Vitesse Energy Inc

Previous wording

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.

Current wording

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.

Previous wording

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

Current wording

■Paid $63.6 million in dividends to our equity holders.

Previous wording

■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.

Current wording

■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.

Previous wording

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.

Current wording

See Non-GAAP Financial Information for additional information about PV-10.

Previous wording

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

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

Impairment expense. Under the successful efforts method of accounting, we review our oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and natural gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering, processing and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and natural gas properties in each depletion pool to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the aggregated oil and natural gas properties, no impairment is recorded. If the carrying amount of the oil and natural gas properties exceeds the undiscounted future net cash flows, we will record an impairment expense to reduce the carrying value to fair value as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows. There were no proved oil and gas property impairments during the years ended December 31, 2024, 2023 and 2022.

Previous wording

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.

Current wording

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.

Previous wording

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

Current wording

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

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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 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.

Current wording

The decreases in realized oil and natural gas prices were primarily due to lower benchmark commodity prices in the year ended December 31, 2024 as compared to the year ended December 31, 2023, as well as increased differentials. Our oil price differential to the weighted average benchmark price during the year ended December 31, 2024 was negative $5.90 per Bbl, as compared to a negative $4.19 per Bbl during the year ended December 31, 2023, primarily due to less favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2024 was $1.34 per Mcf, representing a 62% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $1.88 per Mcf during the year ended December 31, 2023, representing a 74% realization relative to the weighted average NYMEX natural gas price. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

(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.

Current wording

(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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

At December 31, 2024, we had a working capital deficit of $49.4 million, compared to a deficit of $2.1 million at December 31, 2023. Current assets decreased by $7.4 million while current liabilities increased by $39.9 million at December 31, 2024, compared to December 31, 2023. The decrease in current assets in 2024 as compared to 2023 was due to a decrease of $6.2 million in our commodity derivative instruments due to forward oil price decreases as compared to hedged oil prices, and a decrease of $5.1 million in revenue receivable primarily due to lower oil and natural gas revenue in the fourth quarter, partially offset by an increase in our cash balance of $2.4 million and an increase in other receivables of $1.5 million primarily related to prepayments and a higher receivable from commodity derivative instruments. The increase in current liabilities in 2024 as compared to 2023 was primarily due to an increase of $39.8 million in accounts payable and accrued liabilities as a result of increased development activity.

Previous wording

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:

Current wording

Cash Flows. Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below:

Previous wording

$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.

Current wording

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.

Previous wording

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.

Current wording

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.

Previous wording

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.

Current wording

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.