Vitesse Energy, Inc. (VTS)

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

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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

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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.

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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.

(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.

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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.

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

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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.

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

(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

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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:

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.

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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.

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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.

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

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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.

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

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

Executive Overview

Our business strategy is focused on creating long-term stockholder value through the profitable acquisition, development and production of oil and natural gas assets at attractive rates of return, while maintaining a strong balance sheet and distributing a meaningful dividend to our stockholders. We invest in non-operated minority working and mineral interests in oil and natural gas properties with our core area of focus in the Williston Basin of North Dakota and Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of December 31, 2023, we had a working interest in 5,734 gross (157.5 net) productive wells and 224 gross (6.7 net) wells that were being drilled or completed, and an additional 363 gross (9.9 net) wells that had been permitted for development by our operators. Our estimated proved reserves as of December 31, 2023 were 40,595 MBoe (68% oil) and our average production was 11,889 Boe per day during the year ended December 31, 2023.

Our financial and operating performance for the year ended December 31, 2023 included the following:

■Total revenue of $233.9 million.

■Cash flows from operations of $141.9 million.

■Net loss of $19.7 million.

■Proved reserves of 40.6 MMBoe and $682.1 million PV-10 value at December 31, 2023, as estimated by our third-party reserve engineers using SEC guidelines.

■Total debt of $81.0 million at December 31, 2023.

■Paid $58.0 million in dividends to our equity holders.

See Part II. Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Information for additional information about PV-10.

Industry Trends Impacting Our Business

Commodity prices are a significant factor impacting our acquisition and divestiture strategy, as well as the decisions of our operators in conducting their operations. Prices for oil and natural gas can be highly volatile. For instance, the COVID-19 pandemic and efforts to mitigate the spread of the disease, combined with OPEC actions in early 2020, led to spot and future prices of oil and natural gas falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Oil and gas operators responded by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells. Commodity prices, however, quickly reached pre-pandemic levels in the second half of 2021, and during 2022 increased further, in part as a result of the Russian invasion of Ukraine in combination with ongoing oil production limits from OPEC. In November 2023, certain members of OPEC and Russia and certain of its other allies (“OPEC+”) agreed to voluntary production/ export cuts of 2.2 million bpd for the first quarter of 2024 (subject to extension) from the 2024 required production levels. These voluntary cuts are in addition to (i) a production cut of 2 million bpd agreed to by the alliance in October 2022 and (ii) voluntary cuts by certain members of OPEC+ of 1.66 million bpd announced in April 2023 and subsequently extended through the end of 2024. In addition, while the impact of the ongoing conflicts between Russia and Ukraine and in the Middle East remain uncertain, these conflicts may have further global economic consequences, including disruptions of the global energy markets, inflation and supply chain constraints.

As a result of such commodity price volatility, which we expect to continue throughout 2024, 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 future planned repurchases (or additional possible releases) of oil from the strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC countries, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts (including invasion), civil unrest, pandemic or political uncertainty. Any of the foregoing can have a substantial impact on the prices of oil and natural gas, which in turn impacts the decision of our operators to drill and extract resources. Despite such commodity price volatility, we expect that our cash flow

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from operations and borrowing availability under our Revolving Credit Facility will allow us to meet our liquidity needs for the next twelve months.

Source of Our Revenues

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

Principal Components of Our Cost Structure

Commodity price differentials. The price differential between our 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.

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

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. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.

Depletion, depreciation, amortization, and accretion. Depletion, depreciation, amortization, and accretion (“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 2022 and 2023, general and administrative expenses included non-recurring costs related to the Spin-Off.

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

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

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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. Vitesse Energy, our Predecessor, was a limited liability company. Accordingly, no provision for income taxes was recorded, as the income, deductions, expenses, and credits of the Predecessor were reported on the income tax returns of it’s members.

Selected Factors That Affect Our Operating Results

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

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

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

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

■changes in the fair value of the derivative instruments;

■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. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, 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, 2023 was negative $4.19 per Bbl, as compared to a negative $3.39 per Bbl during the year ended December 31, 2022, 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, 2023 was $1.88 per Mcf, representing a 74% realization relative to average Henry Hub pricing, compared to a net realized natural gas price of $6.64 per Mcf during the year ended December 31, 2022, representing a 103% 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. Factors impacting the future oil supply balance include world-wide demand for oil, as well as the growth in domestic oil production.

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.

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(1)Based on a simple average of daily NYMEX closing prices.

The average calendar 2023 WTI oil price was $77.58 per Bbl or 18% lower than the average WTI price per Bbl in calendar 2022. Our settled derivatives increased our realized oil price per Bbl by $0.40 in calendar 2023 and decreased our realized oil price per Bbl by $18.07 in calendar 2022. Our average 2023 realized oil price per Bbl after reflecting settled derivatives was $73.99 compared to $72.66 in 2022. The average calendar 2023 NYMEX natural gas price was $2.53 per MMBtu, or 61% lower than the average NYMEX price per MMBtu in calendar 2022. We had no gas price derivatives in place in calendar 2023 and our settled derivatives decreased our realized natural gas price per Mcf by $0.08 in 2022. Our 2023 realized natural gas price per Mcf after reflecting settled derivatives was $1.88 compared to $6.56 in 2022, which was primarily driven by lower NYMEX pricing for natural gas and gas realization.

We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk and 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

Change in Estimate that is Inseparable from a Change in Accounting Principle

Effective January 1, 2023, the Company changed its method of recording gathering and transportation (“GT”) costs. Under the current method, GT costs are presented as a deduction to oil and gas revenue, following how these items are reported to us by operators. Prior to January 1, 2023, under our previous method, we determined the GT costs that were reported within production expense versus revenue deductions based on our best estimates using information from all our operators in aggregate. Although the change does not have a material impact to the financial statements the change in methodology has been applied on a retrospective basis to the prior periods presented in order to conform to the current period presentation. This change results in a reclassification within the statements of operations and has no balance sheet impact, nor does it impact net income, operating income, the gross margin we generate from our interests in oil and gas properties, or cash flows for any period.

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Year Ended December 31, 2023 Compared with Year Ended December 31, 2022

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

*Not meaningful

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue decreased to $233.9 million for the year ended December 31, 2023 from $281.9 million for the year ended December 31, 2022. The decrease in oil and natural gas revenue was due to a 28% decrease in the average realized prices per Boe before hedging, and was partially offset by a 15% increase in production volumes for the year ended December 31, 2023. The decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $77.7 million, while the increase in production volumes increased oil and natural gas revenue by approximately $29.8 million.

The decreases in realized oil and natural gas prices were primarily due to lower benchmark commodity prices in the year ended December 31, 2023 as compared to the year ended December 31, 2022, as well as increased differentials. Our oil price differential to the weighted average benchmark price during the year ended December 31, 2023 was negative $4.19 per Bbl, as compared to a negative $3.39 per Bbl during the year ended December 31, 2022, 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, 2023 was $1.88 per Mcf, representing a 74% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $6.64 per Mcf during the year ended December 31, 2022, representing a 103% 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

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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.

Lease Operating Expense. Lease operating expense increased to $9.11 per Boe for the year ended December 31, 2023 from $8.22 per Boe for the year ended December 31, 2022. The increase per Boe for the year ended December 31, 2023 compared with the year ended December 31, 2022 was related to increased workover operations and higher service costs. The increased workover costs were responsible for approximately $0.48/Boe of the increase and should result in increased production when these wells return to production.

Production Tax Expense. Total production taxes decreased to $21.6 million for the year ended December 31, 2023 from $24.1 million for the year ended December 31, 2022, primarily due to the decrease in oil and gas revenue in 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 9.2% and 8.5% for the years ended December 31, 2023 and 2022, respectively. The increase in the production tax rate for the year ended December 31, 2023 was primarily due to a higher ratio of oil revenue to total revenue, since oil revenue is taxed at a higher rate than gas revenue.

General and Administrative Expense. General and administrative expense increased to $23.9 million for the year ended December 31, 2023 from $19.8 million for the year ended December 31, 2022. General and administrative expense on a per Boe basis increased to $5.52 for the year ended December 31, 2023 from $5.24 for the year ended December 31, 2022. Costs related to the Spin -Off are included in both periods. Excluding costs related to the Spin-Off, the per Boe rate for the years ended December 31, 2023 and 2022 would have been $3.94 and $3.15, respectively. The increase in general and administrative expense per Boe, excluding the Spin-Off costs, was primarily due to higher costs associated with being a public company.

DD&A. DD&A increased to $81.7 million for the year ended December 31, 2023 compared with $63.7 million for the year ended December 31, 2022. The increase of $18.0 million or 28% was the result of a 15% increase in production and a 12% increase in the DD&A rate for the year ended December 31, 2023 compared with the year ended December 31, 2022. The increase in production accounted for a $10.4 million increase in DD&A expense while the increase in the DD&A rate accounted for a $7.6 million increase in DD&A expense.

For the year ended December 31, 2023, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $18.68 per Boe compared with $16.71 per Boe for the year ended December 31, 2022. The increase in the depletion rate was driven by a combination of decreased oil and natural gas reserves related to the lower oil and natural gas prices and the impact of acquisitions in the year ended December 31, 2023.

Equity-based Compensation. The Company’s long-term incentive plan (“LTIP”) provides for the granting of various forms of equity-based awards, including restricted stock units, performance units, stock options, stock appreciation rights, restricted stock, cash awards and other stock-based awards to employees, directors and consultants of the Company. Through December 31, 2023, the Company granted 3,152,247 restricted stock units, net of forfeitures, to employees and directors at a weighted-average grant date fair value of $14.99 per share. For restricted stock units, the Company recognizes the grant date fair-value of stock-based compensation awards expected to vest over the requisite service period as stock-based compensation expense on a straight-line basis except when provisions are present that accelerate vesting. Retirement vesting provisions in some of the awards resulted in 1,863,000 restricted stock units being expensed upon award. Equity-based compensation expense was $32.2 million for the year ended December 31, 2023.

Unit-based compensation expense was previously recorded by our Predecessor for in-substance call options granted to the founding members of management which are classified as liabilities and recorded at estimated fair value at each period end. Unit-based compensation expense was also recognized for management incentive units granted to other employees which are classified as liabilities until the holder has borne the risk of unit ownership. Unit-based compensation expense was recorded as these units vested and expense or contra-expense was recognized as the estimated fair value of the liability changed with market conditions. Unit-based compensation contra-expense was $10.8 million for the year ended December 31, 2022.

Interest Expense. Interest expense increased to $5.3 million for the year ended December 31, 2023 from $4.2 million for the year ended December 31, 2022. The increase for the year ended December 31, 2023 was due to a higher SOFR interest rate in the year ended December 31, 2023 despite a lower average outstanding balance on our Revolving Credit Facility during the year ended December 31, 2023 compared to 2022. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve throughout 2022 and 2023.

Commodity Derivative Gain (Loss). The net commodity derivative gain was $12.5 million for the year ended December 31, 2023 compared with a loss of $30.8 million for the year ended December 31, 2022. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

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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.

(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the consolidated statements of operations included in this 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 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. In 2022, approximately 55% of our oil volumes and 6% of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $46.5 million and a realized loss on natural gas derivatives of $0.6 million after settlements.

At December 31, 2023, all of our derivative contracts were recorded at their fair value, which was a net asset of $11.1 million, an increase of $11.3 million from the $0.2 million net liability recorded as of December 31, 2022. The increase was due to changes to forward commodity prices relative to prices on our open commodity derivative contracts and new contracts entered into in the year ended December 31, 2023.

Income Tax Expense. We recorded income tax expense of $61.9 million for the year ended December 31, 2023 related to federal and state income taxes, including $44.1 million recorded at Spin-Off as discussed below. The provision for income taxes for the year ended December 31, 2023 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. No income tax expense was recorded for the year ended December 31, 2022 because the Predecessor was treated as a nontaxable partnership for income tax purposes for that period.

During the year ended December 31, 2023, 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.

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Change in Fiscal Year End

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

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

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

*Not meaningful

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $281.9 million for the year ended December 31, 2022 from $176.0 million for the year ended December 31, 2021. The increase in oil and natural gas revenue was due to a 53% increase in the average realized prices per Boe before hedging, along with a 4% increase in production volumes for the year ended December 31, 2022. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by approximately $93.9 million, while the increase in production volumes increased oil and natural gas revenue by approximately $12.0 million.

Our oil price differential to the weighted average WTI benchmark price during the year ended December 31, 2022 was negative $3.39 per Bbl as compared to a negative $6.11 per Bbl during the year ended December 31, 2021, primarily due to favorable local market pricing as compared to the weighted average benchmark price. Our net realized natural gas price during the year ended December 31, 2022 was $6.56 per Mcf, representing a 103% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $3.34 per Mcf during the year ended December 31, 2021, representing a 92% realization relative to weighted average NYMEX natural gas price. Fluctuations in our price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, 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.

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Lease Operating Expense. Lease operating expense increased to $8.22 per Boe for the year ended December 31, 2022 from $7.49 per Boe for the year ended December 31, 2021. The increase per Boe for the year ended December 31, 2022 compared with the year ended December 31, 2021 was primarily related to higher expense related to workovers and inflationary pressure on service costs. The increased workover costs were responsible for approximately $0.60/Boe of the increase.

Production Tax Expense. Total production taxes increased to $24.1 million for the year ended December 31, 2022 from $15.0 million for the year ended December 31, 2021. Production taxes are primarily based on oil revenue and gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 8.5% for both years ended December 31, 2022 and 2021.

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

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

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

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

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

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

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

(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the consolidated statements of operations included in this 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 2022, approximately 55% of our oil volumes and 6% of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $46.5 million and a realized loss on natural gas derivatives of $0.6 million after settlements. In 2021, approximately 47% of our oil volumes and 11% of our natural gas volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $16.1 million and a realized loss on natural gas derivatives of $0.8 million after settlements.

Liquidity and Capital Resources

Overview. At December 31, 2023, we had $0.6 million of unrestricted cash on hand and $164.0 million available under our borrowing base. At December 31, 2022, we had $10.0 million of unrestricted cash on hand and $152.0 million available under our borrowing base in our Prior Revolving Credit Facility. 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 that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements for the next twelve months, as described below, including our planned capital expenditures program, as well as dividends and our share repurchase program. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings under our Revolving Credit Facility or the issuance of equity or debt. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and dividend payments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of revenue receivables, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments. Excess liquidity was retained at December 31, 2022 in anticipation of fees related to the Spin-Off that were paid in early 2023.

At December 31, 2023, we had a working capital deficit of $2.1 million, compared to a surplus of $17.7 million at December 31, 2022. Current assets increased by $4.0 million while current liabilities increased by $23.7 million at December 31, 2023, compared to December 31, 2022. The increase in current assets in 2023 as compared to 2022 was primarily due to an increase of $7.9 million in our commodity derivative instruments due to forward oil price decreases and more advantageous hedge instruments in place at December 31, 2023, and an increase of $3.5 million in revenue receivable primarily due to higher oil and natural gas revenue in the fourth quarter, partially offset by a decreased cash balance of $9.5 million. The change in current liabilities in 2023 as compared to 2022 was primarily due to an increase of $27.1 million in accounts payable and accrued liabilities as a result of increased development activity offset by a decrease of $3.4 million in derivative instrument liabilities as a result of forward oil price decreases and more advantageous hedge instruments in place at December 31, 2023.

Cash Flows. Our cash flows for the years ended December 31, 2023, December 31, 2022 and November 30, 2021 and the month ended December 31, 2021 are presented below:

During the year ended December 31, 2023, we generated $141.9 million of cash from operations, a decrease of 3% from the year ended December 31, 2022 despite a 17% decrease in total revenue. During the year ended December 31, 2022, we generated

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$147.0 million of cash from operating activities, an increase of $60.1 million from the year ended November 30, 2021. 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, 2023, we had oil swaps covering 1,374,998 Bbls at a weighted average price of $78.95 per Bbl for calendar 2024 and oil swaps covering the sale of 180,000 Bbls at a weighted average price of $75.30 per Bbl for calendar 2025. As of December 31, 2023, 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, 2023 and 2022 was $120.7 million and $84.6 million, respectively, as compared to $43.3 million during the year ended November 30, 2021 and $4.0 million during the month ended December 31, 2021. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. The reduced level of cash used in investing activities in 2021 was primarily attributable to reduced development activity by our operators due to the COVID-19 pandemic, while increased activity during the years ended December 31, 2023 and December 31, 2022 represent a recovery from these same factors. 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 $35.7 million, $28.5 million and $6.2 million during the fiscal years ended December 31, 2023, December 31, 2022, and November 30, 2021, respectively, and $0.1 million in the month ended December 31, 2021.

Cash used in financing activities was $30.7 million, $57.8 million, and $42.6 million during the fiscal years ended December 31, 2023, December 31, 2022, and November 30, 2021, respectively, and $6.0 million during the month ended December 31, 2021. The cash used in financing activities during the fiscal years ended December 31, 2022 and November 30, 2021 was related to $20.0 million and $30.5 million, respectively, of net repayments under our Prior Revolving Credit Facility as compared to net borrowings of $28.0 million during the fiscal year ended December 31, 2023 under our Revolving Credit Facility. Additionally, we paid distributions to our equity holders of $58.0 million, $36.0 million and $12.0 million during the fiscal years ended December 31, 2023, December 31, 2022, November 30, 2021, respectively, and $6.0 million during the month ended December 31, 2021.

Prior Revolving Credit Facility. See Notes to the Consolidated Financial Statements —Note 5—Credit Facility for further details regarding the Prior Revolving Credit Facility.

Revolving Credit Facility. In connection with the Spin-Off, we entered into the secured Revolving Credit Facility. The Revolving Credit Facility amends and restates the Prior Revolving Credit Facility.

The Predecessor, as predecessor borrower under the Prior Revolving Credit Facility, assigned the liens and its existing rights, liabilities and obligations under the Prior Revolving Credit Facility to Vitesse. Vitesse then entered into the 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 April 29, 2026.

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, 2023, the Company’s borrowing base was $245.0 million with an aggregate elected commitment of $180.0 million of which $81.0 million was outstanding. On January 17, 2024, the Company increased the elected commitments to

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$210 million and added a fifth lender to the syndicate of banks. See Notes to Consolidated Financial Statements—Note 5—Credit Facility for further details regarding the 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, 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, 2023, 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 $58.0 million during the year ended December 31, 2023. While we believe that our future cash flows from operations will be able to sustain the current 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, 2023 total capital expenditures was $120.5 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. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity including issuing equity or debt securities and extending maturities. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline or we are otherwise unable to access capital or liquidity. Reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected financial returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, change in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see Part 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, which we have seen in 2023 and 2022 compared to 2021. 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

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personnel. Despite these effects of inflation and pricing, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

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, 2023 to the Standardized Measure.

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 30% 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.

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External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements for the year ended December 31, 2023, 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, 2023, December 31, 2022, and November 30, 2021 and the month ended December 31, 2021 we did not record any impairment expense.

Equity-Based Compensation

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

Previous grants of 180,875 RSUs were forfeited during the year ended December 31, 2023. In January 2024, 792,000 restricted stock units vested with the Company retaining 332,840 of the vested shares to fund employee tax withholding of $6.9 million with the retained shares subsequently retired by the Company.

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

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

Executive Overview

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

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

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

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

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

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

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

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

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

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

Industry Trends Impacting Our Business

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

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

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

Source of Our Revenues

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

Principal Components of Our Cost Structure

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

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

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

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

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

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

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

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

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

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

Selected Factors That Affect Our Operating Results

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

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

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

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

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

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

■the level of our operating expenses.

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

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

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

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

Market Conditions

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

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

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

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(1)Based on average daily NYMEX closing prices.

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

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

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Change in Fiscal Year End

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

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Results of Operations

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

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

*Not meaningful

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

*Not meaningful

Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $185.2 million for the year ended November 30, 2021 from $97.2 million for the year ended November 30, 2020. The increase in oil and natural gas revenue was due to an 86% increase in the average realized prices per Boe before hedging, along with a 2% increase in production volumes for the year ended November 30, 2021. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by approximately $83.9 million, while the increase in production volumes increased oil and natural gas revenue by approximately $4.0 million.

Our oil price differential to the WTI benchmark price during the year ended November 30, 2021 was $3.58 per barrel, as compared to $5.88 per barrel during the year ended November 30, 2020. Our net realized natural gas price during the year ended November 30, 2021 was $4.72 per Mcf, representing a 129% realization relative to average NYMEX pricing, compared to a net realized natural gas price of $1.01 per Mcf during the year ended November 30, 2020, representing a 50% realization relative to

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average NYMEX pricing. Fluctuations in our price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators pass through these costs in a different manner. Some operators may deduct these costs directly from our revenues while other operators may invoice them directly to us as lease operating expenses.

Production Expense. Production expense increased to $12.15 per Boe for the year ended November 30, 2021 from $11.81 per Boe for the year ended November 30, 2020. The slight increase per Boe for the year ended November 30, 2021 compared with the year ended November 30, 2020 was primarily related to higher expense related to workovers and higher costs related to added natural gas gathering and processing infrastructure due to increased regulation regarding capturing natural gas.

Production Tax Expense. Total production taxes increased to $14.5 million for the year ended November 30, 2021 from $9.2 million for the year ended November 30, 2020. Production taxes are primarily based on oil revenue and gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 7.9% and 9.4% for the years ended November 30, 2021 and 2020, respectively. The decrease in the production tax rate for the year ended November 30, 2021 was due to a larger percentage of our revenue during that period coming from natural gas sales, which are taxed at a lower rate than oil sales in North Dakota.

General and Administrative Expense. General and administrative expense increased to $10.6 million for the year ended November 30, 2021 from $9.2 million for the year ended November 30, 2020. General and administrative expense on a per Boe basis increased slightly to $2.93 for the year ended November 30, 2021 from $2.60 for the year ended November 30, 2020. The increase in general and administrative expense on a per Boe basis was primarily related to employee costs, legal fees related to our litigation against one of our operators for withholding excessive deductions against our revenues and costs related to becoming a public entity.

DD&A. DD&A increased to $60.8 million for the year ended November 30, 2021 compared with $58.3 million for the year ended November 30, 2020. The increase of $2.5 million was the result of a 2% increase in production and a 2% increase in the DD&A rate for the year ended November 30, 2021 compared with the year ended November 30, 2020. The increase in production accounted for a $1.3 million increase in DD&A expense while the increase in the DD&A rate accounted for a $1.2 million increase in DD&A expense.

For the year ended November 30, 2021, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $16.84 per Boe compared with $16.50 per Boe for the year ended November 30, 2020. The slight increase in the depletion rate of 2% was the result of end-of-period undeveloped reserve adjustments for the year ended November 30, 2021.

Unit-based Compensation. Unit-based compensation expense is recorded for in-substance call options granted to the founding members of management which are classified as liabilities and recorded at estimated fair value at each period end. Unit-based compensation expense is also recognized for management incentive units granted to other employees which are classified as liabilities until the holder has borne the risk of unit ownership. Unit-based compensation expense is recorded as these units vest and expense or contra-expense is recognized as the estimated fair value of the liability changes with market conditions. Unit-based compensation expense increased to $1.4 million for the year ended November 30, 2021 from negative $0.5 million for the year ended November 30, 2020 primarily due to increased oil and gas prices causing the estimated fair value of the liabilities to increase.

Interest Expense. Interest expense decreased to $3.2 million for the year ended November 30, 2021 from $4.7 million for the year ended November 30, 2020. The decrease for the year ended November 30, 2021 was due to a lower balance on our Prior Revolving Credit Facility as we reduced the outstanding debt balance from $98.5 million at November 30, 2020 to $68.0 million at November 30, 2021.

Commodity Derivative Gain (Loss). Commodity derivative loss was $32.6 million for the year ended November 30, 2021 compared with a gain of $29.6 million for the year ended November 30, 2020. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.

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

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

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

In 2021, approximately 46% of our oil volumes and 8% of our natural gas volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $13.1 million and a realized loss on natural gas derivatives of $0.8 million after settlements. In 2020, approximately 65% of our oil volumes and 0% of our natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $27.2 million.

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Month Ended December 31, 2021

On November 30, 2021, the Board of Managers approved a change in the Company's fiscal year end from November 30 to December 31. The Company's 2022 fiscal year began on January 1, 2022 and ended on December 31, 2022. As a result of this change, the Company has included financial statements as of and for the Transition Period in this form 10-K. The Transition Period's results were included in the comparative analyses presented above and a comparison to the month ended December 31, 2022 was not considered meaningful or necessary by management as there were no significant changes, acquisitions or divestitures that occurred during the one-month period.

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

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

Liquidity and Capital Resources

Overview. At December 31, 2022, we had $10.0 million of unrestricted cash on hand and $48.0 million of long-term debt. At December 31, 2021, we had $5.4 million of unrestricted cash on hand and $68.0 million of long-term debt, while at November 30, 2021, we had $2.8 million of unrestricted cash on hand and $68.0 million of long-term debt. 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 that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements, as described below, including our planned capital expenditures program, as well as distributions to our equity holders. 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. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of receivables, capital expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments. Excess liquidity was retained at December 31, 2022 in anticipation of fees related to the Spin-Off that were paid in early 2023.

At December 31, 2022, we had a working capital surplus of $17.7 million, compared to a deficit of $4.2 million at December 31, 2021. Current assets increased by $18.2 million while current liabilities decreased by $3.7 million at December 31, 2022, compared to December 31, 2021. The increase in current assets in 2022 as compared to 2021 was primarily due to an increase of $10.8 million in revenue receivable primarily due to higher oil and natural gas revenue, an increased cash balance of $4.7 million and an increase of $2.1 million in our commodity derivative instruments due to the change in fair value as a result of more advantageous hedge instruments in place at December 31, 2022. The change in current liabilities in 2022 as compared to 2021 was primarily due to an increase of $9.5 million in accounts payable and accrued liabilities primarily as a result of increased development activity offset by an decrease of $13.0 million in derivative instrument liabilities as a result of forward oil price decreases and more advantageous hedge instruments in place at December 31, 2022 .

Cash Flows. Our cash flows for the fiscal years ended December 31, 2022, November 30, 2021 and November 30, 2020 and the Transition Period are presented below:

During the year ended December 31, 2022, we generated $147.0 million of cash from operations, a 69% increase from the year ended November 30, 2021. During the year ended November 30, 2021, we generated $87.0 million of cash from operating

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activities, an increase of $10.7 million from the year ended November 30, 2020. 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 Prior Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil and gas production for the next 12 to 24 months. 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 are required by certain debt covenants to partially mitigate through the use of commodity derivative contracts. As of December 31, 2022, we had oil swaps covering 1,340,000 Bbls at a weighted average price of $78.14 per Bbl for calendar 2023 and oil swaps covering the sale of 660,000 Bbls at a weighted average price of $75.97 per Bbl for calendar 2024. As of December 31, 2022, we had no natural gas derivative contracts. For more information on our outstanding derivatives, see Note 6 (“Derivative Instruments”) to the Audited Consolidated Financial Statements.

Cash used in investing activities during the year ended December 31, 2022 was $84.6 million. Cash used in investing activities during the year ended November 30, 2021 was $43.3 million, compared to $70.8 million during the year ended November 30, 2020, and primarily related to capital expenditures for acquisition and development costs. The decreases in cash used in investing activities from 2020 to 2021 was primarily attributable to reduced development activity by our operators due to the COVID-19 pandemic, while increased activity during the year ended December 31, 2022 represent a recovery from these same factors. 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 acquisitions of near-term drilling opportunities when development activity by our operators on our existing properties lags behind our development objectives. Our cash spending for acquisition activities was $28.5 million, $6.2 million and $9.2 million during the fiscal years ended December 31, 2022, November 30, 2021, 2020, respectively, and $0.1 million in the month ended December 31, 2021.

Cash used in financing activities was $57.8 million, $42.6 million, and $5.5 million during the fiscal years ended December 31, 2022, November 30, 2021, and 2020, respectively, and $6.0 million during the month ended December 31, 2021. The cash used in financing activities during the fiscal years ended December 31, 2022, November 30, 2021, and 2020 was related to $20.0 million, $30.5 million and $5.5 million, respectively, of net repayments under our Prior Revolving Credit Facility. Additionally, we paid distributions to our equity holders of $36.0 million and $12.0 million during the fiscal years ended December 31, 2022 and November 30, 2021, respectively, and $6.0 million during the month ended December 31, 2021.

Prior Revolving Credit Facility. In May 2015, Vitesse Energy entered into a revolving credit facility with a syndicate of banks led by Wells Fargo Bank, N.A. (as Administrative Agent). In connection with the Spin-Off, the Revolving Credit Facility amended and restated the Prior Revolving Credit Facility. The Prior Revolving Credit Facility permits borrowing on a revolving credit basis with availability equal to least of (1) the current aggregate elected commitments of $170 million, (2) the current borrowing base of $200 million and (3) the maximum credit amount of $500 million. The aggregate elected commitments of the lenders under the Prior Revolving Credit Facility may be increased up to a maximum credit amount of $500 million, subject to the satisfaction of certain customary conditions, including the willingness of the existing lenders to increase their commitments or of new lenders to provide additional commitments. The borrowing base under the Prior Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of our proved oil and natural gas reserves, as determined by the lenders in their discretion. The borrowing base is subject to further adjustments for asset dispositions and liquidations of hedge agreements, among other things. As of December 31, 2022, under the Prior Revolving Credit Facility we had outstanding borrowings of $48.0 million and available borrowing capacity of $122.0 million. At our option, borrowings under the Prior 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 an applicable margin ranging from 1.75% to 2.75% with respect to Base Rate borrowings and 2.75% to 3.75% with respect to Term SOFR borrowings, in each case based on the percentage of the current commitments being utilized. The Prior Revolving Credit Facility is guaranteed by all of our subsidiaries and is collateralized by a first priority lien on substantially all assets of Vitesse Energy and its subsidiaries, including a first priority lien on properties representing a minimum of 85% of the proved reserve value of our oil and natural gas properties. See Note 5 (“Credit Facility”) to the Audited Consolidated Financial Statements for further details regarding the Prior Revolving Credit Facility.

Revolving Credit Facility. In connection with the Spin-Off, we entered into the secured Revolving Credit Facility. The Revolving Credit Facility amends and restates the Prior Revolving Credit Facility of Vitesse Energy.

Vitesse Energy, as predecessor borrower under the Prior Revolving Credit Facility, assigned the liens and Vitesse Energy’s existing rights, liabilities and obligations under the Prior Revolving Credit Facility to Vitesse. Vitesse then entered into the

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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 April 29, 2026. The Revolving Credit Facility will permit borrowing on a revolving credit basis with availability equal to the least of (1) the anticipated aggregate elected commitments of $170 million, (2) the borrowing base of $265 million and (3) the maximum credit amount of $500 million. We anticipate that the aggregate elected commitments of the lenders under the Revolving Credit Facility will allow increases up to a maximum credit amount of $500 million, subject to the satisfaction of certain customary conditions, including the willingness of the existing lenders to increase their commitments or of new lenders to provide additional commitments. Our borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of our proved oil and natural gas reserves, as determined by the lenders in their discretion. At our option, borrowings under the Revolving Credit Facility bear interest at a rate unchanged from the Prior Revolving Credit Facility, which is either an adjusted forward-looking term rate based on SOFR (“Term SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.50% or the 30-day Term SOFR rate plus 1.00%), plus an applicable margin expected to range from 1.75% to 2.75% with respect to Base Rate borrowings and 2.75% to 3.75% with respect to Term SOFR borrowings, in each case based on the current commitment utilization percentage. Consistent with the Prior Revolving Credit Facility, the Revolving Credit Facility is guaranteed by all of our subsidiaries and is collateralized by a first priority lien on substantially all assets of Vitesse and its subsidiaries, including a first priority lien on properties representing a minimum of 85% of the total present value of our proved oil and natural gas properties.

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

Under the New Credit Agreement, we are permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) our total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500 million, (2) our then-effective borrowing base, and (3) the then-effective aggregate amount of the aggregate elected commitments and (b) as of the date of such distribution, the EBITDAX Ratio does not exceed 1.50 to 1.00. If our EBITDAX Ratio does not exceed 2.25 to 1.00, and if our total outstanding credit usage does not exceed 80% of the Commitments, we may also make distributions if our free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and we have delivered a certificate to our lenders attesting to the foregoing.

The New Credit Agreement contains covenants requiring us to maintain the following financial ratios tested on a quarterly basis: (1) a consolidated Total Funded Debt to consolidated EBITDAX ratio (in each case, as defined in the New Credit Agreement) of not greater than 3.0 to 1.0; and (2) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. These financial covenants are consistent with the Prior Revolving Credit Facility. The New Credit Agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change in control. If an event of default exists under the New Credit Agreement, the lenders will be able to terminate the lending commitments, accelerate the maturity of the Credit Agreement and exercise other rights and remedies with respect to the collateral.

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 anticipated repayment of outstanding borrowings and interest payment obligations under our Prior Revolving Credit Facility, 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 Prior Revolving Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. We cannot provide specific timing for other current and long-term liability obligations where we cannot forecast with certainty the amount and timing of such payments, including asset retirement obligations, as the plugging and abandonment of wells is at the discretion of the operators and any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. See Note 4 (“Fair Value Measurements”) to the Audited Consolidated Financial Statements set forth in the section entitled “Index to Financial Statements” for further information on these contracts and their fair values as of December 31, 2022, which fair values represent

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the estimated cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date.

Distributions. We paid cash distributions to our equity holders of $36.0 million and $12.0 million during the fiscal years ended December 31, 2022 and November 30, 2021, respectively, and $6.0 million during the month ended December 31, 2021. While we believe that our future cash flows from operations can sustain the current level of distributions, future distributions 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 distributions to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will make distributions or otherwise return capital to our investors in the future.

Capital Expenditures. For the year ended December 31, 2022 total capital expenditures was $84.6 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. 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. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.

The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected financial returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, change in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see Part II. Item 7A Quantitative and Qualitative Disclosures About Market Risk.

Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline. Because production from existing oil and natural gas wells declines over time, 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. Also, our obligations may change due to acquisitions, divestitures and continued growth. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. If internally generated cash flow and borrowing capacity is not available under our Revolving Credit Facility, we may issue equity or debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

Effects of Inflation and Pricing. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme 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, which we expect to occur in 2023 compared to 2022. 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 current 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

We include financial information prepared in accordance with accounting principles generally accepted in the United States, which we refer to as “GAAP,” as well as the non-GAAP financial measures Net Debt, which we use as a measure of liquidity, and Adjusted EBITDA and PV-10 which we use as measures of our operational performance. Non-GAAP measures, such as Net Debt, Adjusted EBITDA, and PV-10, should not be viewed as a supplement to nor a substitute for net income (loss) or any other performance measure calculated in accordance with GAAP or as a measure of our profitability or liquidity. As a result of the adjustments made in calculating Net Debt, Adjusted EBITDA,and PV-10 , there are significant limitations to using such measures as measures of performance or liquidity, as applicable, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income (loss). Such non-GAAP measures are not necessarily comparable to similarly titled measures reported by other companies.

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Reconciliations of Net Debt and Adjusted EBITDA to Most Directly Comparable GAAP Measures

Net Debt is calculated by deducting cash on hand from the amount outstanding on our Prior Revolving Credit Facility as of the balance sheet or measurement date. We believe Net Debt is meaningful to investors because it is frequently used by analysts, investors and other interested parties in our industry to evaluate a company’s debt position in relation to cash relative to its peers and competitors as a point in time measurement relative to other liquidity-based metrics.

Adjusted EBITDA is defined as net income before expenses for interest, income taxes, depletion, depreciation, amortization and accretion, and excludes non-cash gains and losses on unsettled derivative instruments and non-cash unit-based compensation in addition to certain items we consider non-routine in nature, including non-cash oil and natural gas property impairments and material non-recurring general and administrative costs related to the Spin-Off. We believe Adjusted EBITDA is useful to us and external users of our financial statements in understanding our operating results and the ongoing performance of our underlying business because it allows our management and investors to compare our operating performance on a consistent basis across periods and against our peers, since it removes or adjusts for the impact of, among other things, the impact of our capital structure, non-cash gains and losses on unsettled derivative instruments, non-cash unit-based compensation and the non-routine charges noted in the table below. We also use Adjusted EBITDA as a basis for strategic planning and forecasting.

(1) Our Adjusted EBITDA calculation excludes certain items we consider non-routine and non-recurring. In 2020, adjustments for non-routine items were comprised of a $13.2 million impairment charge to our Colorado and Wyoming properties because of the significant decline in oil and natural gas prices as a result of the COVID-19 pandemic. During the twelve months ended December 31, 2022, adjustments for non-routine items were composed of a $7.9 million of costs related to the Spin-Off.

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 2022 to the Standardized Measure.

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

(2) Future income taxes for Vitesse as of December 31, 2022 were zero due to Vitesse Energy's tax status as a pass-through entity.

(3) Vitesse’s PV-10 has historically been computed on the same basis as our Standardized Measure because it did not include a provision for future income taxes. Our calculation of PV-10 for annual periods following the Spin-Off will be adjusted upward for estimated future income tax expense, computed by applying the then applicable year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

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 “Supplemental Oil and Gas Information (Unaudited)” in the notes to the Audited Consolidated Financial Statements in the section entitled “Index to Financial Statements."

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 38% 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, 2022, 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

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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, 2022 and November 30, 2021 and for the Transition Period, we did not record any impairment expense. For the year ended November 30, 2020, we recorded a $13.2 million impairment expense.

Unit-based Compensation

We account for unit-based compensation under accounting guidance related to share-based compensation, whereby the awards are recognized as liabilities, with changes in the estimated value of the awards recorded in earnings. For certain management incentive units, once the holders have borne the risk of unit ownership, the liability associated with those certain management incentive units is reclassified to temporary equity, and changes in the estimated fair value is recorded as an adjustment to members’ equity.

The fair value determination for unit-based compensation requires the use of highly subjective assumptions, including the market value of Vitesse, expected volatility, and expected term, among others. Changes in these inputs and assumptions can materially affect the measure of estimated fair value, which in turn can materially affect the amount of unit-based compensation expense (or reduction to expense) that we recognize in a given period. These assumptions are highly subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience. As we were a private entity whose units were not publicly traded before the Spin-Off, we considered the average volatility of comparable entities to develop an estimate of expected volatility which resulted in a reasonable estimate of fair value. Our estimate of the fair value of Vitesse is determined using estimates of discounted future cash flows, a market approach using multiples for publicly traded comparable entities, and relevant precedent transactions, among other factors.

The appropriate weight to place on historical experience, as well as on each estimate of fair value using the applicable approach, is a matter of judgment, based on relevant facts and circumstances. The market value of Vitesse can vary significantly based on changes in the market value of oil and natural gas prices. Variances in these factors can materially affect unit-based compensation expense in the periods presented. Additionally, changes in various assumptions may impact the fair value of unit-based compensation in different directions which may be material.

Recently Issued or Adopted Accounting Pronouncements

For discussion of recently issued or adopted accounting pronouncements, see Note 2 (“Significant Accounting Policies”) to the Audited Consolidated Financial Statements set forth in the section entitled “Index to Financial Statements.”

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.