HighPeak Energy, Inc.
For the period ended Dec 31, 2025. Filed Mar 11, 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 11, 2026
HPK$7.140.0%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 2025-03-10.
0001437749-25-006838
Item 7. Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-11.
0001437749-26-007770
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 94 previous paragraphs and 139 current paragraphs.
60 unchanged; 30 reworded; 48 added; 3 removed; 1 previous and 1 current paragraphs rearranged.
Tables are not compared: 27 previous and 36 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 (48)
Current report
The following discussion and analysis should be read in conjunction with the other sections of this Annual Report, including but not limited to“Items 1 and 2. Business and Properties—Regulation of the Crude Oil and Natural Gas Industry.”Historical financial statements and related notes included elsewhere in this Annual Report. This discussion contains“forward-looking statements”* reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward*-looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report. Please read Cautionary Statement Concerning Forward-Looking Statements. Also, please read the risk factors and other cautionary statements described under“Part I, Item 1A. Risk Factors.”* We assume no obligation to update any of these forward*-looking statements, except as required by applicable law. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on March 10, 2025 for a discussion of the Company’s 2024 results of operations compared with the Company’s 2023 results of operations.
Current report
Overview
Current report
HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019, is an independent crude oil and natural gas exploration and production company that explores for, develops and produces crude oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin. The Company’s assets are located primarily in Howard and Borden Counties, Texas, and to a lesser extent Scurry and Mitchell Counties, which lie within the northeastern part of the crude oil-rich Midland Basin. As of December 31, 2025, the assets consisted of two highly contiguous leasehold positions of approximately 154,472 gross (142,560 net) acres, approximately 72% of which were held by production, with an average working interest of 92%. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern portion of Howard County. We operate approximately 98% of the net acreage across the Company’s assets and more than 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the year ended December 31, 2025, approximately 85% and 15% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of December 31, 2025, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew and expects to average one (1) drilling rig and one (1) frac crew during 2026 under our current development plan, depending on certain market conditions.
Current report
Recent Events
Current report
Recent management ***changes.***In September 2025, Mr. Jack Hightower, the Company’s Chief Executive Officer and Chairman of the Board retired and resigned from our Board of Directors, and on November 4, 2025, our President, Mr. Michael Hollis, was named President and Chief Executive Officer.
Current report
Concurrent with these changes, Mr. Jack Hightower also retired from managing HighPeak Energy Partners, LP and HighPeak Energy Partners II, LP (collectively, the “HighPeak Funds”), which collectively own approximately 64% of the shares of common stock of the Company. In connection with Mr. Jack Hightower’s retirement, HighPeak Pure Acquisition, LLC (“Pure”), a wholly owned subsidiary of HighPeak Energy Partners, LP distributed 1,532,478 shares of common stock in full and complete redemption of Mr. Jack Hightower’s interest in Pure. Following Mr. Jack Hightower’s retirement, the HighPeak Funds are managed by a committee comprised of Mr. Hollis, Daniel Silver and William R. Hightower, each of whom also serve as President and Chief Executive Officer, Executive Vice President and Executive Vice President of the Company, respectively. In addition, pursuant to the Stockholder’s Agreement, dated August 21, 2020, the HighPeak Funds have designated Mr. Silver to serve as their board appointee under the Stockholder’s Agreement, and Mr. Silver was appointed to serve as a director of the Board effective immediately.
Current report
***Debt amendments and actions taken to bolster covenant compliance.***In August 2025, the Company entered into the First Term Loan Amendment and the Second Facility Amendment which amended the Term Loan Credit Agreement and the Senior Credit Facility Agreement whereby, among other things, (i) the maturity date was extended two years to September 2028, (ii) Term Loan Credit Agreement was upsized to $1.2 billion, providing additional liquidity, and (iii) the Term Loan Credit Agreement quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026.
Current report
Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company has entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourth Quarter of 2025 and the First Quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the Fourth Quarter of 2025 and the First Quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the Second Quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels currently in effect for such quarters prior to these amendments. It is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the Second Quarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. Any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder.
Current report
***Dividends and dividend equivalents.***In February, May, August and November 2025, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.0 million, $5.0 million, $5.0 million and $5.0 million, respectively, in dividends being paid on March 25, 2025, June 25, 2025, September 25, 2025 and December 23, 2025, respectively. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $531,000 in March 2025, $531,000 in June 2025, $531,000 in September 2025 and $502,000 in December 2025. In addition, the Company accrued an additional combined $86,000 in March 2025, $84,000 in June 2025, $31,000 in September 2025 and $3,000 in December 2025 in dividends on the restricted stock issued to directors, management directors and certain employees that was paid or will be payable upon vesting, assuming no forfeitures.
Current report
***Acquisitions.***During the year ended December 31, 2025, the Company incurred a total of $6.7 million in acquisition costs related to lease extensions and to acquire additional crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage to its Flat Top and Signal Peak operating areas.
Current report
***Crude Oil and Natural Gas Industry Considerations.***Our operating results, and those of the crude oil and natural gas industry as a whole, are heavily influenced by commodity prices. Crude oil, NGL and natural gas prices and basis differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term.
Current report
In early 2025, OPEC and its non-OPEC allies, known collectively as OPEC+, began unwinding prior voluntary production cuts and subsequent to quarter end announced that they agreed to increase oil production by another 548,000 bopd starting in September 2025, completing the reversal of its prior 2.2 million bopd cutback from 2023, but paused production increases in early 2026. This substantial supply boost contributed to a decline in global crude oil prices during the year ended December 31, 2025. OPEC+ also emphasized that the production increases could continue or be reversed depending on how market conditions evolve, maintaining flexibility to support price stability. Concurrently, the U.S. imposed tariffs on energy imports from Canada and Mexico, set at 10% and 25%, respectively, and expanded tariffs to include all steel and aluminum imports, aiming to bolster domestic production. In addition, the current U.S. presidential administration began announcing a substantial number of trade tariffs, including a new universal baseline reciprocal tariff, plus an additional country-specific reciprocal tariff for select trading partners, on all U.S. imports, although imports of crude oil, natural gas and refined products received exemptions from the tariffs. Furthermore, the administration announced additional sector-specific tariffs, including on copper imports. Although the Supreme Court recently invalidated the reciprocal tariffs, the administration has indicated that it will continue seeking to implement tariffs through other means, and concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed further downward pressure on oil prices. The situation remains fluid, with certain tariff rates and obligations established through trade agreements that were negotiated while the reciprocal tariffs were in effect, and we expect price volatility to continue. Collectively, these policy changes—OPEC+'s production increase and the U.S. tariffs—are introducing significant volatility to the crude oil and natural gas sector. In addition, tariffs have the potential to significantly increase our operating and capital costs, which could negatively impact our ability to carry out our planned drilling program and future growth projects.
Current report
In addition, since being sworn into office, President Trump has issued numerous Executive Orders that aim to increase crude oil production and decrease commodity prices. For example, President Trump declared a “national energy emergency” in January 2025, and gave the executive branch more power to expedite approvals for energy resource infrastructure (including crude oil and natural gas). Additionally, President Trump’s “Unleashing American Energy” Executive Order incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as crude oil and natural gas. More recently, in March 2025, President Trump signed an Executive Order that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices or our operations. These and other factors make it difficult to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings and maintain our hedging program. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized price.
Current report
Sanctions and import bans on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. As a result of crude oil and natural gas supply constraints, there have been significant increases in European energy costs, which have resulted in inflationary pressures throughout Europe, increasing prospects of recession in many countries throughout the continent. The ongoing war between Russia and Ukraine, conflicts in the Middle East, and U.S. intervention in Venezuela have resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by the tariffs and proposed tariffs by the current administration. Specifically, the Company’s 2023, 2024 and 2025 capital program has been and continues to be impacted by higher prices for steel, diesel, chemicals and services, among other items.
Current report
Global crude oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) general economic conditions and increasing expectations that the world may be heading into a global recession, (ii) the ability of OPEC+ and other crude oil producing nations to manage the global crude oil supply, (iii) the impact of sanctions and import bans on production from Russia and any resulting impact on production from conflicts in the Middle East and U.S. intervention in Venezuela, (iv) the timing and supply impact of any Iranian or Venezuelan sanction relief on their ability to export crude oil, (v) the global supply chain constraints associated with manufacturing and distribution delays, (vi) oilfield service demand and cost inflation, and (vii) political stability of crude oil consuming countries. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.
Current report
Outlook
Current report
HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend heavily on prevailing commodity prices. The crude oil and natural gas industry is cyclical and commodity prices are highly volatile and subject to a high degree of uncertainty. For example, during the period from January 1, 2021 through December 31, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35.
Current report
The markets for the commodities produced by our industry strengthened in 2021 continuing into 2023. However, they began declining in 2024 and continued to decline in 2025 and early 2026 due to concerns over trade wars and energy tariffs, among other factors, and has decreased from 2022 levels overall, as a result of increased supply outpacing increased demand for each of the commodities we produce. This decline in commodity prices through 2025 and into 2026 contributed to the Company's need to enter into amendments to its Term Loan Credit Agreement and Senior Credit Facility Agreement to address potential financial covenant compliance issues. There can be no assurance that commodity prices will improve sufficiently to enable the Company to comply with the financial covenants under its credit facilities when the required asset coverage ratio and total net leverage ratio levels reset to more stringent levels in the Second Quarter of 2026. There are many factors beyond the Company’s control, including commodity markets, unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services or supply constraints remain subject to heightened levels of uncertainty as a result of commodity-specific tariffs and the possibility of trade wars, the ongoing war between Russia and Ukraine, conflicts in the Middle East, U.S. intervention in Venezuela, and elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. For additional information on the risks, see “Part I. Item 1A. Risk Factors.”
Current report
Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a one (1) drilling rig program for 2026 depending on certain market conditions. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. If the Company is unable to maintain compliance with its financial covenants or obtain further amendments or waivers from its lenders, it may be required to reduce its capital expenditures, which could adversely impact its ability to develop its acreage, maintain its leasehold positions and grow its production. Despite continuing impacts of the factors listed above and future uncertainty, we are focused on maintaining our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.
Current report
Strategic Alternatives
Current report
On January 23, 2023, the Company announced the intention of its Board to initiate a process to evaluate certain strategic alternatives to maximize shareholder value, including a potential sale of the Company. Texas Capital Securities was retained as a financial advisor with respect to this strategic alternatives process. To date, however, this process has been exploratory in nature and accordingly remains in preliminary stages, with our discussions to date with prospective counterparties generally excluding substantive discussions regarding potential valuation, structure or other key transaction terms. The Company has not set a timetable for the conclusion of this review, nor has it made any decisions related to any further actions or potential strategic alternatives at this time. There can be no assurance that the review will progress beyond this exploratory phase or result in any transaction or other strategic change or outcome. The Company does not intend to comment further regarding the strategic alternatives process unless and until our Board has approved a specific course of action or we have otherwise determined that further disclosure is appropriate or required by law.
Current report
Financial and Operating Performance
Current report
The Company’s financial and operating performance for the year ended December 31, 2025 included the following highlights:
Current report
Partially offset by:
Current report
Derivative Financial Instruments
Current report
***Derivative financial instrument exposure.***As of December 31, 2025 and factoring in derivative instruments entered into subsequent to year end, the Company was a party to the following open crude oil derivative financial instruments.
Current report
As of December 31, 2025 and factoring in derivative instruments entered into subsequent to year end, the Company was a party to the following open natural gas derivative financial instruments.
Current report
The estimated fair value of the outstanding open derivative financial instruments as of December 31, 2025, excluding those contracts entered into subsequent to December 31, 2025, was a net asset of $33.0 million which is included in current and noncurrent assets and current and noncurrent liabilities on the Company’s consolidated balance sheet as of December 31, 2025. During the year ended December 31, 2025, the Company recognized a net derivative gain of $44.9 million, including a $30.8 million mark-to-market gain and $14.1 million in net monthly settlement receipts.
Current report
Operations and Drilling Highlights
Current report
The Company's liquids production was 85% of total production on a Boe basis for the year ended December 31, 2025.
Current report
Costs incurred are as follows (in thousands):
Current report
Development/service and exploration/extension drilling activity is as follows:
Current report
Lease operating expense per Boe for 2025 remained relatively flat compared with 2024. Workover costs per Boe for 2025 increased significantly in 2025 compared to 2024 primarily as a result of more pump swaps and/or failures as our producing well count increases and becomes older.
Current report
Gathering, processing and transportation expenses.
Current report
Gathering, processing and transportation expenses are as follows (in thousands):
Current report
Gathering, processing and transportation expenses per Boe are as follows:
Current report
Gathering, processing and transportation expenses per Boe for 2025 increased compared with 2024. This is primarily related to connecting more natural gas to processing facilities that were not previously connected, thereby enhancing the Company’s ability to maximize returns from its wells by increasing sales volumes.
Current report
Other expense.
Current report
During the year ended December 31, 2025, the Company incurred approximately $2.5 million in rating agency fees, legal and accounting professional fees and other costs related to a proposed refinancing of its existing debt obligations. That specific refinancing transaction was not completed. Accordingly, these costs have been expensed as incurred. During the year ended December 31, 2024, the Company incurred approximately $3.8 million in costs related to repairs to production facilities.
Current report
Derivative gain (loss), net.
Showing the first 40 of 48 passages. Open the source sections for the rest.
Removed paragraphs (3)
Previous report
Lease operating expense per Boe for 2024 decreased compared with 2023. This is primarily related to lower chemical and treating costs, lower costs of handling produced water and lower workover costs, partially offset by increased pumper, roustabout and supervision costs, communication expenses, rental equipment and contract services.
Reworded paragraphs (30)
Previous wording
The Company’s revenues, which are entirely originated in the continental United States, are derived from the sale of crude oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. For the years ended December 31, 2024, 2023 and 2022, revenues from our assets were derived approximately 99%, 98% and 95%, respectively, from crude oil sales and 1%, 2% and 5%, respectively, from NGL and natural gas sales.
Current wording
The Company’s revenues, which are entirely originated in the continental United States, are derived from the sale of crude oil and natural gas production and the sale of NGL that are extracted from natural gas during processing. For the years ended December 31, 2025, 2024 and 2023, revenues from our assets were derived approximately 91%, 95% and 96%, respectively, from crude oil sales and 9%, 5% and 4%, respectively, from NGL and natural gas sales.
Previous wording
The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2024, sales to the Company’s largest purchaser accounted for approximately 76% of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Current wording
The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2025, sales to the Company’s largest purchaser accounted for approximately 82% of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of this particular purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Previous wording
The increase in average daily Boe sales volumes for the year ended December 31, 2024, compared with 2023 was due to the Company tying in all of its existing production facilities into natural gas gathering, processing and treating facilities and maintaining relatively flat crude oil production utilizing only a two-rig drilling program throughout 2024.
Current wording
The decrease in average daily Boe sales volumes for the year ended December 31, 2025, compared with 2024 was due to the natural decline on its producing properties and decreased drilling and completion activities, partially offset by the Company tying in all of its existing production facilities into natural gas gathering, processing and treating facilities.
Previous wording
The slight decrease in prices for crude oil, slight increase in prices for NGL and decrease in prices for natural gas for the year ended December 31, 2024, compared with 2023 was due to an overall lower commodity price environment.
Current wording
The decrease in prices for crude oil and NGL can be attributed to an overall lower commodity price environment for crude oil for the year ended December 31, 2025, compared with 2024, partially offset by higher natural gas prices in 2025 compared to 2024.
Previous wording
As detailed above, the decrease in total operating revenues for the year ended December 31, 2024 compared to the same period in 2023 is the result of a 12% decrease in average realized price per Boe partially offset by a 10% increase in average daily sales volumes primarily as a result of the Company’s successful drilling program.
Current wording
As detailed above, the decrease in total operating revenues for the year ended December 31, 2025 compared to the same period in 2024 is the result of a 20% decrease in average realized price per Boe in addition to a 3% decrease in average daily sales volumes primarily as a result of natural decline and decreased drilling and completion activities of the Company due to the lower commodity price environment.
Previous wording
In general, production taxes and ad valorem taxes are directly related to production and commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices and valuations as of the first of the year, whereas production taxes are based upon current year commodity prices and sales volumes.
Current wording
In general, production taxes and ad valorem taxes are directly related to production and commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices and valuations as of the first of the year, whereas production taxes are based upon current year commodity prices and sales volumes. Production and ad valorem taxes are as follows (in thousands):
Previous wording
Production taxes per Boe for the year ended December 31, 2024, compared with 2023, decreased primarily due to the 12% overall decrease in realized sales prices. The increase in ad valorem taxes per Boe for the year ended December 31, 2024, compared with 2023, was primarily due to the increase in commodity prices in 2023 and a significant number of wells that came on production during 2023 that had no ad valorem tax in 2023. 2024 was the first year these wells were assessed ad valorem taxes. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.
Current wording
Production taxes per Boe for the year ended December 31, 2025, compared with 2024, decreased primarily due to the 20% overall decrease in realized sales prices and 3% decrease in average daily sales volumes in addition to a $10.0 million natural gas severance tax refund that was realized by taking advantage of previously unrealized marketing deductions allowed by the State of Texas. The decrease in ad valorem taxes per Boe for the year ended December 31, 2025, compared with 2024, was primarily due to the successful efforts of the Company to reduce the taxable valuation by the state on numerous properties throughout our portfolio. In Texas, ad valorem taxes are based on a valuation of the wells on January 1 of a given year.
Previous wording
The decrease in exploration and abandonment expenses is primarily the result of $3.3 million less in abandoned leasehold costs related to undeveloped acreage that was not in an area where the Company had current plans to drill and thus the leases were allowed to expire in 2023. The Company remains committed to maintaining as much of its undeveloped acreage leasehold position as possible, but from time to time, certain acreage is not able to be extended at reasonable prices and we are not able to get a drilling rig in the area in time to save the leases for a multitude of reasons. In addition, the Company spent $194,000 less in 2024 on plugging various old vertical wells across our acreage position in accordance with applicable regulations.
Current wording
The increase in exploration and abandonment expenses is primarily the result of an $11.1 million unsuccessful exploratory well that was realized in 2025, $2.4 million in additional plugging and abandonment expenses over the prior year due to more wells failing fluid tests and requiring plugging according to state regulations, $1.3 million more in abandoned leasehold costs related to undeveloped acreage that was not in an area where the Company had current plans to drill and thus the leases were allowed to expire in 2025 and $416,000 in increased geologic and geophysical personnel costs. This is the first unsuccessful well drilled by the Company in its history and was a step out to the furthest northeast portion of its acreage. While other wells in the area were successful, one well was written off because it never achieved commercial volumes of crude oil and natural gas after attempting interventions to reduce anomalous water inflows. The Company remains committed to maintaining as much of its undeveloped acreage leasehold position as possible, but from time to time, certain acreage is not able to be extended at reasonable prices and we are not able to get a drilling rig in the area in time to save the leases for a multitude of reasons.
Previous wording
The increase in DD&A expense is primarily due to the increased production associated with our successful horizontal drilling program in addition to an increase in the DD&A rate primarily attributed to increased infrastructure and associated costs as we test new areas. Based on year-end 2024 proved reserves, we anticipate our DD&A rate going into 2025 to be in the $23.00 per Boe range, similar to the fourth quarter of 2024.
Current wording
The decrease in DD&A expense is primarily due to the decreased production associated with the natural decline of our wells and decreased drilling and completion activities coupled with a decrease in the DD&A rate primarily attributed to increased proved reserves at the end of 2024, reducing the rate that was recognized during the first three quarters of 2025. Based on year-end 2025 proved reserves, we anticipate our DD&A rate going into 2026 to be in the $27.52 per Boe range, similar to the fourth quarter of 2025.
Previous wording
The increase in general and administrative expense for the year ended December 31, 2024 is primarily as a result of salary increases and annual bonuses in addition to an increase in internal and external audit costs and legal expenses related to the growth of the Company.
Current wording
The increase in general and administrative expense for the year ended December 31, 2025 is primarily as a result of the resignation and retirement of our former Chief Executive Officer which accounted for approximately $3.4 million of the increase and the increase in legal, insurance and audit related expenses.
Previous wording
The decrease in noncash stock-based compensation expense is due to fewer awards granted in 2024 compared with 2023.
Current wording
The decrease in noncash stock-based compensation expense is due to fewer awards granted recently.
Previous wording
The increase in interest expense can be primarily attributed to higher interest rates in 2024 compared to 2023, but more importantly, to increased borrowings under the Term Loan Credit Agreement beginning in September 2023, partially offset by lower amortization of discounts and debt issuance costs with the longer term on the new debt issuances in 2023.
Current wording
The decrease in interest expense can be primarily attributed to lower interest rates in 2025 compared to 2024 in addition to lower amortization of discounts and debt issuance costs with the amendment of Term Loan Credit Agreement in September 2025.
Previous wording
Derivative loss, net is as follows (in thousands):
Current wording
Derivative gain (loss), net is as follows (in thousands):
Previous wording
The change in income tax expense during the year ended December 31, 2024, compared with 2023, was due to decreased net income during the year ended December 31, 2024 compared with 2023. The effective income tax rate differs from the statutory rate primarily due to a revision on the deferred tax asset related to certain stock-based compensation and permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information.
Current wording
The change in provision for income taxes during the year ended December 31, 2025, compared with 2024, was due to decreased net income during the year ended December 31, 2025 compared with 2024. The effective income tax rate differs from the statutory rate primarily due to a revision on the deferred tax asset related to certain wage and stock-based compensation and permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information.
Previous wording
Liquidity*.*The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, including remaining cash proceeds from our $1.2 billion Term Loan Credit Agreement, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Senior Credit Facility Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets.
Current wording
Liquidity*.*The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Senior Credit Facility Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) sales of nonstrategic assets.
Previous wording
The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortization of its indebtedness. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity. Although the Company expects its sources of funding will be adequate to fund its 2025 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.
Current wording
The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of other contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortizations of its indebtedness. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity. Although the Company expects its sources of funding will be adequate to fund its 2026 planned capital expenditures and provide adequate liquidity to fund other needs, however this may be subject to significant uncertainty due to changes in crude oil, NGL and natural gas pricing and potential covenant compliance issues under its debt instruments described below and no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.
Previous wording
***Debt Refinancing.***In September 2023, we completed a refinancing of our long-term debt in its entirety by entering into an agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement matures on September 30, 2026. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00% of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.
Current wording
Debt Refinancing and Recent Amendments. In September 2023, we completed a refinancing of our long-term debt in its entirety by entering into an agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement was set to mature on September 30, 2026 prior to the amendments discussed below. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00% of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.
Previous wording
The Term Loan Credit Agreement also contains certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio.
Current wording
The Term Loan Credit Agreement also contained certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter prior to the amendments discussed below. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio.
Previous wording
The Term Loan Credit Agreement contains customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.
Current wording
The Term Loan Credit Agreement contained customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.
Previous wording
2025 capital budget*.*The Company’s capital budget for 2025 is expected to be in the range of approximately $375 to $405 million for drilling, completion, facilities and equipping crude oil wells plus $40 to $50 million for field infrastructure buildout and other costs and $33 - $35 million on one-time infrastructure expenditures. The 2025 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical general and administrative expenses and corporate facilities. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations and borrowings under the Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the year ended December 31, 2024 were $604.3 million, excluding acquisitions.
Current wording
2026 capital budget*.* The Company’s capital budget for 2026 is expected to be in the range of approximately $255 to $285 million for drilling, completion, facilities and equipping crude oil wells, field infrastructure buildout and other costs, excluding acquisitions. The 2026 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses and general and administrative expenses. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its consolidated balance sheet, cash generated by operations and borrowing capacity available under its Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the year ended December 31, 2025 were $511.8 million, including the completion and/or continuation of certain one-time infrastructure projects but excluding acquisitions.
Previous wording
The budget above assumes that the Company will operate an average of two (2) drilling rigs and an average of one (1) frac crew during 2025. However, there are many factors and consequences beyond the Company’s control, such as policies of the Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, and OPEC and other cooperating countries, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors.” Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.
Current wording
However, there are many factors and consequences beyond the Company’s control impacting our capital budget, such as political and regulatory uncertainties associated with the new Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC or OPEC+, and governments in response to pandemics, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors.” The Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.
Previous wording
Capital resources*.*As of December 31, 2024, the Company had $1.1 billion in outstanding borrowings under the Term Loan Credit Agreement and approximately $93.1 million available to borrow under the Senior Credit Facility Agreement. The Company also had unrestricted cash on hand of $86.6 million as of December 31, 2024.
Current wording
Capital resources*.* As of December 31, 2025, the Company had $1.2 billion in outstanding borrowings under the Term Loan Credit Agreement and approximately $93.1 million available to borrow under the Senior Credit Facility Agreement. The Company also had unrestricted cash on hand of $162.1 million as of December 31, 2025.
Previous wording
*Operating activities.*The decrease in net cash flow provided by operating activities for the year ended December 31, 2024, compared with 2023, was primarily due to a decrease in cash flow from the statement of operations related mostly to decreased revenues associated with lower commodity prices partially offset by increased production volumes as a result of our successful horizontal drilling program, increased interest expense due to a higher debt balance and increased interest rates, partially offset by lower operating expenses.
Current wording
*Operating activities.*The decrease in net cash flow provided by operating activities for the year ended December 31, 2025, compared with 2024, was primarily due to a decrease in cash flow from the statement of operations related mostly to decreased revenues associated with lower commodity prices and decreased sales volumes as a result of natural decline and decreased drilling and completion activity due to the lower commodity price environment.
Previous wording
*Investing activities.*The decrease in net cash used in investing activities for the year ended December 31, 2024, compared with 2023, was primarily due to a decrease in additions to crude oil and natural gas properties including drilling and completion operations and a decrease in the change in working capital associated with oil and gas property additions.
Current wording
*Investing activities.*The decrease in net cash used in investing activities for the year ended December 31, 2025, compared with 2024, was primarily due to a decrease in additions to crude oil and natural gas properties including drilling and completion operations.
Previous wording
Interest Rate Risk. * *We are exposed to market risk due to the floating interest rate associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of December 31, 2024, we had a $1.1 billion outstanding balance on the Term Loan Credit Agreement and zero outstanding on the Senior Credit Facility Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance for a period of three months and the Senior Credit Facility Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period of up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.
Current wording
Interest Rate Risk. We are exposed to market risk due to the floating interest rates associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of December 31, 2025, we had a $1.2 billion outstanding balance on the Term Loan Credit Agreement and zero outstanding on the Senior Credit Facility Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the end of each quarter for a period of three months and the Senior Credit Facility Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period of up to six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.
Previous wording
Commodity Price Risk. * *The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing armed conflict between Russia and Ukraine. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our 2024 sales volumes and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the year ended December 31, 2024 would have increased (decreased) the Company’s crude oil and NGL revenues by approximately $14.5 million and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2024 would have increased (decreased) the Company’s natural gas revenues by approximately $1.3 million.
Current wording
Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic but are significantly down from the past two years. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing war between Russia and Ukraine, conflicts in the Middle East, and U.S. intervention in Venezuela. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our sales volumes during the year ended December 31, 2025 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the year ended December 31, 2025 would have increased (decreased) the Company’s revenues by approximately $12.9 million and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the year ended December 31, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million.
Previous wording
We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2024, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have changed our net derivative positions for these products by approximately $1.4 million.
Current wording
We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2025, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $6.5 million. Additionally, as of December 31, 2025, a $0.10 increase (decrease) in the forward curves associated with our natural gas commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $1.3 million.
Previous wording
EBITDAX represents net income before interest expense, interest and other income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, noncash derivative gains and losses, other expense, gains and losses on divestitures and certain other items. EBITDAX excludes certain items we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies.
Current wording
EBITDAX represents net income before interest expense, interest and other income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, noncash derivative gains and losses, loss on extinguishment of debt, other expense, gains and losses on divestitures and certain other items. EBITDAX excludes certain items we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies.
Previous wording
The Company’s proved reserve information included in this Annual Report as of December 31, 2024, 2023 and 2022 was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions, positively or negatively, to the estimate of proved reserves. For the year ended December 31, 2024, net upward revisions of our proved reserves totaled approximately 18,017 MBoe and for the years ended December 31, 2023 and 2022, net downward revisions of our proved reserves totaled approximately 16,093 MBoe and 9,211 MBoe, respectively. We cannot predict the amounts or timing of future reserve revisions or removals.
Current wording
The Company’s proved reserve information included in this Annual Report as of December 31, 2025, 2024 and 2023 was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions, positively or negatively, to the estimate of proved reserves. For the year ended December 31, 2025, net downward revisions of our proved reserves totaled approximately 11,531 Mboe, for the year ended December 31, 2024, net upward revisions of our proved reserves totaled approximately 18,017 MBoe and for the year ended December 31, 2023 net downward revisions of our proved reserves totaled approximately 16,093 MBoe. We cannot predict the amounts or timing of future reserve revisions or removals.
Previous wording
***Impairment of unproved crude oil and natural gas properties.***At December 31, 2024, the Company carried unproved property costs of $70.9 million. Management assesses unproved crude oil and natural gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, management's price outlooks and planned future sales or expiration of all or a portion of such projects.
Current wording
***Impairment of unproved crude oil and natural gas properties.***At December 31, 2025, the Company carried unproved property costs of $59.3 million. Management assesses unproved crude oil and natural gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, management's price outlooks and planned future sales or expiration of all or a portion of such projects.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
Average daily crude oil, NGL and natural gas sales volumes are as follows:
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Production and ad valorem taxes are as follows (in thousands):