HighPeak Energy, Inc. (HPK)

CIK: 0001792849. SIC: 1381 Drilling Oil & Gas Wells. Latest 10-K as of: 2026-03-11.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1381 Drilling Oil & Gas Wells

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1792849. Latest filing source: 0001437749-26-007770.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-03-11. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001792849.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Free cash flow = operating cash flow - capital expenditures. Missing metrics are omitted rather than fabricated.

Ratios

ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001792849.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0001437749-26-015191.

Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high. Filing date: 2026-05-06. Report date: 2026-03-31.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and related notes. This discussion contains certain “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. These forward-looking statements involve risks and uncertainties and 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, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read “Cautionary Statement Concerning Forward‑Looking Statements.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law.

Overview

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 March 31, 2026, the assets consisted of two highly contiguous leasehold positions of approximately 152,201 gross (140,439 net) acres, approximately 74% 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 three months ended March 31, 2026, approximately 84% and 16% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of March 31, 2026, HighPeak Energy was developing its properties using one (1) drilling rig and expects to average one (1) drilling rig and one (1) frac crew during the remainder of 2026 under our current development plan, depending on certain market conditions.

Recent Events

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 this amendment. 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.

Acquisitions. During the three months ended March 31, 2026, the Company incurred a total of $127,000 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.

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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.

Throughout 2025, OPEC and its non-OPEC allies, known collectively as OPEC+, began unwinding prior voluntary production cuts, 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 and through February 2026. OPEC+ also emphasized that the production increases could continue or be reversed depending on how market conditions evolve, maintaining flexibility to support price stability. With the recent war in Iran and the closing of the Strait of Hormuz, crude oil prices have increased significantly beginning in March 2026, which the Company expects to be temporary depending on when the war comes to an end.  Further complicating crude oil markets is the exit of the UAE from OPEC+, which the Company anticipates could exert further downward pressure on oil prices with their supposed additional capacity to increase production. 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 instability 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 countri

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high. Filing date: 2026-03-11. Report date: 2025-12-31.

ITEM 7. 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. 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.

Overview

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.

Recent Events

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.  

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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.

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 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.

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. 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 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.

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Outlook

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.

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.”

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.

Strategic Alternatives

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. 

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Financial and Operating Performance

The Company’s financial and operating performance for the year ended December 31, 2025 included the following highlights:

•

Net income for the year ended December 31, 2025 was $19.0 million ($0.14 per diluted share) compared with $95.1 million for the year ended December 31, 2024. The primary components of the $76.1 million decrease in net income include:

•

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; and

•

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 $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; and

•

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.

•

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 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.

68

Derivative Financial Instruments

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.

Settlement

Month

Settlement

Year

Type of

Contract

Bbls

Per Day

Index

Swap

Price per

Bbl

Costless

Collar

Floor

Price per

Bbl

Costless

Collar

Ceiling

Price per

Bbl

Crude Oil:

Jan – Mar

2026

Costless Collar

14,350

WTI Cushing

$

—

$

60.58

$

69.62

Jan – Mar

2026

Swap

5,139

WTI Cushing

$

62.54

$

—

$

—

Jan – Mar

2026

Basis Swap

689

Argus WTI Midland

$

0.92

$

—

$

—

Apr – Jun

2026

Costless Collar

12,350

WTI Cushing

$

—

$

59.87

$

66.82

Apr – Jun

2026

Swap

10,000

WTI Cushing

$

64.91

$

—

$

—

Apr – Jun

2026

Roll Swap

10,000

NYMEX WTI Roll

$

4.04

$

—

$

—

Apr – Jun

2026

Basis Swap

5,000

Argus WTI Midland

$

1.01

$

—

$

—

Jul – Sep

2026

Costless Collar

12,000

WTI Cushing

$

—

$

59.83

$

66.84

Jul – Sep

2026

Swap

5,000

WTI Cushing

$

63.45

$

—

$

—

Jul – Sep

2026

Roll Swap

10,000

NYMEX WTI Roll

$

4.04

$

$

—

Jul – Sep

2026

Basis Swap

5,000

Argus WTI Midland

$

1.01

$

—

$

—

Oct – Dec

2026

Costless Collar

9,800

WTI Cushing

$

—

$

59.80

$

65.31

Oct – Dec

2026

Swap

5,000

WTI Cushing

$

63.45

$

—

$

—

Oct – Dec

2026

Roll Swap

10,000

NYMEX WTI Roll

$

4.04

$

—

$

—

Oct – Dec

2026

Basis Swap

5,000

Argus WTI Midland

$

1.01

$

—

$

—

Jan – Mar

2027

Costless Collar

8,900

WTI Cushing

$

—

$

59.78

$

65.24

Jan – Mar

2027

Swap

4,400

WTI Cushing

$

62.14

$

—

$

—

Jan – Mar

2027

Basis Swap

10,000

Argus WTI Midland

$

1.00

$

—

$

—

Apr – Jun

2027

Costless Collar

4,000

WTI Cushing

$

—

$

52.00

$

62.85

Apr – Jun

2027

Swap

6,470

WTI Cushing

$

59.61

$

—

$

—

Apr – Jun

2027

Basis Swap

10,000

Argus WTI Midland

$

1.00

$

—

$

—

Jul – Sep

2027

Swap

8,950

WTI Cushing

$

61.46

$

—

$

—

Jul – Sep

2027

Basis Swap

10,000

Argus WTI Midland

$

1.00

$

—

$

—

Oct – Dec

2027

Basis Swap

10,000

Argus WTI Midland

$

1.00

$

—

$

—

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

Settlement

Year

Type of

Contract

MMBtu

Per Day

Index

Price per

MMBtu

Natural Gas:

Jan – Mar

2026

Swap

31,556

HH

$

4.53

Apr – Jun

2026

Swap

30,000

HH

$

4.30

Jul – Sep

2026

Swap

30,000

HH

$

4.30

Oct – Dec

2026

Swap

30,000

HH

$

4.30

Jan – Mar

2027

Swap

19,667

HH

$

4.30

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

Average daily crude oil, NGL and natural gas sales volumes are as follows:

Year Ended

December 31,

2025

Crude Oil (Bbls)

32,911

NGL (Bbls)

7,931

Natural Gas (Mcf)

44,733

Total (Boe)

48,297

The Company's liquids production was 85% of total production on a Boe basis for the year ended December 31, 2025.

69

Costs incurred are as follows (in thousands):

Year Ended

December 31,

2025

Unproved property acquisition costs

$

6,724

Proved acquisition costs

—

Total acquisitions

6,724

Development costs

366,084

Exploration costs

145,679

Total finding and development costs

518,487

Asset retirement obligations

3,823

Total costs incurred

$

522,310

Development/service and exploration/extension drilling activity is as follows:

Year Ended December 31, 2025

Development/

Service

Exploration/

Extension

Beginning wells in progress

13

10

Well spud

30

22

Successful wells

(34

)

(17

)

Unsuccessful wells

—

(1

)

Ending wells in progress

9

14

Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report. 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.

Sources of Revenues

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.

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.

The Company’s revenues are presented net of certain gathering, transportation and processing expenses incurred to deliver production of its assets’ crude oil, NGL and natural gas to the market. Cost levels of these expenses can vary based on the volume of crude oil, NGL and natural gas produced as well as the cost of commodity processing. Crude oil, NGL and natural gas prices are inherently volatile and are influenced by many factors outside the Company’s control. To reduce the impact of fluctuations in crude oil, NGL and natural gas prices on revenues, the Company may periodically enter into derivative contracts with respect to a portion of its estimated crude oil, NGL and natural gas production through various transactions that fix or set a floor price for future prices received.

70

Principal Components of Cost Structure

Costs associated with producing crude oil, NGL and natural gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells owned. The sections below summarize the primary operating costs typically incurred:

●

Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, workover rigs and workover expenses, materials and supplies comprise the most significant portion of LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, power costs are incurred in connection with various production-related activities, such as pumping to recover crude oil and natural gas and separation and treatment of water produced in connection with crude oil and natural gas production.

The Company monitors the operation of its assets to determine whether it is incurring LOE at an acceptable level. For example, it monitors LOE per Boe to determine if any wells or properties should be shut-in, recompleted or sold. This unit rate also allows the Company to monitor these costs to identify trends and to benchmark against other producers. Although the Company strives to reduce its LOE, these expenses can increase or decrease on a per-unit basis as a result of various factors as it operates its assets or makes acquisitions and dispositions of properties. For example, the Company may increase field-level expenditures to optimize their operations, incurring higher expenses in one quarter relative to another, or they may acquire or dispose of properties that have different LOE per Boe. 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. Production and other taxes are paid on produced crude oil and natural gas based on rates established by federal, state or local taxing authorities. In general, production and other taxes paid correlate to changes in crude oil, NGL and natural gas revenues. Production taxes are based on the market value of production at the wellhead. The Company is also subject to ad valorem taxes in the counties where production is located. Ad valorem taxes are based on the fair market value of the mineral interests for producing wells.

●

Depletion – Crude Oil and Natural Gas Properties. Depletion is the systematic expensing of the capitalized costs incurred to acquire and develop crude oil and natural gas properties. The Company uses the successful efforts method of accounting for crude oil and natural gas properties. Accordingly, all costs associated with acquisition, successful exploration/extension wells and development of crude oil and natural gas reserves, including directly related overhead costs and asset retirement costs are capitalized. However, the costs of abandoned properties, exploratory dry holes, geophysical costs and annual lease rentals are charged to expense as incurred. All capitalized costs of crude oil and natural gas properties are amortized on the unit-of-production method using estimates of proved reserves. Any remaining investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs.

●

General and Administrative Expenses. General and administrative expenses (“G&A”) are costs incurred for overhead, including payroll and benefits for corporate staff and costs of maintaining a headquarters, costs of managing production and development operations, IT expenses and audit and other fees for professional services, including legal compliance and acquisition-related expenses.

71

Results of Operations

Results of operations should be read together with the Company’s consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

Crude Oil, NGL and natural gas revenues.

The Company’s revenues are derived from the sales of crude oil, NGL and natural gas production. Increases or decreases in the Company’s revenues, profitability and future production are highly dependent on commodity prices. Prices are market driven and future prices will fluctuate due to supply and demand factors, availability of transportation, seasonality, geopolitical developments and economic factors, among other items.

Crude oil, NGL and natural gas revenues are as follows (in thousands):

Year Ended December 31,

2025

2024

Change

Crude oil, NGL and natural gas revenues

$

863,359

$

1,117,175

$

(253,816

)

Average daily sales volumes are as follows:

Year Ended December 31,

2025

2024

% Change

Crude Oil (Bbls)

32,911

37,914

(13

)%

NGL (Bbls)

7,931

6,241

27

%

Natural Gas (Mcf)

44,733

34,828

28

%

Total (Boe)

48,297

49,960

(3

)%

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. The weighted average prices, excluding the effects of derivatives, are as follows:

Year Ended December 31,

2025

2024

% Change

Crude oil per Bbl

$

65.43

$

76.42

(14

)%

NGL per Bbl

19.69

22.06

(11

)%

Natural gas per Mcf

1.25

0.49

155

%

Total per Boe

$

48.98

$

61.10

(20

)%

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.

The following table illustrates the variance in revenues attributable to prices versus volumes (in thousands except prices and percentages):

Year Ended

December 31,

2025

2024

% Change

Total operating revenues

$

863,359

$

1,117,175

(23

)%

Average daily sales volumes (Boe)

48,297

49,960

(3

)%

Realized price per Boe

$

48.98

$

61.10

(20

)%

Revenue change from prior period due to prices

$

(221,619

)

(20

)%

Revenue change from prior period due to volumes

(32,178

)

(3

)%

Rounding

(19

)

0

%

Total change from prior period revenues

$

(253,816

)

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.

Crude oil and natural gas production costs are as follows (in thousands):

Year Ended December 31,

2025

2024

Change

Crude oil and natural gas production costs

$

139,492

$

132,244

$

7,248

72

Crude oil and natural gas production costs per Boe are as follows:

Year Ended December 31,

2025

2024

% Change

Lease operating expense

$

6.78

$

6.76

0

%

Workover costs

1.13

0.47

140

%

$

7.91

$

7.23

9

%

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,

2025

2024

Change

Gathering, processing and transportation expenses

$

68,401

$

47,761

$

20,640

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

Year Ended December 31,

2025

2024

% Change

Gathering, processing and transportation expenses

$

3.88

$

2.61

49

%

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.

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):

Year Ended December 31,

2025

2024

Change

Production and ad valorem taxes

$

37,224

$

59,677

$

(22,453

)

Production and ad valorem taxes per Boe are as follows:

Year Ended December 31,

2025

2024

% Change

Production taxes per Boe

$

1.75

$

2.87

(39

)%

Ad valorem taxes per Boe

$

0.36

$

0.39

(8

)%

$

2.11

$

3.26

(35

)%

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.

73

Exploration and abandonments expense.

Exploration and abandonment expense details are as follows (in thousands):

Year Ended December 31,

2025

2024

Change

Unsuccessful exploratory well costs

$

11,092

$

—

$

11,092

Plugging and abandonment expense

2,950

551

2,399

Abandoned leasehold costs

1,371

35

1,336

Geologic and geophysical personnel costs

1,272

856

416

Geologic and geophysical data costs

—

34

(34

)

Exploration and abandonments expense

$

16,685

$

1,476

$

15,209

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.

74

Depletion, depreciation and amortization expense.

DD&A expense is as follows (in thousands):

Year Ended December 31,

2025

2024

Change

DD&A expense

$

421,776

$

500,752

$

(78,976

)

DD&A expense per Boe is as follows:

Year Ended December 31,

2025

2024

% Change

DD&A expense per Boe

$

23.93

$

27.39

(13

)%

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.

General and administrative expense.

General and administrative expense and stock-based compensation expense are as follows (in thousands):

Year Ended December 31,

2025

2024

Change

General and administrative expense

$

25,270

$

20,392

$

4,878

Stock-based compensation expense

$

619

$

12,701

$

(12,082

)

General and administrative expense per Boe is as follows:

Year Ended December 31,

2025

2024

% Change

General and administrative expense per Boe

$

1.43

$

1.12

28

%

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,

2025

2024

Change

Debt refinancing costs

$

2,518

$

—

$

2,518

Other

318

—

318

Repairs on production facilities

—

3,795

(3,795

)

$

2,836

$

3,795

$

(959

)

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.

75

Interest expense.

Interest expense is as follows (in thousands):

Year Ended December 31,

2025

2024

Change

Interest expense on Term Loan Credit Agreement

$

134,511

$

149,844

$

(15,333

)

Interest expense on Senior Credit Facility Agreement

1,030

725

305

Amortization of debt issuance costs

5,881

8,278

(2,397

)

Amortization of discounts

5,714

9,865

(4,151

)

$

147,136

$

168,712

$

(21,576

)

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,

2025

2024

Change

Noncash gain (loss) on derivative instruments, net

$

30,829

$

(32,218

)

$

63,047

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

14,084

(14,246

)

28,330

Gain (loss) on derivative instruments, net

$

44,913

$

(46,464

)

$

91,377

76

The Company primarily utilizes commodity swap contracts, collars, enhanced collars and deferred premium puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budget and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require the Company to hedge certain quantities of its projected crude oil production. The Company may also, from time to time, utilize natural gas contracts or interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. 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.

Loss on extinguishment of debt.

Year Ended December 31,

2025

2024

Change

Unamortized discount

$

11,482

$

—

$

11,482

Unamortized debt issuance costs

9,205

—

9,205

Premium paid to exiting lenders

4,750

—

4,750

$

25,437

$

—

$

25,437

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,

2025

2024

Change

Provision for income taxes

$

7,205

$

35,851

$

(28,646

)

Effective income tax rate

27.5

%

27.4

%

0.1

%

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.

Liquidity and Capital Resources

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.

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.  

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. 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. 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.

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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.

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 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.

Simultaneously with the closing of the Term Loan Credit Agreement, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.

The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof.

On November 1, 2023, but included in part of the refinancing of the Company’s overall long-term debt, the Company entered into a Senior Credit Facility Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $100.0 million and effective March 29, 2024 pursuant to the First Facility Amendment, current commitments of $100.0 million and customary debt issuance costs which totaled approximately $1.1 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility 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 without premium or penalty. 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.

78

August 2025 Amendments

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.

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 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.

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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.

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.  

Cash flows from operating, investing and financing activities are summarized below (in thousands).

Year Ended December 31,

2025

2024

Change

Net cash provided by operating activities

$

511,597

$

690,391

$

(178,794

)

Net cash used in investing activities

$

(515,337

)

$

(620,843

)

$

105,506

Net cash provided by (used in) financing activities

$

79,166

$

(177,414

)

$

256,580

80

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.

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.

Financing activities. The Company’s significant financing activities are as follows:

•

2025: 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.

•

2024: 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.

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.

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.

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.

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Contractual obligations. The Company’s contractual obligations include leases (primarily related to contracted drilling rigs, equipment and office facilities), capital funding obligations and other liabilities. Other joint owners in the properties operated by the Company could incur portions of the costs represented by these commitments.

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, 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. 

We are also subject to financial covenants under our Term Loan Credit Agreement and Senior Credit Facility Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report. The Term Loan Credit Agreement and Senior Credit Facility Agreement provide a material source of liquidity for us. Under the terms of our Term Loan Credit Agreement and the Senior Credit Facility Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of total net leverage or a minimum permitted ratio of asset coverage, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, lenders under those agreements would be entitled to exercise all of their remedies for default.

The following table provides a reconciliation of our net income (GAAP) to EBITDAX (non-GAAP) for the periods presented (in thousands):

Year Ended December 31,

2025

2024

2023

Net income

$

18,963

$

95,069

$

215,866

Interest expense

147,136

168,712

147,901

Interest income

(3,847

)

(8,685

)

(2,908

)

Provision for income taxes

7,205

35,851

65,905

Depletion, depreciation and amortization

421,776

500,752

424,424

Accretion of discount

1,075

966

522

Exploration and abandonment expense

16,685

1,476

5,234

Stock-based compensation

619

12,701

25,957

Derivative related noncash activity

(30,829

)

32,218

(51,796

)

Loss on extinguishment of debt

25,437

—

27,300

Other expense

2,836

3,795

8,262

EBITDAX

$

607,056

$

842,855

$

866,667

Critical Accounting Estimates

The Company prepares its consolidated financial statements for inclusion in this Annual Report in accordance with GAAP. See Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” in this Annual Report for additional information. The following is a discussion of the Company’s most critical accounting estimates, judgments and uncertainties that are inherent in the Company’s application of GAAP.

Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for crude oil and natural gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for crude oil and natural gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of DD&A expense.

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Proved reserve estimates. Estimates of the Company’s proved reserves included in this Annual Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

●

the quality and quantity of available data;

●

the interpretation of that data;

●

the accuracy of various mandated economic assumptions; and

●

the judgment of the persons preparing the estimate.

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.

It should not be assumed that the standardized measure included in this Annual Report as of December 31, 2025 is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the 2025 standardized measure on a twelve-month average of commodity prices on the first day of each month in 2025 and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Items 1 and 2. Business and Properties” and Unaudited Supplementary Data included in “Item 8. Financial Statements and Supplementary Data” for additional information.

The Company’s estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which the Company records DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company’s assessment of its proved properties for impairment.

Impairment of proved crude oil and natural gas properties. The Company performs assessments of its long-lived assets to be held and used, including proved crude oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If there is an indication the carrying value of the assets may not be recovered, an impairment loss is recognized if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Proved crude oil and natural gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

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.

Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:

●

The well has found a sufficient quantity of reserves to justify its completion as a producing well; and

●

The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

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Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and economics associated with making a determination of its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predict the hydrocarbon recoverability based on well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found sufficient quantities of proved reserves to sanction the project or is determined to be noncommercial and is impaired. See Note 6 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land at the end of crude oil and natural gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the crude oil and natural gas property or other property and equipment balance. See Note 8 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets will be realized prior to their expiration. HighPeak Energy monitors Company-specific, crude oil and natural gas industry and worldwide economic factors and based on that information, along with other data, reassesses the likelihood that the Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period.

Uncertain tax positions. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefits is sustained upon examination by the taxing authorities, the tax benefit will be recorded as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recorded. As of December 2025, the Company did not have any unrecognized tax benefits. See Note 13 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments of the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note 10 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, and (ii) the closing stock price on the date of grant for the fair value of unrestricted and restricted stock awards. See Note 9 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities the Company measures and records at fair value on a recurring basis include commodity derivative contracts and interest rate contracts. Other assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. The assets and liabilities the Company measures and records at fair value on a nonrecurring basis include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities may require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Recent Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

Off-Balance Sheet Arrangements

Commitments and Contingencies are discussed in Note 10 of Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

84