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 March 31, 2026
or
☐
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).
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 April 30, 2026, there were 126,358,104 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
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
27
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
40
Item 4.
Controls and Procedures
41
PART II. OTHER INFORMATION
Legal Proceedings
Item 1A.
Risk Factors
Item 5.
Other Information
42
Item 6.
Exhibits
Signatures
43
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, 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.
“Second Term Loan Amendment” means the Second Amendment to the Term Loan Credit Agreement, dated March 5, 2026, 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.
“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.
“Third Facility Amendment” means the Third Amendment to Senior Credit Facility Agreement, dated March 5, 2026, by and between HighPeak Energy, Inc., as borrower, Fifth Third Bank, National Association, as administrative agent, the guarantors party thereto and the lenders 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 interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
“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.
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;
the results of our ongoing strategic alternatives review process;
inflation rates and 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, conflicts in the Middle East and U.S. intervention in Venezuela;
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, including 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 availability of capital resources;
our ability to maintain compliance with the covenants in our debt agreements and 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;
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; 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, 2025 filed with the SEC on March 11, 2026 (“Annual Report”) 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.
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands, except share data)
March 31,
2026
December 31,
2025
(Unaudited)
Current assets:
Cash and cash equivalents
Accounts receivable
Derivative instruments
Prepaid expenses
Inventory
Total current assets
Crude oil and natural gas properties, using the successful efforts method of accounting:
Proved properties
Unproved properties
Accumulated depletion, depreciation and amortization
)
Total crude oil and natural gas properties, net
Other property and equipment, net
Other noncurrent assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt
Accounts payable – trade
Revenues and royalties payable
Accrued capital expenditures
Derivative settlements payable
Other accrued liabilities
Operating leases
Advances from joint interest owners
Total current liabilities
Noncurrent liabilities:
Long-term debt, net
Deferred income taxes
Asset retirement obligations
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at March 31, 2026 and December 31, 2025
Common stock, $0.0001 par value, 600,000,000 shares authorized, 126,358,104 and 125,330,104 shares issued and outstanding at March 31, 2026 and December 31, 2025, respectively
Additional paid-in capital
Retained earnings
Total stockholders’ equity
Total liabilities and stockholders’ equity
The accompanying notes are an integral part of these condensed consolidated financial statements.
(in thousands, except per share data)
Three Months Ended March 31,
Operating Revenues:
Crude oil sales
NGL and natural gas sales
Total operating revenues
Operating Costs and Expenses:
Crude oil and natural gas production
Gathering, processing and transportation
Production and ad valorem taxes
Exploration and abandonments
Depletion, depreciation and amortization
Accretion of discount
General and administrative
Stock-based compensation
Total operating costs and expenses
Other expense
Income from operations
Interest income
Interest expense
Loss on derivative instruments, net
(Loss) income before income taxes
Provision for income taxes
Net (loss) income
(Loss) earnings per share:
Basic net (loss) income
Diluted net (loss) income
Weighted average shares outstanding:
Basic
Diluted
Dividends declared per share
Condensed Consolidated Statements of Changes in Stockholders' Equity
(in thousands)
Three Months Ended March 31, 2026
Shares
Outstanding
Common
Stock
Additional
Paid-in-
Capital
Retained
Earnings
Total
Stockholders'
Equity
Balance, December 31, 2025
Stock-based compensation costs:
Restricted shares issued to employees
Compensation costs included in net income
Net loss
Balance, March 31, 2026
Three Months Ended March 31, 2025
Balance, December 31, 2024
Dividends declared ($0.04 per share)
Dividend equivalents declared on outstanding stock options ($0.04 per share)
Net income
Balance, March 31, 2025
CASH FLOWS FROM OPERATING ACTIVITIES:
Adjustments to reconcile net (loss) income to net cash provided by operations:
Provision for deferred income taxes
Cash paid on settlement of derivative instruments
Amortization of debt issuance costs
Amortization of discounts on long-term debt
Stock-based compensation expense
Accretion expense
Depletion, depreciation and amortization expense
Exploration and abandonment expense
Changes in operating assets and liabilities:
Prepaid expenses, inventory and other assets
Accounts payable, accrued liabilities and other current liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties
Changes in working capital associated with oil and gas property additions
Acquisitions of crude oil and natural gas properties
Proceeds from sales of properties
Other property additions
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt issuance costs
Repayments under Term Loan Credit Agreement
Dividends paid
Dividend equivalents paid
Net cash used in financing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental cash flow information:
Cash paid for interest
Cash paid for (received from) income taxes
Supplemental disclosure of non-cash transactions:
Additions to asset retirement obligations
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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, 2025, filed with the U.S. Securities and Exchange Commission (“SEC”) on March 11, 2026, 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 March 31, 2026 and for the three months ended March 31, 2026 and 2025 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 reclassifications have been made to prior period amounts to conform to the current period’s presentation, specifically gathering, processing and transportation expenses, which were previously netted against NGL and natural gas sales and are now reflected as a component of total operating costs and expenses, which had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. The operating results for the three months ended March 31, 2026 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, 2025.
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 consolidated financial statements. Preparation of the Company's 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 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 March 31, 2026 and December 31, 2025, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $76.8 million and $35.4 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, a receivable from the State of Texas of $10.0 million for a multi-year natural gas severance tax refund as of both March 31, 2026 and December 31, 2025, receivables from electric power infrastructure installed throughout Flat Top by the Company for which it will be reimbursed totaling $4.1 million and $224,000, respectively, joint interest receivables of $3.4 million and $4.8 million, respectively, current U.S. federal income tax receivables of $2.9 million and $3.2 million, respectively, and receivables related to settlements of derivative contracts of $1.2 million and $1.9 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 March 31, 2026 and December 31, 2025, 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 three months ended March 31, 2026 and 2025, sales to the Company’s largest purchaser accounted for approximately 86% and 81%, respectively, of the Company’s total crude oil, NGL and natural gas sales revenues and sales to the Company’s second largest purchaser accounted for approximately 6% and 10%, respectively, of the Company’s total crude oil, NGL and natural gas 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 consolidated balance sheet and as charges to other expense in the consolidated statements of operations. The Company’s materials and supplies inventory as of March 31, 2026 and December 31, 2025 is $4.4 million and $7.6 million, respectively, and the Company has not recognized any valuation allowance to date.
Prepaid expenses. Prepaid expenses are comprised primarily of fees related to advisory services that will be deducted from eventual commissions on a future transaction, if any, caliche that will be used on future locations and roads in our development areas and prepaid agency fees and software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of March 31, 2026 and December 31, 2025 are $5.6 million and $5.1 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 wells 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 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, net of accumulated depreciation of $1.4 million and $1.3 million as of March 31, 2026 and December 31, 2025, respectively, are as follows (in thousands):
Land
Buildings
Transportation equipment
Leasehold improvements
Field equipment
Furniture and fixtures
Total other property and equipment, net
Other property and equipment are depreciated over their estimated useful life on a straight-line basis. Land is not depreciated. Transportation equipment is generally depreciated over five years, buildings are generally depreciated over forty years, field equipment is generally depreciated over seven years and furniture and fixtures is generally depreciated over five years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method.
Aid-in-construction assets. As of March 31, 2026 and December 31, 2025, the Company had aid-in-construction assets totaling $14.7 million and $15.2 million, respectively, included in other noncurrent assets. The Company funded aid-in-construction projects during the three months ended March 31, 2026 and 2025 of zero and zero, 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 three months ended March 31, 2026 and 2025 were approximately $520,000 and $375,000, respectively. The contract calls for future additional 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 March 31, 2026 and December 31, 2025 totaled approximately $317.1 million and $230.3 million, respectively, including current maturities of long-term debt, derivative liabilities, trade accounts payable, revenues and royalties payable, accrued capital expenditures, derivative settlements payable and accruals for operating and general and administrative expenses, interest expense, operating leases and other miscellaneous items.
Debt issuance costs and original issue discount. The Company has paid and has capitalized a total of $15.0 million in debt issuance costs, $6.1 and $7.9 million of which was incurred during the three months ended March 31, 2026 and the year ended December 31, 2025, respectively, primarily related to amendments to the Term Loan Credit Agreement and Senior Credit Facility Agreement in March 2026 and August 2025, respectively. 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 $884,000 and $2.0 million during the three months ended March 31, 2026 and 2025, respectively. 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 were being amortized over the life of the agreement which approximates the effective interest method and was zero and $2.4 million during the three months ended March 31, 2026 and 2025, respectively. All unamortized debt issuance costs and discounts as of the refinancing of the Term Loan Credit Agreement in August 2025 were charged to expense and included in loss on extinguishment of debt. See Note 7 for more information. As of March 31, 2026 and December 31, 2025, 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 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 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 March 31, 2026 and December 31, 2025, the Company had receivables related to contracts with purchasers of approximately $76.8 million and $35.4 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 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. 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 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 counterparties’ 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.
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 March 31, 2026 and December 31, 2025.
Tax benefits from uncertain tax positions 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 13 for additional information.
Tax-related interest charges are recorded as interest expense and any tax-related penalties as other expense in the consolidated statements of operations of which there have been none to date.
The Company is also subject to Texas margin tax. The Company realized zero related to current Texas margin tax for the three months ended March 31, 2026 and 2025 in the accompanying consolidated financial statements.
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 or modification 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.
Reportable 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 income. We believe net income provides information useful in assessing our operating and financial performance across periods.
The following table reflects the Company’s net income, assets and capital expenditures for the Company’s one reporting segment for the time periods presented:
Lease operating expenses
Gathering, processing and transportation expenses
Expense workover costs
Total significant expenses
General and administrative expenses, including stock-based comp
Interest expense, net(1)
Other segment items(2)
Total expenses
Capital costs incurred, including acquisitions
(1)
Interest expense, net included in segment net income includes interest expense and loss on extinguishment of debt, partially offset by interest income.
(2)
Other segment items included in segment net income are exploration and abandonment expense, accretion of discount, other expense and gains and losses on derivative instruments.
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. The Company adopted this update effective December 31, 2025. While the adoption of this ASU modified the Company’s disclosures, it had no impact on the Company’s consolidated balance sheets, consolidated statements of operations or consolidated statements of cash flows in its 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 consolidated balance sheets, consolidated statements of operations or consolidated statements of cash flows in its 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 three months ended March 31, 2026 and 2025, the Company incurred a total of $127,000 and $2.5 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 three months ended March 31, 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
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available techniques based on available inputs to measure the fair value of its assets and liabilities.
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis as of March 31, 2026 and December 31, 2025 are as follows (in thousands):
As of March 31, 2026
(Level 1)
(Level 2)
(Level 3)
Total Gross Fair Value
Assets:
Commodity price derivatives – current
Commodity price derivatives – noncurrent
Liabilities:
Total liabilities
Total recurring fair value measurements, net
As of December 31, 2025
Total recurring fair value measurements
Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil swap contracts, costless collars, roll swaps 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 consolidated financial statements.
Financial instruments not carried at fair value. As of March 31, 2026 and December 31, 2025, 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 utilizes derivative financial instruments, primarily swaps, costless collars, basis swaps and roll swaps 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 Company has not designated its derivative financial instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
The following table summarizes the effect of derivative instruments on the Company’s condensed consolidated statements of operations (in thousands):
Noncash loss on derivative instruments, net
Cash paid on settlement of derivative instruments, net
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company has entered into commodity derivative instruments only with counterparties that are also lenders under its Term Loan Credit Agreement and Senior Credit Facility Agreement and have been deemed acceptable credit risk. As such, collateral is not required from either the counterparties or the Company on its outstanding derivative contracts.
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 and NYMEX WTI roll 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 March 31, 2026 and the weighted average crude oil prices per barrel for those contracts are as follows:
Settlement
Month
Year
Type of
Contract
Bbls
Per Day
Index
Swap
Price per
Bbl
Costless
Collar
Floor
Ceiling
Crude Oil:
Apr – Jun
Costless Collar
WTI Cushing
Roll Swap
NYMEX WTI Roll
Basis Swap
Argus WTI Midland
Jul – Sep
Oct – Dec
Jan – Mar
2027
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 March 31, 2026 and the weighted average natural gas prices per MMBtu for those contracts are as follows:
Settlement Month
MMBtu
Natural Gas:
HH
$
Balance Sheet Offsetting of Derivative Assets and Liabilities. The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. While it is acceptable to record these fair values by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement, the Company elects to record them at the gross level showing assets and liabilities as if they were settled separately. See Note 4 – Fair Value Measurements for further details. Net derivative assets associated with the Company’s open commodity derivative instruments by counterparty are as follows (in thousands):
As of
Fifth Third Bank, National Association
Macquarie Bank Limited
J. Aron & Company LLC
Mercuria Energy Trading SA
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):
Three Months
Ended
Beginning capitalized exploratory/extension well costs
Additions to exploratory/extension well costs
Reclassification to proved properties
Exploratory/extension well costs charged to exploration and abandonment expense
Ending capitalized exploratory/extension well costs
All capitalized exploratory/extension well costs have been capitalized for less than one year based on the date of drilling.
NOTE 7. Long-Term Debt
The components of long-term debt, including the effects of debt issuance costs, are as follows (in thousands):
Term Loan Credit Agreement due 2028
Senior Credit Facility Agreement due 2028
Debt issuance costs, net (a)
Total debt
Less current maturities of long-term debt
(a)
Debt issuance costs as of March 31, 2026 and December 31, 2025 consisted of $15.0 million and $8.9 million, respectively, in costs less accumulated amortization of $2.6 million and $1.7 million, respectively.
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 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. Effective as of December 30, 2025, the Company entered into the Second Term Loan Amendment whereby, among other things, (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourth Quarter of 2025 and the first quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the second quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to this amendment. As of March 31, 2026, $1.2 billion was outstanding under the Term Loan Credit Agreement. 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, which will require the Company to comply with an asset coverage ratio of not less than 1.25:1.00 for the fiscal quarter ending June 30, 2026 and 1.50:1.00 for fiscal quarters ending thereafter and a total net leverage ratio of not greater than 2.00:1.00 for the fiscal quarter ending June 30, 2026 and fiscal quarters ending thereafter.
The Term Loan Credit Agreement contains customary 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.
In addition, 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 March 31, 2026). The Term Loan Credit Agreement is subject to customary events of default, including upon the occurrence of 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. Effective as of December 30, 2025, the Company entered into the Third Facility Amendment whereby, among other things, (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the second quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to this amendment. As of March 31, 2026, 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):
Beginning asset retirement obligations
Liabilities incurred from new wells
Ending asset retirement obligations
As of March 31, 2026 and December 31, 2025, 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 three months ended March 31, 2026 and 2025, the Company contributed $255,000 and $173,000 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 March 31, 2026 and December 31, 2025 are as follows:
Approved and authorized shares
Shares subject to awards issued under plan
Shares available for future grant
Stock options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021, May 4, 2022, August 15, 2022 and July 21, 2023. Stock-based compensation expense related to the Company’s stock option awards for the three months ended March 31, 2026 and 2025 was zero and a negative $12,000 due to certain forfeitures, respectively, and as of March 31, 2026 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. In 2025, 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 the stock options granted was determined based on the simplified method of the midpoint between the vesting dates and the contractual term of the stock options. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the stock 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:
Options
Average
Exercise
Price
Remaining
Term in
Years
Intrinsic
Value (in
thousands)
Outstanding at December 31, 2024
Forfeitures
Outstanding at December 31, 2025
Outstanding at March 31, 2026
Vested at December 31, 2025
Exercisable at December 31, 2025
Vested at March 31, 2026
Exercisable at March 31, 2026
Restricted stock issued to 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, no stock-based compensation expense was recognized during the three months ended March 31, 2026 and 2025, and there is no remaining unrecognized stock-based compensation expense as of March 31, 2026 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, no stock-based compensation expense was recognized during the three months ended March 31, 2026 and 2025, and there is no remaining unrecognized stock-based compensation expense as of March 31, 2026 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. On December 31, 2025, the remaining 715,000 shares of restricted stock issued to certain other employees vested. As a result, 256,989 shares were withheld and cancelled in lieu of $1.2 million in cash taxes withheld and paid by the Company on their behalf. On January 9, 2026, a total of 1,028,000 shares of restricted stock was approved by the Board to be granted to certain employees of the Company which will vest pro-rata over the next three years assuming the employees remain in his or her position as of the annual anniversary dates. Therefore, compensation expense of $688,000 and zero was recognized during the three months ended March 31, 2026 and 2025, respectively, and there is $3.8 million in unrecognized stock-based compensation expense as of March 31, 2026 to be recognized, which was based upon the closing price of the stock on the date of the restricted stock issuance.
Restricted 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 $177,000 was recognized during the three months ended March 31, 2026 and the remaining $118,000 will be recognized 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 zero and $189,000 was recognized during the three months ended March 31, 2026 and 2025, 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 March 31, 2026 the Company had right-of-use assets totaling $728,000 included in other noncurrent assets and operating lease liabilities totaling $757,000, $661,000 of which is included in current liabilities and $96,000 of which is included in noncurrent liabilities, and as of December 31, 2025 the Company had right-of-use assets totaling $957,000 included in other noncurrent assets and operating lease liabilities totaling $987,000, $845,000 of which are included in current liabilities and $142,000 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):
Remainder of 2026
2028
Less present value discount
Present value of lease liabilities
Legal actions. From time to time, the Company may be a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable, and the amount of the loss can be reasonably estimated.
Indemnifications. The Company has agreed to indemnify its directors, officers and certain employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
Environmental. Environmental expenditures that relate to an existing condition caused by past operations and have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs.
Crude oil delivery commitments. In September 2024, the Company entered into an amended and restated crude oil marketing contract with DK Trading & Supply, LLC (“Delek”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from the majority of its horizontal wells in Flat Top and Signal Peak where DKL is continually expanding their crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries. The contract contains a minimum volume commitment commencing May 2024 that totals $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 March 31, 2026, the Company has delivered approximately 32,077 Bopd under the contract. The remaining monetary commitment as of March 31, 2026, if the Company never delivers any additional volumes under the agreement, is approximately $111.7 million.
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.
NOTE 11. Related Party Transactions
Retirement of Jack Hightower. On September 16, 2025, the Company announced Mr. Jack Hightower’s retirement and resignation from his role as Chief Executive Officer and Chairman of the Board of the Company, effective as of September 15, 2025 (the “Separation Date”). In connection with Mr. Hightower’s notice of retirement and resignation from employment with the Company and his resignation from the Board, the Company entered into a Separation Agreement and General Release of Claims with Mr. Hightower on September 15, 2025 (the “Separation Agreement”), pursuant to which Mr. Hightower released the Company and its affiliates from certain liabilities and agrees to certain restrictive covenants. The Company, in turn, released Mr. Hightower from certain liabilities and provided Mr. Hightower with certain payments and benefits pursuant to the terms and conditions of the Separation Agreement, which, among other things, modified the benefits provided under Mr. Hightower’s outstanding equity awards, namely, his outstanding stock option grant notices and agreements, dated August 24, 2020, November 4, 2021, May 4, 2022, and August 15, 2022, respectively (the “Stock Option Agreements”), and his certain restricted stock agreement and the amendment thereto, dated November 4, 2021 and October 31, 2024, respectively (the “Restricted Stock Agreement”). The Separation Agreement provided for (i) Mr. Hightower’s 1,385,500 unvested shares outstanding under the Restricted Stock Agreement to fully vest as of the Separation Date; (ii) extending the period in which Mr. Hightower may exercise the stock options pursuant to the 2020 and 2021 Stock Option Agreements such that the stock options pursuant to such agreements remains exercisable by Mr. Hightower until the date that is twelve (12) months following the Separation Date; (iii) forfeiture by Mr. Hightower of the right to exercise the outstanding stock options granted pursuant to the 2022 Stock Option Agreements as of the Separation Date; (iv) a cash separation payment to Mr. Hightower in the amount of $2,400,000, payable on the Company’s next regularly scheduled payroll date after the Separation Date and (v) the registration of Mr. Hightower’s 1,532,478 founder’s shares as soon as reasonably possible following the Separation Date.
NOTE 12. Major Customers
Delek accounted for approximately 86% and 81% and Energy Transfer Crude Marketing, LLC (“ETC”) accounted for less than 10% and approximately 10% of the Company’s revenues during the three months ended March 31, 2026 and 2025, 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 13. Income Taxes
Income Tax (Benefit) Expense
The following table presents the Company’s income tax (benefit) expense (in thousands):
Current income tax (benefit) expense:
Federal
State
Total current income tax (benefit) expense
Deferred income tax (benefit) expense:
Deferred income tax (benefit) expense
Income tax (benefit) expense
The income tax (benefit) expense differed from the amounts computed by applying the U.S. federal income tax rate to (losses) earnings before income taxes as a result of the following (in thousands, except rate):
Income tax (benefit) expense at U.S. federal statutory rate
State income tax, net of federal income tax effect (1)
Tax Credits
Changes in valuation allowances
Nontaxable or nondeductible items:
Limited tax benefit due to compensation
Annualized loss limitation
Other
Changes in unrecognized tax benefits
Other, net
State taxes in Texas make up 100% of the tax effect of this category.
Income taxes were (received from) paid to the following jurisdictions (in thousands):
Total income taxes paid
On July 4, 2025, the “One Big Beautiful Bill” (“OBBB”) was signed into law. The OBBB is a significant piece of tax legislation that includes provisions that restore 100% bonus depreciation under section 168(k) for certain property place in service after January 19, 2025, allow for the expensing of domestic R&D expenditures beginning in 2025, and allow for the deduction of intangible drilling costs as part of the computation of the corporate alternative minimum tax beginning in 2026. The OBBB did not have a significant impact on the Company’s income tax expense.
Deferred Tax Assets and Liabilities
The following table presents the tax effects of temporary differences that give rise to the Company’s deferred tax assets and liabilities (in thousands):
Deferred tax assets:
Interest expense limitations
Net operating loss carryforwards
Unrecognized derivative losses, net
Less: Valuation allowance
Deferred tax assets
Deferred tax liabilities:
Crude oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes
Unrecognized derivative gains, net
Deferred tax liabilities
Net deferred tax liabilities
As required by ASC Topic 740, “Income Taxes,” (“ASC 740”) the Company uses reasonable judgments and makes estimates and assumptions related to evaluating the probability of uncertain tax positions. The Company bases its estimates and assumptions on the potential liability related to an assessment of whether the income tax position will “more likely than not” be sustained in an income tax audit. Based on that analysis, the Company believes the Company has not taken any material uncertain tax positions, and therefore has not recorded an income tax liability related to uncertain tax positions. However, if actual results materially differ, the Company’s effective income tax rate and cash flows could be affected in the period of discovery or resolution. The Company also reviews the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company’s deferred tax assets and records a valuation allowance when the Company believes that a portion or all the deferred tax assets may not be realized. If the Company is unable to realize the expected future benefits of its deferred tax assets, the Company is required to provide a valuation allowance. The Company uses its history and experience, overall profitability, future management plans, tax planning strategies, and current economic information to evaluate the amount of valuation allowance to record. As of March 31, 2026 and December 31, 2025, 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 is also subject to Texas margin tax. The Company realized zero in current Texas margin tax in the accompanying consolidated financial statements for the three months ended March 31, 2026 and 2025. The Company has recognized a net deferred Texas margin tax liability of $9.1 million and $9.7 million as of March 31, 2026 and December 31, 2025, respectively, in the accompanying condensed consolidated balance sheets.
NOTE 14. (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 months ended March 31, 2026 and 2025 under the two-class method (in thousands):
Three Months Ended
Net (loss) income as reported
Participating basic earnings (a)
Basic (losses) earnings attributable to common stockholders
Reallocation of participating earnings
Diluted net (loss) income attributable to common stockholders
Basic weighted average shares outstanding
Dilutive warrants and unvested stock options
Dilutive unvested restricted stock
Diluted weighted average shares outstanding
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 15. Stockholders’ Equity
Issuance of Common Stock. During the three months ended March 31, 2026 and 2025, the Company issued 1,028,000 and zero shares, respectively, of restricted stock to certain employees of the Company and zero and 60 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 the first quarter of 2026, the Board elected to discontinue the quarterly dividend. 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.
Outstanding securities. As of March 31, 2026 and December 31, 2025, the Company had 126,358,104 and 125,330,104 shares of common stock outstanding, respectively.
NOTE 16. Subsequent Events
Crude oil derivative financial instruments. Subsequent to March 31, 2026, the Company entered into the following additional crude oil derivative financial instruments:
Swap Price
per Bbl
Basic Swap
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and related notes. This discussion contains certain “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. These forward-looking statements involve risks and uncertainties and actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read “Cautionary Statement Concerning Forward‑Looking Statements.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law.
Overview
HighPeak Energy, Inc., a Delaware corporation, was formed in October 2019, is an independent crude oil and natural gas exploration and production company that explores for, develops and produces crude oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin. The Company’s assets are located primarily in Howard and Borden Counties, Texas, and to a lesser extent Scurry and Mitchell Counties, which lie within the northeastern part of the crude oil-rich Midland Basin. As of March 31, 2026, the assets consisted of two highly contiguous leasehold positions of approximately 152,201 gross (140,439 net) acres, approximately 74% of which were held by production, with an average working interest of 92%. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern portion of Howard County. We operate approximately 98% of the net acreage across the Company’s assets and more than 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the three months ended March 31, 2026, approximately 84% and 16% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of March 31, 2026, HighPeak Energy was developing its properties using one (1) drilling rig and expects to average one (1) drilling rig and one (1) frac crew during the remainder of 2026 under our current development plan, depending on certain market conditions.
Recent Events
Debt amendments and actions taken to bolster covenant compliance. In August 2025, the Company entered into the First Term Loan Amendment and the Second Facility Amendment which amended the Term Loan Credit Agreement and the Senior Credit Facility Agreement whereby, among other things, (i) the maturity date was extended two years to September 2028, (ii) Term Loan Credit Agreement was upsized to $1.2 billion, providing additional liquidity, and (iii) the Term Loan Credit Agreement quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026.
Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company has entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourth Quarter of 2025 and the First Quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the Fourth Quarter of 2025 and the First Quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the Second Quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels currently in effect for such quarters prior to this amendment. It is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the Second Quarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. Any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder.
Acquisitions. During the three months ended March 31, 2026, the Company incurred a total of $127,000 in acquisition costs related to lease extensions and to acquire additional crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage to its Flat Top and Signal Peak operating areas.
Crude Oil and Natural Gas Industry Considerations. Our operating results, and those of the crude oil and natural gas industry as a whole, are heavily influenced by commodity prices. Crude oil, NGL and natural gas prices and basis differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term.
Throughout 2025, OPEC and its non-OPEC allies, known collectively as OPEC+, began unwinding prior voluntary production cuts, completing the reversal of its prior 2.2 million bopd cutback from 2023, but paused production increases in early 2026. This substantial supply boost contributed to a decline in global crude oil prices during the year ended December 31, 2025 and through February 2026. OPEC+ also emphasized that the production increases could continue or be reversed depending on how market conditions evolve, maintaining flexibility to support price stability. With the recent war in Iran and the closing of the Strait of Hormuz, crude oil prices have increased significantly beginning in March 2026, which the Company expects to be temporary depending on when the war comes to an end. Further complicating crude oil markets is the exit of the UAE from OPEC+, which the Company anticipates could exert further downward pressure on oil prices with their supposed additional capacity to increase production. Concurrently, the U.S. imposed tariffs on energy imports from Canada and Mexico, set at 10% and 25%, respectively, and expanded tariffs to include all steel and aluminum imports, aiming to bolster domestic production. In addition, the current U.S. presidential administration began announcing a substantial number of trade tariffs, including a new universal baseline reciprocal tariff, plus an additional country-specific reciprocal tariff for select trading partners, on all U.S. imports, although imports of crude oil, natural gas and refined products received exemptions from the tariffs. Furthermore, the administration announced additional sector-specific tariffs, including on copper imports. Although the Supreme Court recently invalidated the reciprocal tariffs, the administration has indicated that it will continue seeking to implement tariffs through other means, and concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed further downward pressure on oil prices. The situation remains fluid, with certain tariff rates and obligations established through trade agreements that were negotiated while the reciprocal tariffs were in effect, and we expect price volatility to continue. Collectively, these policy changes—OPEC+'s instability and the U.S. tariffs—are introducing significant volatility to the crude oil and natural gas sector. In addition, tariffs have the potential to significantly increase our operating and capital costs, which could negatively impact our ability to carry out our planned drilling program and future growth projects.
In addition, since being sworn into office, President Trump has issued numerous Executive Orders that aim to increase crude oil production and decrease commodity prices. For example, President Trump declared a “national energy emergency” in January 2025, and gave the executive branch more power to expedite approvals for energy resource infrastructure (including crude oil and natural gas). Additionally, President Trump’s “Unleashing American Energy” Executive Order incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as crude oil and natural gas. More recently, in March 2025, President Trump signed an Executive Order that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices or our operations. These and other factors make it difficult to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings and maintain our hedging program. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized price.
Sanctions and import bans on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global crude oil supply. As a result of crude oil and natural gas supply constraints, there have been significant increases in European energy costs, which have resulted in inflationary pressures throughout Europe, increasing prospects of recession in many countries throughout the continent. The ongoing war between Russia and Ukraine, conflicts in the Middle East, and U.S. intervention in Venezuela have resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by the tariffs and proposed tariffs by the current administration. Specifically, the Company’s capital program has been and continues to be impacted by higher prices for steel, diesel, chemicals and services, among other items.
Global crude oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) general economic conditions and increasing expectations that the world may be heading into a global recession, (ii) the ability of OPEC+ and other crude oil producing nations to manage the global crude oil supply, (iii) the impact of sanctions and import bans on production from Russia and any resulting impact on production from conflicts in the Middle East and U.S. intervention in Venezuela, (iv) the timing and supply impact of any Iranian or Venezuelan sanction relief on their ability to export crude oil, (v) the global supply chain constraints associated with manufacturing and distribution delays, (vi) oilfield service demand and cost inflation, and (vii) political stability of crude oil consuming countries. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.
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 March 31, 2026, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35.
The markets for the commodities produced by our industry strengthened in 2021 continuing into 2023. However, they began declining in 2024 and continued to decline in 2025 and early 2026 due to concerns over trade wars and energy tariffs, among other factors, and has decreased from 2022 levels overall, as a result of increased supply outpacing increased demand for each of the commodities we produce. This decline in commodity prices through 2025 and into 2026 contributed to the Company's need to enter into amendments to its Term Loan Credit Agreement and Senior Credit Facility Agreement to address potential financial covenant compliance issues. The increase in commodity prices in March 2026 is considered temporary related to the conflicts in the Middle East and the Company anticipates that they may retreat after the conflicts are resolved. There can be no assurance that commodity prices will improve sufficiently to enable the Company to comply with the financial covenants under its credit facilities when the required asset coverage ratio and total net leverage ratio levels reset to more stringent levels in the Second Quarter of 2026. There are many factors beyond the Company’s control, including commodity markets, unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services or supply constraints remain subject to heightened levels of uncertainty as a result of commodity-specific tariffs and the possibility of trade wars, the ongoing war between Russia and Ukraine, conflicts in the Middle East, U.S. intervention in Venezuela, and elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. For additional information on the risks, see “Part I. Item 1A. Risk Factors.”
Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to maintain a one (1) drilling rig program for 2026 depending on certain market conditions. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. If the Company is unable to maintain compliance with its financial covenants or obtain further amendments or waivers from its lenders, it may be required to reduce its capital expenditures, which could adversely impact its ability to develop its acreage, maintain its leasehold positions and grow its production. Despite continuing impacts of the factors listed above and future uncertainty, we are focused on maintaining our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.
Strategic Alternatives
On January 23, 2023, the Company announced the intention of its Board to initiate a process to evaluate certain strategic alternatives to maximize shareholder value, including a potential sale of the Company. To date, however, this process has been exploratory in nature and accordingly remains in preliminary stages, with our discussions to date with prospective counterparties generally excluding substantive discussions regarding potential valuation, structure or other key transaction terms. The Company has not set a timetable for the conclusion of this review, nor has it made any decisions related to any further actions or potential strategic alternatives at this time. There can be no assurance that the review will progress beyond this exploratory phase or result in any transaction or other strategic change or outcome. The Company does not intend to comment further regarding the strategic alternatives process unless and until our Board has approved a specific course of action or we have otherwise determined that further disclosure is appropriate or required by law.
Financial and Operating Performance
The Company's financial and operating performance for the three months ended March 31, 2026 included the highlights described below and comparative discussion of related drivers for the three months ended March 31, 2025:
Net loss was $127.4 million ($(1.02) per diluted share) for the three months ended March 31, 2026 compared with net income of $36.3 million for three months ended March 31, 2025. The primary components of the $163.8 million decrease in net income include:
a $149.1 million increase in the Company’s derivative instruments loss 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 $56.4 million decrease in crude oil, NGL and natural gas revenues due to a 14% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased activity and natural decline coupled with an 8% decrease in average realized commodity prices per Boe, excluding the effects of derivatives;
a $3.7 million increase in DD&A expense primarily due to a 20% increase in the DD&A rate from $22.86 to $27.52 per Boe as a result of a decrease in proved reserves at the end of 2025 partially offset by an 14% decrease in daily sales volumes resulting primarily from a decrease in crude oil sales as a result of decreased activity and natural decline;
a $2.9 million increase in gathering, processing and transportation expenses related to the Company’s natural gas production as a result of connecting more natural gas to processing facilities that were not previously connected, thereby enhancing the Company’s ability to maximize returns from its wells by increasing sales volumes;
a $688,000 increase in the Company’s stock-based compensation expense primarily due restricted shares granted to certain employees in January 2026; and
a $478,000 increase in the Company’s exploration and abandonment expenses primarily due to increased plugging and abandonment expenses and abandoned leasehold costs;
partially offset by:
a $37.6 million decrease in the Company’s income tax expense primarily due to a decrease in income before income taxes;
a $6.0 million decrease in the Company’s crude oil and natural gas production costs primarily as a result of decreased expense workover activity, lower chemical and treating costs related to third party midstream expansions and debottlenecking and decreased communication expenses;
a $3.3 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 $2.0 million decrease in the Company’s interest expense primarily as a result of decreased amortization of discounts and debt issuance costs related to the refinancing of the Company’s debt in August 2025 and lower interest rates experienced, partially offset by an increased outstanding debt balance; and
a $600,000 decrease in the Company’s general and administrative expenses primarily attributable to lower wages and benefits primarily as a result of the retirement of the Company’s former chief executive officer in September 2025.
During the three months ended March 31, 2026, average daily sales volumes totaled 45,629 Boepd, compared with 51,128 Boepd during the same period in 2025, a decrease of 14%, primarily due to lower crude oil volumes as a result of decreased activity and natural decline.
Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, increased during the three months ended March 31, 2026 to $71.79, compared with $71.64 for the same period in 2025. Weighted average NGL prices per Bbl decreased during the three months ended March 31, 2026 to $17.22, compared with $24.21 for the same period in 2025. Weighted average natural gas prices per Mcf decreased to $1.32 during the three months ended March 31, 2026, compared with $2.34 during the same period in 2025.
Cash provided by operating activities totaled $54.2 million for the three months ended March 31, 2026, compared with $157.1 million for the three months ended March 31, 2025.
Derivative Financial Instruments
Crude oil derivative financial instrument exposure. As of March 31, 2026 and factoring in derivative instruments entered into subsequent to quarter end, the Company was party to the following open crude oil derivative financial instruments.
Natural gas derivative financial instrument exposure. As of March 31, 2026, the Company was party to the following open natural gas derivative financial instruments.
The estimated fair value of the outstanding open derivative financial instruments as of March 31, 2026 was a net liability of $106.5 million which is included in current assets and current and noncurrent liabilities on the Company’s condensed consolidated balance sheet as of March 31, 2026. During the three months ended March 31, 2026, the Company recognized a net derivative loss of $157.0 million, including a $139.5 million mark-to-market loss and $17.5 million in net monthly settlement payments.
Operations and Drilling Highlights
Average daily crude oil, NGL and natural gas sales volumes are as follows:
Crude Oil (Bbls)
NGL (Bbls)
Natural Gas (Mcf)
Total (Boe)
The Company’s liquids production was 84% of total production on a Boe basis for the three months ended March 31, 2026.
Costs incurred are as follows (in thousands):
Unproved property acquisition costs
Proved acquisition costs
Total acquisitions
Development costs
Exploration costs
Total finding and development costs
Total costs incurred
The following table sets forth the total number of horizontal producing wells drilled and completed during the three months ended March 31, 2026:
Drilled
Completed
Gross
Net
Flat Top area
Signal Peak area
As of March 31, 2026, HighPeak Energy was developing its properties using one (1) drilling rig. 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 three months ended March 31, 2026, the Company successfully completed and placed on production twelve (12) gross (12.0 net) horizontal wells. As of March 31, 2026, the Company had sixteen (16) gross (15.9 net) horizontal wells that had been drilled and were in various stages of completion. In addition, as of March 31, 2026, the Company was in the process drilling two (2) gross (1.9 net) horizontal wells. The frac crew which was reassigned in early March returned in early April to begin fracing the Company’s wells once again. This is part of a program of frac pauses planned throughout the year given that one frac crew can outpace one drilling rig.
Results of Operations
Crude Oil, NGL and natural gas revenues.
Average daily sales volumes are as follows:
% Change
The decrease in average daily Boe sales volumes for the three months ended March 31, 2026, compared with the same period in 2025 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:
Crude Oil per Bbl
NGL per Bbl
Natural Gas per Mcf
Total per Boe
Revenue Variance Analysis.
The following table illustrates the variance in revenues attributable to prices versus volumes (in thousands except prices and percentages):
Average daily sales volumes (Boe)
Realized price per Boe
Revenue change from prior period due to prices
Revenue change from prior period due to volumes
Rounding
Total change from prior period revenues
As detailed above, the decrease in total operating revenues for the three months ended March 31, 2026 compared to the same periods in 2025 is the result of a 14% decrease in average daily sales volumes primarily as a result of lower crude oil sales volumes as a result of reduced activity and natural decline plus an 8% decrease in average realized price per Boe.
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):
Crude oil and natural gas production costs
Crude oil and natural gas production costs per Boe (excluding expense workovers)
Workover expense
The decrease in crude oil and natural gas production costs for the three months ended March 31, 2026 compared to the same period in 2025 can be attributed primarily to decreased expense workover costs and chemical and treating costs related to third party midstream expansions and debottlenecking.
Gathering, processing and transportation expenses.
Gathering, processing and transportation expenses are as follows (in thousands):
Gathering, processing and transportation expenses per Boe are as follows:
Gathering, processing and transportation expenses per Boe for the three months ended March 31, 2026 increased compared to the same period in 2025. This is primarily related to connecting more natural gas to processing facilities that were not previously connected, thereby enhancing the Company’s ability to maximize returns from its wells by increasing sales volumes.
Production and ad valorem taxes.
Production and ad valorem taxes are as follows (in thousands, except percentages):
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 months ended March 31, 2026 compared to the same period in 2025 can be attributed primarily to the aforementioned 14% decrease in sales volumes coupled with the 8% decrease in overall commodity prices received.
Production and ad valorem taxes per Boe are as follows:
Production taxes per Boe
Ad valorem taxes per Boe
The decrease in production taxes per Boe for the three months ended March 31, 2026, compared with the same period in 2025 can be attributed primarily to the lower sales volumes thus far in 2026. The change in ad valorem taxes per Boe for the three months ended March 31, 2026, compared with the same period in 2025, was primarily due to natural decline from wells put on line in recent years coupled with the decreased activity of the Company.
Exploration and abandonments expense.
Exploration and abandonment expense details are as follows (in thousands, except percentages):
Plugging and abandonment expense
Geologic and geophysical personnel costs
Unsuccessful exploratory well costs
Abandoned leasehold costs
Geologic and geophysical data costs
Exploration and abandonments expense
Exploration and abandonment costs increased during the three months ended March 31, 2026 primarily due to increased plugging and abandonment expenses as a result of regulatory requirements.
DD&A expense.
DD&A expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):
DD&A expense
DD&A expense per Boe
The increase in DD&A during the three months ended March 31, 2026 is primarily due to an increase in the DD&A rate primarily attributable to decreased proved reserves partially offset by decreased sales 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):
General and administrative expense
General and administrative expense per Boe
The decrease in general and administrative expense in total for the three months ended March 31, 2026 compared to the same period in 2025 is primarily a result of decreased wages and benefits primarily related to the retirement of the Company’s former chief executive officer in September 2026. The increase in stock-based compensation expense for the three months ended March 31, 2026 compared to the same period in 2025 is the result of restricted stock issued to certain employees of the Company in January 2026.
Interest expense.
Term Loan Credit Agreement
Senior Credit Facility Agreement
Amortization of discount
The decrease in interest expense can be attributed to a decrease in amortization of discounts and debt issuance costs related to the refinancing of the Company’s debt in August 2025 and lower interest rates in 2026 compared with interest rates in 2025 partially offset by an increased outstanding debt balance.
Loss on derivative instruments, net.
Cash payments on settlement derivatives, net
The Company primarily utilizes commodity swap contracts, costless collars, roll swaps and basis swaps 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 loss and cash settlements relate to crude oil derivative swap contracts, costless collars and basis swaps and natural gas derivative swap contracts.
Provision for income taxes.
Effective income tax rate
The change in provision for income taxes during the three months ended March 31, 2026, compared with the same period in 2025, was primarily due to the change in income before income taxes mainly due to the significant increase in derivative losses. The effective income tax rate differs from the statutory rate primarily due to Texas state margin taxes and other permanent differences between GAAP income and taxable income. See Note 13 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” for additional information.
Liquidity and Capital Resources
Liquidity. The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Senior Credit Facility Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) sales of nonstrategic assets.
The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of other contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortizations of its indebtedness. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity. Although the Company expects its sources of funding will be adequate to fund its 2026 planned capital expenditures and provide adequate liquidity to fund other needs, however this may be subject to significant uncertainty due to changes in crude oil, NGL and natural gas pricing and potential covenant compliance issues under its debt instruments described below and no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.
As of March 31, 2026, the Company was in compliance with the financial covenants under its Term Loan Credit Agreement and Senior Credit Facility Agreement, as amended. In particular, we recently entered into credit facility amendments described below to ensure our continued compliance with covenants in our debt instruments, but it is uncertain whether the Company will be able to comply with these covenants, in particular beginning in the Second Quarter of 2026 when the required asset coverage ratio and total net leverage ratio levels will reset to the prior more stringent levels. The Company has already taken steps to improve these ratios, including, but not limited to, suspending the payment of dividends and reducing capital expenditures, and in connection with any potential or anticipated covenant shortfalls, the Company may seek to take other action such as raising additional capital through debt or equity offerings, selling assets, reducing capital expenditures further, obtaining additional amendments or waivers from its lenders, or pursuing other strategic alternatives. There can be no assurance that any such measures will be available on acceptable terms, or at all, or that they will be sufficient to address any covenant compliance issues. If the Company is unable to maintain compliance with its financial covenants or successfully implement the measures described above, its liquidity and capital resources would be materially and adversely affected. Specifically, the Company's borrowing availability under its Senior Credit Facility Agreement, which was approximately $92.1 million as of March 31, 2026, could be reduced or eliminated, and the Company may be unable to access additional debt or equity financing on acceptable terms or at all. In addition, any failure of the Company to comply with its financial covenants would result in an event of default under the Term Loan Credit Agreement and Senior Credit Facility Agreement, entitling the lenders to accelerate amounts outstanding thereunder. If such amounts were accelerated and became immediately due and payable, the Company does not expect it would have sufficient liquidity to repay such indebtedness and would likely need to pursue a restructuring, refinancing or other strategic alternatives, which may not be available on acceptable terms or at all.
Debt Refinancing and Recent Amendments. In September 2023, we completed a refinancing of our long-term debt in its entirety by entering into an agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement was set to mature on September 30, 2026 prior to the amendments discussed below. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50%. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00% of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.
The Term Loan Credit Agreement also contained certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter prior to the amendments discussed below. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio.
The Term Loan Credit Agreement contained customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.
Simultaneously with the closing of the Term Loan Credit Agreement, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.
The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof.
On November 1, 2023, but included in part of the refinancing of the Company’s overall long-term debt, the Company entered into a Senior Credit Facility Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $100.0 million and effective March 29, 2024 pursuant to the First Facility Amendment, current commitments of $100.0 million and customary debt issuance costs which totaled approximately $1.1 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Senior Credit Facility Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries.
August 2025 Amendments
In August 2025, the Company entered into the First Term Loan Amendment and the Second Facility Amendment which amended the Term Loan Credit Agreement and the Senior Credit Facility Agreement whereby, among other things, (i) the maturity date was extended two years to September 2028, (ii) Term Loan Credit Agreement was upsized to $1.2 billion, providing additional liquidity, and (iii) the Term Loan Credit Agreement quarterly amortization payments of $30.0 million were deferred for one year such that they begin again in September 2026.
February 2026 Amendments
Effective as of December 30, 2025, in order to ensure continued compliance with the financial covenants under the Term Loan Credit Agreement and the Senior Credit Facility Agreement, the Company has entered into the Second Term Loan Amendment and the Third Facility Amendment whereby, among other things, (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourth Quarter of 2025 and the First Quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the Fourth Quarter of 2025 and the First Quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the Second Quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to these amendments.
2026 capital budget. The Company’s capital budget for 2026 is expected to be in the range of approximately $255 to $285 million for drilling, completion, facilities and equipping crude oil wells, field infrastructure buildout and other costs, excluding acquisitions. The 2026 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses and general and administrative expenses. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its consolidated balance sheet, cash generated by operations and borrowing capacity available under its Senior Credit Facility Agreement, if needed. The Company’s capital expenditures for the year ended December 31, 2025 were $511.8 million, including the completion and/or continuation of certain one-time infrastructure projects but excluding acquisitions.
However, there are many factors and consequences beyond the Company’s control impacting our capital budget, such as political and regulatory uncertainties associated with the new Trump Administration, economic downturn or potential recession, geo-political risks and additional actions by businesses, OPEC or OPEC+, and governments in response to pandemics, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors.” The Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.
Capital resources. Cash flows from operating, investing and financing activities are summarized below (in thousands).
Change
Operating activities. The decrease in net cash flow provided by operating activities for the three months ended March 31, 2026, compared with the same period in 2025, was primarily related to a decrease in discretionary cash flow as a result of a decrease in revenues less operating and general administrative expenses of approximately $49.4 million associated with lower overall commodity prices and lower sales volumes coupled with changes in operating assets and liabilities that differ from the prior year period.
Investing activities. The decrease in net cash used in investing activities for the three months ended March 31, 2026, compared with 2025, was primarily due to decreases in additions to crude oil and natural gas properties and acquisitions partially offset by a decrease in working capital related to additions to crude oil and natural gas properties.
Financing activities. The Company's significant financing activities are as follows:
Three months ended March 31, 2026: The Company paid debt issuance costs of $6.1 million primarily related to the Second Term Loan Amendment and the Third Facility Amendment.
Three months ended March 31, 2025: The Company made a mandatory amortization payment on its Term Loan Credit Agreement totaling $30.0 million and paid dividends and dividend equivalents of $5.0 million and $531,000, respectively.
Interest Rate Risk. We are exposed to market risk due to the floating interest rates associated with any outstanding balance on the Term Loan Credit Agreement and the Senior Credit Facility Agreement. As of March 31, 2026, we had a $1.2 billion outstanding balance on the Term Loan Credit Agreement and zero outstanding on the Senior Credit Facility Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the end of each quarter for a period of three months and the Senior Credit Facility Agreement allows us to fix the interest rate for all or a portion of the principal balance for a period of up to six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.
Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic but are significantly down from the past two years. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing war between Russia and Ukraine, conflicts in the Middle East, and U.S. intervention in Venezuela. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our sales volumes during the three months ended March 31, 2026 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the three months ended March 31, 2026 would have increased (decreased) the Company’s revenues by approximately $11.7 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the three months ended March 31, 2026 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis.
We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of March 31, 2026, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $7.9 million. Additionally, as of March 31, 2026, a $0.10 increase (decrease) in the forward curves associated with our natural gas commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $1.0 million.
Contractual obligations. The Company’s contractual obligations include leases (primarily related to contracted drilling rigs, equipment and office facilities), capital funding obligations and other liabilities. Other joint owners in the properties operated by the Company could incur portions of the costs represented by these commitments.
Non-GAAP Financial Measures
EBITDAX represents net income before interest expense, interest and other income, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, exploration and abandonment expense, non-cash stock-based compensation expense, noncash derivative gains and losses, loss on extinguishment of debt, other expense, gains and losses on divestitures and certain other items. EBITDAX excludes certain items we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies.
We are also subject to financial covenants under our Term Loan Credit Agreement and Senior Credit Facility Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Condensed Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” of this Quarterly Report. The Term Loan Credit Agreement and Senior Credit Facility Agreement provide a material source of liquidity for us. Under the terms of our Term Loan Credit Agreement and the Senior Credit Facility Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of total net leverage or a minimum permitted ratio of asset coverage, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, lenders under those agreements would be entitled to exercise all of their remedies for default.
The following table provides a reconciliation of our net income (GAAP) to EBITDAX (non-GAAP) for the periods presented (in thousands):
Interest and other income
Stock based compensation
Derivative related noncash activity
EBITDAX
New Accounting Pronouncements
Our historical condensed consolidated financial statements and related notes to condensed consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done, and judgments made on how the specifics of a given rule apply to us.
In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for crude oil and natural gas activities, crude oil, NGL and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, litigation and environmental contingencies, valuation of financial derivative instruments, uncertain tax positions and income taxes.
Management’s judgments and estimates in all the areas listed above are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2026. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report.
New accounting pronouncements issued but not yet adopted. The effects of new accounting pronouncements are discussed in Note 2 of Notes to Condensed Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)."
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company’s major market risk exposure is the pricing it receives for its sales of crude oil, NGL and natural gas. Pricing for crude oil, NGL and natural gas has been volatile and unpredictable for several years, and HighPeak Energy expects this volatility to continue in the future.
During the period from January 1, 2021 through March 31, 2026, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the three months ended March 31, 2026 would have increased (decreased) the Company’s revenues by approximately $11.7 million on an annualized basis, excluding the effects of derivatives, and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the three months ended March 31, 2026 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis, excluding the effects of derivatives.
Due to this volatility, the Company uses commodity derivative instruments, such as swaps, collars, roll swaps and basis swaps, to hedge price risk associated with a portion of anticipated production. These hedging instruments allow the Company to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in crude oil and natural gas prices and provide increased certainty of cash flows for its drilling program. These instruments provide only partial price protection against declines in crude oil and natural gas prices and may partially limit the Company’s potential gains from future increases in prices. The Company enters into hedging arrangements to protect its capital expenditure budget. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require the Company to hedge certain quantities of its projected crude oil production. The Company does not enter into any commodity derivative instruments, including derivatives, for speculative or trading purposes.
Counterparty and Customer Credit Risk. The Company’s derivative contracts, if any, expose it to credit risk in the event of nonperformance by counterparties. It is anticipated that if the Company enters into any commodity contracts, the collateral for the outstanding borrowings under the Credit Agreements may be used as collateral for the Company’s commodity derivatives. The Company evaluates the credit standing of its counterparties as it deems appropriate. It is anticipated that any counterparties to HighPeak Energy’s derivative contracts would have investment grade ratings.
The Company’s principal exposures to credit risk are through receivables from the sale of crude oil and natural gas production due to the concentration of its crude oil and natural gas receivables with a few significant customers. The inability or failure of the Company’s significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company’s financial results.
The average forward prices based on March 31, 2026 market quotes were as follows:
Remainder of
Year Ending
Average forward NYMEX crude oil price per Bbl
Average forward NYMEX natural gas price per MMBtu
The average forward prices based on April 30, 2026 market quotes were as follows:
Credit Risk. The Company's primary concentration of credit risk is associated with (i) the collection of receivables resulting from the sale of crude oil and natural gas production and (ii) the risk of a counterparty's failure to meet its obligations under derivative contracts with the Company.
The Company monitors exposure to counterparties primarily by reviewing credit ratings, financial criteria and payment history. Where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. The Company's crude oil and natural gas is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Historically, the Company's credit losses on crude oil and natural gas receivables have not been material.
The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.
The Company entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with right of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative contract, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.
Interest Rate Risk. At March 31, 2026, we had $1.2 billion outstanding under the Term Loan Credit Agreement and had $92.1 million of available borrowing capacity under the Senior Credit Facility Agreement. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement and Senior Credit Facility Agreement. The Company also periodically has fixed rate debt but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The impact of a 1% increase in interest rates on our outstanding debt as of March 31, 2026 would have resulted in an annual increase in interest expense of approximately $12.0 million.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, HighPeak Energy has evaluated, under the supervision and with the participation of the Company’s management, including HighPeak Energy’s principal executive officer and principal financial officer, the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the fiscal period covered by this Quarterly Report. Based on that evaluation, HighPeak Energy’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective, as of the end of the period covered by this Quarterly Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2026 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.
ITEM 1. LEGAL PROCEEDINGS
From time to time, the Company may be a party to various lawsuits, proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future results of operations.
ITEM 1A. RISK FACTORS
In addition to the information set forth in this Quarterly Report, the risks that are discussed in the Company’s Annual Report under the headings “Risk Factors,” “Business and Properties,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors that were described in the Company’s Annual Report.
ITEM 5. OTHER INFORMATION
During the three months ended March 31, 2026, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
ITEM 6. EXHIBITS
Exhibit
Number
Description
3.1
Second Amended & Restated Certificate of Incorporation of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 2, 2023).
3.2
Second Amended and Restated Bylaws of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on May 1, 2026).
4.1
Registration Rights Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP and certain other security holders named therein (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).
4.2
Stockholders’ Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, Jack Hightower and certain directors of Pure Acquisition Corp. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).
10.1
Second Amendment to Term Loan Credit Agreement, dated March 5, 2026, 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 (incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K (File No. 001-39464) filed with the SEC on March 11, 2026).
10.2
Third Amendment to the Senior Credit Facility Agreement, dated as of March 5, 2026, by and between HighPeak Energy, Inc., Fifth Third Bank, National Association, as administrative agent, each Guarantor party thereto and the lenders party thereto (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K (File No. 001-39464) filed with the SEC on March 11, 2026).
31.1*
Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*
Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1**
Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2**
Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
101.INS**
Inline XBRL Instance Document – The instance document does not appear in the Interactive Data File because its XBRL tabs are embedded within the Inline XBRL document
101.SCH**
Inline XBRL Taxonomy Extension Schema Document
101.CAL**
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**
Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE**
Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*
Filed herewith.
**
Furnished herewith.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.
May 6, 2026
By:
/s/ Steven Tholen
Steven Tholen
Chief Financial Officer
/s/ Keith Forbes
Keith Forbes
Vice President and Chief Accounting Officer