What changed in this filing

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Item 5. Market for Registrant’s Common Equity

2026-03-11 compared with 2025-03-10 · 215 added, 127 removed, 394 unchanged (46% of the section changed)

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Market Information

HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq under the symbols “HPK” and “HPKEW,” respectively.

As of March 6, 2025, there were 35 holders of record of HighPeak Energy common stock and 5 holders of record of HighPeak Energy’s warrants.

HighPeak Energy’s common stock is listed and traded on the Nasdaq under the symbol “HPK.”

As of March 6, 2026, there were 43 holders of record of HighPeak Energy common stock.

Dividend Policy

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The Company also approved a special dividend of $0.075 per share of common stock that was paid in July 2021.

During the first quarter of 2024, the Company announced an increase in its quarterly cash dividends to $0.04 per share of our common stock.

The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board.

During the first quarter of 2024, the Company announced an increase in its quarterly cash dividends to $0.04 per share of our common stock which has continued through the fourth quarter of 2025 thus far.

However, in the first quarter of 2026, the Board elected not to declare a quarterly dividend and suspended the payment of dividends by the Company for the foreseeable future.

There can be no assurance that we will resume paying dividends following the expiration of this restriction, and any decision to pay any future dividends is solely within the discretion of, and subject to approval by, our Board.

Our Board’s determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the Board deems relevant at the time of such determination.

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December 1, 2025 - December 31, 2025

(1) Such shares are cancelled and retired.

(1) Consists entirely of 256,989 shares of common stock repurchased from officers of the Company in order to satisfy tax withholding requirements.

Such shares have been cancelled and retired.

These shares also do not count toward the dollar value that may yet to be purchased under the plan nor are they subject to the 1% excise tax discussed below.

(2) The average price paid per share includes any commissions paid to repurchase stock.

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However, on March 6, 2025, our Board extended the program in its entirety to December 31, 2025.

The program may be suspended, modified, or discontinued by the Board at any time.

(4) The IRA of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022.

The program has not been extended beyond December 31, 2025 and if it is, it may be suspended, modified, or discontinued by the Board at any time.

(4) A nondeductible 1% excise tax is imposed on the net value of certain stock repurchases.

All dollar amounts presented exclude such excise taxes, as applicable.

Stock Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall the information be incorporated by reference into any future filing under the Securities Act or Exchange Act except to the extent that the Company specifically incorporate it be reference to such filing.

The graph below compares the cumulative total stockholder return on the Company’s common stock during the period from August 24, 2020 through December 31, 2024, with cumulative total returns during the same period for the Standard & Poor’s (“S&P”) 500 Index and the S&P Oil and Gas Exploration & Production Index.

The graph below compares the cumulative total stockholder return on the Company’s common stock during the period from December 31, 2020 through December 31, 2025, with cumulative total returns during the same period for the Standard & Poor’s (“S&P”) 500 Index and the S&P Oil and Gas Exploration & Production Index.

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

MANAGEMENT ’ S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS {START HERE}

MANAGEMENT ’ S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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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, 2024, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew and expects to average two (2) drilling rigs and approximately one (1) frac crew during 2025 under our current development plan.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2023 and into 2024, although the market has decreased from 2022 levels overall, as a result of increased demand outpacing increased supply for each of the commodities we produce.

Prices for the commodities produced by our industry improved from historic lows in 2020, with crude oil and natural gas prices reaching their highest average annual price since 2014 in 2022 before cooling off slightly in 2023.

However, 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 the war in Ukraine, the conflict between Israel and Hamas, elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy’s ability to execute on its capital plan.

Despite continuing impacts of these and other factors and future uncertainty, we expect to maintain 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.

Additionally, the impact of inflation as well as elevated interest rates continue to have a negative impact on our cash flows and results of operations.

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.

Recent Events

Share Repurchase Program.

In February 2024, the Company’s board of directors approved a common stock repurchase program to acquire up to $75.0 million of the Company’s outstanding common stock, excluding excise taxes and other expenses, which was subject to being suspended from time to time, modified, extended or discontinued by the board of directors at any time.

The common stock repurchase program expired on December 31, 2024 (the “2024 Repurchase Program”).

On March 6, 2025, the Company’s board of directors extended the program from its original expiration on December 31, 2024 and extended the program through December 31, 2025 (the “Repurchase Extension”).

The Repurchase Extension did not alter any of the original terms of the 2024 Repurchase Program nor did it change the total amount provided for under the original 2024 Repurchase Program.

HighPeak’s management the authority to repurchase shares opportunistically in the open market from time to time, through block trades, in privately negotiated transactions or by such other means which comply with applicable state and federal laws.

This is the Company’s second authorization for a stock repurchase program since its founding.

The Company intends to fund the repurchases from available working capital, cash provided from operations and borrowings under its Senior Credit Facility Agreement.

The timing, number and value of shares repurchased under the program will be at the discretion of management and the Board of Directors and will depend on a number of factors, including general market and economic conditions, business conditions, the trading price of the Company’s common stock, the nature of other investment opportunities available to the Company and compliance with the Company’s debt and other agreements.

The stock repurchase program does not obligate HighPeak to acquire any particular dollar amount or number of shares of its common stock and the stock repurchase program may be suspended from time to time, modified, extended or discontinued by the Company’s Board of Directors.

The stock repurchase program authority will expire December 31, 2025.

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.

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.

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.

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.

Dividends and dividend equivalents.

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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 $84,000 in March 2024, $84,000 in June 2024, $86,000 in September 2024 and $86,000 in December 2024 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting, assuming no forfeitures.

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.

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.

Crude oil sales contract.

In September 2024, the Company entered into an amended and restated crude oil marketing contract with DK Trading & Supply, LLC (“Delek”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter.

The contract includes the Company’s current and future crude oil production from the majority of its horizontal wells in Flat Top and Signal Peak where DKL is continually constructing a crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries.

The contract contains a minimum volume commitment commencing May 2024 that totals $138.7 million based on the gross piped barrels delivered of 23,500 Bopd for the first ten years of the contract at a certain amount per barrel escalating throughout the term of the contract.

However, the Company generally has the ability under the contract to cumulatively bank dollars based on excess volumes delivered to offset the minimum volume commitment.

For the period from May 1, 2024 to December 31, 2024, the Company has delivered approximately 31,196 Bopd under the contract.

The remaining monetary commitment as of December 31, 2024, if the Company never delivers any additional volumes under the agreement, is approximately $130.3 million.

Crude Oil and Natural Gas Industry Considerations.

Since mid-2020, crude oil prices have improved, with demand steadily increasing.

In addition, 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.

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.

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.

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.

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.

In April 2023, OPEC announced production cuts of around 1.16 million Bopd.

On June 4, 2023, OPEC agreed to extend these previously announced production cuts through the end of 2024.

On July 3, 2023, Saudi Arabia announced it was extending voluntary cuts through August 2023.

However, as a result of current global supply and demand imbalances, crude oil and natural gas prices remain strong, although down from the prior year.

In addition, the war between Russia and Ukraine and ongoing conflict between Israel and Hamas and other tensions in the Middle East have resulted in global supply chain disruptions, which has led to significant cost inflation.

Such impacts may also be exacerbated by recent developments in the Israel-Hamas conflict.

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.

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 the Israel-Hamas conflict, (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.

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.

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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.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2024 and into 2025, although the market has decreased from 2022 levels overall, as a result of increased demand outpacing increased supply for each of the commodities we produce.

Prices for the commodities produced by our industry improved from historic lows in 2020, with crude oil and natural gas prices reaching their highest average annual price since 2014.

However, 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 the conflicts between Russia and Ukraine and between Israel and Hamas, 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.

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.

Risk Factors.”

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a two (2) drilling rig program for 2025.

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.

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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 and Wells Fargo Securities, LLC have been retained as a financial advisors with respect to this strategic alternatives process.

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.

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The primary components of the $76.1 million decrease in net income include:

a $76.3 million increase in DD&A expense due to an 10% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program, in addition to a 7% increase in the DD&A rate from $25.51 to $27.39 per Boe primarily as a result of significant inflationary pressures on capital costs;

a $74.1 million increase in the Company’s net derivative instruments loss from a $27.6 million gain to a $46.5 million loss year over year as a result of its crude oil commodity contracts entered into and the change in crude oil prices thereafter;

a $41.9 million decrease in crude oil, NGL and natural gas revenues due to a 12% decrease in average realized commodity prices per Boe, partially offset by a 10% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program, excluding the effects of derivatives;

a $20.8 million increase in interest expense due to the increase in the Company’s average overall indebtedness and the increase in overall interest rates, partially offset by decreased amortization of debt issuance costs and discounts;

a $3.8 million increase in the Company’s general and administrative expenses primarily attributable to increased employee count, salary increases and annual bonuses in addition to increased internal and external audit costs and legal expenses as a result of the growth of the Company;

a $1.2 million increase in production and ad valorem taxes primarily attributable to an increase in ad valorem taxes, partially offset by lower production taxes as a result of lower revenues recognized by the Company;

a $253.8 million decrease in crude oil, NGL and natural gas revenues due to a 20% decrease in average realized commodity prices per Boe and a 4% decrease in daily sales volumes resulting from natural decline and a decrease in the Company’s drilling and completion activities with the lower commodity price environment, excluding the effects of derivatives;

a $25.4 million increase in loss on extinguishment of debt related to the Company amending its long-term debt in September 2025, extending the maturity and deferring mandatory amortization payments, among other things;

a $20.6 million increase in the Company’s gathering, processing and transportation expense primarily as a result of connecting natural gas in the Signal Peak area to processing and treating facilities, thereby increasing sales volumes as well;

a $15.2 million increase in exploration and abandonment expense primarily due to unsuccessful exploratory well costs, plugging and abandonment expenses and certain abandoned leasehold that the Company chose not to extend;

a $7.2 million increase in crude oil and natural gas production costs related primarily to increased expense workover activities related to our aging well inventory;

a $4.9 million increase in the Company’s general and administrative expense, primarily as a result of the resignation and retirement of our former Chief Executive Officer in September 2025;

a $4.8 million decrease in interest income related to the Company’s lower cash balance throughout 2025 compared with 2024;

Partially offset by:

a $91.4 million increase in the Company’s derivative instruments gain from a loss of $46.5 million in 2024 to a gain of $44.9 million in 2025 primarily as a result of declining commodity prices during 2025;

a $79.0 million decrease in DD&A expense due to a 13% decrease in the DD&A rate from $27.39 to $23.93 per Boe primarily as a result of increased reserves at year end 2024, however the DD&A rate for the three months ended December 31, 2025 was $27.52 due to lower commodity prices at year end 2025 which contributed to lower reserve volumes, in addition to a 4% decrease in daily sales volumes primarily due to natural decline and a decrease in the Company’s drilling and completion activities;

a $28.6 million decrease in the Company’s income tax expense primarily due to the net income realized during 2025 being less than the net income realized during 2024;

a $27.3 million decrease in loss on extinguishment of debt as a result of the Company refinancing its debt in 2023 which resulted in the recognition of a loss thereon, which included $22.8 million of unamortized debt issuance costs and discounts and a make whole premium on the 10.625% Senior Notes of $4.5 million;

a $22.5 million decrease in production and ad valorem taxes primarily attributable to a 20% decrease in operating revenues and a $10.0 million natural gas severance tax refund realized;

a $21.6 million decrease in interest expense primarily related to overall lower rates than 2024 in addition to less amortization of discounts and debt issuance costs;

a $12.1 million decrease in the Company’s stock-based compensation expense as a result of fewer restricted stock and stock options being issued relative to the prior period.

a $13.1 million decrease in lease operating expenses related primarily 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;

a $5.8 million increase in the Company’s interest income due to the increased cash on hand (interest-bearing) subsequent to the closing of the Term Loan Credit Agreement in September 2023;

a $4.5 million decrease in the Company’s other expense primarily as a result of the settlement of a water treatment contract in the prior year;

a $3.8 million decrease in the Company’s exploration and abandonment expense due to a decrease in the amount of leasehold abandonments experienced in 2024 compared to 2023.

During the year ended December 31, 2024, average daily sales volumes totaled 49,960 Boepd, an increase of 10% over 2023, due to the Company’s successful horizontal drilling program in the Permian Basin.

During the year ended December 31, 2025, average daily sales volumes totaled 48,297 Boepd, a decrease of 3% from 2024, due to natural decline and decreased drilling and completion activities given the lower commodity price environment.

Weighted average realized crude oil prices per Bbl decreased during the year ended December 31, 2025 to $65.43, excluding the effects of derivatives, compared with $76.42 for 2024.

Weighted average realized NGL prices per Bbl increased during the year ended December 31, 2024 to $22.06, compared with $21.51 for 2023.

Weighted average realized natural gas prices per Mcf decreased to $0.49 during the year ended December 31, 2024, compared with $1.56 during 2023.

Weighted average realized NGL prices per Bbl decreased during the year ended December 31, 2025 to $19.69, compared with $22.06 for 2024.

Weighted average realized natural gas prices per Mcf increased to $1.25 during the year ended December 31, 2025, excluding the effects of derivatives, compared with $0.49 during 2024.

Cash provided by operating activities totaled $511.6 million for the year ended December 31, 2025, compared with $690.4 million for the year ended December 31, 2024.

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Derivative financial instrument exposure.

As of December 31, 2024, the Company was a party to the following open crude oil derivative financial instruments.

Collars, Enhanced Collars

The estimated fair value of the outstanding open derivative financial instruments as of December 31, 2024 was a net asset of $2.2 million which is included in current assets and current liabilities on the Company’s consolidated balance sheet as of December 31, 2024.

During the year ended December 31, 2024, the Company recognized a net derivative loss of $46.5 million, including a $32.2 million mark-to-market loss and $14.3 million in net monthly settlement payments.

Natural gas derivative instruments.

In February 2025, the Company entered into the following natural gas derivative instruments, specifically HH fixed price swaps at $4.43 per MMBtu for 30,000 MMBtu per day for March 2025 through February 2026.

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.

Costless Collar

Argus WTI Midland

Costless Collar

NYMEX WTI Roll

Argus WTI Midland

Costless Collar

NYMEX WTI Roll

Argus WTI Midland

Costless Collar

NYMEX WTI Roll

Argus WTI Midland

Costless Collar

Argus WTI Midland

Costless Collar

Argus WTI Midland

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.

Settlement Month

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.

Operations and Drilling Highlights

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Successful wells

Unsuccessful wells

Ending wells in progress

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These initiatives would influence overall operating cost and could cause fluctuations when comparing LOE on a period-to-period basis.

Gathering, Processing and Transportation Expense.

Gathering, processing and transportation expenses (“GP&T”) are the costs to gather, transport, treat and process our natural gas production such that we can extract the liquids content from the natural gas in order that the dry gas and NGL can be sold separately at the tailgate of the plants to maximize returns to the Company for its natural gas production.

Production and other taxes.

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Natural Gas (Mcf)

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.

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.

The crude oil, NGL and natural gas prices that the Company reports are based on the market prices received for each commodity.

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Total per Boe

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.

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.

Revenue Variance Analysis.

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Total change from prior period revenues

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.

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.

Crude oil and natural gas production costs.

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Workover costs

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.

Production and ad valorem taxes.

Production and ad valorem taxes are as follows (in thousands):

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.

Gathering, processing and transportation expenses.

Gathering, processing and transportation expenses are as follows (in thousands):

Year Ended December 31,

Gathering, processing and transportation expenses

Gathering, processing and transportation expenses per Boe are as follows:

Year Ended December 31,

Gathering, processing and transportation expenses

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.

Production and ad valorem taxes.

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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):

Year Ended December 31,

Production and ad valorem taxes

Production and ad valorem taxes per Boe are as follows:

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Ad valorem taxes per Boe

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.

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.

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Year Ended December 31,

Geologic and geophysical personnel costs

Unsuccessful exploratory well costs

Plugging and abandonment expense

Abandoned leasehold costs

Geologic and geophysical personnel costs

Geologic and geophysical data costs

Exploration and abandonments expense

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 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.

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.

Depletion, depreciation and amortization expense.

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DD&A expense per Boe

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.

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.

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General and administrative expense per Boe

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.

The decrease in noncash stock-based compensation expense is due to fewer awards granted in 2024 compared with 2023.

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.

The decrease in noncash stock-based compensation expense is due to fewer awards granted recently.

Other expense.

Year Ended December 31,

Debt refinancing costs

Repairs on production facilities

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.

Interest expense.

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Interest expense on Senior Credit Facility Agreement

Interest expense on Prior Credit Agreement

Interest expense on 10.625% Senior Notes

Interest expense on 10.000% Senior Notes

Amortization of discounts

Amortization of debt issuance costs

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.

Derivative loss, net.

Derivative loss, net is as follows (in thousands):

Amortization of discounts

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.

Derivative gain (loss), net.

Derivative gain (loss), net is as follows (in thousands):

Year Ended December 31,

Noncash gain (loss) on derivative instruments, net

Cash paid on settlement of derivative instruments, net

Cash received (paid) on settlement of derivative instruments, net

Gain (loss) on derivative instruments, net

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The above mark-to-market gains and losses and cash settlements relate to crude oil and natural gas derivative swap, enhanced collars and deferred premium put contracts.

Income tax expense.

Loss on extinguishment of debt.

Year Ended December 31,

Income tax expense (in thousands)

Unamortized discount

Unamortized debt issuance costs

Premium paid to exiting lenders

On August 1, 2025, the Company entered into the First Term Loan Amendment which, among other things, (i) extended the maturity date two years to September 2028, (ii) upsized the Term Loan Credit Agreement to $1.2 billion, providing additional liquidity, and (iii) deferred the Term Loan Credit Agreement quarterly amortization payments of $30.0 million for one year such that they begin again in September 2026.

This amendment was considered an extinguishment of debt and thus unamortized discounts and debt issuance costs at the time of the amendment were written off to expense as was a premium paid to exiting lenders.

Provision for income taxes.

Year Ended December 31,

Provision for income taxes

Effective income tax rate

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.

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.

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Liquidity and Capital Resources

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.

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.

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.

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 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.

Debt Refinancing.

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.

As of March 11, 2026, the Company was in compliance with the financial covenants under its Term Loan Credit Agreement and Senior Credit Facility Agreement, as amended.

In particular, we recently entered into credit facility amendments described below to ensure our continued compliance with covenants in our debt instruments, but 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.

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.

If the Company is unable to maintain compliance with its financial covenants or successfully implement the measures described above, its liquidity and capital resources would be materially and adversely affected.

Specifically, the Company's borrowing availability under its Senior Credit Facility Agreement, which was approximately $93.1 million as of March 11, 2026, could be reduced or eliminated, and the Company may be unable to access additional debt or equity financing on acceptable terms or at all .

In addition, 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.

If such amounts were accelerated and became immediately due and payable, the Company does not expect it would have sufficient liquidity to repay such indebtedness and would likely need to pursue a restructuring, refinancing or other strategic alternatives, which may not be available on acceptable terms or at all.

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 matures on September 30, 2026.

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%.

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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.

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.

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.

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.

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.

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The Senior Credit Facility 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.

August 2025 Amendments

February 2026 Amendments

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 in effect for such quarters prior to these amendments.

2026 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.

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.

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.

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.” 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.

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.

Capital resources .

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Net cash used in investing activities

Net cash provided by financing activities

Net cash provided by (used in) financing activities

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.

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.

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.

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.

Financing activities.

The Company’s significant financing activities are as follows:

The Company increased borrowings under the Term Loan Credit Agreement on August 1, 2025 upon closing the First Term Loan Amendment by $180.0 million, partially offset by mandatory amortization payments totaling $60.0 million prior to that, borrowed and repaid $30.0 million under the Senior Credit Facility Agreement, paid dividends and dividend equivalents of $20.9 million and $2.1 million, respectively, paid debt issuance costs of $7.9 million primarily related to the First Term Loan Amendment and the Second Facility Amendment, paid $5.1 million for tax withholding on vested equity awards for certain employees, $3.8 million of which was related to the retirement of the Company’s former Chief Executive Officer and paid $4.8 million in premium on extinguishment of debt.

The Company (i) repaid $120.0 million of the Term Loan Credit Agreement, (ii) repurchased $35.2 million of its common stock and (iii) paid dividends to its common stockholders of $20.1 million and dividend equivalents to certain holders of vested stock options of $2.1 million.

The Company (i) borrowed $1.4 billion and repaid $1.0 billion for a net increase in long-term debt related to the now refinanced debt in the form of the Term Loan Credit Agreement of $425.0 million, (ii) received $155.8 million from the issuance of 14,835,000 shares of common stock in a public offering, (iii) received $4.2 million in proceeds from the exercises of warrants and stock options of the Company, (iv) paid dividends to its common stockholders of $11.9 million and dividend equivalents to certain holders of vested stock options of $1.3 million, (v) spent $28.4 million on debt issuance costs primarily related to the issuance of the Term Loan Credit Agreement and to a lesser extent the new Senior Credit Facility Agreement and amendments to increase its borrowing capacity under the Prior Credit Agreement, (vi) spent $5.4 million in stock offering costs related to the public offering and (vii) spent $4.5 million in make whole payments to retire the 10.625% Senior Notes early.

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.

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 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.

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.

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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.

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 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.

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.

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.

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.

Contractual obligations.

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Non-GAAP Financial Measures

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 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.

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Interest income

Income tax expense

Provision for income taxes

Depletion, depreciation and amortization

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Derivative related noncash activity

Other expense

Loss on extinguishment of debt

Other expense

Critical Accounting Estimates

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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.

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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity