SEC Form 10-Q filed by HighPeak Energy Inc.

5/12/25 4:11:12 PM ET

$HPK

Oil & Gas Production

Energy

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hpe20250331_10q.htm

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, 2025

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

For the transition period from ________ to ________

Commission File Number: 001-39464

HighPeak Energy, Inc.

(Exact name of Registrant as specified in its charter)

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

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

(817) 850-9200

(Registrant's telephone number, including area code)

Not applicable

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

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

Title of each class

Trading Symbol

Name of each exchange on which

registered

Common Stock, par value $0.0001 per share

HPK

The Nasdaq Stock Market LLC

Warrants to purchase Common Stock

HPKEW

The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

As of May 8, 2025, there were 126,067,436 shares of common stock, par value $0.0001 per share, issued and outstanding.

HIGHPEAK ENERGY, INC.

TABLE OF CONTENTS

		Page
Definitions of Certain Terms and Conventions Used Herein		1
Cautionary Statement Concerning Forward-Looking Statements		5
PART I. FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	6
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Operations	7
	Condensed Consolidated Statements of Changes in Stockholders’ Equity	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Condensed Consolidated Financial Statements	10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 5.	Other Information	41
Item 6.	Exhibits	42
Signatures		43

HIGHPEAK ENERGY, INC.

Definitions of Certain Terms and Conventions Used Herein

Within this Quarterly Report on Form 10-Q (this “Quarterly Report”), the following terms and conventions have specific meanings:

	•	*“3-D seismic*” means three-dimensional seismic data which is geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional data.
	•	*“ASC*” means Accounting Standards Codification.
	•	*“ASU*” means Accounting Standards Update.
	•	*“Basin*” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
	•	*“Bbl*” means a standard barrel containing 42 United States gallons.
	•	*“Bcf*” means one billion cubic feet.
	•	*“Boe*” means a barrel of crude oil equivalent and is a standard convention used to express crude oil and natural gas volumes on a comparable crude oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of natural gas to one Bbl of crude oil or NGL.
	•	*“Boepd*” means Boe per day.
	•	*“Bopd*” means one barrel of crude oil per day.
	•	*“Btu*” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
	•	*“Collateral Agency Agreement*” means the Company’s Collateral Agency Agreement, dated as of September 12, 2023, by and among HighPeak Energy, Inc., Texas Capital Bank, as collateral agent, Chambers Energy Management, LP, as term representative, Mercuria Energy Trading SA, as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023, and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023.
	•	*“common stock” or “HighPeak Energy common stock*” means the Company’s common stock, par value $0.0001 per share.
	•	*“Completion*” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
	•	*“Credit Agreement*” means the Term Loan Credit Agreement and the Senior Credit Facility Agreement.
	•	*“DD&A*” means depletion, depreciation and amortization.
	•	*“Development costs*” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).
	•	*“Development project*” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
	•	*“Development well*” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
	•	*“Differential*” An adjustment to the price of crude oil, NGL or natural gas from an established spot market price to reflect differences in the quality and/or location of crude oil, NGL or natural gas.
	•	*“Dry hole” or “dry well*” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
	•	*“Economically producible*” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
	•	*“EUR” or “Estimated ultimate recovery*” The sum of reserves remaining as of a given date and cumulative production as of that date.
	•	*“Exploratory well*” An exploratory well is a well drilled to find a new field, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC.

	•	*“Extension well*” An extension well is a well drilled to extend the limits of a known reservoir.
	•	*“FASB*” Financial Accounting Standards Board.
	•	*“Field*” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
	•	*“First Facility Amendment*” means the First Amendment to Senior Credit Facility Agreement, dated March 29, 2024, by and among HighPeak Energy, Inc., as borrower, Fifth Third Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
	•	*“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.
	•	*“HighPeak II*” means HighPeak Energy II, LP, a Delaware limited partnership.
	•	*“Horizontal drilling*” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
	•	*“HPK Contributors*” means HighPeak I, HighPeak II and HPK GP.
	•	*“HPK GP*” means HighPeak Energy, LLC, a Delaware limited liability company.
	•	*“Hydraulic fracturing*” is the technique of stimulating the production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in its drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.
	•	*“Lease operating expenses*” The expenses of lifting crude oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
	•	*“MBbl*” means one thousand Bbls.
	•	*“MBoe*” means one thousand Boes.
	•	*“Mcf*” means one thousand cubic feet and is a measure of natural gas volume.
	•	*“MMBbl*” means one million Bbls.
	•	*“MMBtu*” means one million Btus.
	•	*“MMcf*” means one million cubic feet and is a measure of natural gas volume.
	•	*“Net acres*” The percentage of total acres an owner has out of a particular number of gross acres or a specified tract. As an example. an owner who has 50% interest in 100 gross acres owns 50 net acres.
	•	*“Net production*” Production that is owned by us, less royalties and production due others.
	•	*“NGL*” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the natural gas stream; such liquids include ethane, propane, isobutane, normal butane and gasoline.
	•	*“NYMEX*” means the New York Mercantile Exchange.
	•	*“OPEC*” means the Organization of Petroleum Exporting Countries.
	•	*“Operator*” The individual or company responsible for the exploration and/or production of a crude oil or natural gas well or lease.
	•	*“Plugging*” A downhole tool that is set inside the casing to isolate the lower part of the wellbore.
	•	*“Pooling*” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules.
	•	*“Principal Stockholder Group*” means HighPeak Pure Acquisition, LLC, a Delaware limited liability company, and wholly owned subsidiary of HighPeak I, the HPK Contributors and Jack Hightower 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.
	•	*“Senior Credit Facility Agreement*” means the Company’s Credit Agreement, dated as of November 1, 2023, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent and collateral agent, and the lenders party thereto.
	•	*“Service well*” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include natural gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
	•	*“Spacing*” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, the distance between horizontal wellbores, e.g., 880-foot spacing or the number of wells per section, e.g., 6-well spacing. It is often established by regulatory agencies and/or the operator to optimize recovery of hydrocarbons.
	•	*“Spot market price*” The cash market price without reduction for expected quality, transportation and demand adjustments.
	•	*“Standardized measure*” The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines as well as the rules and regulations of the SEC, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to DD&A. Standardized measure does not give effect to derivative transactions.
	•	*“Stratigraphic test well*” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
	•	*“Term Loan Credit Agreement*” means the Company’s Term Loan Credit Agreement, dated as of September 12, 2023, by and between HighPeak Energy, Inc., as borrower, Texas Capital Bank, as administrative agent, Chambers Energy Management, LP, as collateral agent, and the lenders from time-to-time party thereto.
	•	*“Undeveloped acreage*” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether such acreage contains proved reserves.
	•	*“Unit*” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
	•	*“U.S.*” means the United States.
	•	*“Warrants*” means warrants to purchase one share of HighPeak Energy common stock at a price of $11.50 per share.
	•	*“Wellbore*” The hole drilled by the bit that is equipped for crude oil and natural gas production on a completed well. Also called well or borehole.
	•	*“Working interes*t” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
	•	*“Workover*” Operations on a producing well to restore or increase production.
	•	*“WTI*” means West Texas Intermediate, a light sweet blend of crude oil produced from fields in western Texas and is a grade of crude oil used as a benchmark in crude oil pricing.
	•	With respect to information on the working interest in wells and acreage, “*net” wells and acres are determined by multiplying “gross*” wells and acres by the Company’s working interest in such wells or acres. Unless otherwise specified, wells and acreage statistics quoted herein represent gross wells or acres.
	•	All currency amounts are expressed in U.S. dollars.

The terms “development costs,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery,” “exploratory well,” “production costs,” “reserves,” “reservoir,” “resources,” “service wells” and “stratigraphic test well” are defined by the SEC. Except as noted, the terms defined in this section are not the same as SEC definitions.

Cautionary Statement Concerning Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included or incorporated by reference in this Quarterly Report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on the beliefs of management, as well as assumptions made by, and information currently available to, the Company’s management. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “believes,” “plans,” “expects,” “anticipates,” “forecasts,” “intends,” “continue,” “may,” “will,” “could,” “should,” “future,” “potential,” “estimate” or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company’s current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company’s control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the Company’s assumptions about:

	●	our ability to refinance or pay, when due, the principal of, interest or other amounts due in respect of our indebtedness;
	●	our liquidity, cash flow and access to capital;

●

the results of our ongoing strategic alternatives process;

	●	the supply and demand for and market prices of crude oil, NGL, natural gas and other products or services, and the associated impact of our hedging policies relating thereto;
	●	inflation rates, the impacts of associated monetary policy responses, including increased interest rates and resulting pressures on economic growth, U.S. trade policy and the imposition of tariffs;
	●	political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine, the Israel-Hamas conflict and the Israel-Iran conflict;
	●	volatility in the political, legal and regulatory environments;
	●	political and regulatory uncertainties;
	●	the integration of acquisitions;
	●	the availability of capital resources;
	●	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;
	●	legislative, regulatory or policy changes;
	●	regulatory and related policy actions intended by federal, state and/or local governments to reduce fossil fuel use and associated carbon emissions, to drive the substitution of renewable forms of energy for crude oil and natural gas, which may over time reduce demand for crude oil, NGL and natural gas, including as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise;
	●	our ability to predict and manage the effects of actions of OPEC and agreements to set and maintain production levels;
	●	cyber-attacks;
	●	occurrence of property acquisitions or divestitures;
	●	capital markets and our ability to access such markets on attractive terms or at all, and related risks such as general credit, liquidity, market and interest-rate risks; and
	●	other factors disclosed under “Part I, Items 1 and 2. Business and Properties,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC on March 10, 2025 (“Annual Report”).

All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, the Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of crude oil, NGL and natural gas that are ultimately recovered.

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

HighPeak Energy, Inc.

Condensed Consolidated Balance Sheets

(in thousands, except share data)

	March 31, 2025			December 31, 2024
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	51,619		$	86,649
Accounts receivable		78,356			85,242
Inventory		8,706			10,952
Prepaid expenses		8,301			4,587
Derivative instruments		5,620			7,582
Total current assets		152,602			195,012
Crude oil and natural gas properties, using the successful efforts method of accounting:
Proved properties		4,140,881			3,959,545
Unproved properties		71,359			70,868
Accumulated depletion, depreciation and amortization		(1,293,949	)		(1,184,684	)
Total crude oil and natural gas properties, net		2,918,291			2,845,729
Other property and equipment, net		3,141			3,201
Other noncurrent assets		19,047			19,346
Total assets	$	3,093,081		$	3,063,288
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current maturities of long-term debt	$	120,000		$	120,000
Accounts payable – trade		66,473			74,011
Accrued capital expenditures		53,240			35,170
Revenues and royalties payable		27,993			26,838
Other accrued liabilities		22,065			22,196
Derivative instruments		8,275			5,380
Operating leases		821			719
Advances from joint interest owners		—			316
Total current liabilities		298,867			284,630
Noncurrent liabilities:
Long-term debt, net		902,844			928,384
Deferred income taxes		242,337			232,398
Asset retirement obligations		15,058			14,750
Operating leases		581			670
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, 2025 and December 31, 2024		—			—
Common stock, $0.0001 par value, 600,000,000 shares authorized, 126,067,436 and 126,067,436 shares issued and outstanding at March 31, 2025 and December 31, 2024, respectively		13			13
Additional paid-in capital		1,166,786			1,166,609
Retained earnings		466,595			435,834
Total stockholders’ equity		1,633,394			1,602,456
Total liabilities and stockholders’ equity	$	3,093,081		$	3,063,288

The accompanying notes are an integral part of these condensed consolidated financial statements.

HighPeak Energy, Inc.

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(Unaudited)

	Three Months Ended March 31,
	2025			2024
Operating revenues:
Crude oil sales	$	246,424		$	282,369
NGL and natural gas sales		11,024			5,395
Total operating revenues		257,448			287,764
Operating costs and expenses:
Crude oil and natural gas production		35,562			30,271
Production and ad valorem taxes		15,152			14,402
Exploration and abandonments		264			498
Depletion, depreciation and amortization		109,325			130,850
Accretion of discount		244			239
General and administrative		6,345			4,685
Stock-based compensation		177			3,798
Total operating costs and expenses		167,069			184,743
Other expense		—			1
Income from operations		90,379			103,020
Interest income		810			2,392
Interest expense		(36,988	)		(43,634	)
Loss on derivative instruments, net		(7,927	)		(53,043	)
Income before income taxes		46,274			8,735
Provision for income taxes		9,939			2,297
Net income	$	36,335		$	6,438
Earnings per share:
Basic net income	$	0.26		$	0.05
Diluted net income	$	0.26		$	0.05

Weighted average shares outstanding:
Basic		123,913			125,696
Diluted		127,213			129,641

Dividends declared per share	$	0.04		$	0.04

The accompanying notes are an integral part of these condensed consolidated financial statements.

HighPeak Energy, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity

(in thousands)

(Unaudited)

Three Months Ended March 31, 2025
	Shares Outstanding		Common Stock		Additional Paid-in- Capital		Retained Earnings			Total Stockholders' Equity
Balance, December 31, 2024		126,067	$	13	$	1,166,609	$	435,834		$	1,602,456
Dividends declared ($0.04 per share)		—		—		—		(5,043	)		(5,043	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—		—		—		(531	)		(531	)
Stock-based compensation costs:
Compensation costs included in net income		—		—		177		—			177
Net income		—		—		—		36,335			36,335
Balance, March 31, 2025		126,067	$	13	$	1,166,786	$	466,595		$	1,633,394

Three Months Ended March 31, 2024
	Shares Outstanding			Common Stock		Additional Paid-in- Capital			Retained Earnings			Total Stockholders' Equity
Balance, December 31, 2023		128,421		$	13	$	1,189,424		$	363,284		$	1,552,721
Dividends declared ($0.04 per share)		—			—		—			(5,137	)		(5,137	)
Dividend equivalents declared on outstanding stock options ($0.04 per share)		—			—		—			(532	)		(532	)
Repurchased shares under buyback program		(566	)		—		(8,851	)		—			(8,851	)
Stock-based compensation costs:
Compensation costs included in net income		—			—		3,798			—			3,798
Net income		—			—		—			6,438			6,438
Balance, March 31, 2024		127,855		$	13	$	1,184,371		$	364,053		$	1,548,437

The accompanying notes are an integral part of these condensed consolidated financial statements.

HighPeak Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2025			2024
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	36,335		$	6,438
Adjustments to reconcile net income to net cash provided by operations:
Provision for deferred income taxes		9,939			1,688
Loss on derivative instruments, net		7,927			53,043
Cash paid on settlement of derivative instruments		(3,071	)		(5,148	)
Amortization of debt issuance costs		2,034			2,053
Amortization of discounts on long-term debt		2,426			2,453
Stock-based compensation expense		177			3,798
Accretion expense		244			239
Depletion, depreciation and amortization expense		109,325			130,850
Exploration and abandonment expense		4			274
Changes in operating assets and liabilities:
Accounts receivable		6,886			(14,414	)
Prepaid expenses, inventory and other assets		(1,314	)		(4,722	)
Accounts payable, accrued liabilities and other current liabilities		(13,860	)		(5,113	)
Net cash provided by operating activities		157,052			171,439
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to crude oil and natural gas properties		(179,819	)		(147,698	)
Changes in working capital associated with crude oil and natural gas property additions		25,172			1,705
Acquisitions of crude oil and natural gas properties		(2,517	)		(2,171	)
Proceeds from sales of properties		570			—
Other property additions		—			(59	)
Net cash used in investing activities		(156,594	)		(148,223	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments under Term Loan Credit Agreement		(30,000	)		(30,000	)
Dividends paid		(4,957	)		(5,050	)
Dividend equivalents paid		(531	)		(530	)
Repurchased shares under buyback program		—			(8,764	)
Debt issuance costs		—			(7	)
Net cash used in financing activities		(35,488	)		(44,351	)
Net decrease in cash and cash equivalents		(35,030	)		(21,135	)
Cash and cash equivalents, beginning of period		86,649			194,515
Cash and cash equivalents, end of period	$	51,619		$	173,380

Supplemental cash flow information:
Cash paid for interest	$	32,528		$	39,678
Cash paid for income taxes		—			—
Supplemental disclosure of non-cash transactions:
Additions to asset retirement obligations		152			201

The accompanying notes are an integral part of these condensed consolidated financial statements.

HIGHPEAK ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. Organization and Nature of Operations

HighPeak Energy, Inc. ("HighPeak Energy" or the "Company") is a Delaware corporation, formed in October 2019. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the U.S. Securities and Exchange Commission (“SEC”) on March 10, 2025, for further information regarding the formation of the Company. HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq Global Market (the "Nasdaq") under the ticker symbols “HPK” and “HPKEW,” respectively. 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, 2025 and for the three months ended March 31, 2025 and 2024 include all adjustments and accruals, consisting only of normal, recurring adjustments and accruals necessary for a fair presentation of the results for the interim periods in conformity with generally accepted accounting principles in the United States ("GAAP"). Certain prior period amounts have been reclassified to conform to the current period condensed consolidated financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. The operating results for the three months ended March 31, 2025 are not indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted in accordance with the rules and regulations of the SEC. These unaudited interim condensed consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024.

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

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

Cash and cash equivalents. The Company’s cash and cash equivalents include depository accounts held by banks with original issuance maturities of 90 days or less. The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Accounts receivable. As of March 31, 2025 and December 31, 2024, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $70.1 million and $76.0 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, joint interest receivables of $3.3 million and $4.7 million, respectively, current U.S. federal income tax receivables of $3.1 million and $3.1 million, respectively, and receivables related to settlements of derivative contracts of $1.9 million and $1.4 million, respectively. The Company’s share of crude oil, NGL and natural gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company’s credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support.

Accounts receivable are stated at amounts due from purchasers or joint interest owners, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from purchasers or joint interest owners outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. As of March 31, 2025 and December 31, 2024, the Company had no allowance for credit losses related to accounts receivable.

Concentration of credit risk. The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the three months ended March 31, 2025 and the year ended December 31, 2024, sales to the Company’s largest purchaser accounted for approximately 81% and 76%, respectively, and sales to the Company’s second largest purchaser accounted for approximately 10% and 18%, respectively, of the Company’s total crude oil, NGL and natural gas sales revenues. The Company generally does not require collateral and does not believe the loss of these particular purchasers would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

Inventory. Inventory is comprised primarily of crude oil and natural gas drilling and completion or repair items such as pumps, tubing, casing, vessels, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling and completion or repair operations and is carried at the lower of cost or net realizable value, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company’s condensed consolidated balance sheet and as charges to other expense in the condensed consolidated statements of operations. The Company’s materials and supplies inventory as of March 31, 2025 and December 31, 2024 is $8.7 million and $11.0 million, respectively, and the Company has not recognized any valuation allowance to date.

Prepaid expenses. Prepaid expenses are comprised primarily of fees related to a debt refinancing that will be included in debt issuance costs when consummated or charged to expense if not successful, strategic alternatives that will be deducted from eventual commissions on a future transaction, caliche that will be used on future locations and roads in our development areas, and prepaid insurance, software maintenance fees, listing fees and subscriptions that will be amortized over the life of the contracts. Prepaid expenses as of March 31, 2025 and December 31, 2024 are $8.3 million and $4.6 million, respectively.

Crude oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its crude oil and natural gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed.

The Company does not carry the costs of drilling an exploratory well as an asset in its condensed consolidated balance sheet following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

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

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved developed reserves for drilling, completion and other crude oil and natural gas property costs. Unproved leasehold costs are excluded from depletion until proved reserves are established or, if unsuccessful, impairment is determined.

Proceeds from the sales of individual properties are credited to proved or unproved crude oil and natural gas properties, as the case may be, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

The Company performs assessments of its long-lived assets to be held and used, including proved crude oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If there is an indication the carrying value of the assets may not be recovered, an impairment loss is recognized if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets.

Unproved crude oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the estimates of future recoverable reserves, results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time.

Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $1.1 million and $1.1 million as of March 31, 2025 and December 31, 2024, respectively, are as follows (in thousands):

	March 31, 2025		December 31, 2024
Land	$	1,869	$	1,869
Transportation equipment		569		620
Buildings		513		516
Leasehold improvements		189		193
Field equipment		1		2
Furniture and fixtures		—		1
Total other property and equipment, net	$	3,141	$	3,201

Other property and equipment are depreciated over their estimated useful life on a straight-line basis. Land is not depreciated. Transportation equipment is generally depreciated over five years, buildings are generally depreciated over forty years, field equipment is generally depreciated over seven years and furniture and fixtures is generally depreciated over five years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method.

Aid-in-construction assets. As of March 31, 2025 and December 31, 2024, the Company had aid-in-construction assets totaling $17.7 million and $18.0 million, respectively, included in other noncurrent assets. The Company funded aid-in-construction projects during the three months ended March 31, 2025 and the year ended December 31, 2024 of zero and $17.5 million, respectively, under the contract. The Company has received and will continue to receive payments based on gross system throughput, including any third-party natural gas that is potentially tied into the Flat Top gathering system in the future. Payments received during the three months ended March 31, 2025 and the year ended December 31, 2024 were approximately $375,000 and $2.0 million, respectively. The contract calls for future aid-in-construction fundings if expansions of the system are necessary as determined in the sole discretion of the Company.

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

Current liabilities. Current liabilities as of March 31, 2025 and December 31, 2024 totaled approximately $298.9 million and $284.6 million, respectively, including current maturities of long-term debt, trade accounts payable, accrued capital expenditures revenues and royalties payable, derivative liabilities and accruals for operating and general and administrative expenses, interest expense, operating leases, dividends and dividend equivalents and other miscellaneous items.

Debt issuance costs and original issue discount. The Company has paid a total of $25.1 million in debt issuance costs, zero and $58,000 of which were incurred during the three months ended March 31, 2025 and the year ended December 31, 2024, respectively, primarily related to the completion of the Term Loan Credit Agreement and Senior Credit Facility Agreement. Amortization based on the straight-line method over the terms of the Term Loan Credit Agreement and Senior Credit Facility Agreement which approximates the effective interest method was $2.0 million and $2.1 million during the three months ended March 31, 2025 and 2024, 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 is being amortized over the life of the agreement which approximates the effective interest method and was $2.4 million and $2.5 million during the three months ended March 31, 2025 and 2024, respectively. See Note 7 for more information. As of March 31, 2025 and December 31, 2024, the remaining net debt issuance costs and discounts related to the Term Loan Credit Agreement and Senior Credit Facility Agreement are netted against the outstanding long-term debt on the accompanying condensed consolidated balance sheets.

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

Revenue recognition. The Company follows FASB ASC 606, “Revenue from Contracts with Customers,” (“ASC 606”) whereby the Company recognizes revenues from the sales of crude oil, NGL and natural gas to its purchasers and presents them disaggregated on the Company’s condensed consolidated statements of operations.

The Company enters into contracts with purchasers to sell its crude oil, NGL and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the crude oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the crude oil and natural gas marketing contracts is typically received from the purchaser one to two months after the date of sale. As of March 31, 2025 and December 31, 2024, the Company had receivables related to contracts with purchasers of approximately $70.1 million and $76.0 million, respectively.

Crude Oil Contracts. The Company’s crude oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the crude oil has been transferred to the purchaser. The crude oil produced is sold under contracts using market-based pricing which is then adjusted for the differentials based upon delivery location and crude oil quality. Since the differentials are incurred after the transfer of control of the crude oil, the differentials are included in crude oil sales on the condensed consolidated statements of operations as they represent part of the transaction price of the contract.

Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts or (ii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue natural gas are then sold by the purchaser. Under percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue natural gas. Since control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Derivatives. All the Company’s derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the condensed consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.

The Company’s credit risk related to derivatives is a 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, 2025 or December 31, 2024.

Tax benefits from an 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 12 for additional information.

Tax-related interest charges are recorded as interest expense and any tax-related penalties as other expense in the condensed consolidated statements of operations of which there have been none to date.

The Company is also subject to Texas Margin Tax. The Company realized zero and $223,000 in current Texas Margin Tax during the three months ended March 31, 2025 and 2024, respectively, in the accompanying condensed 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 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.

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 Chief Executive Officer and President are the chief operating decision makers (“CODMs”). To assess the performance of our assets, the CODMs use 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:

	Three Months Ended March 31,
	2025		2024
Total operating revenues	$	257,448	$	287,764

Lease operating expenses		31,599		28,511
Production and ad valorem taxes		15,152		14,402
Expensed workover costs		3,963		1,760
Total significant expenses		50,714		44,673
Depletion, depreciation and amortization		109,325		130,850
General and administrative expenses, including stock-based comp		6,522		8,483
Interest expense, net		36,178		41,242
Provision for income taxes		9,939		2,297
Other segment items⁽¹⁾		8,435		53,781
Total expenses		221,113		281,326

Net income	$	36,335	$	6,438

Total assets	$	3,093,081	$	3,054,692

Capital costs incurred, including acquisitions	$	182,488	$	150,070

⁽¹⁾

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. While the adoption of this ASU will modify the Company's disclosures, it will not have an impact on the Company’s financial position, results of operations or liquidity.

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 financial position, results of operations or liquidity.

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, 2025 and 2024, the Company incurred a total of $2.5 million and $2.2 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

The Company determines fair value based on the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The three input levels of the fair value hierarchy are as follows:

	●	Level 1 – quoted prices for identical assets or liabilities in active markets.
	●	Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
	●	Level 3 – unobservable inputs for the asset or liability, typically reflecting management’s estimate of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore, determined using model-based techniques, including discounted cash flow models.

Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis as of March 31, 2025 and December 31, 2024 are as follows (in thousands):

	As of March 31, 2025
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
Assets:
Commodity price derivatives – current	$	—	$	5,620		$	—	$	5,620
Liabilities:
Commodity price derivatives – current		—		8,275			—		8,275
Total recurring fair value measurements, net	$	—	$	(2,655	)	$	—	$	(2,655	)

	As of December 31, 2024
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Assets:
Commodity price derivatives – current	$	—	$	7,582	$	—	$	7,582
Liabilities:
Commodity price derivatives – current		—		5,380		—		5,380
Total recurring fair value measurements, net	$	—	$	2,202	$	—	$	2,202

Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil swap contracts, enhanced collars, costless collars, deferred premium put options and natural gas swap contracts. The Company measures derivatives using an industry-standard pricing model that is provided by the counterparties. The inputs utilized in the third-party discounted cash flow and option-pricing models for valuing commodity price derivatives include forward prices for crude oil, contracted volumes, volatility factors and time to maturity, which are considered Level 2 inputs.

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Specifically, (i) stock-based compensation is measured at fair value on the date of grant based on Level 1 inputs for restricted stock awards or Level 2 inputs for stock option awards based upon market data, (ii) the estimates and fair value measurements used for the evaluation of proved property for potential impairment using Level 3 inputs based upon market conditions in the area and (iii) asset retirement obligations are measured at estimated fair value on the date the liabilities are incurred using Level 3 inputs based on expected future costs to retire the assets, market conditions and estimated lives of the assets. The Company assesses the recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved or unproved crude oil and natural gas properties for the periods presented in the accompanying condensed consolidated financial statements.

Financial instruments not carried at fair value. As of March 31, 2025 and December 31, 2024, the Company has financial instruments consisting primarily of cash and cash equivalents, accounts receivable, accounts payable, long-term debt (specifically the Term Loan Credit Agreement and Senior Credit Facility Agreement), and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities.

NOTE 5. Derivative Financial Instruments

The Company primarily utilizes commodity swap contracts, deferred premium put options, collars and enhanced collars to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s capital budgeting and expenditure plans, (iii) protect the Company’s commitments under the Term Loan Credit Agreement and Senior Credit Facility Agreement and (iv) support the payment of contractual obligations.

The following table summarizes the effect of derivative instruments on the Company’s condensed consolidated statements of operations (in thousands):

	Three Months Ended March 31,
	2025			2024

Noncash derivative loss, net	$	(4,856	)	$	(47,895	)
Cash payments on settled derivatives, net		(3,071	)		(5,148	)
Derivative loss, net	$	(7,927	)	$	(53,043	)

Crude oil production derivatives. The Company sells its crude oil production at the lease and the sales contracts governing such crude oil production are tied directly to, or are correlated with, NYMEX WTI Cushing and Argus WTI Midland crude oil prices. As such, the Company primarily uses NYMEX WTI Cushing derivative contracts as well as Argus WTI Midland basis swaps from time to time to manage future crude oil price volatility. The Argus WTI Midland basis differential represents the amount of premium to NYMEX WTI Cushing.

The Company’s outstanding NYMEX WTI Cushing and Argus WTI Midland crude oil derivative instruments as of March 31, 2025 and the weighted average crude oil prices and premiums payable per barrel for those contracts are as follows:

									Swaps		Collars, Enhanced Collars & Deferred Premium Puts
Settlement Month	Settlement Year		Type of Contract		Bbls Per Day		Index		Price per Bbl		Floor or Strike Price per Bbl		Ceiling Price per Bbl		Deferred Premium Payable per Bbl
Crude Oil:
Apr - Jun		2025		Swap		5,500		WTI Cushing	$	76.37	$	—	$	—	$	—
Apr - Jun		2025		Collar		7,989		WTI Cushing	$	—	$	64.38	$	88.55	$	2.00
Apr - Jun		2025		Put		9,000		WTI Cushing	$	—	$	65.78	$	—	$	5.00
Jul - Sep		2025		Swap		3,000		WTI Cushing	$	75.85	$	—	$	—	$	—
Jul - Sep		2025		Collar		7,000		WTI Cushing	$	—	$	65.00	$	90.08	$	2.28
Jul - Sep		2025		Put		9,000		WTI Cushing	$	—	$	65.78	$	—	$	5.00
Oct - Dec		2025		Collar		5,000		WTI Cushing	$	—	$	60.00	$	72.80	$	—
Jan - Mar		2026		Collar		5,000		WTI Cushing	$	—	$	60.00	$	72.80	$	—

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 tied directly to, or 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, 2025 and the weighted average natural gas prices per MMBtu for those contracts are as follows:

Settlement Month	Settlement Year		Type of Contract		MMBtu Per Day		Index		Price per MMBtu
Natural Gas:
Apr – Jun		2025		Swap		30,000		HH	$	4.43
Jul – Sep		2025		Swap		30,000		HH	$	4.43
Oct – Dec		2025		Swap		30,000		HH	$	4.43
Jan – Mar		2026		Swap		19,667		HH	$	4.43

The Company uses credit and other financial criteria to evaluate the credit standings of, and to select, counterparties to its derivative financial instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative financial instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.

Net derivative assets associated with the Company’s open commodity derivative instruments by counterparty are as follows (in thousands):

	As of March 31, 2025
Macquarie Bank Limited	$	(2,812	)
Wells Fargo Bank, National Association		(1,200	)
Fifth Third Bank, National Association		(583	)
Mercuria Energy Trading SA		1,940
	$	(2,655	)

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 March 31, 2025
Beginning capitalized exploratory/extension well costs	$	33,619
Additions to exploratory/extension well costs		28,613
Reclassification to proved properties		(9,528	)
Exploratory/extension well costs charged to exploration and abandonment expense		—
Ending capitalized exploratory/extension well costs	$	52,704

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):

	March 31, 2025			December 31, 2024
Term Loan Credit Agreement due 2026	$	1,050,000		$	1,080,000
Senior Credit Facility Agreement due 2026		—			—
Discounts, net (a)		(14,771	)		(17,197	)
Debt issuance costs, net (b)		(12,385	)		(14,419	)
Total debt		1,022,844			1,048,384
Less current maturities of long-term debt		(120,000	)		(120,000	)
Long-term debt, net	$	902,844		$	928,384

(a)

Discounts as of March 31, 2025 and December 31, 2024 consisted of $30.0 million in discounts less accumulated amortization of $15.2 million and $12.8 million, respectively.

(b)

Debt issuance costs as of March 31, 2025 and December 31, 2024 consisted of $25.1 million and $25.1 million, respectively, in costs less accumulated amortization of $12.7 million and $10.7 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”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $24.0 million. The Term Loan Credit Agreement matures on September 30, 2026. 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 contains certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio.

The Term Loan Credit Agreement contains customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount which began March 31, 2024 ($150.0 million paid to date through March 31, 2025), 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) which began with the fiscal quarter ending March 31, 2024 (none paid to date as of March 31, 2025). In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.

Collateral Agency Agreement. On September 12, 2023, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) 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.

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 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.

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):

	Three Months Ended March 31, 2025
Beginning asset retirement obligations	$	14,750
Liabilities incurred from new wells		152
Dispositions		(88	)
Accretion of discount		244
Ending asset retirement obligations	$	15,058

As of March 31, 2025 and December 31, 2024, all asset retirement obligations are considered noncurrent and classified as such in the accompanying condensed consolidated balance sheets.

NOTE 9. Incentive Plans

401(k) Plan. The HighPeak Energy Employees, Inc 401(k) Plan (the “401(k) Plan”) is a defined contribution plan established under Section 401 of the Internal Revenue Code of 1986, as amended (the “Code”). All regular full-time and part-time employees of the Company are eligible to participate in the 401(k) Plan after three continuous months of employment with the Company. Participants may contribute up to 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k) Plan up to four percent of the participant’s annual base salary (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances at their eligibility date. During the three months ended March 31, 2025 and 2024, the Company contributed $173,000 and $201,000 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, 2025 and December 31, 2024 are as follows:

	March 31, 2025			December 31, 2024
Approved and authorized shares		16,414,015			16,414,015
Shares subject to awards issued under plan		(15,807,337	)		(15,808,671	)
Shares available for future grant		606,678			605,344

Stock options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021, May 4, 2022, August 15, 2022 and July 21, 2023. Stock-based compensation expense related to the Company’s stock option awards for the three months ended March 31, 2025 and 2024 was a negative $12,000 due to certain forfeitures and $52,000, respectively, and as of March 31, 2025 there was no unrecognized stock-based compensation expense related to unvested stock option awards. The 1,949,000 stock options granted in July 2023 were 100% vested upon grant on July 21, 2023. However, to encourage long-term alignment with the Company stockholders, the stock options are not exercisable until the earlier of (i) August 31, 2026, (ii) upon a change in control or (iii) upon the death or disability of the grantee.

The Company estimates the fair value of stock options granted on the grant date using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The expected term of options granted was determined based on the simplified method of the midpoint between the vesting dates and the contractual term of the options. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant and the volatility was based on the volatility of either an index of exploration and production crude oil and natural gas companies or on a peer group of companies with similar characteristics of the Company on the date of grant since the Company had minimal or did not have any trading history. More detailed stock options activity and details are as follows:

	Stock Options			Average Exercise Price		Remaining Term in Years		Intrinsic Value (in thousands)
Outstanding at December 31, 2023		13,449,061		$	11.95		6.3	$	47,672
Forfeitures		(4,999	)	$	26,44
Outstanding at December 31, 2024		13,444,062		$	11.95		5.3	$	53,093
Forfeitures		(1,334	)	$	19.98
Outstanding at March 31, 2025		13,442,728		$	11.94		5.1	$	29,544

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

Vested at March 31, 2025		13,442,728		$	11.94		5.1	$	29,544
Exercisable at March 31, 2025		11,493,728		$	12.19		5.7	$	25,334

Restricted stock issued to employee members of the Board and certain employees. A total of 1,500,500 shares of restricted stock was approved by the Board to be granted to certain employee members of the Board of the Company on November 4, 2021, which vest on the three-year anniversary of such grant assuming the employees remain in his or her position as of the anniversary date. Therefore, stock-based compensation expense of zero and $1.8 million was recognized during the three months ended March 31, 2025 and 2024, respectively, and there is no remaining unrecognized stock-based compensation expense as of March 31, 2025 to be recognized, which was based upon the closing price of the stock on the date of the restricted stock issuance. The Board also approved a total of 600,000 shares of restricted stock to be granted to certain employees of the Company on June 1, 2022, which vest on November 4, 2024, assuming the employees remain in his or her position as of that date. Therefore, stock-based compensation expense of zero and $1.8 million was recognized during the three months ended March 31, 2025 and 2024, respectively, and there is no remaining unrecognized stock-based compensation expense as of March 31, 2025 to be recognized, which was based upon the closing price of the stock on the date of the restricted stock issuance. On October 31, 2024, the vesting date for the aforementioned 2,100,500 shares of restricted stock was extended from November 4, 2024 to December 31, 2025 to ensure said restricted stock would continue to provide retention value to the Company. There is no excess stock-based compensation expense as the closing price on the modification date was lower than the original grant dates.

Stock issued to outside directors. 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, which will vest at the next annual meeting, assuming the Board members maintain their positions on the Board. Therefore, stock-based compensation expense of $189,000 was recognized during the three months ended March 31, 2025 and the remaining $126,000 will be recognized during the second quarter of 2025, which was based upon the closing price of the stock on the date of the restricted stock issuance. Also, a total of 58,767 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2023, which vested on June 4, 2024. Therefore, stock-based compensation expense of zero and $189,000 was recognized during the three months ended March 31, 2025 and 2024, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance.

NOTE 10. Commitments and Contingencies

Leases. The Company follows ASC Topic 842, “Leases” to account for its operating and finance leases. Therefore, as of March 31, 2025 the Company had right-of-use assets totaling $1.4 million included in other noncurrent assets and operating lease liabilities totaling $1.4 million, $821,000 of which is included in current liabilities and $581,000 of which is included in noncurrent liabilities, and as of December 31, 2024 the Company had right-of-use assets totaling $1.4 million included in other noncurrent assets and operating lease liabilities totaling $1.4 million, $719,000 of which are included in current liabilities and $670,000 of which are included in noncurrent liabilities on the accompanying condensed consolidated balance sheets. The Company does not currently have any finance right-of-use leases. Maturities of the operating lease obligations are as follows (in thousands):

	March 31, 2025
Remainder of 2025	$	900
2026		599
Total		1,499
Less present value discount		(98	)
Present value of lease liabilities	$	1,401

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 constructing a crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries. The contract contains a minimum volume commitment commencing May 2024 that totals $138.7 million based on the gross piped barrels delivered of 23,500 Bopd for the first ten years of the contract at a certain amount per barrel escalating throughout the term of the contract. However, the Company generally has the ability under the contract to cumulatively bank dollars based on excess volumes delivered to offset the minimum volume commitment. For the period from May 1, 2024 to March 31, 2025, the Company has delivered approximately 30,962 Bopd under the contract. The remaining monetary commitment as of March 31, 2025, if the Company never delivers any additional volumes under the agreement, is approximately $127.3 million.

Natural gas gathering and treating agreement. In June 2024, the Company entered into a natural gas gathering and treating agreement to gather certain natural gas in its Signal Peak area. Pursuant to said agreement, the Company has agreed to fund certain aid-in-construction costs totaling $7.2 million and $5.4 million during the three months ended March 31, 2025 and the year ended December 31, 2024, respectively. In addition, throughout the remainder of 2025 and first quarter of 2026, the Company has a remaining commitment under the contract of $20.0 million as certain milestones are attained. The agreement does not contain any minimum volume commitments.

Power contracts. In June 2022, the Company entered into a contract to provide 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 provide an additional block of electric power under similar terms. In conjunction with these contracts, the Company has a $4.6 million Letter of Credit in place in lieu of a deposit that is cancellable at the end of the contract term.

Sand commitments. The Company is party to an amended agreement whereby it has agreed to purchase at least 750,000 tons of sand over a fifteen-month period beginning April 1, 2024. The Company has taken deliveries of approximately 720,000 tons of sand through March 31, 2025, leaving a commitment of approximately 30,000 remaining. There are stipulations in the agreement that reduce this commitment should there be a downturn in crude oil prices. Generally, if the Company never takes delivery of any additional sand under the agreement, the monetary commitment that remains as of March 31, 2025 is approximately $776,000.

NOTE 11. Major Customers

Delek accounted for approximately 81% and 76% and Energy Transfer Crude Marketing, LLC (“ETC”) accounted for approximately 10% and 19% of the Company’s revenues during the three months ended March 31, 2025 and 2024, respectively. Based on the current demand for crude oil and natural gas and the availability of other purchasers, management believes the loss of either of these major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

NOTE 12. Income Taxes

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and Texas margin tax. The Company and its subsidiaries file a U.S. federal corporate income tax return on a consolidated basis.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”), which among other tax provisions, created a 15 percent corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1.0 billion of average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock repurchases for tax years beginning after December 31, 2022. Based on application of currently available guidance, the Company’s income tax expense for the three months ended March 31, 2025 and 2024 was not impacted by the CAMT. The Company’s excise tax imposed on its stock repurchases during the three months ended March 31, 2025 and the year ended December 31, 2024 was zero and $352,000, respectively, recognized as part of the cost basis of the stock repurchased.

The Company’s provision for income taxes attributable to income before income taxes consisted of the following (in thousands):

	Three Months Ended March 31,
	2025		2024
Provision for current income taxes:
Federal	$	—	$	386
State		—		223
Total provision for current income taxes		—		609
Provision for deferred income taxes:
Federal		9,572		1,465
State		367		223
Total provision for deferred income taxes		9,939		1,688
Total provision for income taxes	$	9,939	$	2,297

The reconciliation between the provision for income taxes computed by multiplying pre-tax income by the U.S. federal statutory rate and the reported amounts of provision for income taxes is as follows (in thousands, except rate):

	Three Months Ended March 31,
	2025			2024
Provision for income taxes at U.S. federal statutory rate	$	9,718		$	1,834
State deferred income taxes		367			399
Limited tax benefit (expense) due to stock-based compensation		(112	)		377
Other, net		(34	)		(313	)
Provision for income taxes	$	9,939		$	2,297
Effective income tax rate		21.5	%		26.3	%

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities were as follows as of March 31, 2025 and December 31, 2024 (in thousands):

	March 31, 2025			December 31, 2024
Deferred tax assets:
Interest expense limitations	$	80,163		$	73,013
Net operating loss carryforwards		16,030			13,089
Stock-based compensation		3,388			3,351
Unrecognized derivative losses, net		573			—
Other		79			35
Less: Valuation allowance		—			—
Deferred tax assets		100,233			89,488
Deferred tax liabilities:
Crude oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes		(342,570	)		(321,411	)
Unrecognized derivative gains, net		—			(475	)
Deferred tax liabilities		(342,570	)		(321,886	)
Net deferred tax liabilities	$	(242,337	)	$	(232,398	)

The effective income tax rate differs from the U.S. statutory rate of 21 percent primarily due to certain stock-based compensation which exceeds the federal limits, deferred state income taxes and other permanent differences between GAAP income and taxable income.

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, 2025 and December 31, 2024, the Company had not recorded a valuation allowance for deferred tax assets arising from its operations because the Company believed they met the “more likely than not” criteria as defined by the recognition and measurement provisions of ASC 740. The Company reversed a portion of its deferred tax asset related to stock-based compensation based on the assumption that the tax deduction will be subject to IRC Section 162(m) limits when the restricted stock vests. IRC Section 162(m) limits compensation deductions to $1.0 million per year for certain Company executives. This resulted in a $3.0 million reduction in the deferred tax asset and increased the amount of income tax expense realized during the three months ended March 31, 2024.

The Company is also subject to Texas margin tax. The Company realized zero and $223,000in current Texas margin tax in the accompanying condensed consolidated financial statements for the three months ended March 31, 2025 and 2024, respectively. In addition, the Company has recognized a net deferred Texas margin tax liability of $9.0 million and $8.6 million as of March 31, 2025 and December 31, 2024, respectively, in the accompanying condensed consolidated balance sheets.

NOTE 13. Earnings Per Share

The Company uses the two-class method of calculating earnings per share because certain of the Company’s stock-based awards qualify as participating securities.

The Company’s basic earnings per share attributable to common stockholders is computed as (i) net income as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as (i) basic 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, 2025 and 2024 under the two-class method (in thousands):

	Three Months Ended March 31,
	2025			2024
Net income as reported	$	36,335		$	6,438
Participating basic earnings (a)		(3,542	)		(605	)
Basic earnings attributable to common stockholders		32,793			5,833
Reallocation of participating earnings		47			1
Diluted net income attributable to common stockholders	$	32,840		$	5,834

Basic weighted average shares outstanding		123,913			125,696
Dilutive warrants and unvested stock options		1,146			1,786
Dilutive unvested restricted stock		2,154			2,159
Diluted weighted average shares outstanding		127,213			129,641

(a)

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

The calculation for weighted average shares reflects shares outstanding over the reporting period based on the actual number of days the shares were outstanding.

NOTE 14. Stockholders’ Equity

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

Issuance of Common Stock. During the three months ended March 31, 2025 and 2024, the Company did not issue any shares of HighPeak Energy common stock.

Dividends and Dividend Equivalents. 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 and accrued a dividend equivalent per share to all unvested stock option holders which will be payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In February 2024, the Board declared a quarterly dividend of $0.04 per share of common stock outstanding which resulted in a total of $5.1 million in dividends being paid in March 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $530,000 in March 2024 and accrued a dividend equivalent per share to all unvested stock option holders which will be payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Outstanding securities. At March 31, 2025 and December 31, 2024, the Company had 126,067,436 and 126,067,436 shares of common stock outstanding, respectively, and 7,934,922 and 7,934,922 warrants outstanding, respectively, with an exercise price of $11.50 per share that expire on August 21, 2025.

NOTE 15. Subsequent Events

Dividends and dividend equivalents. In May 2025, the Board approved a quarterly dividend of $0.04 per share of common stock outstanding which will result in a total of approximately $5.0 million in dividends to be paid in June 2025. In addition, under the terms of the LTIP, the Company will pay a dividend equivalent per share to all vested stock option holders of approximately $531,000 in June 2025. In addition, the Company will accrue 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.

Natural gas derivative instruments. In April 2025, the Company entered into the following additional natural gas derivative instruments.

Settlement Month	Settlement Year		Type of Contract		MMBtu Per Day		Index		Price per MMBtu
Natural Gas:
Jan – Mar		2026		Swap		10,333		HH	$	4.30
Apr – Jun		2026		Swap		30,000		HH	$	4.30
Jul – Sep		2026		Swap		30,000		HH	$	4.30
Oct – Dec		2026		Swap		30,000		HH	$	4.30
Jan – Mar		2027		Swap		19,667		HH	$	4.30

PART I. FINANCIAL INFORMATION

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

The following discussion and analysis is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and related notes. This discussion contains certain “forward‑looking statements” reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. These forward-looking statements involve risks and uncertainties and actual results and the timing of events may differ materially from those contained in these forward‑looking statements due to a number of factors. Factors that could cause or contribute to such differences include, but are not limited to, market prices for crude oil, NGL and natural gas, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties. Please read “Cautionary Statement Concerning Forward‑Looking Statements.” We assume no obligation to update any of these forward‑looking statements, except as required by applicable law.

Overview

HighPeak Energy, Inc., a Delaware corporation, 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, 2025, the assets consisted of two highly contiguous leasehold positions of approximately 154,810 gross (143,098 net) acres, approximately 65% 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, 2025, approximately 86% and 14% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of March 31, 2025, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew and expects to average one to two (1-2) drilling rigs and approximately one (1) frac crew during the remainder of 2025 under our current development plan.

Recent Events

Dividends and dividend equivalents. 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 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $86,000 in March 2025 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Acquisitions and divestitures. During the three months ended March 31, 2025, the Company incurred a total of $2.5 million in acquisition costs related to lease extensions and to acquire crude oil and natural gas leases covering additional contiguous bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas. In addition, during the three months ended March 31, 2025, the Company received $570,000 in proceeds from the sale of some non-core non-operated properties.

Crude Oil and Natural Gas Industry Considerations. Our operating results, and those of the crude oil and natural gas industry as a whole, are heavily influenced by commodity prices. Crude oil, NGL and natural gas prices and basis differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in crude oil prices may materially affect the quantities of crude oil, NGL and natural gas reserves we can economically produce over the longer term.

In early 2025, OPEC began unwinding prior voluntary production cuts, which added approximately 400,000 barrels per day to the global crude oil market. This substantial supply boost contributed to a decline in global crude oil prices during the three months ended March 31, 2025. Concurrently, in March 2025, the U.S. imposed tariffs on energy imports from Canada and Mexico, set at 10% and 25%, respectively, and expanded tariffs to include all steel and aluminum imports, aiming to bolster domestic production. In addition, in early April 2025, the current administration began announcing a substantial number of trade tariffs, including a new universal baseline reciprocal tariff of 10%, plus an additional country-specific reciprocal tariff for select trading partners, on all U.S. imports, although imports of crude oil, natural gas and refined products received exemptions from the tariffs. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff applied to China, which the administration increased. Concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed further downward pressure on oil prices. With negotiations and countermeasures still ongoing, the situation is fluid, and we expect price volatility to continue over the next few months. Collectively, these policy changes—OPEC's production increase and the U.S. tariffs—are introducing significant volatility to the crude oil and natural gas sector. In addition, tariffs have the potential to significantly increase our operating and capital costs, which could negatively impact our ability to carry out our planned drilling program and future growth projects.

In addition, since being sworn into office, President Trump has issued numerous Executive Orders that aim to increase crude oil production and decrease commodity prices. For example, President Trump declared a “national energy emergency” in January 2025, and gave the executive branch more power to expedite approvals for energy resource infrastructure (including crude oil and natural gas). Additionally, President Trump’s “Unleashing American Energy” Executive Order incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as crude oil and natural gas. More recently, in March 2025, President Trump signed an Executive Order that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices, our operations or California laws and regulations relating to crude oil and natural gas, CCUS and climate change. 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 war between Russia and Ukraine and ongoing conflicts between Israel and Hamas and other tensions in the Middle East have resulted in global supply chain disruptions, which has led to significant cost inflation. Such impacts may also be exacerbated by recent developments in the Israel-Hamas conflict as well as the tariffs and proposed tariffs by the new administration. Specifically, the Company’s 2023, 2024 and 2025 capital program has been and continues to be impacted by higher prices for steel, diesel, chemicals and services, among other items.

Global crude oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) general economic conditions and increasing expectations that the world may be heading into a global recession, (ii) the ability of OPEC and other crude oil producing nations to manage the global crude oil supply, (iii) the impact of sanctions and import bans on production from Russia and any resulting impact on production from the Israel-Hamas conflict, (iv) the timing and supply impact of any Iranian or Venezuelan sanction relief on their ability to export crude oil, (v) the global supply chain constraints associated with manufacturing and distribution delays, (vi) oilfield service demand and cost inflation, and (vii) political stability of crude oil consuming countries. 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, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35.

The markets for the commodities produced by our industry strengthened in 2021 and continued to remain strong through 2024 and into 2025, although the market has decreased from 2022 levels overall, as a result of increased demand outpacing increased supply for each of the commodities we produce. Prices for the commodities produced by our industry improved from historic lows in 2020, with crude oil and natural gas prices reaching their highest average annual price since 2014. However, there are many factors beyond the Company’s control, including commodity markets, unavailability or high cost of drilling rigs, equipment, supplies, personnel, frac crews and oilfield services or supply constraints remain subject to heightened levels of uncertainty as a result of the conflicts between Russia and Ukraine and between Israel and Hamas, elevated interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. For additional information on the risks, see “Part I. Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on March 10, 2025.

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its plan to average a one to two (1-2) drilling rig program for the remainder of 2025. The Company will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly. Despite continuing impacts of the factors listed above and future uncertainty, we are focused on maintaining our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our Midland Basin assets.

Strategic Alternatives

On January 23, 2023, the Company announced the intention of its Board to initiate a process to evaluate certain strategic alternatives to maximize shareholder value, including a potential sale of the Company. Texas Capital Securities has been retained as a financial advisor with respect to this strategic alternatives process. 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, 2025 included the highlights described below and comparative discussion of related drivers for the three months ended March 31, 2024:

•	Net income was $36.3 million ($0.26 per diluted share) for the three months ended March 31, 2025 compared with $6.4 million for three months ended March 31, 2024. The primary components of the $29.9 million increase in net income include:

	•	a $45.1 million decrease in the Company’s derivative instruments loss from $53.0 million in the prior year period compared with $7.9 million in the current year quarter 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 $21.5 million decrease in DD&A expense due to a 21% decrease in the DD&A rate from $28.92 to $22.86 per Boe as a result of a significant increase in proved reserves at the end of 2024;

	•	a $6.6 million decrease in the Company’s interest expense as a result of a decrease in the principal balance due to quarterly amortization payments and lower interest rates experienced; and

	•	a $3.6 million decrease in the Company’s stock-based compensation expense primarily due to a the majority of stock-based compensation instruments reaching fully vested status and thus have no further stock-based compensation expense to be recognized;

Partially offset by:

	•	a $30.3 million decrease in crude oil, NGL and natural gas revenues due to a 15% decrease in average realized commodity prices per Boe, excluding the effects of derivatives, partially offset by a 7% increase in daily sales volumes resulting primarily from increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking;

	•	a $7.6 million increase in the Company’s income tax expense primarily due to an increase in income before income taxes;

	•	a $5.3 million increase in the Company’s crude oil and natural gas production costs primarily as a result of increased expense workover costs with increased well cleanouts and pump changes with our aging well population, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper and roustabout costs also due to the increased number of wells operated;

	•	a $1.7 million increase in the Company’s general and administrative expenses primarily attributable to higher wages and benefits as well as an increase in professional fees, all primarily as a result of the growth of the Company; and

	•	a $1.6 million decrease in the Company’s interest income due to the decreased cash on hand.

•	During the three months ended March 31, 2025, average daily sales volumes totaled 53,128 Boepd, compared with 49,729 Boepd during the same period in 2024, an increase of 7%, primarily due to increased NGL and natural gas sales volumes due to third party midstream expansions and debottlenecking.

•

Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended March 31, 2025 to $71.64, compared with $77.65 for the same period in 2024. Weighted average NGL prices per Bbl decreased during the three months ended March 31, 2025 to $24.21, compared with $24.94 for the same period in 2024. Weighted average natural gas prices per Mcf increased to $2.34 during the three months ended March 31, 2025, compared with $1.33 during the same period in 2024.

•	Cash provided by operating activities totaled $157.1 million for the three months ended March 31, 2025, compared with $171.4 million for the three months ended March 31, 2024.

Derivative Financial Instruments

Crude oil derivative financial instrument exposure. As of March 31, 2025, the Company was a party to the following open crude oil derivative financial instruments.

									Swaps		Collars, Enhanced Collars & Deferred Premium Puts
Settlement Month	Settlement Year		Type of Contract		Bbls Per Day		Index		Price per Bbl		Floor or Strike Price per Bbl		Ceiling Price per Bbl		Deferred Premium Payable per Bbl
Crude Oil:
Apr - Jun		2025		Swap		5,500		WTI Cushing	$	76.37	$	—	$	—	$	—
Apr - Jun		2025		Collar		7,989		WTI Cushing	$	—	$	64.38	$	88.55	$	2.00
Apr - Jun		2025		Put		9,000		WTI Cushing	$	—	$	65.78	$	—	$	5.00
Jul - Sep		2025		Swap		3,000		WTI Cushing	$	75.85	$	—	$	—	$	—
Jul - Sep		2025		Collar		7,000		WTI Cushing	$	—	$	65.00	$	90.08	$	2.28
Jul - Sep		2025		Put		9,000		WTI Cushing	$	—	$	65.78	$	—	$	5.00
Oct - Dec		2025		Collar		5,000		WTI Cushing	$	—	$	60.00	$	72.80	$	—
Jan - Mar		2026		Collar		5,000		WTI Cushing	$	—	$	60.00	$	72.80	$	—

Natural gas derivative financial instrument exposure. As of March 31, 2025, the Company was a party to the following open natural gas derivative financial instruments.

Settlement Month	Settlement Year		Type of Contract		MMBtu Per Day		Index		Price per MMBtu
Natural Gas:
Apr – Jun		2025		Swap		30,000		HH	$	4.43
Jul – Sep		2025		Swap		30,000		HH	$	4.43
Oct – Dec		2025		Swap		30,000		HH	$	4.43
Jan – Mar		2026		Swap		19,667		HH	$	4.43

The estimated fair value of the outstanding open derivative financial instruments as of March 31, 2025 was a net liability of $2.7 million which is included in current assets and current liabilities on the Company’s consolidated balance sheet as of March 31, 2025. During the three months ended March 31, 2025, the Company recognized a net derivative loss of $7.9 million, including a $4.8 million mark-to-market loss and $3.1 million in net monthly settlement payments.

Operations and Drilling Highlights

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

	Three Months Ended March 31, 2025
Crude Oil (Bbls)		38,222
NGL (Bbls)		7,724
Natural Gas (Mcf)		43,096
Total (Boe)		53,128

The Company’s liquids production was 86% of total production on a Boe basis for the three months ended March 31, 2025.

Costs incurred are as follows (in thousands):

	Three Months Ended March 31, 2025
Unproved property acquisition costs	$	2,517
Proved acquisition costs		—
Total acquisitions		2,517
Development costs		151,201
Exploration costs		28,614
Total finding and development costs		182,332
Asset retirement obligations		156
Total costs incurred	$	182,488

The following table sets forth the total number of horizontal producing wells drilled and completed during the three months ended March 31, 2025:

	Drilled				Completed
	Gross		Net		Gross		Net
Flat Top area		16		16.0		13		12.9
Signal Peak area		—		—		—		—
Total		16		16.0		13		12.9

As of March 31, 2025, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew. The continued threat of an extensive recession, the scope, duration and magnitude of the direct and indirect effects of pandemics, the war between Russia and Ukraine, the Israel-Hamas conflict and the production cuts 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, 2025, the Company successfully completed and placed on production thirteen (13) gross (12.9 net) horizontal wells, all in the Flat Top area. As of March 31, 2025, the Company had twenty-one (21) gross (21.0 net) horizontal wells that had been drilled and were in various stages of completion and two (2) gross (2.0 net) salt-water disposal wells in progress, all in the Flat Top area. In addition, as of March 31, 2025, the Company was in the process of drilling seven (7) gross (7.0 net) horizontal wells, all in the Flat Top area.

Results of Operations

Three Months Ended March 31, 2025

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

	Three Months Ended March 31,
	2025		2024		% Change
Crude Oil (Bbls)		38,222		39,959		(4	)%
NGL (Bbls)		7,724		5,147		50	%
Natural Gas (Mcf)		43,096		27,733		55	%
Total (Boe)		53,128		49,729		7	%

The increase in average daily Boe sales volumes for the three months ended March 31, 2025, compared with the same period in 2024 was primarily due to increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

The crude oil, NGL and natural gas prices that the Company reports are based on the market prices received for each commodity. The weighted average realized prices, excluding the effects of derivatives, are as follows:

	Three Months Ended March 31,
	2025		2024		% Change
Crude Oil per Bbl	$	71.64	$	77.65		(8	)%
NGL per Bbl	$	24.21	$	24.94		(3	)%
Natural Gas per Mcf	$	2.34	$	1.33		76	%
Total per Boe	$	53.84	$	63.59		(15	)%

Revenue Variance Analysis.

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

	Three Months Ended March 31,
	2025			2024		% Change
Total operating revenues	$	257,448		$	287,764		(11	)%
Average daily sales volumes (Boe)		53,128			49,729		7	%
Realized price per Boe	$	53.84		$	63.59		(15	)%

Revenue change from prior period due to prices	$	(44,122	)				(15	)%
Revenue change from prior period due to volumes		13,793					5	%
Rounding		13					0	%
Total change from prior period revenues	$	(30,316	)

As detailed above, the decrease in total operating revenues for the three months ended March 31, 2025 compared to the same period in 2024 is the result of a 15% decrease in average realized price per Boe partially offset by a 7% increase in average daily sales volumes primarily as a result of increased NGL and natural gas sales volumes due to third-party midstream expansions and debottlenecking.

Crude Oil and natural gas production costs.

Crude oil and natural gas production costs in total and per Boe are as follows (in thousands, except percentages and per Boe amounts):

	Three Months Ended March 31,
	2025		2024		% Change
Crude oil and natural gas production costs	$	35,562	$	30,271		17	%
Crude oil and natural gas production costs per Boe (excluding expense workovers)	$	6.61	$	6.30		5	%
Workover expense	$	0.83	$	0.39		113	%

The increase in crude oil and natural gas production costs compared to the first quarter 2024 can be attributed primarily to increased expense workover costs with increased well cleanouts and pump changes with our aging well population, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper and roustabout costs also due to the increased number of wells operated.

Production and ad valorem taxes.

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

Three Months Ended

March 31,

2025

2024

% Change

Production and ad valorem taxes

15,152

14,402

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 increase in production and ad valorem taxes during the three months ended March 31, 2025 compared to the same period in 2024 can be attributed primarily to an increase in ad valorem taxes due to an over-accrual that was reversed during the three months ended March 31, 2024 that was not realized in the current year partially offset by the 15% decrease in overall commodity prices received partially offset by the aforementioned 7% increase in sales volumes.

Production and ad valorem taxes per Boe are as follows:

	Three Months Ended March 31,
	2025		2024		% Change
Production taxes per Boe	$	2.72	$	3.11		(13	)%
Ad valorem taxes per Boe	$	0.45	$	0.07		543	%

The decrease in production taxes per Boe for the three months ended March 31, 2025, compared with the same period in 2024 can be attributed primarily to the lower commodity prices received thus far in 2025. The increase in ad valorem taxes per Boe for the three months ended March 31, 2025, compared with the same period in 2024, was primarily due to the aforementioned reversal of an over-accrual from 2023 during the three months ended March 31, 2024 that was not realized during the current year.

Exploration and abandonments expense.

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

	Three Months Ended March 31,
	2025		2024		% Change
Geologic and geophysical personnel costs	$	260	$	225		16	%
Plugging and abandonment expense		4		148		(97	)%
Geologic and geophysical data costs		—		90		100	%
Abandoned leasehold costs		—		35		100	%
Exploration and abandonments expense	$	264	$	498		(47	)%

Exploration and abandonment costs decreased during the three months ended March 31, 2025 primarily due to less plugging and abandonment expenses, geologic and geophysical data costs and abandoned leasehold costs.

DD&A expense.

DD&A expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):

	Three Months Ended March 31,
	2025		2024		% Change
DD&A expense	$	109,325	$	130,850		(16	)%
DD&A expense per Boe	$	22.86	$	28.92		(21	)%

The decrease in DD&A during the three months ended March 31, 2025 is primarily due to a decrease in the DD&A rate primarily attributable to increased proved reserves partially offset by the increased production.

General and administrative expense.

General and administrative expense and general and administrative expense per Boe as well as stock-based compensation expense are as follows (in thousands, except percentages and per Boe amounts):

	Three Months Ended March 31,
	2025		2024		% Change
General and administrative expense	$	6,345	$	4,685		35	%
General and administrative expense per Boe	$	1.33	$	1.04		28	%
Stock-based compensation expense	$	177	$	3,798		(95	)%

The increase in general and administrative expense and general and administrative expense per Boe for the three months ended March 31, 2025 is primarily a result of increased wages and benefits related to the growth of the Company in addition to higher professional services costs related to the growth of the Company.

Interest expense.

	Three Months Ended March 31,
	2025		2024		% Change
Term Loan Credit Agreement	$	32,343	$	38,973		(17	)%
Senior Credit Facility Agreement		185		155		19	%
Amortization of discount		2,426		2,453		(1	)%
Amortization of debt issuance costs		2,034		2,053		(1	)%
	$	36,988	$	43,634		(15	)%

The decrease in interest expense can be attributed to a lower overall debt balance in 2025 compared with 2024, lower interest rates in 2025 compared with interest rates in 2024, and fewer calendar days compared to the same period in the prior year.

Loss on derivative instruments, net.

	Three Months Ended March 31,
	2025			2024			% Change
Noncash loss on derivative instruments, net	$	(4,856	)	$	(47,895	)		(90	)%
Cash paid on settlements of derivative instruments, net		(3,071	)		(5,148	)		(40	)%
Loss on derivative instruments, net	$	(7,927	)	$	(53,043	)		(85	)%

The Company primarily utilizes commodity swap contracts, costless collars, deferred premium collars and deferred premium put option contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budget and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require the Company to hedge certain quantities of its projected crude oil production. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market gain (loss) and cash settlements relate to crude oil derivative swap contracts, deferred premium collars and deferred premium put option contracts.

Provision for income taxes.

	Three Months Ended March 31,
	2025			2024			% Change
Income tax expense	$	9,939		$	2,297			333	%
Effective income tax rate		21.5	%		26.3	%		(18	)%

The change in provision for income taxes during the three months ended March 31, 2025, compared with the same period in 2024, was primarily due to the change in income before income taxes and the reversal of a deferred tax asset related to a temporary difference from restricted stock being reclassified to a permanent difference. The effective income tax rate differs from the statutory rate primarily due to certain aforementioned stock-based compensation revisions, Texas state income taxes and other permanent differences between GAAP income and taxable income. See Note 12 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)" for additional information.

Liquidity and Capital Resources

Liquidity. The Company’s primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under the Senior Credit Facility Agreement, (iv) on an opportunistic basis, other issuances of debt or equity securities and (v) sales of nonstrategic assets.

The Company’s short-term and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of other contractual obligations, (iv) working capital obligations, and (v) interest payments on and amortizations of its indebtedness. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity. Although the Company expects its sources of funding will be adequate to fund its 2025 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company’s future needs.

2025 capital budget. The Company’s capital budget for 2025 is expected to be in the range of approximately $375 to $405 million for drilling, completion, facilities and equipping crude oil wells plus $40 to $50 million for field infrastructure buildout and other costs and $33 to $35 million on one-time infrastructure expenditures. The 2025 capital budget excludes acquisitions, asset retirement obligations, geological and geophysical expenses, general and administrative expenses and corporate facilities. 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 three months ended March 31, 2025 were $179.8 million, 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 and other cooperating countries, and governments in response to pandemics, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors” in the Company’s Annual Report. The Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

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

	Three Months Ended March 31,
	2025			2024			Change			% Change
Net cash provided by operating activities	$	157,052		$	171,439		$	(14,387	)		(8	)%
Net cash used in investing activities	$	(156,594	)	$	(148,223	)	$	(8,371	)		6	%
Net cash (used in) provided by financing activities	$	(35,488	)	$	(44,351	)	$	8,863			(20	)%

Operating activities. The decrease in net cash flow provided by operating activities for the three months ended March 31, 2025, compared with 2024, was primarily related to a decrease in discretionary cash flow as a result of a decrease in revenues less operating and general administrative expenses of approximately $38.0 million associated with lower overall commodity prices partially offset by increased production volumes and increased costs related primarily to increased expense workover costs with increased well cleanouts and pump changes with our aging well population, increased electricity, power and fuel charges with the increased number of wells operated by the Company, increased insurance costs and increased pumper and roustabout costs also due to the increased number of wells operated partially offset by changes in operating assets and liabilities that differ from the prior year period.

Investing activities. The increase in net cash used in investing activities for the three months ended March 31, 2025, compared with 2024, was primarily due to increases in additions to crude oil and natural gas properties.

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

•

Three months ended March 31, 2025: The Company made a mandatory amortization payment on its Term Loan Credit Facility totaling $30.0 million and paid dividends and dividend equivalents of $5.0 million and $531,000, respectively.

•

Three months ended March 31, 2024: The Company made a mandatory amortization payment on its Term Loan Credit Facility of $30.0 million, paid $8.8 million to repurchase 565,540 shares of its common stock at an average cost of approximately $15.50 per share, excluding any potential excise taxes, and paid dividends and dividend equivalents of $5.1 million and $530,000, 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, 2025, we had a $1.05 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 six months. To the extent the interest rate is fixed, interest rate changes will affect the Term Loan Credit Agreement’s and Senior Credit Facility Agreement’s fair value but will not impact results of operations or cash flows. Conversely, for the portion of the Term Loan Credit Agreement and Senior Credit Facility Agreement that has a floating interest rate, interest rate changes will not affect the fair value but will impact future results of operations and cash flows.

Commodity Price Risk. The prices we receive for our crude oil, NGL and natural gas production directly impact our revenue, profitability, access to capital, and future rate of growth. Crude oil, NGL and natural gas prices are subject to unpredictable fluctuations resulting from a variety of factors, including changes in supply and demand and the macroeconomic environment, and seasonal anomalies, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, especially over the last several years. Commodity prices have improved from historic lows in 2020 resulting from the impacts of the COVID-19 pandemic. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing armed conflicts between Russia and Ukraine, Israel and Hamas and Israel and Iran. 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, 2025 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, 2025 would have increased (decreased) the Company’s revenues by approximately $14.7 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, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis.

We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of March 31, 2025, a $1.00 increase (decrease) in the forward curves associated with our crude oil commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $4.7 million. Additionally, as of March 31, 2025, a $0.10 increase (decrease) in the forward curves associated with our natural gas commodity derivative instruments would have decreased (increased) our net derivative positions for these products by approximately $1.0 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, other expense, gains and losses on divestitures and certain other items. EBITDAX excludes certain items we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. In addition, EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because EBITDAX excludes some, but not all items that affect net income and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies.

We are also subject to financial covenants under our Term Loan Credit Agreement and Senior Credit Facility Agreement based on EBITDAX ratios as further described in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Condensed Consolidated Financial Statements (Unaudited)” of this Quarterly Report. The Term Loan Credit Agreement and Senior Credit Facility Agreement provide a material source of liquidity for us. Under the terms of our Term Loan Credit Agreement and the Senior Credit Facility Agreement, if we fail to comply with the covenants that establish a maximum permitted ratio of total net leverage or a minimum permitted ratio of asset coverage, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, they would be entitled to exercise all their remedies for default.

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

	Three Months Ended March 31,
	2025			2024
Net income	$	36,335		$	6,438
Interest expense		36,988			43,634
Interest income		(810	)		(2,392	)
Provision for income taxes		9,939			2,297
Depletion, depreciation and amortization		109,325			130,850
Accretion of discount		244			239
Exploration and abandonment expense		264			498
Stock based compensation		177			3,798
Derivative related noncash activity		4,856			47,895
Other expense		—			1
EBITDAX	$	197,318		$	233,258

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, 2025. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report.

New accounting pronouncements issued but not yet adopted. The effects of new accounting pronouncements are discussed in Note 2 of Notes to Condensed Consolidated Financial Statements included in "Item 1. Condensed Consolidated Financial Statements (Unaudited)."

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company’s major market risk exposure is the pricing it receives for its sales of crude oil, NGL and natural gas. Pricing for crude oil, NGL and natural gas has been volatile and unpredictable for several years, and HighPeak Energy expects this volatility to continue in the future.

During the period from January 1, 2021 through March 31, 2025, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $52.10 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.58 to a high of $9.35. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the three months ended March 31, 2025 would have increased (decreased) the Company’s revenues by approximately $14.7 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, 2025 would have increased (decreased) the Company’s revenues by approximately $1.6 million on an annualized basis, excluding the effects of derivatives.

Due to this volatility, the Company uses commodity derivative instruments, such as collars, puts, swaps and basis swaps, to hedge price risk associated with a portion of anticipated production. These hedging instruments allow the Company to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in crude oil and natural gas prices and provide increased certainty of cash flows for its drilling program. These instruments provide only partial price protection against declines in crude oil and natural gas prices and may partially limit the Company’s potential gains from future increases in prices. The Company enters into hedging arrangements to protect its capital expenditure budget. The Company’s Term Loan Credit Agreement and Senior Credit Facility Agreement require the Company to hedge certain quantities of its projected crude oil production. The Company does not enter into any commodity derivative instruments, including derivatives, for speculative or trading purposes.

Counterparty and Customer Credit Risk. The Company’s derivative contracts, if any, expose it to credit risk in the event of nonperformance by counterparties. It is anticipated that if the Company enters into any commodity contracts, the collateral defined in the Collateral Agency Agreement may be used as collateral for the Company’s commodity derivatives. The Company evaluates the credit standing of its counterparties as it deems appropriate. It is anticipated that any counterparties to HighPeak Energy’s derivative contracts would have investment grade ratings.

The Company’s principal exposures to credit risk are through receivables from the sale of crude oil and natural gas production due to the concentration of its crude oil and natural gas receivables with a few significant customers. The inability or failure of the Company’s significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company’s financial results.

The average forward prices based on March 31, 2025 market quotes were as follows:

Remainder of

2025

Year Ending

December 31,

2026

Average forward NYMEX crude oil price per Bbl

68.96

65.54

Average forward NYMEX natural gas price per MMBtu

4.48

4.44

The average forward prices based on May 8, 2025 market quotes were as follows:

Remainder of

2025

Year Ending

December 31,

2026

Average forward NYMEX crude oil price per Bbl

58.68

59.27

Average forward NYMEX natural gas price per MMBtu

4.12

4.35

Credit Risk. The Company's primary concentration of credit risk is associated with (i) the collection of receivables resulting from the sale of crude oil and natural gas production and (ii) the risk of a counterparty's failure to meet its obligations under derivative contracts with the Company.

The Company monitors exposure to counterparties primarily by reviewing credit ratings, financial criteria and payment history. Where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. The Company's crude oil and natural gas is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. Historically, the Company's credit losses on crude oil and natural gas receivables have not been material.

The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures.

The Company entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with right of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative contract, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

Interest Rate Risk. As of March 31, 2025, we had $1.05 billion outstanding under the Term Loan Credit Agreement and had $93.1 million of available borrowing capacity under the Senior Credit Facility Agreement. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement and Senior Credit Facility Agreement. The Company also 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, 2025 would have resulted in an annual increase in interest expense of approximately $10.5 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, 2025 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, the Company may be a party to various lawsuits, proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of 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 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.

Potential new trade policies, such as tariffs, could adversely affect our operations, profitability and business.

There is currently significant uncertainty regarding the future relationship between the United States and various other countries arising from changes that may be implemented by the United States federal government, including with respect to trade policies, treaties, tariffs, taxes and other limitations on cross-border operations. Any actions taken by the United States’ federal government that restrict or could impact the economics of trade—including additional tariffs, trade barriers, and other similar measures—could have the potential to disrupt existing supply chains and trigger retaliatory efforts by other countries, including the imposition of tariffs, raising taxation, setting foreign exchange or capital controls, or establishing embargos, sanctions, or other import/export restrictions, thereby negatively impacting our business, both directly and indirectly. These developments, or the perception that more of them could occur, may create or increase business uncertainty and could materially adversely affect the global economy and stability of global financial markets, potentially reducing trade and depressing economic activity. Such changes in international trade policies may result in direct impacts to our business or indirectly to our customers or suppliers through increased costs, changes in business prospects or operating results, which could materially adversely affect our financial condition. The extent of such impacts cannot be predicted at this time.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

Our common stock repurchase activity for the three months ended March 31, 2025 was as follows:

Period	Total Number of Shares Purchased⁽¹⁾		Average Price Paid Per Share⁽²⁾		Total Number of Shares Purchased as Part of Publicly Announced Plan		Approximate Dollar Value of Shares that May Yet to Be Purchased Under the Plan⁽³⁾⁽⁴⁾
($ in thousands, except per share amounts and shares)
January 1, 2025 - January 31, 2025		—	$	—		—	$	39,907
February 1, 2025 - February 28, 2025		—	$	—		—	$	39,907
March 1, 2025 - March 31, 2025		—	$	—		—	$	39,907
Total		—	$	—		—

(1) Such shares are cancelled and retired.

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

(3) In February 2024, our Board approved a stock repurchase program for up to $75.0 million, excluding excise taxes and other expenses. The stock repurchase program expires on December 31, 2024. However, on March 6, 2025, our Board extended the program in its entirety to December 31, 2025. The program may be suspended, modified, or discontinued by the Board at any time.

(4) The IRA of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.

ITEM 5. OTHER INFORMATION

During the three months ended March 31, 2025, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

HIGHPEAK ENERGY, INC.

ITEM 6. EXHIBITS

Exhibit Number	Description

3.1	Second Amended & Restated Certificate of Incorporation of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 2, 2023).

3.2	Amended and Restated Bylaws of HighPeak Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on November 9, 2020).

4.1	Registration Rights Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP and certain other security holders named therein (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

4.2	Stockholders’ Agreement, dated as of August 21, 2020, by and among HighPeak Energy, Inc., HighPeak Pure Acquisition, LLC, HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, Jack Hightower and certain directors of Pure Acquisition Corp. (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

4.3	Amendment and Assignment to Warrant Agreement, dated as of August 21, 2020, by and among Pure Acquisition Corp., Continental Stock Transfer & Trust Company and HighPeak Energy, Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

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

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.

HIGHPEAK ENERGY, INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.

	HIGHPEAK ENERGY, INC.

May 12, 2025	By:	/s/ Steven Tholen
		Steven Tholen
		Chief Financial Officer

May 12, 2025	By:	/s/ Keith Forbes
		Keith Forbes
		Vice President and Chief Accounting Officer

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