.11 per Boe for the year ended December 31, 2023. The increase per Boe for the year ended December 31, 2024 compared with the year ended December 31, 2023 was related to increased workover operations and higher service costs. The increased workover costs were responsible for approximately $0.10/Boe of the increase and should result in increased production when these wells return to production.
Production Tax Expense. Total production taxes decreased to $21.5 million for the year ended December 31, 2024 from $21.6 million for the year ended December 31, 2023. 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 9.2% for the years ended December 31, 2024 and 2023, respectively. The lower production tax rate was driven by the production mix and the relative tax rates on oil and natural gas revenue.
General and Administrative Expense. General and administrative expense decreased to $23.5 million for the year ended December 31, 2024 from $23.9 million for the year ended December 31, 2023. General and administrative expense on a per Boe basis decreased to $4.94 for the year ended December 31, 2024 from $5.52 for the year ended December 31, 2023. Costs related to the Spin-Off are included in 2023 and costs related to the Lucero Acquisition are included in 2024. Excluding these costs, the per Boe rate for the years ended December 31, 2024 and 2023 would have been $4.47 and $3.94, respectively. The increase in general and administrative expense per Boe, excluding the Spin-Off and Lucero Acquisition costs, was due to higher legal costs and costs associated with being a public company.
DD&A. DD&A increased to $100.3 million for the year ended December 31, 2024 compared with $81.7 million for the year ended December 31, 2023. The increase of $18.6 million or 23% was the result of a 10% increase in production and a 12% increase in the DD&A rate for the year ended December 31, 2024 compared with the year ended December 31, 2023. The increase in production accounted for a $8.8 million increase in DD&A expense while the increase in the DD&A rate accounted for a $9.7 million increase in DD&A expense.
For the year ended December 31, 2024, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $20.92 per Boe compared with $18.68 per Boe for the year ended December 31, 2023. The increase in the depletion rate was driven by decreased oil and natural gas reserves related to the lower oil and natural gas prices combined with higher operating expenses and the impact of acquisitions and related capital expenditures in the year ended December 31, 2024.
Equity-based Compensation. During the year ended December 31, 2024, equity-based compensation expense decreased to $8.1 million from $32.2 million during the year ended December 31, 2023. Equity-based compensation expense was higher in 2023 due to retirement vesting provisions in some of the awards resulting in 1,863,000 restricted stock units being expensed upon award. The retirement vesting provisions were responsible for $26.8 million of expenses during the year ended December 31, 2023.
Interest Expense. Interest expense increased to $10.0 million for the year ended December 31, 2024 from $5.3 million for the year ended December 31, 2023. The increase for the year ended December 31, 2024 was due to a higher SOFR interest rate in the year ended December 31, 2024 and a higher average outstanding balance on our Revolving Credit Facility during the year ended December 31, 2024 compared to 2023. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve during the first nine months of the year ended December 31, 2024.
Commodity Derivative (Loss) Gain. The net commodity derivative loss was $2.3 million for the year ended December 31, 2024 compared with a gain of $12.5 million for the year ended December 31, 2023. Gain (loss) on commodity derivatives, net is comprised of (i) cash gains and losses we recognize on settled commodity derivatives during the period, and (ii) non-cash mark-to-market 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.
YEAR ENDED DECEMBER 31,
(in thousands)
2024 2023
Realized gain on commodity derivatives (1)
$ 5,065 $ 1,166
Unrealized (loss) gain on commodity derivatives (1)
(7,413) 11,318
Total commodity derivative (loss) gain
$ (2,348) $ 12,484
(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 (loss) gain in the consolidated statements of operations included in this Annual Report on Form 10-K. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position.
In 2024, approximately 59% of our oil volumes and none of our natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $5.1 million. In 2023, approximately 49% of our oil volumes and none of our natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $1.2 million.
At December 31, 2024, all of our derivative contracts were recorded at their fair value, which was a net asset of $3.7 million, a decrease of $7.4 million from the $11.1 million net asset recorded as of December 31, 2023, while a net liability of $0.2 million was recorded as of December 31, 2022. The decrease in 2024 and asset increase in 2023 was due to changes to forward commodity prices relative to prices on our open commodity derivative contracts and new contracts entered into in the respective years.
Income Tax Expense. We recorded income tax expense of $7.7 million for the year ended December 31, 2024 related to federal and state income taxes. The effective tax rate of 26.7% for the year ended December 31, 2024 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 and state income taxes.
During the year ended December 31, 2023, we recorded income tax expense of $61.9 million related to federal and state income taxes. In January 2023, in connection with the Spin-Off, the Predecessor was contributed into Vitesse resulting in a change in tax status and the recording of a $44.1 million deferred tax liability related to the temporary difference between the tax and GAAP basis of the assets of the Predecessor and an offsetting charge to income tax expense.
Liquidity and Capital Resources
Overview. At December 31, 2024 and 2023, we had $3.0 million and $0.6 million of unrestricted cash on hand and $128.0 million and $164.0 million available under our Revolving Credit Facility, respectively. We expect that our liquidity going forward will be primarily derived from cash flows from our operations, cash on hand and 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.
The Lucero Acquisition is expected to increase the optionality of our capital deployment by adding a limited operating function. This acquisition is expected to increase future revenue, expenses, cash flows and capital expenditures. Upon the closing of the Lucero Acquisition, $49.8 million of cash was acquired along with the other assets and liabilities, which did not include any incremental long term debt.
Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of revenue receivables, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments.
At December 31, 2024, we had a working capital deficit of $49.4 million, compared to a deficit of $2.1 million at December 31, 2023. Current assets decreased by $7.4 million while current liabilities increased by $39.9 million at December 31, 2024, compared to December 31, 2023. The decrease in current assets in 2024 as compared to 2023 was due to a decrease of $6.2 million in our commodity derivative instruments due to forward oil price decreases as compared to hedged oil prices, and a decrease of $5.1 million in revenue receivable primarily due to lower oil and natural gas revenue in the fourth quarter, partially offset by an increase in our cash balance of $2.4 million and an increase in other receivables of $1.5 million primarily related to prepayments and a higher receivable from commodity derivative
instruments. The increase in current liabilities in 2024 as compared to 2023 was primarily due to an increase of $39.8 million in accounts payable and accrued liabilities as a result of increased development activity.
Cash Flows. Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below:
FOR THE YEARS ENDED DECEMBER 31,
(in thousands) 2024 2023 2022
Cash flows provided by operating activities
$ 155,003 $ 141,942 $ 147,041
Cash flows used in investing activities
(115,321) (120,666) (84,583)
Cash flows used in financing activities
(37,267) (30,731) (57,807)
Net increase (decrease) in cash
$ 2,415 $ (9,455) $ 4,651
During the year ended December 31, 2024, we generated $155.0 million of cash from operations, an increase of 9% from the year ended December 31, 2023 driven by a 3% increase in total revenue. During the year ended December 31, 2023, we generated $141.9 million of cash from operating activities, a 3% decrease from the year ended December 31, 2022. Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. A minimum level of derivative coverage is required by certain debt covenants. See Part II. Item 7A. 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. As of December 31, 2024, we had oil swaps covering 2,304,003 Bbls at a weighted average price of $71.16 per Bbl for calendar 2025 and oil swaps covering the sale of 917,994 Bbls at a weighted average price of $66.95 per Bbl for calendar 2026. As of December 31, 2024, we had no natural gas derivative contracts. For more information on our outstanding derivatives, see Notes to Consolidated Financial Statements-Note 6-Derivative Instruments.
Cash used in investing activities during the years ended December 31, 2024, 2023 and 2022 was $115.3 million, $120.7 million, and $84.6 million, respectively. 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 cash spending for acquisition activities was $21.1 million, $35.7 million and $28.5 million during the years ended December 31, 2024, 2023 and 2022, respectively.
Cash used in financing activities was $37.3 million, $30.7 million, and $57.8 million during the years ended December 31, 2024, 2023 and 2022, respectively. The cash used in financing activities was related to distributions to our equity holders of $63.6 million, $58.0 million and $36.0 million during the years ended December 31, 2024, 2023 and 2022, respectively and net repayments of $20.0 million during the year ended December 31, 2022 under our Prior Revolving Credit Facility. During the years ended December 31, 2024, and 2023, net borrowings under our Revolving Credit Facility of $36.0 million and $28.0 million, respectively, partially offset these other uses of funds.
Revolving Credit Facility. In connection with the Spin-Off, 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 will mature 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.
As of December 31, 2024, the Company’s borrowing base was $245.0 million with an aggregate elected commitment of $235.0 million of which $117.0 million was outstanding. See Notes to Consolidated Financial Statements-Note 5-Credit Facility for further details regarding the Revolving Credit Facility. In conjunction with the closing of the Lucero Acquisition on March 7, 2025, the Revolving Credit Facility was amended to increase the borrowing base to $315 million. This increase will serve as the borrowing base redetermination scheduled to occur in April 2025. The next borrowing base redetermination is scheduled for the fall of 2025. In addition, pursuant to the terms of the Revolving Credit Facility and as part of the amendment, the Company elected to increase the aggregate elected commitment amount to $250.0 million.
Prior Revolving Credit Facility. See Notes to the Consolidated Financial Statements -Note 5-Credit Facility for further details regarding the Prior Revolving Credit Facility.
Material Cash Requirements. Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. As 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.
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 (including the Lucero Acquisition), 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 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 Notes to Consolidated Financial Statements-Note 4- Fair Value Measurements for further information on these contracts and their fair values as of December 31, 2024, 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 $63.6 million during the year ended December 31, 2024. While we believe that our future cash flows from operations will be able to sustain an increasing level of 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 year ended December 31, 2024 total capital expenditures was $115.2 million, including development expenditures and our acquisition 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, including the Lucero Acquisition. For additional information on the impact of changing prices and market conditions on our financial position, see Part II. Item 7A 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 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.
Non-GAAP Financial Information
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure for proved reserves. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at ten percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. PV-10 and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves.
The table below reconciles the pre-tax PV-10 value of our proved reserves at SEC prices as of December 31, 2024 to the Standardized Measure.
FOR THE YEAR ENDED DECEMBER 31,
(in thousands) 2024
Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) $ 586,590
Future Income Taxes, Discounted at 10%
$ (80,259)
Standardized Measure of Discounted Future Net Cash Flows $ 506,331
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves. Further, our actual realized price for our oil and natural gas is not likely to equal the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.
Additional discussion of our proved reserves is set forth under Notes to Consolidated Financial Statements-Supplemental Oil and Gas Information (Unaudited).
Critical Accounting Policies and Estimates
We prepare our financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies and estimates as critical based on, among other things, their impact on our financial condition, results of operations, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies and estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies and estimates. The following is a discussion of our most critical accounting policies and estimates.
Proved Oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments that may be recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our
reserves may change and therefore the estimate of proved reserves may also change. Approximately 32% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves. Our 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.
External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements for the year ended December 31, 2024, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.
Oil and Natural Gas Properties
We follow 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.
We review our oil and natural gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. If we determined an evaluation for impairment is required, we estimate the expected future cash flows of our oil and natural gas properties and compare such cash flows to the carrying amount of the proved oil and natural gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of proved oil and natural gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks.
For the years ended December 31, 2024, 2023, and 2022 we did not record any impairment expense.
Predecessor Equity-Based Compensation
In 2020, the Predecessor amended the Predecessor Company Agreement which modified certain terms and conditions related to management incentive units (“MIUs”) and common units held by the founding members of management. The Predecessor accounted for MIUs granted to employees (which excludes the founding members of management) as liability awards under accounting guidance related to share-based compensation, whereby vested awards are recognized as liabilities, with changes in the estimated value of the awards recorded in earnings, until the holders have borne the risk of unit ownership, at which point the liability associated with the employee MIUs is reclassified to temporary equity, and changes in the estimated value of the MIUs are recorded as an adjustment to members’ equity.
Equity-based compensation was also recognized for in-substance call options granted to the founding members of management which were classified as liabilities, recorded at estimated fair market value at each period end. Changes in the estimated fair value were recorded in earnings. As the Predecessor was a private entity whose units were not traded, we considered the average volatility of comparable entities to develop an estimate of expected volatility which resulted in a reasonable estimate of fair value.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Notes to the Consolidated Financial Statements-Note 2-Significant Accounting Policies.”
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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosure 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 that also increase and decrease along with oil 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. 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.
The following table summarizes our open crude oil swap contracts as of December 31, 2024, by fiscal quarter.
SETTLEMENT PERIOD OIL (Bbls)
WEIGHTED AVERAGE PRICE
Swaps-Crude Oil
2025:
Q1 526,500 $72.55
Q2 649,503 $71.85
Q3 586,503 $69.99
Q4 541,497 $70.25
2026:
Q1 353,997 $66.90
Q2 329,997 $66.90
Q3 119,997 $67.10
Q4 114,003 $67.10
See Notes to the Consolidated Financial Statements-Note 4-Fair Value Measurements and -Note 6-Derivative Instruments for further details regarding our commodity derivatives.
Based upon our open commodity derivative positions at December 31, 2024, a hypothetical $1 increase or decrease in the NYMEX WTI strip price would increase or decrease our net commodity derivative position by approximately $3.1 million. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices decrease or increase.
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 $1.0 million increase or decrease in interest expense for the year ended December 31, 2024.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
The information required by this Item is included in this Annual Report as set forth in the “Index to Financial Statements” on page of this report and is incorporated herein by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, under the supervision of our principal executive officer and principal financial officer, performed an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Annual Report. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide a reasonable level of assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on such evaluation, management has concluded that, as of December 31, 2024, the Company’s disclosure controls and procedures were effective at the reasonable assurance level.
In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(f) of the Exchange Act that occurred during the fourth quarter of 2024 that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act and for performing an assessment of the effectiveness of internal control over financial reporting as of December 31, 2024. Our internal control over financial reporting is a process under the supervision of our principal executive officer and principal financial officer, and effected by our Board of Directors, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles (“GAAP”).
Our internal control over financial reporting includes those policies and procedures that:
(i)pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of assets of the Company;
(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures are being made only in accordance with authorizations of the Company’s management and Board of Directors; and
(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations in all control systems, no evaluation of internal controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Also, any evaluation of the effectiveness of controls in future periods is subject to the risk that those internal controls may become inadequate because of changes in business conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2024 based on the framework and criteria in Internal Control - Integrated Framework issued by the 2013 Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”). Based on our evaluation under such framework, management determined that our internal control over financial reporting was effective as of December 31, 2024.
Attestation Report of the Registered Public Accounting Firm
Our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
During the fiscal quarter ended December 31, 2024, none of our officers or directors, as defined in Rule 16a-1(f), informed us of the adoption, modification or termination of any "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as those terms are defined in Item 408 of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The following table presents information, as of March 11, 2025, regarding the individuals who are serving as executive officers and directors of Vitesse:
NAME AGE POSITION
Robert W. Gerrity
73 Chairman and Chief Executive Officer
Brian J. Cree 61 President
James P. Henderson
59 Chief Financial Officer
M. Scott Regan
54 General Counsel and Secretary
Linda Adamany 72 Director
M. Bruce Chernoff
59 Director
Brian P. Friedman 69 Director
Daniel O’Leary 69 Lead Independent Director
Cathleen M. Osborn 72 Director
Gary D. Reaves
45 Director
Randy Stein 71 Director
Joseph S. Steinberg 81 Director
Information regarding our Code of Business Conduct and Ethics, and Corporate Governance Guidelines 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.
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 10 the information not otherwise disclosed in this Item 10 and to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 11 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 12 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 13 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 14 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2024.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
The consolidated financial statements are listed on the Index to Financial Statements to this report beginning on page.
(a)(3) Exhibits.
Exhibit No. Description Reference
2.1* Separation and Distribution Agreement, dated as of January 13, 2023, by and among Jefferies Financial Group Inc., Vitesse Energy Finance LLC, Vitesse Energy, Inc., and the other signatories listed therein
Incorporated by reference to Exhibit 2.1 to Form 8-K filed January 17, 2023, File No. 001-41546
2.2*
Arrangement Agreement, dated as of December 15, 2024, between Vitesse Energy, Inc. and Lucero Energy Corp.
Incorporated by reference to Exhibit 2.1 to Form 8-K filed December 19, 2024, File No. 001-41546
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 Description of Vitesse Energy, Inc.’s Common Stock
Incorporated by reference to Exhibit 4.1 to Form 10-K filed February 26, 2024, File No. 0001-41546
10.1 Tax Matters Agreement, dated as of January 13, 2023, between Jefferies Financial Group Inc. and Vitesse Energy, Inc.
Incorporated by reference to Exhibit 10.1 to Form 8-K filed January 17, 2023, File No. 001-41546
10.2* Second Amended and Restated Credit Agreement, dated as of January 13, 2023, among Vitesse Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
Incorporated by reference to Exhibit 10.2 to Form 8-K filed January 17, 2023, File No. 001-41546
10.3 First Amendment to Second Amended and Restated Credit Agreement dated as of May 2, 2023, among Vitesse Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
Incorporated by reference to Exhibit 10.3 to Form 10-Q filed May 8, 2023, File No. 001-41546
10.4 Second Amendment to Second Amended and Restated Credit Agreement dated as of May 20, 2024, among Vitesse Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
Incorporated by reference to Exhibit 10.1 to Form 10-Q filed August 5, 2024, File No. 001-41546
10.5 Third Amendment to Second Amended and Restated Credit Agreement dated as of October 22, 2024, among Vitesse Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
Incorporated by reference to Exhibit 10.1 to Form 10-Q filed November 4, 2024, File No. 001-41546
10.6†
Vitesse Energy, Inc. Long-Term Incentive Plan
Incorporated by reference to Exhibit 10.3 to Form 8-K filed January 17, 2023, File No. 001-41546
10.7†*
Vitesse Energy, Inc. Transitional Equity Award Adjustment Plan*
Incorporated by reference to Exhibit 10.4 to Form 8-K filed January 17, 2023, File No. 001-41546
10.8†
Form of RSU Award Agreement (Executive - Retirement)
Incorporated by reference to Exhibit 10.9 to the Registration Statement on Form 10, declared effective January 6, 2023, File No. 001-41546
10.9†
Form of RSU Agreement (Executive - Three Year Vesting)
Incorporated by reference to Exhibit 10.10 to the Registration Statement on Form 10, declared effective January 6, 2023, File No. 001-41546
10.10†
Form of RSU Agreement (Employee - Three Year Vesting)
Filed herewith.
10.11†
Form of RSU Agreement (Employee - Four Year Vesting)
Incorporated by reference to Exhibit 10.11 to the Registration Statement on Form 10, declared effective January 6, 2023, File No. 001-41546
10.12†
Form of RSU Agreement (Director)
Incorporated by reference to Exhibit 10.10 to Form 10-K filed February 16, 2023, File No. 001-41546
10.13†
Form of Performance Stock Unit Grant Notice
Incorporated by reference to Exhibit 10.13 to Form 10-K filed February 26, 2024, File No. 0001-41546
10.14 Form of Lucero Voting Agreement (filed with Lucero Arrangement Agreement)
Incorporated by reference to Exhibit 2.1 to Form 8-K filed December 19, 2024, File No. 0001-41546
10.15*
Form of Vitesse Voting Agreement (filed with Lucero Arrangement Agreement)
Incorporated by reference to Exhibit 2.1 to Form 8-K filed December 19, 2024, File No. 0001-41546
10.16*
Limited Consent and Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of March 7, 2025, among Vitesse Energy, Inc., as borrower, the guarantors party thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
Incorporated by reference to Exhibit 10.1 to Form 8-K filed March 11, 20-25, File No. 0001-41546
19 Vitesse Energy Inc. Insider Trading Policy
Filed herewith.
21.1 List of Subsidiaries
Filed herewith.
23.1 Consent of Deloitte & Touche LLP
Filed herewith.
23.2 Consent of Cawley, Gillespie & Associates
Filed herewith.
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)
Filed herewith.
97.1 Vitesse Energy, Inc. Incentive-Based Compensation Recoupment Policy, adopted as of October 31, 2023.
Incorporated by reference to Exhibit 97.1 to Form 10-K filed February 26, 2024, File No. 001-41456
99.1 Report of Cawley, Gillespie & Associates as of December 31, 2024
Filed herewith.
† Compensatory plan or arrangement.
* Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant undertakes to furnish supplemental copies of any of the omitted schedules upon request by the Securities and Exchange Commission.