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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2023

or

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

For the transition period from ________ to ________

Commission File Number: 001-3946

| 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 November 2, 2023, there were 128,420,923 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 | 4
PART I. FINANCIAL INFORMATION
Item 1. | Condensed Consolidated Financial Statements (Unaudited) | 5
| Condensed Consolidated Balance Sheets | 5
| Condensed Consolidated Statements of Operations | 6
| Condensed Consolidated Statements of Changes in Stockholders’ Equity | 7
| Condensed Consolidated Statements of Cash Flows | 8
| Notes to Condensed Consolidated Financial Statements | 9
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | 27
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 40
Item 4. | Controls and Procedures | 41
PART II. OTHER INFORMATION
Item 1. | Legal Proceedings | 41
Item 1A. | Risk Factors | 41
Item 5. | Other Information | 44
Item 6. | Exhibits | 45
Signatures |  | 46

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:

| • | “10.000% Senior Notes” means the $225.0 million aggregate principal amount of our 10.000% Senior Notes due 2024, which were issued pursuant to an indenture in February 2022.
| • | “10.625% Senior Notes” means the $250.0 million aggregate principal amount of our 10.625% Senior Notes due 2024, $225.0 million of which were issued pursuant to an indenture in November 2022 and $25.0 million of which were issued pursuant to an indenture in December 2022.
| • | “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.
| • | “Alamo Acquisitions” means the acquisitions of certain crude oil and natural gas properties in Borden County, Texas, collectively, from (i) Alamo Borden County II, LLC (“Alamo II”), Alamo Borden County III, LLC (“Alamo III”) and Alamo Borden County IV, LLC (“Alamo IV”) pursuant to that certain Purchase and Sale Agreement dated February 15, 2022 by and among HighPeak Energy, HighPeak Energy Assets, LLC (together with HighPeak Energy, the “HighPeak Parties”), Alamo II, Alamo III, and Alamo IV and (ii) Alamo Borden County 1, LLC (“Alamo I”) pursuant to that certain Purchase and Sale Agreement dated June 3, 2022 by and among the HighPeak Parties and Alamo I.
| • | “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 between HighPeak Energy, Inc., Texas Capital Bank, as collateral agent, Chambers Energy Management, LP, as term representative, and Mercuria Energy Trading SA, as first-out representative.
| • | “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.
| • | “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.
| • | “Eighth Amendment” means the Eighth Amendment to Prior Credit Agreement, dated as of March 14, 2023, by and among HighPeak Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
| • | “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.
| • | “Fifth Amendment” means the Fifth Amendment to Prior Credit Agreement, dated as of October 14, 2022, by and among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as the existing administrative agent, Wells Fargo Bank, National Association, as the new 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.
| • | “Fourth Amendment” means the Fourth Amendment to Prior Credit Agreement, dated as of June 27, 2022, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the guarantors party thereto and lenders party thereto.
| • | “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.

1

| • | “Hannathon Acquisition” means the acquisition of various crude oil and natural gas properties largely contiguous to the Company’s Signal Peak operating area in Howard County, Texas pursuant to that certain Purchase and Sale Agreement dated as of April 26, 2022, with Hannathon Petroleum, LLC and certain other third-party private sellers set forth therein.
| • | “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.
| • | “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.
| • | “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.
| • | “Ninth Amendment” means the Ninth Amendment to Prior Credit Agreement, dated as of July 12, 2023, by and among HighPeak Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
| • | “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.
| • | “Predecessor” refers to HPK LP for the period from January 1, 2020 to August 20, 2020.
| • | “Prior Credit Agreement” means the Company’s Credit Agreement, dated as of December 17, 2020, as amended from time to time, among HighPeak Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as administrative agent, and the Lenders party thereto.
| • | “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.

2

| • | “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.
| • | “Seventh Amendment” means the Seventh Amendment to Prior Credit Agreement, dated as of December 9, 2022, by and among HighPeak Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
| • | “Sixth Amendment” means the Sixth Amendment to Prior Credit Agreement, dated as of October 31, 2022, by and among HighPeak Energy, Inc., as Borrower, Wells Fargo Bank, National Association, as administrative agent, the guarantors party thereto and the lenders party thereto.
| • | “Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, the distance between horizontal wellbores, e.g., 880-foot spacing or the number of wells per section, e.g., 6-well spacing. It is often established by regulatory agencies and/or the operator to optimize recovery of hydrocarbons.
| • | “Spot market price” The cash market price without reduction for expected quality, transportation and demand adjustments.
| • | “Standardized measure” The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines as well as the rules and regulations of the SEC, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to DD&A. Standardized measure does not give effect to derivative transactions.
| • | “Stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
| • | “Term Loan Credit Agreement” means the Company’s Term Loan Credit Agreement, dated as of September 12, 2023, by and between HighPeak Energy, Inc., as borrower, Texas Capital Bank, as administrative agent, Chambers Energy Management, LP, as collateral agent, and the lenders from time-to-time party thereto.
| • | “Third Amendment” means the Third Amendment to Prior Credit Agreement, dated as of February 9, 2022, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the lenders party thereto.
| • | “Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether such acreage contains proved reserves.
| • | “Unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
| • | “U.S.” means the United States.
| • | “warrants” means warrants to purchase one share of HighPeak Energy common stock at a price of $11.50 per share.
| • | “Wellbore” The hole drilled by the bit that is equipped for crude oil and natural gas production on a completed well. Also called well or borehole.
| • | “Working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
| • | “Workover” Operations on a producing well to restore or increase production.
| • | “WTI” means West Texas Intermediate, a light sweet blend of crude oil produced from fields in western Texas and is a grade of crude oil used as a benchmark in crude oil pricing.
| • | With respect to information on the working interest in wells and acreage, “net” wells and acres are determined by multiplying “gross” wells and acres by the Company’s working interest in such wells or acres. Unless otherwise specified, wells and acreage statistics quoted herein represent gross wells or acres.
| • | All currency amounts are expressed in U.S. dollars.

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

3

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 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;
| ● | capital expenditures and other contractual obligations, including our obligations under our Term Loan Credit Agreement and Senior Credit Facility Agreement;
| ● | the results of our ongoing strategic alternatives review process;
| ● | political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine and the Israel-Hamas conflict;
| ● | the integration of acquisitions, including the Alamo Acquisitions and the Hannathon Acquisition;
| ● | the availability of capital resources;
| ● | production and reserve levels;
| ● | drilling and completion risks;
| ● | inflation rates and the impacts of associated monetary policy responses, including increased interest rates and resulting pressures on economic growth;
| ● | economic and competitive conditions;
| ● | the impacts of the transition to an anticipated three-rig development program for the remainder of 2023;
| ● | weather conditions;
| ● | the length, scope and severity of the ongoing coronavirus disease (“COVID-19”) pandemic, 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 the pandemic and its 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;
| ● | cyber-attacks;
| ● | occurrence of property acquisitions or divestitures;
| ● | the securities or 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, 2022 filed with the SEC on March 6, 2023 (“Annual Report”) our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2023, filed with the SEC on May 10, 2023, June 30, 2023, filed with the SEC on August 7, 2023, and this Quarterly Report, under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and “Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

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.

4

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

HighPeak Energy, Inc.

Condensed Consolidated Balance Sheets

(in thousands, except share data)

|  | September 30, 2023 |  |  | December 31, 2022 |
|  | (Unaudited) |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 151,807 |  |  | $ | 30,504 |
Accounts receivable |  |  | 125,982 |  |  |  | 96,596 |
Inventory |  |  | 15,130 |  |  |  | 13,275 |
Derivative instruments |  |  | 3,247 |  |  |  | 17 |
Prepaid expenses |  |  | 1,726 |  |  |  | 4,133 |
Total current assets |  |  | 297,892 |  |  |  | 144,525 |
Crude oil and natural gas properties, using the successful efforts method of accounting: |  |  |  |  |  |  |  |
Proved properties |  |  | 3,151,619 |  |  |  | 2,270,236 |
Unproved properties |  |  | 79,961 |  |  |  | 114,665 |
Accumulated depletion, depreciation and amortization |  |  | (551,373 | ) |  |  | (259,962 | )
Total crude oil and natural gas properties, net |  |  | 2,680,207 |  |  |  | 2,124,939 |
Other property and equipment, net |  |  | 3,539 |  |  |  | 3,587 |
Other noncurrent assets |  |  | 7,229 |  |  |  | 6,431 |
Total assets |  | $ | 2,988,867 |  |  | $ | 2,279,482 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Current maturities of long-term debt |  | $ | 90,000 |  |  | $ | — |
Accrued capital expenditures |  |  | 60,573 |  |  |  | 91,842 |
Accounts payable – trade |  |  | 50,341 |  |  |  | 105,565 |
Revenues and royalties payable |  |  | 34,086 |  |  |  | 15,623 |
Other accrued liabilities |  |  | 30,457 |  |  |  | 15,600 |
Derivative instruments |  |  | 27,776 |  |  |  | 16,702 |
Accrued interest |  |  | 869 |  |  |  | 13,152 |
Operating leases |  |  | 517 |  |  |  | 343 |
Advances from joint interest owners |  |  | 28 |  |  |  | 7,302 |
Total current liabilities |  |  | 294,647 |  |  |  | 266,129 |
Noncurrent liabilities: |  |  |  |  |  |  |  |
Long-term debt, net |  |  | 1,057,803 |  |  |  | 704,349 |
Deferred income taxes |  |  | 169,414 |  |  |  | 131,164 |
Asset retirement obligations |  |  | 8,022 |  |  |  | 7,502 |
Derivative instruments |  |  | 3,743 |  |  |  | 691 |
Operating leases |  |  | 136 |  |  |  | — |
Commitments and contingencies (Note 10) |  |  |  |  |  |  |  |
Stockholders’ equity: |  |  |  |  |  |  |  |
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at September 30, 2023 and December 31, 2022 |  |  | — |  |  |  | — |
Common stock, $0.0001 par value, 600,000,000 shares authorized, 128,220,923 and 113,165,027 shares issued and outstanding at September 30, 2023 and December 31, 2022, respectively |  |  | 13 |  |  |  | 11 |
Additional paid-in capital |  |  | 1,183,262 |  |  |  | 1,008,896 |
Retained earnings |  |  | 271,827 |  |  |  | 160,740 |
Total stockholders’ equity |  |  | 1,455,102 |  |  |  | 1,169,647 |
Total liabilities and stockholders’ equity |  | $ | 2,988,867 |  |  | $ | 2,279,482 |

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

5

HighPeak Energy, Inc.

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(Unaudited)

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |  |  | 2023 |  |  | 2022 |
Operating revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil sales |  | $ | 338,372 |  |  | $ | 189,441 |  |  | $ | 790,458 |  |  | $ | 467,305 |
NGL and natural gas sales |  |  | 7,214 |  |  |  | 14,673 |  |  |  | 19,682 |  |  |  | 30,466 |
Total operating revenues |  |  | 345,586 |  |  |  | 204,114 |  |  |  | 810,140 |  |  |  | 497,771 |
Operating costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and natural gas production |  |  | 39,820 |  |  |  | 19,707 |  |  |  | 107,696 |  |  |  | 45,748 |
Production and ad valorem taxes |  |  | 18,839 |  |  |  | 10,526 |  |  |  | 44,395 |  |  |  | 25,833 |
Exploration and abandonments |  |  | 1,728 |  |  |  | 290 |  |  |  | 4,372 |  |  |  | 683 |
Depletion, depreciation and amortization |  |  | 117,420 |  |  |  | 42,624 |  |  |  | 291,562 |  |  |  | 94,531 |
Accretion of discount |  |  | 122 |  |  |  | 125 |  |  |  | 360 |  |  |  | 245 |
General and administrative |  |  | 6,934 |  |  |  | 1,877 |  |  |  | 11,952 |  |  |  | 5,833 |
Stock-based compensation |  |  | 14,057 |  |  |  | 10,655 |  |  |  | 22,095 |  |  |  | 29,210 |
Total operating costs and expenses |  |  | 198,920 |  |  |  | 85,804 |  |  |  | 482,432 |  |  |  | 202,083 |
Other expense |  |  | 540 |  |  |  | — |  |  |  | 8,042 |  |  |  | — |
Income from operations |  |  | 146,126 |  |  |  | 118,310 |  |  |  | 319,666 |  |  |  | 295,688 |
Interest and other income |  |  | 730 |  |  |  | 1 |  |  |  | 923 |  |  |  | 253 |
Interest expense |  |  | (37,022 | ) |  |  | (14,608 | ) |  |  | (103,278 | ) |  |  | (29,142 | )
Gain (loss) on derivative instruments, net |  |  | (29,655 | ) |  |  | 35,798 |  |  |  | (30,898 | ) |  |  | (42,487 | )
Loss on extinguishment of debt |  |  | (27,300 | ) |  |  | — |  |  |  | (27,300 | ) |  |  | — |
Income before income taxes |  |  | 52,879 |  |  |  | 139,501 |  |  |  | 159,113 |  |  |  | 224,312 |
Provision for income taxes |  |  | 14,100 |  |  |  | 31,597 |  |  |  | 38,251 |  |  |  | 55,357 |
Net income |  | $ | 38,779 |  |  | $ | 107,904 |  |  | $ | 120,862 |  |  | $ | 168,955 |
Earnings per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic net income |  | $ | 0.28 |  |  | $ | 0.90 |  |  | $ | 0.94 |  |  | $ | 1.48 |
Diluted net income |  | $ | 0.28 |  |  | $ | 0.85 |  |  | $ | 0.90 |  |  | $ | 1.40 |
Weighted average shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 123,159 |  |  |  | 108,681 |  |  |  | 115,164 |  |  |  | 102,614 |
Diluted |  |  | 127,006 |  |  |  | 115,118 |  |  |  | 120,531 |  |  |  | 109,144 |
Dividends declared per share |  | $ | 0.025 |  |  | $ | 0.025 |  |  | $ | 0.075 |  |  | $ | 0.075 |

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

6

HighPeak Energy, Inc.

Condensed Consolidated Statements of Changes in Stockholders' Equity

(in thousands)

(Unaudited)

Three and Nine Months Ended September 30, 2023 |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Shares Outstanding |  |  | Common Stock |  |  | Additional Paid-in-Capital |  |  | Retained Earnings |  |  | Total Stockholders' Equity |
Balance, December 31, 2022 |  |  | 113,165 |  |  | $ | 11 |  |  | $ | 1,008,896 |  |  | $ | 160,740 |  |  | $ | 1,169,647 |
Dividends declared ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,829 | ) |  |  | (2,829 | )
Dividend equivalents declared on outstanding stock options ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (288 | ) |  |  | (288 | )
Exercise of warrants |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | — |  |  |  | 2 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Shares issued upon options being exercised |  |  | 12 |  |  |  | — |  |  |  | 148 |  |  |  | — |  |  |  | 148 |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 4,054 |  |  |  | — |  |  |  | 4,054 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 50,257 |  |  |  | 50,257 |
Balance, March 31, 2023 |  |  | 113,177 |  |  |  | 11 |  |  |  | 1,013,100 |  |  |  | 207,880 |  |  |  | 1,220,991 |
Dividends declared ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,830 | ) |  |  | (2,830 | )
Dividend equivalents declared on outstanding stock options ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (287 | ) |  |  | (287 | )
Exercise of warrants |  |  | 150 |  |  |  | — |  |  |  | 1,726 |  |  |  | — |  |  |  | 1,726 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Restricted shares issued to outside directors |  |  | 59 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 3,984 |  |  |  | — |  |  |  | 3,984 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 31,826 |  |  |  | 31,826 |
Balance, June 30, 2023 |  |  | 113,386 |  |  |  | 11 |  |  |  | 1,018,810 |  |  |  | 236,589 |  |  |  | 1,255,410 |
Dividends declared ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (3,205 | ) |  |  | (3,205 | )
Dividend equivalents declared on outstanding stock options ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (336 | ) |  |  | (336 | )
Stock issued in public offering |  |  | 14,835 |  |  |  | 2 |  |  |  | 155,766 |  |  |  | — |  |  |  | 155,768 |
Stock issuance costs |  |  | — |  |  |  | — |  |  |  | (5,371 | ) |  |  | — |  |  |  | (5,371 | )
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 14,057 |  |  |  | — |  |  |  | 14,057 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 38,779 |  |  |  | 38,779 |
Balance, September 30, 2023 |  |  | 128,221 |  |  | $ | 13 |  |  | $ | 1,183,262 |  |  | $ | 271,827 |  |  | $ | 1,455,102 |

Three and Nine Months Ended September 30, 2022 |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Shares Outstanding |  |  | Common Stock |  |  | Additional Paid-in-Capital |  |  | Retained Earnings (Accumulated Deficit) |  |  | Total Stockholders' Equity |
Balance, December 31, 2021 |  |  | 96,774 |  |  | $ | 10 |  |  | $ | 617,489 |  |  | $ | (64,436 | ) |  | $ | 553,063 |
Dividends declared ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,434 | ) |  |  | (2,434 | )
Dividend equivalents declared on outstanding stock options ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (250 | ) |  |  | (250 | )
Stock issued for acquisition |  |  | 6,960 |  |  |  | — |  |  |  | 156,599 |  |  |  | — |  |  |  | 156,599 |
Stock issuance costs |  |  | — |  |  |  | — |  |  |  | (55 | ) |  |  | — |  |  |  | (55 | )
Exercise of warrants |  |  | 69 |  |  |  | — |  |  |  | 779 |  |  |  | — |  |  |  | 779 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Shares issued upon options being exercised |  |  | 8 |  |  |  | — |  |  |  | 75 |  |  |  | — |  |  |  | 75 |
Compensation costs included in net loss |  |  | — |  |  |  | — |  |  |  | 2,614 |  |  |  | — |  |  |  | 2,614 |
Net loss |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (16,510 | ) |  |  | (16,510 | )
Balance, March 31, 2022 |  |  | 103,811 |  |  |  | 10 |  |  |  | 777,501 |  |  |  | (83,630 | ) |  |  | 693,881 |
Dividends declared ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,630 | ) |  |  | (2,630 | )
Dividend equivalents declared on outstanding stock options ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (249 | ) |  |  | (249 | )
Stock issued for acquisitions |  |  | 3,894 |  |  |  | 1 |  |  |  | 108,382 |  |  |  | — |  |  |  | 108,383 |
Stock issuance costs |  |  | — |  |  |  | — |  |  |  | (3 | ) |  |  | — |  |  |  | (3 | )
Exercise of warrants |  |  | 897 |  |  |  | — |  |  |  | 6,971 |  |  |  | — |  |  |  | 6,971 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Shares issued upon options being exercised |  |  | 4 |  |  |  | — |  |  |  | 45 |  |  |  | — |  |  |  | 45 |
Restricted shares issued to outside directors |  |  | 21 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Restricted shares issued to employees |  |  | 600 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 16,429 |  |  |  | — |  |  |  | 16,429 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 77,561 |  |  |  | 77,561 |
Balance, June 30, 2022 |  |  | 109,227 |  |  |  | 11 |  |  |  | 909,325 |  |  |  | (8,948 | ) |  |  | 900,388 |
Dividends declared ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (2,730 | ) |  |  | (2,730 | )
Dividend equivalents declared on outstanding stock options ($0.025 per share) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (270 | ) |  |  | (270 | )
Stock issued in private placement |  |  | 3,933 |  |  |  | — |  |  |  | 85,000 |  |  |  | — |  |  |  | 85,000 |
Stock issuance costs |  |  | — |  |  |  | — |  |  |  | (232 | ) |  |  | — |  |  |  | (232 | )
Exercise of warrants |  |  | 3 |  |  |  | — |  |  |  | 30 |  |  |  | — |  |  |  | 30 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 10,655 |  |  |  | — |  |  |  | 10,655 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 107,904 |  |  |  | 107,904 |
Balance, September 30, 2022 |  |  | 113,163 |  |  | $ | 11 |  |  | $ | 1,004,778 |  |  | $ | 95,956 |  |  | $ | 1,100,745 |

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

7

HighPeak Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

|  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |  |  |  |  |
Net income |  | $ | 120,862 |  |  | $ | 168,955 |
Adjustments to reconcile net income to net cash provided by operations: |  |  |  |  |  |  |  |
Provision for deferred income taxes |  |  | 38,251 |  |  |  | 55,357 |
Loss on extinguishment of debt |  |  | 27,300 |  |  |  | — |
Loss on derivative instruments, net |  |  | 30,898 |  |  |  | 42,487 |
Cash paid on settlement of derivative instruments |  |  | (21,032 | ) |  |  | (64,143 | )
Amortization of debt issuance costs |  |  | 9,352 |  |  |  | 3,261 |
Amortization of discounts on long-term debt |  |  | 12,660 |  |  |  | 4,609 |
Stock-based compensation expense |  |  | 22,095 |  |  |  | 29,210 |
Accretion expense |  |  | 360 |  |  |  | 245 |
Depletion, depreciation and amortization expense |  |  | 291,562 |  |  |  | 94,531 |
Exploration and abandonment expense |  |  | 3,747 |  |  |  | 134 |
Changes in operating assets and liabilities: |  |  |  |  |  |  |  |
Accounts receivable |  |  | (29,385 | ) |  |  | (43,822 | )
Prepaid expenses, inventory and other assets |  |  | (1,628 | ) |  |  | (7,148 | )
Accounts payable, accrued liabilities and other current liabilities |  |  | 16,700 |  |  |  | 19,130 |
Net cash provided by operating activities |  |  | 521,742 |  |  |  | 302,806 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |  |  |  |
Additions to crude oil and natural gas properties |  |  | (840,663 | ) |  |  | (725,107 | )
Changes in working capital associated with crude oil and natural gas property additions |  |  | (86,468 | ) |  |  | 142,299 |
Acquisitions of crude oil and natural gas properties |  |  | (9,602 | ) |  |  | (258,385 | )
Deposit and other costs related to pending acquisitions |  |  | (409 | ) |  |  | — |
Other property additions |  |  | (103 | ) |  |  | (2,158 | )
Net cash used in investing activities |  |  | (937,245 | ) |  |  | (843,351 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |  |  |  |
Borrowings under Term Loan Credit Agreement, net of discount |  |  | 1,170,000 |  |  |  | — |
Borrowings under Prior Credit Agreement |  |  | 255,000 |  |  |  | 450,000 |
Proceeds from issuance of 10.000% Senior Notes, net of discount |  |  | — |  |  |  | 210,179 |
Repayments under Prior Credit Agreement |  |  | (525,000 | ) |  |  | (195,000 | )
Repayments of 10.000% Senior Notes and 10.625% Senior Notes |  |  | (475,000 | ) |  |  | — |
Premium on extinguishment of debt |  |  | (4,457 | ) |  |  | — |
Proceeds from issuance of common stock |  |  | 155,768 |  |  |  | 85,000 |
Proceeds from exercises of warrants |  |  | 1,728 |  |  |  | 7,780 |
Proceeds from exercises of stock options |  |  | 148 |  |  |  | 120 |
Debt issuance costs |  |  | (26,401 | ) |  |  | (9,221 | )
Stock offering costs |  |  | (5,371 | ) |  |  | (290 | )
Dividends paid |  |  | (8,706 | ) |  |  | (7,636 | )
Dividend equivalents paid |  |  | (903 | ) |  |  | (908 | )
Net cash provided by financing activities |  |  | 536,806 |  |  |  | 540,024 |
Net increase (decrease) in cash and cash equivalents |  |  | 121,303 |  |  |  | (521 | )
Cash and cash equivalents, beginning of period |  |  | 30,504 |  |  |  | 34,869 |
Cash and cash equivalents, end of period |  | $ | 151,807 |  |  | $ | 34,348 |
Supplemental cash flow information: |  |  |  |  |  |  |  |
Cash paid for interest |  | $ | 93,549 |  |  | $ | 18,318 |
Cash paid for income taxes |  |  | — |  |  |  | — |
Supplemental disclosure of non-cash transactions: |  |  |  |  |  |  |  |
Stock issued for acquisition |  | $ | — |  |  | $ | 264,982 |
Additions to asset retirement obligations |  |  | 241 |  |  |  | 3,748 |

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

8

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, 2022, filed with the U.S. Securities and Exchange Commission (“SEC”) on March 6, 2023, 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 September 30, 2023 and for the three and nine months ended September 30, 2023 and 2022 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"). The operating results for the three and nine months ended September 30, 2023 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, 2022. Certain prior period amounts have been reclassified to conform to the current period 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 accompanying unaudited interim condensed consolidated financial statements have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. During the three months ended September 30, 2023, the Company was successful in refinancing its current and long-term debt, specifically extending all near term maturities to late 2026, which is further discussed in Note 7. This debt refinancing also allowed the Company to eliminate its working capital deficits. As a result of the effectiveness and implementation of the refinancing, there is no longer substantial doubt about the Company’s ability to continue as a going concern.

Principles of consolidation. The 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. Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation.

Use of estimates in the preparation of financial statements. Preparation of the Company's consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the 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, 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 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.

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Accounts receivable. As of September 30, 2023 and December 31, 2022, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $116.3 million and $81.6 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, joint interest receivables of $6.5 million and $2.2 million, respectively, current U.S. federal income tax receivables of $3.2 million and $3.2 million, respectively, zero and $4.9 million, respectively, related to receivables from electric power infrastructure installed throughout Flat Top by the Company that it was reimbursed for, and receivables related to settlements of derivative contracts of zero and $4.7 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.

The Company adopted ASU 2016-13 and the subsequent applicable modifications to the rule on January 1, 2023. Accounts receivable are stated at amounts due from purchasers or joint interest owners, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from purchasers or joint interest owners outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. As of September 30, 2023 and December 31, 2022, the Company had no allowance for credit losses related to accounts receivable.

Concentration of credit risk. The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the nine months ended September 30, 2023 and the year ended December 31, 2022, sales to the Company’s two largest purchasers accounted for approximately 96% and 94%, 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 consolidated balance sheet and as charges to other expense in the consolidated statements of operations. The Company’s materials and supplies inventory as of September 30, 2023 and December 31, 2022 is $15.1 million and $13.3 million, respectively, and the Company has not recognized any valuation allowance to date.

Prepaid expenses. Prepaid expenses are comprised primarily of prepaid insurance costs that will be amortized over the life of the policies, caliche that will be used on future locations and roads in our development areas, tubulars and proppant that the Company has prepaid the suppliers to guarantee their availability when needed for our current drilling program, a deposit on a small property acquisition that is expected to close in the fourth quarter of 2023, prepaid agency fees and software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of September 30, 2023 and December 31, 2022 are $1.7 million and $4.1 million, respectively.

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

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

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

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved developed reserves for drilling, completion and other crude oil and natural gas property costs. Costs of 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. An impairment loss is indicated 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 $847,000 and $696,000 as of September 30, 2023 and December 31, 2022, respectively, are as follows (in thousands):

|  | September 30, 2023 |  |  | December 31, 2022 |
Land |  | $ | 2,139 |  |  | $ | 2,139 |
Transportation equipment |  |  | 648 |  |  |  | 691 |
Buildings |  |  | 534 |  |  |  | 544 |
Leasehold improvements |  |  | 213 |  |  |  | 206 |
Field equipment |  |  | 4 |  |  |  | 6 |
Furniture and fixtures |  |  | 1 |  |  |  | 1 |
Total other property and equipment, net |  | $ | 3,539 |  |  | $ | 3,587 |

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

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

Aid-in-construction assets. As of September 30, 2023 and December 31, 2022, the Company had aid-in-construction assets totaling $5.6 million and $6.1 million, respectively, included in other noncurrent assets. The Company is receiving 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. 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.

11

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 maturities of long-term debt, accounts payable, accrued liabilities and derivative liabilities included in current liabilities as of September 30, 2023 and December 31, 2022 totaled approximately $294.6 million and $266.1 million, respectively, including current maturities of long-term debt, accrued capital expenditures, trade accounts payable, 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 $46.1 million in debt issuance costs, $26.4 million of which was incurred during the nine months ended September 30, 2023 primarily related to the completion of the Term Loan Credit Agreement and amendments to the Prior Credit Agreement. Amortization based on the straight-line method over the terms of the Term Loan Credit Agreement, Prior Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes which approximates the effective interest method was $9.4 million and $3.3 million during the nine months ended September 30, 2023 and 2022, respectively. In addition, the Company realized a total of $64.8 million in original issue discounts on the issuance of its Term Loan Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes that is being amortized over the life of the agreements which approximates the effective interest method and was $12.7 million and $4.6 million during the nine months ended September 30, 2023 and 2022, respectively. All unamortized debt issuance costs and discounts as of the termination of the Prior Credit Agreement and redemption of the 10.000% Senior Notes and 10.625% Senior Notes during September 2023 were charged to expense and included in loss on extinguishment of debt in the accompanying consolidated financial statements. See Note 7 for more information. As of September 30, 2023 and December 31, 2022, the remaining net debt issuance costs and discounts related to the Term Loan Credit Agreement are netted against the outstanding long-term debt on the accompanying consolidated balance sheets in accordance with GAAP.

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

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

The Company enters into contracts with purchasers to sell its crude oil, NGL and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the crude oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the crude oil and natural gas marketing contracts is typically received from the purchaser one to two months after the date of sale. As of September 30, 2023 and December 31, 2022, the Company had receivables related to contracts with purchasers of approximately $116.3 million and $81.6 million, respectively.

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

Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. 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 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.

12

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 September 30, 2023 and December 31, 2022.

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 13 for additional information.

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

The Company is also subject to Texas Margin Tax. The Company realized no current Texas Margin Tax in the accompanying consolidated financial statements as we do not anticipate owing any Texas Margin Tax for the periods presented.

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. Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Recently adopted accounting pronouncements. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investment in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company adopted this update effective January 1, 2023. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity since it does not have a history of credit losses.

New accounting pronouncements not yet adopted. 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.

13

NOTE 3. Acquisitions

Hannathon Acquisition. In June 2022, the Company closed the Hannathon Acquisition for total net consideration of $337.2 million after normal and customary closing adjustments, including 3,522,117 shares of HighPeak Energy common stock valued at $97.2 million at closing to acquire various crude oil and natural gas properties largely contiguous to its Signal Peak operating area in Howard County, including associated producing properties, water system infrastructure and in-field fluid gathering pipelines. The Hannathon Acquisition was accounted for as an asset acquisition as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. The consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. All transaction costs associated with the Hannathon Acquisition were capitalized.

Alamo Acquisitions. In March and June 2022, the Company closed the Alamo Acquisitions in two separate deals for total net consideration of $156.1 million and $11.0 million, respectively, after normal and customary closing adjustments, including 6,960,000 and 371,517 shares of HighPeak Energy common stock valued at $156.6 million and $11.2 million, respectively, at closing to acquire various crude oil and natural gas properties contiguous to its Flat Top operating area in Borden county, including associated producing properties, water system infrastructure and in-field fluid gathering pipelines. The Alamo Acquisitions were accounted for as asset acquisitions as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. The consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. All transaction costs associated with the Alamo Acquisitions were capitalized.

Other acquisitions. During the nine months ended September 30, 2023 and 2022, the Company incurred a total of $9.6 million and $19.2 million, respectively, in acquisition costs to acquire various undeveloped crude oil and natural gas properties contiguous to its Flat Top and Signal Peak operating areas.

14

NOTE 4. Fair Value Measurements

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

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

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

Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 are as follows (in thousands):

|  | As of September 30, 2023 |
|  | 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 |  | $ | — |  |  | $ | 3,247 |  |  | $ | — |  |  | $ | 3,247 |
Commodity price derivatives – noncurrent |  |  | — |  |  |  | 1,030 |  |  |  | — |  |  |  | 1,030 |
Total assets |  |  | — |  |  |  | 4,277 |  |  |  | — |  |  |  | 4,277 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity price derivatives – current |  |  | — |  |  |  | 27,776 |  |  |  | — |  |  |  | 27,776 |
Commodity price derivatives – noncurrent |  |  | — |  |  |  | 3,743 |  |  |  | — |  |  |  | 3,743 |
Total liabilities |  |  | — |  |  |  | 31,519 |  |  |  | — |  |  |  | 31,519 |
Total recurring fair value measurements |  | $ | — |  |  | $ | (27,242 | ) |  | $ | — |  |  | $ | (27,242 | )

|  | As of December 31, 2022 |
|  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  |  | Significant Other Observable Inputs (Level 2) |  |  | Significant Unobservable Inputs (Level 3) |  |  | Total |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity price derivatives– current |  | $ | — |  |  | $ | 17 |  |  | $ | — |  |  | $ | 17 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity price derivatives – current |  |  | — |  |  |  | 16,702 |  |  |  | — |  |  |  | 16,702 |
Commodity price derivatives – noncurrent |  |  | — |  |  |  | 691 |  |  |  | — |  |  |  | 691 |
Total liabilities |  |  | — |  |  |  | 17,393 |  |  |  | — |  |  |  | 17,393 |
Total recurring fair value measurements |  | $ | — |  |  | $ | (17,376 | ) |  | $ | — |  |  | $ | (17,376 | )

Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil swap contracts and deferred premium collars and deferred premium put options. 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, and (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. The Company assesses the recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved or unproved crude oil and natural gas properties for the periods presented in the accompanying consolidated financial statements.

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Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidating balance sheets are as follows (in thousands):

|  | As of September 30, 2023 |  |  | As of December 31, 2022 |
|  | Carrying |  |  |  |  |  |  | Carrying |  |  |  |  |
|  | Value |  |  | Fair Value |  |  | Value |  |  | Fair Value |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
10.625% Senior Notes (a) |  | $ | — |  |  | $ | — |  |  | $ | 250,000 |  |  | $ | 250,000 |
10.000% Senior Notes (a) |  | $ | — |  |  | $ | — |  |  | $ | 225,000 |  |  | $ | 225,000 |

| (a) | Fair value is determined using Level 2 inputs. The Company’s senior unsecured notes are quoted, but not actively traded, on major exchanges; therefore, fair value is based on periodic values as quoted on major exchanges. See Note 7 for additional information.

The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, accounts payable, long-term debt (specifically the Term Loan Credit Agreement, Senior Credit Facility Agreement and the Prior Credit 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 and deferred premium 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 consolidated statements of operations (in thousands):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |  |  | 2023 |  |  | 2022 |
Noncash gain (loss) on derivative instruments, net |  | $ | (15,883 | ) |  | $ | 38,098 |  |  | $ | (9,866 | ) |  | $ | 21,656 |
Cash paid on settlement of derivative instruments, net |  |  | (13,772 | ) |  |  | (2,300 | ) |  |  | (21,032 | ) |  |  | (64,143 | )
Gain (loss) on derivative instruments, net |  | $ | (29,655 | ) |  | $ | 35,798 |  |  | $ | (30,898 | ) |  | $ | (42,487 | )

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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 crude oil prices. As such, the Company uses NYMEX WTI derivative contracts to manage future crude oil price volatility.

The Company’s outstanding crude oil derivative instruments as of September 30, 2023 and the weighted average crude oil prices and premiums payable per barrel for those contracts are as follows:

|  |  |  |  |  |  |  |  |  |  | Swaps |  |  | Deferred Premium Collars & Deferred Premium Puts |
Settlement Month |  | Settlement Year |  | Type of Contract |  | Bbls Per Day |  | Index |  | Price |  |  | Floor or Strike Price |  |  | Ceiling Price |  |  | Deferred Premium Payable |
Crude Oil: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oct - Dec |  | 2023 |  | Swap |  |  | 11,300 |  | WTI |  | $ | 77.84 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Oct - Dec |  | 2023 |  | Collar |  |  | 5,000 |  | WTI |  | $ | — |  |  | $ | 75.50 |  |  | $ | 100.00 |  |  | $ | 0.35 |
Oct - Dec |  | 2023 |  | Put |  |  | 19,000 |  | WTI |  | $ | — |  |  | $ | 69.46 |  |  | $ | — |  |  | $ | 5.00 |
Jan - Mar |  | 2024 |  | Swap |  |  | 4,000 |  | WTI |  | $ | 84.00 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jan - Mar |  | 2024 |  | Collar |  |  | 6,000 |  | WTI |  | $ | — |  |  | $ | 80.00 |  |  | $ | 100.00 |  |  | $ | 3.50 |
Jan - Mar |  | 2024 |  | Put |  |  | 20,000 |  | WTI |  | $ | — |  |  | $ | 66.44 |  |  | $ | — |  |  | $ | 5.00 |
Apr - Jun |  | 2024 |  | Swap |  |  | 4,000 |  | WTI |  | $ | 84.00 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Apr - Jun |  | 2024 |  | Collar |  |  | 5,500 |  | WTI |  | $ | — |  |  | $ | 69.73 |  |  | $ | 95.00 |  |  | $ | 0.61 |
Apr - Jun |  | 2024 |  | Put |  |  | 14,000 |  | WTI |  | $ | — |  |  | $ | 60.41 |  |  | $ | — |  |  | $ | 5.00 |
Jul - Sep |  | 2024 |  | Swap |  |  | 4,000 |  | WTI |  | $ | 84.00 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jul - Sep |  | 2024 |  | Collar |  |  | 1,500 |  | WTI |  | $ | — |  |  | $ | 69.00 |  |  | $ | 95.00 |  |  | $ | 0.85 |
Jul - Sep |  | 2024 |  | Put |  |  | 14,000 |  | WTI |  | $ | — |  |  | $ | 60.41 |  |  | $ | — |  |  | $ | 5.00 |
Oct - Dec |  | 2024 |  | Swap |  |  | 5,500 |  | WTI |  | $ | 76.37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Oct - Dec |  | 2024 |  | Collar |  |  | 10,600 |  | WTI |  | $ | — |  |  | $ | 65.68 |  |  | $ | 90.32 |  |  | $ | 1.85 |
Oct - Dec |  | 2024 |  | Put |  |  | 2,000 |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |
Jan - Mar |  | 2025 |  | Swap |  |  | 5,500 |  | WTI |  | $ | 76.37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jan - Mar |  | 2025 |  | Collar |  |  | 8,000 |  | WTI |  | $ | — |  |  | $ | 65.00 |  |  | $ | 90.00 |  |  | $ | 2.12 |
Jan - Mar |  | 2025 |  | Put |  |  | 2,000 |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |
Apr - Jun |  | 2025 |  | Swap |  |  | 5,500 |  | WTI |  | $ | 76.37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Apr - Jun |  | 2025 |  | Collar |  |  | 7,000 |  | WTI |  | $ | — |  |  | $ | 65.00 |  |  | $ | 90.08 |  |  | $ | 2.28 |
Apr - Jun |  | 2025 |  | Put |  |  | 2,000 |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |
Jul - Sep |  | 2025 |  | Swap |  |  | 3,000 |  | WTI |  | $ | 75.85 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jul - Sep |  | 2025 |  | Collar |  |  | 7,000 |  | WTI |  | $ | — |  |  | $ | 65.00 |  |  | $ | 90.08 |  |  | $ | 2.28 |
Jul - Sep |  | 2025 |  | Put |  |  | 2,000 |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |

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

|  | As of September 30, 2023 |
Macquarie Bank Limited |  | $ | (16,697 | )
Wells Fargo Bank, National Association |  |  | (10,034 | )
Mercuria Energy Trading SA |  |  | (888 | )
Fifth Third Bank, National Association |  |  | 377 |
|  | $ | (27,242 | )

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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 consolidated balance sheets. If the exploratory/extension well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The changes in capitalized exploratory/extension well costs are as follows (in thousands):

|  | Nine Months Ended September 30, 2023 |
Beginning capitalized exploratory/extension well costs |  | $ | 186,427 |
Additions to exploratory/extension well costs |  |  | 416,091 |
Reclassification to proved properties |  |  | (551,217 | )
Exploratory/extension well costs charged to exploration and abandonment expense |  |  | — |
Ending capitalized exploratory/extension well costs |  | $ | 51,301 |

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):

|  | September 30, 2023 |  |  | December 31, 2022 |
Term Loan Credit Agreement due 2026 |  | $ | 1,200,000 |  |  | $ | — |
Senior Credit Facility Agreement due 2026 |  |  | — |  |  |  | — |
Prior Credit Agreement |  |  | — |  |  |  | 270,000 |
10.625% Senior Notes |  |  | — |  |  |  | 250,000 |
10.000% Senior Notes |  |  | — |  |  |  | 225,000 |
Discounts, net (a) |  |  | (29,542 | ) |  |  | (27,086 | )
Debt issuance costs, net (b) |  |  | (22,655 | ) |  |  | (13,565 | )
Total debt |  |  | 1,147,803 |  |  |  | 704,349 |
Less current maturities of long-term debt |  |  | (90,000 | ) |  |  | — |
Long-term debt, net |  | $ | 1,057,803 |  |  | $ | 704,349 |

| (a) | Discounts as of September 30, 2023 and December 31, 2022 consisted of $30.0 million and $34.8 million, respectively, in discounts less accumulated amortization of $458,000 and $7.7 million, respectively.

| (b) | Debt issuance costs as of September 30, 2023 and December 31, 2022 consisted of $23.0 million and $19.7 million, respectively, in costs less accumulated amortization of $351,000 and $6.1 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 $23.0 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.

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The Term Loan Credit Agreement contains customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.

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.

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 Capitol 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. Subsequent to quarter end, 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 a borrowing capacity of $100.0 million with elected commitments of $75.0 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.

Prior Credit Agreement. In December 2020, the Company entered into a Credit Agreement with Fifth Third as the administrative agent and sole lender to establish a revolving credit facility (the “Prior Credit Agreement”) that was set to mature on June 17, 2024. In February 2022, the Company entered into the Third Amendment to, among other things, (i) reduce the borrowing base from $195.0 million to $138.8 million, (ii) modify the terms of the Prior Credit Agreement to reduce the aggregate elected commitments from $195.0 million to $138.8 million, (iii) update the maturity date to a springing maturity date, which caused the Prior Credit Agreement to mature on October 1, 2023 if the 10.000% Senior Notes are not redeemed or refinanced by that date or the terms of the 10.000% Senior Notes have not been amended to extend the scheduled repayment thereof to no earlier than October 1, 2024, (iv) allow the Company to redeem the 10.000% Senior Notes with proceeds of a refinancing, with proceeds of an equity offering or with cash, in each case, subject to certain customary conditions and (v) replace the USD LIBOR rates with Term SOFR rates.

In June 2022, the Company entered into the Fourth Amendment to, among other things, (i) increase (a) the aggregate elected commitments to $400.0 million, (b) the borrowing base to $400.0 million and (c) the maximum credit amount to $1.5 billion, (ii) increase the excess cash threshold to $75.0 million, (iii) modify the affirmative hedging requirement so that if total debt to EBITDAX is greater than 1.25 to 1.00 but less than or equal to 1.75 to 1.00, notional volumes covering the first 24 months following the measurement date shall be hedged in an amount equal to not less than 25% of the projected production and if total debt to EBITDAX is greater than 1.75 to 1.00, notional volumes covering the first 24 months following the measurement date shall be hedged in an amount equal to not less than 50% of the projection production and (iv) increase the number of banks included in the syndicate at differing levels of commitments, with Fifth Third remaining the administrative agent.

In October 2022, the Company entered into the Fifth Amendment to, among other things, (i) increase the elected commitments to $525 million and the borrowing base to $550 million, (ii) require an additional borrowing base redetermination on or about December 1, 2022, (iii) modify the permitted dividends and distributions conditions such that minimum availability under the credit facility must be 25% percent (as opposed to 30% before giving effect to the Fifth Amendment) and (iv) appoint Wells Fargo Bank, National Association (“Wells Fargo”) as the new administrative agent to replace Fifth Third. In addition, in connection with the Fifth Amendment, to the extent the Company incurs any additional specified unsecured senior, senior subordinated or subordinated future indebtedness in an aggregate amount of up to $250.0 million before June 30, 2023, the Company’s obligation to reduce the borrowing base by an amount equal to 25% of the principal amount of such additional future indebtedness shall be waived. In connection with the Fifth Amendment, the lenders waived two events of default existing with the Prior Credit Agreement, as it existed prior to giving effect to the Fifth Amendment, related to entering into and maintaining certain minimum hedges as of the fiscal quarters ending June 30, 2022 and September 30, 2022 and complying with the required current ratio as of the fiscal quarter ending September 30, 2022. In October 2022, the Company entered into the Sixth Amendment to, among other things, (i) change the period to 120 days following the maturity date for which there can be no scheduled principal payments, mandatory redemption or maturity date for the 10.000% Senior Notes and the Specified Senior Notes, (ii) clarify that the Specified Senior Notes are subject to the restriction on the voluntary redemption by the Company of certain specified additional debt, including the 10.000% Senior Notes, (iii) add a permitted lien basket in connection with the escrow account to be opened in connection with the Specified Senior Notes and (iv) provide for an exception for the restriction on mandatory redemptions of the Specified Senior Notes in connection with the special mandatory redemption provided for with respect to the Specified Senior Notes.

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In December 2022, the Company entered into the Seventh Amendment to, among other things, increase the amount of Specified Senior Notes from $225.0 million to $250.0 million. In March 2023, the Company entered into the Eighth Amendment to, among other things, (a) increase the borrowing base to $700.0 million, (b) add an aggregate elected commitments concept at an initial amount of $575.0 million, (c) provide that the applicable margin shall be determined in reference to such aggregate elected commitments (as opposed to being determined in reference to the borrowing base before giving effect to the Eighth Amendment), (d) modify the permitted dividends and distributions conditions such that minimum availability under the credit facility must be 25% of such aggregate elected commitments (as opposed to the borrowing base before giving effect to the Eighth Amendment), (e) permit quarterly dividends and distributions in an amount not to exceed $4.0 million provided that there is no default and that after giving effect thereto and any concurrent borrowing, the Company is in pro forma compliance with its financial covenants, (f) require the Company, on or before June 30, 2023, to redeem or refinance the 10.000% Senior Notes, allocate a portion of its cash flow that will retire the 10.000% Senior Notes on or before November 30, 2023 or amend the terms of the 10.000% Senior Notes to extend the scheduled repayment thereof to no earlier than February 15, 2025, (g) permit the redemption of Specified Additional Debt (defined in the Prior Credit Agreement to mean any unsecured senior, senior subordinated or subordinated Debt of the Borrower incurred after the Effective Date and any refinancing of such Debt, including without limitation, the 10.000% Senior Notes; provided that any such Debt may be refinanced only to the extent that the aggregate principal amount of such refinanced Debt does not result in an increase in the principal amount thereof plus amounts to fund any original issue discount or upfront fees relating thereto plus amounts to fund accrued interest, fees, expenses and premiums, with all Capitalized terms defined in such Prior Credit Agreement) with the proceeds of Loans if pre-approved by all Lenders provided that there is no default and that after giving effect thereto, the Company is in pro forma compliance with its financial covenants and (h) add Texas Capital Bank as a Lender.

In July 2023, the Company entered into the Ninth Amendment to, among other things, provide for (i) a waiver of the minimum current ratio covenant for the fiscal quarter ended June 30, 2023 under the Prior Credit Agreement, (ii) a waiver of the failure to subject one or more certain accounts to an Account Control Agreement within the period provided in the Prior Credit Agreement, (iii) a postponement of the April 2023 borrowing base redetermination until September 2023, (iv) a postponement of the date on which the Company was previously obligated thereunder to either extend the maturity of the 10.000% Senior Notes due February 2024, redeem or refinance the 10.000% Senior Notes or allocate a portion of the Company’s cash flow satisfactory to the Administrative Agent and the Majority Lenders that will retire the 10.000% Senior Notes on or before November 30, 2023 to September 1, 2023 or such later date as agreed to in writing by the Majority Lenders in their reasonable discretion, (v) certain pricing increases and additional minimum hedging requirements, (vi) an additional requirement to deliver a 13-week cash flow forecast on a weekly basis through completion of the September 2023 borrowing base redetermination and (vii) a temporary restriction on borrowing further amounts under the Prior Credit Agreement until the Company has received at least $95 million of net proceeds from the sales of the Company’s equity securities, which has been subsequently satisfied and the restriction no longer applies.

In connection with the entry into the aforementioned Term Loan Credit Agreement, the Prior Credit Agreement was terminated, all outstanding obligations for principal, interest and fees were paid off in full, and all liens securing such obligations and guarantees of such obligations and securing any letter of credit or hedging obligations (other than those novated pursuant to the terms of the Term Loan Credit Agreement) permitted by the Prior Credit Agreement to be secured by such liens were released. In addition, unamortized debt issuance costs as of the termination date of $2.7 million were charged to expense and included in the accompanying consolidated financial statements in loss on extinguishment of debt.

10.000% Senior Notes. In February 2022, the Company issued $225.0 million aggregate principal amount of its 10.000% Senior Notes due 2024 (“10.000% Senior Notes”), which were set to mature on February 15, 2024. The Company received proceeds of $202.9 million, net of $22.1 million of issuance costs and discounts. The net proceeds were used to pay down the balance of the Prior Credit Agreement to zero at closing and to fund our ongoing capital development program with subsequent draws on the Prior Credit Agreement. Interest on the 10.000% Senior Notes was payable on February 15 and August 15 of each year. In connection with the aforementioned Term Loan Credit Agreement, the 10.000% Senior Notes were redeemed at a redemption price of 100% of the principal amount thereof plus accrued and unpaid interest and fees. In addition, unamortized discounts and debt issuance costs as of the redemption date of $3.2 million and $1.5 million, respectively, were charged to expense and included in the accompanying consolidated financial statements in loss on extinguishment of debt.

10.625% Senior Notes. In November 2022 and December 2022, the Company issued $225.0 million and $25.0 million, respectively, under separate indentures, of its 10.625% Senior Notes due 2024 (“10.625% Senior Notes”), which were set to mature on November 15, 2024. The Company received proceeds of $223.7 million, net of $26.3 million of issuance costs and discounts. The net proceeds were used to reduce the outstanding balance of the Prior Credit Agreement at closing and for general corporate purposes. Interest on the 10.625% Senior Notes was payable on May 15 and November 15 of each year. In addition, the Company paid additional interest of $8.3 million in June 2023 in accordance with the indentures whereby if the Company did not receive a rating increase by June 30, 2023, it was required to pay said additional interest that is included in interest expense during the nine months ended September 30, 2023. In connection with the aforementioned Term Loan Credit Agreement, the 10.625% Senior Notes were redeemed at a redemption price of 100% of the principal amount thereof plus accrued and unpaid interest and fees, plus the applicable premium calculated as $4.5 million, which was the present value at September 14, 2023 of all required interest payments due on the 10.625% Senior Notes through November 15, 2023. In addition, unamortized discounts and debt issuance costs as of the redemption date of $11.7 million and $3.7 million, respectively, were charged to expense and included in the accompanying consolidated financial statements in loss on extinguishment of debt.

The Term Loan Credit Agreement and the Senior Credit Facility Agreement have hedging requirements to which the Company adheres.

20

NOTE 8. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and remediation of related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

Asset retirement obligations activity is as follows (in thousands):

|  | Nine Months Ended September 30, 2023 |
Beginning asset retirement obligations |  | $ | 7,502 |
Liabilities incurred from new wells |  |  | 241 |
Dispositions |  |  | (81 | )
Accretion of discount |  |  | 360 |
Ending asset retirement obligations |  | $ | 8,022 |

As of September 30, 2023 and December 31, 2022, all asset retirement obligations are considered noncurrent and classified as such in the accompanying consolidated balance sheets.

NOTE 9. Incentive Plans

401(k) Plan. The HighPeak Energy Employees, Inc 401(k) Plan (the “401(k) Plan”) is a defined contribution plan established under Section 401 of the Internal Revenue Code of 1986, as amended (the “Code”). All regular full-time and part-time employees of the Company are eligible to participate in the 401(k) Plan after three continuous months of employment with the Company. Participants may contribute up to 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k) Plan up to four percent of the participant’s annual base salary (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances at their eligibility date. During the nine months ended September 30, 2023 and 2022, the Company contributed $176,000 and $210,000 to the 401(k) Plan, respectively.

Long-Term Incentive Plan. The Company’s Second Amended & Restated Long Term Incentive Plan (“LTIP”) provides for the grant of stock options, restricted stock, stock awards, dividend equivalents, cash awards and substitute awards to officers, employees, directors and consultants of the Company. The number of shares available for grant pursuant to awards under the LTIP as of September 30, 2023 and December 31, 2022 are as follows:

|  | September 30, 2023 |  |  | December 31, 2022 |
Approved and authorized shares |  |  | 16,388,015 |  |  |  | 14,340,324 |
Shares subject to awards issued under plan |  |  | (15,759,791 | ) |  |  | (13,769,191 | )
Shares available for future grant |  |  | 628,224 |  |  |  | 571,133 |

Stock options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021, May 4, 2022, August 15, 2022 and July 21, 2023. Stock-based compensation expense related to the Company’s stock option awards for the nine months ended September 30, 2023 and 2022 was $10.9 million and $17.7 million, respectively, and as of September 30, 2023 and December 31, 2022 there was $261,000 and $1.1 million, respectively, of unrecognized stock-based compensation expense related to unvested stock option awards. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than one year. 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.

21

The Company estimates the fair values 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, 2021 |  |  | 9,983,727 |  |  | $ | 10.19 |  |  |  | 8.7 |  |  | $ | 44,395 |
Awards granted |  |  | 1,564,500 |  |  |  | 25.09 |  |  |  |  |  |  |  |  |
Exercised |  |  | (12,000 | ) |  | $ | 10.00 |  |  |  |  |  |  |  |  |
Forfeitures |  |  | (18,999 | ) |  | $ | 18.66 |  |  |  |  |  |  |  |  |
Outstanding at December 31, 2022 |  |  | 11,517,228 |  |  | $ | 12.20 |  |  |  | 7.9 |  |  | $ | 128,429 |
Awards granted |  |  | 1,949,000 |  |  |  | 10.50 |  |  |  |  |  |  |  |  |
Exercised |  |  | (11,834 | ) |  | $ | 12.52 |  |  |  |  |  |  |  |  |
Forfeitures |  |  | (5,333 | ) |  | $ | 24.83 |  |  |  |  |  |  |  |  |
Outstanding at September 30, 2023 |  |  | 13,449,061 |  |  | $ | 11.95 |  |  |  | 6.6 |  |  | $ | 160,724 |
Vested at December 31, 2022 |  |  | 11,304,747 |  |  | $ | 12.02 |  |  |  | 7.9 |  |  | $ | 127,591 |
Exercisable at December 31, 2022 |  |  | 11,304,747 |  |  | $ | 12.02 |  |  |  | 7.9 |  |  | $ | 127,591 |
Vested at September 30, 2023 |  |  | 13,301,247 |  |  | $ | 11.87 |  |  |  | 6.6 |  |  | $ | 157,820 |
Exercisable at September 30, 2023 |  |  | 11,352,247 |  |  | $ | 12.10 |  |  |  | 7.2 |  |  | $ | 137,356 |

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 $5.4 million and $5.4 million was recognized during the nine months ended September 30, 2023 and 2022, respectively, and the remaining $7.8 million as of September 30, 2023 will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuance. The Board also cancelled the previously issued equity-based liability bonuses and 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 and cancelled certain contractual equity-based bonuses to such employees. Therefore, stock-based compensation expense of $5.3 million and $5.0 million was recognized during the nine months ended September 30, 2023 and 2022, respectively, and the remaining $7.6 million as of September 30, 2023 will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuance.

Stock issued to outside directors. 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 will vest at the next annual meeting, assuming the Board members maintain their positions on the Board. Therefore, stock-based compensation expense of $253,000 was recognized during the nine months ended September 30, 2023 and the remaining $505,000 will be recognized between October 2023 and June 2024, which was based upon the closing price of the stock on the date of the restricted stock issuance. In addition, a total of 21,184 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2022, which vested during the second quarter of 2022. Therefore, stock-based compensation expense of $305,000 and $244,000 was recognized during the nine months ended September 30, 2023 and 2022, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. Finally, a total of 67,779 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2021, which vested in January 2022. Therefore, the remaining stock-based compensation expense of $284,000 was recognized during the nine months ended September 30, 2022, which was based upon the closing price of the stock on the date of the restricted stock issuance.

NOTE 10. Commitments and Contingencies

Leases. The Company follows ASC Topic 842, “Leases” to account for its operating and finance leases. Therefore, as of September 30, 2023 the Company had right-of-use assets totaling $637,000 included in other noncurrent assets and operating lease liabilities totaling $653,000, $517,000 of which are included in other current liabilities and $136,000 of which are included in other noncurrent liabilities, and as of December 31, 2022 the Company had right-of-use assets totaling $333,000 included in other noncurrent assets and operating lease liabilities totaling $343,000, included in other current liabilities on the accompanying consolidated balance sheets. The Company does not currently have any finance right-of-use leases. Maturities of the operating lease obligations are as follows (in thousands):

|  | September 30, 2023 |
Remainder of 2023 |  | $ | 138 |
2024 |  |  | 552 |
Total lease payments |  |  | 690 |
Less present value discount |  |  | (37 | )
Present value of lease liabilities |  | $ | 653 |

22

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 May 2021, the Company entered into a 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 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 October 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to September 30, 2023, the Company has delivered approximately 28,008 Bopd under the contract which is approximately 61 percent of the contracted volume for the life of the contract. The monetary commitment for the remaining 13.3 MMBbl as of September 30, 2023, if the Company never delivers any additional volumes under the agreement, is approximately $10.9 million.

Natural gas purchasing replacement contract. In May 2021, the Company entered into a replacement natural gas purchase contract with WTG Gas Processing, L.P. (“WTG”) as the gatherer, processor and purchaser of the Company’s current and future gross natural gas production in Flat Top. The replacement contract provides the Company with improved natural gas and NGL pricing and required WTG to expand its current low-pressure gathering system, which eliminates the need for in-field compression in Flat Top to accommodate the Company’s increased natural gas production volumes based on the current plan of development. The Company provides WTG with certain aid-in-construction payments to be reimbursed over time based on throughput through the system. The replacement contract does not contain any minimum volume commitments.

Connection fee commitments. As a result of the Hannathon Acquisition, the Company assumed a connection fee commitment related to a natural gas contract on certain properties whereby a minimum volume must be delivered, or the Company is obligated to reimburse WTG any shortfall by May 2025. If the Company fails to deliver any future volumes to the delivery point, the monetary commitment that remains as of September 30, 2023 would be approximately $526,000.

Power contracts. In June 2022, the Company entered into a contract with TXU Energy Retail Company LLC (“TXU”) 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 conjunction with this contract, the Company issued a $1.7 million letter of Credit in lieu of a deposit to TXU 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 1.6 million tons of sand over a two-year period beginning July 1, 2022. There are stipulations in the agreement that reduce this commitment should there be a downturn in crude oil prices. As of September 30, 2023, the Company has purchased approximately 988,000 tons of sand under the contract. However, generally if the Company never takes delivery of any additional sand under the agreement, the monetary commitment that remains as of September 30, 2023 is approximately $14.5 million.

NOTE 11. Related Party Transactions

Underwritten Equity Offering. In connection with the Company’s underwritten equity offering in July 2023, certain of the Company’s existing stockholders, John Paul DeJoria Family Trust and Jack Hightower, the Company’s Chairman and Chief Executive Officer, and entities and individuals associated with them, purchased an aggregate of approximately 10 million shares of Common Stock in the offering at the public offering price per share. In connection therewith, the Underwriter received a reduced underwriting discount on such shares purchased by these person or entities compared with other shares sold to the public in the offering.

Water Treatment. In September 2021, the Company entered into a contract with Pilot Exploration, Inc., (“Pilot”), whose President and CEO was an outside director of the Company, to deploy Pilot’s proprietary water treatment technology in the Company’s Flat Top area to treat up to 25,000 barrels of produced water per day that can be reused in the Company’s completion operations or sold to third parties for their completion operations. This contract was set to expire on March 1, 2022; however, it was extended to October 1, 2022 based on the early results of the project. During the year ended December 31, 2022, the Company paid $2.0 million to Pilot for such services.

In May 2022, the Company entered into an agreement with Pilot to utilize Pilot’s proprietary water treatment technology in the Company’s Flat Top area to treat produced water such that it can be reused in the Company’s completion operations or sold to third parties for their completion operations. During the one-year term of the agreement, beginning on October 1, 2022, the Company agreed to a minimum volume commitment of 29.2 million barrels of produced water while maintaining the ability to bank excess produced water processed each month toward the minimum volume commitment. During the nine months ended September 30, 2023 and the year ended December 31, 2022, the Company paid $1.5 million and $1.6 million, respectively, to Pilot for such services. In April 2023, the Company terminated the contract with Pilot in exchange for $6.5 million that was charged to other expense in the accompanying consolidated financial statements during the nine months ended September 30, 2023.

23

NOTE 12. Major Customers

Delek accounted for approximately 73% and 88% during the nine months ended September 30, 2023 and 2022, respectively, and Energy Transfer Crude Marketing, LLC (“ETC”) accounted for approximately 23% and less than 10% of the Company’s revenues during the nine months ended September 30, 2023 and 2022, respectively. Based on the current demand for crude oil and natural gas and the availability of other purchasers, management believes the loss of either of these major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

NOTE 13. Income Taxes

Enactment of the Inflation Reduction Act of 2022. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, imposes a 15 percent corporate alternative minimum tax on corporations with book financial statement income in excess of $1.0 billion, effective for tax years beginning after December 31, 2022. The IRA 2022 also establishes a one percent excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases in excess of an annual limit of $1.0 million after December 31, 2022. The IRA 2022 did not impact the Company’s current year tax provision or the Company’s consolidated financial statements. The Company is evaluating the accounting and disclosure implications of the IRA 2022 on its future filings.

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

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |  |  | 2023 |  |  | 2022 |
Provision for current income taxes: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
State |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Total provision for current income taxes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Provision for deferred income taxes: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  |  | 13,347 |  |  |  | 30,599 |  |  |  | 36,388 |  |  |  | 53,726 |
State |  |  | 753 |  |  |  | 998 |  |  |  | 1,863 |  |  |  | 1,631 |
Total provision for deferred income taxes |  |  | 14,100 |  |  |  | 31,597 |  |  |  | 38,251 |  |  |  | 55,357 |
Total provision for income taxes |  | $ | 14,100 |  |  | $ | 31,597 |  |  | $ | 38,251 |  |  | $ | 55,357 |

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

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |  |  | 2023 |  |  | 2022 |
Provision for income taxes at U.S. federal statutory rate |  | $ | 11,105 |  |  | $ | 29,295 |  |  | $ | 33,414 |  |  | $ | 47,106 |
Limited tax benefit due to stock-based compensation |  |  | 2,211 |  |  |  | 592 |  |  |  | 2,951 |  |  |  | 6,128 |
State deferred income taxes |  |  | 753 |  |  |  | 999 |  |  |  | 1,863 |  |  |  | 1,723 |
Other, net |  |  | 31 |  |  |  | 711 |  |  |  | 23 |  |  |  | 400 |
Provision for income taxes |  | $ | 14,100 |  |  | $ | 31,597 |  |  | $ | 38,251 |  |  | $ | 55,357 |
Effective income tax rate |  |  | 26.7 | % |  |  | 22.7 | % |  |  | 24.0 | % |  |  | 24.7 | %

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities were as follows as of September 30, 2023 and December 31, 2022 (in thousands):

|  | September 30, 2023 |  |  | December 31, 2022 |
Deferred tax assets: |  |  |  |  |  |  |  |
Interest expense limitations |  | $ | 32,843 |  |  | $ | 10,623 |
Net operating loss carryforwards |  |  | 12,210 |  |  |  | 5,496 |
Stock-based compensation |  |  | 5,899 |  |  |  | 4,102 |
Unrecognized derivative losses |  |  | 5,882 |  |  |  | 3,756 |
Other |  |  | 22 |  |  |  | 32 |
Less: Valuation allowance |  |  | — |  |  |  | — |
Deferred tax assets |  |  | 56,856 |  |  |  | 24,009 |
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 |  |  | (226,270 | ) |  |  | (155,169 | )
Unrecognized derivative gains |  |  | — |  |  |  | (4 | )
Deferred tax liabilities |  |  | (226,270 | ) |  |  | (155,173 | )
Net deferred tax liabilities |  | $ | (169,414 | ) |  | $ | (131,164 | )

24

The effective income tax rate differs from the U.S. statutory rate of 21 percent primarily due to reversing a portion of its deferred tax asset related to stock-based compensation, 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 September 30, 2023 and December 31, 2022, 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 stock options are exercised and 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 $3.4 million reduction in the deferred tax asset and reduced the amount of income tax expense realized during the nine months ended September 30, 2022.

The Company is also subject to Texas Margin Tax. The Company realized no current Texas Margin Tax in the accompanying consolidated financial statements as we do not anticipate owing any Texas Margin Tax for 2023 or 2022. However, the Company has recognized a net deferred Texas Margin Tax liability of $6.0 million and $4.1 million as of September 30, 2023 and December 31, 2022, respectively, in the accompanying consolidated financial statements.

NOTE 14. 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 and nine months ended September 30, 2023 and 2022 under the two-class method (in thousands):

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |  |  | 2023 |  |  | 2022 |
Net income as reported |  | $ | 38,779 |  |  | $ | 107,904 |  |  | $ | 120,862 |  |  | $ | 168,955 |
Participating basic earnings (a) |  |  | (3,771 | ) |  |  | (10,282 | ) |  |  | (12,413 | ) |  |  | (16,718 | )
Basic earnings attributable to common stockholders |  |  | 35,008 |  |  |  | 97,622 |  |  |  | 108,449 |  |  |  | 152,237 |
Reallocation of participating earnings |  |  | 54 |  |  |  | 176 |  |  |  | 192 |  |  |  | 300 |
Diluted net income attributable to common stockholders |  | $ | 35,062 |  |  | $ | 97,798 |  |  | $ | 108,641 |  |  | $ | 152,537 |
Basic weighted average shares outstanding |  |  | 123,159 |  |  |  | 108,681 |  |  |  | 115,164 |  |  |  | 102,614 |
Dilutive warrants and unvested stock options |  |  | 1,688 |  |  |  | 4,315 |  |  |  | 3,208 |  |  |  | 4,408 |
Dilutive unvested restricted stock |  |  | 2,159 |  |  |  | 2,122 |  |  |  | 2,159 |  |  |  | 2,122 |
Diluted weighted average shares outstanding |  |  | 127,006 |  |  |  | 115,118 |  |  |  | 120,531 |  |  |  | 109,144 |

| (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.

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NOTE 15. Stockholders’ Equity

Issuance of common stock. On July 19, 2023, the Company closed an aggregate $155.8 million public stock offering of 14,835,000 newly issued shares of HighPeak Energy common stock in an underwritten public offering at a price per share of $10.50. The remaining 220,896 shares of HighPeak Energy common stock issued during the nine months ended September 30, 2023 were the result of warrants (150,295 shares) being exercised, the issuance of restricted stock (58,767 shares) to outside directors and stock options (11,834 shares) being exercised. On March 25, 2022, June 21, 2022 and June 27, 2022, respectively, the Company issued 6,960,000, 371,517 and 3,522,117 shares of HighPeak Energy common stock related to the aforementioned Alamo Acquisitions and Hannathon Acquisition. On June 1, 2022, the Company issued 21,184 and 600,000 shares of restricted stock to outside directors and certain employees, respectively. On September 2, 2022, the Company closed an aggregate $85.0 million private placement of 3,933,376 newly issued shares of HighPeak Energy common stock at a price per share of $21.61 as determined by the 5-day volume weighted average closing price per share for the five days immediately prior to (and excluding) August 22, 2022. The initial closings occurred on August 22, 2022, with the final closings on September 2, 2022. The remaining 980,488 shares of HighPeak Energy common stock issued during the nine months ended September 30, 2022 were the result of warrants (968,448 shares) and stock options (12,000 shares) being exercised.

Dividends and Dividend Equivalents. In July 2023, the Board declared a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $3.2 million in dividends being paid on August 25, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $333,000 in August 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting of up to an additional $4,000, assuming no forfeitures. In addition, the Company accrued an additional combined $54,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In April 2023, the Board declared a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.8 million in dividends being paid on May 25, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $282,000 in May 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting of up to an additional $5,000, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In January 2023, the Board declared a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.8 million in dividends being paid on February 24, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $283,000 in February 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting of up to an additional $5,000, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In July 2022, the board of directors of the Company declared a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.7 million in dividends being paid on August 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $263,000 in August 2022 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting of up to an additional $7,000, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

In April 2022, the Board approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.6 million in dividends being paid on May 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders and accrued a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total payment of $214,000 in May 2022 and up to an additional $2,000, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to management directors and certain employees that will be payable upon vesting.

In January 2022, the Board approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.4 million in dividends being paid on February 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders and accrued a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total payment of $214,000 in February 2022 and up to an additional $2,000, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in dividends on the restricted stock issued to management directors and certain employees that will be payable upon vesting.

Outstanding securities. At September 30, 2023 and December 31, 2022, the Company had 128,220,923 and 113,165,027 shares of common stock outstanding, respectively, and 8,134,977 and 8,285,272 warrants outstanding, respectively, with an exercise price of $11.50 per share that expire on August 21, 2025.

NOTE 16. Subsequent Events

Dividends and dividend equivalents. In October 2023, the Board approved a quarterly dividend of $0.025 per share of common stock outstanding which will result in a total of approximately $3.2 million in dividends to be paid on November 22, 2023. In addition, under the terms of the LTIP, the Company will pay a dividend equivalent per share to all vested stock option holders of $335,000 in November 2023 and will accrue a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional $2,000, assuming no forfeitures. In addition, the Company will accrue an additional combined $54,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Senior Credit Facility Agreement. On November 1, 2023, the Company entered into a Credit Agreement with Fifth Third as the administrative agent and as the collateral agent and a number of banks included in the syndicate at differing levels of commitments to establish a senior revolving credit facility that matures on September 30, 2026. See Note 7 above for more details.

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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. The Company’s assets are located primarily in Howard and Borden Counties, Texas, and to a lesser extent Scurry and Mitchell Counties, which lie within the northeastern part of the crude oil-rich Midland Basin. As of September 30, 2023, the assets consisted of two generally contiguous leasehold positions of approximately 126,988 gross (114,324 net) acres (consisting of 64,142 net acres in our Flat Top area to the north and 50,182 net acres in our Signal Peak area to the south) covering various subsurface depths, approximately 65% of which were held by production, with an average working interest of approximately 90%. We operate approximately 98% of the net acreage across the Company’s assets and more than 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the nine months ended September 30, 2023, approximately 93% and 7% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of September 30, 2023, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac fleet and expects to average two to three (2-3) drilling rigs and one to two (1-2) frac crews for the remainder of 2023.

Recent Events

Debt Refinancing. In September 2023, we completed a refinancing of our long-term debt in its entirety by entering into an agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $1.2 billion in borrowings, less a 2.5% original issue discount of $30.0 million at closing and customary debt issuance costs which totaled approximately $23.0 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.

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The Term Loan Credit Agreement contains customary mandatory prepayments, including quarterly installments of $30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments.

Simultaneously with the closing of the Term Loan Credit Agreement, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA as first-out representative.

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 Capitol 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.

Subsequent to quarter end, but included in part of the refinancing of the Companies overall long-term debt, the Company entered into a Senior Credit Facility Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has a borrowing capacity of $100.0 million with elected commitments of $75.0 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.

Public stock offering. In July 2023, we completed a public stock offering whereby we issued 14,835,000 shares of common stock at a price of $10.50, netting proceeds to the Company of approximately $151.2 million that was used for working capital and to otherwise enhance near-term liquidity.

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Dividends and dividend equivalents. In January, April and July 2023, the Board declared a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.8 million, $2.8 million and $3.2 million, respectively, in dividends being paid on February 24, 2023, May 25, 2023 and August 25, 2023, respectively. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $283,000 in February 2023, $282,000 in May 2023 and $333,000 in August 2023 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional $7,000 in February 2023, $5,000 in May 2023 and $4,000 in August 2023, respectively, assuming no forfeitures. In addition, the Company accrued an additional combined $53,000 in February 2023, $53,000 in May 2023 and $54,000 in August 2023 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting.

Acquisitions. During the nine months ended September 30, 2023, the Company incurred a total of $9.6 million in acquisition costs to acquire additional bolt-on undeveloped acreage contiguous to its Flat Top and Signal Peak operating areas.

Crude Oil and Natural Gas Industry Considerations. The COVID-19 pandemic resulted in a severe worldwide economic downturn, significantly disrupting the demand for crude oil throughout the world, and created significant volatility, uncertainty and turmoil in the crude oil and natural gas industry. The decrease in demand for crude oil, combined with excess supply of crude oil and related products, resulted in crude oil prices declining significantly beginning in late February 2020. Since mid-2020, crude oil prices have improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants that have continued to inhibit a full global demand recovery. In addition, worldwide crude oil inventories are, from a historical perspective, very low and concerns exist with the ability of OPEC and other crude oil producing nations to meet forecasted crude oil demand growth in 2023, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their lack of capital investments over the past few years in developing incremental crude oil supplies. Furthermore, 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. In April 2023, OPEC announced production cuts of around 1.16 million Bopd. On June 4, 2023, OPEC agreed to extend these previously announced production cuts through the end of 2024. On July 3, 2023, Saudi Arabia announced it was extending voluntary cuts through August 2023. However, as a result of current global supply and demand imbalances, crude oil and natural gas prices remain strong, although down from the prior quarter. In addition, the ongoing pandemic, combined with the conflict between Russia and Ukraine, has 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. Specifically, the Company’s 2023 capital program has been and continues to be impacted by higher inflation in steel, diesel, chemical prices 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, 2018 through September 30, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35.

The markets for the commodities produced by our industry strengthened in 2021 and remained strong in 2022 and continuing in 2023, although 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 in Russia and Ukraine and in Israel and the Gaza Strip, the COVID-19 pandemic, rising interest rates and associated policies of the Federal Reserve, which could adversely affect HighPeak Energy. Additionally, in April 2023, OPEC announced production cuts of around 1.16 million Bopd. On June 4, 2023, OPEC agreed to extend these previously announced production cuts through the end of 2024. On July 3, 2023, Saudi Arabia announced it was extending voluntary cuts through August 2023. The actions of OPEC with respect to crude oil production levels, including agreement on and compliance with production cuts, may result in further volatility in commodity prices and the crude oil and natural gas industry generally. Additionally, the impact of inflation as well as rising interest rates continue to have a negative impact on our cash flows and results of operations. 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, 2022, filed with the SEC on March 6, 2023 (the “Annual Report”).

Given the dynamic nature of this situation, the Company is maintaining flexibility in its capital plan as indicated by its recent shift to an anticipated two to three (2-3) drilling rig program for the remainder of the year. 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.

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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. Wells Fargo Securities, LLC 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 September 30, 2023 included the following highlights:

• | Net income was $38.8 million ($0.27 per diluted share) for the three months ended September 30, 2023 compared with $107.9 million for three months ended September 30, 2022. The primary components of the $69.1 million decrease in net income include:

| • | a $74.8 million increase in DD&A expense due to a 101% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program and to a lesser extent, bolt-on acquisitions, in addition to a 37% increase in the DD&A rate from $17.65 to $24.21 per Boe as a result of significant inflationary pressures on capital costs as well as bolt-on acquisitions;

| • | a $65.5 million decrease in the Company's net derivative instruments gain from a $35.8 million gain to a $29.7 million loss year over year as a result of its crude oil commodity contracts entered into and the increase in crude oil prices thereafter;
| • | a $27.3 million increase in loss on extinguishment of debt as a result of the Company refinancing its debt which resulted in the recognition of a loss thereon, which included $22.8 million of unamortized debt issuance costs and discounts and a make whole premium on the 10.625% Senior Notes of $4.5 million;

| • | a $22.4 million increase in interest expense due to the increase in the Company’s overall indebtedness and increased amortization of debt issuance costs and discounts;
| • | a $20.1 million increase in lease operating expenses related primarily to the increased well count and production from the Company’s successful horizontal drilling program, increased power and chemical costs, repair and maintenance costs and other inflationary pressures;

| • | a $8.3 million increase in production and ad valorem taxes, primarily attributable to the 101% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program partially offset by 17% lower production taxes on a dollar per Boe basis due to lower overall realized prices of 16%, excluding the effects of derivatives;

| • | a $5.1 million increase in the Company’s general and administrative expenses primarily attributable to accrued yearend bonuses, increased internal and external audit costs and legal expenses as a result of the growth of the Company;

| • | a $3.4 million increase in the Company's stock-based compensation expense as a result of more stock options being issued relative to the prior period; and
| • | a $1.4 million increase in exploration and abandonments expense primarily due to an increase in leasehold abandonments and plugging and abandonment expenses related to legacy vertical wells;

Partially offset by:

| • | a $141.5 million increase in crude oil, NGL and natural gas revenues due to a 101% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program, partially offset by a 16% decrease in average realized commodity prices per Boe, excluding the effects of derivatives;
| • | a $17.5 million decrease in the Company’s income tax expense due to the net income realized during the three months ended September 30, 2023 compared with the net income during the three months ended September 30, 2022; and
| • | a $729,000 increase in the Company’s interest income due to the increased cash on hand (interest-bearing) subsequent to the closing of the Term Loan Credit Agreement.

• | During the three months ended September 30, 2023, average daily sales volumes totaled 52,708 Boe/d, compared with 26,247 Boe/d during the same period in 2022, an increase of 101%, due to the Company’s successful horizontal drilling program, and to a lesser extent, bolt-on acquisitions.

• | Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, decreased during the three months ended September 30, 2023 to $82.87, compared with $94.21 for the same period in 2022. Weighted average NGL prices per Bbl decreased during the three months ended September 30, 2023 to $20.08, compared with $36.59 for the same period in 2022. Weighted average natural gas prices per Mcf decreased to $1.89 during the three months ended September 30, 2023, compared with $7.73 during the same period in 2022.

• | Cash provided by operating activities totaled $521.7 million for the three months ended September 30, 2023, compared with $302.8 million for the three months ended September 30, 2022.

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Derivative Financial Instruments

Derivative financial instrument exposure. As of September 30, 2023, the Company was a party to the following open derivative financial instruments.

|  |  |  |  |  |  |  |  |  |  |  | Swaps |  |  | Deferred Premium Collars & Deferred Premium Puts |
Settlement Month |  | Settlement Year |  | Type of Contract |  | Bbls Per Day |  |  | Index |  | Price |  |  | Floor or Strike Price |  |  | Ceiling Price |  |  | Deferred Premium Payable |
Crude Oil: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oct - Dec |  | 2023 |  | Swap |  |  | 11,300 |  |  | WTI |  | $ | 77.84 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Oct - Dec |  | 2023 |  | Collar |  |  | 5,000 |  |  | WTI |  | $ | — |  |  | $ | 75.50 |  |  | $ | 100.00 |  |  | $ | 0.35 |
Oct - Dec |  | 2023 |  | Put |  |  | 19,000 |  |  | WTI |  | $ | — |  |  | $ | 69.46 |  |  | $ | — |  |  | $ | 5.00 |
Jan - Mar |  | 2024 |  | Swap |  |  | 4,000 |  |  | WTI |  | $ | 84.00 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jan - Mar |  | 2024 |  | Collar |  |  | 6,000 |  |  | WTI |  | $ | — |  |  | $ | 80.00 |  |  | $ | 100.00 |  |  | $ | 3.50 |
Jan - Mar |  | 2024 |  | Put |  |  | 20,000 |  |  | WTI |  | $ | — |  |  | $ | 66.44 |  |  | $ | — |  |  | $ | 5.00 |
Apr - Jun |  | 2024 |  | Swap |  |  | 4,000 |  |  | WTI |  | $ | 84.00 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Apr - Jun |  | 2024 |  | Collar |  |  | 5,500 |  |  | WTI |  | $ | — |  |  | $ | 69.73 |  |  | $ | 95.00 |  |  | $ | 0.61 |
Apr - Jun |  | 2024 |  | Put |  |  | 14,000 |  |  | WTI |  | $ | — |  |  | $ | 60.41 |  |  | $ | — |  |  | $ | 5.00 |
Jul - Sep |  | 2024 |  | Swap |  |  | 4,000 |  |  | WTI |  | $ | 84.00 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jul - Sep |  | 2024 |  | Collar |  |  | 1,500 |  |  | WTI |  | $ | — |  |  | $ | 69.00 |  |  | $ | 95.00 |  |  | $ | 0.85 |
Jul - Sep |  | 2024 |  | Put |  |  | 14,000 |  |  | WTI |  | $ | — |  |  | $ | 60.41 |  |  | $ | — |  |  | $ | 5.00 |
Oct - Dec |  | 2024 |  | Swap |  |  | 5,500 |  |  | WTI |  | $ | 76.37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Oct - Dec |  | 2024 |  | Collar |  |  | 10,600 |  |  | WTI |  | $ | — |  |  | $ | 65.68 |  |  | $ | 90.32 |  |  | $ | 1.85 |
Oct - Dec |  | 2024 |  | Put |  |  | 2,000 |  |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |
Jan - Mar |  | 2025 |  | Swap |  |  | 5,500 |  |  | WTI |  | $ | 76.37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jan - Mar |  | 2025 |  | Collar |  |  | 8,000 |  |  | WTI |  | $ | — |  |  | $ | 65.00 |  |  | $ | 90.00 |  |  | $ | 2.12 |
Jan - Mar |  | 2025 |  | Put |  |  | 2,000 |  |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |
Apr - Jun |  | 2025 |  | Swap |  |  | 5,500 |  |  | WTI |  | $ | 76.37 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Apr - Jun |  | 2025 |  | Collar |  |  | 7,000 |  |  | WTI |  | $ | — |  |  | $ | 65.00 |  |  | $ | 90.08 |  |  | $ | 2.28 |
Apr - Jun |  | 2025 |  | Put |  |  | 2,000 |  |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |
Jul - Sep |  | 2025 |  | Swap |  |  | 3,000 |  |  | WTI |  | $ | 75.85 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Jul - Sep |  | 2025 |  | Collar |  |  | 7,000 |  |  | WTI |  | $ | — |  |  | $ | 65.00 |  |  | $ | 90.08 |  |  | $ | 2.28 |
Jul - Sep |  | 2025 |  | Put |  |  | 2,000 |  |  | WTI |  | $ | — |  |  | $ | 58.00 |  |  | $ | — |  |  | $ | 5.00 |

The estimated fair value of the outstanding open derivative financial instruments as of September 30, 2023 was a net liability of $27.2 million which is included in current assets, noncurrent assets, current liabilities and noncurrent liabilities on the Company’s consolidated balance sheet as of September 30, 2023. During the nine months ended September 30, 2023, the Company recognized a net derivative loss of $30.9 million, including $21.0 million in net monthly settlement payments and a $9.9 million mark-to-market loss.

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Operations and Drilling Highlights

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

|  | Nine Months Ended September 30, 2023 |
Crude Oil (Bbls) |  |  | 37,171 |
NGL (Bbls) |  |  | 3,895 |
Natural Gas (Mcf) |  |  | 18,221 |
Total (Boe) |  |  | 44,102 |

The Company’s liquids production was 93 percent of total production on a Boe basis for the nine months ended September 30, 2023.

Costs incurred are as follows (in thousands):

|  | Nine Months Ended September 30, 2023 |
Unproved property acquisition costs |  | $ | 9,602 |
Proved acquisition costs |  |  | — |
Total acquisitions |  |  | 9,602 |
Development costs |  |  | 423,812 |
Exploration costs |  |  | 416,159 |
Total finding and development costs |  |  | 849,573 |
Asset retirement obligations |  |  | 854 |
Total costs incurred |  | $ | 850,427 |

The following table sets forth the total number of horizontal producing wells drilled and completed during the nine months ended September 30, 2023:

|  | Drilled |  |  | Completed |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |
Flat Top area |  |  | 48 |  |  |  | 47.6 |  |  |  | 72 |  |  |  | 64.2 |
Signal Peak area |  |  | 20 |  |  |  | 14.5 |  |  |  | 25 |  |  |  | 24.7 |
Total |  |  | 68 |  |  |  | 62.1 |  |  |  | 97 |  |  |  | 88.9 |

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As of September 30, 2023, HighPeak Energy was developing its properties using two (2) drilling rigs and one (1) frac crew in addition to having a third rig drilling salt-water disposal wells. With the continued threat of an extensive recession and uncertainty of the debt refinancing, the Company released a frac crew in the first week of July and now expects to average two to three (2-3) drilling rigs and one to two (1-2) frac crews for the remainder of 2023. However, the scope, duration and magnitude of the direct and indirect effects of the COVID-19 pandemic, 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 in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

During the nine months ended September 30, 2023, the Company successfully completed and placed on production seventy-two (72) gross (64.2 net) horizontal wells in the Flat Top area and twenty-five (25) gross (24.7 net) horizontal wells in the Signal Peak area. The Company had twenty-five (25) gross (18.6 net) wells that had been drilled and were in various stages of completion as of September 30, 2023, seventeen (17) gross (16.0 net) of which are in the Flat Top area, and eight (8) gross (2.7 net) of which are in the Signal Peak area. In addition, as of September 30, 2023, the Company was in the process of drilling two (2) gross (2.0 net) horizontal wells in the Flat Top area and five (5) gross (5.0 net) horizontal wells in the Signal Peak area. In addition to the aforementioned numbers are two (2) gross (2.0 net) salt-water disposal wells that have been finished and placed in service during the nine months ended September 30, 2023 and an additional four (4) gross (4.0 net) salt-water disposal wells that were in progress as of September 30, 2023.

Results of Operations

Three and Nine Months Ended September 30, 2023

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Crude Oil (Bbls) |  |  | 44,381 |  |  |  | 21,857 |  |  |  | 103 | % |  |  | 37,171 |  |  |  | 16,964 |  |  |  | 119 | %
NGL (Bbls) |  |  | 4,708 |  |  |  | 2,530 |  |  |  | 86 | % |  |  | 3,895 |  |  |  | 1,894 |  |  |  | 106 | %
Natural Gas (Mcf) |  |  | 21,716 |  |  |  | 11,162 |  |  |  | 95 | % |  |  | 18,221 |  |  |  | 7,755 |  |  |  | 135 | %
Total (Boe) |  |  | 52,708 |  |  |  | 26,247 |  |  |  | 101 | % |  |  | 44,102 |  |  |  | 20,150 |  |  |  | 119 | %

The increase in average daily Boe sales volumes for the three and nine months ended September 30, 2023, compared with the same periods in 2022 was primarily due to the Company’s successful horizontal drilling program. However, increases in production were partially offset due to unexpected temporary reduced third-party gas takeaway at Flat Top that began in early fourth quarter 2022 and continues today to a lesser extent. The fourth quarter of 2023 is expected to continue to be impacted by this curtailment at Flat Top, and a natural gas plant that gathers and processes a portion of the natural gas at Signal Peak will be down for six to eight weeks for repairs and maintenance.

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

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Crude Oil per Bbl |  | $ | 82.87 |  |  | $ | 94.21 |  |  |  | (12 | )% |  | $ | 77.90 |  |  | $ | 100.91 |  |  |  | (23 | )%
NGL per Bbl |  | $ | 20.08 |  |  | $ | 36.59 |  |  |  | (45 | )% |  | $ | 22.23 |  |  | $ | 41.23 |  |  |  | (46 | )%
Natural Gas per Mcf |  | $ | 1.89 |  |  | $ | 7.73 |  |  |  | (76 | )% |  | $ | 1.58 |  |  | $ | 6.47 |  |  |  | (76 | )%
Total per Boe |  | $ | 71.27 |  |  | $ | 84.53 |  |  |  | (16 | )% |  | $ | 67.29 |  |  | $ | 90.49 |  |  |  | (26 | )%

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Crude Oil and natural gas production costs.

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

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Crude oil and natural gas production costs |  | $ | 39,820 |  |  | $ | 19,707 |  |  |  | 102 | % |  | $ | 107,696 |  |  | $ | 45,748 |  |  |  | 135 | %
Crude oil and natural gas production costs per Boe (excluding expense workovers) |  | $ | 7.87 |  |  | $ | 7.23 |  |  |  | 9 | % |  | $ | 8.23 |  |  | $ | 7.88 |  |  |  | 4 | %
Workover expense |  | $ | 0.34 |  |  | $ | 0.93 |  |  |  | (63 | )% |  | $ | 0.71 |  |  | $ | 0.43 |  |  |  | 65 | %

The increase in crude oil and natural gas production costs can primarily be attributed to the Company’s successful horizontal drilling program adding a significant number of newly completed producing wells, increased chemical and treating costs, increased repair and maintenance expense with the addition of a significant number of legacy vertical wells in the Hannathon Acquisition in 2022 and expense workover costs. The change in crude oil and natural gas production costs per Boe were minimal during the three and nine months ended September 30, 2023 compared with the same periods in 2022. Our crude oil production in the first half of 2023 was negatively impacted by (i) a weather event that disrupted a considerable amount of production for a short time, (ii) a fire that shut-in a considerable amount of production for a short time and (iii) temporarily shutting in a considerable amount of production periodically for offset completion operations. The issues described in (i) and (ii) have been resolved and do not continue to impact our crude oil production. In addition, a significant portion of natural gas production in our Flat Top operating area was negatively impacted due to the inability of a new natural gas plant to take all of our volumes since coming online in December 2022. This issue improved during the second and third quarters of 2023 but is still not completely resolved. It is expected to be fully resolved during the fourth quarter of 2023 as the natural gas gatherer continues to optimize their gathering system. These production issues not only curtailed Boe production during the nine months ended September 30, 2023, but they also all increased the costs to the Company. The increase in workover expenses can be attributed to more well work being performed, most significantly, the replacement of tubing strings on two of the Company’s salt-water disposal wells, pump downsizes, and other well work that is being performed to reestablish production on legacy vertical wells that have gone down for various reasons. We anticipate the operating costs per Boe and workover expenses per Boe to continue to decrease in the fourth quarter of 2023. Significant drivers to this decrease are associated with (i) reduced chemical and treating costs by connecting wells in the southeast portion of Flat Top to a new third party facility during the fourth quarter of 2023, (ii) increasing the operational capacity of the natural gas plant taking our Flat Top natural gas production which should increase our NGL and natural gas sales going forward, (iii) returning production back on line that was off line during the three and nine months ended September 30, 2023 related to offset frac operations, weather and fire events that shut-in production for a temporary period of time and related costs, and (iv) reduced workover expense.

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Production and ad valorem taxes.

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

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Production and ad valorem taxes |  | $ | 18,839 |  |  | $ | 10,526 |  |  |  | 79 | % |  | $ | 44,395 |  |  | $ | 25,833 |  |  |  | 72 | %

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.

Production and ad valorem taxes per Boe are as follows:

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Production taxes per Boe |  | $ | 3.38 |  |  | $ | 4.08 |  |  |  | (17 | )% |  | $ | 3.21 |  |  | $ | 4.35 |  |  |  | (26 | )%
Ad valorem taxes per Boe |  | $ | 0.51 |  |  | $ | 0.28 |  |  |  | 82 | % |  | $ | 0.48 |  |  | $ | 0.35 |  |  |  | 37 | %

The decrease in production taxes per Boe for the three and nine months ended September 30, 2023, compared with the same periods in 2022, was primarily due to the 16% and 26% decrease in realized prices, respectively.

Exploration and abandonments expense.

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

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Abandoned leasehold costs |  | $ | 1,137 |  |  | $ | — |  |  | n/m |  |  | $ | 3,068 |  |  | $ | (1 | ) |  | n/m |
Geologic and geophysical personnel costs |  |  | 204 |  |  |  | 188 |  |  |  | 9 | % |  |  | 625 |  |  |  | 549 |  |  |  | 14 | %
Plugging and abandonment expense |  |  | 387 |  |  |  | — |  |  | n/m |  |  |  | 612 |  |  |  | (2 | ) |  | n/m |
Geologic and geophysical data costs |  |  | — |  |  |  | 102 |  |  | n/m |  |  |  | 67 |  |  |  | 137 |  |  |  | (51 | )%
Exploration and abandonments expense |  | $ | 1,728 |  |  | $ | 290 |  |  |  | 496 | % |  | $ | 4,372 |  |  | $ | 683 |  |  |  | 540 | %

Exploration and abandonment costs increased during the three and nine months ended September 30, 2023 primarily due to $1.1 million and $3.1 million in abandoned leasehold costs related to undeveloped acreage that was not in an area where the Company had current plans to drill and thus the leases were allowed to expire and higher plugging and abandonment costs related to increased activity centered around legacy vertical wells. The Company remains committed to maintaining as much of its undeveloped acreage leasehold position as possible, but from time to time, certain acreage is not able to be extended at reasonable prices and we are not able to get a drilling rig in the area to drill in time to save the leases for a multitude of reasons.

DD&A expense.

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

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
DD&A expense |  | $ | 117,420 |  |  | $ | 42,624 |  |  |  | 175 | % |  | $ | 291,562 |  |  | $ | 94,531 |  |  |  | 208 | %
DD&A expense per Boe |  | $ | 24.21 |  |  | $ | 17.65 |  |  |  | 37 | % |  | $ | 24.22 |  |  | $ | 17.18 |  |  |  | 41 | %

The increase in DD&A is primarily due to the increased production associated with our successful horizontal drilling program and the increase in rate can be attributed to significant inflationary pressures on capital costs over the past year or so as well as bolt-on acquisitions.

General and administrative expense.

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

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
General and administrative expense |  | $ | 6,934 |  |  | $ | 1,877 |  |  |  | 269 | % |  | $ | 11,952 |  |  | $ | 5,833 |  |  |  | 105 | %
General and administrative expense per Boe |  | $ | 1.43 |  |  | $ | 0.78 |  |  |  | 83 | % |  | $ | 0.99 |  |  | $ | 1.06 |  |  |  | (7 | )%
Stock-based compensation expense |  | $ | 14,057 |  |  | $ | 10,655 |  |  |  | 32 | % |  | $ | 22,095 |  |  | $ | 29,210 |  |  |  | (24 | )%

The increase in general and administrative expense for the three and nine months ended September 30, 2023 is primarily as a result of accrued bonuses in 2023 which were not recognized until the fourth quarter in 2022, adding new employees and increased salaries and benefits related to the growth of the Company in addition to higher professional services costs related to the growth of the Company. The decrease in the rate per Boe for the nine months ended September 2023 compared to the same period in 2022 is the result of economies of scale and efficiencies gained as we bring additional wells on production due to our successful horizontal drilling program.

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Interest expense.

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Prior Credit Agreement |  | $ | 11,421 |  |  | $ | 5,635 |  |  |  | 103 | % |  | $ | 30,492 |  |  | $ | 7,272 |  |  |  | 319 | %
Term Loan Credit Agreement |  |  | 7,835 |  |  |  | — |  |  |  | 100 | % |  |  | 7,835 |  |  |  | — |  |  |  | 100 | %
10.625% Senior Notes |  |  | 5,460 |  |  |  | — |  |  |  | 100 | % |  |  | 18,734 |  |  |  | — |  |  |  | 100 | %
10.000% Senior Notes |  |  | 4,625 |  |  |  | 5,625 |  |  |  | (18 | )% |  |  | 15,875 |  |  |  | 14,000 |  |  |  | 13 | %
Additional interest on 10.625% Senior Notes |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 8,330 |  |  |  | — |  |  |  | 100 | %
Amortization of discount |  |  | 4,033 |  |  |  | 1,868 |  |  |  | 116 | % |  |  | 12,660 |  |  |  | 4,609 |  |  |  | 175 | %
Amortization of debt issuance costs |  |  | 3,648 |  |  |  | 1,480 |  |  |  | 146 | % |  |  | 9,352 |  |  |  | 3,261 |  |  |  | 187 | %
|  | $ | 37,022 |  |  | $ | 14,608 |  |  |  | 153 | % |  | $ | 103,278 |  |  | $ | 29,142 |  |  |  | 254 | %

The increase in interest expense can be attributed to the fact that we have continued to increase our borrowings under our Prior Credit Agreement, and we issued $225.0 million of 10.000% Senior Notes in February 2022 and $225.0 million and $25.0 million of 10.625% Senior Notes in November and December 2022, respectively, and additional interest of $8.3 million on the 10.625% Senior Notes in June 2023 related to not achieving an increased rating and increased amortization of discounts and debt issuance costs related to these new issuances. In addition, the Company issued $1.2 billion under the Term Loan Credit Agreement in mid-September 2023 and paid off the Prior Credit Agreement, 10.000% Senior Notes and 10.625% Senior Notes.

Gain (loss) on derivative instruments, net.

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Noncash gain (loss) on derivative instruments, net |  | $ | (15,883 | ) |  | $ | 38,098 |  |  |  | (141 | )% |  | $ | (9,866 | ) |  | $ | 21,656 |  |  |  | (146 | )%
Cash paid on settlements of derivative instruments, net |  |  | (13,772 | ) |  |  | (2,300 | ) |  |  | (499 | )% |  |  | (21,032 | ) |  |  | (64,143 | ) |  |  | 67 | %
Gain (loss) on derivative instruments, net |  | $ | (29,655 | ) |  | $ | 35,798 |  |  |  | (183 | )% |  | $ | (30,898 | ) |  | $ | (42,487 | ) |  |  | 27 | %

The Company primarily utilizes commodity swap contracts and 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, and previously the Prior Credit Agreement and the indentures governing the Company’s 10.000% Senior Notes and 10.625% Senior Notes required, 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 and the newly entered into deferred premium collars and deferred premium put option contracts.

Other expense.

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Water treatment contract buyout |  | $ | — |  |  | $ | — |  |  | n/m |  |  | $ | 6,516 |  |  | $ | — |  |  |  | 100 | %
Other |  |  | 540 |  |  |  | — |  |  |  | 100 | % |  |  | 1,526 |  |  |  | — |  |  |  | 100 | %
|  | $ | 540 |  |  | $ | — |  |  |  | 100 | % |  | $ | 8,042 |  |  | $ | — |  |  |  | 100 | %

The Company paid $6.5 million during the second quarter of 2023 to buyout and terminate a water treatment contract with a former outside board member. Other costs of $1.5 million relate primarily to repairs on production facilities that were damaged in a fire that shut in a significant amount of production for a short time.

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Provision for income taxes.

|  | Three Months Ended September 30, |  |  |  |  |  |  | Nine Months Ended September 30, |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | % Change |  |  | 2023 |  |  | 2022 |  |  | % Change |
Provision for income taxes |  | $ | 14,100 |  |  | $ | 31,597 |  |  |  | (55 | )% |  | $ | 38,251 |  |  | $ | 55,357 |  |  |  | (31 | )%
Effective income tax rate |  |  | 26.7 | % |  |  | 22.7 | % |  |  | 18 | % |  |  | 24.0 | % |  |  | 24.7 | % |  |  | (3 | )%

The change in provision for income taxes during the three and nine months ended September 30, 2023, compared with the same periods in 2022, was due to the Company realizing decreased net income during the three and nine months ended September 30, 2023 compared to the same periods in 2022. The effective income tax rate differs from the statutory rate primarily due to a revision in the deferred tax asset related to certain stock-based compensation and permanent differences between GAAP income and taxable income during the nine months ended September 30, 2022. See Note 13 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 which include the remaining net proceeds of the Term Loan financing, (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) near-term debt maturities, including quarterly mandatory payments under our Term Loan Credit Agreement beginning March 31, 2024, (iii) payments of other contractual obligations, (iv) acquisitions of crude oil and natural gas properties and (v) working capital obligations. Funding for these cash needs may be provided by any combination of the Company’s sources of liquidity.

2023 capital budget. In March 2023, the Company determined to reduce its previously reported capital budget for 2023 in connection with its transition from a six-rig drilling program to a two-rig drilling program. The Company anticipates moving to a three-rig program in the fourth quarter of 2023. The Company currently expects total capital expenditures for 2023 to be in the range of approximately $900.0 to $975.0 million for drilling, completion, facilities and equipping crude oil wells plus $50 to $60 million for field infrastructure buildout and other costs. The 2023 reduced capital budget excludes acquisitions, asset retirement obligations, geological and geophysical general and administrative expenses and corporate facilities. HighPeak Energy expects to fund its forecasted capital expenditures with cash generated by operations and cash on its consolidated balance sheet which includes the remaining net proceeds of the Term Loan financing. The Company’s capital expenditures for the nine months ended September 30, 2023 were $840.0 million, excluding acquisitions.

37

However, there are many factors and consequences beyond the Company’s control impacting our capital budget, such as policies of the Biden Administration, economic downturn or potential recession, a potential government shut-down, geo-political risks and additional actions by businesses, OPEC and other cooperating countries, and governments in response to the COVID-19 pandemic, that may have an impact on the Company’s future results and drilling plans. For additional information on the risks, see “Part I, Item 1A. Risk Factors” in the Company’s Annual Report. The Company is maintaining flexibility in its capital plan and will continue to evaluate drilling and completion activity on an economic basis, with future activity levels assessed monthly.

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

|  | Nine Months Ended September 30, |  |  |  |  |  |  |  |  |
|  | 2023 |  |  | 2022 |  |  | Change |  |  | % Change |
Net cash provided by operating activities |  | $ | 521,742 |  |  | $ | 302,806 |  |  | $ | 218,936 |  |  |  | 72 | %
Net cash used in investing activities |  | $ | (937,245 | ) |  | $ | (843,351 | ) |  | $ | (93,894 | ) |  |  | (11 | )%
Net cash provided by financing activities |  | $ | 536,806 |  |  | $ | 540,024 |  |  | $ | (3,218 | ) |  |  | (1 | )%

Operating activities. The increase in net cash flow provided by operating activities for the nine months ended September 30, 2023, compared with 2022, was primarily related to higher revenues associated with increased production volumes as a result of our successful horizontal drilling program.

Investing activities. The increase in net cash used in investing activities for the nine months ended September 30, 2023, compared with 2022, was primarily due to increases in additions to crude oil and natural gas properties compared with the nine months ended September 30, 2022, when the Company had more drilling rigs and frac crews running compared with the prior year period, partially offset by a significant decrease in cash crude oil and natural gas property acquisition costs.

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

| • | Nine months ended September 30, 2023: The Company borrowed $1.17 billion on the Term Loan Credit Agreement, net of a $30.0 million original issue discount, and $255.0 million on the Prior Credit Agreement, received $155.8 million from a public offering of 14,835,000 shares of common stock and $1.7 million and $148,000 in proceeds from the exercise of warrants and stock options, respectively, partially offset by the repayment of the Prior Credit Agreement, 10.625% Senior Notes and 10.000% Senior Notes of $525.0 million, $250.0 million and $225.0 million, respectively, payment of a make whole premium on the 10.625% Senior Notes of $4.5 million, payment of debt issuance costs and stock issuance costs totaling $26.4 million and $5.4 million, respectively, and the payment of dividends and dividend equivalents of $8.7 million and $903,000, respectively.

| • | Nine months ended September 30, 2022: The Company received $210.2 million in net proceeds from the issuance of the 10.000% Senior Notes, borrowed a net $255.0 million on the Prior Credit Agreement and received $85.0 million in proceeds from a private placement of HighPeak Energy common stock, $7.8 million from the exercise of warrants and $120,000 from the exercise of stock options. These cash inflows were partially offset by the Company incurring $9.2 million of debt issuance costs primarily related to the 10.000% Senior Notes, $8.5 million in dividends and dividend equivalent payments and $290,000 in stock issuance costs related to the aforementioned private placement.

Interest Rate Risk. We are exposed to market risk due to the floating interest rate associated with any outstanding balance on the Term Loan Credit Agreement. As of September 30, 2023, we had a $1.2 billion outstanding balance on the Term Loan Credit Agreement. Our Term Loan Credit Agreement fixes the interest rate for all of the principal balance of the Term Loan Credit Agreement at the beginning of each quarter for a period three months. To the extent that the interest rate on our long-term debt is fixed, interest rate changes will affect the fair value but will not impact results of operations or cash flows. However, for the Term Loan Credit 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. However, future case surges, outbreaks, COVID-19 virus variants, the potential that current vaccines may be less effective or ineffective against future COVID-19 virus variants, and the risk that large groups of the population may not receive vaccinations against COVID-19, could have further negative impacts on prices. Additionally, commodity prices are subject to heightened levels of uncertainty related to geopolitical issues such as the ongoing armed conflicts between Russia and Ukraine and between Israel and Hamas, and recent production cut announcements from OPEC. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Based on our sales volumes during the nine months ended September 30, 2023 and excluding the effects on derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2023 would have increased (decreased) the Company’s revenues by approximately $13.9 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2023 would have increased (decreased) the Company’s revenues by approximately $663,000 on an annualized basis.

We enter into commodity derivative contracts to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of September 30, 2023, 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 $3.9 million.

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

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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. 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).” 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. The Term Loan Credit Agreement and Senior Credit Facility Agreement provides 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 debt, as defined in the Term Loan Credit Agreement and Senior Credit Facility Agreement, to EBITDAX, we would be in default, an event that would accelerate repayments under the Term Loan Credit Agreement and prevent us from borrowing under the Senior Credit Facility Agreement and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under the Term Loan Credit Agreement and the Senior Credit Facility Agreement and are unable to obtain a waiver of that default from our lenders, lenders under those agreements would be entitled to exercise all of their remedies for default.

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

|  | Three Months Ended September 30, |  |  | Nine Months Ended September 30, |
|  | 2023 |  |  | 2022 |  |  | 2023 |  |  | 2022 |
Net income |  | $ | 38,779 |  |  | $ | 107,904 |  |  | $ | 120,862 |  |  | $ | 168,955 |
Interest expense |  |  | 37,022 |  |  |  | 14,608 |  |  |  | 103,278 |  |  |  | 29,142 |
Interest and other income |  |  | (730 | ) |  |  | (1 | ) |  |  | (923 | ) |  |  | (253 | )
Income tax expense |  |  | 14,100 |  |  |  | 31,597 |  |  |  | 38,251 |  |  |  | 55,357 |
Depletion, depreciation and amortization |  |  | 117,420 |  |  |  | 42,624 |  |  |  | 291,562 |  |  |  | 94,531 |
Accretion of discount |  |  | 122 |  |  |  | 125 |  |  |  | 360 |  |  |  | 245 |
Exploration and abandonment expense |  |  | 1,728 |  |  |  | 290 |  |  |  | 4,372 |  |  |  | 683 |
Stock based compensation |  |  | 14,057 |  |  |  | 10,655 |  |  |  | 22,095 |  |  |  | 29,210 |
Derivative related noncash activity |  |  | 15,883 |  |  |  | (38,098 | ) |  |  | 9,866 |  |  |  | (21,656 | )
Loss on extinguishment of debt |  |  | 27,300 |  |  |  | — |  |  |  | 27,300 |  |  |  | — |
Other expense |  |  | 540 |  |  |  | — |  |  |  | 8,042 |  |  |  | — |
EBITDAX |  | $ | 266,221 |  |  | $ | 169,704 |  |  | $ | 625,065 |  |  | $ | 356,214 |

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 September 30, 2023. 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)."

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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, 2018 through September 30, 2023, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 to a high of $114.34, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $9.35. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the nine months ended September 30, 2021 would have increased (decreased) the Company’s revenues by approximately $13.6 million on an annualized basis, excluding the effects of derivatives, and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the nine months ended September 30, 2023 would have increased (decreased) the Company’s revenues by approximately $663,000 on an annualized basis, excluding the effects of derivatives.

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

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

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

The average forward prices based on September 30, 2023 market quotes were as follows:

|  | Remainder of 2023 |  |  | Year Ending December 31, 2024 |
Average forward NYMEX crude oil price per Bbl |  | $ | 86.33 |  |  | $ | 80.35 |
Average forward NYMEX natural gas price per MMBtu |  | $ | 3.12 |  |  | $ | 3.38 |

The average forward prices based on November 2, 2023 market quotes were as follows:

|  | Remainder of 2023 |  |  | Year Ending December 31, 2024 |
Average forward NYMEX crude oil price per Bbl |  | $ | 81.98 |  |  | $ | 78.96 |
Average forward NYMEX natural gas price per MMBtu |  | $ | 3.47 |  |  | $ | 3.59 |

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

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

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

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

Interest Rate Risk. As of September 30, 2023, we had $1.2 billion outstanding under the Term Loan Credit Agreement and no available borrowing capacity. The Company is subject to interest rate risk on its variable rate debt from our Term Loan Credit Agreement. The impact of a 1% increase in interest rates on our outstanding debt as of September 30, 2023 would have resulted in an annual increase in interest expense of approximately $12.0 million.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, HighPeak Energy has evaluated, under the supervision and with the participation of the Company’s management, including HighPeak Energy’s principal executive officer and principal financial officer, the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the fiscal period covered by this Quarterly Report. Based on that evaluation, HighPeak Energy’s principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective, as of the end of the period covered by this Quarterly Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2023 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 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, except as described below.

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Restrictions in our Term Loan Credit Agreement, our Senior Credit Facility Agreement and any future debt agreements could limit our growth and ability to engage in certain activities.

The terms and conditions governing our Term Loan Credit Agreement, our Senior Credit Facility Agreement and any future additional indebtedness are expected to:

| ● | require us to dedicate a portion of cash flow from operations to service our debt, thereby reducing the cash available to finance operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

| ● | increase vulnerability to economic downturns and adverse developments in our business;

| ● | place restrictions on our ability to engage in certain business activities, including without limitation, to raise capital, obtain additional financing (whether for working capital, capital expenditures or acquisitions) or to refinance indebtedness, grant or incur liens on assets, pay dividends or make distributions in respect of our capital stock, make investments, amend or repay subordinated indebtedness, sell or otherwise dispose of assets, businesses or operations and engage in business combinations or other fundamental changes;

| ● | potentially place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

| ● | limit management’s discretion in operating our business.

Our ability to meet our expenses and debt obligations and comply with the covenants and restrictions contained therein will depend on our future performance, which will be affected by financial, business, economic, industry, regulatory and other factors, many of which are beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. We cannot be certain that our cash flow will be sufficient to enable us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, or at all. For example, our future debt agreements may require the satisfaction of certain conditions, including coverage and leverage ratios, to borrow money. Our future debt agreements may also restrict the payment of dividends and distributions by certain of our subsidiaries to it, which could affect our access to cash. In addition, our ability to comply with the financial and other restrictive covenants in the agreements governing our indebtedness will be affected by the levels of cash flow from operations and future events and circumstances beyond our control. Breach of these covenants or restrictions will result in a default under our financing arrangements, which if not cured or waived, would permit the lenders to accelerate all indebtedness outstanding thereunder. Upon acceleration, the debt would become immediately due and payable, together with accrued and unpaid interest, and any lenders’ commitment to make further loans to us may terminate. Even if new financing were then available, it may not be on terms that are acceptable to us. Additionally, upon the occurrence of an event of default under our financing agreements, the affected lenders may exercise remedies, including through foreclosure, on the collateral securing any such secured financing arrangements. Moreover, any subsequent replacement of our financing arrangements may require us to comply with more restrictive covenants which could further restrict business operations.

Our existing and future indebtedness may adversely affect our cash flows and ability to operate our business, remain in compliance and repay our debt.

As of September 30, 2023, we have $1.2 billion of total indebtedness outstanding under our Term Loan Credit Agreement, which contains restrictive covenants and other provisions with which we must comply on an ongoing basis.

We may be unable to repay amounts due when they become due, and our ability to refinance our indebtedness on reasonable terms may be limited. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to several significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial, and some of which may be secured by our assets. Our current level of indebtedness could have important consequences, such as:

| ● | making it difficult for us to satisfy our obligations under our indebtedness and contractual and commercial commitments;

| ● | increasing our vulnerability to adverse economic and industry conditions;

| ● | requiring us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, or otherwise reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;

| ● | limiting our flexibility to plan for, or react to, changes in our business and the industry in which we operate;

| ● | restricting us from making strategic acquisitions or exploiting business opportunities;

| ● | placing us at a competitive disadvantage compared to our competitors that have less debt;

| ● | limiting our ability to borrow additional funds; and

| ● | decreasing our ability to compete effectively or operate successfully under adverse economic and industry conditions.

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Our results of operations and cash flows vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry.

We expect our results of operations and cash flows to vary significantly from year to year due to the cyclical nature of the crude oil and natural gas industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flows may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and as a result, our ability to generate cash flows from operations and to pay our debt. Many of these factors, such as crude oil, NGL and natural gas prices, regulatory factors, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. If we do not generate sufficient cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

| ● | refinancing or restructuring our debt;

| ● | selling assets;

| ● | reducing or delaying capital investments; or

| ● | seeking to raise additional capital.

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However, any alternative financing plans that we undertake may not allow us to meet our debt obligations. Any refinancing or debt restructuring may not be possible, any assets may not be sold or, if sold, the timing of the sales and the amount of proceeds realized from those sales may not be favorable to us or additional financing may not be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt obligations could materially and adversely affect our business, financial condition, results of operations and prospects.

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and could require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest or principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to refinance our indebtedness, sell assets or issue equity, or borrow more funds on terms acceptable to us, if at all.

In addition, if we fail to comply with the covenants or other terms of our Term Loan Credit Agreement or Senior Credit Facility Agreement, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

ITEM 5. OTHER INFORMATION

During the three months ended September 30, 2023, 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(a) of Regulation S-K.

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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 Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020).
10.1 | Term Loan Credit Agreement, dated 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.
10.2 | Collateral Agency Agreement, dated September 12, 2023, by and between HighPeak Energy, Inc., Texas Capital Bank, as collateral agent, Chambers Energy Management, LP, as term representative, and Mercuria Energy Trading SA, as first-out representative.
10.3 | Credit Agreement, dated November 1, 2023, by and between HighPeak Energy, Inc., as borrower and guarantor, and Fifth Third Bank, National Association, as administrative agent and collateral agent, and lenders party thereto.
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.

45

HIGHPEAK ENERGY, INC.

SIGNATURES

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

| HIGHPEAK ENERGY, INC.
November 6, 2023 | By: | /s/ Steven Tholen
|  | Steven Tholen
|  | Chief Financial Officer
November 6, 2023 | By: | /s/ Keith Forbes
|  | Keith Forbes
|  | Vice President and Chief Accounting Officer

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