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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 June 30, 2022

or

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

For the transition period from ________ to ________

Commission File Number: 001-39464

| HighPeak Energy, Inc. |
| (Exact name of Registrant as specified in its charter) |

Delaware | 84-3533602
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.)
421 W. 3rd St., Suite 1000 | 76102
Fort Worth, Texas | (Zip Code)
(Address of principal executive offices and zip code) |

(817) 850-9200

(Registrant's telephone number, including area code)

Not applicable

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

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

Title of each class |  | Trading Symbol |  | Name of each exchange on which registered
Common Stock, par value $0.0001 per share |  | HPK |  | The Nasdaq Stock Market LLC
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 August 4, 2022, there were 109,226,691 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 | 23
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 31
Item 4. | Controls and Procedures | 32
PART II. OTHER INFORMATION
Item 1. | Legal Proceedings | 32
Item 1A. | Risk Factors | 32
Item 6. | Exhibits | 33
Signatures |  | 35

HIGHPEAK ENERGY, INC.

Definitions of Certain Terms and Conventions Used Herein

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

| • | “3-D seismic” means three-dimensional seismic data which is geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional data.
| • | “Alamo Acquisitions” means the recently completed acquisitions of certain crude oil and natural gas properties in Howard and Borden Counties, Texas, collectively, from (i) Alamo Borden County II, LLCD (“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.
| • | “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.
| • | “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.
| • | “Contingent Value Right” or “CVR” refers to contractual contingent value rights, representing the right, under certain circumstances, to receive additional shares of HighPeak Energy common stock, if necessary, to satisfy a 10% preferred simple annual return, subject to a floor downside per-share price of $4.00, as measured on August 21, 2022 or February 21, 2023 (with an equivalent number of shares of HighPeak Energy common stock held by HighPeak I and HighPeak II being collectively forfeited).
| • | “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, Fifth Third Bank, National Association, as administrative agent, and the Lenders party thereto.
| • | “DD&A” means depletion, depreciation and amortization.
| • | “Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).
| • | “Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
| • | “Development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
| • | “Differential” An adjustment to the price of crude oil, NGL or natural gas from an established spot market price to reflect differences in the quality and/or location of crude oil, NGL or natural gas.
| • | “Dry hole” or “dry well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
| • | “Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
| • | “EUR” or “Estimated ultimate recovery” The sum of reserves remaining as of a given date and cumulative production as of that date.
| • | “Exploratory well” An exploratory well is a well drilled to find a new field, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend the limits of an existing 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.
| • | “FASB” Financial Accounting Standards Board.
| • | “Field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

| • | “First Amendment” means the First Amendment to Credit Agreement, dated as of June 23, 2021, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Guarantors and Lenders party thereto.
| • | “Formation” A layer of rock which has distinct characteristics that differs from nearby rocks.
| • | “Fourth Amendment” means the Fourth Amendment to 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 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.
| • | “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.

1

| • | “HH” means Henry Hub, a distribution hub in Louisiana that serves as the delivery location for natural gas futures contracts on the NYMEX.
| • | “Hannathon Acquisition” means the recently completed acquisition of various crude oil and natural gas properties 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.
| • | “HighPeak Energy” or the “Company” means HighPeak Energy, Inc. and its subsidiaries.
| • | “HighPeak I” means HighPeak Energy, LP, a Delaware limited partnership.
| • | “HighPeak II” means HighPeak Energy II, LP, a Delaware limited partnership.
| • | “Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
| • | “Hydraulic fracturing” is the technique of stimulating the production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in its drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.
| • | “Lease operating expenses” The expenses of lifting crude oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, marketing and transportation costs, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
| • | “MBbl” means one thousand Bbls.

| • | “MBoe” means one thousand Boes.
| • | “Mcf” means one thousand cubic feet and is a measure of natural gas volume.
| • | “MMBbl” means one million Bbls.
| • | “MMBtu” means one million Btus.
| • | “MMcf” means one million cubic feet and is a measure of natural gas volume.
| • | “Net acres” The percentage of total acres an owner has out of a particular number of gross acres or a specified tract. As an example. an owner who has 50% interest in 100 gross acres owns 50 net acres.
| • | “Net production” Production that is owned by us, less royalties and production due others.
| • | “NGL” means natural gas liquids, which are the heavier hydrocarbon liquids that are separated from the natural gas stream; such liquids include ethane, propane, isobutane, normal butane and gasoline.
| • | “NYMEX” means the New York Mercantile Exchange.
| • | “OPEC” means the Organization of Petroleum Exporting Countries.
| • | “Operator” The individual or company responsible for the exploration and/or production of a crude oil or natural gas well or lease.
| • | “Plugging” A downhole tool that is set inside the casing to isolate the lower part of the wellbore.
| • | “Pooling” The bringing together of small tracts or fractional mineral interests in one or more tracts to form a drilling and production unit for a well under applicable spacing rules.
| • | “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 recompletion. Undrilled locations can be classified as being 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.
| • | “Pure” means Pure Acquisition Corp., a Delaware corporation and wholly owned subsidiary of the Company.
| • | “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 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.
| • | “Revolving Credit Facility” means the Company’s senior secured reserve-based lending facility which matures June 17, 2024.
| • | “Royalty” An interest in a crude oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof) but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
| • | “SEC” means the United States Securities and Exchange Commission.
| • | “Second Amendment” means the Second Amendment to Credit Agreement, dated as of October 1, 2021, among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Guarantors and Lenders party thereto.
| • | “Service well” A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include natural gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
| • | “Spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 100-acre spacing, the distance between horizontal wellbores, e.g. 880-foot spacing or the number of wells per section, e.g. 6-well spacing. It is often established by regulatory agencies and/or the operator to optimize recovery of hydrocarbons.
| • | “Spot market price” The cash market price without reduction for expected quality, transportation and demand adjustments.
| • | “Standardized measure” The present value (discounted at an annual rate of 10 percent) of estimated future net revenues to be generated from the production of proved reserves net of estimated income taxes associated with such net revenues, as determined in accordance with FASB guidelines as well as the rules and regulations of the SEC, without giving effect to non-property related expenses such as indirect general and administrative expenses, and debt service or to DD&A. Standardized measure does not give effect to derivative transactions.
| • | “Stratigraphic test well” A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
| • | “Third Amendment” means the Third Amendment to 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 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 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:

| ● | the market prices of crude oil, NGL, natural gas and other products or services;
| ● | political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine;
| ● | the supply and demand for crude oil, NGL, natural gas and other products or services;
| ● | the integration of acquisitions, including the recently completed Alamo Acquisitions and Hannathon Acquisition;
| ● | the availability of capital resources;
| ● | production and reserve levels;
| ● | drilling risks;
| ● | 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;
| ● | economic and competitive conditions;
| ● | capital expenditures and other contractual obligations;
| ● | weather conditions;
| ● | inflation rates;
| ● | the availability of goods and services and supply chain issues;
| ● | legislative, regulatory or policy changes;
| ● | cyber-attacks;
| ● | occurrence of property acquisitions or divestitures;

| ● | the securities or capital markets 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 filed on March 7, 2022 (“Annual Report”), as supplemented by our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022 and “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part I, Item 3. Quantitative and Qualitative Disclosures about Market Risk,” included in this Quarterly Report, and elsewhere in this Quarterly Report.

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

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

4

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

HighPeak Energy, Inc.

Condensed Consolidated Balance Sheets

(in thousands, except share data)

|  | June 30, 2022 |  |  | December 31, 2021 |
|  | (Unaudited) |  |  |  |  |
ASSETS |  |  |  |  |  |  |  |
Current Assets: |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 22,417 |  |  | $ | 34,869 |
Accounts receivable |  |  | 90,235 |  |  |  | 39,378 |
Prepaid expenses |  |  | 19,072 |  |  |  | 7,154 |
Derivatives |  |  | 8,002 |  |  |  | 2,199 |
Inventory |  |  | 6,207 |  |  |  | 3,304 |
Deposits |  |  | 50 |  |  |  | 50 |
Total current assets |  |  | 145,983 |  |  |  | 86,954 |
Crude oil and natural gas properties, using the successful efforts method of accounting: |  |  |  |  |  |  |  |
Proved properties |  |  | 1,479,748 |  |  |  | 699,701 |
Unproved properties |  |  | 250,595 |  |  |  | 108,392 |
Accumulated depletion, depreciation and amortization |  |  | (134,261 | ) |  |  | (82,478 | )
Total crude oil and natural gas properties, net |  |  | 1,596,082 |  |  |  | 725,615 |
Other property and equipment, net |  |  | 2,473 |  |  |  | 1,600 |
Other noncurrent assets |  |  | 4,234 |  |  |  | 4,791 |
Total assets |  | $ | 1,748,772 |  |  | $ | 818,960 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Accounts payable - trade |  | $ | 101,990 |  |  | $ | 38,144 |
Accrued liabilities |  |  | 104,211 |  |  |  | 32,230 |
Derivatives |  |  | 39,911 |  |  |  | 13,591 |
Revenues and royalties payable |  |  | 14,150 |  |  |  | 7,502 |
Advances from joint interest owners |  |  | 2,880 |  |  |  | 10,841 |
Other current liabilities |  |  | 8,977 |  |  |  | 692 |
Total current liabilities |  |  | 272,119 |  |  |  | 103,000 |
Noncurrent liabilities: |  |  |  |  |  |  |  |
Long-term debt, net |  |  | 488,532 |  |  |  | 97,929 |
Deferred income taxes |  |  | 79,562 |  |  |  | 55,802 |
Asset retirement obligations |  |  | 8,055 |  |  |  | 4,260 |
Derivatives |  |  | — |  |  |  | 4,075 |
Other |  |  | 116 |  |  |  | 831 |
Commitments and contingencies (Note 10) |  |  |  |  |  |  |  |
Stockholders' equity: |  |  |  |  |  |  |  |
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at June 30, 2022 and December 31, 2021 |  |  | — |  |  |  | — |
Common stock, $0.0001 par value, 600,000,000 shares authorized, 109,226,591 and 96,774,185 shares issued and outstanding at June 30, 2022 and December 31, 2021, respectively |  |  | 11 |  |  |  | 10 |
Additional paid-in capital |  |  | 909,325 |  |  |  | 617,489 |
Accumulated deficit |  |  | (8,948 | ) |  |  | (64,436 | )
Total stockholders' equity |  |  | 900,388 |  |  |  | 553,063 |
Total liabilities and stockholders' equity |  | $ | 1,748,772 |  |  | $ | 818,960 |

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 June 30, |  |  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Operating Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil sales |  | $ | 190,926 |  |  | $ | 46,985 |  |  | $ | 277,864 |  |  | $ | 71,855 |
NGL and natural gas sales |  |  | 10,502 |  |  |  | 1,285 |  |  |  | 15,793 |  |  |  | 2,132 |
Total operating revenues |  |  | 201,428 |  |  |  | 48,270 |  |  |  | 293,657 |  |  |  | 73,987 |
Operating Costs and Expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Crude oil and natural gas production |  |  | 16,595 |  |  |  | 4,692 |  |  |  | 26,041 |  |  |  | 6,919 |
Production and ad valorem taxes |  |  | 10,301 |  |  |  | 2,543 |  |  |  | 15,307 |  |  |  | 4,207 |
Exploration and abandonments |  |  | 184 |  |  |  | 463 |  |  |  | 393 |  |  |  | 654 |
Depletion, depreciation and amortization |  |  | 34,883 |  |  |  | 16,857 |  |  |  | 51,907 |  |  |  | 29,820 |
Accretion of discount |  |  | 66 |  |  |  | 37 |  |  |  | 120 |  |  |  | 72 |
General and administrative |  |  | 2,016 |  |  |  | 1,617 |  |  |  | 3,956 |  |  |  | 3,376 |
Stock-based compensation |  |  | 14,579 |  |  |  | 1,023 |  |  |  | 18,555 |  |  |  | 1,989 |
Total operating costs and expenses |  |  | 78,624 |  |  |  | 27,232 |  |  |  | 116,279 |  |  |  | 47,037 |
Income from operations |  |  | 122,804 |  |  |  | 21,038 |  |  |  | 177,378 |  |  |  | 26,950 |
Interest and other income |  |  | 2 |  |  |  | — |  |  |  | 252 |  |  |  | 1 |
Interest expense |  |  | (9,282 | ) |  |  | (152 | ) |  |  | (14,534 | ) |  |  | (206 | )
Derivative loss, net |  |  | (11,891 | ) |  |  | (13,596 | ) |  |  | (78,285 | ) |  |  | (13,596 | )
Other expense |  |  | — |  |  |  | (127 | ) |  |  | — |  |  |  | (127 | )
Income before income taxes |  |  | 101,633 |  |  |  | 7,163 |  |  |  | 84,811 |  |  |  | 13,022 |
Income tax expense |  |  | 24,072 |  |  |  | 1,420 |  |  |  | 23,760 |  |  |  | 2,535 |
Net income |  | $ | 77,561 |  |  | $ | 5,743 |  |  | $ | 61,051 |  |  | $ | 10,487 |
Earnings per share: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic net income |  | $ | 0.69 |  |  | $ | 0.06 |  |  | $ | 0.56 |  |  | $ | 0.11 |
Diluted net income |  | $ | 0.64 |  |  | $ | 0.06 |  |  | $ | 0.52 |  |  | $ | 0.10 |
Weighted average shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 103,178 |  |  |  | 92,676 |  |  |  | 99,530 |  |  |  | 92,634 |
Diluted |  |  | 111,228 |  |  |  | 92,676 |  |  |  | 106,843 |  |  |  | 92,830 |
Dividends declared per share |  | $ | 0.025 |  |  | $ | — |  |  | $ | 0.05 |  |  | $ | — |

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 Six Months Ended June 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 |

Three and Six Months Ended June 30, 2021 |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Shares Outstanding |  |  | Common Stock |  |  | Additional Paid-in- Capital |  |  | Retained Earnings (Accumulated Deficit) |  |  | Total Stockholders’ Equity |
Balance, December 31, 2020 |  |  | 91,968 |  |  | $ | 9 |  |  | $ | 581,426 |  |  | $ | (107,209 | ) |  | $ | 474,226 |
Exercise of warrants |  |  | 554 |  |  |  | — |  |  |  | 5,466 |  |  |  | — |  |  |  | 5,466 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Shares issued upon options being exercised |  |  | 154 |  |  |  | — |  |  |  | 1,574 |  |  |  | — |  |  |  | 1,574 |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 966 |  |  |  | — |  |  |  | 966 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 4,744 |  |  |  | 4,744 |
Balance, March 31, 2021 |  |  | 92,676 |  |  |  | 9 |  |  |  | 589,432 |  |  |  | (102,465 | ) |  |  | 486,976 |
Stock-based compensation costs: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Restricted shares issued to outside directors |  |  | 53 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Compensation costs included in net income |  |  | — |  |  |  | — |  |  |  | 1,023 |  |  |  | — |  |  |  | 1,023 |
Net income |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 5,743 |  |  |  | 5,743 |
Balance, June 30, 2021 |  |  | 92,729 |  |  | $ | 9 |  |  | $ | 590,455 |  |  | $ | (96,722 | ) |  | $ | 493,742 |

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)

|  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |
CASH FLOWS FROM OPERATING ACTIVITIES: |  |  |  |  |  |  |  |
Net income |  | $ | 61,051 |  |  | $ | 10,487 |
Adjustments to reconcile net income to net cash provided by operations: |  |  |  |  |  |  |  |
Exploration and abandonment expense |  |  | 32 |  |  |  | 369 |
Depletion, depreciation and amortization expense |  |  | 51,907 |  |  |  | 29,820 |
Accretion expense |  |  | 120 |  |  |  | 72 |
Stock-based compensation expense |  |  | 18,555 |  |  |  | 1,989 |
Amortization of debt issuance costs |  |  | 1,781 |  |  |  | 77 |
Amortization of original issue discount on senior notes |  |  | 2,741 |  |  |  | — |
Derivative-related activity |  |  | 16,442 |  |  |  | 12,558 |
Deferred income taxes |  |  | 23,760 |  |  |  | 2,535 |
Changes in operating assets and liabilities: |  |  |  |  |  |  |  |
Accounts receivable |  |  | (50,857 | ) |  |  | (16,064 | )
Prepaid expenses, inventory and other assets |  |  | (2,571 | ) |  |  | (366 | )
Accounts payable, accrued liabilities and other current liabilities |  |  | 25,225 |  |  |  | 5,803 |
Net cash provided by operating activities |  |  | 148,186 |  |  |  | 47,280 |
CASH FLOWS FROM INVESTING ACTIVITIES: |  |  |  |  |  |  |  |
Additions to crude oil and natural gas properties |  |  | (403,177 | ) |  |  | (89,959 | )
Changes in working capital associated with crude oil and natural gas property additions |  |  | 105,476 |  |  |  | 15,223 |
Acquisitions of crude oil and natural gas properties |  |  | (250,448 | ) |  |  | (2,070 | )
Other property additions |  |  | (996 | ) |  |  | (61 | )
Net cash used in investing activities |  |  | (549,145 | ) |  |  | (76,867 | )
CASH FLOWS FROM FINANCING ACTIVITIES: |  |  |  |  |  |  |  |
Proceeds from issuance of senior unsecured notes, net of discount |  |  | 210,179 |  |  |  | — |
Borrowings under revolving credit facility |  |  | 380,000 |  |  |  | 14,000 |
Repayments under revolving credit facility |  |  | (195,000 | ) |  |  | — |
Debt issuance costs |  |  | (9,098 | ) |  |  | (1,759 | )
Proceeds from exercises of warrants |  |  | 7,750 |  |  |  | 5,466 |
Proceeds from subscription receivable from exercises of warrants |  |  | — |  |  |  | 3,596 |
Proceeds from exercises of stock options |  |  | 120 |  |  |  | 1,574 |
Dividends paid |  |  | (4,959 | ) |  |  | — |
Dividend equivalents paid |  |  | (427 | ) |  |  | — |
Stock offering costs |  |  | (58 | ) |  |  | — |
Net cash provided by financing activities |  |  | 388,507 |  |  |  | 22,877 |
Net decrease in cash and cash equivalents |  |  | (12,452 | ) |  |  | (6,710 | )
Cash and cash equivalents, beginning of period |  |  | 34,869 |  |  |  | 19,552 |
Cash and cash equivalents, end of period |  | $ | 22,417 |  |  | $ | 12,842 |
Supplemental disclosure of non-cash transactions: |  |  |  |  |  |  |  |
Interest paid |  | $ | 1,689 |  |  | $ | 133 |
Income taxes paid |  | $ | — |  |  | $ | — |
Stock issued for acquisition |  | $ | 264,982 |  |  | $ | — |
Additions to asset retirement obligations |  | $ | 3,676 |  |  | $ | 600 |

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, 2021 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. HighPeak Energy’s Contingent Value Rights (“CVRs”) are currently traded on the Over-The-Counter market under the ticker symbol “HPKER.” 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 in Howard and Borden Counties. Our acreage is composed of two core areas, Flat Top in the northern portion of Howard County extending into southern Borden 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 June 30, 2022 and for the three and six months ended June 30, 2022 and 2021 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 six months ended June 30, 2022 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 United States Securities and Exchange Commission (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, 2021.

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 and evaluations for impairment of proved and unproved crude oil and natural gas properties, in part, is determined using estimates of proved, 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.

Accounts receivable. As of June 30, 2022 and December 31, 2021, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $69.0 million and $29.0 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, $8.9 million and zero, respectively, of receivables for purchase price adjustments related to the Hannathon Acquisition, receivables related to refunds from pipe suppliers of zero and $3.2 million, respectively, current U.S. federal income tax receivables of $3.2 million and $3.2 million, respectively, joint interest receivables of $9.1 million and $3.1 million, respectively, and receivables related to settlements of derivative contracts of zero and $771,000, 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 routinely reviews outstanding balances and establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. As of June 30, 2022 and December 31, 2021, the Company had no allowance for doubtful accounts.

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 six months ended June 30, 2022 and 2021, sales to the Company’s largest purchaser accounted for approximately 88% and 95%, 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 this particular purchaser 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.

Prepaid expenses. Prepaid expenses are comprised primarily of tubulars that the Company has prepaid for the suppliers to produce the tubulars in time such as to guarantee their availability when we need them for our current drilling program, prepaid drilling and completion costs on wells being drilled and completed by third party operators where we own a non-operated working interest, prepaid caliche that will be used on future locations and roads in our development areas, prepaid insurance costs, software maintenance costs and listing fees that will be amortized over the life of the policies and prepaid software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of June 30, 2022 and December 31, 2021 is $19.1 million and $7.2 million, respectively.

9

Inventory. Inventory is comprised primarily of crude oil and natural gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate crude oil and natural gas wells, water, chemicals, pumps, vessels, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling 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 June 30, 2022 and December 31, 2021 is $6.2 million and $3.3 million, respectively, and the Company has not recognized any valuation allowance to date.

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 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 $562,000 and $438,000 as of June 30, 2022 and December 31, 2021, respectively, are as follows (in thousands):

|  | June 30, 2022 |  |  | December 31, 2021 |
Land |  | $ | 1,122 |  |  | $ | 1,122 |
Transportation equipment |  |  | 609 |  |  |  | 202 |
Buildings |  |  | 532 |  |  |  | — |
Leasehold improvements |  |  | 161 |  |  |  | 143 |
Information technology |  |  | 42 |  |  |  | 125 |
Field equipment |  |  | 7 |  |  |  | 8 |
Total other property and equipment, net |  | $ | 2,473 |  |  | $ | 1,600 |

Other property and equipment is depreciated over its 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 information technology is generally depreciated over three 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 June 30, 2022 and December 31, 2021, the Company has aid-in-construction assets totaling $3.7 million and $3.9 million, respectively, included in other noncurrent assets. The Company contracted with the natural gas gatherer and processor in its Flat Top area to construct a low-pressure gas gathering system to transport the Company’s natural gas to its processing facility. The Company agreed to incur the cost to construct the system in return for future payments based on gross system throughput, including any third-party natural gas that is potentially tied into the system in the future. Based on the Company’s current projections of its natural gas reserves in Flat Top, it is anticipated that the full amount will be paid back in less than four years. The contract calls for future aid-in-construction fundings if expansions of the system are necessary at the sole discretion of the Company.

10

Debt issuance costs and original issue discount. The Company has paid a total of $11.7 million in debt issuance costs, $9.1 million of which was incurred during the six months ended June 30, 2022, related to the issuance of senior unsecured notes and amendments to its revolving credit facility. Amortization based on the straight-line method over the terms of the senior unsecured notes and the revolving credit facility which approximates the effective interest method was $1.8 million and $77,000 during the six months ended June 30, 2022 and 2021, respectively. In addition, the company realized a $14.8 million discount on the issuance of its senior unsecured notes that is being amortized over the life of the notes which approximates the effective interest method and was $2.7 million and zero during the six months ended June 30, 2022 and 2021, respectively. As of June 30, 2022 and December 31, 2021, the net debt issuance costs and discount are netted against the outstanding long-term debt on the accompanying balance sheets in accordance with GAAP.

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

Current liabilities. Current liabilities as of June 30, 2022 and December 31, 2021 totaled approximately $272.1 million and $103.0 million, respectively, including trade accounts payable, derivative liabilities, revenues payable, advances from joint interest owners and accruals for capital expenditures, operating and general and administrative expenses, interest expense, operating leases, dividends and dividend equivalents and other miscellaneous items.

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 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 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 production. As of June 30, 2022 and December 31, 2021, the Company had receivables related to contracts with purchasers of approximately $69.0 million and $29.0 million, respectively.

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

11

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 had not established a valuation allowance as of June 30, 2022 and December 31, 2021.

The Company recognizes the tax benefit from an uncertain tax position 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.

The Company records any tax-related interest charges 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 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 HighPeak Energy common stock issued to outside directors with no restrictions thereon, is measured at the grant date using the fair value of the award and is recognized as stock-based compensation in the accompanying financial statements immediately. Stock-based compensation for restricted stock awarded to outside directors, employee members of the board of directors 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.

Impact of the COVID-19 Pandemic. A novel strain of the coronavirus disease ("COVID-19") surfaced in late 2019 and spread around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The COVID-19 pandemic significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for crude oil throughout the world and when combined with pressures on the global supply-demand balance for crude oil and related products, resulted in significant volatility in crude oil prices beginning late February 2020. The length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact of the effects of the COVID-19 pandemic to global crude oil demand.

Recently adopted accounting pronouncements. There are no recently adopted accounting pronouncements.

New accounting pronouncements not yet adopted. In October 2021, the FASB issued ASU 2021-08, “Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity.

The Company considers the applicability and the impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.

NOTE 3. Acquisitions

Acquisitions. During the six months ended June 30, 2022, the Company incurred a total of $515.4 million in acquisition costs primarily related to a series of agreements to acquire various crude oil and natural gas properties contiguous to its Signal Peak and Flat Top operating areas in Howard and Borden counties, consisting of approximately 34,500 net acres and associated producing properties, water system infrastructure and in-field fluid gathering pipelines. Included in the acquisition costs is the issuance of 10,853,634 shares of HighPeak Energy common stock valued at $265.0 million on the respective closing dates. All the aforementioned acquisitions were accounted for as asset acquisitions as substantially all 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 acquisitions were capitalized.

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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 June 30, 2022 and December 31, 2021 are as follows (in thousands):

|  | As of June 30, 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 |  | $ | — |  |  | $ | 8,002 |  |  | $ | — |  |  | $ | 8,002 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity price derivatives |  |  | — |  |  |  | 39,911 |  |  |  | — |  |  |  | 39,911 |
Total recurring fair value measurements |  | $ | — |  |  | $ | (31,909 | ) |  | $ | — |  |  | $ | (31,909 | )

|  | As of December 31, 2021 |
|  | 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 |  | $ | — |  |  | $ | 2,199 |  |  | $ | — |  |  | $ | 2,199 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity price derivatives – current |  |  | — |  |  |  | 13,591 |  |  |  | — |  |  |  | 13,591 |
Commodity price derivatives – noncurrent |  |  | — |  |  |  | 4,075 |  |  |  | — |  |  |  | 4,075 |
Total liabilities |  |  | — |  |  |  | 17,666 |  |  |  | — |  |  |  | 17,666 |
Total recurring fair value measurements |  | $ | — |  |  | $ | (15,467 | ) |  | $ | — |  |  | $ | (15,467 | )

Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil and natural gas swap contracts. The Company measures derivatives using an industry-standard pricing model that is provided by a third party. 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 June 30, 2022 |  |  | As of December 31, 2021 |
|  | Carrying Value |  |  | Fair Value |  |  | Carrying Value |  |  | Fair Value |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 22,417 |  |  | $ | 22,417 |  |  | $ | 34,869 |  |  | $ | 34,869 |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
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 accounts receivable, accounts payable, long-term debt, specifically the revolving credit facility, 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 to (i) reduce the effect of price volatility on the commodities the Company produces and sells, and (ii) support the Company’s capital budgeting and expenditure plans, (iii) protect the Company’s borrowing base under its Revolving Credit Facility, (iv) adhere to the hedge obligations included in the senior unsecured notes and (v) support the payment of contractual obligations.

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

|  | Three Months Ended |  |  | Six Months Ended |
|  | June 30, |  |  | June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Noncash derivative gain (loss), net |  | $ | 25,191 |  |  | $ | (12,558 | ) |  | $ | (16,442 | ) |  | $ | (12,558 | )
Derivative settlements, net |  |  | (37,082 | ) |  |  | (1,038 | ) |  |  | (61,843 | ) |  |  | (1,038 | )
Derivative loss, net |  | $ | (11,891 | ) |  | $ | (13,596 | ) |  | $ | (78,285 | ) |  | $ | (13,596 | )

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 contracts as of June 30, 2022 and the weighted average crude oil prices per barrel for those contracts are as follows:

|  | Remainder of 2022 |  |  | 2023 |
|  | Third |  |  | Fourth |  |  |  |  |  |  | First |  |  | Second |  |  |  |  |
|  | Quarter |  |  | Quarter |  |  | Total |  |  | Quarter |  |  | Quarter |  |  | Total |
Crude Oil Price Swaps - WTI: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MBbls) |  |  | 980.8 |  |  |  | 1,011.8 |  |  |  | 1,992.6 |  |  |  | 441.0 |  |  |  | 200.2 |  |  |  | 641.2 |
Price per Bbl |  | $ | 88.97 |  |  | $ | 86.13 |  |  | $ | 87.53 |  |  | $ | 70.05 |  |  | $ | 57.22 |  |  | $ | 66.04 |

Natural gas production derivatives. The Company sells its natural gas production at the lease and the sales contracts governing such natural gas production are tied directly to, or are correlated with, NYMEX HH natural gas prices. As such, the Company uses NYMEX HH derivative contracts to manage future natural gas price volatility.

The Company’s outstanding natural gas derivative contracts as of June 30, 2022 and the weighted average natural gas prices per MMBtu for those contracts are as follows:

|  | Remainder of 2022 |  |  | 2023 |
|  | Third |  |  | Fourth |  |  |  |  |  |  | First |  |  |  |  |
|  | Quarter |  |  | Quarter |  |  | Total |  |  | Quarter |  |  | Total |
Natural Gas Price Swaps - HH: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  | 460.0 |  |  |  | 460.0 |  |  |  | 920.0 |  |  |  | 450.0 |  |  |  | 450.0 |
Price per MMBtu |  | $ | 9.00 |  |  | $ | 9.00 |  |  | $ | 9.00 |  |  | $ | 9.00 |  |  | $ | 9.00 |

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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 derivatives by counterparty are as follows (in thousands):

|  | As of June 30, 2022 |
Fifth Third Bank, National Association |  | $ | (22,656 | )
Bank of America, National Association |  |  | (9,643 | )
Bank of Oklahoma, National Association |  |  | (3,668 | )
Citizens Bank, National Association |  |  | 4,058 |
|  | $ | (31,909 | )

NOTE 6. Exploratory Well Costs

The Company capitalizes exploratory well 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 well and project costs are included in proved properties in the consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

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

|  | Six Months Ended June 30, 2022 |
Beginning capitalized exploratory well costs |  | $ | 28,076 |
Additions to exploratory well costs |  |  | 161,331 |
Reclassification to proved properties |  |  | (177,720 | )
Exploratory well costs charged to exploration and abandonment expense |  |  | — |
Ending capitalized exploratory well costs |  | $ | 11,687 |

All capitalized exploratory 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):

|  | June 30, 2022 |  |  | December 31, 2021 |
Revolving Credit Facility due 2024 |  | $ | 285,000 |  |  | $ | 100,000 |
10.00% Senior Notes due 2024 |  |  | 225,000 |  |  |  | — |
Debt issuance costs, net (a) |  |  | (9,388 | ) |  |  | (2,071 | )
Discounts, net (b) |  |  | (12,080 | ) |  |  | — |
Total debt |  |  | 488,532 |  |  |  | 97,929 |
Less current portion of long-term debt |  |  | — |  |  |  | — |
Long-term debt, net |  | $ | 488,532 |  |  | $ | 97,929 |

(a) Debt issuance costs as of June 30, 2022 and December 31, 2021 consisted of $11.7 million and $2.6 million, respectively, in costs less accumulated amortization of $2.3 million and $502,000, respectively.

(b) Discounts as of June 30, 2022 and December 31, 2021 consisted of $14.8 million and zero, respectively, in discounts less accumulated amortization of $2.7 million and zero, respectively.

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Revolving Credit Facility. In December 2020, the Company entered into a Credit Agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and sole lender to establish a revolving credit facility (“Revolving Credit Facility”) that matures on June 17, 2024 (subject to a springing maturity date of October 1, 2023 if the Senior Notes are outstanding on such date). The Revolving Credit Facility had an initial borrowing base of $40.0 million. However, the Company elected to reduce the aggregate elected commitments under the Revolving Credit Facility to $20.0 million. In June 2021, the Company entered into the First Amendment to, among other things, (i) complete the semi-annual borrowing base redetermination process which increased the borrowing base from $40.0 million to $125.0 million and (ii) modify the terms of the Credit Agreement to increase the aggregate elected commitments from $20.0 million to $125.0 million. A syndicate of banks joined the credit facility at differing levels of commitments with Fifth Third remaining the administrative agent. In October 2021, the Company entered into the Second Amendment to, among other things, (i) complete a semi-annual borrowing base redetermination process, which increased the borrowing base from $125.0 million to $195.0 million and (ii) modify the terms of the Credit Agreement to increase the aggregate elected commitments from $125.0 million to $195.0 million. 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 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 will cause the Credit Agreement to mature on October 1, 2023 if the Senior Notes are not retired by that date, (iv) allow the Company to redeem the 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, simultaneous with the closing of one of the aforementioned acquisitions, the Company entered into the Fourth Amendment to the Revolving Credit Facility 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 and (iv) increase the number of banks included in the syndicate at differing levels of commitments with Fifth Third remaining the administrative agent.

The borrowing capacity under the Revolving Credit Facility is equal to the lowest of (i) the borrowing base (which stands at $400.0 million as of June 30, 2022), (ii) the aggregate elected commitments (which stand at $400.0 million as of June 30, 2022) and (iii) $1.5 billion. As of June 30, 2022 and December 31, 2021, the Company had $285.0 million and $100.0 million, respectively, outstanding borrowings under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility prior to February 2022 bore interest, at the option of the Company, based on (a) a rate per annum equal to the higher of (i) the prime rate announced from time to time by Fifth Third, (ii) the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent and (iii) the Adjusted LIBO Rate for one-month Interest Period, plus a margin (the “Applicable Margin”) which was determined by the Borrowing Base Utilization Percentage as defined in the Revolving Credit Facility or (b) the LIBO Rate for a one, three or six month Interest Period multiplied by the Statutory Reserve Rate. As of February 2022, borrowings under the Revolving Credit Facility bear interest at the option of the Company, based on (a) the prime rate announced from time to time by Fifth Third or (b) a rate equal to the higher of (i) zero percent per annum and (ii) SOFR relating to quotations for 1 or 3 months. Letters of credit outstanding under the Revolving Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Revolving Credit Facility equal to 0.50 percent. Borrowings under the Revolving Credit Facility are secured by a first lien security interest on substantially all assets of the Company and its restricted subsidiaries, including mortgages on the Company’s and its restricted subsidiaries’ crude oil and natural gas properties. The Revolving Credit Facility is scheduled to have the borrowing base redetermined semiannually in April and October. Additionally, the Company and Fifth Third each have the option for a wild card evaluation between redeterminations.

The Revolving Credit Facility requires the maintenance of a ratio of total debt to EBITDAX, subject to certain adjustments, not to exceed 3.00 to 1.00 as of the last day of any fiscal quarter and a current ratio, subject to certain adjustments, of at least 1.00 to 1.00 as of the last day of any fiscal quarter.

The Company has limited equity cure rights for a breach of the above-listed financial covenants. Additionally, the Revolving Credit Facility contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness, incur additional liens, make investments and loans, enter into mergers and acquisitions, make or declare dividends and other payments, enter into certain hedging transactions, sell assets and engage in transactions with affiliates. The Revolving Credit Facility contains customary mandatory prepayments, including a monthly mandatory prepayment if the Consolidated Cash Balance (as defined in the Credit Agreement) is in excess of $75.0 million. In addition, the Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the administrative agent or the majority of the lenders may accelerate any amounts outstanding and terminate lender commitments.

Senior Notes. In February 2022, the Company issued $225.0 million aggregate principal amount of 10.00% senior unsecured notes that will mature on February 15, 2024 (“Senior Notes”). The Company received proceeds, net of $21.2 million of issuance costs and discounts, of $203.8 million. The net proceeds were used to pay down the balance of our Revolving Credit Facility to zero at closing and to fund our ongoing capital development program with subsequent draws on the Revolving Credit Facility. Interest on the Senior Notes will be payable on August 15 and February 15 of each year.

Both the Revolving Credit Facility and the Senior Notes have hedging obligations that the Company adheres to.

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NOTE 8. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and 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):

|  | Six Months Ended June 30, 2022 |
Beginning asset retirement obligations |  | $ | 4,260 |
Liabilities incurred from wells acquired |  |  | 3,218 |
Liabilities incurred from new wells |  |  | 457 |
Accretion of discount |  |  | 120 |
Ending asset retirement obligations |  | $ | 8,055 |

As of June 30, 2022 and December 31, 2021, 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 six months ended June 30, 2022 and 2021, the Company contributed $141,000 and $111,000 to the 401(k) Plan, respectively.

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

|  | June 30, 2022 |
Approved and authorized awards |  |  | 13,793,197 |
Awards issued under plan |  |  | (13,048,190 | )
Awards available for future grant |  |  | 745,007 |

Stock Options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021 and May 4, 2022. Stock-based compensation expense related to the Company’s stock option awards for the three and six months ended June 30, 2022 and 2021 was $10.8 million and $1.9 million, respectively, and as of June 30, 2022 and December 31, 2021 there was $1.9 million and $1.8 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 two years.

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

|  | Stock Options |  |  | Exercise Price |  |  | Remaining Term in Years |  |  | Intrinsic Value (in thousands) |
Outstanding at December 31, 2020 |  |  | 9,705,495 |  |  | $ | 10.00 |  |  |  | 9.7 |  |  | $ | 57,942 |
Awards granted |  |  | 442,500 |  |  | $ | 14.36 |  |  |  |  |  |  |  |  |
Exercised |  |  | (154,268 | ) |  | $ | 10.00 |  |  |  |  |  |  |  |  |
Forfeitures |  |  | (10,000 | ) |  | $ | 10.00 |  |  |  |  |  |  |  |  |
Outstanding at December 31, 2021 |  |  | 9,983,727 |  |  | $ | 10.19 |  |  |  | 8.7 |  |  | $ | 44,395 |
Awards granted |  |  | 824,500 |  |  | $ | 29.67 |  |  |  |  |  |  |  |  |
Exercised |  |  | (12,000 | ) |  | $ | 10.00 |  |  |  |  |  |  |  |  |
Outstanding at June 30, 2022 |  |  | 10,796,227 |  |  | $ | 11.68 |  |  |  | 8.3 |  |  | $ | 152,316 |
Vested at December 31, 2021 |  |  | 8,551,070 |  |  | $ | 10.13 |  |  |  | 8.7 |  |  | $ | 38,556 |
Exercisable at December 31, 2021 |  |  | 8,551,070 |  |  | $ | 10.13 |  |  |  | 8.7 |  |  | $ | 38,556 |
Vested at June 30, 2022 |  |  | 9,268,914 |  |  | $ | 11.67 |  |  |  | 8.3 |  |  | $ | 103,055 |
Exercisable at June 30, 2022 |  |  | 9,268,914 |  |  | $ | 11.67 |  |  |  | 8.3 |  |  | $ | 103,055 |

Restricted Stock Issued to Employee Members of the Board. A total of 1,500,500 shares of restricted stock was approved by the board of directors 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 $3.6 million was recognized during the six months ended June 30, 2022 and the remaining $16.8 million 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 of directors 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 $3.8 million was recognized during the six months ended June 30, 2022, and the remaining $16.4 million 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 21,184 shares of restricted stock was approved by the board of directors to be granted to the outside directors of the Company on June 1, 2022, which will vest at the next annual meeting, assuming the board members maintain their positions on the board. Therefore, stock-based compensation expense of $61,000 was recognized during the six months ended June 30, 2022 and the remaining $672,000 will be recognized between July 2022 and June 2023, which was based upon the closing price of the stock on the date of the restricted stock issuance. In addition, a total of 67,779 shares of restricted stock was approved by the board of directors 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 six months ended June 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 June 30, 2022 the Company had right-of-use assets totaling $579,000 included in other noncurrent assets and operating lease liabilities totaling $591,000, $475,000 of which are included in other current liabilities and $116,000 of which are included in other noncurrent liabilities, and as of December 31, 2021 the Company had right-of-use assets totaling $852,000 included in other noncurrent assets and operating lease liabilities totaling $856,000, $513,000 of which are included in other current liabilities and $343,000 of which are included in other noncurrent 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):

|  | June 30, 2022 |
Remainder of 2022 |  | $ | 257 |
2023 |  |  | 349 |
Total lease payments |  |  | 606 |
Less present value discount |  |  | (15 | )
Present value of lease liabilities |  | $ | 591 |

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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 Lion 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 constructing a crude oil gathering system and custody transfer meters to most of all 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 June 30, 2022, the Company has delivered approximately 17,503 Bopd under the contract. The remaining monetary commitment as of June 30, 2022, if the Company never delivers any additional volumes under the agreement, is approximately $22.2 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 requires 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 will provide 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.

Power contracts. In June 2021, the Company entered into a contract with Priority Power Management, LLC (“Priority Power”) whereby Priority Power will develop an electric high-voltage (“EHV”) substation, medium voltage distribution systems and a 13-megawatt direct current solar photovoltaic facility located on approximately 80 acres of land owned by the Company north of Big Spring, Texas in Howard County to provide for the Company’s electrical power needs in its Flat Top operating area including powering drilling rigs and day-to-day operations. The EHV substation was interconnected with the ERCOT transmission grid in May 2022 via the local electric utility, has an initial capacity of up to 50 megavolt amperes and was designed for future expansion capability. The solar generation facility will be interconnected with the medium voltage distribution system that will be energized from the new EHV substation. Priority Power will develop, finance, engineer, construct, operate and maintain the project facilities.

Also in June 2021, the Company entered into a contract with Oncor Electric Delivery Company, LLC (“Oncor”) to construct certain facilities to deliver electricity to the aforementioned substation. In conjunction with this contract, the Company issued a $1.9 million letter of credit to Oncor until such time as the Company’s load meets or exceeds 12 megawatts as measured during any fifteen (15) minute interval on or before May 20, 2023.

Finally, in June 2022, the Company entered into a contract with TXU Energy Retail Company LLC (“TXU”) to provide a block of electric power via the aforementioned transmission system 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 agreement whereby it has agreed to purchase at least 600,000 tons of sand over a two-year period beginning at the commencement date of the sand mine being operational, which was late in the second quarter of 2022. There are stipulations in the agreement that reduce this commitment should we experience a downturn in oil prices. However, generally if the Company never takes delivery of any sand under the agreement, the monetary commitment as of June 30, 2022 is approximately $8.7 million.

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NOTE 11. Related Party Transactions

Water Treatment. In September 2021, the Company entered into a contract with Pilot Exploration, Inc., (“Pilot”), whose President and CEO is 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 such that it 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 July 1, 2022 based on the early results of the project. During the six months ended June 30, 2022, the Company paid $1.4 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 no later than October 1, 2022, the Company has 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. The monetary commitment, if the Company never delivers any produced water to be treated under the agreement, is approximately $6.0 million.

NOTE 12. Major Customers

Lion Oil Trading and Transportation, LLC (“Lion”) accounted for approximately 88% and 95% of the Company’s revenues during the six months ended June 30, 2022 and 2021, respectively. Based on the current demand for crude oil and natural gas and the availability of other purchasers, management believes the loss of this major purchaser 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

The Company’s income tax expense attributable to income from operations consisted of the following (in thousands):

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Current income tax expense: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
State |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Total current income tax expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Deferred income tax expense: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Federal |  |  | 23,315 |  |  |  | 1,420 |  |  |  | 23,127 |  |  |  | 2,535 |
State |  |  | 757 |  |  |  | — |  |  |  | 633 |  |  |  | — |
Deferred income tax expense |  |  | 24,072 |  |  |  | 1,420 |  |  |  | 23,760 |  |  |  | 2,535 |
Total income tax expense |  | $ | 24,072 |  |  | $ | 1,420 |  |  | $ | 23,760 |  |  | $ | 2,535 |

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

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Income tax expense at U.S. federal statutory rate |  | $ | 21,343 |  |  | $ | 1,505 |  |  | $ | 17,810 |  |  | $ | 2,735 |
Limited tax benefit due to stock-based compensation |  |  | 1,930 |  |  |  | 28 |  |  |  | 5,536 |  |  |  | (81 | )
State deferred income taxes |  |  | 848 |  |  |  | — |  |  |  | 724 |  |  |  | — |
Other, net |  |  | (49 | ) |  |  | (113 | ) |  |  | (310 | ) |  |  | (119 | )
Income tax expense |  | $ | 24,072 |  |  | $ | 1,420 |  |  | $ | 23,760 |  |  | $ | 2,535 |
Effective income tax rate |  |  | 23.7 | % |  |  | 19.8 | % |  |  | 28.0 | % |  |  | 19.5 | %

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities were as follows as of June 30, 2022 and December 31, 2021 (in thousands):

|  | June 30, 2022 |  |  | December 31, 2021 |
Deferred tax assets: |  |  |  |  |  |  |  |
Unrecognized derivative losses |  | $ | 6,890 |  |  | $ | 3,248 |
Net operating loss carryforwards |  |  | 4,037 |  |  |  | 2,870 |
Interest expense limitations |  |  | 3,052 |  |  |  | — |
Stock-based compensation |  |  | 2,629 |  |  |  | 4,373 |
Other |  |  | 97 |  |  |  | 31 |
Deferred tax assets |  |  | 16,705 |  |  |  | 10,522 |
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 |  |  | (96,267 | ) |  |  | (66,324 | )
Net deferred tax liabilities |  | $ | (79,562 | ) |  | $ | (55,802 | )

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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 June 30, 2022 and December 31, 2021, 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 benefit realized during the six months ended June 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 2022 or 2021. However, the Company has recognized a deferred Texas Margin Tax liability of $2.5 million and $1.8 million as of June 30, 2022 and December 31, 2021, 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 six months ended June 30, 2022 and 2021 under the two-class method (in thousands):

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Net income as reported |  | $ | 77,561 |  |  | $ | 5,743 |  |  | $ | 61,051 |  |  | $ | 10,487 |
Participating basic earnings (a) |  |  | (6,376 | ) |  |  | (407 | ) |  |  | (5,169 | ) |  |  | (743 | )
Basic earnings attributable to common stockholders |  |  | 71,185 |  |  |  | 5,336 |  |  |  | 55,882 |  |  |  | 9,744 |
Reallocation of participating earnings |  |  | 162 |  |  |  | — |  |  |  | 124 |  |  |  | 1 |
Diluted net income attributable to common stockholders |  | $ | 71,347 |  |  | $ | 5,336 |  |  | $ | 55,006 |  |  | $ | 9,745 |
Basic weighted average shares outstanding |  |  | 103,178 |  |  |  | 92,676 |  |  |  | 99,530 |  |  |  | 92,634 |
Dilutive warrants and unvested stock options |  |  | 5,928 |  |  |  | — |  |  |  | 5,191 |  |  |  | 196 |
Dilutive unvested restricted stock |  |  | 2,122 |  |  |  | — |  |  |  | 2,122 |  |  |  | — |
Diluted weighted average shares outstanding |  |  | 111,228 |  |  |  | 92,676 |  |  |  | 106,843 |  |  |  | 92,830 |

| (a) | Certain unvested restricted stock awarded to outside directors represent participating securities because they participate in nonforfeitable dividends with the common equity holders of the Company. 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 of directors 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 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 crude oil and natural gas property acquisitions. On June 1, 2022, the Company issued 21,184 and 600,000 shares of restricted stock to outside directors and certain employees, respectively. The remaining 977,588 shares of HighPeak Energy common stock issued during the six months ended June 30, 2022 were the result of warrants (965,588 shares) and stock options (12,000 shares) being exercised.

Dividends and dividend equivalents. In April 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 $2.6 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 of $214,000 in May 2022 and will accrue a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional $36,000, assuming no forfeitures. In addition, the Company will accrue 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 of directors of the Company 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 $36,000, 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 June 30, 2022 and December 31, 2021, the Company had 109,226,591 and 96,774,185 shares of common stock outstanding, respectively, 8,290,572 and 9,500,166 warrants outstanding, respectively, with an exercise price of $11.50 per share that expire on August 21, 2025 and 10,209,300 and 10,209,300 CVRs outstanding, respectively, that give the holders a right to receive up to 2.125 shares of HighPeak Energy common stock per CVR to satisfy the Preferred Returns (with an equivalent number of shares of Company common stock held by HighPeak Energy, LP (“HighPeak I”) and HighPeak Energy II, LP (“HighPeak II”) being collectively forfeited in connection therewith). As such, HighPeak I and HighPeak II have placed a total of 21,694,763 shares of common stock of the Company in escrow.

NOTE 16. Subsequent Events

Dividends and dividend equivalents. In July 2022, the board of directors of the Company declared a quarterly dividend of $0.025 per share of common stock outstanding which will result in a total of $2.7 million in dividends being paid on August 25, 2022. The Company received a waiver from the bank group in the Revolving Credit Facility at no cost to pay this dividend. In addition, under the terms of the LTIP, the Company will pay a dividend equivalent per share to all vested stock option holders of $263,000 in August 2022 and will accrue a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional $7,000, assuming no forfeitures. In addition, the Company will accrue 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.

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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 Regarding 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, which lie within the northeastern part of the crude oil-rich Midland Basin. As of June 30, 2022, the assets consisted of two highly contiguous leasehold positions of approximately 114,940 gross (97,129 net) acres, approximately 50% of which were held by production, with an average working interest of 85%. Our acreage is composed of two core areas, Flat Top to the north and Signal Peak to the south. We operate approximately 98% of the net acreage across the Company’s assets and approximately 90% of the net operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the six months ended June 30, 2022, approximately 94% and 6% of sales volumes from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of June 30, 2022, HighPeak Energy was drilling with six (6) rigs.

Acquisitions

During the six months ended June 30, 2022, the Company incurred a total of $515.4 million in acquisition costs primarily related to a series of agreements to acquire various crude oil and natural gas properties contiguous to its Signal Peak and Flat Top operating areas in Howard and Borden counties, consisting of approximately 34,500 net acres and associated producing properties, water system infrastructure and in-field fluid gathering pipelines. Included in the acquisition costs is the issuance of 10,853,634 shares of HighPeak Energy common stock valued at $265.0 million on the respective closing dates. The acquisitions were accounted for as asset acquisitions and included approximately 31 gross (26.3 net) producing horizontal wells, 109 gross (87.8 net) producing vertical wells and six vertical salt-water disposal wells and related water system infrastructure as well as over 200 gross horizontal drilling locations targeting the Wolfcamp A, Wolfcamp D and Lower Spraberry formations.

Financial and Operating Performance

The Company's financial and operating performance for the three months ended June 30, 2022 included the following highlights:

• | Net income was $77.6 million ($0.64 per diluted share) for the three months ended June 30, 2022 compared with net income of $5.7 million for three months ended June 30, 2021. The primary components of the $71.8 million increase in net income include:

| • | a $153.2 million increase in crude oil, NGL and natural gas revenues due to a 150% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program in addition to a 67% increase in average realized commodity prices per Boe, excluding the effects of derivatives; and

| • | a $1.7 million decrease in the Company's net derivative loss as a result of its crude oil and natural gas commodity contracts entered into and the decrease of crude oil and natural gas prices thereafter; partially offset by:
| • | a $22.7 million increase in the Company’s income tax expense due to the net income realized during the three months ended June 30, 2022 compared with the three months ended June 30, 2021;
| • | a $18.0 million increase in DD&A expense due to a 150% increase in daily sales volumes, partially offset by a 17% decrease in the DD&A rate from $21.09 to $17.43 per Boe, both as a result of increased proved reserves due to the Company’s successful horizontal drilling program;
| • | a $13.6 million increase in the Company's stock-based compensation expense primarily attributable to equity-based awards issued in May 2022;
| • | a $11.9 million increase in lease operating expenses related primarily to the increased well count and production from the Company’s successful horizontal drilling program;
| • | A $9.1 million increase in interest expense due to the issuance of two year 10.00% senior unsecured notes in February 2022, increased borrowings on the revolving credit facility and increased amortization of debt issuance costs and discounts; and
| • | a $7.8 million increase in production and ad valorem taxes, primarily attributable to the 150% increase in daily sales volumes as a result of the Company’s successful horizontal drilling program combined with 62% higher production and ad valorem taxes on a dollar per Boe basis due to higher overall realized prices of 67%, excluding the effects of derivatives.

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• | During the three months ended June 30, 2022, average daily sales volumes totaled 21,995 Boe/d (excluding production from the recently completed Hannathon Acquisition which will not have an impact until the third quarter of 2022), compared with 8,783 Boe/d during the same period in 2021, an increase of 150% over the same period in 2021, due to the Company's successful horizontal drilling program and bolt-on acquisitions.

• | Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, increased during the three months ended June 30, 2022 to $111.26, compared with $64.93 for the same period in 2021. Weighted average NGL prices per Bbl increased during the three months ended June 30, 2022 to $47.29, compared with $26.77 for the same period in 2021. Weighted average natural gas prices per Mcf increased to $6.99 during the three months ended June 30, 2022, compared with $2.81 during the same period in 2021.

• | Cash provided by operating activities totaled $98.2 million for the three months ended June 30, 2022, compared with $35.9 million for the three months ended June 30, 2021.

Recent Events

Acquisitions. During the six months ended June 30, 2022, the Company incurred a total of $515.4 million in acquisition costs primarily related to a series of agreements to acquire various crude oil and natural gas properties contiguous to its Signal Peak and Flat Top operating areas in Howard and Borden counties, consisting of approximately 34,500 net acres and associated producing properties, water system infrastructure and in-field fluid gathering pipelines. Included in the acquisition costs is the issuance of 10,853,634 shares of HighPeak Energy common stock valued at $265.0 million on the respective closing dates of the Alamo Acquisitions and the Hannathon Acquisition. The acquisitions were accounted for as asset acquisitions and included approximately 31 gross (26.3 net) producing horizontal wells, 109 gross (87.8 net) producing vertical wells and six vertical salt-water disposal wells and related water system infrastructure as well as over 200 gross horizontal drilling locations targeting the Wolfcamp A, Wolfcamp D and Lower Spraberry formations.

Senior Unsecured Notes. In February 2022, the Company issued $225.0 million of two year 10.00% senior unsecured notes (“Senior Notes”), netting proceeds of $210.2 million net of an originator discount. The proceeds were used to pay off the Revolving Credit Facility and to fund a portion of the Company’s 2022 capital drilling program.

Revolving Credit Facility Amendment and Borrowing Base Increase. Simultaneous with the issuance of the Senior Notes in February 2022, the Company entered into the Third Amendment to the Revolving Credit Facility to, among other things, (i) reduce the borrowing base from $195.0 million to $138.8 million and (ii) modify the terms of the Credit Agreement to reduce the aggregate elected commitments from $195.0 million to $138.8 million. In June 2022, simultaneous with the closing of the Hannathon Acquisition, the Company entered into the Fourth Amendment to the Revolving Credit Facility 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 and (iv) increase the number of banks included in the syndicate at differing levels of commitments with Fifth Third remaining the administrative agent.

Dividends and dividend equivalents. In January 2022 and April 2022, the board of directors of the Company approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in a total of $2.4 million and $2.6 million in dividends being paid on February 25, 2022 and May 25, 2022, respectively. 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 and May 2022 and up to an additional $62,000 in August 2022, $4,000 in November 2022 and $4,000 in November 2023, assuming no forfeitures. In addition, the Company accrued an additional combined $105,000 in dividends on the restricted stock issued to management directors and certain employees of the Company that will be payable upon vesting in November 2024.

Issuance of Common Stock. During the six months ended June 30, 2022, the Company issued 10,853,634 shares of HighPeak Energy common stock related to the aforementioned crude oil and natural gas property acquisitions. On June 1, 2022, the Company issued 21,184 and 600,000 shares of restricted stock to outside directors and employees, respectively. The remaining 977,588 shares of HighPeak Energy common stock issued during the six months ended June 30, 2022 were the result of warrants (965,588 shares) and stock options (12,000 shares) being exercised.

Production Curtailment and Subsequent Increase. Throughout 2022, some of the Company’s production has been curtailed due to offset frac operations near a considerable amount of its existing producing horizontal wells. As wells are being brought back online, production has continued to increase subsequent to quarter end, setting up an expected increase in production for the third quarter of 2022.

COVID-19. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains and created significant volatility and disruption of financial and commodity markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices of crude oil and natural gas, which has adversely affected our business. There continues to be uncertainty around the extent and duration of disruption, including any resurgence, and we expect that the longer the period of such disruption continues, the greater the adverse impact will be on our business. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions taken by governmental authorities and third parties in response to the COVID-19 pandemic, its impact on the U.S. and world economies, the U.S. capital markets and market conditions, and how quickly and to what extent normal economic and operating conditions can resume.

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Derivative Financial Instruments

Derivative financial instrument exposure. As of June 30, 2022, the Company was a party to the following open derivative financial instruments.

|  | Remainder of 2022 |  |  | 2023 |
|  | Third |  |  | Fourth |  |  |  |  |  |  | First |  |  | Second |  |  |  |  |
|  | Quarter |  |  | Quarter |  |  | Total |  |  | Quarter |  |  | Quarter |  |  | Total |
Crude Oil Price Swaps - WTI: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MBbls) |  |  | 980.8 |  |  |  | 1,011.8 |  |  |  | 1,992.6 |  |  |  | 441.0 |  |  |  | 200.2 |  |  |  | 641.2 |
Price per Bbl |  | $ | 88.97 |  |  | $ | 86.13 |  |  | $ | 87.53 |  |  | $ | 70.05 |  |  | $ | 57.22 |  |  | $ | 66.04 |
Natural Gas Price Swaps - HH: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Volume (MMBtu) |  |  | 460.0 |  |  |  | 460.0 |  |  |  | 920.0 |  |  |  | 450.0 |  |  |  | — |  |  |  | 450.0 |
Price per MMBtu |  | $ | 9.00 |  |  | $ | 9.00 |  |  | $ | 9.00 |  |  | $ | 9.00 |  |  | $ | — |  |  | $ | 9.00 |

The estimated fair value of the outstanding open derivative financial instruments as of June 30, 2022 was a net liability of $31.9 million which is included in current assets and liabilities on the Company’s balance sheet as of June 30, 2022. During the six months ended June 30, 2022, the Company recognized a derivative loss of $78.3 million, including a $16.4 million mark-to-market loss plus $61.9 million related to monthly settlements.

Operations and Drilling Highlights

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

|  | Six Months Ended June 30, 2022 |
Crude Oil (Bbls) |  |  | 14,477 |
NGL (Bbls) |  |  | 1,570 |
Natural Gas (Mcf) |  |  | 6,023 |
Total (Boe) |  |  | 17,051 |

The Company's liquids production was 94 percent of total production on a Boe basis for the six months ended June 30, 2022.

Costs incurred are as follows (in thousands):

|  | Six Months Ended June 30, 2022 |
Unproved property acquisition costs |  | $ | 164,228 |
Proved acquisition costs |  |  | 351,202 |
Total acquisitions |  |  | 515,430 |
Development costs |  |  | 241,813 |
Exploration costs |  |  | 161,357 |
Total finding and development costs |  |  | 918,600 |
Asset retirement obligations |  |  | 3,682 |
Total costs incurred |  | $ | 922,282 |

The following table sets forth the total number of horizontal producing wells drilled and completed during the six months ended June 30, 2022:

|  | Drilled |  |  | Completed |
|  | Gross |  |  | Net |  |  | Gross |  |  | Net |
Flat Top area |  |  | 42 |  |  |  | 35.9 |  |  |  | 35 |  |  |  | 30.9 |
Signal Peak area |  |  | 12 |  |  |  | 11.9 |  |  |  | 7 |  |  |  | 6.9 |
Total |  |  | 54 |  |  |  | 47.8 |  |  |  | 42 |  |  |  | 37.8 |

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The Company was running six (6) drilling rigs as of June 30, 2022 and three (3) frac fleets. We plan to run six (6) drilling rigs and average approximately three (3) frac fleets for the remainder of the year. However, the scope, duration and magnitude of the direct and indirect effects of the COVID-19 pandemic and the war between Russia and Ukraine 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 six months ended June 30, 2022, the Company successfully completed and placed on production twenty-eight (28) gross horizontal wells in the Flat Top area and seven (7) gross horizontal wells in the Signal Peak area. The Company had forty (40) wells that had been drilled and were in various stages of completion as of June 30, 2022, thirty-three (33) of which are in the Flat Top area, including one (1) salt-water disposal well, and seven (7) of which are in the Signal Peak area. As of June 30, 2022, the Company was in the process of drilling eight (8) horizontal wells and one (1) salt-water disposal well in the Flat Top area and three (3) horizontal wells in the Signal Peak area.

Results of Operations

Three and Six Months Ended June 30, 2022

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

|  | Three Months Ended June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Oil (Bbls) |  |  | 18,858 |  |  |  | 7,951 |  |  |  | 137 | % |  |  | 14,477 |  |  |  | 6,352 |  |  |  | 128 | %
NGL (Bbls) |  |  | 1,939 |  |  |  | 502 |  |  |  | 286 | % |  |  | 1,570 |  |  |  | 399 |  |  |  | 293 | %
Natural Gas (Mcf) |  |  | 7,190 |  |  |  | 1,973 |  |  |  | 264 | % |  |  | 6,023 |  |  |  | 1,771 |  |  |  | 240 | %
Total (Boe) |  |  | 21,995 |  |  |  | 8,783 |  |  |  | 150 | % |  |  | 17,051 |  |  |  | 7,046 |  |  |  | 142 | %

The increase in average daily Boe sales volumes for the three and six months ended June 30, 2022, compared with the same periods in 2021 was due to the Company's successful horizontal drilling program and bolt-on acquisitions (excluding production from the recently completed Hannathon Acquisition which will not have an impact until the third quarter of 2022).

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 June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Oil per Bbl |  | $ | 111.26 |  |  | $ | 64.93 |  |  |  | 71 | % |  | $ | 106.04 |  |  | $ | 62.50 |  |  |  | 70 | %
NGL per Bbl |  | $ | 47.29 |  |  | $ | 26.77 |  |  |  | 77 | % |  | $ | 45.03 |  |  | $ | 27.16 |  |  |  | 66 | %
Gas per Mcf |  | $ | 6.99 |  |  | $ | 2.81 |  |  |  | 149 | % |  | $ | 6.15 |  |  | $ | 2.55 |  |  |  | 141 | %
Total per Boe |  | $ | 100.63 |  |  | $ | 60.40 |  |  |  | 67 | % |  | $ | 95.15 |  |  | $ | 58.01 |  |  |  | 64 | %

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 June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Oil and natural gas production costs |  | $ | 16,595 |  |  | $ | 4,692 |  |  |  | 254 | % |  | $ | 26,041 |  |  | $ | 6,919 |  |  |  | 276 | %
Oil and natural gas production costs per Boe |  | $ | 8.29 |  |  | $ | 5.87 |  |  |  | 41 | % |  | $ | 8.44 |  |  | $ | 5.43 |  |  |  | 55 | %

The increase in crude oil and natural gas production costs can primarily be attributed to the Company's successful horizontal drilling program bringing on a significant number of newly completed producing wells, additional rentals and fuel for power generation and bolt-on acquisitions. The increase in crude oil and natural gas production costs per Boe can be attributed to temporarily shutting in a considerable amount of production periodically for offset completion operations. However, operating expenses were not affected as significantly by the shut-ins as the production volumes were. We anticipate this increase in operating costs per Boe to reverse beginning in the third quarter of 2022. Significant drivers to this decrease are associated with connecting wells and central tank batteries to the electrical grid and removing rental power generators as well as increasing our daily production volumes.

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Production and ad valorem taxes.

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

|  | Three Months Ended June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Production and ad valorem taxes |  | $ | 10,301 |  |  | $ | 2,542 |  |  |  | 305 | % |  | $ | 15,307 |  |  | $ | 4,207 |  |  |  | 264 | %

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 June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Production taxes per Boe |  | $ | 4.82 |  |  | $ | 2.87 |  |  |  | 68 | % |  | $ | 4.56 |  |  | $ | 2.74 |  |  |  | 66 | %
Ad valorem taxes per Boe |  | $ | 0.33 |  |  | $ | 0.31 |  |  |  | 6 | % |  | $ | 0.40 |  |  | $ | 0.56 |  |  |  | (29 | )%

The increase in production taxes per Boe for the three and six months ended June 30, 2022, compared with the same periods in 2021, was primarily due to the 67% and 64% increase in realized prices, respectively. The decrease in ad valorem taxes per Boe for the six months ended June 30, 2022, compared with the same period in 2021, was primarily related to the new wells that came online during 2022. Ad valorem taxes in Texas are based on valuations as of January 1 of a given year based on pricing data for the previous year. Therefore, a well does not incur any ad valorem taxes until the year following when it came on production.

Exploration and abandonments expense.

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

|  | Three Months Ended June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Geologic and geophysical personnel costs |  | $ | 187 |  |  | $ | 143 |  |  |  | 31 | % |  | $ | 361 |  |  | $ | 285 |  |  |  | 27 | %
Geologic and geophysical data costs |  |  | — |  |  |  | 320 |  |  |  | (100 | )% |  |  | 35 |  |  |  | 320 |  |  |  | (89 | )%
Plugging and abandonment expense |  |  | (2 | ) |  |  | — |  |  |  | 100 | % |  |  | (2 | ) |  |  | — |  |  |  | 100 | %
Abandoned leasehold costs |  |  | (1 | ) |  |  | — |  |  |  | 100 | % |  |  | (1 | ) |  |  | 49 |  |  |  | (102 | )%
Exploration and abandonments expense |  | $ | 184 |  |  | $ | 463 |  |  |  | (60 | )% |  | $ | 393 |  |  | $ | 654 |  |  |  | (40 | )%

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 June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
DD&A expense |  | $ | 34,883 |  |  | $ | 16,857 |  |  |  | 107 | % |  | $ | 51,907 |  |  | $ | 29,820 |  |  |  | 74 | %
DD&A expense per Boe |  | $ | 17.43 |  |  | $ | 21.09 |  |  |  | (17 | )% |  | $ | 16.82 |  |  | $ | 23.38 |  |  |  | (28 | )%

The increase in DD&A is primarily due to the increased production associated with our successful horizontal drilling program and bolt-on acquisitions and the decrease in rate can be attributed to the same.

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 June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
General and administrative expense |  | $ | 2,016 |  |  | $ | 1,617 |  |  |  | 25 | % |  | $ | 3,956 |  |  | $ | 3,376 |  |  |  | 17 | %
General and administrative expense per Boe |  | $ | 1.01 |  |  | $ | 2.02 |  |  |  | (50 | )% |  | $ | 1.28 |  |  | $ | 2.65 |  |  |  | (52 | )%
Stock-based compensation expense |  | $ | 14,579 |  |  | $ | 1,023 |  |  |  | 1,325 | % |  | $ | 18,555 |  |  | $ | 1,989 |  |  |  | 833 | %

The increase in general and administrative expense for the three and six months ended June 30, 2022 is primarily as a result of adding new employees and increased salaries and benefits related to the growth of the Company. The decrease in the rate per Boe is the result of economies of scale and efficiencies gained as we bring additional wells on production due to our successful horizontal drilling program.

The increase in noncash stock-based compensation expense is primarily due to equity-based awards granted in May 2022 and late 2021.

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Interest expense.

|  | Three Months Ended June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Interest expense on Senior Notes |  | $ | 5,562 |  |  | $ | — |  |  |  | 100 | % |  | $ | 8,375 |  |  | $ | — |  |  |  | 100 | %
Interest expense on Revolving Credit Facility |  |  | 735 |  |  |  | 104 |  |  |  | 607 | % |  |  | 1,637 |  |  |  | 129 |  |  |  | 1,169 | %
Amortization of discount |  |  | 1,848 |  |  |  | 48 |  |  |  | 3,750 | % |  |  | 2,741 |  |  |  | 77 |  |  |  | 3,460 | %
Amortization of debt issuance costs |  |  | 1,137 |  |  |  | — |  |  |  | 100 | % |  |  | 1,781 |  |  |  | — |  |  |  | 100 | %
|  | $ | 9,282 |  |  | $ | 152 |  |  |  | 6,007 | % |  | $ | 14,534 |  |  | $ | 206 |  |  |  | 6,955 | %

The increase in interest expense can be attributed to the fact that we have continued to increase our borrowings under our Revolving Credit Facility, and we issued $225.0 million of 10.00% senior unsecured notes in February 2022 in support of our current 6-rig drilling program.

Derivative gain (loss), net.

|  | Three Months Ended June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Noncash derivative gain (loss), net |  | $ | 25,191 |  |  | $ | (12,558 | ) |  |  | (301 | %) |  | $ | (16,442 | ) |  | $ | (12,558 | ) |  |  | 31 | %
Cash payments on settled derivative instruments, net |  |  | (37,082 | ) |  |  | (1,038 | ) |  |  | 3,472 | % |  |  | (61,843 | ) |  |  | (1,038 | ) |  |  | 5,858 | %
Derivative gain (loss), net |  | $ | (11,891 | ) |  | $ | (13,596 | ) |  |  | (13 | %) |  | $ | (78,285 | ) |  | $ | (13,596 | ) |  |  | 476 | %

The Company primarily utilizes commodity swap contracts, collar contracts, collar contracts with short puts and basis swap contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) adhere to hedging obligations related to the senior unsecured notes and the Revolving Credit Facility, (iii) support the Company’s annual capital budget and expenditure plans and (iv) reduce commodity price risk associated with certain capital projects. The Company may also, from time to time, utilize interest rate contracts to reduce the effect of interest rate volatility on the Company’s indebtedness. The above mark-to-market loss and cash settlements relate to crude oil and natural gas derivative swap contracts.

Income tax expense.

|  | Three Months Ended June 30, |  |  |  |  |  |  | Six Months Ended June 30, |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | % Change |  |  | 2022 |  |  | 2021 |  |  | % Change |
Income tax expense (benefit) |  | $ | 24,072 |  |  | $ | 1,420 |  |  |  | 1,595 | % |  | $ | 23,760 |  |  | $ | 2,535 |  |  |  | 837 | %
Effective income tax rate |  |  | 23.7 | % |  |  | 19.8 | % |  |  | 20 | % |  |  | 28.0 | % |  |  | 19.5 | % |  |  | 44 | %

The change in income tax expense during the three and six months ended June 30, 2022, compared with the same periods in 2021, was due to the Company realizing increased net income during the three and six months ended June 30, 2022 compared with the same periods in 2021. 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. 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, (ii) net cash provided by operating activities, (iii) unused borrowing capacity under its Revolving Credit Facility, (iv) on an opportunistic basis, issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets. In February 2022, the Company entered into the Third Amendment to the Revolving Credit facility simultaneous with the issuance of $225.0 million of two year 10.00% senior unsecured notes (“2024 Notes”) whereby it, among other things, (i) reduced the borrowing base from $195.0 million to $138.8 million, (ii) modified the terms of the 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 will cause the Credit Agreement to mature on October 1, 2023 if the Senior Notes are not retired by that date, (iv) allow the Company to redeem the 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, simultaneous with the closing of one of the aforementioned acquisitions, the Company entered into the Fourth Amendment to the Revolving Credit Facility 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 amount of excess cash that may be held to $75.0 million, (iii) modify the affirmative hedging requirement and (iv) increase the number of banks included in the syndicate at differing levels of commitments with Fifth Third remaining the administrative agent. As of June 30, 2022, the Company had $285.0 million in borrowings and approximately $111.1 million available to borrow under its Revolving Credit Facility. The Company also had unrestricted cash on hand of $22.4 million as of June 30, 2022.

The Company's primary needs for cash are for (i) capital expenditures, (ii) acquisitions of crude oil and natural gas properties, (iii) payments of contractual obligations, (iv) working capital obligations, and (v) general corporate purposes. Funding for these cash needs may be provided by any combination of the Company's sources of liquidity. Although the Company expects that its sources of funding will be adequate to fund its 2022 planned capital expenditures and provide adequate liquidity to fund other needs, no assurance can be given that such funding sources will be adequate to meet the Company's future needs.

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2022 capital budget. The Company’s revised capital budget for 2022 after the announcement of the Hannathon acquisition is expected to be in the range of approximately $790 to $860 million for drilling, completion, facilities and equipping crude oil wells plus $35 to $40 million for field infrastructure buildout and other costs. The revised 2022 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 on its balance sheet, cash generated by operations, through borrowings under the Credit Agreement, proceeds from the issuance and sale of the 2024 Notes and, depending on market circumstances, potential future debt or equity offerings. The Company's capital expenditures for the six months ended June 30, 2022 were $403.2 million, excluding acquisitions.

The budget above assumes that the Company will operate six (6) drilling rigs and average approximately three (3) frac fleets for the remainder of 2022. However, there are many factors and consequences beyond the Company's control, such as policies of the Biden Administration, economic downturn or potential recession, 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. 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.

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

|  | Six Months Ended June 30, |  |  |  |  |  |  |  |  |
|  | 2022 |  |  | 2021 |  |  | Change |  |  | % Change |
Net cash provided by operating activities |  | $ | 148,186 |  |  | $ | 47,280 |  |  | $ | 100,906 |  |  |  | 213 | %
Net cash used in investing activities |  | $ | (549,145 | ) |  | $ | (76,867 | ) |  | $ | (472,278 | ) |  |  | 614 | %
Net cash provided by financing activities |  | $ | 388,507 |  |  | $ | 22,877 |  |  | $ | 365,630 |  |  |  | 1,598 | %

Operating activities. The increase in net cash flow provided by operating activities for the six months ended June 30, 2022, compared with 2021, was primarily related to higher revenues associated with increased production volumes as a result of our successful horizontal drilling program and bolt-on acquisitions and increased realized prices.

Investing activities. The increase in net cash used in investing activities for the six months ended June 30, 2022, compared with 2021, was primarily due to increases in additions to crude oil and natural gas properties compared with the six months ended June 30, 2021, when the Company had only one rig running compared with an average of four rigs running during the six months ended June 30, 2022, and increases in cash crude oil and natural gas acquisition costs.

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

| • | 2022: The Company received $210.2 million in net proceeds from the issuance of the 2024 Notes, borrowed net $185.0 million on its Revolving Credit Facility and received $7.8 million from the exercise of 965,588 of the Company’s $11.50 warrants and $120,000 from the exercise of 12,000 of stock options by employees of the Company. These cash inflows were partially offset by the Company incurring $9.1 million of debt issuance costs primarily related to the 2024 Notes and the Fourth Amendment to the Revolving Credit Facility and $5.4 million in dividends and dividend equivalent payments.
| • | 2021: The Company borrowed $14.0 million on its Revolving Credit Facility, received $9.1 million from the exercise of 788,009 of the Company’s $11.50 warrants and $1.6 million from the exercise of 154,268 of stock options by employees of the Company. Partially offsetting these cash inflows was the Company incurring $1.8 million of debt issuance costs related to its Revolving Credit Facility.

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 (loss) 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, derivative gains and losses net of settlements, gains and losses on divestitures and certain other items. EBITDAX excludes certain items that 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 Credit 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 analysis 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 (loss), income (loss) 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 (loss) and may vary among companies, the EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our Revolving Credit Facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total debt, as defined in the Credit Agreement, to EBITDAX, we would be in default, an event that would prevent us from borrowing under our Revolving Credit Facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our Revolving Credit Facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility 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 June 30, |  |  | Six Months Ended June 30, |
|  | 2022 |  |  | 2021 |  |  | 2022 |  |  | 2021 |
Net income |  | $ | 77,561 |  |  | $ | 5,743 |  |  | $ | 61,051 |  |  | $ | 10,487 |
Interest expense |  |  | 9,282 |  |  |  | 152 |  |  |  | 14,534 |  |  |  | 206 |
Interest and other income |  |  | (2 | ) |  |  | — |  |  |  | (252 | ) |  |  | (1 | )
Income tax expense |  |  | 24,072 |  |  |  | 1,420 |  |  |  | 23,760 |  |  |  | 2,535 |
Depletion, depreciation and amortization |  |  | 34,883 |  |  |  | 16,857 |  |  |  | 51,907 |  |  |  | 29,820 |
Accretion of discount |  |  | 66 |  |  |  | 37 |  |  |  | 120 |  |  |  | 72 |
Exploration and abandonment expense |  |  | 184 |  |  |  | 463 |  |  |  | 393 |  |  |  | 654 |
Stock based compensation |  |  | 14,579 |  |  |  | 1,023 |  |  |  | 18,555 |  |  |  | 1,989 |
Derivative-related noncash activity |  |  | (25,191 | ) |  |  | 12,558 |  |  |  | 16,442 |  |  |  | 12,558 |
Other expense |  |  | — |  |  |  | 127 |  |  |  | — |  |  |  | 127 |
EBITDAX |  | $ | 135,434 |  |  | $ | 38,380 |  |  | $ | 186,510 |  |  | $ | 58,447 |

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 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 six months ended June 30, 2022. 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 on Form 10-K for the year ended December 31, 2021, filed with the SEC on March 7, 2022.

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 June 30, 2022, 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 $8.91. Excluding derivatives, a $1.00 per barrel increase (decrease) in the weighted average crude oil price for the six months ended June 30, 2022 would have increased (decreased) the Company’s revenues by approximately $5.5 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the six months ended June 30, 2022 would have increased (decreased) the Company’s revenues by approximately $218,000 on an annualized basis.

Due to this volatility and obligations under the senior unsecured notes and the Revolving Credit Facility, the Company began to use, commodity derivative instruments, such as swaps, collars and puts, 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 has entered into hedging arrangements to protect its capital expenditure budget and to protect its Revolving Credit Facility borrowing base. The Company does not enter into any commodity derivative instruments, including derivatives, for speculative or trading purposes.

The average forward prices based on June 30, 2022 market quotes were as follows:

|  | Remainder of 2022 |  |  | Year Ending December 31, 2023 |
Average forward NYMEX crude oil price per Bbl |  | $ | 97.28 |  |  | $ | 86.46 |
Average forward NYMEX natural gas price per MMBtu |  | $ | 5.48 |  |  | $ | 4.70 |

The average forward prices based on August 4, 2022 market quotes were as follows:

|  | Remainder of 2022 |  |  | Year Ending December 31, 2023 |
Average forward NYMEX crude oil price per Bbl |  | $ | 86.07 |  |  | $ | 80.71 |
Average forward NYMEX natural gas price per MMBtu |  | $ | 8.18 |  |  | $ | 5.62 |

Counterparty and Customer Credit Risk. The Company’s derivative contracts expose it to credit risk in the event of nonperformance by counterparties. The Company’s collateral for the outstanding borrowings under the Revolving Credit Facility is also collateral for the Company’s commodity derivatives. The Company evaluates the credit standing of its counterparties as it deems appropriate. Counterparties to HighPeak Energy’s derivative contracts have investment grade ratings.

The Company’s primary concentration of credit risks is associated with (i) the collection of receivables resulting 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 and (ii) the risk of a counterparty’s failure to meet its obligations under derivative contracts with the Company. The inability or failure of the Company’s significant customers and/or counterparties to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company’s financial results.

The Company monitors exposure to customers and/or 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 customer and/or 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, NGL and natural gas receivables have not been material. 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. The Company is subject to interest rate risk on its variable rate debt from our Revolving Credit Facility. The Company also has fixed rate debt but does not currently utilize derivative instruments to manage the economic effect of changes in interest rates. The impact of a 1% increase in interest ratees on our outstanding debt as of June 30, 2022 would have resulted in an annual increase in interest expense of approximately $2.9 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 June 30, 2022 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,” as supplemented by our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. Except as set forth below, there has been no material change in the Company's risk factors that were described in the Company’s Annual Report.

Risks Related to Our Business

Political instability or armed conflict in crude oil or natural gas producing regions, such as the ongoing war between Russia and Ukraine, could have a material adverse impact on our business, financial condition or future results.

Our business, financial condition and future results are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in oil or gas producing areas such as the ongoing war between Russia and Ukraine.

In late February 2022, Russian military forces commenced a military operation and invasion against Ukraine. The United States and other countries and certain international organizations have imposed broad-ranging economic sanctions on Russia and certain Russian individuals, banking entities and corporations as a response, and additional sanctions may be imposed in the future. The length, impact, and outcome of the ongoing war between Russia and Ukraine is highly unpredictable, which has created uncertainty for financial and commodity markets. While the Company does not have operations overseas, the conflict elevates the likelihood of supply chain disruptions, heightened volatility in oil and gas prices and negative effects on our ability to raise additional capital when required and could have a material adverse impact on our business, financial condition or future results.

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.

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HIGHPEAK ENERGY, INC.

ITEM 6. EXHIBITS

Exhibit |
Number | Description
2.1# | Purchase and Sale Agreement, dated as of February 15, 2022, by and among HighPeak Energy, Inc., HighPeak Energy Assets, LLC, Alamo Borden County II, LLC, Alamo Borden County III, LLC and Alamo Borden County IV, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 23, 2022).
2.2# | Put/Call Agreement, dated as of February 15, 2022, by and among HighPeak Energy, Inc. HighPeak Energy Assets, LLC, Alamo Frac Holdings, LLC, Alamo Exploration and Production, LLC, Crocket Operating LLC, Alamo Borden County II, LLC, Alamo Borden County III, LLC, Alamo Borden County IV, LLC and the other parties signatory thereto (incorporated by reference to Exhibit 2.3 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 23, 2022).
2.3# | Purchase and Sale Agreement, dated as of April 26, 2022, by and among HighPeak Energy, Inc., HighPeak Energy Assets, LLC, Hannathon Petroleum, LLC and other sellers party thereto (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 30, 2022).
2.4# | Purchase and Sale Agreement, dated as of June 3, 2022, by and among HighPeak Energy Assets, LLC and Alamo Borden County 1, LLC (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 23, 2022).
3.1 | Amended and 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 August 27, 2020).
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).
4.4 | Indenture, dated February 16, 2022, by and among HighPeak Energy, Inc., the guarantors named therein and UMB Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on February 22, 2022).
4.5# | Registration Rights Agreement, dated as of June 27, 2022, by and among HighPeak Energy, Inc., Hannathon Petroleum, LLC, the parties listed as signatories hetero in their capacities as holders of Registrable Securities, and any Transferees thereof which hold Registrable Securities (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 30, 2022).

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10.1 | Fourth Amendment to Credit Agreement, dated as of June 27, 2022, by and among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on June 30, 2022).
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.
+ | Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K but will be furnished supplementally to the SEC upon request.
# | Pursuant to Regulation S-K, Item 601(b)(2), the Exhibits and Schedules to the Purchase Agreement referenced in Exhibit 2.1, Exhibit 2.2, Exhibit 2.3, Exhibit 2.4 and Exhibit 4.5, respectively, above, have not been filed. The registrant agrees to furnish supplementally a copy of any omitted Exhibit or Schedule to the SEC upon request; provided, however, that the registrant may request confidential treatment of omitted items. Further, certain portions of these exhibits have been omitted and include a prominent statement on the first page that certain identified information has been excluded from the exhibit because it is both (i) not material and (ii) is the type that the registrant treats as private or confidential as required by Item 601(b)(2)(ii) of Regulation S-K. Information that was omitted has been noted in the exhibit with a placeholder identified by the mark “[***]” to indicate where omissions have been made.

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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.
August 8, 2022 | By: | /s/ Steven Tholen
|  | Steven Tholen
|  | Chief Financial Officer
August 8, 2022 | By: | /s/ Keith Forbes
|  | Keith Forbes
|  | Vice President and Chief Accounting Officer

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