[10-Q] HighPeak Energy, Inc. Quarterly Earnings Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________ to ________
Commission File Number:
(Exact name of Registrant as specified in its charter)
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(Address of principal executive offices and zip code) |
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(Registrant's telephone number, including area code)
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(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
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The Nasdaq Stock Market LLC |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer |
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Non-accelerated filer |
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Emerging growth company |
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
As of October 31, 2025, there were
HIGHPEAK ENERGY, INC.
TABLE OF CONTENTS
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Definitions of Certain Terms and Conventions Used Herein |
1 |
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Cautionary Statement Concerning Forward-Looking Statements |
5 |
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PART I. FINANCIAL INFORMATION |
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Item 1. |
Condensed Consolidated Financial Statements (Unaudited) |
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Condensed Consolidated Balance Sheets |
6 |
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Condensed Consolidated Statements of Operations |
7 |
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Condensed Consolidated Statements of Changes in Stockholders’ Equity |
8 |
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Condensed Consolidated Statements of Cash Flows |
9 |
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Notes to Condensed Consolidated Financial Statements |
10 |
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Item 2. |
Management's Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. |
Quantitative and Qualitative Disclosures About Market Risk |
40 |
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Item 4. |
Controls and Procedures |
41 |
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PART II. OTHER INFORMATION |
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Item 1. |
Legal Proceedings |
41 |
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Item 1A. |
Risk Factors |
41 |
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Item 2. |
Unregistered Sales of Equity Securities and Use of Proceeds |
47 |
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Item 5. |
Other Information |
47 |
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Item 6. |
Exhibits |
48 |
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Signatures |
49 |
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HIGHPEAK ENERGY, INC.
Definitions of Certain Terms and Conventions Used Herein
Within this Quarterly Report on Form 10-Q (this “Quarterly Report”), the following terms and conventions have specific meanings:
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“3-D seismic” means three-dimensional seismic data which is geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional data. |
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“ASC” means Accounting Standards Codification. |
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“ASU” means Accounting Standards Update. |
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“Basin” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate. |
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“Bbl” means a standard barrel containing 42 United States gallons. |
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“Bcf” means one billion cubic feet. |
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“Boe” means a barrel of crude oil equivalent and is a standard convention used to express crude oil and natural gas volumes on a comparable crude oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of natural gas to one Bbl of crude oil or NGL. |
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“Boepd” means Boe per day. |
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“Bopd” means one barrel of crude oil per day. |
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“Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. |
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“Collateral Agency Agreement” means the Company’s Collateral Agency Agreement, dated as of September 12, 2023, by and among HighPeak Energy, Inc., Texas Capital Bank, as collateral agent, Chambers Energy Management, LP, as term representative, 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. |
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“common stock” or “HighPeak Energy common stock” means the Company’s common stock, par value $0.0001 per share. |
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“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. |
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“Credit Agreement” means the Term Loan Credit Agreement and the Senior Credit Facility Agreement. |
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“DD&A” means depletion, depreciation and amortization. |
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“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7). |
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“Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. |
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“Development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. |
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“Differential” An adjustment to the price of crude oil, NGL or natural gas from an established spot market price to reflect differences in the quality and/or location of crude oil, NGL or natural gas. |
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“Dry hole” or “dry well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. |
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“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. |
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“EUR” or “Estimated ultimate recovery” The sum of reserves remaining as of a given date and cumulative production as of that date. |
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“Exploratory well” An exploratory well is a well drilled to find a new field, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC. |
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“Extension well” An extension well is a well drilled to extend the limits of a known reservoir. |
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“FASB” Financial Accounting Standards Board. |
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“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. |
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“First Facility Amendment” means the First Amendment to Senior Credit Facility Agreement, dated March 29, 2024, by and among HighPeak Energy, Inc., as borrower, Fifth Third Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto. |
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“First Term Loan Amendment” means the First Amendment to Term Loan Credit Agreement, dated August 1, 2025, by and among HighPeak Energy, Inc., as borrower, Texas Capital Bank, as administrative agent, Chambers Energy Management, LP, as collateral agent, and the lenders from time-to-time party thereto. |
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“Formation” A layer of rock which has distinct characteristics that differs from nearby rocks. |
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“GAAP” means accounting principles generally accepted in the United States of America. |
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“Gross wells” means the total wells in which a working interest is owned. |
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“Held by production” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of crude oil or natural gas. |
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“HH” means Henry Hub, a distribution hub in Louisiana that serves as the delivery location for natural gas futures contracts on the NYMEX. |
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“HighPeak Energy” or the “Company” means HighPeak Energy, Inc. and its subsidiaries. |
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“HighPeak I” means HighPeak Energy, LP, a Delaware limited partnership, and a wholly owned subsidiary of HighPeak Energy Partners, LP, a Delaware limited partnership. |
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“HighPeak II” means HighPeak Energy II, LP, a Delaware limited partnership, and a wholly owned subsidiary of HighPeak Energy Partners II, LP, a Delaware limited partnership. |
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“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. |
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“HPK Contributors” means HighPeak I, HighPeak II and HPK GP. |
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“HPK GP” means HighPeak Energy, LLC, a Delaware limited liability company. |
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“Hydraulic fracturing” is the technique of stimulating the production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in its drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. |
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“Lease operating expenses” The expenses of lifting crude oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses. |
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“MBbl” means one thousand Bbls. |
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“MBoe” means one thousand Boes. |
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“Mcf” means one thousand cubic feet and is a measure of natural gas volume. |
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“MMBbl” means one million Bbls. |
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“MMBtu” means one million Btus. |
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“MMcf” means one million cubic feet and is a measure of natural gas volume. |
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“Net acres” The percentage of total acres an owner has out of a particular number of gross acres or a specified tract. As an example. an owner who has 50% interest in 100 gross acres owns 50 net acres. |
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“Net production” Production that is owned by us, less royalties and production due others. |
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“NGL” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the natural gas stream; such liquids include ethane, propane, isobutane, normal butane and gasoline. |
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“NYMEX” means the New York Mercantile Exchange. |
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“OPEC” means the Organization of Petroleum Exporting Countries. |
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“Operator” The individual or company responsible for the exploration and/or production of a crude oil or natural gas well or lease. |
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“Plugging” A downhole tool that is set inside the casing to isolate the lower part of the wellbore. |
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“Pooling” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules. |
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“Principal Stockholder Group” means HighPeak Pure Acquisition, LLC, a Delaware limited liability company, and a wholly owned subsidiary of HighPeak Energy, LP and the HPK Contributors and each of their respective affiliates and certain permitted transferees, collectively. |
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“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20). |
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“Productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. |
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“Proration unit” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction. |
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“Prospect” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. |
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“Proved developed nonproducing reserves” or “PDNP” means proved reserves that are developed nonproducing reserves. |
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“Proved developed producing reserves” or “PDP” means proved reserves that are developed producing reserves. |
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“Proved developed reserves” means proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and can be expected to be recovered through extraction technology installed and operational at the time of the reserve estimate and can be subdivided into PDP and PDNP reserves. |
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“Proved reserves” Those quantities of crude oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. |
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(i) The area of the reservoir considered as proved includes: (A) the area identified by drilling and limited by fluid contacts, if any, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or natural gas on the basis of available geoscience and engineering data. |
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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. |
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(iii) Where direct observation from well penetrations has defined a highest known crude oil elevation and the potential exists for an associated natural gas cap, proved crude oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. |
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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) the project has been approved for development by all necessary parties and entities, including governmental entities. |
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(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
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“Proved undeveloped reserves” or “PUD” means proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion. Undrilled locations can be classified as PUDs only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five (5) years, unless specific circumstances justify a longer time. |
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“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. |
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“Realized price” The cash market price less all expected quality, transportation and demand adjustments. |
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“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs or enhancing existing reservoirs in an attempt to establish or increase existing production. |
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“Reserves” Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil and natural gas or related substances to market, and all permits and financing required to implement the project. |
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“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs. |
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“Resources” Quantities of crude oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations. |
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“Royalty” An interest in a crude oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof) but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. |
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“SEC” means the United States Securities and Exchange Commission. |
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“Second Facility Amendment” means the Second Amendment to Senior Credit Facility Agreement, dated August 1, 2025, by and among HighPeak Energy, Inc., as borrower, Fifth Third Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto. |
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“Senior Credit Facility Agreement” means the Company’s Credit Agreement, dated as of November 1, 2023, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent and collateral agent, and the lenders party thereto. |
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“Service well” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include natural gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. |
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“Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, the distance between horizontal wellbores, e.g., 880-foot spacing or the number of wells per section, e.g., 6-well spacing. It is often established by regulatory agencies and/or the operator to optimize recovery of hydrocarbons. |
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“Spot market price” The cash market price without reduction for expected quality, transportation and demand adjustments. |
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“Standardized measure” The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines as well as the rules and regulations of the SEC, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to DD&A. Standardized measure does not give effect to derivative transactions. |
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“Stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area. |
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“Term Loan Credit Agreement” means the Company’s Term Loan Credit Agreement, dated as of September 12, 2023, by and between HighPeak Energy, Inc., as borrower, Texas Capital Bank, as administrative agent, Chambers Energy Management, LP, as collateral agent, and the lenders from time-to-time party thereto. |
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“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether such acreage contains proved reserves. |
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“Unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. |
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“U.S.” means the United States. |
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“Warrants” means warrants to purchase one share of HighPeak Energy common stock at a price of $11.50 per share, which expired on August 21, 2025. |
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“Wellbore” The hole drilled by the bit that is equipped for crude oil and natural gas production on a completed well. Also called well or borehole. |
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“Working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis. |
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“Workover” Operations on a producing well to restore or increase production. |
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“WTI” means West Texas Intermediate, a light sweet blend of crude oil produced from fields in western Texas and is a grade of crude oil used as a benchmark in crude oil pricing. |
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With respect to information on the working interest in wells and acreage, “net” wells and acres are determined by multiplying “gross” wells and acres by the Company’s working interest in such wells or acres. Unless otherwise specified, wells and acreage statistics quoted herein represent gross wells or acres. |
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All currency amounts are expressed in U.S. dollars. |
The terms “development costs,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery,” “exploratory well,” “production costs,” “reserves,” “reservoir,” “resources,” “service wells” and “stratigraphic test well” are defined by the SEC. Except as noted, the terms defined in this section are not the same as SEC definitions.
Cautionary Statement Concerning Forward-Looking Statements
This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included or incorporated by reference in this Quarterly Report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on the beliefs of management, as well as assumptions made by, and information currently available to, the Company’s management. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate” or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the Company’s assumptions regarding the following factors:
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the supply and demand for and market prices of crude oil, NGL, natural gas and other products or services, and the associated impact of our hedging policies relating thereto; |
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inflation rates, the impacts of associated monetary policy responses, including increased or decreased interest rates and resulting pressures on economic growth, U.S. trade policy and the imposition of and changes to tariffs; |
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political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine and conflicts in the Middle East; |
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volatility in the political, legal and regulatory environments, including the effects of a prolonged U.S. government shutdown; |
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political and regulatory uncertainties; |
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our liquidity, cash flow and access to capital; |
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the availability of capital resources; |
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our ability to refinance or pay, when due, the principal of, interest or other amounts due in respect of our indebtedness; |
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production and reserve levels; |
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drilling and completion risks; |
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economic and competitive conditions; |
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the impacts of revising our drilling plan during the year transitioning to an increased or decreased rig count from time to time; |
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severe weather conditions; |
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epidemics or pandemics, including the effects of related public health concerns and the impact of continued actions taken by governmental authorities and other third parties in response to pandemics and their impact on commodity prices, supply and demand considerations, and storage capacity; |
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the availability of goods and services and supply chain issues; |
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regulatory and related policy actions intended by federal, state and/or local governments to reduce fossil fuel use and associated carbon emissions, to drive the substitution of renewable forms of energy for crude oil and natural gas, which may over time reduce demand for crude oil, NGL and natural gas, including as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise; |
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our ability to predict and manage the effects of actions of OPEC and its non-OPEC allies, known collectively as OPEC+, and agreements to set and maintain production levels; |
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recent management changes; |
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cyber-attacks; |
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occurrence of property acquisitions or divestitures; |
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the integration of acquisitions; |
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capital markets and our ability to access such markets on attractive terms or at all, and related risks such as general credit, liquidity, market and interest-rate risks; |
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the results of our ongoing strategic alternatives process; and |
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other factors disclosed under “Part I, Items 1 and 2. Business and Properties,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on March 10, 2025 (“Annual Report”) and under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and “Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk,” included in each of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025 filed with the SEC on May 12, 2025, Form 10-Q for the quarter ended June 30, 2025 filed with the SEC on August 11, 2025 and this Quarterly Report. |
All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, the Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.
Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGL and natural gas that are ultimately recovered.
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
HighPeak Energy, Inc.
Condensed Consolidated Balance Sheets
(in thousands, except share data)
|
September 30, 2025 |
December 31, 2024 |
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(Unaudited) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
$ | $ | ||||||
|
Accounts receivable |
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Derivative instruments |
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Inventory |
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Prepaid expenses |
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Total current assets |
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Crude oil and natural gas properties, using the successful efforts method of accounting: |
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Proved properties |
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Unproved properties |
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Accumulated depletion, depreciation and amortization |
( |
) |
( |
) |
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Total crude oil and natural gas properties, net |
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Other property and equipment, net |
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Derivative instruments |
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Other noncurrent assets |
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Total assets |
$ | $ | ||||||
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
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Current liabilities: |
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|
Current maturities of long-term debt |
$ | $ | ||||||
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Accounts payable – trade |
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Revenues and royalties payable |
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Other accrued liabilities |
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Accrued capital expenditures |
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Operating leases |
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Derivative instruments |
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Advances from joint interest owners |
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Total current liabilities |
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Noncurrent liabilities: |
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Long-term debt, net |
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Deferred income taxes |
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Asset retirement obligations |
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Derivative instruments |
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Operating leases |
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Commitments and contingencies (Note 10) |
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|
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Stockholders’ equity: |
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Preferred stock, $ |
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Common stock, $ |
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|
Additional paid-in capital |
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|
Retained earnings |
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|
Total stockholders’ equity |
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|
Total liabilities and stockholders’ equity |
$ | $ | ||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
HighPeak Energy, Inc.
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
(Unaudited)
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
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|
2025 |
2024 |
2025 |
2024 |
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Operating revenues: |
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|
Crude oil sales |
$ | $ | $ | $ | ||||||||||||
|
NGL and natural gas sales |
( |
) | ||||||||||||||
|
Total operating revenues |
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Operating costs and expenses: |
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Crude oil and natural gas production |
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Production and ad valorem taxes |
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Exploration and abandonments |
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Depletion, depreciation and amortization |
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Accretion of discount |
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General and administrative |
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Stock-based compensation |
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Total operating costs and expenses |
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Other expense |
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Income from operations |
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Interest and other income |
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Interest expense |
( |
) |
( |
) |
( |
) | ( |
) | ||||||||
|
Gain (loss) on derivative instruments, net |
( |
) | ||||||||||||||
|
Loss on extinguishment of debt |
( |
) | ( |
) | ||||||||||||
|
(Loss) income before income taxes |
( |
) | ||||||||||||||
|
Provision for income taxes |
( |
) | ||||||||||||||
|
Net (loss) income |
$ | ( |
) | $ | $ | $ | ||||||||||
|
(Loss) earnings per share: |
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|
Basic net (loss) income |
$ | ( |
) | $ | $ | $ | ||||||||||
|
Diluted net (loss) income |
$ | ( |
) | $ | $ | $ | ||||||||||
|
Weighted average shares outstanding: |
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|
Basic |
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|
Diluted |
||||||||||||||||
|
Dividends declared per share |
$ | $ | $ | $ | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
HighPeak Energy, Inc.
Condensed Consolidated Statements of Changes in Stockholders' Equity
(in thousands)
(Unaudited)
|
Three and Nine Months Ended September 30, 2025 |
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|
Shares Outstanding |
Common Stock |
Additional Paid-in- Capital |
Retained Earnings |
Total Stockholders' Equity |
||||||||||||||||
|
Balance, December 31, 2024 |
$ | $ | $ | $ | ||||||||||||||||
|
Dividends declared ($ |
— | ( |
) |
( |
) |
|||||||||||||||
|
Dividend equivalents declared on outstanding stock options ($ |
— | ( |
) |
( |
) |
|||||||||||||||
|
Stock-based compensation costs: |
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|
Compensation costs included in net income |
— | |||||||||||||||||||
|
Net income |
— | |||||||||||||||||||
|
Balance, March 31, 2025 |
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|
Dividends declared ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Dividend equivalents declared on outstanding stock options ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Exercise of warrants |
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|
Stock-based compensation costs: |
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|
Restricted shares issued to outside directors |
||||||||||||||||||||
|
Compensation costs included in net income |
— | |||||||||||||||||||
|
Net income |
— | |||||||||||||||||||
|
Balance, June 30, 2025 |
||||||||||||||||||||
|
Dividends declared ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Dividend equivalents declared on outstanding stock options ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Stock-based compensation costs: |
||||||||||||||||||||
|
Compensation costs included in net income |
— | |||||||||||||||||||
|
Cash paid for tax withholding on vested equity awards |
( |
) | ( |
) | ( |
) | ||||||||||||||
|
Net loss |
— | ( |
) | ( |
) | |||||||||||||||
|
Balance, September 30, 2025 |
$ | $ | $ | $ | ||||||||||||||||
|
Three and Nine Months Ended September 30, 2024 |
||||||||||||||||||||
|
Shares Outstanding |
Common Stock |
Additional Paid-in- Capital |
Retained Earnings |
Total Stockholders' Equity |
||||||||||||||||
|
Balance, December 31, 2023 |
$ | $ | $ |
$ |
||||||||||||||||
|
Dividends declared ($ |
— | ( |
) |
( |
) |
|||||||||||||||
|
Dividend equivalents declared on outstanding stock options ($ |
— | ( |
) |
( |
) |
|||||||||||||||
|
Repurchased shares under buyback program |
( |
) | ( |
) | ( |
) | ||||||||||||||
|
Stock-based compensation costs: |
||||||||||||||||||||
|
Compensation costs included in net income |
— | |||||||||||||||||||
|
Net income |
— | |||||||||||||||||||
|
Balance, March 31, 2024 |
||||||||||||||||||||
|
Dividends declared ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Dividend equivalents declared on outstanding stock options ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Exercise of warrants |
||||||||||||||||||||
|
Repurchased shares under buyback program |
( |
) | ( |
) | ( |
) | ||||||||||||||
|
Stock-based compensation costs: |
||||||||||||||||||||
|
Restricted shares issued to outside directors |
||||||||||||||||||||
|
Compensation costs included in net income |
— | |||||||||||||||||||
|
Net income |
— | |||||||||||||||||||
|
Balance, June 30, 2024 |
||||||||||||||||||||
|
Dividends declared ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Dividend equivalents declared on outstanding stock options ($ |
— | ( |
) | ( |
) | |||||||||||||||
|
Repurchased shares under buyback program |
( |
) | — | ( |
) | — | ( |
) | ||||||||||||
|
Stock-based compensation costs: |
||||||||||||||||||||
|
Compensation costs included in net income |
— | |||||||||||||||||||
|
Net income |
— | |||||||||||||||||||
|
Balance, September 30, 2024 |
$ | $ | $ | $ | ||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
HighPeak Energy, Inc.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
|
Nine Months Ended September 30, |
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|
2025 |
2024 |
|||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
|
Net income |
$ | $ | ||||||
|
Adjustments to reconcile net income to net cash provided by operations: |
||||||||
|
Provision for deferred income taxes |
||||||||
|
Loss on extinguishment of debt |
||||||||
|
(Gain) loss on derivative instruments, net |
( |
) | ||||||
|
Cash received (paid) on settlement of derivative instruments |
( |
) | ||||||
|
Amortization of debt issuance costs |
||||||||
|
Amortization of discounts on long-term debt |
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|
Stock-based compensation expense |
||||||||
|
Accretion expense |
||||||||
|
Depletion, depreciation and amortization expense |
||||||||
|
Exploration and abandonment expense |
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|
Changes in operating assets and liabilities: |
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|
Accounts receivable |
||||||||
|
Prepaid expenses, inventory and other assets |
( |
) | ||||||
|
Accounts payable, accrued liabilities and other current liabilities |
( |
) | ( |
) | ||||
|
Net cash provided by operating activities |
||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
|
Additions to crude oil and natural gas properties |
( |
) |
( |
) |
||||
|
Changes in working capital associated with crude oil and natural gas property additions |
( |
) | ( |
) | ||||
|
Acquisitions of crude oil and natural gas properties |
( |
) |
( |
) |
||||
|
Proceeds from sales of properties |
||||||||
|
Other property additions |
( |
) | ( |
) | ||||
|
Net cash used in investing activities |
( |
) | ( |
) | ||||
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
|
Borrowings under Term Loan Credit Agreement |
||||||||
|
Borrowings under Senior Credit Facility Agreement |
||||||||
|
Repayments under Term Loan Credit Agreement |
( |
) | ( |
) | ||||
|
Repayments under Senior Credit Facility Agreement |
( |
) | ||||||
|
Dividends paid |
( |
) |
( |
) |
||||
|
Debt issuance costs |
( |
) | ( |
) | ||||
|
Premium on extinguishment of debt |
( |
) | ||||||
|
Cash paid for tax withholding on vested equity awards |
( |
) | ||||||
|
Dividend equivalents paid |
( |
) | ( |
) | ||||
|
Proceeds from exercise of warrants |
||||||||
|
Repurchased shares under buyback program |
( |
) | ||||||
|
Net cash provided by (used in) financing activities |
( |
) | ||||||
|
Net increase (decrease) in cash and cash equivalents |
( |
) | ||||||
|
Cash and cash equivalents, beginning of period |
||||||||
|
Cash and cash equivalents, end of period |
$ | $ | ||||||
|
Supplemental cash flow information: |
||||||||
|
Cash paid for interest |
$ | $ | ||||||
|
Cash paid for income taxes |
||||||||
|
Supplemental disclosure of non-cash transactions: |
||||||||
|
Additions to asset retirement obligations |
||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
HIGHPEAK ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1. Organization and Nature of Operations
HighPeak Energy, Inc. ("HighPeak Energy" or the "Company") is a Delaware corporation, formed in October 2019. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the U.S. Securities and Exchange Commission (“SEC”) on March 10, 2025, for further information regarding the formation of the Company. HighPeak Energy’s common stock is listed and traded on the Nasdaq Global Market (the "Nasdaq") under the ticker symbol “HPK.” The Company 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 primarily in Howard and Borden Counties. 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.
NOTE 2. Basis of Presentation and Summary of Significant Accounting Policies
Presentation. In the opinion of management, the unaudited interim condensed consolidated financial statements of the Company as of September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024 include all adjustments and accruals, consisting only of normal, recurring adjustments and accruals necessary for a fair presentation of the results for the interim periods in conformity with generally accepted accounting principles in the United States ("GAAP"). Certain prior period amounts have been reclassified to conform to the current period condensed consolidated financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. The operating results for the three and nine months ended September 30, 2025 are not indicative of results for a full year.
Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in accordance with the rules and regulations of the SEC. These unaudited interim condensed consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024.
Cash and cash equivalents. The Company’s cash and cash equivalents include depository accounts held by banks with original issuance maturities of 90 days or less. The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.
Accounts receivable. As of September 30, 2025 and December 31, 2024, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $
Accounts receivable are stated at amounts due from purchasers or joint interest owners, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from purchasers or joint interest owners outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. As of September 30, 2025 and December 31, 2024, the Company had no allowance for credit losses related to accounts receivable.
Concentration of credit risk. The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the nine months ended September 30, 2025 and the year ended December 31, 2024, sales to the Company’s largest purchaser accounted for approximately
Crude oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its crude oil and natural gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed.
The Company does not carry the costs of drilling an exploratory well as an asset in its condensed consolidated balance sheet following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
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 the economics associated with making a determination on 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 data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonment expense. See Note 6 for additional information.
The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved developed reserves for drilling, completion and other crude oil and natural gas property costs. Unproved leasehold costs are excluded from depletion until proved reserves are established or, if unsuccessful, impairment is determined.
Proceeds from the sales of individual properties are credited to proved or unproved crude oil and natural gas properties, as the case may be, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
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.
Unproved crude oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the estimates of future recoverable reserves, results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time.
Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment are as follows, net of accumulated depreciation of $
|
September 30, 2025 |
December 31, 2024 |
|||||||
|
Land |
$ | $ | ||||||
|
Transportation equipment |
||||||||
|
Buildings |
||||||||
|
Leasehold improvements |
||||||||
|
Field equipment |
||||||||
|
Furniture and fixtures |
||||||||
|
Total other property and equipment, net |
$ | $ | ||||||
Other property and equipment are depreciated over their estimated useful life on a straight-line basis. Land is not depreciated. Transportation equipment is generally depreciated over five years, buildings are generally depreciated over forty years, field equipment is generally depreciated over seven years and furniture and fixtures is generally depreciated over five years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method.
Current liabilities. Current liabilities as of September 30, 2025 and December 31, 2024 totaled approximately $
Revenue recognition. The Company follows FASB ASC 606, “Revenue from Contracts with Customers,” (“ASC 606”) whereby the Company recognizes revenues from the sales of crude oil, NGL and natural gas to its purchasers and presents them disaggregated on the Company’s condensed consolidated statements of operations.
The Company enters into contracts with purchasers to sell its crude oil, NGL and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the crude oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the crude oil and natural gas marketing contracts is typically received from the purchaser one to two months after the date of sale. As of September 30, 2025 and December 31, 2024, the Company had receivables related to contracts with purchasers of approximately $
Crude Oil Contracts. The Company’s crude oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the crude oil has been transferred to the purchaser. The crude oil produced is sold under contracts using market-based pricing which is then adjusted for the differentials based upon delivery location and crude oil quality. Since the differentials are incurred after the transfer of control of the crude oil, the differentials are included in crude oil sales on the condensed consolidated statements of operations as they represent part of the transaction price of the contract.
Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts or (ii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue natural gas are then sold by the purchaser. Under percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue natural gas. Since control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Derivatives. All the Company’s derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the condensed consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.
The Company’s credit risk related to derivatives is a counterparty’s failure to perform under derivative contracts owed to the Company. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.
The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 for additional information.
Stock-based compensation. Stock-based compensation expense for stock option awards is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of forfeitures, on a straight-line basis over the requisite service period of the respective award. The fair value of stock option awards is determined on the grant date or modification date, as applicable, using a Black-Scholes option valuation model with the following inputs: (i) the grant date’s closing stock price, (ii) the exercise price of the stock options, (iii) the expected term of the stock option, (iv) the estimated risk-free adjusted interest rate for the duration of the option’s expected term, (v) the expected annual dividend yield on the underlying stock and (vi) the expected volatility over the option’s expected term.
Stock-based compensation for restricted stock awarded to outside directors, employee members of the Board and certain other employees is measured at the grant date using the fair value of the award and is recognized on a straight-line basis over the requisite service period of the respective award.
Other expense. During the nine months ended September 30, 2025, the Company incurred approximately $
Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the carrying amounts for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date.
The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all the deferred tax assets will not be realized. The Company has not established a valuation allowance as of September 30, 2025 or December 31, 2024.
Tax benefits from an uncertain tax position are recognized 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 benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period it is recognized. See Note 12 for additional information.
Tax-related interest charges are recorded as interest expense and any tax-related penalties as other expense in the condensed consolidated statements of operations of which there have been none to date.
The Company is also subject to Texas Margin Tax. The Company realized a benefit of $
Segments. The Company is an independent energy company engaged in the exploration, development and production of crude oil and natural gas. The Company’s crude oil and natural gas exploration and production activities are solely focused in the U.S., specifically the Midland Basin portion of the Permian Basin in West Texas. For financial reporting purposes, the Company aggregates its operations into one reporting segment due to the similar geographic location and nature of the operations.
The Company’s President and Chief Executive Officer is the chief operating decision maker (“CODM”). To assess the performance of our assets, the CODM uses net (loss) income. We believe net (loss) income provides information useful in assessing our operating and financial performance across periods.
The following table reflects the Company’s net (loss) income, assets and capital expenditures for the Company’s one reporting segment for the time periods presented:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
|
2025 |
2024 |
2025 |
2024 |
|||||||||||||
|
Total operating revenues |
$ | $ | $ | $ | ||||||||||||
|
Lease operating expenses |
||||||||||||||||
|
Production and ad valorem taxes |
||||||||||||||||
|
Expensed workover costs |
||||||||||||||||
|
Total significant expenses |
||||||||||||||||
|
Depletion, depreciation and amortization |
||||||||||||||||
|
General and administrative expenses, including stock-based comp |
||||||||||||||||
|
Interest expense, net |
||||||||||||||||
|
Provision for income taxes |
( |
) | ||||||||||||||
|
Other segment items (1) |
( |
) | ||||||||||||||
|
Total expenses |
||||||||||||||||
|
Net (loss) income |
$ | ( |
) | $ | $ | $ | ||||||||||
|
Total assets |
$ | $ | $ | $ | ||||||||||||
|
Capital costs incurred, including acquisitions |
$ | $ | $ | $ | ||||||||||||
|
(1) |
|
Recently adopted accounting pronouncements. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures,” which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid. This ASU is effective for the Company prospectively to all annual periods beginning after December 15, 2024, and interim reporting periods beginning after December 15, 2025. While the adoption of this ASU will modify the Company’s disclosures, it will not have an impact on the Company’s condensed consolidated balance sheets, condensed consolidated statements of operations or condensed consolidated statements of cash flows in its condensed consolidated financial statements.
New accounting pronouncements not yet adopted. In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Topic 220): Disaggregation of Income Statement Expenses. The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation and amortization recognized as part of crude oil and natural gas producing activities and employee compensation. This ASU is effective for the Company to all annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. While the adoption of this ASU will modify the Company’s disclosures, it will not have an impact on the Company's condensed consolidated balance sheets, condensed consolidated statements of operations or condensed consolidated statements of cash flows in its condensed consolidated financial statements.
The Company considers the applicability and the impact of all ASUs. ASUs were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.
NOTE 3. Acquisitions and Divestitures
Acquisitions. During the nine months ended September 30, 2025 and 2024, the Company incurred a total of $
Divestitures. During the nine months ended September 30, 2025, the Company sold various non-core non-operated working interests in certain producing properties outside of our core areas for total proceeds of $
NOTE 4. Fair Value Measurements
The Company determines fair value based on the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.
The three input levels of the fair value hierarchy are as follows:
|
● |
Level 1 – quoted prices for identical assets or liabilities in active markets. |
|
● |
Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. |
|
● |
Level 3 – unobservable inputs for the asset or liability, typically reflecting management’s estimate of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore, determined using model-based techniques, including discounted cash flow models. |
Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis as of September 30, 2025 and December 31, 2024 are as follows (in thousands):
|
As of September 30, 2025 |
||||||||||||||||
|
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total |
|||||||||||||
|
Assets: |
||||||||||||||||
|
Commodity price derivatives – current |
$ | $ | $ | $ | ||||||||||||
|
Commodity price derivatives – noncurrent |
||||||||||||||||
|
Total assets |
||||||||||||||||
|
Liabilities: |
||||||||||||||||
|
Commodity price derivatives – current |
||||||||||||||||
|
Commodity price derivatives – noncurrent |
||||||||||||||||
|
Total liabilities |
||||||||||||||||
|
Total recurring fair value measurements, net |
$ | $ | $ | $ | ||||||||||||
|
As of December 31, 2024 |
||||||||||||||||
|
Quoted Prices in Active Markets for Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total |
|||||||||||||
|
Assets: |
||||||||||||||||
|
Commodity price derivatives – current |
$ | $ | $ | $ | ||||||||||||
|
Liabilities: |
||||||||||||||||
|
Commodity price derivatives – current |
||||||||||||||||
|
Total recurring fair value measurements, net |
$ | $ | $ | $ | ||||||||||||
Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil swap contracts, costless collars and basis swaps and natural gas swap contracts. The Company measures derivatives using an industry-standard pricing model that is provided by the counterparties. The inputs utilized in the third-party discounted cash flow and option-pricing models for valuing commodity price derivatives include forward prices for crude oil, contracted volumes, volatility factors and time to maturity, which are considered Level 2 inputs.
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Specifically, (i) stock-based compensation is measured at fair value on the date of grant based on Level 1 inputs for restricted stock awards or Level 2 inputs for stock option awards based upon market data, (ii) the estimates and fair value measurements used for the evaluation of proved property for potential impairment using Level 3 inputs based upon market conditions in the area and (iii) asset retirement obligations are measured at estimated fair value on the date the liabilities are incurred using Level 3 inputs based on expected future costs to retire the assets, market conditions and estimated lives of the assets. The Company assesses the recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can 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 impaired or held for sale. The Company did not record any impairments to proved or unproved crude oil and natural gas properties for the periods presented in the accompanying condensed consolidated financial statements.
Financial instruments not carried at fair value. As of September 30, 2025 and December 31, 2024, the Company has financial instruments consisting primarily of cash and cash equivalents, accounts receivable, accounts payable, long-term debt (specifically the Term Loan Credit Agreement and Senior Credit Facility Agreement), and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities.
NOTE 5. Derivative Financial Instruments
The Company primarily utilizes commodity swap contracts and costless collars to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s capital budgeting and expenditure plans, (iii) protect the Company’s commitments under the Term Loan Credit Agreement and Senior Credit Facility Agreement and (iv) support the payment of contractual obligations.
The following table summarizes the effect of derivative instruments on the Company’s condensed consolidated statements of operations (in thousands):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
|
2025 |
2024 |
2025 |
2024 |
|||||||||||||
|
Noncash derivative gain (loss), net |
$ |
$ |
$ | $ | ( |
) | ||||||||||
|
Cash receipts (payments) on settled derivatives, net |
( |
) | ( |
) | ||||||||||||
|
Derivative gain (loss), net |
$ | $ | $ | $ | ( |
) | ||||||||||
Crude oil production derivatives. The Company sells its crude oil production at the lease and the sales contracts governing such crude oil production are tied directly to, or are correlated with, NYMEX WTI Cushing and Argus WTI Midland crude oil prices. As such, the Company primarily uses NYMEX WTI Cushing derivative contracts as well as Argus WTI Midland basis swaps from time to time to manage future crude oil price volatility. The Argus WTI Midland basis differential represents the amount of premium to NYMEX WTI Cushing.
The Company’s outstanding NYMEX WTI Cushing and Argus WTI Midland crude oil derivative instruments as of September 30, 2025 and the weighted average crude oil prices and premiums payable per barrel for those contracts are as follows:
|
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: |
|||||||||||||||||||||
|
Oct – Dec |
2025 |
Swap |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Oct – Dec |
2025 |
Basis Swap |
Argus WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Oct – Dec |
2025 |
Costless Collar |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Jan – Mar |
2026 |
Swap |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Jan – Mar |
2026 |
Costless Collar |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Apr – Jun |
2026 |
Swap |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Apr – Jun |
2026 |
Costless Collar |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Jul – Sep |
2026 |
Swap |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Jul – Sep |
2026 |
Costless Collar |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Oct – Dec |
2026 |
Swap |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Oct – Dec |
2026 |
Costless Collar |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Jan – Mar |
2027 |
Swap |
WTI Cushing |
$ | $ | $ | |||||||||||||||
|
Jan – Mar |
2027 |
Costless Collar |
WTI Cushing |
$ | $ | $ | |||||||||||||||
Natural gas production derivatives. The Company sells its natural gas production at the tailgate of the gas processing plants and the sales contracts governing such natural gas production are correlated with HH natural gas prices. As such, the Company primarily uses HH derivative contracts to manage future natural gas price volatility.
The Company’s outstanding HH natural gas derivative instruments as of September 30, 2025 and the weighted average natural gas prices per MMBtu for those contracts are as follows:
|
Settlement Month |
Settlement Year |
Type of Contract |
MMBtu Per Day |
Index |
Price per MMBtu |
||||||||
|
Natural Gas: |
|||||||||||||
|
Oct – Dec |
2025 |
Swap |
HH |
$ |
|||||||||
|
Jan – Mar |
2026 |
Swap |
HH |
$ |
|||||||||
|
Apr – Jun |
2026 |
Swap |
HH |
$ |
|||||||||
|
Jul – Sep |
2026 |
Swap |
HH |
$ |
|||||||||
|
Oct – Dec |
2026 |
Swap |
HH |
$ |
|||||||||
|
Jan – Mar |
2027 |
Swap |
HH |
$ |
|||||||||
The Company uses credit and other financial criteria to evaluate the credit standings of, and to select, counterparties to its derivative financial instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative financial instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.
Net derivative assets associated with the Company’s open commodity derivative instruments by counterparty are as follows (in thousands):
|
As of September 30, 2025 |
||||
|
Fifth Third Bank, National Association |
$ | |||
|
Macquarie Bank Limited |
||||
|
Mercuria Energy Trading SA |
||||
|
J. Aron & Company LLC |
||||
| $ | ||||
NOTE 6. Exploratory/Extension Well Costs
The Company capitalizes exploratory/extension wells and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company’s capitalized exploratory/extension well and project costs are included in proved properties in the condensed consolidated balance sheets. If the exploratory/extension well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.
The changes in capitalized exploratory/extension well costs are as follows (in thousands):
|
Nine Months Ended September 30, 2025 |
||||
|
Beginning capitalized exploratory/extension well costs |
$ | |||
|
Additions to exploratory/extension well costs |
||||
|
Reclassification to proved properties |
( |
) |
||
|
Exploratory/extension well costs charged to exploration and abandonment expense |
||||
|
Ending capitalized exploratory/extension well costs |
$ | |||
All capitalized exploratory/extension well costs have been capitalized for less than one year based on the date of drilling other than approximately $
NOTE 7. Long-Term Debt
The components of long-term debt, including the effects of debt issuance costs, are as follows (in thousands):
|
September 30, 2025 |
December 31, 2024 |
|||||||
|
Term Loan Credit Agreement due 2028 |
$ | $ | ||||||
|
Senior Credit Facility Agreement due 2028 |
||||||||
|
Debt issuance costs, net (a) |
( |
) | ( |
) | ||||
|
Discounts, net (b) |
( |
) | ||||||
|
Total debt |
||||||||
|
Less current maturities of long-term debt |
( |
) | ( |
) | ||||
|
Long-term debt, net |
$ | $ | ||||||
|
(a) |
|
|
(b) |
|
Term Loan Credit Agreement. On September 12, 2023, the Company entered into a Term Loan Credit 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”) in an aggregate principal amount of $
The Term Loan Credit Agreement, as amended, also contains certain financial covenants, consisting of (i) an asset coverage ratio that may not be less than
The Term Loan Credit Agreement contains customary mandatory prepayments, in addition to quarterly scheduled amortization payments of $
Collateral Agency Agreement. On September 12, 2023, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) with Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA, as initial first-out representative, which was later joined by Fifth Third Bank, National Association, as successor first-out representative.
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 holders of “first-out” obligations and obligations under the Term Loan Credit Agreement) to receive, hold, administer and distribute proceeds of the collateral and to enforce the Security Documents. Under the terms of the Collateral Agency Agreement, proceeds of collateral are first distributed to holders of “first-out” obligations, including certain hedging and cash management obligations and obligations under the Senior Credit Facility Agreement but excluding certain “excess” first-out obligations, and second to holders of obligations under the Term Loan Credit Agreement.
Senior Credit Facility Agreement. On November 1, 2023, the Company entered into a credit agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and as the collateral agent, together with a number of other banks and financial institutions party thereto, to establish a senior revolving credit facility (“Senior Credit Facility Agreement”). The Senior Credit Facility Agreement has aggregate maximum commitments of $
The Term Loan Credit Agreement and the Senior Credit Facility Agreement have hedging requirements to which the Company adheres.
NOTE 8. Asset Retirement Obligations
The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and remediation of related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.
Asset retirement obligations activity is as follows (in thousands):
|
Nine Months Ended September 30, 2025 |
||||
|
Beginning asset retirement obligations |
$ | |||
|
Liabilities incurred from new wells |
||||
|
Liabilities settled and divested |
( |
) | ||
|
Accretion of discount |
||||
|
Ending asset retirement obligations |
$ | |||
As of September 30, 2025 and December 31, 2024, all asset retirement obligations are considered noncurrent and classified as such in the accompanying condensed consolidated balance sheets.
NOTE 9. Incentive Plans
401(k) Plan. The HighPeak Energy Employees, Inc 401(k) Plan (the “401(k) Plan”) is a defined contribution plan established under Section 401 of the Internal Revenue Code of 1986, as amended (the “Code”). All regular full-time and part-time employees of the Company are eligible to participate in the 401(k) Plan after three continuous months of employment with the Company. Participants may contribute up to
Long-Term Incentive Plan. The Company’s Second Amended & Restated Long Term Incentive Plan (“LTIP”) provides for the grant of stock options, restricted stock, stock awards, dividend equivalents, cash awards and substitute awards to officers, employees, directors and consultants of the Company. The number of shares available for grant pursuant to awards under the LTIP as of September 30, 2025 and December 31, 2024 are as follows:
|
September 30, 2025 |
December 31, 2024 |
|||||||
|
Approved and authorized shares |
||||||||
|
Shares subject to awards issued under plan |
( |
) |
( |
) |
||||
|
Shares available for future grant |
||||||||
Stock options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021, May 4, 2022, August 15, 2022 and July 21, 2023. Stock-based compensation expense related to the Company’s stock option awards for the nine months ended September 30, 2025 and 2024 was a negative $
The Company estimates the fair value of stock options granted on the grant date using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company approved an extension of the expiration term for certain outstanding stock options, lengthening the window to exercise those awards, and the table below reflects such extension. The expected term of options granted was determined based on the simplified method of the midpoint between the vesting dates and the contractual term of the options. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant and the volatility was based on the volatility of either an index of exploration and production crude oil and natural gas companies or on a peer group of companies with similar characteristics of the Company on the date of grant since the Company had minimal or did not have any trading history. More detailed stock options activity and details are as follows:
|
Stock Options |
Average Exercise Price |
Remaining Term in Years |
Intrinsic Value (in thousands) |
|||||||||||||
|
Outstanding at December 31, 2023 |
$ | $ | ||||||||||||||
|
Forfeitures |
( |
) | $ | |||||||||||||
|
Outstanding at December 31, 2024 |
$ | $ | ||||||||||||||
|
Forfeitures |
( |
) |
$ | |||||||||||||
|
Outstanding at September 30, 2025 |
$ | $ | ||||||||||||||
|
Vested at December 31, 2024 |
$ | $ | ||||||||||||||
|
Exercisable at December 31, 2024 |
$ | $ | ||||||||||||||
|
Vested at September 30, 2025 |
$ | $ | ||||||||||||||
|
Exercisable at September 30, 2025 |
$ | $ | ||||||||||||||
Restricted stock issued to employee members of the Board and certain employees. A total of
Stock issued to outside directors. A total of
NOTE 10. Commitments and Contingencies
Leases. The Company follows ASC Topic 842, “Leases” to account for its operating and finance leases. Therefore, as of September 30, 2025 the Company had right-of-use assets totaling $
|
September 30, 2025 |
||||
|
Remainder of 2025 |
$ | |||
|
2026 |
||||
|
2027 |
||||
|
Total |
||||
|
Less present value discount |
( |
) | ||
|
Present value of lease liabilities |
$ | |||
Legal actions. From time to time, the Company may be a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable, and the amount of the loss can be reasonably estimated.
Indemnifications. The Company has agreed to indemnify its directors, officers and certain employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
Environmental. Environmental expenditures that relate to an existing condition caused by past operations and have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs.
Crude oil delivery commitments. In September 2024, the Company entered into an amended and restated crude oil marketing contract with DK Trading & Supply, LLC (“Delek”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from the majority of its horizontal wells in Flat Top and Signal Peak where DKL is continually expanding their crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries. The contract contains a minimum volume commitment commencing May 2024 that totals $
Natural gas gathering and treating agreement. In June 2024, the Company entered into a natural gas gathering and treating agreement to gather certain natural gas in its Signal Peak area. Pursuant to said agreement, the Company has agreed to fund certain aid-in-construction costs totaling $
Power contracts. In June 2022, the Company entered into a contract to receive a block of electric power at an attractive variable rate, which fluctuates based on the usage by the Company through May 31, 2032. In March 2024, the Company entered into a contract to receive an additional block of electric power under similar terms. In conjunction with these contracts, the Company has a $
Sand commitments. The Company was party to an amended agreement whereby it agreed to purchase at least
NOTE 11. Major Customers
Delek accounted for approximately
NOTE 12. Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and Texas margin tax. The Company and its subsidiaries file a U.S. federal corporate income tax return on a consolidated basis.
The Company’s provision for income taxes attributable to (loss) income before income taxes consisted of the following (in thousands):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
|
2025 |
2024 |
2025 |
2024 |
|||||||||||||
|
Current income tax (benefit) expense: |
||||||||||||||||
|
Federal |
$ | ( |
) | $ | $ | ( |
) | $ | ||||||||
|
State |
( |
) | ( |
) | ||||||||||||
|
Total current income tax (benefit) expense |
( |
) | ( |
) | ||||||||||||
|
Deferred income tax (benefit) expense: |
||||||||||||||||
|
Federal |
( |
) | ||||||||||||||
|
State |
||||||||||||||||
|
Deferred income tax (benefit) expense |
( |
) | ||||||||||||||
|
Total provision for income taxes |
$ | ( |
) | $ | $ | $ | ||||||||||
The reconciliation between the provision for income taxes computed by multiplying pre-tax income by the U.S. federal statutory rate and the reported amounts of provision for income taxes is as follows (in thousands, except rate):
| Three Months Ended
September 30, |
Nine Months Ended
September 30, |
|||||||||||||||
|
2025 |
2024 |
2025 |
2024 |
|||||||||||||
|
Provision for income taxes at U.S. federal statutory rate |
$ | ( |
) | $ | $ | $ | ||||||||||
| Limited tax benefit due to compensation limitations | ||||||||||||||||
|
State deferred income taxes |
||||||||||||||||
|
Other, net |
( |
) | ( |
) | ||||||||||||
|
Provision for income taxes |
$ | ( |
) | $ | $ | $ | ||||||||||
|
Effective income tax rate |
% | % | % | % | ||||||||||||
The effective income tax rate differs from the U.S. statutory rate of
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities were as follows as of September 30, 2025 and December 31, 2024 (in thousands):
|
September 30, 2025 |
December 31, 2024 |
|||||||
|
Deferred tax assets: |
||||||||
|
Interest expense limitations |
$ | $ | ||||||
|
Net operating loss carryforwards |
||||||||
|
Stock-based compensation |
||||||||
|
Other |
||||||||
|
Less: Valuation allowance |
||||||||
|
Deferred tax assets |
||||||||
|
Deferred tax liabilities: |
||||||||
|
Crude oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes |
( |
) | ( |
) | ||||
|
Unrecognized derivative gains, net |
( |
) | ( |
) | ||||
|
Deferred tax liabilities |
( |
) | ( |
) | ||||
|
Net deferred tax liabilities |
$ | ( |
) | $ | ( |
) | ||
As required by ASC Topic 740, “Income Taxes,” (“ASC 740”) the Company uses reasonable judgments and makes estimates and assumptions related to evaluating the probability of uncertain tax positions. The Company bases its estimates and assumptions on the potential liability related to an assessment of whether the income tax position will “more likely than not” be sustained in an income tax audit. Based on that analysis, the Company believes the Company has not taken any material uncertain tax positions, and therefore has not recorded an income tax liability related to uncertain tax positions. However, if actual results materially differ, the Company’s effective income tax rate and cash flows could be affected in the period of discovery or resolution. The Company also reviews the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company’s deferred tax assets and records a valuation allowance when the Company believes that a portion or all the deferred tax assets may not be realized. If the Company is unable to realize the expected future benefits of its deferred tax assets, the Company is required to provide a valuation allowance. The Company uses its history and experience, overall profitability, future management plans, tax planning strategies, and current economic information to evaluate the amount of valuation allowance to record. As of September 30, 2025 and December 31, 2024, the Company had not recorded a valuation allowance for deferred tax assets arising from its operations because the Company believed they met the “more likely than not” criteria as defined by the recognition and measurement provisions of ASC 740. The Company reversed a portion of its deferred tax asset related to stock-based compensation based on the assumption that the tax deduction will be subject to IRC Section 162(m) limits when the restricted stock vests. IRC Section 162(m) limits compensation deductions to $
On July 4, 2025, the “One Big Beautiful Bill” (“OBBB”) was enacted. The OBBB is a significant piece of legislation that includes significant changes to federal tax policy, environmental funding, and energy development regulations. Key provisions relevant to the crude oil and natural gas industry include (i) tax policy changes that extend and expand components of the 2017 Tax Cuts and Jobs Act, (ii) the introduction of fee and royalty-related provisions aimed at reducing financial and administrative burdens on domestic energy producers, and (iii) the recission of environmental funding which rescinds unobligated balances from several programs originally authorized under the Inflation Reduction Act of 2022 (“IRA 2022”), including the Greenhouse Gas Reduction Fund and climate justice block grants. The Company is currently evaluating the full impact of the OBBB on the Company’s condensed consolidated balance sheets, condensed consolidated statements of operations and condensed consolidated statements of cash flows in its condensed consolidated financial statements.
The Company is also subject to Texas margin tax. The Company realized a benefit of $
In addition to the provision for income taxes, the Company recognized and paid an excise tax of 1% on its stock repurchases during the nine months ended September 30, 2025 and the year ended December 31, 2024 of zero and $
NOTE 13. (Losses) Earnings Per Share
The Company uses the two-class method of calculating (losses) earnings per share because certain of the Company’s stock-based awards qualify as participating securities.
The Company’s basic (losses) earnings per share attributable to common stockholders is computed as (i) net (loss) income as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted (losses) earnings per share attributable to common stockholders is computed as (i) basic (losses) earnings attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding.
The following table reconciles the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the three and nine months ended September 30, 2025 and 2024 under the two-class method (in thousands):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
|
2025 |
2024 |
2025 |
2024 |
|||||||||||||
|
Net (loss) income as reported |
$ | ( |
) | $ | $ | $ | ||||||||||
|
Participating basic earnings (a) |
( |
) |
( |
) |
( |
) | ( |
) | ||||||||
|
Basic (losses) earnings attributable to common stockholders |
( |
) | ||||||||||||||
|
Reallocation of participating earnings |
||||||||||||||||
|
Diluted net (loss) income attributable to common stockholders |
$ | ( |
) | $ | $ | $ | ||||||||||
|
Basic weighted average shares outstanding |
||||||||||||||||
|
Dilutive warrants and unvested stock options |
||||||||||||||||
|
Dilutive unvested restricted stock |
||||||||||||||||
|
Diluted weighted average shares outstanding |
||||||||||||||||
|
(a) |
|
The calculation for weighted average shares reflects shares outstanding over the reporting period based on the actual number of days the shares were outstanding.
NOTE 14. Stockholders’ Equity
Stock Repurchase Program. In February 2024, the Company’s board of directors approved a common stock repurchase program to acquire up to $
Issuance of Common Stock. During the nine months ended September 30, 2025 and 2024, the Company issued
Dividends and Dividend Equivalents. In August 2025, the Board declared a quarterly dividend of $
In May 2025, the Board declared a quarterly dividend of $
In February 2025, the Board declared a quarterly dividend of $
In August 2024, the Board declared a quarterly dividend of $
In May 2024, the Board declared a quarterly dividend of $
In February 2024, the Board declared a quarterly dividend of $
Outstanding securities. As of September 30, 2025 and December 31, 2024, the Company had
NOTE 15. Subsequent Events
Dividends and dividend equivalents. In November 2025, the Board approved a quarterly dividend of $
PART I. FINANCIAL INFORMATION
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, 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 September 30, 2025, the assets consisted of two highly contiguous leasehold positions of approximately 154,650 gross (143,496 net) acres, approximately 70% of which were held by production, with an average working interest of 93%. 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 nine months ended September 30, 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 September 30, 2025, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew and expects to average one to two (1-2) drilling rigs and approximately one (1) frac crew during the remainder of 2025 under our current development plan.
Recent Events
Recent managements changes. In September 2025, Mr. Jack Hightower, the Company’s Chief Executive Officer and Chairman of the board retired and resigned from the board of directors, and our President, Mr. Michael Hollis, was named Interim Chief Executive Officer. Subsequent to quarter end on November 4, 2025, the board named Mr. Hollis, 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 64.7% 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 will distribute 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 Ryan 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. 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 dates were 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.
Dividends and dividend equivalents. In August 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 in dividends being paid in September 2025. 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 September 2025. In addition, the Company accrued an additional combined $31,000 in September 2025 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In addition, in November 2025, the Company’s Board of Directors declared a quarterly dividend of $0.04 per share, or approximately $5.0 million in dividends, to be paid on December 23, 2025, to stockholders of record on December 1, 2025.
Acquisitions and divestitures. During the nine months ended September 30, 2025, the Company incurred a total of $4.5 million in acquisition costs related to lease extensions and to acquire crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas. In addition, during the nine months ended September 30, 2025, the Company received $570,000 in proceeds from the sale of some non-core non-operated properties.
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. This substantial supply boost contributed to a decline in global crude oil prices during the nine months ended September 30, 2025. OPEC+ also emphasized that the production increases could be paused or reversed depending on how market conditions evolve, maintaining flexibility to support price stability. Concurrently, in March 2025, 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, in early April 2025, the current 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. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff applied to China, which the administration increased. The pause was extended to August 1, 2025 based on ongoing negotiations with several trading partners to address U.S. concerns about non-reciprocal trade practices. Furthermore, on July 8, 2025, the United States announced additional sector-specific tariffs, including on copper imports. Concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed further downward pressure on oil prices. With negotiations and countermeasures still ongoing, the situation is fluid, 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 and conflicts in the Middle East have resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by recent conflicts in the Middle East as well as 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, (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.
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 September 30, 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 have continued in the first nine months of 2025 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. Although prices for the commodities produced by our industry improved from historic lows in 2020, 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 and conflicts in the Middle East, 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” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 10, 2025.
Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to average a one to two (1-2) drilling rig program for the remainder of 2025. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. 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 has been retained as a financial advisor with respect to this strategic alternatives process. 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.
Financial and Operating Performance
The Company's financial and operating performance for the three months ended September 30, 2025 included the highlights described below and comparative discussion of related drivers for the three months ended September 30, 2024:
|
• |
Net loss was $18.3 million ($(0.15) per diluted share) for the three months ended September 30, 2025 compared with net income of $49.9 million for three months ended September 30, 2024. The primary components of the $68.3 million decrease in net income include: |
|
• |
a $82.7 million decrease in crude oil, NGL and natural gas revenues due to a 25% decrease in average realized commodity prices per Boe, excluding the effects of derivatives, coupled with a 7% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking; |
|
• |
a $25.4 million loss on extinguishment of debt recognized in the current year period related to the amendment to our Term Loan Credit Agreement in August 2025; |
|
• |
a $25.4 million decrease in the Company’s derivative instruments gain as a result of its crude oil and natural gas commodity contracts entered into and the change in crude oil and natural gas prices thereafter; |
|
• |
a $4.4 million increase in the Company’s general and administrative expenses primarily attributable to legal and severance costs related to the retirement of the Company’s Chief Executive Officer in September 2025 and higher wages and benefits as well as an increase in professional fees, all primarily as a result of the growth of the Company; |
|
• |
a $1.9 million increase in the Company’s exploration and abandonment expenses due to increased plugging and abandonment expenses and abandoned leasehold costs; and |
|
• |
a $1.0 million decrease in the Company’s interest income due to the decrease in average cash on hand, |
partially offset by:
|
• |
a $35.9 million decrease in DD&A expense primarily due to a 21% decrease in the DD&A rate from $28.91 to $22.87 per Boe as a result of a significant increase in proved reserves at the end of 2024 and a 7% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking; |
|
• |
a $19.0 million decrease in the Company’s income tax expense primarily due to a decrease in income before income taxes and a correction in the prior year period related to the reversal of a deferred tax asset related to stock-based compensation; |
|
• |
a $5.4 million decrease in the Company’s interest expense primarily as a result of a decrease in the principal balance due to quarterly amortization payments, lower discount and debt issuance costs amortization and lower interest rates experienced; |
|
• |
a $5.4 million decrease in the Company’s production and ad valorem tax expense as a result of a decrease in the revenues of the Company ; |
|
• |
a $3.6 million decrease in the Company’s stock-based compensation expense primarily due to the majority of stock-based compensation instruments reaching fully vested status and thus having no further stock-based compensation expense to be recognized; |
|
• |
a $2.1 million decrease in the Company’s crude oil and natural gas production costs primarily as a result of decreased chemical and treating costs related to third party midstream expansions and debottlenecking partially offset by increased expense workover costs with increased well cleanouts and pump changes with our aging well population; and |
|
• |
a $1.2 million decrease in the Company’s other expense primarily as a result of some production facility repairs recognized in the prior year period. |
|
• |
During the three months ended September 30, 2025, average daily sales volumes totaled 47,839 Boepd, compared with 51,346 Boepd during the same period in 2024, a decrease of 7%, primarily due to lower crude oil volumes as a result of decreased activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking. |
|
• |
Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended September 30, 2025 to $65.63, compared with $75.99 for the same period in 2024. Weighted average NGL prices per Bbl decreased during the three months ended September 30, 2025 to $17.40, compared with $21.14 for the same period in 2024. Weighted average natural gas prices per Mcf increased to $1.07 during the three months ended September 30, 2025, compared with $0.42 during the same period in 2024. |
|
• |
Cash provided by operating activities totaled $120.2 million for the three months ended September 30, 2025, compared with $177.1 million for the three months ended September 30, 2024. |
Derivative Financial Instruments
Crude oil derivative financial instrument exposure. As of September 30, 2025, the Company was 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: |
|||||||||||||||||||||
|
Oct – Dec |
2025 |
Swap |
1,800 |
WTI Cushing |
$ | 63.77 | $ | — | $ | — | |||||||||||
|
Oct – Dec |
2025 |
Basis Swap |
20,000 |
Argus WTI Cushing |
$ | 0.97 | $ | — | $ | — | |||||||||||
|
Oct – Dec |
2025 |
Costless Collar |
15,850 |
WTI Cushing |
$ | — | $ | 60.53 | $ | 69.65 | |||||||||||
|
Jan – Mar |
2026 |
Swap |
2,000 |
WTI Cushing |
$ | 63.14 | $ | — | $ | — | |||||||||||
|
Jan – Mar |
2026 |
Costless Collar |
14,350 |
WTI Cushing |
$ | — | $ | 60.58 | $ | 69.92 | |||||||||||
|
Apr – Jun |
2026 |
Swap |
1,000 |
WTI Cushing |
$ | 63.25 | $ | — | $ | — | |||||||||||
|
Apr – Jun |
2026 |
Costless Collar |
12,350 |
WTI Cushing |
$ | — | $ | 59.87 | $ | 66.82 | |||||||||||
|
Jul – Sep |
2026 |
Swap |
1,000 |
WTI Cushing |
$ | 63.25 | $ | — | $ | — | |||||||||||
|
Jul – Sep |
2026 |
Costless Collar |
12,000 |
WTI Cushing |
$ | — | $ | 59.83 | $ | 66.84 | |||||||||||
|
Oct – Dec |
2026 |
Swap |
1,000 |
WTI Cushing |
$ | 63.25 | $ | — | $ | — | |||||||||||
|
Oct – Dec |
2026 |
Costless Collar |
9,800 |
WTI Cushing |
$ | — | $ | 59.80 | $ | 65.31 | |||||||||||
|
Jan – Mar |
2027 |
Swap |
1,000 |
WTI Cushing |
$ | 63.25 | $ | — | $ | — | |||||||||||
|
Jan – Mar |
2027 |
Costless Collar |
8,900 |
WTI Cushing |
$ | — | $ | 59.78 | $ | 65.24 | |||||||||||
Natural gas derivative financial instrument exposure. As of September 30, 2025, the Company was 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: |
|||||||||||||
|
Oct – Dec |
2025 |
Swap |
30,000 |
HH |
$ | 4.43 | |||||||
|
Jan – Mar |
2026 |
Swap |
30,000 |
HH |
$ | 4.39 | |||||||
|
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 September 30, 2025 was a net asset of $19.6 million which is included in current and noncurrent assets and noncurrent liabilities on the Company’s consolidated balance sheet as of September 30, 2025. During the nine months ended September 30, 2025, the Company recognized a net derivative gain of $25.4 million, including a $17.4 million mark-to-market gain and $8.0 million in net monthly settlement receipts.
Operations and Drilling Highlights
Average daily crude oil, NGL and natural gas sales volumes are as follows:
|
Nine Months Ended September 30, 2025 |
||||
|
Crude Oil (Bbls) |
34,552 | |||
|
NGL (Bbls) |
7,824 | |||
|
Natural Gas (Mcf) |
44,862 | |||
|
Total (Boe) |
49,853 | |||
The Company’s liquids production was 85% of total production on a Boe basis for the nine months ended September 30, 2025.
Costs incurred are as follows (in thousands):
|
Nine Months Ended September 30, 2025 |
||||
|
Unproved property acquisition costs |
$ | 4,475 | ||
|
Proved acquisition costs |
— | |||
|
Total acquisitions |
4,475 | |||
|
Development costs |
290,049 | |||
|
Exploration costs |
101,850 | |||
|
Total finding and development costs |
396,374 | |||
|
Asset retirement obligations |
2,747 | |||
|
Total costs incurred |
$ | 399,121 | ||
The following table sets forth the total number of horizontal producing wells drilled and completed during the nine months ended September 30, 2025:
|
Drilled |
Completed |
|||||||||||||||
|
Gross |
Net |
Gross |
Net |
|||||||||||||
|
Flat Top area |
33 | 32.8 | 36 | 35.7 | ||||||||||||
|
Signal Peak area |
2 | 2.0 | — | — | ||||||||||||
|
Total |
35 | 34.8 | 36 | 35.7 | ||||||||||||
As of September 30, 2025, HighPeak Energy was developing its properties using one (1) drilling rig and one (1) frac crew. The continued threat of a potential recession, commodity-specific tariffs and the possibility of trade wars, the scope, duration and magnitude of the direct and indirect effects of pandemics, the ongoing war between Russia and Ukraine and conflicts in the Middle East and the production cuts and reversals thereof announced by OPEC+ are continuing to evolve and in ways that are difficult or impossible to anticipate. Given the dynamic nature of this situation, the Company is maintaining flexibility with its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed regularly.
During the nine months ended September 30, 2025, the Company successfully completed and placed on production thirty-six (36) gross (35.7 net) horizontal wells and completed and placed in operation two (2) gross (2.0 net) salt-water disposal wells. As of September 30, 2025, the Company had seventeen (17) gross (17.0 net) horizontal wells that had been drilled and were in various stages of completion. In addition, as of September 30, 2025, the Company was in the process drilling two (2) gross (2.0 net) horizontal wells.
Results of Operations
Three and Nine Months Ended September 30, 2025
Crude Oil, NGL and natural gas revenues.
Average daily sales volumes are as follows:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Crude Oil (Bbls) |
31,594 | 38,710 | (18 | )% | 34,552 | 38,581 | (10 | )% | ||||||||||||||||
|
NGL (Bbls) |
8,279 | 6,497 | 27 | % | 7,824 | 5,890 | 33 | % | ||||||||||||||||
|
Natural Gas (Mcf) |
47,795 | 36,831 | 30 | % | 44,862 | 32,418 | 38 | % | ||||||||||||||||
|
Total (Boe) |
47,839 | 51,346 | (7 | )% | 49,853 | 49,874 | (0 | )% | ||||||||||||||||
The decrease in average daily Boe sales volumes for the three and nine months ended September 30, 2025, compared with the same periods in 2024 was primarily due to lower crude oil sales volumes as a result of reduced activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.
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 realized prices, excluding the effects of derivatives, are as follows:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Crude Oil per Bbl |
$ | 65.63 | $ | 75.99 | (14 | )% | $ | 67.20 | $ | 78.29 | (14 | )% | ||||||||||||
|
NGL per Bbl |
$ | 17.40 | $ | 21.14 | (18 | )% | $ | 20.55 | $ | 21.96 | (6 | )% | ||||||||||||
|
Natural Gas per Mcf |
$ | 1.07 | $ | 0.42 | 155 | % | $ | 1.61 | $ | 0.58 | 178 | % | ||||||||||||
|
Total per Boe |
$ | 42.91 | $ | 57.49 | (25 | )% | $ | 47.52 | $ | 61.07 | (22 | )% | ||||||||||||
Revenue Variance Analysis.
The following table illustrates the variance in revenues attributable to prices versus volumes (in thousands except prices and percentages):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Total operating revenues |
$ | 188,862 | $ | 271,578 | (30 | )% | $ | 646,710 | $ | 834,608 | (23 | )% | ||||||||||||
|
Average daily sales volumes (Boe) |
47,839 | 51,346 | (7 | )% | 49,853 | 49,874 | (0 | )% | ||||||||||||||||
|
Realized price per Boe |
$ | 42.91 | $ | 57.49 | (25 | )% | $ | 47.52 | $ | 61.07 | (22 | )% | ||||||||||||
|
Revenue change from prior period due to prices |
$ | (68,873 | ) | (25 | )% | $ | (185,167 | ) | (22 | )% | ||||||||||||||
|
Revenue change from prior period due to volumes |
(13,845 | ) | (5 | )% | (2,642 | ) | (0 | )% | ||||||||||||||||
|
Rounding |
2 | 0 | % | (89 | ) | (0 | )% | |||||||||||||||||
|
Total change from prior period revenues |
$ | (82,716 | ) | $ | (187,898 | ) | ||||||||||||||||||
As detailed above, the decrease in total operating revenues for the three and nine months ended September 30, 2025 compared to the same periods in 2024 is the result of a 25% and 22% decrease in average realized price per Boe, respectively, plus 5% and 0% decrease in average daily sales volumes, respectively, primarily as a result of lower crude oil sales volumes as a result of reduced activity and natural decline partially offset by increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.
Crude Oil and natural gas production costs.
Crude oil and natural gas production costs in total and per Boe are as follows (in thousands, except percentages and per Boe amounts):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Crude oil and natural gas production costs |
$ | 33,312 | $ | 35,413 | (6 | )% | $ | 102,600 | $ | 98,482 | 4 | % | ||||||||||||
|
Crude oil and natural gas production costs per Boe (excluding expense workovers) |
$ | 6.57 | $ | 7.12 | (8 | )% | $ | 6.58 | $ | 6.74 | (2 | )% | ||||||||||||
|
Workover expense |
$ | 1.00 | $ | 0.38 | 163 | % | $ | 0.96 | $ | 0.47 | 104 | % | ||||||||||||
The decrease in crude oil and natural gas production costs for the three months ended September 30, 2025 compared to the same period in 2024 can be attributed primarily to decreased chemical and treating costs related to third party midstream expansions and debottlenecking partially offset by increased expense workover costs with increased well cleanouts and pump changes. The increase in crude oil and natural gas production costs for the nine months ended September 30, 2025 compared to the same period in 2024 can be attributed primarily to increased expense workover costs with increased well cleanouts and pump changes, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper costs also due to the increased number of wells operated partially offset by decreased chemical and treating costs related to third party midstream expansions and debottlenecking partially offset by increased expense workover costs with increased well cleanouts and pump changes with our aging well population.
Production and ad valorem taxes.
Production and ad valorem taxes are as follows (in thousands, except percentages):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Production and ad valorem taxes |
$ | 10,016 | $ | 15,412 | (35 | )% | $ | 37,559 | $ | 46,410 | (19 | )% | ||||||||||||
In general, production taxes and ad valorem taxes are directly related to commodity sales volumes and price changes; however, Texas ad valorem taxes are based upon an asset valuation assessed by the state as of January 1 of that particular year based on prior year commodity prices, whereas production taxes are based upon current year sales revenues at current commodity prices. Overall, the decrease in production and ad valorem taxes during the three and nine months ended September 30, 2025 compared to the same periods in 2024 can be attributed primarily to the 25% and 22% decrease in overall commodity prices received, respectively, coupled with the aforementioned 7% and 0% decrease in sales volumes, respectively.
Production and ad valorem taxes per Boe are as follows:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Production taxes per Boe |
$ | 2.23 | $ | 2.83 | (14 | )% | $ | 2.43 | $ | 2.99 | (19 | )% | ||||||||||||
|
Ad valorem taxes per Boe |
$ | 0.05 | $ | 0.43 | (88 | )% | $ | 0.33 | $ | 0.41 | (20 | )% | ||||||||||||
The decrease in production taxes per Boe for the three and nine months ended September 30, 2025, compared with the same periods in 2024 can be attributed primarily to the lower commodity prices received thus far in 2025. The change in ad valorem taxes per Boe for the three and nine months ended September 30, 2025, compared with the same periods in 2024, was primarily due to an overaccrual during the early part of 2025 that was adjusted during the three months ended September 30, 2025 and overall for the year, taxes have decreased due to the assessments being lower based on lower overall prices in 2024 as compared to 2023 which is how taxes are assessed.
Exploration and abandonments expense.
Exploration and abandonment expense details are as follows (in thousands, except percentages):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Plugging and abandonment expense |
$ | 1,482 | $ | 157 | 844 | % | $ | 2,076 | $ | 346 | 500 | % | ||||||||||||
|
Abandoned leasehold costs |
532 | — | 100 | % | 798 | 35 | 21,800 | % | ||||||||||||||||
|
Geologic and geophysical personnel costs |
264 | 205 | 29 | % | 777 | 641 | 21 | % | ||||||||||||||||
|
Geologic and geophysical data costs |
— | — |
n/m |
— | 5 |
n/m |
||||||||||||||||||
|
Exploration and abandonments expense |
$ | 2,278 | $ | 362 | 529 | % | $ | 3,651 | $ | 1,027 | 256 | % | ||||||||||||
Exploration and abandonment costs increased during the three and nine months ended September 30, 2025 primarily due to increased plugging and abandonment expenses as a result of regulatory requirements and abandoned leasehold costs related to some low value leases in Signal Peak that were not extended due to the fact that they were in low working interest units that were not on the immediate drilling schedule due to the work and cost involved in acquiring enough additional working interest to justify drilling the units.
DD&A expense.
DD&A expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
DD&A expense |
$ | 100,636 | $ | 136,578 | (26 | )% | $ | 311,187 | $ | 395,121 | (21 | )% | ||||||||||||
|
DD&A expense per Boe |
$ | 22.87 | $ | 28.91 | (21 | )% | $ | 22.86 | $ | 28.91 | (21 | )% | ||||||||||||
The decrease in DD&A during the three and nine months ended September 30, 2025 is primarily due to a decrease in the DD&A rate primarily attributable to increased proved reserves coupled with the decreased production volumes.
General and administrative expense.
General and administrative expense and general and administrative expense per Boe as well as stock-based compensation expense are as follows (in thousands, except percentages and per Boe amounts):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
General and administrative expense |
$ | 9,329 | $ | 4,971 | 88 | % | $ | 21,345 | $ | 14,391 | 48 | % | ||||||||||||
|
General and administrative expense per Boe |
$ | 2.12 | $ | 1.05 | 102 | % | $ | 1.57 | $ | 1.05 | 50 | % | ||||||||||||
|
Stock-based compensation expense |
$ | 177 | $ | 3,753 | (95 | )% | $ | 442 | $ | 11,326 | (96 | )% | ||||||||||||
The increase in general and administrative expense in total and per Boe for the three and nine months ended September 30, 2025 compared to the same periods in 2024 is primarily a result of severance and legal costs paid related to the retirement of our former Chief Executive Officer who retired in September 2025 which totaled approximately $3.4 million, increased wages and benefits in addition to higher professional services costs related to the growth of the Company. The decrease in stock-based compensation expense for the three and nine months ended September 30, 2025 compared to the same periods in 2024 is the result of the Company not issuing any significant stock options or restricted stock in the past couple of years. All stock-based compensation has been fully recognized except for the restricted stock issued to outside directors.
Other expense.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Debt refinancing costs |
$ | 29 | $ | — | 100 | % | $ | 2,518 | $ | — | 100 | % | ||||||||||||
|
Other |
193 | 181 | 7 | % | 193 | 181 | 7 | % | ||||||||||||||||
|
Repairs on production facilities |
— | 1,223 | (100 | )% | — | 3,224 | (100 | )% | ||||||||||||||||
| $ | 222 | $ | 1,404 | (84 | )% | $ | 2,711 | $ | 3,405 | (20 | )% | |||||||||||||
During the three and nine months ended September 30, 2025, the Company incurred approximately $29,000 and $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 three and nine months ended September 30, 2024, the Company incurred approximately $1.2 million and $3.2 million, respectively, in costs related to repairs to production facilities.
Interest expense.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Term Loan Credit Agreement |
$ | 34,722 | $ | 37,828 | (8 | )% | $ | 98,780 | $ | 115,084 | (14 | )% | ||||||||||||
|
Senior Credit Facility Agreement |
469 | 192 | 144 | % | 841 | 536 | 57 | % | ||||||||||||||||
|
Amortization of discount |
835 | 2,479 | (66 | )% | 5,714 | 7,385 | (23 | )% | ||||||||||||||||
|
Amortization of debt issuance costs |
1,124 | 2,080 | (46 | )% | 5,215 | 6,199 | (16 | )% | ||||||||||||||||
| $ | 37,150 | $ | 42,579 | (13 | )% | $ | 110,550 | $ | 129,204 | (14 | )% | |||||||||||||
The decrease in interest expense can be attributed to a lower overall debt balance in 2025 compared with 2024, lower interest rates in 2025 compared with interest rates in 2024, lower amortization of discount and debt issuance costs in 2025 due to the loss on extinguishment of debt recognized during the three and nine months ended September 30, 2025 whereby the unamortized discount and debt issuance costs were expensed upon the closing of the First Term Loan Amendment on August 1, 2025 and fewer calendar days in the nine month period compared to the same period in the prior year.
Gain (loss) on derivative instruments, net.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Noncash gain (loss) on derivative instruments, net |
$ | 3,266 | $ | 33,775 | (90 | )% | $ | 17,444 | $ | (11,514 | ) | n/m | ||||||||||||
|
Cash receipts (payments) on settlement derivatives, net |
3,647 | (1,441 | ) |
n/m |
7,988 | (11,897 | ) |
n/m |
||||||||||||||||
|
Gain (loss) on derivative instruments, net |
$ | 6,913 | $ | 32,334 | (79 | )% | $ | 25,432 | $ | (23,411 | ) |
n/m |
||||||||||||
The Company primarily utilizes commodity swap contracts, costless collars, enhanced collars and deferred premium put option contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (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 interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market gain (loss) and cash settlements relate to crude oil derivative swap contracts, costless collars, enhanced collars and deferred premium put option contracts and natural gas derivative swap contracts.
Loss on extinguishment of debt.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Unamortized discount |
$ | 11,482 | $ | — | 100 | % | $ | 11,482 | $ | — | 100 | % | ||||||||||||
|
Unamortized debt issuance costs |
9,205 | — | 100 | % | 9,205 | — | 100 | % | ||||||||||||||||
|
Premium paid to exiting lenders |
4,750 | — | 100 | % | 4,750 | — | 100 | % | ||||||||||||||||
| $ | 25,437 | $ | — | 100 | % | $ | 25,437 | $ | — | 100 | % | |||||||||||||
On August 1, 2025, the Company entered into the First Term Loan Amendment which, among other things, (i) extended the maturity dates 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.
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||||||||||
|
2025 |
2024 |
% Change |
2025 |
2024 |
% Change |
|||||||||||||||||||
|
Provision for income taxes |
$ | (3,567 | ) | $ | 15,438 | (123 | )% | $ | 14,035 | $ | 31,985 | (56 | )% | |||||||||||
|
Effective income tax rate |
16.3 | % | 23.6 | % | (31 | )% | 24.1 | % | 27.1 | % | (11 | )% | ||||||||||||
The change in provision for income taxes during the three and nine months ended September 30, 2025, compared with the same periods in 2024, was primarily due to the change in income before income taxes and the reversal of a $3.0 million deferred tax asset related to a temporary difference from restricted stock being reclassified to a permanent difference during the 2024 periods. The effective income tax rate differs from the statutory rate primarily due to the certain aforementioned stock-based compensation revision, Texas state margin taxes and other permanent differences between GAAP income and taxable income. See Note 12 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)" 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 2025 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.
2025 capital budget. The Company’s capital budget for 2025 is expected to be in the range of approximately $375 to $405 million for drilling, completion, facilities and equipping crude oil wells plus $40 to $50 million for field infrastructure buildout and other costs and $33 to $35 million on one-time infrastructure expenditures. The 2025 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 nine months ended September 30, 2025 were $391.9 million, including the completion and/or continuation of certain one-time infrastructure projects but excluding acquisitions.
However, there are many factors and consequences beyond the Company’s control impacting our capital budget, such as political and regulatory uncertainties associated with the new Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC or OPEC+, and governments in response to pandemics, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors” in the Company’s Annual Report. 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. Cash flows from operating, investing and financing activities are summarized below (in thousands).
|
Nine Months Ended September 30, |
||||||||||||||||
|
2025 |
2024 |
Change |
% Change |
|||||||||||||
|
Net cash provided by operating activities |
$ | 418,504 | $ | 550,873 | $ | (132,369 | ) | (24 | )% | |||||||
|
Net cash used in investing activities |
$ | (426,804 | ) | $ | (475,827 | ) | $ | 49,023 | (10 | )% | ||||||
|
Net cash provided by (used in) financing activities |
$ | 86,564 | $ | (133,988 | ) | $ | 220,552 | (165 | )% | |||||||
Operating activities. The decrease in net cash flow provided by operating activities for the nine months ended September 30, 2025, compared with 2024, was primarily related to a decrease in discretionary cash flow as a result of a decrease in revenues less operating and general administrative expenses of approximately $190.1 million associated with lower overall commodity prices and lower crude oil production volumes partially offset by increased natural gas and NGL production volumes and increased costs related primarily to increased expense workover costs with increased well cleanouts and pump changes, increased electricity, power and fuel charges with the increased number of wells operated by the Company and increased pumper costs also due to the increased number of wells operated partially offset by changes in operating assets and liabilities that differ from the prior year period.
Investing activities. The decrease in net cash used in investing activities for the nine months ended September 30, 2025, compared with 2024, was primarily due to decreases in additions to crude oil and natural gas properties and acquisitions partially offset by a decrease in working capital related to additions to crude oil and natural gas properties.
Financing activities. The Company's significant financing activities are as follows:
|
• |
Nine months ended September 30, 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 $15.5 million and $1.6 million, respectively, paid debt issuance costs of $7.7 million primarily related to the First Term Loan Amendment and the Second Facility Amendment, paid $4.8 million in premium on extinguishment of debt and paid $3.8 million for tax withholding on vested equity awards related to the retirement of the Company’s Chief Executive Officer. |
|
• |
Nine months ended September 30, 2024: The Company made mandatory payments on its Term Loan Credit Agreement totaling $90.0 million, paid $27.2 million to repurchase 1,849,636 shares of its common stock at an average cost of approximately $14.73 per share, excluding any potential excise taxes, and paid dividends and dividend equivalents of $15.1 million and $1.6 million, respectively. |
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 September 30, 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. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing war between Russia and Ukraine andconflicts in the Middle East. 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 nine months ended September 30, 2025 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $13.5 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis.
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 September 30, 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 $7.4 million. Additionally, as of September 30, 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 $1.5 million.
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, 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 1. Condensed Consolidated Financial Statements (Unaudited)” of this Quarterly 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, they would be entitled to exercise all 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):
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
|
2025 |
2024 |
2025 |
2024 |
|||||||||||||
|
Net (loss) income |
$ | (18,335 | ) | $ | 49,933 | $ | 44,176 | $ | 86,088 | |||||||
|
Interest expense |
37,150 | 42,579 | 110,550 | 129,204 | ||||||||||||
|
Interest and other income |
(1,165 | ) | (2,172 | ) | (2,336 | ) | (6,964 | ) | ||||||||
|
Provision for income taxes |
(3,567 | ) | 15,438 | 14,035 | 31,985 | |||||||||||
|
Depletion, depreciation and amortization |
100,636 | 136,578 | 311,187 | 395,121 | ||||||||||||
|
Accretion of discount |
285 | 241 | 785 | 722 | ||||||||||||
|
Exploration and abandonment expense |
2,278 | 362 | 3,651 | 1,027 | ||||||||||||
|
Stock based compensation |
177 | 3,753 | 442 | 11,326 | ||||||||||||
|
Derivative related noncash activity |
(3,266 | ) | (33,775 | ) | (17,444 | ) | 11,514 | |||||||||
|
Loss on extinguishment of debt |
25,437 | — | 25,437 | — | ||||||||||||
|
Other expense |
222 | 1,404 | 2,711 | 3,405 | ||||||||||||
|
EBITDAX |
$ | 139,852 | $ | 214,341 | $ | 493,194 | $ | 663,428 | ||||||||
New Accounting Pronouncements
Our historical condensed consolidated financial statements and related notes to condensed consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done, and judgments made on how the specifics of a given rule apply to us.
In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for crude oil and natural gas activities, crude oil, NGL and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes.
Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 2025. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report.
New accounting pronouncements issued but not yet adopted. The effects of new accounting pronouncements are discussed in Note 2 of Notes to Condensed Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)."
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s major market risk exposure is the pricing it receives for its sales of crude oil, NGL and natural gas. Pricing for crude oil, NGL and natural gas has been volatile and unpredictable for several years, and HighPeak Energy expects this volatility to continue in the future.
During the period from January 1, 2021 through September 30, 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. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $13.5 million on an annualized basis, excluding the effects of derivatives, and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis, excluding the effects of derivatives.
Due to this volatility, the Company uses commodity derivative instruments, such as collars, puts, swaps and basis swaps, to hedge price risk associated with a portion of anticipated production. These hedging instruments allow the Company to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in crude oil and natural gas prices and provide increased certainty of cash flows for its drilling program. These instruments provide only partial price protection against declines in crude oil and natural gas prices and may partially limit the Company’s potential gains from future increases in prices. The Company enters into hedging arrangements to protect its capital expenditure budget. 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 does not enter into any commodity derivative instruments, including derivatives, for speculative or trading purposes.
Counterparty and Customer Credit Risk. The Company’s derivative contracts, if any, expose it to credit risk in the event of nonperformance by the counterparties. It is anticipated that if the Company enters into any commodity contracts, the collateral defined in the Collateral Agency Agreement may be used as collateral for the Company’s commodity derivatives. The Company evaluates the credit standing of its counterparties as it deems appropriate. It is anticipated that any counterparties to HighPeak Energy’s derivative contracts would have investment grade ratings.
The Company’s principal exposures to credit risk are through receivables from the sale of crude oil and natural gas production due to the concentration of its crude oil and natural gas receivables with a few significant customers. The inability or failure of the Company’s significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company’s financial results.
The average forward prices based on September 30, 2025 market quotes were as follows:
|
Remainder of 2025 |
Year Ending December 31, 2026 |
|||||||
|
Average forward NYMEX crude oil price per Bbl |
$ | 61.91 | $ | 61.15 | ||||
|
Average forward NYMEX natural gas price per MMBtu |
$ | 3.34 | $ | 3.90 | ||||
The average forward prices based on October 31, 2025 market quotes were as follows:
|
Remainder of 2025 |
Year Ending December 31, 2026 |
|||||||
|
Average forward NYMEX crude oil price per Bbl |
$ | 60.68 | $ | 60.04 | ||||
|
Average forward NYMEX natural gas price per MMBtu |
$ | 3.75 | $ | 4.06 | ||||
Credit Risk. The Company's primary concentration of credit risk is associated with (i) the collection of receivables resulting from the sale of crude oil and natural gas production and (ii) the risk of a counterparty's failure to meet its obligations under derivative contracts with the Company.
The Company monitors exposure to counterparties primarily by reviewing credit ratings, financial criteria and payment history. Where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. The Company's crude oil and natural gas is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Historically, the Company's credit losses on crude oil and natural gas receivables have not been material.
The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.
The Company entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with right of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative contract, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.
Interest Rate Risk. As of September 30, 2025, we had $1.2 billion outstanding under the Term Loan Credit Agreement and had $93.1 million of available borrowing capacity under the Senior Credit Facility Agreement. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement and Senior Credit Facility Agreement. The Company also has fixed rate debt for short periods that is periodically adjusted, but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The impact of a 1% increase in interest rates on our outstanding debt as of September 30, 2025 would have resulted in an annual increase in interest expense of approximately $12.0 million.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, HighPeak Energy has evaluated, under the supervision and with the participation of the Company’s management, including HighPeak Energy’s principal executive officer and principal financial officer, the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the fiscal period covered by this Quarterly Report. Based on that evaluation, HighPeak Energy’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective, as of the end of the period covered by this Quarterly Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2025 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, the Company may be a party to various lawsuits, proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations.
ITEM 1A. RISK FACTORS
In addition to the information set forth in this Quarterly Report, the risks that are discussed in the Company’s Annual Report under the headings “Risk Factors,” “Business and Properties,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. Except as set forth below, there has been no material change in the Company's risk factors that were described in the Company’s Annual Report.
We are currently a “controlled company” within the meaning of Nasdaq rules and qualify for exemptions from certain corporate governance requirements. As a result, stockholders do not have the same protections afforded to stockholders of companies that are not exempt from such corporate governance requirements. It is anticipated that we will cease to be a controlled company following the end of year, but that over a majority of our shares will still be held by the HighPeak Funds, the John Paul DeJoria Family Trust and the John Paul DeJoria Dynasty Trust. The HighPeak Funds have and, following the HighPeak II Distribution expected early next year, the John Paul DeJoria Family Trust and John Paul DeJoria Dynasty Trust, will have significant influence over us.
The HighPeak Funds collectively own a majority of HighPeak Energy’s outstanding voting stock. Therefore, HighPeak Energy is a controlled company within the meaning of Nasdaq corporate governance standards. Following Mr. Jack Hightower’s retirement, the HighPeak Funds are managed by a committee comprised of Mr. Hollis, Daniel Silver and Ryan Hightower, each of whom also serve as President and Chief Executive Officer, Executive Vice President and Executive Vice President of the Company, respectively.
Under Nasdaq rules, a company of which more than 50% of the voting power is held by an individual, company or group of persons acting together is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:
|
● |
a majority of the Board consist of independent directors under Nasdaq rules; |
|
● |
the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and |
|
● |
the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. |
A majority of the HighPeak Energy board members are independent and both the Nominating and Governance Committee and Compensation Committees are composed solely of independent members of the board. These requirements will not apply to HighPeak Energy as long as it remains a controlled company.
In connection with Mr. Jack Hightower’s retirement, the HighPeak Funds have agreed that HighPeak II will likely distribute its shares early next year (the “HighPeak II Distribution”), at which time HighPeak Energy will cease to be a controlled company. Following the HighPeak II Distribution and the distribution of 1,532,478 founder shares to Mr. Jack Hightower, the HighPeak Funds will own approximately 34.2% of our common stock, and approximately 35.8% of our common stock will be owned by the John Paul DeJoria Family Trust and the John Paul DeJoria Dynasty Trust. Such beneficial ownership by HighPeak Funds, the John Paul DeJoria Family Trust and the John Paul DeJoria Dynasty Trust of our voting interests could limit the ability of our other stockholders to approve transactions they may deem to be in the best interests of our Company or delay or prevent changes in control or changes in our management.
As long as the HighPeak Funds and, following the HighPeak II Distribution, the John Paul DeJoria Family Trust and John Paul DeJoria Dynasty Trust continue to own or control a significant percentage of outstanding voting power, they may have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our Second Amended and Restated Certificate of Incorporation or our Amended and Restated Bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets. Moreover, this concentration of stock ownership by our significant stockholders may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with stockholders who own such a significant percentage of our voting securities.
Further, following the HighPeak II Distribution, because HighPeak Energy will cease to be a controlled company, any action required or permitted to be taken by the stockholders of the Company must be taken at a duly held annual or special meeting of stockholders and may not be taken by any consent in writing of such stockholders.
Crude oil, NGL and natural gas prices are volatile. Sustained volatility, or declines in, crude oil, NGL and natural gas prices could adversely affect HighPeak Energy’s business, financial condition and results of operations and its ability to meet its capital expenditure obligations and other financial commitments.
The prices we receive for our crude oil, NGL and natural gas production heavily influence its revenue, profitability, access to capital, future rate of growth and the carrying value of its properties. The markets for crude oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period from January 1, 2021 through September 30, 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. One of the factors which caused the fall in prices was OPEC and its non-OPEC allies, known collectively as OPEC+, being unable to reach an agreement on production levels for crude oil, which resulted in Saudi Arabia and Russia initiating efforts to increase production. The convergence of these events, along with the significantly reduced demand because of the COVID-19 pandemic, created an unprecedented global crude oil and natural gas supply and demand imbalance, reduced global crude oil and natural gas storage capacity, caused crude oil and natural gas prices to decline significantly and resulted in continued volatility in crude oil, NGL and natural gas prices. Prices have recovered to pre-pandemic levels, with the calendar month average NYMEX WTI crude oil price of $63.53 per Bbl and the last trading day NYMEX natural gas price of $2.867 per MMBtu for the month of September 2025. However, there can be no certainty that commodity prices will sustain at these levels or continue to increase. In addition, the current U.S. presidential administration has signaled it will encourage increased domestic production of crude oil, which could lead to declines in crude oil, NGL and natural gas prices.
Likewise, NGL, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which has different uses and pricing characteristics, have also fluctuated widely during this period. The prices HighPeak Energy receives for its production, and the levels of HighPeak Energy’s production, will depend on numerous factors beyond HighPeak Energy’s control, which include the following:
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● |
worldwide and regional economic conditions, including elevated interest rates and associated policies of the Federal Reserve, impacting the global supply and demand for crude oil, NGL and natural gas; |
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the price and quantity of foreign imports of crude oil, NGL and natural gas; |
|
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domestic and global political and economic conditions, such as the change in U.S. presidential administration, the ongoing war between Russia and Ukraine, conflicts in the Middle East, socio-political unrest and instability, terrorism or hostilities in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia; |
|
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the occurrence or threat of epidemic or pandemic diseases, such as COVID-19, or any government response to such occurrence or threat; |
|
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actions of OPEC or OPEC+, its members and other state-controlled crude oil companies relating to crude oil price and production controls; |
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the level of global exploration, development and production; |
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the level of global inventories; |
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prevailing prices, and expectations regarding future prices, on local price indexes in the areas in which HighPeak Energy operates; |
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the proximity, capacity, cost and availability of gathering and transportation facilities; |
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localized and global supply and demand fundamentals and transportation availability; |
|
● |
the cost of exploring for, developing, producing and transporting reserves; |
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weather conditions and natural disasters; |
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technological advances affecting energy consumption; |
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the price and availability of alternative fuels, including the potential acceleration of the development of alternative fuels as a result of the IRA 2022 or otherwise; |
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expectations about future commodity prices; and |
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U.S. federal, state and local and non-U.S. governmental regulation and taxes. |
Lower commodity prices may reduce HighPeak Energy’s cash flow and access to capital markets. If HighPeak Energy is unable to obtain needed capital or financing on satisfactory terms, its ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with lower crude oil and natural gas prices may adversely affect drilling economics and HighPeak Energy’s ability to raise capital, which may require it to re-evaluate and postpone or eliminate its development program, and result in the reduction of some proved undeveloped reserves and related standardized measure. If HighPeak Energy is required to curtail its drilling program, HighPeak Energy may be unable to hold leases that are scheduled to expire, which may further reduce reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect HighPeak Energy’s future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
Tariffs and other trade measures could adversely affect our operations, profitability and business.
On April 2, 2025, the United States announced a baseline tariff on all foreign goods, with goods imported from specified nations, including China and those in the European Union, subject to higher tariff rates. Since then, there have been delays of imposition of tariffs while the United States negotiates with those countries, as well as litigation seeking to restrict and/or delay the implantation of such tariffs, and the extent of such delays and the ultimate outcome and impacts cannot be predicted at this time. It remains unclear to what extent, upon which countries, and upon which terms, tariffs may be levied and, to the extent that such trade policies impact our supply chain, we may not be able to fully mitigate the impact of these increased costs or pass price increases on to our customers.
We may be materially adversely impacted by tariffs if we are not able to adapt our supply chain strategy. We may also face unanticipated costs in developing our domestic supply chain and increased competition for materials and components in the United States, which also would impact our business and results of operations. The imposition of tariffs has and may create uncertainty in our industry. Increases in costs to drill and develop reserves as a result of tariffs coupled with lower commodity prices from increased domestic production could make producing such reserves no longer economically viable or technically feasible. Additionally, existing or future tariffs may negatively affect our customers, suppliers, and manufacturing partners. Such outcomes could adversely affect the amount or timing of our revenues, results of operations or cash flows, and continuing uncertainty could cause sales volatility and price fluctuations.
Tariffs, the adoption and expansion of trade restrictions, the occurrence of a trade war, or other governmental action related to tariffs, trade agreements or related policies have the potential to adversely impact our supply chain and access to equipment, and our costs and ability to economically serve certain markets. Any such cost increases or decreases in availability could slow our growth and cause our financial results and operational metrics to suffer. There is current uncertainty about the future relationship between the United States and other countries with respect to trade policies, taxes, government regulations, and tariffs and we cannot predict whether, and to what extent, U.S. trade policies will change in the future.
HighPeak Energy’s development projects and acquisitions will require substantial capital expenditures. HighPeak Energy may be unable to obtain required capital or financing on satisfactory terms, including as a result of recent increases in the cost of capital resulting from Federal Reserve policies or otherwise, which could reduce its ability to access or increase production and reserves.
The crude oil and natural gas industry is capital-intensive. We have evaluated multiple development scenarios under multiple potential commodity price assumptions. Under its current 2025 development program, we would expect to incur approximately $375 to $405 million of capital expenditures for drilling, completion, facilities and equipping costs, $40 to $50 million for field infrastructure and $33 to $35 million on one-time infrastructure expenditures. The ability to make these capital expenditures will be highly dependent on the price of crude oil and available funding of HighPeak Energy. Commodity prices have declined in the first nine months of 2025, with the calendar month average NYMEX WTI price of $63.53 per Bbl and last trading day NYMEX natural gas price of $2.867 per MMBtu for the month of September 2025. We ran a two-rig program for the majority of 2024. We expect to average one to two (1-2) drilling rigs and one (1) frac crew during 2025. We recognize that commodity prices remain highly volatile and that its liquidity is limited, and as a result, there is no certainty that we will operate a two (2) rig development program in the future.
We expect to fund our forecasted capital expenditures with cash on its balance sheet, cash generated by operations and, depending on market circumstances, potential future debt or equity offerings.
Cash flows from operations are subject to significant uncertainty. As a result, the amount of liquidity that we will have in the future is uncertain.
Our financing needs may require it to alter or increase its capitalization substantially through the issuance of debt or equity securities or the sale of assets. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. For example, due to the high levels of inflation in the United States, the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023, and began decreasing rates with three rate cuts toward the end of 2024. The Federal Reserve kept interest rates steady in 2025 citing the unknown effects of the Trump Administration’s trade policies on inflation, but it resumed such decreases in September 2025, although uncertainty remains as to when or if such elevated rates may be decreased further. Such increased interest rates have increased the cost of capital and may prevent us from being able to obtain debt financing at favorable rates, or at all, which would materially impact our operations. In addition, conditions in the global capital markets have been volatile due to uncertainty around tariff rates and trade policies, the ongoing war between Russia and Ukraine, conflicts in the Middle East or otherwise, making terms for certain types of financing difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. Further, the issuance of additional indebtedness would require that an additional portion of cash flow from operations be used for the payment of interest and principal on its indebtedness, thereby further reducing its ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to existing stockholders. The actual amount and timing of future capital expenditures may differ materially from estimates as a result of, among other things: commodity prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in actual capital expenditures, which would negatively impact our ability to increase production.
Our cash flow from operations and access to capital are subject to several variables, including:
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the prices at which our production is sold; |
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proved reserves; |
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the amount of hydrocarbons we are able to produce from our wells; |
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Our ability to acquire, locate and produce new reserves; |
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the amount of our operating expenses; |
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cash settlements from our derivative activities; |
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production interruptions or curtailments from time-to-time related to third-party infrastructure downtime or delays in third-party installation of infrastructure, including electrical power supply, that affects our ability to produce our crude oil and natural gas; |
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the duration and scope of the ongoing war between Russia and Ukraine and conflicts in the Middle East; |
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Our ability to obtain storage capacity for the crude oil we produce; |
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restrictions in the instruments governing our debt on our ability to incur additional indebtedness; and |
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Our ability to access the public or private capital markets. |
Should our revenues decrease as a result of lower crude oil, NGL and natural gas prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain operations at expected levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to it, if at all, due to elevated interest rates and associated policies of the Federal Reserve, or otherwise. If cash flow generated by our operations or available debt financing are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in reserves and production and could materially and adversely affect our business, financial condition and results of operations. If we seek and obtain additional financing, subject to the restrictions in the instruments governing its existing debt, the addition of new debt to existing debt levels could intensify the operational risks that we will face. Further, adding new debt could limit our ability to service existing debt service obligations.
Hedging transactions expose HighPeak Energy to counterparty credit risk and may become more costly or unavailable.
Hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when there is an increase in the differential between the underlying price in the derivative instrument and actual prices received or there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in an adverse manner, our cash otherwise available for use in operations would be reduced which could limit our ability to make future capital expenditures and make payments on indebtedness. Future collateral requirements will depend on arrangements with counterparties, highly volatile crude oil, NGL and natural gas prices and interest rates.
In addition, derivative arrangements could limit the benefits to be received from increases in the prices for crude oil, NGL and natural gas, which could also have an adverse effect on HighPeak Energy’s financial condition. If crude oil, NGL and natural gas prices upon settlement of derivative swap contracts exceed the price at which commodities have been hedged, we will be obligated to make cash payments to counterparties, which could, in certain circumstances, be significant.
HighPeak Energy experiences periods of higher costs when commodity prices rise and inflation may adversely affect our operating results, which could negatively impact our profitability, cash flow and ability to complete development activities as planned. Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.
Historically, capital and operating costs have risen during periods of increasing crude oil, NGL and natural gas prices. Inflationary factors such as increases in labor costs, material costs and overhead costs may adversely affect our operating results. These cost increases have resulted from a variety of factors that we will be unable to control, such as increases in the cost of electricity, steel and other raw materials; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting its profitability, cash flow and ability to complete development activities as scheduled and on budget. A high rate of inflation may have an adverse effect on our operating results and this impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by its derivative activities.
Although inflation rates moderated in 2024 and the first half of 2025, inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Due to the high levels of inflation, the Federal Reserve and other central banks increased interest rates multiple times in 2022 and 2023, and began decreasing rates with three rate cuts toward the end of 2024. The Federal Reserve kept interest rates steady in 2025 citing the unknown effects of the Trump Administration’s trade policies on inflation, but resumed such decreases in September 2025, although uncertainty remains as to when or if such rates may be decreased further.
Higher crude oil and natural gas prices, continued inflation and supply chain issues as well as an increase in demand for services may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher crude oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations.
Volatility in the political, legal and regulatory environments as a result of the change in the U.S. presidential administration and political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine, conflicts in the Middle East and OPEC+ policy decisions could have a material adverse impact on our business, financial condition or future results.
Our business, financial condition and future results are subject to political and economic risks and uncertainties, including volatility in the political, legal and regulatory environments as a result of the imposition of and changes in tariffs and instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in crude oil or natural gas producing areas such as the ongoing war between Russia and Ukraine and conflicts in the Middle East.
The United States and other countries and certain international organizations have imposed broad-ranging and severe economic sanctions on Russia and certain Russian individuals, banking entities and corporations as a response, and additional sanctions may be imposed in the future. This conflict and the resulting sanctions and concerns regarding global energy security have contributed to increases and volatility in the prices for crude oil and natural gas. The length, impact, and outcome of the ongoing war between Russia and Ukraine is highly unpredictable, and such events or any further hostilities in Ukraine or elsewhere could severely impact the world economy and may adversely affect our financial condition. Furthermore, escalations of conflicts in the Middle East may result in heightened geopolitical risks for crude oil and natural gas markets, given the significant share of global oil supply in the Middle East. While the Company does not have operations overseas, these conflicts elevate the likelihood of supply chain disruptions, heightened volatility in crude oil and natural gas prices and negative effects on our ability to raise additional capital when required and could have a material adverse impact on our business, financial condition or future results.
Currently, global crude oil inventories are low relative to historical levels and supply from OPEC+ and other crude oil producing nations are not expected to be sufficient to meet forecasted crude oil demand growth for the next few years. It is believed that many OPEC+ countries will be unable to increase their production levels or even produce at expected levels due to their lack of capital investments in developing incremental crude oil supplies over the past few years. OPEC+ began phasing out a 2.2 million Bopd reduction in oil production in April 2025, which it had previously postponed due to a slowdown in global demand and rising output surrounding the global economic and crude oil market outlooks, and approved another crude oil production increase of 137,000 Bopd in October 2025. Furthermore, sanctions and import bans on Russian crude oil have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. Still, crude oil and natural gas prices have declined from the highs experienced in second quarter of 2022 and could decrease or increase with any changes in demand due to, among other things, uncertainty and volatility from global supply chain disruptions attributable to the pandemic, the ongoing war between Russia and Ukraine, conflicts in the Middle East, international sanctions, speculation as to future actions by OPEC+, increasing inflation and government efforts to reduce inflation, and possible changes in the overall health of the global economy, including a prolonged recession. Further, the volatility in crude oil and natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over the longer term. To what extent these and other external factors (such as government action with respect to climate change regulation) ultimately impact our future business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous factors, including future developments, which are not within our control and cannot be accurately predicted.
We are evaluating strategic alternatives, including a possible sale of our business, and there can be no assurance that we will be successful in identifying or completing any strategic alternative transactions, that any such strategic alternative transactions will result in additional value for our shareholders or that the process will not have an adverse impact on our business and shareholders.
Our Board continues to evaluate a range of strategic alternative transactions to maximize shareholder value, including a potential sale of the Company. These transactions could include, but are not limited to, acquisitions, debt refinancing transactions, asset divestitures, monetization of intellectual property, and mergers, reverse mergers or other business combinations. Because we have publicly approved the undertaking of this process, the market price of our common stock may reflect an expectation that shares of our common stock may be acquired at a premium in the near future.
There can be no assurance that the review of strategic alternative transactions will result in the identification or consummation of any transaction. Our Board may also determine that our most effective strategy is to continue to effectuate our current business plan. The process of reviewing strategic alternative transactions may be time consuming and disruptive to our business operations and, if we are unable to effectively manage the process, our business, financial condition and results of operations could be adversely affected. We could incur substantial expenses associated with identifying and evaluating potential strategic alternative transactions. No decision has been made with respect to any transaction and we cannot assure you that we will be able to identify and undertake any transaction that allows our shareholders to realize an increase in the value of their common stock or provide any guidance on the timing of such action, if any.
We also cannot assure you that any potential transaction or other strategic alternatives, if identified, evaluated and consummated, will provide greater value to our shareholders than that reflected in the current price of our common stock. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, but not limited to, market conditions, industry trends, the interest of third parties in our business and the availability of financing to potential buyers on reasonable terms. We do not intend to comment regarding the evaluation of strategic alternative transactions until such time as our Board has determined the outcome of the process or otherwise has deemed that disclosure is appropriate or required by applicable law. As a consequence, perceived uncertainties related to our future may result in the loss of potential business opportunities and volatility in the market price of our common stock and may make it more difficult for us to attract and retain qualified personnel and business partners. Volatility in the trading price of our common stock could also adversely affect the trading market for and the trading price of the notes.
The Principal Stockholder Group has significant influence over HighPeak Energy.
The Principal Stockholder Group owns approximately 65% of our common stock as of September 30, 2025. As long as the Principal Stockholder Group owns or controls a significant percentage of our outstanding voting power, subject to the terms of the Stockholders’ Agreement, they will have the ability to influence certain corporate actions requiring stockholder approval. Under the Stockholders’ Agreement, the Principal Stockholder Group will be entitled to nominate a specified number of directors for appointment to the Board so long as the Principal Stockholder Group meets certain ownership criteria outlined in the Stockholders’ Agreement.
If one of our former executive officers were forced to sell shares of our common stock that he has pledged to secure certain personal loan obligations, such sales could cause our stock price to decline.
Certain banking institutions have made extensions of credit to Jack Hightower, our former Chief Executive Officer, a portion of which was used to purchase shares of common stock in the public market and in certain of our public offerings and private placements at the same prices offered to third-party participants in such offerings and placements. We are not a party to these loans, which are primarily secured by pledges of shares of our common stock currently owned directly by Mr. Jack Hightower and shares of HighPeak common stock held indirectly by Mr. Jack Hightower via his interests in the HighPeak Funds and HPK GP. If the price of our common stock were to decline or such loans were to reach maturity without renewal, Mr. Jack Hightower may be forced by one or more of the banking institutions to sell, or the applicable banking institution may elect to sell, shares of HighPeak common stock or interests in the HighPeak Funds to satisfy his applicable loan obligations if he could not do so through other means. Any such sales could adversely affect the trading market and trading price of our common stock, as well as significantly reduce Mr. Jack Hightower’s ownership in the Company.
Recent management changes could disrupt our operations and impair our ability to attract and retain key personnel.
We have experienced recent changes to our senior management team, including the departure of our Chief Executive Officer, Jack Hightower, in September 2025 when our President, Michael Hollis, was named Interim Chief Executive Officer. Subsequent to quarter end on November 4, 2025, the Board named Michael Hollis President and Chief Executive Officer. Changes in our senior management and uncertainty regarding pending changes may disrupt our operations, impact customer and partner relationships, and impair our ability to recruit and retain other needed personnel. Any such disruption or impairment could have an adverse effect on our business.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
Our common stock repurchase activity for the three months ended September 30, 2025 was as follows:
|
Period |
Total Number of Shares Purchased(1) |
Average Price Paid Per Share(2) |
Total Number of Shares Purchased as Part of Publicly Announced Plan |
Approximate Dollar Value of Shares that May Yet to Be Purchased Under the Plan(3)(4) |
||||||||||||
|
($ in thousands, except per share amounts and shares) |
||||||||||||||||
|
July 1, 2025 - July 31, 2025 |
— | $ | — | — | $ | 39,907 | ||||||||||
|
August 1, 2025 - August 31, 2025 |
— | $ | — | — | $ | 39,907 | ||||||||||
|
September 1, 2025 - September 30, 2025 |
545,195 | $ | 7.06 | — | $ | 39,907 | ||||||||||
|
Total |
545,195 | $ | 7.06 | — | ||||||||||||
(1) Consists entirely of 545,195 shares of common stock repurchased from the former Chairman and Chief Executive Officer in order to satisfy tax withholding requirements. Such shares are cancelled and retired. These shares also do not count toward the dollar value that may yet to be purchased under the plan nor are they subject to the 1% excise tax discussed below.
(2) The average price paid per share includes any commissions paid to repurchase stock.
(3) In February 2024, our Board approved a stock repurchase program for up to $75.0 million, excluding excise taxes and other expenses. The stock repurchase program expired on December 31, 2024. However, on March 6, 2025, our Board extended the program in its entirety to December 31, 2025. The program may be suspended, modified, or discontinued by the Board at any time.
(4) The IRA of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.
ITEM 5. OTHER INFORMATION
During the three months ended September 30, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
41
HIGHPEAK ENERGY, INC.
ITEM 6. EXHIBITS
|
Exhibit Number |
Description |
|
3.1 |
Second Amended & Restated Certificate of Incorporation of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 2, 2023). |
|
3.2 |
Amended and Restated Bylaws of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on November 9, 2020). |
|
4.1 |
Registration Rights Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP and certain other security holders named therein (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020). |
|
4.2 |
Stockholders’ Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, Jack Hightower and certain directors of Pure Acquisition Corp. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020). |
|
4.3 |
Amendment and Assignment to Warrant Agreement, dated as of August 21, 2020, by and among Pure Acquisition Corp., Continental Stock Transfer & Trust Company and HighPeak Energy, Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020). |
|
10.1 |
Second Amendment to Revolving Credit Agreement, dated August 1, 2025, by and among HighPeak Energy, Inc., as borrower, Fifth Third Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 4, 2025). |
|
10.2 |
Master Assignment and First Amendment to Credit Agreement, dated August 1, 2025, by and among HighPeak Energy, Inc., as borrower, the guarantors party thereto, Texas Capital Bank, as administrative agent, Chambers Energy Management, LP, as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 4, 2025). |
|
10.3 |
HighPeak Energy, Inc. Change in Control Plan and Summary Plan Description (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on September 15, 2025). |
|
10.4† |
Separation Agreement and General Release of Claims by and between the Company and Jack Hightower, effective September 15, 2025 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on September 16, 2025). |
|
31.1* |
Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241). |
|
31.2* |
Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241). |
|
32.1** |
Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350). |
|
32.2** |
Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350). |
|
101.INS** |
Inline XBRL Instance Document – The instance document does not appear in the Interactive Data File because its XBRL tabs are embedded within the Inline XBRL document |
|
101.SCH** |
Inline XBRL Taxonomy Extension Schema Document |
|
101.CAL** |
Inline XBRL Taxonomy Extension Calculation Linkbase Document |
|
101.DEF** |
Inline XBRL Taxonomy Extension Definition Linkbase Document |
|
101.LAB** |
Inline XBRL Taxonomy Extension Label Linkbase Document |
|
101.PRE** |
Inline XBRL Taxonomy Extension Presentation Linkbase Document |
|
104* |
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
|
* |
Filed herewith. |
|
** |
Furnished herewith. |
|
† |
Management contract or compensatory plan or agreement. |
HIGHPEAK ENERGY, INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.
|
HIGHPEAK ENERGY, INC. |
||
|
November 5, 2025 |
By: |
/s/ Steven Tholen |
|
Steven Tholen |
||
|
Chief Financial Officer |
||
|
November 5, 2025 |
By: |
/s/ Keith Forbes |
|
Keith Forbes |
||
|
Vice President and Chief Accounting Officer |
||
