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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐	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: 001-39464

HighPeak Energy, Inc.

(Exact name of Registrant as specified in its charter)

Delaware	84-3533602
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

421 W. 3rd St., Suite 1000	76102
Fort Worth, Texas	(Zip Code)
(Address of principal executive offices and zip code)

(817) 850-9200

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange on which

registered

Common Stock, par value $0.0001 per share

HPK

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.

Yes ☒ No ☐

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).

Yes ☒ No ☐

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.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☒

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 ☐ No ☒

As of October 31, 2025, there were 125,587,093 shares of common stock, par value $0.0001 per share, issued and outstanding.

HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

		Page
Definitions of Certain Terms and Conventions Used Herein		1
Cautionary Statement Concerning Forward-Looking Statements		5
PART I. FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	6
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Operations	7
	Condensed Consolidated Statements of Changes in Stockholders’ Equity	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 5.	Other Information	47
Item 6.	Exhibits	48
Signatures		49

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:

	•	“*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.
	•	“*ASC*” means Accounting Standards Codification.
	•	“*ASU*” means Accounting Standards Update.
	•	“*Basin*” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
	•	“*Bbl*” means a standard barrel containing 42 United States gallons.
	•	“*Bcf*” means one billion cubic feet.
	•	“*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.
	•	“*Boepd*” means Boe per day.
	•	“*Bopd*” means one barrel of crude oil per day.
	•	“*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.
	•	“*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.
	•	“*common stock” or “HighPeak Energy common stock*” means the Company’s common stock, par value $0.0001 per share.
	•	“*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.
	•	“*Credit Agreement*” means the Term Loan Credit Agreement and the Senior Credit Facility Agreement.
	•	“*DD&A*” means depletion, depreciation and amortization.
	•	“*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).
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*EUR” or “Estimated ultimate recovery*” The sum of reserves remaining as of a given date and cumulative production as of that date.
	•	“*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.

	•	“*Extension well*” An extension well is a well drilled to extend the limits of a known reservoir.
	•	“*FASB*” Financial Accounting Standards Board.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*Formation*” A layer of rock which has distinct characteristics that differs from nearby rocks.
	•	“*GAAP*” means accounting principles generally accepted in the United States of America.
	•	“*Gross wells*” means the total wells in which a working interest is owned.
	•	“*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.
	•	“HH” means Henry Hub, a distribution hub in Louisiana that serves as the delivery location for natural gas futures contracts on the NYMEX.
	•	“*HighPeak Energy” or the “Company*” means HighPeak Energy, Inc. and its subsidiaries.
	•	“*HighPeak I*” means HighPeak Energy, LP, a Delaware limited partnership, and a wholly owned subsidiary of HighPeak Energy Partners, LP, a Delaware limited partnership.
	•	“*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.
	•	“*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.
	•	“*HPK Contributors*” means HighPeak I, HighPeak II and HPK GP.
	•	“*HPK GP*” means HighPeak Energy, LLC, a Delaware limited liability company.
	•	“*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.
	•	“*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.
	•	“*MBbl*” means one thousand Bbls.
	•	“*MBoe*” means one thousand Boes.
	•	“*Mcf*” means one thousand cubic feet and is a measure of natural gas volume.
	•	“*MMBbl*” means one million Bbls.
	•	“*MMBtu*” means one million Btus.
	•	“*MMcf*” means one million cubic feet and is a measure of natural gas volume.
	•	“*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.
	•	“*Net production*” Production that is owned by us, less royalties and production due others.
	•	“*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.
	•	“*NYMEX*” means the New York Mercantile Exchange.
	•	“*OPEC*” means the Organization of Petroleum Exporting Countries.
	•	“*Operator*” The individual or company responsible for the exploration and/or production of a crude oil or natural gas well or lease.
	•	“*Plugging*” A downhole tool that is set inside the casing to isolate the lower part of the wellbore.
	•	“*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.
	•	“*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.
	•	“*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).
	•	“*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.

	•	“*Proration unit*” A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.
	•	“*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.
	•	“*Proved developed nonproducing reserves” or “PDNP*” means proved reserves that are developed nonproducing reserves.
	•	“*Proved developed producing reserves” or “PDP*” means proved reserves that are developed producing reserves.
	•	“*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.
	•	“*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.
		(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.
		(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.
		(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.
		(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.
		(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.
	•	“*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.
	•	“*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.
	•	“*Realized price*” The cash market price less all expected quality, transportation and demand adjustments.
	•	“*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.
	•	“*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.
	•	“*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.

	•	“*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.
	•	“*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.
	•	“*SEC*” means the United States Securities and Exchange Commission.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*Spot market price*” The cash market price without reduction for expected quality, transportation and demand adjustments.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*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.
	•	“*U.S.*” means the United States.
	•	“*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.
	•	“*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.
	•	“*Working interes*t” 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.
	•	“*Workover*” Operations on a producing well to restore or increase production.
	•	“*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.
	•	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.
	•	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:

	●	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;
	●	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;
	●	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;
	●	volatility in the political, legal and regulatory environments, including the effects of a prolonged U.S. government shutdown;
	●	political and regulatory uncertainties;
	●	our liquidity, cash flow and access to capital;
	●	the availability of capital resources;
	●	our ability to refinance or pay, when due, the principal of, interest or other amounts due in respect of our indebtedness;
	●	production and reserve levels;
	●	drilling and completion risks;
	●	economic and competitive conditions;
	●	the impacts of revising our drilling plan during the year transitioning to an increased or decreased rig count from time to time;
	●	severe weather conditions;
	●	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;
	●	the availability of goods and services and supply chain issues;
	●	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;
	●	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;
	●	recent management changes;
	●	cyber-attacks;
	●	occurrence of property acquisitions or divestitures;
	●	the integration of acquisitions;
	●	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;
	●	the results of our ongoing strategic alternatives process; and
	●	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
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	164,913		$	86,649
Accounts receivable		54,556			85,242
Derivative instruments		17,335			7,582
Inventory		9,906			10,952
Prepaid expenses		4,628			4,587
Total current assets		251,338			195,012
Crude oil and natural gas properties, using the successful efforts method of accounting:
Proved properties		4,358,116			3,959,545
Unproved properties		67,887			70,868
Accumulated depletion, depreciation and amortization		(1,495,689	)		(1,184,684	)
Total crude oil and natural gas properties, net		2,930,314			2,845,729
Other property and equipment, net		3,052			3,201
Derivative instruments		3,083			—
Other noncurrent assets		16,975			19,346
Total assets	$	3,204,762		$	3,063,288
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt	$	30,000		$	120,000
Accounts payable – trade		44,623			74,011
Revenues and royalties payable		29,966			26,838
Other accrued liabilities		24,057			22,196
Accrued capital expenditures		23,162			35,170
Operating leases		885			719
Derivative instruments		—			5,380
Advances from joint interest owners		—			316
Total current liabilities		152,693			284,630
Noncurrent liabilities:
Long-term debt, net		1,162,300			928,384
Deferred income taxes		246,469			232,398
Asset retirement obligations		15,699			14,750
Derivative instruments		772			—
Operating leases		327			670
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at September 30, 2025 and December 31, 2024		—			—
Common stock, $0.0001 par value, 600,000,000 shares authorized, 125,587,093 and 126,067,436 shares issued and outstanding at September 30, 2025 and December 31, 2024, respectively		13			13
Additional paid-in capital		1,163,203			1,166,609
Retained earnings		463,286			435,834
Total stockholders’ equity		1,626,502			1,602,456
Total liabilities and stockholders’ equity	$	3,204,762		$	3,063,288

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,
	2025			2024			2025			2024
Operating revenues:
Crude oil sales	$	190,773		$	270,636		$	633,920		$	827,595
NGL and natural gas sales		(1,911	)		942			12,790			7,013
Total operating revenues		188,862			271,578			646,710			834,608
Operating costs and expenses:
Crude oil and natural gas production		33,312			35,413			102,600			98,482
Production and ad valorem taxes		10,016			15,412			37,559			46,410
Exploration and abandonments		2,278			362			3,651			1,027
Depletion, depreciation and amortization		100,636			136,578			311,187			395,121
Accretion of discount		285			241			785			722
General and administrative		9,329			4,971			21,345			14,391
Stock-based compensation		177			3,753			442			11,326
Total operating costs and expenses		156,033			196,730			477,569			567,479
Other expense		222			1,404			2,711			3,405
Income from operations		32,607			73,444			166,430			263,724
Interest and other income		1,165			2,172			2,336			6,964
Interest expense		(37,150	)		(42,579	)		(110,550	)		(129,204	)
Gain (loss) on derivative instruments, net		6,913			32,334			25,432			(23,411	)
Loss on extinguishment of debt		(25,437	)		—			(25,437	)		—
(Loss) income before income taxes		(21,902	)		65,371			58,211			118,073
Provision for income taxes		(3,567	)		15,438			14,035			31,985
Net (loss) income	$	(18,335	)	$	49,933		$	44,176		$	86,088
(Loss) earnings per share:
Basic net (loss) income	$	(0.15	)	$	0.36		$	0.32		$	0.62
Diluted net (loss) income	$	(0.15	)	$	0.35		$	0.32		$	0.60

Weighted average shares outstanding:
Basic		124,807			124,988			124,807			125,595
Diluted		124,807			129,094			125,587			129,581

Dividends declared per share	$	0.04		$	0.04		$	0.12		$	0.12

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
	Shares Outstanding			Common Stock		Additional Paid-in- Capital			Retained Earnings			Total Stockholders' Equity
Balance, December 31, 2024		126,067		$	13	$	1,166,609		$	435,834		$	1,602,456
Dividends declared ($0.04 per share)		—			—		—			(5,043	)		(5,043	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(531	)		(531	)
Stock-based compensation costs:
Compensation costs included in net income		—			—		177			—			177
Net income		—			—		—			36,335			36,335
Balance, March 31, 2025		126,067			13		1,166,786			466,595			1,633,394
Dividends declared ($0.04 per share)		—			—		—			(5,042	)		(5,042	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(531	)		(531	)
Exercise of warrants		—			—		1			—			1
Stock-based compensation costs:
Restricted shares issued to outside directors		65			—		—			—			—
Compensation costs included in net income		—			—		88			—			88
Net income		—			—		—			26,176			26,176
Balance, June 30, 2025		126,132			13		1,166,875			487,198			1,654,086
Dividends declared ($0.04 per share)		—			—		—			(5,046	)		(5,046	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(531	)		(531	)
Stock-based compensation costs:
Compensation costs included in net income		—			—		177			—			177
Cash paid for tax withholding on vested equity awards		(545	)		—		(3,849	)		—			(3,849	)
Net loss		—			—		—			(18,335	)		(18,335	)
Balance, September 30, 2025		125,587		$	13	$	1,163,203		$	463,286		$	1,626,502

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		128,421		$	13	$	1,189,424		$	363,284		$	1,552,721
Dividends declared ($0.04 per share)		—			—		—			(5,137	)		(5,137	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(532	)		(532	)
Repurchased shares under buyback program		(566	)		—		(8,851	)		—			(8,851	)
Stock-based compensation costs:
Compensation costs included in net income		—			—		3,798			—			3,798
Net income		—			—		—			6,438			6,438
Balance, March 31, 2024		127,855			13		1,184,371			364,053			1,548,437
Dividends declared ($0.04 per share)		—			—		—			(5,114	)		(5,114	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(530	)		(530	)
Exercise of warrants		—			—		1			—			1
Repurchased shares under buyback program		(413	)		—		(5,845	)		—			(5,845	)
Stock-based compensation costs:
Restricted shares issued to outside directors		54			—		—			—			—
Compensation costs included in net income		—			—		3,775			—			3,775
Net income		—			—		—			29,717			29,717
Balance, June 30, 2024		127,496			13		1,182,302			388,126			1,570,441
Dividends declared ($0.04 per share)		—			—		—			(5,082	)		(5,082	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(531	)		(531	)
Repurchased shares under buyback program		(871	)		—		(12,824	)		—			(12,824	)
Stock-based compensation costs:
Compensation costs included in net income		—			—		3,753			—			3,753
Net income		—			—		—			49,933			49,933
Balance, September 30, 2024		126,625		$	13	$	1,173,231		$	432,446		$	1,605,690

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,
	2025			2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	44,176		$	86,088
Adjustments to reconcile net income to net cash provided by operations:
Provision for deferred income taxes		14,071			30,898
Loss on extinguishment of debt		25,437			—
(Gain) loss on derivative instruments, net		(25,432	)		23,411
Cash received (paid) on settlement of derivative instruments		7,988			(11,897	)
Amortization of debt issuance costs		5,215			6,199
Amortization of discounts on long-term debt		5,714			7,385
Stock-based compensation expense		442			11,326
Accretion expense		785			722
Depletion, depreciation and amortization expense		311,187			395,121
Exploration and abandonment expense		2,874			386
Changes in operating assets and liabilities:
Accounts receivable		30,686			18,145
Prepaid expenses, inventory and other assets		3,334			(12,387	)
Accounts payable, accrued liabilities and other current liabilities		(7,973	)		(4,524	)
Net cash provided by operating activities		418,504			550,873
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties		(394,395	)		(452,148	)
Changes in working capital associated with crude oil and natural gas property additions		(28,473	)		(13,214	)
Acquisitions of crude oil and natural gas properties		(4,475	)		(10,367	)
Proceeds from sales of properties		570			118
Other property additions		(31	)		(216	)
Net cash used in investing activities		(426,804	)		(475,827	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Term Loan Credit Agreement		180,000			—
Borrowings under Senior Credit Facility Agreement		30,000			—
Repayments under Term Loan Credit Agreement		(60,000	)		(90,000	)
Repayments under Senior Credit Facility Agreement		(30,000	)		—
Dividends paid		(15,545	)		(15,082	)
Debt issuance costs		(7,700	)		(58	)
Premium on extinguishment of debt		(4,750	)		—
Cash paid for tax withholding on vested equity awards		(3,849	)		—
Dividend equivalents paid		(1,593	)		(1,602	)
Proceeds from exercise of warrants		1			1
Repurchased shares under buyback program		—			(27,247	)
Net cash provided by (used in) financing activities		86,564			(133,988	)
Net increase (decrease) in cash and cash equivalents		78,264			(58,942	)
Cash and cash equivalents, beginning of period		86,649			194,515
Cash and cash equivalents, end of period	$	164,913		$	135,573

Supplemental cash flow information:
Cash paid for interest	$	99,621		$	117,018
Cash paid for income taxes		465			—
Supplemental disclosure of non-cash transactions:
Additions to asset retirement obligations		2,747			571

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.

Principles of consolidation. The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated.

Use of estimates in the preparation of financial statements. Preparation of the Company's condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of crude oil and natural gas properties is determined using estimates of proved crude oil, NGL and natural gas reserves and evaluations for impairment of proved and unproved crude oil and natural gas properties, in part, is determined using estimates of proved and risk adjusted probable and possible crude oil, NGL and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, if needed, evaluations for impairment of proved crude oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and future undiscounted and discounted net cash flows. In addition, evaluations for impairment of unproved crude oil and natural gas properties on a project-by-project basis are also subject to numerous uncertainties including, among others, 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. Other items subject to such estimates and assumptions include, but are not limited to, the carrying value of crude oil and natural gas properties, asset retirement obligations, equity-based compensation, fair value of derivatives, expected credit losses and estimates of income taxes. Actual results could differ from the estimates and assumptions utilized.

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 $41.8 million and $76.0 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, joint interest receivables of $3.4 million and $4.7 million, respectively, receivables from electric power infrastructure installed throughout Flat Top by the Company for which it will be reimbursed for totaling $3.3 million and zero, respectively, current U.S. federal income tax receivables of $3.1 million and $3.1 million, respectively, and receivables related to settlements of derivative contracts of $3.0 million and $1.4 million, respectively. The Company’s share of crude oil, NGL and natural gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company’s credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support.

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 88% and 76%, respectively, and sales to the Company’s second largest purchaser accounted for approximately 9% and 18%, respectively, of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of these particular purchasers would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

Inventory. Inventory is comprised primarily of crude oil and natural gas drilling and completion or repair items such as pumps, tubing, casing, vessels, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling and completion or repair operations and is carried at the lower of cost or net realizable value, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company’s condensed consolidated balance sheet and as charges to other expense in the condensed consolidated statements of operations. The Company’s materials and supplies inventory as of September 30, 2025 and December 31, 2024 is $9.9 million and $11.0 million, respectively, and the Company has not recognized any valuation allowance to date.

Prepaid expenses. Prepaid expenses are comprised primarily of fees related to strategic alternatives that will be deducted from eventual commissions on a future transaction, caliche that will be used on future locations and roads in our development areas, and prepaid insurance, software maintenance fees, listing fees and subscriptions that will be amortized over the life of the contracts. Prepaid expenses as of September 30, 2025 and December 31, 2024 are $4.6 million and $4.6 million, respectively.

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 $1.2 million and $1.1 million as of September 30, 2025 and December 31, 2024, respectively (in thousands):

	September 30, 2025		December 31, 2024
Land	$	1,869	$	1,869
Transportation equipment		464		620
Buildings		506		516
Leasehold improvements		182		193
Field equipment		31		2
Furniture and fixtures		—		1
Total other property and equipment, net	$	3,052	$	3,201

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.

Aid-in-construction assets. As of September 30, 2025 and December 31, 2024, the Company had aid-in-construction assets totaling $15.8 million and $18.0 million, respectively, included in other noncurrent assets. The Company funded aid-in-construction projects during the nine months ended September 30, 2025 and the year ended December 31, 2024 of $71,000 and $13.8 million, respectively, under the contract. The Company has received and will continue to receive payments based on gross system throughput, including any third-party natural gas that is potentially tied into the Flat Top gathering system in the future. Payments received during the nine months ended September 30, 2025 and the year ended December 31, 2024 were approximately $2.2 million and $2.0 million, respectively. The contract calls for future aid-in-construction fundings if expansions of the system are necessary as determined in the sole discretion of the Company.

Leases. The Company enters into leases for drilling rigs, storage tanks, equipment and buildings and recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of a lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are generally not recorded as lease right-of-use assets and liabilities. See Note 10 for additional information.

Current liabilities. Current liabilities as of September 30, 2025 and December 31, 2024 totaled approximately $152.7 million and $284.6 million, respectively, including trade accounts payable, revenues and royalties payable, accrued capital expenditures, derivative liabilities and accruals for operating and general and administrative expenses, operating leases, dividends, current portion of long-term debt, if any, and other miscellaneous items.

Debt issuance costs and original issue discount. The Company has paid a total of $8.8 million in debt issuance costs that are still being carried on the condensed consolidated balance sheet as of September 30, 2025, net of accumulated amortization, $7.7 million and $58,000 of which were incurred during the nine months ended September 30, 2025 and the year ended December 31, 2024, respectively, primarily related to an amendment to the Term Loan Credit Agreement and amendments and the completion of the Senior Credit Facility Agreement. Amortization based on the straight-line method over the terms of the Term Loan Credit Agreement and Senior Credit Facility Agreement which approximates the effective interest method was $5.2 million and $6.2 million during the nine months ended September 30, 2025 and 2024, respectively. Upon closing of the First Term Loan Amendment, which was considered an extinguishment, the remaining unamortized debt issue costs of $9.2 million was charged to expense and included in loss on extinguishment of debt in the condensed consolidated statements of operations for the three and nine months ended September 30, 2025. In addition, the Company realized a total of $30.0 million in original issue discounts on the issuance of its Term Loan Credit Agreement that was being amortized over the life of the agreement which approximates the effective interest method and was $5.7 million and $7.4 million during the nine months ended September 30, 2025 and 2024, respectively. Upon closing of the First Term Loan Amendment, which was considered an extinguishment, the remaining unamortized original issue discounts of $11.5 million was charged to expense and included in loss on extinguishment of debt in the condensed consolidated statements of operations for the three and nine months ended September 30, 2025. See Note 7 for more information. As of September 30, 2025 and December 31, 2024, the remaining net debt issuance costs related to the Term Loan Credit Agreement and Senior Credit Facility Agreement are netted against the outstanding long-term debt on the accompanying condensed consolidated balance sheets.

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. See Note 8 for additional information.

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 $41.8 million and $76.0 million, respectively.

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 $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 and are included in other expense on the condensed consolidated statements of operations along with an additional $192,000 of other items. During the nine months ended September 30, 2024, the Company incurred approximately $3.4 million in costs related to repairs to production facilities primarily damaged from a 100-year flooding event that hit our area of operation.

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 $16,000 and an expense of $519,000 in current Texas Margin Tax during the nine months ended September 30, 2025 and 2024, respectively, in the accompanying condensed consolidated financial statements.

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	$	188,862		$	271,578		$	646,710	$	834,608

Lease operating expenses		28,907			33,615			89,520		92,124
Production and ad valorem taxes		10,016			15,412			37,559		46,410
Expensed workover costs		4,405			1,798			13,080		6,358
Total significant expenses		43,328			50,825			140,159		144,892
Depletion, depreciation and amortization		100,636			136,578			311,187		395,121
General and administrative expenses, including stock-based comp		9,506			8,724			21,787		25,717
Interest expense, net		35,985			40,407			108,214		122,240
Provision for income taxes		(3,567	)		15,438			14,035		31,985
Other segment items ⁽¹⁾		21,309			(30,327	)		7,152		28,565
Total expenses		207,197			221,645			602,534		748,520

Net (loss) income	$	(18,335	)	$	49,933		$	44,176	$	86,088

Total assets	$	3,204,762		$	3,061,466		$	3,204,762	$	3,061,466

Capital costs incurred, including acquisitions	$	87,535		$	142,695		$	396,374	$	462,191

⁽¹⁾

Other segment items included in segment net income are exploration and abandonment expense, accretion of discount, other expense, gains and losses on derivative instruments and loss on extinguishment of debt.

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 $4.5 million and $10.4 million, respectively, in acquisition costs primarily to acquire various undeveloped crude oil and natural gas leases largely contiguous to its Flat Top and Signal Peak operating areas.

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 $570,000.

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	$	—	$	17,335	$	—	$	17,335
Commodity price derivatives – noncurrent		—		3,083		—		3,083
Total assets		—		20,418		—		20,418
Liabilities:
Commodity price derivatives – current		—		—		—		—
Commodity price derivatives – noncurrent		—		772		—		772
Total liabilities		—		772		—		772
Total recurring fair value measurements, net	$	—	$	19,646	$	—	$	19,646

	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	$	—	$	7,582	$	—	$	7,582
Liabilities:
Commodity price derivatives – current		—		5,380		—		5,380
Total recurring fair value measurements, net	$	—	$	2,202	$	—	$	2,202

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	$	3,266	$	33,775		$	17,444	$	(11,514	)
Cash receipts (payments) on settled derivatives, net		3,647		(1,441	)		7,988		(11,897	)
Derivative gain (loss), net	$	6,913	$	32,334		$	25,432	$	(23,411	)

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		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 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		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 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	$	16,296
Macquarie Bank Limited		2,675
Mercuria Energy Trading SA		605
J. Aron & Company LLC		70
	$	19,646

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	$	33,619
Additions to exploratory/extension well costs		101,850
Reclassification to proved properties		(105,216	)
Exploratory/extension well costs charged to exploration and abandonment expense		—
Ending capitalized exploratory/extension well costs	$	30,253

All capitalized exploratory/extension well costs have been capitalized for less than one year based on the date of drilling other than approximately $10.6 million related to one well that had been delayed for an infrastructure connection. The well is now on production pending determination of proved reserves.

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	$	1,200,000		$	1,080,000
Senior Credit Facility Agreement due 2028		—			—
Debt issuance costs, net (a)		(7,700	)		(14,419	)
Discounts, net (b)		—			(17,197	)
Total debt		1,192,300			1,048,384
Less current maturities of long-term debt		(30,000	)		(120,000	)
Long-term debt, net	$	1,162,300		$	928,384

(a)

Debt issuance costs as of September 30, 2025 and December 31, 2024 consisted of $8.8 million and $25.1 million, respectively, in costs less accumulated amortization of $1.1 million and $10.7 million, respectively. Unamortized debt issuance costs of $9.2 million were charged to expense during the nine months ended September 30, 2025 upon the closing of the First Term Loan Amendment which was considered an extinguishment of debt.

(b)

Discounts as of December 31, 2024 consisted of $30.0 million in discounts less accumulated amortization of $12.8 million. Unamortized discounts of $11.5 million were charged to expense during the nine months ended September 30, 2025 upon the closing of the First Term Loan Amendment which was considered an extinguishment of debt.

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 $1.2 billion, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement was set to mature on September 30, 2026. On August 1, 2025, the Company entered into the First Term Loan Amendment whereby, among other things, (i) the maturity was extended to September 30, 2028, (ii) borrowings were upsized to $1.2 billion, providing additional liquidity, and (iii) the quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026. As of September 30, 2025, $1.2 billion was outstanding under the Term Loan Credit Agreement. As a result of this amendment which was considered an extinguishment of debt, the Company recognized a loss on extinguishment of debt of $25.4 million consisting of (i) $11.5 million in unamortized discounts, (ii) $9.2 million in unamortized debt issuance costs and (iii) $4.7 million in premiums paid to those lenders that chose to exit the Term Loan Credit Agreement upon closing of the First Term Loan Amendment. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent a payment or other event of default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement), all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first-lien second-out security interest in substantially all assets of the Company and certain of its subsidiaries.

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 1.25 to 1.00 as of the last day of any fiscal quarter through the fiscal quarter ended June 30, 2026 and not less than 1.50 to 1.00 as of the last day of any fiscal quarter ending thereafter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with exceptions permitting, among other things, the incurrence of a super priority revolving credit facility, subject to a cap of $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, make dividends and certain other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures.

The Term Loan Credit Agreement contains customary mandatory prepayments, in addition to quarterly scheduled amortization payments of $30.0 million referenced above, consisting of prepayments with proceeds of prohibited indebtedness and asset sales (including hedge terminations) in excess of $20.0 million in any calendar year, and prepayments with a percentage of Excess Cash Flow (as defined in the Term Loan Credit Agreement) equal to 0%, 25% or 50% based on a total net leverage ratio to the extent pro forma for any such payment, the aggregate cash and cash equivalents of the Company and its restricted subsidiaries would not be less than $100.0 million as of the date of such payment (with no such excess cash flow prepayments made as of September 30, 2025). In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.

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 $100.0 million. On August 1, 2025, the Company entered into the Second Facility Amendment which, among other things, extended the maturity date to September 30, 2028, which was not considered an extinguishment of debt. As of September 30, 2025, the balance due under the Senior Credit Facility Agreement was zero. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment or other event of default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement), all amounts outstanding under the Senior Credit Facility Agreement will bear interest at 2.00% per annum above the rate otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Senior Credit Facility Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first-lien first-out security interest in substantially all assets of the Company and certain of its subsidiaries.

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	$	14,750
Liabilities incurred from new wells		671
Liabilities settled and divested		(507	)
Accretion of discount		785
Ending asset retirement obligations	$	15,699

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 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k) Plan up to four percent of the participant’s annual base salary (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances at their eligibility date. During the nine months ended September 30, 2025 and 2024, the Company contributed $303,000 and $314,000 to the 401(k) Plan, respectively.

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		16,326,322			16,414,015
Shares subject to awards issued under plan		(15,134,295	)		(15,808,671	)
Shares available for future grant		1,192,027			605,344

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 $109,000 due to certain forfeitures and $86,000, respectively, and as of September 30, 2025 there was no unrecognized stock-based compensation expense related to unvested stock option awards. The 1,949,000 stock options granted in July 2023 were 100% vested upon grant on July 21, 2023. However, to encourage long-term alignment with the Company stockholders, the stock options are not exercisable until the earlier of (i) August 31, 2026, (ii) upon a change in control or (iii) upon the death or disability of the grantee.

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		13,449,061		$	11.95		6.3	$	47,672
Forfeitures		(4,999	)	$	26.44
Outstanding at December 31, 2024		13,444,062		$	11.95		5.3	$	53,093
Forfeitures		(739,168	)	$	24.99
Outstanding at September 30, 2025		12,704,894		$	11.19		4.5	$	—

Vested at December 31, 2024		13,444,062		$	11.95		5.3	$	53,093
Exercisable at December 31, 2024		11,495,062		$	12.19		5.9	$	44,907

Vested at September 30, 2025		12,704,894		$	11.19		4.5	$	—
Exercisable at September 30, 2025		10,755,894		$	11.31		5.1	$	—

Restricted stock issued to employee members of the Board and certain employees. A total of 1,500,500 shares of restricted stock was approved by the Board to be granted to certain employee members of the Board of the Company on November 4, 2021, which were set to vest on the three-year anniversary of such grant assuming the employees remain in his or her position as of the anniversary date. Therefore, stock-based compensation expense of zero and $5.4 million was recognized during the nine months ended September 30, 2025 and 2024, respectively, and there is no remaining unrecognized stock-based compensation expense as of September 30, 2025 to be recognized, which was based upon the closing price of the stock on the date of the restricted stock issuance. The Board also approved a total of 600,000 shares of restricted stock to be granted to certain employees of the Company on June 1, 2022, which were set to vest on November 4, 2024, assuming the employees remain in his or her position as of that date. Therefore, stock-based compensation expense of zero and $5.3 million was recognized during the nine months ended September 30, 2025 and 2024, respectively, and there is no remaining unrecognized stock-based compensation expense as of September 30, 2025 to be recognized, which was based upon the closing price of the stock on the date of the restricted stock issuance. On October 31, 2024, the vesting date for the aforementioned 2,100,500 shares of restricted stock was extended from November 4, 2024 to December 31, 2025 to ensure said restricted stock would continue to provide retention value to the Company. There is no excess stock-based compensation expense as the closing price on the modification date was lower than the original grant dates. On September 15, 2025, the Company’s Chief Executive Officer retired and in conjunction with said retirement, the 1,385,500 shares of restricted stock issued to him vested immediately. As a result, 545,195 shares were withheld and cancelled in lieu of $3.8 million in cash taxes withheld and paid by the Company on his behalf.

Stock issued to outside directors. A total of 64,792 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 3, 2025, which will vest at the next annual meeting, assuming the Board members maintain their positions on the Board. Therefore, stock-based compensation expense of $236,000 was recognized during the nine months ended September 30, 2025 and the remaining $472,000 will be recognized during the remainder of 2025 and through May 2026, which was based upon the closing price of the stock on the date of the restricted stock issuance. In addition, a total of 53,879 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 4, 2024 and which vested on June 3, 2025. Therefore, stock-based compensation expense of $316,000 and $253,000 was recognized during the nine months ended September 30, 2025 and 2024, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. Finally, a total of 58,767 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2023, which vested on June 4, 2024. Therefore, stock-based compensation expense of zero and $316,000 was recognized during the nine months ended September 30, 2025 and 2024, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance.

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 $1.2 million included in other noncurrent assets and operating lease liabilities totaling $1.2 million, $885,000 of which is included in current liabilities and $327,000 of which is included in noncurrent liabilities, and as of December 31, 2024 the Company had right-of-use assets totaling $1.4 million included in other noncurrent assets and operating lease liabilities totaling $1.4 million, $719,000 of which are included in current liabilities and $670,000 of which are included in noncurrent liabilities on the accompanying condensed consolidated balance sheets. The Company does not currently have any finance right-of-use leases. Maturities of the operating lease obligations are as follows (in thousands):

	September 30, 2025
Remainder of 2025	$	247
2026		888
2027		118
		31
Total		1,284
Less present value discount		(72	)
Present value of lease liabilities	$	1,212

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 $138.7 million based on the gross piped barrels delivered of 23,500 Bopd for the first ten years of the contract at a certain amount per barrel escalating throughout the term of the contract. However, the Company generally has the ability under the contract to cumulatively bank dollars based on excess volumes delivered to offset the minimum volume commitment. For the period from May 1, 2024 to September 30, 2025, the Company has delivered approximately 31,572 Bopd under the contract. The remaining monetary commitment as of September 30, 2025, if the Company never delivers any additional volumes under the agreement, is approximately $119.7 million.

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 $18.6 million and $5.4 million during the nine months ended September 30, 2025 and the year ended December 31, 2024, respectively. In addition, throughout the remainder of 2025 and first quarter of 2026, the Company has a remaining commitment under the contract of $8.6 million as certain milestones are attained. The agreement does not contain any minimum volume commitments.

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 $4.6 million Letter of Credit in place in lieu of a deposit that is cancellable at the end of the contract term.

Sand commitments. The Company was party to an amended agreement whereby it agreed to purchase at least 750,000 tons of sand over a fifteen-month period beginning April 1, 2024. The Company has taken all deliveries required under this contract and there is no further monetary commitment as of September 30, 2025.

NOTE 11. Major Customers

Delek accounted for approximately 88% and 76% and Energy Transfer Crude Marketing, LLC (“ETC”) accounted for approximately 9% and 19% of the Company’s revenues during the nine months ended September 30, 2025 and 2024, respectively. Based on the current demand for crude oil and natural gas and the availability of other purchasers, management believes the loss of either of these major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

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	$	(20	)	$	293	$	(20	)	$	569
State		(16	)		218		(16	)		519
Total current income tax (benefit) expense		(36	)		511		(36	)		1,088
Deferred income tax (benefit) expense:
Federal		(3,804	)		14,390		13,030			29,703
State		273			537		1,041			1,194
Deferred income tax (benefit) expense		(3,531	)		14,927		14,071			30,897
Total provision for income taxes	$	(3,567	)	$	15,438	$	14,035		$	31,985

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	$	(4,600	)	$	13,728		$	12,224		$	24,795
Limited tax benefit due to compensation limitations		1,054			861			1,050			5,297
State deferred income taxes		257			709			1,025			1,604
Other, net		(278	)		140			(264	)		289
Provision for income taxes	$	(3,567	)	$	15,438		$	14,035		$	31,985
Effective income tax rate		16.3	%		23.6	%		24.1	%		27.1	%

The effective income tax rate differs from the U.S. statutory rate of 21 percent primarily due to certain stock-based compensation which exceeds the federal limits, deferred state income taxes and other permanent differences between GAAP income and taxable income. The effective tax rates for the three and nine months ended September 30, 2024 were also affected by a $3.0 million adjustment further discussed below.

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	$	89,893		$	73,013
Net operating loss carryforwards		24,980			13,089
Stock-based compensation		3,285			3,351
Other		246			35
Less: Valuation allowance		—			—
Deferred tax assets		118,404			89,488
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		(360,631	)		(321,411	)
Unrecognized derivative gains, net		(4,242	)		(475	)
Deferred tax liabilities		(364,873	)		(321,886	)
Net deferred tax liabilities	$	(246,469	)	$	(232,398	)

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 $1.0 million per year for certain Company executives. This resulted in a $3.0 million reduction in the deferred tax asset and increased the amount of income tax expense realized during the nine months ended September 30, 2024.

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 $16,000 and an expense of $519,000 in current Texas margin tax in the accompanying condensed consolidated financial statements for the nine months ended September 30, 2025 and 2024, respectively. In addition, the Company has recognized a net deferred Texas margin tax liability of $9.7 million and $8.6 million as of September 30, 2025 and December 31, 2024, respectively, in the accompanying condensed consolidated balance sheets.

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 $351,000, respectively, recognized as part of the cost basis of the stock repurchased in the condensed consolidated statements of changes in stockholders’ equity.

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	$	(18,335	)	$	49,933		$	44,176		$	86,088
Participating basic earnings (a)		(531	)		(4,835	)		(4,129	)		(8,280	)
Basic (losses) earnings attributable to common stockholders		(18,866	)		45,098			40,047			77,808
Reallocation of participating earnings		—			66			14			102
Diluted net (loss) income attributable to common stockholders	$	(18,866	)	$	45,164		$	40,061		$	77,910

Basic weighted average shares outstanding		124,807			124,988			124,807			125,595
Dilutive warrants and unvested stock options		—			1,952			—			1,832
Dilutive unvested restricted stock		—			2,154			780			2,154
Diluted weighted average shares outstanding		124,807			129,094			125,587			129,581

(a)

Vested stock options represent participating securities because they participate in dividend equivalents with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Certain unvested restricted stock awarded to outside directors, employee members of the Board and certain employees do not represent participating securities because, while they participate in dividends with the common equity holders of the Company, the dividends associated with such unvested restricted stock are forfeitable in connection with the forfeitability of the underlying restricted stock. Unvested stock options do not represent participating securities because, while they participate in dividend equivalents with the common equity holders of the Company, the dividend equivalents associated with unvested stock options are forfeitable in connection with the forfeitability of the underlying stock options.

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 $75.0 million of the Company’s outstanding common stock, excluding excise taxes and other expenses, which expires on December 31, 2025. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the nine months ended September 30, 2025 and the year ended December 31, 2024, the Company repurchased zero and 2,407,421, respectively, shares of common stock that were cancelled and terminated for a total of approximately zero and $35.1 million, respectively. As of September 30, 2025, up to approximately $39.9 million remained available for use to repurchase shares under the Company’s common stock repurchase program, excluding excise taxes and other expenses.

Issuance of Common Stock. During the nine months ended September 30, 2025 and 2024, the Company issued 60 and 55 shares of HighPeak Energy common stock, respectively, as a result of warrants being exercised. All of the Company’s outstanding warrants expired on August 21, 2025.

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 dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. Also, simultaneously with the aforementioned retirement of our former Chief Executive Officer in September 2025, previously accrued $665,000 in dividends were paid in respect of his restricted stock vesting on that date.

In May 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 June 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 June 2025. In addition, the Company accrued an additional combined $84,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In February 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 March 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 March 2025. In addition, the Company accrued an additional combined $86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In August 2024, 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 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $534,000 in September 2024 and accrued a dividend equivalent per share to all unvested stock option holders which will be payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In May 2024, 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 June 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $538,000 in June 2024. In addition, the Company accrued an additional combined $84,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In February 2024, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.1 million in dividends being paid in March 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $530,000 in March 2024. In addition, the Company accrued an additional combined $86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Outstanding securities. As of September 30, 2025 and December 31, 2024, the Company had 125,587,093 and 126,067,436 shares of common stock outstanding, respectively, and zero and 7,934,922 warrants outstanding, respectively, with an exercise price of $11.50 per share. All of the Company’s outstanding warrants expired on August 21, 2025.

NOTE 15. Subsequent Events

Dividends and dividend equivalents. In November 2025, the Board approved a quarterly dividend of $0.04 per share of common stock outstanding which will result in a total of approximately $5.0 million in dividends to be paid in December 2025. In addition, under the terms of the LTIP, the Company will pay a dividend equivalent per share to all vested stock option holders of approximately $502,000 in December 2025. In addition, the Company will accrue an additional combined $31,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

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,

HighPeak Energy, Inc. 10-Q