Vitesse Energy, Inc.
For the period ended Dec 31, 2025. Filed Mar 2, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 2, 2026
VTS$14.78-1.5%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-03-12.
0001944558-25-000033
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-02.
0001944558-26-000009
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 112 previous paragraphs and 110 current paragraphs.
54 unchanged; 41 reworded; 15 added; 15 removed; 2 previous and 0 current paragraphs rearranged.
Tables are not compared: 5 previous and 5 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (15)
Current report
Unless otherwise indicated, the financial, reserve and operational information presented does not reflect the Lucero Acquisition for periods prior to March 7, 2025.
Current report
■Total revenue of $274.0 million.
Current report
■Net income of $25.3 million.
Current report
■Cash flows from operations of $170.3 million.
Current report
■the realized gains and losses on our derivative instruments;
Current report
*Not meaningful
Current report
General and Administrative Expense. General and administrative expense increased to $24.3 million for the year ended December 31, 2025 from $23.5 million for the year ended December 31, 2024. During the year ended December 31, 2025, $7.1 million of litigation costs were reimbursed as a result of the settlement discussed in Note 11 (“Commitments and Contingencies”) to the Consolidated Financial Statements. Excluding net litigation costs and Lucero Acquisition transaction costs of $0.9 million and $2.2 million for the years ended December 31, 2025 and 2024, respectively, general and administrative expense on a per Boe basis decreased to $3.68 for the year ended December 31, 2025 from $4.47 for the year ended December 31, 2024. The decrease in per Boe cost is associated with economies of scale on a 34% increase in production between periods and impacts from the Lucero Acquisition.
Current report
Equity-based Compensation. During the year ended December 31, 2025, equity-based compensation expense increased to $10.2 million from $8.1 million during the year ended December 31, 2024. Equity-based compensation expense was higher in 2025 due to additional LTIP RSUs and PSUs awarded to employees and directors at a higher grant date price.
Current report
Cash used in financing activities was $44.3 million and $37.3 million during the years ended December 31, 2025 and 2024, respectively. The cash used in financing activities during the year ended December 31, 2025 was primarily related to $92.1 million in dividends paid and $9.2 million value of retained shares paid to fund employee tax withholding in connection with the vesting of restricted stock units, which was partially offset by $49.8 million in cash acquired associated with the Lucero Acquisition and $7.5 million of net borrowings under our Revolving Credit Facility. The cash used in financing activities during the year ended December 31, 2024 was primarily related to $63.6 million in dividends paid and $7.5 million value of retained shares paid to fund employee tax withholding in connection with the vesting of restricted stock units, which was partially offset by $36.0 million of net borrowings under our Revolving Credit Facility.
Current report
The borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of the Company’s proved oil and natural gas reserves, as determined by the lenders in their discretion. As of December 31, 2025, the Company’s borrowing base was $295.0 million with an aggregate elected commitment of $250.0 million of which $124.5 million was outstanding. See Note 5 (“Credit Facility”) to the Consolidated Financial Statements for further details regarding the Revolving Credit Facility.
Current report
Business Combinations
Current report
We account for business combinations using the acquisition method of accounting. Under this method, we recognize the identifiable assets acquired and liabilities assumed at their estimated acquisition-date fair values. Transaction and integration costs related to business combinations are expensed as incurred.
Current report
In valuing the assets acquired and liabilities assumed, we make various assumptions to estimate fair values. Fair value is a market-based measurement that reflects the assumptions market participants would use in pricing an asset or liability. For the Lucero Acquisition, the most significant assumptions related to the estimated fair value of the proved oil and gas properties. The fair value of these properties was determined using the income approach, which is based on discounted future net cash flows derived from the properties' reserve reports. The valuation relied primarily on unobservable inputs, which are classified as Level 3 within the fair value hierarchy under ASC 820. Key inputs included estimates of future production volumes from the proved reserves, future commodity prices based on forward strip price curves (adjusted for basis differentials), estimates of lease operating, development and abandonment costs, and the application of a discount rate.
Current report
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation as described. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Current report
A description of our significant accounting policies and fair value measurements is included in Note 2 (“Significant Accounting Policies”) and Note 4 (“Fair Value Measurements”), respectively, to the Consolidated Financial Statements.
Removed paragraphs (15)
Previous report
■Total revenue of $242.0 million.
Previous report
■Net income of $21.1 million.
Previous report
■Cash flows from operations of $155.0 million.
Previous report
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.
Previous report
■changes in the fair value of the derivative instruments;
Previous report
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 report
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.
Previous report
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 report
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.
Previous report
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.
Previous report
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.
Previous report
Prior Revolving Credit Facility. See Notes to the Consolidated Financial Statements —Note 5—Credit Facility for further details regarding the Prior Revolving Credit Facility.
Previous report
Predecessor Equity-Based Compensation
Previous report
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.
Previous report
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.
Reworded paragraphs (41)
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 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.
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 invest in working and mineral interests in oil and natural gas properties with our core area of focus currently in the Bakken and Three Forks formations of the Williston Basin of North Dakota and Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of December 31, 2025, we had a working interest in 6,402 gross (226.1 net) productive wells and 283 gross (6.1 net) wells that were being drilled or completed, and an additional 336 gross (15.9 net) wells that had been permitted for development by us or our operators. In addition, we had a royalty only interest in 1,301 gross (3.2 net) productive wells.
Previous wording
■Paid $63.6 million in dividends to our equity holders.
Current wording
■Paid $92.1 million in dividends to our equity holders.
Previous wording
■Production of 13,003 Boe/d with 69% of production from oil.
Current wording
■Production of 17,444 Boe/d with 65% of production from oil.
Previous wording
■Invested $115.2 million in capital development and acquisitions.
Current wording
■Invested $127.7 million in capital development and acquisitions.
Previous 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.
Current wording
■Proved reserves of 47.8 MMBoe and $473 million PV-10 value at December 31, 2025, as estimated by our third-party reserve engineers using SEC guidelines.
Previous wording
■Total debt of $117.0 million at December 31, 2024.
Current wording
■Total debt of $124.5 million at December 31, 2025.
Previous wording
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.
Current wording
On March 7, 2025, we closed the Lucero Acquisition pursuant to which we acquired Lucero in an all-stock transaction. Lucero shareholders received 8,169,368 shares of Vitesse common stock. 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.
Previous wording
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
Current wording
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 general economic and political conditions, the conflict between Russia and Ukraine, hostilities in the Middle East, the evolving situation in Venezuela, supply chain constraints, elevated interest rates and costs of capital, and changes in production by OPEC and its key member, Saudi Arabia, and certain other non-OPEC oil-producing countries.
Previous 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.
Current wording
As a result of such commodity price volatility, which we expect to continue throughout 2026, our earnings and operating cash flows can vary substantially. While we do hedge a substantial portion of our production, we are still significantly subject to movements in commodity prices. Such volatility can make it difficult to predict future effects on our financial results and the decisions of our operators. Factors that we expect will continue to impact commodity prices include product demand connected with global economic conditions, inflationary factors, industry production and inventory levels, the United States Department of Energy’s 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 and changes in tariffs and other controls on imports and exports and resulting consequences of such, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty, including a prolonged U.S. government shutdown. 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 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.
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 and natural gas production. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Previous 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.
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 natural 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.
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 2024 and 2023, general and administrative expenses included non-recurring costs related to the Lucero Acquisition and the Spin-Off, respectively.
Current wording
General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. For fiscal 2025, general and administrative expenses included non-recurring costs related to the Lucero Acquisition and an offset for reimbursement of past legal expenses as a result of the settlement discussed in Note 11 (“Commitments and Contingencies”) to the Consolidated Financial Statements.
Previous 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.
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 include the amortization of deferred financing costs, commitment fees and annual agency fees as interest expense.
Previous wording
■our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
Current wording
■our ability to continue to identify and acquire producing properties, high-quality acreage and drilling opportunities; and
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. 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.
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 conflict in Ukraine, hostilities in the Middle East, the evolving situation in Venezuela and the strength of the U.S. dollar can adversely impact oil prices.
Previous 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.
Current wording
The average calendar 2025 WTI oil price was $64.60 per Bbl or 15% lower than the average WTI price per Bbl in calendar 2024. Our settled derivatives increased our realized oil price per Bbl by $3.81 in calendar 2025 and increased our realized oil price per Bbl by $1.54 in calendar 2024. Our average 2025 realized oil price per Bbl after reflecting settled derivatives was $62.95 compared to $71.48 in 2024. The average calendar 2025 NYMEX natural gas price was $3.52 per MMBtu, or 61% higher than the average NYMEX price per MMBtu in calendar 2024. Our settled derivatives increased our realized gas price per Mcf by $0.10 in calendar 2025. We had no gas price derivatives in place in calendar 2024. Our 2025 realized natural gas price per Mcf after reflecting settled derivatives was $2.31 compared to $1.34 in 2024.
Previous 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.
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 Note 6 (“Derivative Instruments”) to Consolidated Financial Statements.
Previous 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.
Current wording
Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $274.0 million for the year ended December 31, 2025 from $242.0 million for the year ended December 31, 2024. The increase in oil and natural gas revenue was due to a 34% increase in production volumes, and was partially offset by a 15% decrease in the average realized prices per Boe before hedging for the year ended December 31, 2025. The increase in production volumes increased oil and natural gas revenue by approximately $69.2 million, while the decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $37.2 million. The increase in production volumes was in part due to the Lucero Acquisition.
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, 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.
Current wording
During the year ended December 31, 2025, $3.3 million and $13.6 million of recoupments of oil and gas revenue, respectively, were recognized as part of the settlement discussed in Note 11 (“Commitments and Contingencies”) to the Consolidated Financial Statements. Our oil price differential to the weighted average benchmark price during the year ended December 31, 2025 was negative $5.40 per Bbl, as compared to a negative $5.90 per Bbl during the year ended December 31, 2024, primarily due to the legal settlement increasing the realized price per Bbl in the period, partially offset by less favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2025 was $2.21 per Mcf, representing a 64% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $1.34 per Mcf during the year ended December 31, 2024, representing a 62% realization relative to the weighted average NYMEX natural gas price. The higher realized price was primarily due to the legal settlement increasing the realized price per Mcf in the period. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators passes through these costs in a different manner.
Previous 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.
Current wording
Lease Operating Expense. Lease operating expense increased to $10.92 per Boe for the year ended December 31, 2025 from $10.00 per Boe for the year ended December 31, 2024. The increase per Boe for the year ended December 31, 2025 compared with the year ended December 31, 2024 was due in part to a $1.10 per Boe increase in workover costs between periods, driven by the properties from the Lucero Acquisition.
Previous 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.
Current wording
Production Tax Expense. Total production taxes increased to $23.4 million for the year ended December 31, 2025 from $21.5 million for the year ended December 31, 2024. 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 8.5% and 8.9% for the years ended December 31, 2025 and 2024, 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
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.
Current wording
DD&A. DD&A increased to $129.4 million for the year ended December 31, 2025 compared with $100.3 million for the year ended December 31, 2024. The increase of $29.1 million or 29% was the result of a 34% increase in production and a 4% decrease in the DD&A rate for the year ended December 31, 2025 compared with the year ended December 31, 2024. The increase in production accounted for a $32.7 million increase in DD&A expense while the decrease in the DD&A rate accounted for a $3.6 million decrease in DD&A expense.
Previous 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.
Current wording
For the year ended December 31, 2025, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $20.16 per Boe compared with $20.92 per Boe for the year ended December 31, 2024. The lower DD&A rate was driven by the properties acquired in the Lucero Acquisition in 2025 and was partially offset by decreased oil and natural gas reserves related to the lower oil and natural gas prices combined with higher operating expenses.
Previous 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.
Current wording
Interest Expense. Interest expense increased to $10.2 million for the year ended December 31, 2025 from $10.0 million for the year ended December 31, 2024. The increase for the year ended December 31, 2025 was due to a higher average debt balance during the year ended December 31, 2025 compared to 2024 partially offset by a lower interest rate.
Previous 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.
Current wording
Commodity Derivative Gain (Loss). The net commodity derivative gain was $27.9 million for the year ended December 31, 2025 compared with a loss of $2.3 million for the year ended December 31, 2024. 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.
Previous 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.
Current wording
In 2025, approximately 61% of our oil volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $15.8 million. In 2025, approximately half of our natural gas volume was covered by residue gas and NGL financial hedges, which resulted in a realized gain on gas and NGL derivatives of $1.4 million. 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.
Previous 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.
Current wording
At December 31, 2025, all of our derivative contracts were recorded at their fair value, which was a net asset of $14.4 million, an increase of $10.7 million from the $3.7 million net asset recorded as of December 31, 2024. The increase was primarily due to decreases in forward commodity prices since December 31, 2024 relative to prices on our open commodity derivative contracts.
Previous 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.
Current wording
Income Tax Expense. We recorded income tax expense of $9.8 million and $7.7 million for the years ended December 31, 2025 and 2024, respectively, related to federal and state income taxes. The effective tax rates of 27.9% and 26.7% for the years ended December 31, 2025 and 2024, respectively, 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, state income taxes and non-amortizable transaction costs.
Previous 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.
Current wording
Overview. At December 31, 2025 and 2024, we had $1.3 million and $3.0 million of unrestricted cash on hand and $125.5 million and $118.0 million available under the elected commitments in 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, 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.
Current wording
Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of accrued revenue, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments.
Previous 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.
Current wording
At December 31, 2025, we had a working capital surplus of $0.9 million, compared to a deficit of $49.4 million at December 31, 2024. Current assets increased by $1.3 million while current liabilities decreased by $49.1 million at December 31, 2025, compared to December 31, 2024. The increase in current assets in 2025 as compared to 2024 was primarily due to an increase of $10.4 million in our commodity derivative instruments due to forward oil price decreases as compared to hedged oil prices, partially offset by a decrease of $9.2 million in accrued revenue driven by improved collections. The decrease in current liabilities in 2025 as compared to 2024 was primarily due to an decrease of $49.1 million in accounts payable and accrued liabilities as a result of decreased development activity.
Previous 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.
Current wording
During the year ended December 31, 2025, we generated $170.3 million of cash from operations, an increase of 10% from the year ended December 31, 2024 driven by a 13% increase in total revenue. Cash flows from operating activities are primarily affected by production volumes, which increased with the Lucero Acquisition, 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, 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.
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, 2025, for calendar 2026 we had oil swaps covering 1,608,134 Bbls at a weighted average price of $64.52 per Bbl, oil collars covering 66,000 Bbls with a weighted average floor and ceiling of $50.00 per Bbl and $68.80 per Bbl, respectively, natural gas collars covering 4,638,900 MMBtu with a weighted average floor and ceiling of $3.73 per MMBtu and $4.99 per MMBtu, respectively, natural gas basis swaps (Chicago City Gate to Henry Hub) covering the same MMBtu at a weighted average price of ($0.121) per MMBtu, and various natural gas liquid swaps covering 6,410,000 gallons at a weighted average price of $0.67 per gallon. For calendar 2027, we had natural gas collars covering 795,000 MMBtu with a weighted average floor and ceiling of $4.00 per MMBtu and $5.68 per MMBtu, respectively, and basis swaps (Chicago City Gate to Henry Hub) covering the same MMBtu at a weighted average price of $0.300 per MMBtu. For more information on our outstanding derivatives, see Note 6 (“Derivative Instruments”) to the Consolidated Financial Statements.
Previous 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.
Current wording
Cash used in investing activities during the years ended December 31, 2025 and 2024 was $127.7 million and $115.3 million, respectively. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. Development costs for the year ended December 31, 2025 included $11.0 million for completion costs on two wells from the Lucero Acquisition. 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 $6.6 million and $21.1 million during the years ended December 31, 2025 and 2024, respectively.
Previous wording
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.
Current wording
Material Cash Requirements. Our material short-term cash requirements include recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. If commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts. Conversely, working capital requirements would be expected to decrease if commodity prices decline.
Previous wording
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.
Current wording
Our long-term material cash requirements from currently known obligations include settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating lease obligations. We cannot provide specific timing for repayments of outstanding borrowings on our Revolving Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. We cannot provide specific timing for other current and long-term liability obligations where we cannot forecast with certainty the amount and timing of such payments, including asset retirement obligations, as the plugging and abandonment of wells is primarily at the discretion of the operators and any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. See Note 4 (“Fair Value Measurements”) to the Consolidated Financial Statements for further information on these contracts and their fair values as of December 31, 2025, 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.
Previous wording
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.
Current wording
Dividends. We paid cash dividends to our equity holders of $92.1 million during the year ended December 31, 2025. While we believe that our future cash flows from operations will be able to sustain future dividends, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations (the most common of which are limitations set forth in a company’s organizational documents and insolvency), business developments and the judgment of our Board. Future cash dividends to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will be able to pay dividends at current levels or at all or otherwise return capital to our investors in the future.
Previous wording
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.
Current wording
Capital Expenditures. For the year ended December 31, 2025 total capital expenditures was $127.7 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.
Previous wording
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.
Current wording
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.
Previous wording
The determination of depreciation, depletion and amortization expense as well as impairments that may be recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 32% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves. Our proved oil and gas reserve information was computed by applying the average first-day-of-the- month oil and gas price during the 12-month period ended on the balance sheet date.
Current wording
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 29% 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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Previous report — wording carried elsewhere
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.
Previous report — wording carried elsewhere
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.