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

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

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included or incorporated by reference in this 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:

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.

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

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

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

HighPeak Energy, Inc. ("HighPeak Energy" the "Company," or the “Successor”) is a Delaware corporation, initially formed in October 2019 as a wholly owned subsidiary of Pure Acquisition Corp (“Pure”), a Delaware corporation, formed in November 2017, which was a special purpose acquisition company for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving Pure and one or more businesses. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 regarding the business combination which resulted in the Company becoming the parent company and Pure becoming a wholly owned subsidiary along with the businesses acquired.

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,” although the Company has applied for listing on the Nasdaq. 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.~~Basin in Eastern Howard County. Our acreage is composed of two core areas, Flat Top toin the ~~north~~northern portion of the county and Signal Peak toin the ~~south.~~southern portion of the county.

NOTE 2. Basis of Presentation and Summary of Significant Accounting Policies

Presentation. In the opinion of management, the unaudited interim condensed consolidated and combined financial statements of the Company as of ~~June~~September 30, 2021 and December 31, 2020 and for the three and ~~six~~nine months ended ~~June~~September 30, 2021and the period from August 22, 2020 through September 30, 2020 (Successor), and for the periods from ~~three~~July 1, 2020 through August 21, 2020 and ~~six~~January 1, 2020 ~~months ended~~through ~~June 30,~~August 21, 2020 (Predecessor) 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~~nine months ended ~~June~~September 30, 2021 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 and combined financial statements should be read together with the consolidated and combined financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

Principles of consolidation. The condensed consolidated and combined financial statements include the accounts of the Company and its wholly owned subsidiaries since August 22, 2020, and its Predecessors and their wholly owned subsidiaries since their acquisition or formation for all periods prior to and including August 21, 2020. 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 unaudited interim condensed consolidated and combined 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 and unproved 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. 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~~September 30, 2021 and December 31, 2020, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of ~~$16.3~~$19.6 million and $4.2 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, ~~joint interest receivables of $4.2 million and $345,000, respectively,~~ a current U.S. federal income tax receivable of $3.2 million and $3.2 million, respectively, and ~~other~~joint interest receivables of ~~$123,000~~$1.1 million and ~~zero~~,$345,000, 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~~September 30, 2021 and December 31, 2020, the Company had 0 allowance for doubtful accounts.

Subscription receivable. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) 505-10-45-2, “Receivables for Issuance of Equity,” the Company recorded a subscription receivable as of December 31, 2020 related to the exercise of warrants prior to December 31, 2020 as the cash was collected before the financial statements were issued or available to be issued. Prior to December 31, 2020, a total of 312,711 warrants were exercised for cash proceeds of $3.6 million. Due to the timing of the exercises, the shares underlying the warrants were issued in December 2020 and the proceeds were received subsequent to December 31, 2020. The outstanding proceeds were recorded as a subscription receivable in the accompanying balance sheets as of December 31, 2020. There is 0 subscription receivable as of ~~June~~September 30, 2021 as all cash related to exercises of warrants was received prior to the balance sheet date.

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, 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 condensed consolidated balance sheet and as charges to other expense in the condensed consolidated statements of operations. The Company’s materials and supplies inventory as of ~~June~~September 30, 2021 and December 31, 2020 is ~~$217,000~~$3.9 million and $121,000, respectively, and the Company has not recognized any valuation allowance to date.

~~Oil~~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 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 ~~and the capitalized costs of individual properties sold or abandoned~~ are credited to proved or unproved oil and ~~charged, respectively, to accumulated depletion, depreciation and amortization,~~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 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 ~~$334,000~~$385,000 and $237,000 as of ~~June~~September 30, 2021 and December 31, 2020, respectively, are as follows (in thousands):

Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Land is not depreciated. Information technology is generally depreciated over three years, transportation equipment is generally depreciated over five years and field equipment is generally depreciated over seven years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.

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

Aid-in-construction assets. As of September 30, 2021, the Company has aid-in-construction assets totaling $3.9 million, 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 gas to its processing facility. The Company agreed to incur the cost to construct the system in return for future payments based on gross throughput through the system, including any other 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.

Debt issuance costs. The Company has paid a total of $2.2 million in debt issuance costs, $1.8 million of which was incurred during the ~~six~~nine months ended ~~June~~September 30, 2021, related to its revolving credit facility. Amortization based on the straight-line method over the term of the revolving credit facility which approximates the effective interest method was ~~$77,000~~$259,000 and ~~zero~~0 during the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020, respectively. As of ~~June~~September 30, 2021, the net debt issuance costs are netted against the outstanding long-term debt on the accompanying balance sheet in accordance with GAAP. As of December 31, 2020, the net debt issuance costs are included in noncurrent assets on the accompanying consolidated balance sheet due to the fact that the revolving credit facility was undrawn at the time. See Note 7 for additional information regarding the Company’s revolving credit facility.

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 ~~liability.~~liabilities. See Note 10 for additional information.

Accounts payable, accrued liabilities, derivative liabilities and ~~derivative liabilities.~~accrued dividends and dividend equivalents. Accounts payable, accrued liabilities, derivative liabilities and ~~derivative~~accrued dividends and dividend equivalents included in current liabilities as of ~~June~~September 30, 2021 and December 31, 2020 totaled approximately ~~$54.3~~$77.0 million and $22.4 million, respectively, including trade accounts payable, derivative liabilities, accrued dividends and dividend equivalents, revenues payable and accruals for capital expenditures, operating and general and administrative expenses, operating leases 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 condensed consolidated and combined 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~~September 30, 2021 and December 31, 2020, the Company had receivables related to contracts with purchasers of approximately ~~$16.3~~$19.6 million and $4.2 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 and combined 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 of the Company’s derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the condensed consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current ofor noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.

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

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 for additional information.

Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the carrying amounts for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date.

The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all the deferred tax assets will not be realized. The Company has not established a valuation allowance as of ~~June~~September 30, 2021 and December 31, 2020.

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 addition information.

The Company records any tax-related interest charges as interest expense and any tax-related penalties as other expense in the condensed consolidated and combined statements of operations of which there have been none to date.

Prior to August 21, 2020, the Predecessors did not record a provision for U.S. federal income tax because the Predecessors were treated as partnerships for U.S. federal income tax purposes and, as such, the partners of the Predecessors reported their share of the Company’s income or loss on their respective income tax returns. The Predecessors were required to file tax returns on Form 1065 with the Internal Revenue Service (“IRS”). The 2017 to 2019 tax years remain open to examination.

The Predecessors recognize in their condensed consolidated and combined financial statements the effect of a tax position, if that position is more likely than not to be sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. Tax positions taken related to the Predecessors’ status as limited partnerships, and state filing requirements have been reviewed, and management is of the opinion that they would more likely than not be sustained by examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax benefits for periods prior to August 21, 2020. Under the new centralized partnership audit rules effective for tax years beginning after 2017, the IRS assesses and collects underpayments of tax from the partnership instead of from each partner. The partnership may be able to pass the adjustments through to its partners by making a push-out election or, if eligible, by electing out of the centralized partnership audit rules. The collection of tax from the partnership is only an administrative convenience for the IRS to collect any underpayment of income taxes including interest and penalties. Income taxes on partnership income, regardless of who pays the tax or when the tax is paid, is attributed to the partners. Any payment made by the Company as a result of an IRS examination will be treated as an expense from the Company in the condensed consolidated and combined financial statements.

The Company is also subject to Texas Margin Tax. The Company realized no Texas Margin Tax in the accompanying condensed consolidated and combined 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 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 1 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~~2019~~ ("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.

Adoption of new accounting standards. In December 2019, the FASB issued Accounting Standards Update (“ASU”) No. 2019-12, “Simplifying the Accounting for Income Taxes (Topic 740).” The new guidance simplifies the accounting for income taxes by eliminating certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period, hybrid taxes, and the recognition of deferred tax liabilities for outside basis differences. It also clarifies and simplifies other aspects of the accounting for income taxes. Amendments are to be applied prospectively, except for certain amendments that are to be applied either retrospectively or with a modified retrospective approach through a cumulative effect adjustment recorded to retained earnings. The Company adopted ASU 2019-12 on January 1, 2021, which did not have a material impact on the Company's condensed consolidated and combined financial statements.

New accounting pronouncements. In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), and in January 2021, issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of ~~June~~September 30, 2021, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. See Note 7 for discussion of the use of the London Interbank Offered Rate (“LIBOR”) in connection with borrowings under the Credit Agreement.

The Company has evaluated other recently issued, but not yet effective, accounting pronouncements and does not believe they would have a material effect on the Company’s condensed consolidated and combined financial statements.

Acquisitions. During the ~~six~~nine months ended ~~June~~September 30, 2021, ~~and~~ ~~2020,~~the Company incurred a total of ~~$2.1~~$53.3 million in multiple bolt-on acquisitions and ~~$3.3~~lease acquisitions to acquire a total of approximately 10,600 net acres in and around the Company’s existing properties for future exploration activities in the Midland Basin and non-operated working interests in approximately 10 gross (3.3 net) horizontal wells and 101 gross (18.6 net) vertical wells plus an interest in 2 gross (0.2 net) salt-water disposal wells and 3 gross (1.5 net) horizontal wells that were in the process of being drilled as of the closing date. During the nine months ended September 30, 2020, the Company incurred a total of $4.0 million ~~respectively,~~ to acquire primarily undeveloped acreage, ~~and in the case of the~~ ~~2020~~ ~~period,~~ 3 vertical producing ~~properties~~wells and 2 salt-water disposal wells in and around the Company’s existing properties for future exploration activities in the Midland Basin.

All of the aforementioned individual acquisitions that included producing properties were accounted for as asset acquisitions as substantially all of the gross assets acquired in each individual acquisition 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.

Grenadier Acquisition. In June 2019, HighPeak Energy Assets II, LLC (“HighPeak Assets II”) signed a purchase and sale agreement with Grenadier Energy Partners II, LLC (“Grenadier”) to acquire substantially all the crude oil and natural gas assets of Grenadier, effective June 1, 2019, subject to certain customary closing adjustments for a total purchase price of $615.0 million. Since HighPeak Assets II was contributed to the Predecessor in the HPK LP business combination, this purchase and sale agreement became part of the Predecessor effective October 1, 2019. A nonrefundable deposit of $61.5 million was paid to Grenadier in 2019 in addition to a $15.0 million nonrefundable extension payment in 2020 to extend the potential closing to May 2020. The Grenadier Acquisition was terminated in April 2020 and was not consummated and therefore a charge to expense of $76.5 million was recognized during the ~~six~~nine months ended ~~June~~September 30, 2020.

Divestitures. During the nine months ended September 30, 2021, the Company realized net proceeds of $3.2 million, which reduced the Company’s proved properties with 0 gain or loss recognized when it divested of 1 gross (0.2 net) non-operated horizontal well and acquired 4 gross (3.7 gross) operated vertical wells in a trade with another operator whereby the Company traded an approximate equal number of net mineral acres to increase its working interest in certain areas of Flat Top where it serves as operator and decrease its working interest in other areas of Flat Top where the other party serves as operator.

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.

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~~September 30, 2021 are as follows (in thousands):

The Company did not have any assets or liabilities that are measured at fair value on a recurring basis as of December 31, 2020.

Commodity price derivatives. The Company’s commodity price derivatives are currently made up entirely of crude oil 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 condensed consolidated and combined financial statements.

The Company has other financial instruments consisting primarily of cash equivalents, accounts receivable, accounts payable, long-term debt and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities.

Impact of the COVID-19 pandemic on certain assets and liabilities measured at fair value on a nonrecurring basis.

Proved Properties. The Company performs assessments of its 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.

The Company performed an impairment assessment of its proved crude oil and natural gas properties as of ~~June~~September 30, 2021 and December 31, 2020 and determined that its proved crude oil and natural gas properties were not impaired. The primary factors that may affect estimates of future cash flows for the Company's proved crude oil and natural gas properties are (i) future reserve adjustments, both positive and negative, to proved reserves and risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's price outlooks and (iv) increases or decreases in production and capital costs.

There is significant uncertainty surrounding the long-term impact to global crude oil demand due to the effects of the COVID-19 pandemic. It is reasonably possible that the carrying value of the Company's proved crude oil and natural gas properties could exceed their estimated fair value resulting in the need to impair their carrying values in the future. If incurred, an impairment of the Company's proved crude oil and natural gas properties could have a material adverse effect on the Company's financial condition and results of operations.

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 and (iii) support the payment of contractual obligations.

The following table summarizes the effect of derivatives on the Company’s condensed consolidated statements of operations:

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~~September 30, 2021 and the weighted average crude oil prices per barrel for those contracts are as follows:

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 are all with Fifth Third Bank, National Association (“Fifth Third”) as of ~~June~~September 30, 2021.

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 condensed 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):

All capitalized exploratory well costs have been capitalized for less than one year based on the date of drilling.

The components of long-term debt, including the effects of debt issuance costs, are as follows (in thousands):

Revolving Credit Facility. In December 2020, the Company entered into a Credit Agreement with Fifth Third as the administrative agent and sole lender to establish a revolving credit facility (“Revolving Credit Facility”) that matures on June 17, 2024. 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 the Credit Agreement 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~~$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 the Credit Agreement 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) modified the terms of the Credit Agreement to increase the aggregate elected commitments from $125.0 million to $195.0 million. The syndicate of banks in the credit facility remained the same, although commitment percentages changed slightly 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 ~~currently~~ stands at $125.0 ~~million)~~million as of September 30, 2021, increased to $195.0 million on October 1, 2021), ~~(ii)~~(ii) the aggregate elected commitments (which ~~currently~~ stand at $125.0 ~~million)~~ million as of September 30, 2021, increased to $195.0 million on October 1, 2021) and (iii) $500.0 million. As of ~~June~~September 30, 2021 and December 31, 2020, the Company had ~~$14.0~~$95.0 million and zero, respectively, outstanding borrowings under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear 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 or (iii) the Adjusted LIBOR Rate, plus a margin (the “Applicable Margin”), which is ~~currently 3.25~~4.00 percent as of September 30, 2021, dropping to 3.5 percent on October 1, 2021 and which is ~~also~~ determined by the Borrowing Base Utilization Percentage as defined in the Revolving Credit Facility. 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 Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. See Note 2 for reference rate reform.

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 ~~(commencing with the fiscal quarter ending~~ ~~June 30, 2021)~~ 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 Revolving Credit Agreement) is in excess of $20.0 million. In addition, the Revolving 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.

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.

As of ~~June~~September 30, 2021 and December 31, 2020, all asset retirement obligations are considered noncurrent and classified as such in the accompanying consolidated balance sheet.

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"). As of October 1, 2020, 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~~nine months ended ~~June~~September 30, 2021 and 2020, the Company contributed ~~$111,000~~$167,000 and zero to the 401(k) Plan, respectively.

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

Stock Options. Stock option awards were granted to employees on August 24, 2020. Stock-based compensation expense related to the Company’s stock option awards for the ~~six~~nine months ended ~~June~~September 30, 2021 and 2020 was ~~$1.9~~$2.7 million and ~~zero~~,$14.5 million, respectively, and as of ~~June~~September 30, 2021 and December 31, 2020 there was ~~$1.9~~$1.2 million and $3.8 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~~one ~~years.~~year.

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

Stock Issued to Directors. 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 vest on the one-year anniversary of such grant assuming the director remains in his or her position as of the anniversary date. ~~Out of the 67,779 shares of restricted stock granted, 52,883 were issued during~~ ~~June 2021~~ ~~and 14,896 shares were issued in~~ ~~July 2021.~~ Therefore, stock-based compensation expense of ~~$57,000~~$228,000 was recognized during the ~~six~~nine months ended ~~June~~September 30, 2021, and the remaining ~~$626,000~~$455,000 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 was issued to the outside directors of the Company in November 2020 in the amount of 12,500 shares for each outside director, totaling 62,500 shares. There were no restrictions of these shares. Therefore stock-based compensation expense was recognized immediately upon the issuance of these shares in the amount of $302,000 which was based upon the closing price of the stock on the date the stock issuance was approved by the board of directors of the Company.

Leases. The Company adopted ASC Topic 842, “Leases” electing the transition method which permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company elected this transition approach, however the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2020 was zero. Therefore, as of ~~June~~September 30, 2021 the Company had right-of-use assets totaling ~~$236,000~~$987,000 included in other noncurrent assets and operating lease liabilities totaling ~~$239,000, $213,000~~$990,000, $534,000 of which are included in other current liabilities and ~~$26,000~~$456,000 of which are included in other noncurrent liabilities, and as of December 31, 2020 the Company had right-of-use assets totaling $506,000 included in other noncurrent assets and operating lease liabilities totaling $508,000, $430,000 of which are included in other current liabilities and $78,000 of which are included in other noncurrent liabilities on the accompanying condensed consolidated balance sheets. The Company does not currently have any finance right-of-use leases. Maturities of the operating lease obligations are as follows (in thousands):

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 ~~that~~ 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.

Salt-Water Disposal Commitments. The Company has committed to deliver a total of 3.0 MMBbl of produced water for disposal with a third-party salt-water disposal company between July 24, 2020 and July 24, 2022. As of ~~June~~September 30, 2021, the Company has delivered approximately ~~1.7~~2.2 MMBbl under the agreement. The agreement requires a payment for any volumes not delivered should the Company not perform under the agreement, indicating a remaining monetary commitment of approximately ~~$603,000~~$367,000 as of ~~June~~September 30, 2021.

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 its horizontal wells in Flat Top where DKL will construct ana crude oil gathering system and custody transfer meters to 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. The remaining monetary commitment as of ~~June~~September 30, 2021, if the Company never delivers any additional volumes under the agreement, is approximately $25.4 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. ~~In exchange for the improved pricing terms and expansion of the gathering system, the~~The Company will provide WTG with certain aid-in-construction ~~payments.~~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 will be interconnected with the ERCOT transmission grid via the local electric utility, have an initial capacity of up to 50 megavolt amperes and be 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.

General and Administrative Expenses. The general partner of HPK LP utilized HighPeak Energy Management, LLC (the “Management Company”) to provide services and assistance to conduct, direct and exercise full control over the activities of HPK LP per its Partnership Agreement. However, the Management Company is funded via payments from the parent companies of HighPeak I and HighPeak II pursuant to their respective Limited Partnership Agreements, as amended. Therefore, HPK LP reimbursed the parent companies of HighPeak I and HighPeak II for actual costs incurred by the Management Company. During the ~~six~~nine months ended ~~June~~September 30, 2020, HPK LP paid ~~$3.8~~$2.4 million each to the parent companies of HighPeak I and HighPeak II of which ~~$4.1~~$4.7 million is included in general and administrative expenses in the accompanying results of operations for the ~~six~~nine months ended ~~June~~September 30, 2020. Effective upon closing of the HighPeak business combination, the Management Company is no longer being paid by the Company as all costs directly attributable to the Company are paid by the Company going forward.

Lion Oil Trading and Transportation, LLC (“Lion”) accounted for approximately ~~95%~~94% of the Company’s revenues during the ~~six~~nine months ended ~~June~~September 30, 2021. Lion and Enlink Crude Purchasing, LLC ~~and Lion~~ accounted for approximately ~~76%~~67% and ~~16%~~28%, respectively, of the Company’s revenues during the ~~six~~nine months ended ~~June~~September 30, 2020. Based on the current demand for crude oil and natural gas and the availability of other purchasers, management believes the loss of these major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

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

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):

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~~September 30, 2021 and December 31, 2020 (in thousands):

The effective income tax rate differs from the U.S. statutory rate of 21 percent primarily due to permanent differences between GAAP income and taxable income. Periods prior to August 22, 2020 are not shown because the Predecessors were treated as partnerships for U.S. federal income tax purposes and therefore do not record a provision for U.S. federal income tax because the partners of the Predecessors report their share of the Predecessors’ income or loss on their respective income tax returns. The Predecessors are required to file tax returns on Form 1065 with the IRS. The 2017 through 2020 tax years remain open to examination.

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~~September 30, 2021 and December 31, 2020, the Company has not recorded a valuation allowance for deferred tax assets arising from its operations because the Company believes they meet the “more likely than not” criteria as defined by the recognition and measurement provisions of ASC 740. However, the Company may not realize the ~~$22.9~~$7.8 million and $12.9 million in deferred tax assets it has as of ~~June~~September 30, 2021 and December 31, 2020, respectively, if the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company's deferred tax assets change, which would affect the Company’s effective income tax rate and cash flows in the period of discovery or resolution.

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~~nine months ended ~~June~~September 30, 2021 under the two-class method (in thousands):

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

Dividends and dividend equivalents. In July 2021, the board of directors of the Company approved a quarterly dividend of $0.025 and a special dividend of $0.075 per share of common stock outstanding which resulted in a total of $9.3 million in dividends being paid on July 26, 2021. 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 $829,000 during the nine months ended September 30, 2021 and up to an additional $125,000 in August 2022, assuming no forfeitures.

In September 2021, the board of directors of the Company approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in accrued dividends payable included in current liabilities as of September 30, 2021 of $2.3 million to be paid on October 25, 2021. In addition, under terms of the LTIP, the Company accrued a dividend equivalent per share to all vested stock option holders and a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total of $207,000 to be paid in October 2021 and up to an additional $31,000 in August 2022, assuming no forfeitures.

Outstanding Securities. At ~~June~~September 30, 2021 and December 31, 2020, the Company had ~~92,728,781~~92,743,677 and 91,967,565 shares of common stock outstanding, respectively, 9,500,174 and 10,225,472 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 I and 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.

Allocation of partner’s net profits and losses. Net income or loss and net gain or loss on investments of the Predecessor for the period are allocated among its partners in proportion to the relative capital contributions made to the Predecessor. The Predecessor realized a net loss of $85.0 million for the period from ~~six~~January 1, 2020 ~~months ended~~through ~~June 30,~~August 21, 2020.

Partner’s distributions. The proceeds distributable by the Predecessor (which shall include all proceeds attributable to the disposition of investments, net of expenses) is distributable in accordance with their respective Partnership Agreements. The Predecessor made distributions to partners of $2.8 million during the period from January 1, 2020 through August 21, 2020.

~~WTG aid-in-construction.~~Dividends and dividend equivalents. InAs previously discussed, in ~~July~~October 2021, the Company paid $3.9 million to WTG related to an aid-in-construction payment pursuant to the aforementioned replacement natural gas purchase contract for WTG to construct a low-pressure natural gas gathering system throughout the Company’s Flat Top area.

~~Acquisitions.~~ In ~~July 2021,~~ ~~the Company signed multiple unrelated purchase and sale agreements to effect certain bolt-on acquisitions from various~~ ~~third~~ parties. In the aggregate, the assets being acquired represent approximately 6,200 net acres and working interests in producing properties and salt-water disposal wells. The Company expects to close these acquisitions later in the ~~third~~ ~~quarter of~~ ~~2021.~~

~~Dividends and dividend equivalents.~~ In ~~July 2021,~~ ~~the board of directors of the Company approved~~ a quarterly dividend of $0.025 ~~and a special dividend of $0.075~~ per share of common stock outstanding which resulted in a total of ~~$9.3~~$2.3 million in dividends being paid on ~~July 26,~~October 25, 2021. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of ~~$705,000~~$207,000 in ~~July~~October 2021 and will accrue a dividend equivalent per share to all unvested stock option holders which is payable upon vesting of up to an additional ~~$125,000~~$31,000 in ~~each of~~ ~~August 2021~~ ~~and~~ August 2022, assuming no forfeitures.

Revolving Credit Facility. Also as previously discussed, in October 2021, the Company entered into the Second Amendment to the Credit Agreement 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) modified the terms of the Credit Agreement to increase the aggregate elected commitments from $125.0 million to $195.0 million. The syndicate of banks in the credit facility remained the same, although commitment percentages changed slightly with Fifth Third remaining the administrative agent.

Public Offering of Common Stock. On October 25, 2021, the Company completed the offering of 2,530,000 shares of its common stock, at a price to the public of $10.00 per share, pursuant to a registration statement on Form S-1 filed with the Securities and Exchange Commission on October 19, 2021. The net proceeds to the Company from the offering, after deducting the underwriting discounts and commissions and other offering expenses, were approximately $23.0 million. The Company intends to use the net proceeds of this offering for general corporate purposes, which may include accelerating its drilling and development activities and funding additional bolt-on acquisitions.

Derivative financial instruments. In October 2021, the Company entered into additional crude oil derivative financial instruments with other counterparties that are included in our syndicate of banks associated with our Revolving Credit Facility. After giving effect to these new contracts, the Company’s outstanding crude oil derivative contracts and the weighted average crude oil prices per barrel for those contracts are as follows:

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 and combined 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 solely for the purpose of combining the businesses of Pure and HPK LP, referred to herein as the “HighPeak business combination,” which was completed on August 21, 2020. HPK LP was formed in August 2019 for the purpose combining the assets of HighPeak I and HighPeak II into one entity. HighPeak I was formed in June 2014 for the purpose of acquiring, exploring and developing crude oil and natural gas properties, although it had no activity until 2017. Beginning in late 2017, HighPeak I began acquiring its assets through an organic leasing campaign and a series of acquisitions consisting primarily of leasehold acreage and existing vertical producing wells.

The Company’s assets are located primarily in Howard County, Texas, which lies within the northeastern part of the crude oil-rich Midland Basin. As of ~~June~~September 30, 2021, the assets consisted of two highly contiguous leasehold positions of approximately ~~58,771~~79,218 gross ~~(51,875~~(62,019 net) acres, approximately ~~59%~~46% of which were held by production, with an average working interest of ~~88%~~78%. Our acreage is composed of two core areas, Flat Top to the north and Signal Peak to the south. Approximately ~~97%~~98% of the operated acreage provides for horizontal wells with lateral lengths of 10,000 feet or greater. For the ~~six~~nine months ended ~~June~~September 30, 2021, approximately ~~96%~~95% and 4%5% of production from the assets were attributable to liquids (both crude oil and NGL) and natural gas, respectively. As of ~~June~~September 30, 2021, HighPeak Energy was drilling with ~~one (1) rig.~~two (2) drilling rigs and was participating in a 3-well pad of horizontal wells being drilled by another operator. We are the operator on approximately ~~95%~~92% of the net acreage across our assets. Further, as of ~~June~~September 30, 2021, ~~there were~~the Company has an ownership interest in approximately ~~123~~241 gross ~~(69.8~~(101.1 net) producing wells, including 3451 gross ~~(32.0~~(43.3 net) horizontal wells, with total sales volumes net to the Company averaging ~~8,783~~10,355 Boe/d during the ~~second quarter~~month of ~~2021.~~September 2021, including wells in which the Company serves as operator of approximately 75 gross (67.8 net) producing wells, including 40 gross (39.0 net) horizontal wells. In addition, as of ~~June~~September 30, 2021, the Company was in the process of drilling ~~one (1) well~~four (4) wells and was in various stages of completing ~~ten (10) wells.~~six (6) wells, including wells operated by other operators.

The financial results as presented in this section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” consist of the historical results of the Company for the three and ~~six~~nine months ended ~~June~~September 30, 2021 and the period from August 22, 2020 through September 30, 2020 and HPK LP for the ~~three~~periods from January 1, 2020 and ~~six months ended June 30,~~July 1, 2020 through August 21, 2020. At the Closing of the HighPeak business combination on August 21, 2020, the Company’s “predecessors” for accounting purposes were HPK LP for the period from October 1, 2019 through August 21, 2020 and HighPeak I from January 1, 2017 through September 30, 2019 (collectively, the “Predecessors”).

Outlook

HighPeak Energy’s financial position and future prospects, including its revenues, operating results, profitability, liquidity, future growth and the value of its assets, depend primarily on prevailing commodity prices. The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2018 through ~~June~~September 30, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 in April 2020 to a high of ~~$71.35~~$72.43 in ~~June~~July 2021, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 to a high of $4.72. Due to the absence of any debt, the Company has not historically entered into any hedges. With the addition of the Revolving Credit Facility in December 2020, HighPeak Energy entered into hedging arrangements in the second quarter of 2021, prior to borrowing under the Revolving Credit Facility late in the second quarter of 2021.

Financial and Operating Performance

The Company's financial and operating performance for the three months ended ~~June~~September 30, 2021 included the following highlights:

•

Net income was ~~$5.7~~$8.0 million ($~~0.06~~0.08 per diluted share) for the three months ended September 30, 2021 compared with a combined net loss of the ~~Company’s~~Company and its Predecessor of ~~$4.1~~$11.6 million for three months ended ~~June~~September 30, ~~2021 and 2020, respectively.~~2020. The primary components of the ~~$9.9~~$19.6 million increase in net income include:

•

a ~~$47.3~~$40.0 million increase in crude oil, NGL and natural gas revenues due to a ~~1,059%~~277% increase in daily sales volumes resulting from the Company’s successful horizontal drilling program ~~coupled with the fact that the Company shut-in the majority of its production starting in the second quarter of 2020 due to the impact COVID-19 had on global energy prices,~~and bolt-on acquisitions in addition to a ~~341%~~68% increase in average realized commodity prices per Boe, excluding the effects of derivatives; and

•

a $13.6 million decrease in stock-based compensation expense related to stock options that were granted in August 2020 upon the Company’s going public;

partially offset by:

•

a ~~$15.1~~$10.8 million increase in the Company's net derivative loss as a result of its crude oil commodity contracts entered into during 2021 and the continued increase of crude oil prices thereafter;

•

a $10.3 million increase in depletion, depreciation and amortization expense due to the 1,059% increase in overall sales volumes, plus a 16% decrease in the depletion, depreciation and amortization rate from $25.15 to $21.09 per Boe, primarily as a result of increased proved reserves due to recently completed successful extension wells;

•

a ~~$13.6~~$5.4 million increase in the Company's ~~net derivative loss as a result of its~~ crude ~~oil commodity contracts entered into during the second quarter of 2021 and the continued increase of crude oil prices thereafter;~~

•

~~a $2.9 million increase in the Company's~~ oil and natural gas production costs due to the Company’s successful horizontal development program ~~coupled with the fact that the Company shut-in the majority of its production starting in the second quarter of 2020 due to the impact COVID-19 had on global energy prices;~~and bolt-on acquisitions;

•

a ~~$2.4~~$4.5 million increase in the Company’s income tax expense due to the net income realized during the three months ended September 30, 2021 compared to a net loss realized during the period from August 22, 2020 through September 30, 2020 and the fact that the Predecessor was a pass through entity for income tax purposes and did not recognize any tax expense or benefit on their financial statements for the period from July 1, 2020 through August 21, 2020;

•

a $1.4 million increase in production and ad valorem taxes due partially to an increase in production taxes per Boe from ~~$0.64~~$1.73 to ~~$2.87,~~$3.03, or ~~348%~~77%, due to higher overall realized prices, excluding the effects of derivatives, of ~~341%~~68% partially offset by a decrease in ad valorem taxes per Boe from ~~$0.73~~$0.38 to ~~$0.31, or 58%,~~a negative $0.66, primarily because 2021 ad valorem taxes were based on 2020 prices, which were much lower due to the impact COVID-19 had on global energy prices. 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;~~

•

~~a $1.4 million increase in the Company’s income tax expense~~year. Even with this decrease due to prices, our initial estimates in early 2021 were too high resulting in an over accrual as of June 30, 2021. In early 2021, we hired a third-party ad valorem tax specialist to aid in our evaluation and negotiation of valuations for ad valorem tax purposes which allowed us to further significantly reduce our ad valorem taxes for 2021. Thus, the ~~net income realized~~over accrual from June 30, 2021 was reversed during the three months ended ~~June 30, 2021 and the fact that the Predecessor was a pass through entity for income tax purposes and did not recognize any tax expense or benefit on their financial statements;~~

•

a $1.0 million increase in stock-based compensation expense related to stock options that were granted in August 2020 upon the Company’s going public and restricted stock issued to outside directors during the three months ended JuneSeptember 30, 2021;

•

a ~~$462,000~~$947,000 increase in interest expense due to borrowings on the revolving credit facility and amortization of debt issuance costs in 2021 compared to none in the prior year;

•

a $422,000 increase in exploration and abandonment expenses primarily as a result of the write off of some small undeveloped leases that we chose not to extend, increased geologic and geophysical data expenses ~~plus exploration general~~ and ~~administrative expenses~~an increase in geologic and geophysical personnel costs being classified as a part of exploration and abandonment expense that are now identifiable and not merely a component of administration fees paid to a management company; and

•

a $283,000 increase in general and administrative expenses primarily as a result of increased personnel and costs associated with being a public company.

•

During the three months ended ~~June~~September 30 2021, average daily sales volumes totaled ~~8,783~~8,168 Boe/d, compared with ~~758~~2,165 Boe/d during the same period in 2020, an increase of ~~1,059%~~277% over the same period in 2020, due to the Company's successful horizontal drilling program in the Permian Basin and ~~due to the fact that the Company shut-in the majority of its production starting in the second quarter of 2020 due to the impact COVID-19 had on global energy prices.~~bolt-on acquisitions.

•

Weighted average realized crude oil prices per Bbl, excluding the effects of derivatives, increased during the three months ended ~~June~~September 30, 2021 to ~~$64.93,~~$69.84, compared with ~~$15.61~~$39.19 for the same period in 2020. Weighted average NGL prices per Bbl increased during the three months ended ~~June~~September 30, 2021 to ~~$26.77,~~$35.83, compared with ~~$4.55~~$9.03 for the same period in 2020. Weighted average natural gas prices per Mcf increased to ~~$2.81~~$3.69 during the three months ended ~~June~~September 30, 2021, compared with ~~($0.03)~~$2.30 during the same period in 2020.

•	Cash provided by operating activities totaled ~~$35.9~~$40.5 million for the three months ended ~~June~~September 30, 2021, compared with cash used in operating activities of ~~$4.8~~$1.9 million for the three months ended ~~June~~September 30, 2020.

Recent Events

Revolving Credit Facility. The Company entered into its Revolving Credit Facility in December 2020 which was amended ~~and restated~~ in June 2021 and asagain in October 2021. As of ~~June~~September 30, 2021, the Company had ~~$14.0~~$95.0 million drawn on the Revolving Credit Facility. In connection with the First Amendment in June 2021, the Company’s borrowing base and elected commitments were increased to $125.0 million and a syndicate of banks was added to the facility at various levels of participation and commitment. In connection with the Second Amendment in October 2021, the Company’s borrowing base and elected commitments were increased to $195.0 million.

Exercises of Warrants and Options. During the ~~six~~nine months ended ~~June~~September 30, 2021, the Company received cash of $9.1 million related to the exercise of 788,009 of its $11.50 warrants and $1.6 million cash related to the exercise of 154,268 of stock options by employees of the Company.

Crude oil marketing contract. In May 2021, the Company entered into a crude oil marketing contract with Lion Oil Trading and Transportation, LLC (“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 its horizontal wells in Flat Top where DKL will construct ana crude oil gathering system and custody transfer meters to all the Company’s central tank batteries. This system will reduce the Company’s cost to transport its crude oil to market and significantly reduce the trucking traffic in and around our development at Flat Top. 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. The remaining monetary commitment as of ~~June~~September 30, 2021, if the Company never delivers any additional volumes under the agreement, is approximately $25.4 million. The Company believes it will meet its minimum volume commitments based on the Company’s current gross production levels and the current Flat Top development plan.

Natural gas purchasing replacement contract. In May 2021, the Company entered into a replacement 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. ~~In exchange for the improved pricing terms and expansion of the gathering system, the~~The Company will provide WTG with certain aid-in-construction payments. The replacement contract does not contain minimum volume commitments. Once operational, the expanded natural gas gathering system will reduce flaring and the emission of greenhouse gases.

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 will be interconnected with the ERCOT transmission grid via the local electric utility, have an initial capacity of up to 50 megavolt amperes and be 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. Over the life of the contract, approximately 263 million kilowatt-hours of clean and reliable solar energy will be delivered to the Company, resulting in an estimated reduction of over 100,000 metric tons of CO2 emissions according to the Environmental Protection Agency.

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. The Company anticipates being able to meet this requirement once the system is operational and be able to terminate the letter of credit.

WTG aid-in-construction. In July 2021, the Company paid $3.9 million to WTG related to an aid-in-construction payment ~~pursuant to~~in connection with the aforementioned replacement natural gas purchase contract for WTG to construct a low-pressure natural gas gathering system throughout the Company’s Flat Top area.

Acquisitions. ~~In July~~During the three months ended September 30, 2021, the Company ~~signed~~closed multiple ~~unrelated purchase~~bolt-on acquisitions and ~~sale agreements to effect certain bolt-on~~lease acquisitions from various third parties. In the aggregate, the assets ~~being~~ acquired represent approximately ~~6,200~~10,600 net acres and working interests in producing properties and salt-water disposal wells that are estimated to average approximately 1,400 Boe/d for the remainder ~~of 2021. The Company expects to close these acquisitions later in the third quarter~~ of 2021.

Dividends and dividend equivalents. In July 2021, the board of directors of the Company approved a quarterly dividend of $0.025 and a special dividend of $0.075 per share of common stock outstanding which resulted in a total of $9.3 million in dividends being paid on July 26, 2021. In addition, under the terms of the LTIP, the Company ~~will also pay~~paid a dividend equivalent per share to all vested stock option holders and ~~accrue~~accrued a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total payment of $705,000 and $125,000 in July 2021 and August 2021, respectively, and up to an additional $125,000 in ~~each of August 2021 and~~ August 2022, assuming no forfeitures.

In September 2021, the board of directors of the Company approved a quarterly dividend of $0.025 per share of common stock outstanding which resulted in accrued dividends payable included in current liabilities as of September 30, 2021 of $2.3 million to be paid on October 25, 2021. In addition, under terms of the LTIP, the Company accrued a dividend equivalent per share to all vested stock option holders and a dividend equivalent per share to all unvested stock option holders payable upon vesting, which equates to a total of $207,000 to be paid in October 2021 and up to an additional $31,000 in August 2022, assuming no forfeitures.

Public Offering of Common Stock. On October 25, 2021, the Company completed the offering of 2,530,000 shares of its common stock, at a price to the public of $10.00 per share, pursuant to a registration statement on Form S-1 filed with the Securities and Exchange Commission on October 19, 2021. The net proceeds to the Company from the offering, after deducting the underwriting discounts and commissions and other offering expenses, were approximately $23.0 million. The Company intends to use the net proceeds of this offering for general corporate purposes, which may include accelerating its drilling and development activities and funding additional bolt-on acquisitions.

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.

Derivative Financial Instruments

Derivative financial instrument exposure. As of ~~June~~September 30, 2021, the Company was a party to the following open derivative financial instruments.

2021

2022

Third
Quarter

Fourth
Quarter

Total

First
Quarter

Second
Quarter

Total

Oil Price Swaps

Volume (Bbls)
460,000 460,000 920,000 450,000 302,500 752,500
Price per Bbl
$ 61.91 $ 61.91 $ 61.91 $ 61.91 $ 62.16 $ 61.95

	2021		2022										2023
	Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total		First Quarter		Second Quarter		Total
Crude Oil Price Swaps - WTI: (a)
Volume (MBbls)		460.0		450.0		302.5		66.0		202.4		1,020.9		198.0		200.2		398.2
Price per Bbl	$	61.91	$	61.91	$	62.16	$	57.22	$	57.22	$	60.75	$	57.22	$	57.22	$	57.22

The estimated fair value of the outstanding open derivative financial instruments as of ~~June~~September 30, 2021 was ~~$12.6~~$19.4 million which is included in current and noncurrent liabilities on the Company’s balance sheet as of ~~June~~September 30, 2021. During the three months ended ~~June~~September 30, 2021, the Company recognized a derivative loss of ~~$13.6~~$10.8 million, including ~~the aforementioned $12.6~~a $6.8 million mark-to-market ~~liability~~loss plus ~~$1.0~~$4.0 million in payments related to monthly settlements. During the nine months ended September 30, 2021, the Company recognized a derivative loss of $24.4 million, including the aforementioned $19.4 million mark-to-market liability plus $5.0 million in payments related to monthly settlements.

In October 2021, the Company entered into additional crude oil derivative financial instruments with other counterparties that are included in our syndicate of banks associated with our Revolving Credit Facility. After giving effect to these new contracts, the Company’s outstanding crude oil derivative contracts and the weighted average crude oil prices per barrel for those contracts are as follows:

	2021		2022										2023
	Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total		First Quarter		Second Quarter		Total
Crude Oil Price Swaps - WTI: (a)
Volume (MBbls)		540.6		684.0		441.5		146.0		239.0		1,510.5		198.0		200.2		398.2
Price per Bbl	$	64.35	$	67.52	$	66.59	$	65.88	$	59.37	$	65.80	$	57.22	$	57.22	$	57.22

Operations and Drilling Highlights

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

	~~Six~~Nine Months Ended ~~June~~ September 30, 2021
Crude Oil (Bbls)		~~6,352~~6,560
NGL (Bbls)		~~399~~491
Natural Gas (Mcf)		~~1,771~~2,235
Total (Boe)		~~7,046~~7,424

The Company's liquids production was 9695 percent of total production on a Boe basis for the ~~six~~nine months ended ~~June~~September 30, 2021.

Costs incurred are as follows (in thousands):

	Six Months Ended June 30, 2021		Nine Months Ended September 30, 2021
Unproved property acquisition costs	$	2,070	$	20,136
Proved acquisition costs		-		33,140
Total acquisitions		2,070		53,276
Development costs		14,349		26,690
Exploration costs		75,610		127,909
Total finding and development costs		92,029		207,875
Asset retirement obligations		600		1,933
Total costs incurred	$	92,629	$	209,808

The following table sets forth the total number of horizontal wells drilled and completed during the ~~six~~nine months ended ~~June~~September 30, 2021:

	Drilled				Completed				Drilled				Completed
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Flat Top area		12		12.0		14		13.2		25		19.4		20		18.9
Signal Peak area		2		1.4		2		1.4		3		1.9		2		1.4
Total		14		13.4		16		14.6		28		21.3		22		20.3

The Company currently plans to add a third drilling rig and operate ~~two (2)~~three (3) drilling rigs and an average of one (1) frac fleet in the Permian Basin during the remainder of ~~2021.~~2021 and participate in minimal development on our acreage that is operated by other operators. However, the scope, duration and magnitude of the direct and indirect effects of the COVID-19 pandemic 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~~nine months ended ~~June~~September 30, 2021, the Company successfully completed and placed on production ~~fourteen (14)~~twenty (20) horizontal wells in the Flat Top area ~~ten (10) of which are in the Wolfcamp A and four (4) of which are in the Lower Spraberry formations~~ and two (2) horizontal wells ~~in the Signal Peak area, one (1) of which was in the Wolfcamp D and one (1) of which was in the Wolfcamp C formations~~ in the Signal Peak area. The Company had six (6) wells in various stages of completion as of ~~June~~September 30, 2021, ~~four (4)~~five (5) of which are in the ~~Wolfcamp A~~Flat Top area and ~~two (2)~~one (1) of which ~~are~~is in the ~~Lower Spraberry formations located in the Flat Top~~Signal Peak area. As of ~~June~~September 30, 2021, the Company was in the process of drilling four (4) horizontal wells in the Flat Top area and one (1) ~~horizontal salt-water disposal~~non-operated well in the ~~Ellenburger formation in the Flat Top~~Signal Peak area.

Results of Operations

Factors Affecting the Comparability of the Predecessor Historical Financial Results

The comparability of the Predecessor results of operations among the periods presented, and for future periods, is impacted by the following factors:

•

As a corporation under the Code, HighPeak Energy is subject to U.S. federal income taxes at a statutory rate of 21% of pretax earnings. This is a significant change from the Predecessor’s historical results which were treated as partnerships for U.S. federal income tax purposes and, as such, the partners of the Predecessor reported their share of the Company’s income or loss on their respective income tax returns;

•

Our assets will incur certain additional general and administrative expenses related to being owned by a publicly traded company that were not previously incurred in HPK LP’s cost structure, including, but not limited to, Securities Exchange Act of 1934, as amended (the “Exchange Act”), reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with being listed on a national securities exchange; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and independent director compensation;

•

During the ~~six~~nine months ended ~~June~~September 30, 2020, HPK LP recognized a charge to expense of $76.5 million related to the termination of the Grenadier Acquisition.

Three Months Ended September 30, 2021

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

Three Months Ended June 30,

Six Months Ended June 30,

2021

2020

% Change

2021

2020

% Change

Successor

Predecessor

Successor

Predecessor

Oil (Bbls)
7,951 660 1,105 % 6,352 940 576 %
NGL (Bbls)
502 52 865 % 399 93 329 %
Natural Gas (Mcf)
1,973 280 605 % 1,771 363 388 %
Total (Boe)
8,783 758 1,059 % 7,046 1,093 545 %

			Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
Crude Oil (Bbls)		6,970		3,104		1,240		240	%
NGL (Bbls)		673		44		61		1,170	%
Natural Gas (Mcf)		3,147		312		409		757	%
Total (Boe)		8,168		3,200		1,369		277	%

The increase in average daily Boe sales volumes for the three ~~and six~~ months ended ~~June~~September 30, 2021, compared with the same ~~periods~~period in 2020 was due to the Company's successful horizontal drilling program ~~coupled with the fact that the Company shut-in the majority of its production starting in the second quarter of 2020 due to the impact COVID-19 had on global energy prices.~~and bolt-on acquisitions.

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,									Three Months Ended September 30, 2020
	2021		2020			% Change			2021		2020		% Change			Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Predecessor						Successor		Predecessor					Successor		Successor		Predecessor
Oil per Bbl	$	64.93	$	15.61			316	%	$	62.50	$	31.93		96	%
Crude Oil per Bbl																$	69.84	$	38.55	$	40.43		78	%
NGL per Bbl	$	26.77	$	4.55			488	%	$	27.16	$	10.13		168	%	$	35.83	$	16.43	$	4.91		297	%
Gas per Mcf	$	2.81	$	(0.03	)		9,467	%	$	2.55	$	0.03		8,400	%
Natural Gas per Mcf																$	3.69	$	2.30	$	2.04		72	%
Total per Boe	$	60.40	$	13.68			341	%	$	58.01	$	27.99		107	%	$	63.18	$	37.77	$	37.30		68	%

Crude Oil and natural gas production costs.

~~Oil~~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,

2021

2020

%
Change

2021

2020

%
Change

Successor

Predecessor

Successor

Predecessor

Oil and natural gas production costs
$ 4,692 $ 1,814 159 % $ 6,919 $ 4,203 65 %
Oil and natural gas production costs per Boe
$ 5.87 $ 26.28 (78 )% $ 5.43 $ 21.13 (74 )%

			Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
Crude oil and natural gas production costs	$	6,710	$	671	$	667		401	%
Crude oil and natural gas production costs per Boe	$	8.93	$	5.24	$	9.38		33	%

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 ~~coupled with the fact that the Company shut-in the majority~~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 ~~its~~ production ~~starting~~early in the ~~second~~third quarter of ~~2020 due to~~2021 for offset completion operations. Operating expenses were not affected much by the ~~impact COVID-19 had on global energy prices.~~shut-ins, but the production volumes were reduced very significantly during the quarter while the offset operations were in progress. Specifically, sales volumes during July and August averaged 7,057 Boe per day while September averaged 10,355 Boe per day. This increase has continued into October where we will average approximately 15,000 Boe per day for the second half of the month.

Production and ad valorem taxes.

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

			Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
Production and ad valorem taxes	$	1,783	$	257	$	164		987	%

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,

2021

2020

% Change

2021

2020

% Change

Successor

Predecessor

Successor

Predecessor

Production taxes per Boe
$ 2.87 $ 0.64 348 % $ 2.74 $ 1.31 109 %
Ad valorem taxes per Boe
$ 0.31 $ 0.73 (58 )% $ 0.56 $ 0.71 (21 )%

				Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021			August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor			Successor		Predecessor
Production taxes per Boe	$	3.03		$	1.75	$	1.71		77	%
Ad valorem taxes per Boe	$	(0.66	)	$	0.26	$	0.59		n/a

The increase in production taxes per Boe for the three ~~and six~~ months ended ~~June~~September 30, 2021, compared with the same ~~periods~~period in 2020, was primarily due to the ~~332% and 104% increases~~68% increase in realized ~~prices, respectively.~~prices. The decrease in ad valorem taxes per Boe for the three ~~and six~~ months ended ~~June~~September 30, 2021, compared with the same ~~periods~~period in 2020, was ~~primarily due to a large number of wells that have come on production during~~because 2021 ~~which will not incur ad valorem tax until 2022 which will be the first year that they will be assessed~~ ad valorem taxes ~~coupled with the fact that the Company shut-in the majority of its production starting in the second quarter of~~were based on 2020 prices, which were much lower due to the impact COVID-19 had on global energy prices. 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. Even with this decrease due to prices, our initial estimates in early 2021 were too high resulting in an over accrual as of June 30, 2021. In early 2021, we hired a third-party ad valorem tax specialist to aid in our evaluation and negotiation of valuations for ad valorem tax purposes which allowed us to further significantly ~~impacted the sale volumes negatively during 2020 increasing the~~reduce our ad valorem taxes ~~per Boe.~~for 2021. Thus, the over accrual from June 30, 2021 was reversed during the three months ended September 30, 2021.

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,									Three Months Ended September 30, 2020
	2021		2020		% Change			2021		2020		% Change			Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Predecessor					Successor		Predecessor					Successor		Successor		Predecessor
Abandoned leasehold costs															$	186	$	—	$	—		100	%
Geologic and geophysical personnel costs																159		52		—		206	%
Geologic and geophysical data costs	$	320	$	-		100	%	$	320	$	3		10,567	%		143		—		—		100	%
Geologic and geophysical personnel costs		143		-		100	%		285		-		100	%
Plugging and abandonment expense		-		1		(100	)%		-		1		(100	)%		—		14		—		(100	)%
Abandoned leasehold costs		-		-		-	%		49		-		100	%
Exploration and abandonments expense	$	463	$	1		46,200	%	$	654	$	4		16,250	%	$	488	$	66	$	—		639	%

The increase in exploration and abandonment expenses ~~are~~is primarily the result of various insignificant undeveloped leases that we chose not to extend, increased geologic and geophysical data expenses ~~plus exploration general~~ and ~~administrative expenses that are~~an increase in geologic and geophysical personnel costs being classified as a part of exploration and abandonment expense ~~which~~that are now identifiable and not merely a component of administration fees paid to a management company.

Depletion, depreciation and amortization expense.

Depletion, depreciation and amortization (“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,

2021

2020

% Change

2021

2020

% Change

Successor

Predecessor

Successor

Predecessor

DD&A expense
$ 16,857 $ 1,735 872 % $ 29,820 $ 5,091 486 %
DD&A expense per Boe
$ 21.09 $ 25.15 (16 )% $ 23.38 $ 25.59 (9 )%

			Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
DD&A expense	$	13,917	$	2,327	$	1,294		284	%
DD&A expense per Boe	$	18.52	$	18.18	$	18.17		2	%

The increase in DD&A ~~was~~is primarily due to the increased production associated with our successful horizontal drilling program ~~plus the fact that the majority of our production was shut-in during the second quarter of 2020 due to COVID-19~~ and the effect it had on global demand and limited amounts of storage. Also, the decrease in DD&A per Boe was primarily the result of the Company’s successful horizontal drilling program and the addition of proved reserves related to recently completed extension wells.bolt-on acquisitions.

General and administrative expense.

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

	Three Months Ended June 30,							Six Months Ended June 30,									Three Months Ended September 30, 2020
	2021		2020		% Change			2021		2020		% Change			Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Predecessor					Successor		Predecessor					Successor		Successor		Predecessor
General and administrative expense	$	1,617	$	1,412		15	%	$	3,376	$	4,273		(21	)%	$	1,666	$	816	$	567		20	%
General and administrative expense per Boe	$	2.02	$	20.45		(90	)%	$	2.65	$	21.48		(88	)%	$	2.22	$	6.38	$	7.96		(68	)%
Stock based compensation expense	$	1,023	$	-		100	%	$	1,989	$	-		100	%
Stock-based compensation expense															$	905	$	14,508	$	—		(94	)%

The increase in general and administrative expense for the three months ended ~~June~~September 30, 2021 is primarily as a result of the increased administrative costs associated with being a public company, partially offset by more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count in the 2021 period compared with 2020, no business combination charges in 2021 compared with 2020 and lower exploration general and administrative expenses that are classified as exploration and abandonment expense which are now identifiable and not included as a component of administration fees paid to a management company. The decrease in general and administrative expense for the six months ended June 30, 2021, compared with the same periods in 2020, is primarily a result of more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count, no business combination charges in 2021 and lower exploration general and administrative expenses that are being classified as a part of exploration and abandonment expense which are now identifiable and not included as a component of administration fees paid to a management company.

The ~~increase~~decrease in noncash stock-based compensation expense is due to stock option awards being granted to officers and employees upon completion of the business combination in August of 2020 when a good portion of said stock options were vested immediately and ~~restricted stock awards granted to outside directors~~thus the majority of the expense related thereto was recognized during the three months ended ~~June~~September 30, ~~2021.~~2020.

Interest expense.

			Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
Interest expense	$	947	$	—	$	—		100	%

The increase in interest expense can be attributed to the fact that we entered into our Revolving Credit Facility in December 2020 and began drawing on it late in the second quarter of 2021. Interest expense for the three ~~and six~~ months ended ~~June~~September 30, 2021 includes interest expense of ~~$78,000 and $78,000, respectively,~~$691,000, commitment fees of ~~$26,000 and $51,000, respectively~~$74,000 and amortization of debt issuance costs of ~~$48,000 and $77,000, respectively.~~$182,000.

Derivative gain (loss), net.

Three Months Ended June 30,

Six Months Ended June 30,

2021

2020

%
Change

2021

2020

%
Change

Successor

Predecessor

Successor

Predecessor

Noncash derivative loss
$ (12,558 ) $ - 100 % $ (12,558 ) $ - 100 %
Cash payments on settled derivative instruments
(1,038 ) - 100 % (1,038 ) - 100 %
Derivative loss, net
$ (13,596 ) $ - 100 % $ (13,596 ) $ - 100 %

				Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021			August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor			Successor		Predecessor
Noncash derivative gain (loss), net	$	(6,844	)	$	—	$	—		100	%
Cash payments on settled derivative instruments, net		(3,976	)		—		—		100	%
Derivative gain (loss), net	$	(10,820	)	$	—	$	—		100	%

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) support the Company’s annual capital budget and expenditure plans and (iii) 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 derivative swap contracts.

Income tax expense.

Three Months Ended June 30,

Six Months Ended June 30,

2021

2020

% Change

2021

2020

% Change

Successor

Predecessor

Successor

Predecessor

Income tax expense
$ 1,420 $ - 100 % $ 2,535 $ - 100 %
Effective income tax rate
19.8 % 0.0 % 100 % 19.5 % 0.0 % 100 %

				Three Months Ended September 30, 2020
	Three Months Ended September 30, 2021			August 22, 2020 through September 30, 2020			July 1, 2020 through August 21, 2020			Qtr % Change
	Successor			Successor			Predecessor
Income tax expense (benefit)	$	2,145		$	(2,309	)	$	—			n/a
Effective income tax rate		21.0	%		16.7	%		0.0	%		n/a

The change in income tax expense during the three ~~and six~~ months ended ~~June~~September 30, 2021, compared with the same period in 2020, was due to the Company realizing net income during the three months ended September 30, 2021 compared with a net loss for the period from August 22, 2020 through September 30, 2020 and the fact that the Predecessor was treated as a partnership for U.S. federal income tax purposes and, as such, the partners of the Predecessor reported their share of the Company’s income or loss on their respective income tax returns. In contrast, HighPeak Energy is a corporation and is subject to U.S. federal income taxes on any income or loss following the business combination on August 21, 2020. The effective income tax rate differs from the statutory rate primarily due to permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)" for additional information.

Nine Months Ended September 30, 2021

Crude Oil, NGL and natural gas revenues.

Average daily sales volumes are as follows:

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
Crude Oil (Bbls)		6,560		3,104		1,007		400	%
NGL (Bbls)		491		44		86		522	%
Natural Gas (Mcf)		2,235		312		373		514	%
Total (Boe)		7,424		3,200		1,154		411	%

The increase in average daily Boe sales volumes for the nine months ended September 30, 2021, compared with the same period in 2020 was due to the Company's successful horizontal drilling program and bolt-on acquisitions.

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		July 1, 2020 through August 21, 2020		Qtr % Change
	Successor		Successor		Predecessor
Crude Oil per Bbl	$	65.13	$	38.55	$	34.26		82	%
NGL per Bbl	$	31.16	$	16.43	$	9.31		215	%
Natural Gas per Mcf	$	3.09	$	2.30	$	0.52		318	%
Total per Boe	$	59.93	$	37.77	$	30.44		83	%

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):

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
Crude oil and natural gas production costs	$	13,629	$	671	$	4,870		146	%
Crude oil and natural gas production costs per Boe	$	6.72	$	5.24	$	18.03		(52	)%

Production and ad valorem taxes.

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

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
Production and ad valorem taxes	$	5,990	$	257	$	566		958	%

Production and ad valorem taxes per Boe are as follows:

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
Production taxes per Boe	$	2.85	$	1.75	$	1.42		101	%
Ad valorem taxes per Boe	$	0.11	$	0.26	$	0.68		(84	)%

The increase in production taxes per Boe for the nine months ended September 30, 2021, compared with the same periods in 2020, was primarily due to the 83% increase in realized prices. The decrease in ad valorem taxes per Boe for nine months ended September 30, 2021, compared with the same period in 2020, was because 2021 ad valorem taxes were based on 2020 prices, which were much lower due to the impact COVID-19 had on global energy prices. 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. In early 2021, we hired a third-party ad valorem tax specialist to aid in our evaluation and negotiation of valuations for ad valorem tax purposes which allowed us to further significantly reduce our ad valorem taxes for 2021.

Exploration and abandonments expense.

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

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
Geologic and geophysical data costs	$	463	$	-	$	3		15,333	%
Geologic and geophysical personnel costs		444		52		—		754	%
Abandoned leasehold costs		235		—		—		(100	)%
Plugging and abandonment expense		—		14		1		100	%
Exploration and abandonments expense	$	1,142	$	66	$	4		1,531	%

The increase in exploration and abandonment expenses are the result of increased geologic and geophysical data expenses, various insignificant undeveloped leases that we chose not to extend and geologic and geophysical personnel costs that are being classified as a part of exploration and abandonment expense which are now identifiable and not merely a component of administration fees paid to a management company.

Depletion, depreciation and amortization expense.

Depletion, depreciation and amortization (“DD&A”) expense and DD&A expense per Boe are as follows (in thousands, except percentages and per Boe amounts):

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
DD&A expense	$	43,737	$	2,327	$	6,385		402	%
DD&A expense per Boe	$	21.58	$	18.18	$	23.64		(1	)%

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

General and administrative expense.

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

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
General and administrative expense	$	5,042	$	816	$	4,840		(11	)%
General and administrative expense per Boe	$	2.49	$	6.38	$	17.92		(82	)%
Stock-based compensation expense	$	2,894	$	14,508	$	—		(80	)%

The decrease in general and administrative expense for the nine months ended September 30, 2021 is primarily as a result of more general and administrative costs being allocated to drilling and completion operations and construction projects and producing properties due to increased activity and well count in the 2021 period compared with 2020, no business combination charges in 2021 compared with 2020 and lower exploration general and administrative expenses that are classified as exploration and abandonment expense which are now identifiable and not included as a component of administration fees paid to a management company, partially offset by the increased administrative costs associated with being a public company.

The decrease in noncash stock-based compensation expense is due to stock option awards being granted to officers and employees upon completion of the business combination in August of 2020 when a good portion of said stock options were vested immediately and thus the majority of the expense related thereto was recognized during the nine months ended September 30, 2020.

Interest expense.

			Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021		August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor		Successor		Predecessor
Interest expense	$	1,153	$	—	$	—		100	%

The increase in interest expense can be attributed to the fact that we entered into our Revolving Credit Facility in December 2020 and began drawing on it late in the second quarter of 2021. Interest expense for the nine months ended September 30, 2021 includes interest expense of $768,000, commitment fees of $126,000 and amortization of debt issuance costs of $259,000.

Derivative gain (loss), net.

				Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021			August 22, 2020 through September 30, 2020		January 1, 2020 through August 21, 2020		YTD % Change
	Successor			Successor		Predecessor
Noncash derivative gain (loss), net	$	(19,402	)	$	—	$	—		100	%
Cash payments on settled derivative instruments, net		(5,014	)		—		—		100	%
Derivative gain (loss), net	$	(24,416	)	$	—	$	—		100	%

Income tax expense.

				Nine Months Ended September 30, 2020
	Nine Months Ended September 30, 2021			August 22, 2020 through September 30, 2020			January 1, 2020 through August 21, 2020			YTD % Change
	Successor			Successor			Predecessor
Income tax expense (benefit)	$	4,680		$	(2,309	)	$	—			n/a
Effective income tax rate		20.2	%		16.7	%		0.0	%		n/a

The change in income tax expense during the nine months ended September 30, 2021, compared with the same period in 2020, was due to the Company realizing net income during the nine months ended September 30, 2021 compared with a net loss for the period from August 22, 2020 through September 30, 2020 and the fact that the Predecessor was treated as a partnership for U.S. federal income tax purposes and, as such, the partners of the Predecessor reported their share of the Company’s income or loss on their respective income tax returns. In contrast, HighPeak Energy is a corporation and is subject to U.S. federal income taxes on any income or loss following the business combination on August 21, 2020. The effective income tax rate differs from the statutory rate primarily due to permanent differences between GAAP income and taxable income. See Note 13 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)" for additional information.

Liquidity and Capital Resources

Liquidity. In response to the COVID-19 pandemic and commensurate decrease in crude oil, NGL and natural gas prices, the Company took steps during 2020 to reduce, defer or cancel certain planned capital expenditures, shut-in the majority of its production and reduce its overall cost structure commensurate with its expected level of activities. During July 2020, the Company began putting its wells back on production based on the recovery of crude oil and natural gas prices. Subsequent to the Closing of the HighPeak business combination, the Company began completing the twelve (12) wells that were drilled but not yet completed when operations were shut down early in 2020. The Company also began running one (1) drilling rig in September 2020. The Company drilled and completed a salt-water disposal well near the center of our current northern acreage operating area and completed phase one of a water disposal infrastructure system to recycle or dispose the water that we anticipate producing with the development drilling planned in 2021 and beyond. Also, in late December 2020, the Company entered into a Revolving Credit Facility with an initial borrowing base of $40.0 million; however, the Company elected to reduce the aggregate elected commitments to $20.0 million. In June 2021, the Company increased its borrowing base and commitments under its Revolving Credit Facility to $125.0 million and added a syndicate of banks at various levels of participation and commitments. In October 2021, the Company increased its borrowing base and commitments under its Revolving Credit Facility to $195.0 million. The Revolving Credit Facility remained undrawn until the second quarter of 2021. Associated with the Revolving Credit Facility, the Company was required to enter into commodity hedging instruments, which it did in the second quarter, to protect against price fluctuations on a portion of its proved developed producing reserves commencing prior to drawing on the Revolving Credit Facility. See Note 5 of the Notes to Consolidated and Combined Financial Statements included in “Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)” for additional information regarding these commodity derivative contracts.

The Company's primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) borrowings from our Revolving Credit Facility, (iv) on an opportunistic basis, issuances of debt or equity securities and (v) other sources, such as sales of nonstrategic assets.

As of ~~June~~September 30, 2021, the Company had ~~$14.0~~$95.0 million in borrowings and approximately ~~$109.1~~$28.1 million available to borrow under its Revolving Credit Facility. The Company also had unrestricted cash on hand of ~~$12.8~~$12.0 million as of ~~June~~September 30, 2021. With the increase of the borrowing base to $195.0 million in October 2021, the Company has $98.1 million available to borrow under its Revolving Credit Facility as of October 1, 2021.

Under our Credit Agreement, borrowing in the form of Eurodollar loans accrue interest based on LIBOR. The use of LIBOR as a global reference rate is expected to be discontinued after 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. We currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business. See Note 2 of Notes to Consolidated Financial Statements included in "Item 1. Condensed Consolidated and Combined Financial Statements (Unaudited)" for discussion of FASB ASU 2020-04 and ASU 2021-01, which provide guidance related to reference rate reform.

On October 25, 2021, the Company completed the offering of 2,530,000 shares of its common stock, at a price to the public of $10.00 per share, pursuant to a registration statement on Form S-1 filed with the Securities and Exchange Commission on October 19, 2021. The net proceeds to the Company from the offering, after deducting the underwriting discounts and commissions and other offering expenses, were approximately $23.0 million. The Company intends to use the net proceeds of this offering for general corporate purposes, which may include accelerating its drilling and development activities and funding additional bolt-on acquisitions.

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, and (iv) working capital obligations. 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 2021 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.

2021 capital budget. ~~Upon increasing~~With the addition of a second rig to accelerate its ~~commitments under the Revolving Credit Facility,~~development drilling program, the Company ~~updated~~increased its capital budget for 2021 to approximately ~~$210~~$245 to ~~$225~~$270 million, ~~for drilling, completion, facilities and equipping oil wells plus $35 to $45 million for field infrastructure buildout and other costs.~~excluding acquisitions. HighPeak Energy expects to fund its forecasted capital expenditures with cash on its balance sheet, cash generated by operations, through borrowings under its Revolving Credit Facility and, on an opportunistic basis, proceeds from the issuance of debt or equity securities. The Company's capital expenditures for the ~~six~~nine months ended ~~June~~September 30, 2021 were ~~$92.0 million.~~$154.6 million for drilling, completion, facilities, equipping crude oil wells and field infrastructure buildout, or $207.9 million, including bolt-on acquisitions and lease extensions and acquisitions.

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

	Six Months Ended June 30,												Nine Months Ended September 30, 2020
	2021			2020			% Change			Nine Months Ended September 30, 2021			August 22, 2020 through September 30, 2020			January 1, 2020 through August 21, 2020			YTD % Change
	Successor			Predecessor						Successor			Successor			Predecessor
Net cash provided by (used in) operating activities	$	47,280		$	(4,812	)		1,083	%	$	87,737		$	10,693		$	(4,102	)		1,231	%
Net cash used in investing activities	$	(76,867	)	$	(65,619	)		(17	)%	$	(189,099	)	$	(42,033	)	$	(67,886	)		72	%
Net cash provided by financing activities	$	22,877		$	54,000			(58	)%	$	93,776		$	84,271		$	51,220			(31	)%

Operating activities. The increase in net cash flow provided by operating activities for the ~~six~~nine months ended ~~June~~September 30, 2021, compared with 2020, was primarily related to higher revenues associated with increased production volumes as a result of our successful horizontal drilling program ~~coupled with the fact that the Company shut-in the majority of its production starting in the second quarter of 2020 due to the impact COVID-19 had on global energy prices,~~and bolt-on acquisitions and increased realized prices. Partially offsetting this increase was a greater accounts receivable balance resulting from the higher oil, NGL and natural gas revenues related to increased sales volumes and realized prices in the current period.

Investing activities. The increase in net cash used in investing activities for the ~~six~~nine months ended ~~June~~September 30, 2021, compared with 2020, was primarily due to increases in additions to crude oil and natural gas properties compared with the ~~six~~nine months ended ~~June~~September 30, 2020, when the Company shut down drilling operations during the second quarter of 2020 due to COVID-19 and the impact it had on global energy prices, and ~~decreases~~increases in crude oil and natural gas acquisition costs. Partially offsetting this increase was the receipt of $3.2 million in sales proceeds from the sale of a non-operated interest in a producing horizontal well in the eastern portion of Flat Top. During the prior year period, the Company also funded an extension payment of $15.0 million related to an acquisition in 2020 that was terminated and funded notes receivable to Pure of $5.9 million related to the HighPeak business combination.

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

	•	2021: The Company borrowed ~~$14.0~~$95.0 million on its Revolving Credit Facility and 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. These cash inflows were partially offset by the Company incurring $10.1 million in dividends and dividend equivalent payments and $1.8 million in debt issuance costs associated with the amended and restated Revolving Credit Facility in June 2021.

	•	2020: The Company’s Predecessors received $54.0 million in capital contributions from its ~~partners.~~partners and distributed $2.8 million to its partners prior to the business combination closing.

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.

Non-GAAP Financial Measures

EBITDAX represents net income (loss) before interest expense, interest 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 analysis, 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 and Combined 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 (loss) (GAAP) to EBITDAX (non-GAAP) for the periods presented (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,								Three Months Ended September 30, 2020									Nine Months Ended September 30, 2020
	2021		2020			2021			2020			Three Months Ended September 30, 2021		August 22, 2020 through September 30, 2020			July 1, 2020 through August 21, 2020			Nine Months Ended September 30, 2021			August 22, 2020 through September 30, 2020			January 1, 2020 through August 21, 2020
	Successor		Predecessor			Successor			Predecessor			Successor		Successor			Predecessor			Successor			Successor			Predecessor
Net income (loss)	$	5,743	$	(4,147	)	$	10,487		$	(84,978	)	$	8,047	$	(11,516	)	$	(56	)	$	18,534		$	(11,516	)	$	(85,034	)
Interest expense		152		-			206			-			947		—			—			1,153			—			—
Interest income		-		-			(1	)		-			—		(1	)		—			(1	)		(1	)		—
Income tax expense		1,420		-			2,535			-
Income tax expense (benefit)													2,145		(2,309	)		—			4,680			(2,309	)		—
Depletion, depreciation and amortization		16,857		1,735			29,820			5,091			13,917		2,327			1,294			43,737			2,327			6,385
Accretion of discount		37		35			72			69			44		15			20			116			15			89
Exploration and abandonment expense		463		1			654			4			488		66			—			1,142			66			4
Stock-based compensation		1,023		-			1,989			-
Derivative-related noncash activity		12,558		-			12,558			-
Stock based compensation													905		14,508			—			2,894			14,508			—
Derivative related noncash activity													6,844		—			—			19,402			—			—
Other expense		127		-			127			76,503			—		—			—			127			—			76,503
EBITDAX	$	38,380	$	(2,376	)	$	58,447		$	(3,311	)	$	33,337	$	3,090		$	1,258		$	91,784		$	3,090		$	(2,053	)

New Accounting Pronouncements

Our historical condensed consolidated and combined financial statements and related notes to condensed consolidated and combined 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~~nine months ended ~~June~~September 30, 2021. 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, 2020, filed with the SEC on March 15, 2021.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

During the period from January 1, 2018 through ~~June~~September 30, 2021, the calendar month average NYMEX WTI crude oil price per Bbl ranged from a low of $16.70 in April 2020 to a high of ~~$71.35~~$72.43 in ~~June of~~July 2021, and the last trading day NYMEX natural gas price per MMBtu ranged from a low of $1.50 in July 2020 to a high of ~~$4.72.~~$4.72 in December 2018. A $1.00 per barrel increase (decrease) in the weighted average crude oil price for the ~~six~~nine months ended ~~June~~September 30, 2021 would have increased (decreased) the Company’s revenues by approximately ~~$2.4~~$2.5 million on an annualized basis and a $0.10 per Mcf increase (decrease) in the weighted average natural gas price for the ~~six~~nine months ended ~~June~~September 30, 2021 would have increased (decreased) the Company’s revenues by approximately ~~$64,000~~$81,000 on an annualized basis.

Due to this volatility, 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~~September 30, 2021 market quotes were as follows:

	Remainder of 2021		Year Ending December 31, 2022		Remainder of 2021		Year Ending December 31, 2022
Average forward NYMEX oil price per Bbl	$	71.13	$	65.70
Average forward NYMEX crude oil price per Bbl					$	74.48	$	70.08
Average forward NYMEX natural gas price per MMBtu	$	3.66	$	3.17	$	5.93	$	4.41

The average forward purchase prices based on ~~August 5,~~November 4, 2021 market quotes were as follows:

	Remainder of 2021		Year Ending December 31, 2022		Remainder of 2021		Year Ending December 31, 2022
Average forward NYMEX oil price per Bbl	$	68.11	$	64.28
Average forward NYMEX crude oil price per Bbl					$	77.86	$	72.19
Average forward NYMEX natural gas price per MMBtu	$	4.20	$	3.58	$	5.72	$	4.49

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 are 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.

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 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 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 ~~six~~nine months ended ~~June~~September 30, 2021 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 report, the risks that are discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, under the headings "Risk Factors,” “Business and Properties,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk” should be carefully considered, as such risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors that were described in the Company’s Annual Report on Form 10-K.

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.

HIGHPEAK ENERGY, INC.

ITEM 6. EXHIBITS

Exhibit
Number	Description

2.1+	Business Combination Agreement, dated as of May 4, 2020, by and among Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC, and, solely for limited purposes specified therein, HighPeak Energy Management, LLC (incorporated by reference to Annex A 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.

2.2	First Amendment to Business Combination Agreement, dated as of June 12, 2020, by and among, Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC and HighPeak Energy Management, LLC (incorporated by reference to Annex A-I 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).

2.3	Second Amendment to Business Combination Agreement, dated as of July 1, 2020, by and among, Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC and HighPeak Energy Management, LLC (incorporated by reference to Annex A-II 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).

2.4	Third Amendment to Business Combination Agreement, dated as of July 24, 2020, by and among, Pure Acquisition Corp., HighPeak Energy, Inc., Pure Acquisition Merger Sub, Inc., HighPeak Energy, LP, HighPeak Energy II, LP, HighPeak Energy III, LP, HPK Energy, LLC and HighPeak Energy Management, LLC (incorporated by reference to Annex A-III 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).

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	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.

10.1	Contingent Value 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 and Continental Stock Transfer & Trust Company, as rights agent (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 August 27, 2020).

10.2	Amended and Restated Forward Purchase Agreement, dated as July 24, 2020, by and among HighPeak Energy, Inc., the Purchasers therein, HighPeak Energy Partners, LP and, solely for the purposes specified therein, Pure Acquisition Corp (incorporated by reference to Annex F to the Company’s Registration Statement on Form S-4 and Form S-1 (File No. 333-235313) filed with the SEC on August 5, 2020).

10.3	HighPeak Energy, Inc. Amended and Restated Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

10.4	Form of Stock Option Agreement (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on August 27, 2020).

10.5	Form of Indemnification Agreement (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 November 9, 2020).

~~10.6+~~10.6	Credit Agreement, dated as of December 17, 2020, 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 December 18, 2020).

~~10.7+~~10.7	First Amendment to Credit Agreement, dated as of June 23, 2021, by and among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, the Guarantors, the Existing Lender and the New 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 October 4, 2021).

10.8	Second amendment to Credit Agreement, dated as of October 1, 2021, by and among HighPeak Energy, Inc., as Borrower, Fifth Third Bank, National Association, as administrative agent, the Guarantors, 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 24,~~October 4, 2021).

10.810.9*	Form of Dividend Equivalent Award Agreement.

16.1	Letter from WithumSmith+Brown, PC to the Securities and Exchange Commission, dated October 1, 2020 (incorporated by reference to Exhibit 16.1 to the Company’s Current Report on Form 8-K (File No. 001-39464) filed with the SEC on October 1, 2020).

31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).

31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).

32.1**	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).

32.2**	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).


101.INS**	Inline XBRL Instance Document

101.SCH**	Inline XBRL Taxonomy Extension Schema Document

101.CAL**	Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**	Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**	Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE**	Inline XBRL Taxonomy Extension Presentation Linkbase Document

104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

_________________

*	Filed herewith.
**	Furnished herewith.
+	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.

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 9,~~November 8, 2021	By:	/s/ Steven Tholen
		Steven Tholen
		Chief Financial Officer

~~August 9,~~November 8, 2021	By:	/s/ Keith Forbes
		Keith Forbes
		Vice President and Chief Accounting Officer

4147

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 Commons Stock	HPKEW	The Nasdaq Stock Market LLC

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

		Page
Definitions of Certain Terms and Conventions Used Herein		1
Cautionary Statement Concerning Forward-Looking Statements		5
	PART I. FINANCIAL INFORMATION
Item 1.	Condensed Consolidated and Combined Financial Statements (Unaudited)	6
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated and Combined Statements of Operations	7
	Condensed Consolidated ~~Statement~~Statements of Changes in Stockholders’ Equity (Successor)	8
	Condensed Consolidated Statement of Changes in Partners’ Capital (Predecessor)	9
	Condensed Consolidated and Combined Statements of Cash Flows	10
	Notes to Condensed Consolidated and Combined Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2628
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3642
Item 4.	Controls and Procedures	3743
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	3844
Item 1A.	Risk Factors	3844
Item 6.	Exhibits	3945
Signatures

		(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.

	June 30, 2021			December 31, 2020			September 30, 2021			December 31, 2020
	(Unaudited)						(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	12,842		$	19,552		$	11,966		$	19,552
Accounts receivable		23,786			7,722			23,891			7,722
Subscription receivable		0			3,596			0			3,596
Inventory								3,920			121
Prepaid expenses		1,062			2,254			2,592			2,254
Inventory		217			121
Deposits		50			50			50			50
Total current assets		37,957			33,295			42,419			33,295
Oil and natural gas properties, using the successful efforts method of accounting:
Crude oil and natural gas properties, using the successful efforts method of accounting:
Proved properties		497,938			367,372			602,833			367,372
Unproved properties		114,435			152,741			123,064			152,741
Accumulated depletion, depreciation and amortization		(47,200	)		(17,477	)		(61,066	)		(17,477	)
Total oil and natural gas properties, net		565,173			502,636
Total crude oil and natural gas properties, net								664,831			502,636
Other property and equipment, net		1,057			1,092			1,397			1,092
Other noncurrent assets		236			907			4,928			907
Total assets	$	604,423		$	537,930		$	713,575		$	537,930
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable - trade	$	18,018		$	7,581		$	12,347		$	7,581
Accrued liabilities		20,727			12,374			29,846			12,374
Derivatives		12,558			0			14,134			0
Advances from joint interest owners								13,463			969
Dividends and dividend equivalents payable								2,683			0
Other current liabilities		3,037			2,480			4,541			1,511
Total current liabilities		54,340			22,435			77,014			22,435
Noncurrent liabilities:
Long-term debt, net		11,918			0			93,102			0
Deferred income taxes		41,432			38,898			43,578			38,898
Derivatives								5,268			0
Asset retirement obligations		2,965			2,293			4,250			2,293
Other		26			78			455			78
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, 2021 and December 31, 2020		0			0
Common stock, $0.0001 par value, 600,000,000 shares authorized, 92,728,781 and 91,967,565 shares issued and outstanding at June 30, 2021 and December 31, 2020, respectively		9			9
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at September 30, 2021 and December 31, 2020								0			0
Common stock, $0.0001 par value, 600,000,000 shares authorized, 92,743,677 and 91,967,565 shares issued and outstanding at September 30, 2021 and December 31, 2020, respectively								9			9
Additional paid-in capital		590,455			581,426			591,360			581,426
Accumulated deficit		(96,722	)		(107,209	)		(101,461	)		(107,209	)
Total stockholders' equity		493,742			474,226			489,908			474,226
Total liabilities and stockholders' equity	$	604,423		$	537,930		$	713,575		$	537,930

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

	•	*"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.
	•	*"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.
	•	*"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 g*as 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.
	•	*"Boe/d"* 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.
	•	*“Business Combination Agreement*” are to the Business Combination Agreement, dated May 4, 2020, as amended, by and among the Company, Pure, MergerSub, HighPeak I, HighPeak II, HPK GP, and solely for the limited purposes specified therein, HPK Energy Management, LLC, pursuant to which, among other things and subject to the terms and conditions contained therein, (i) MergerSub merged with and into Pure, with Pure surviving as a wholly owned subsidiary of HighPeak Energy, (ii) each outstanding share of Pure’s Class A common stock, par value $0.0001 per share, and Pure’s Class B common stock, par value $0.0001 per share (other than certain shares of Pure’s Class B common stock that were surrendered for cancellation by HighPeak Pure Acquisition, LLC (“Pure’s Sponsor”) were converted into the right to receive (A) one share of HighPeak Energy’s common stock (and cash in lieu of fractional shares, if any), and (B) solely with respect to each outstanding share of Pure’s Class A common stock, (I) a cash amount, without interest, equal to $0.62, which represented the amount by which the per-share redemption value of Pure’s Class A common stock at the closing exceeded $10.00 per share, without interest, in each case, totaling approximately $767,902, (II) one (1) Contingent Value Right, for each one whole share of HighPeak Energy’s common stock (excluding fractional shares) issued to holders of Pure’s Class A common stock pursuant to clause (A), representing the right to receive additional shares of HighPeak Energy’s common stock (or such other specified consideration as is specified with respect to certain events) under certain circumstances if necessary to satisfy a 10% preferred simple annual return, subject to a floor downside per-share price of $4.00, as measured at the applicable maturity, which will occur on a date to be specified and which may be any date occurring during the period beginning on (and including) August 21, 2022 and ending on (and including) February 21, 2023, or in certain circumstances after the occurrence of certain change of control events with respect to the Company’s business, including certain mergers, consolidations and asset sales (with an equivalent number of shares of HighPeak Energy’s common stock held by the HPK Contributors being collectively forfeited) and (III) one warrant to purchase one share of HighPeak Energy’s common stock for each one whole share of HighPeak Energy’s common stock (excluding fractional shares) issued to holders of Pure’s Class A common stock pursuant to clause (A), (iii) the HPK Contributors contributed their limited partner interests in HPK LP to HighPeak Energy in exchange for HighPeak Energy common stock and the general partner interests in HPK LP to a wholly owned subsidiary of HighPeak Energy in exchange for no consideration, and (b) contributed the outstanding Sponsor Loans (as defined in the Business Combination Agreement) in exchange for HighPeak Energy common stock and such Sponsor Loans (as defined in the Business Combination Agreement) were cancelled in connection with the closing, and (iv) following the consummation of the foregoing transactions, HighPeak Energy caused HPK LP to merge with and into the Surviving Corporation (as successor to Pure) and all interests in HPK LP were cancelled in exchange for no consideration.
	•	*“Closing*” means the closing of the HighPeak business combination between the Company, Pure, HPK LP, HighPeak I and HighPeak II on August 21, 2020.
	•	*“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 oil,~~ 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 expense.

	•	*“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 ana 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 or natural gas.
	•	*“Dry hole*” 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 or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well as those items are defined by the SEC.
	•	*“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 Lenders party thereto.
	•	*“Formation*” A layer of rock which has distinct characteristics that differs from nearby rocks.
	•	*"GAAP"* means accounting principles generally accepted in the United States of America.
	•	*“Gross wells” or “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.
	•	*“HighPeak business combination*” means the transactions detailed in the Business Combination Agreement, which closed on August 21, 2020.
	•	*"HighPeak Energy"* or the *"Company"* means, at the time of and after the HighPeak business combination, HighPeak Energy, Inc. and its subsidiaries (the “Successor”) and, prior to the HighPeak business combination, the Predecessors.
	•	*“HighPeak Group*” means HighPeak Pure Acquisition, LLC, a Delaware limited liability company, and wholly owned subsidiary of HighPeak I, the HPK Contributors and Jack Hightower and each of their respective affiliates and certain permitted transferees, collectively.
	•	*“HighPeak I*” means HighPeak Energy, LP, a Delaware limited partnership.
	•	*“HighPeak II*” means HighPeak Energy II, LP, a Delaware limited partnership.
	•	*“Horizontal drilling*” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
	•	*“HPK Contributors*” means HighPeak I, HighPeak II and HPK GP.
	•	*“HPK GP*” means HPK Energy, LLC, a Delaware limited liability company.
	•	*“HPK LP*” means HPK Energy, LP, a Delaware limited partnership.
	•	*“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, ad valorem taxes, 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.
	•	*“MergerSub*” means Pure Acquisition Merger Sub, Inc., a Delaware corporation.
	•	*"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 ana 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.
	•	*“Predecessors*” refers to, collectively, HPK LP and HighPeak I and individually from the period from October 1, 2019 to August 21, 2020 to HPK LP and for all prior periods, HighPeak I.
	•	*“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*” Proved reserves that are developed nonproducing reserves.
	•	*“Proved developed producing reserves*” Proved reserves that are developed producing reserves.
	•	*“Proved developed reserves*” 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.
	•	*“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.

	•	*“PUD” or “Proved undeveloped reserves*” 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 having 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.
	•	*“Royalty*” An interest in ana 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 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, and is often established by regulatory agencies.
	•	*“Sponsor*” means HighPeak Pure Acquisition, LLC, a Delaware limited liability company.
	•	*“Spot market price*” The cash market price without reduction for expected quality, transportation and demand adjustments.
	•	*“Standardized measure*” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
	•	*“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.
	•	*“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 natural gas production on a completed well. Also called well or borehole.
	•	*“Working interes*t” The right granted to the lessee of a property to explore for and to produce and own 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.

Three and Nine Months Ended September 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		0		5,466		0			5,466
Stock-based compensation costs:
Shares issued upon options being exercised		154		0		1,574		0			1,574
Compensation costs included in net income		—		0		966		0			966
Net income		—		0		0		4,744			4,744
Balance, March 31, 2020		92,676		9		589,432		(102,465	)		486,976
Stock-based compensation costs:
Restricted shares issued to outside directors		53		0		0		0			0
Compensation costs included in net income		—		0		1,023		0			1,023
Net income		—		0		0		5,743			5,743
Balance, June 30, 2021		92,729		9		590,455		(96,722	)		493,742
Dividends declared ($0.125 per share)		—		0		0		(11,593	)		(11,593	)
Dividend equivalents declared on outstanding stock options ($0.125 per share)		—		0		0		(1,193	)		(1,193	)
Stock-based compensation costs:
Restricted shares issued to outside directors		15		0		0		0			0
Compensation costs included in net income		—		0		905		0			905
Net income		—		0		0		8,047			8,047
Balance, September 30, 2021		92,744	$	9	$	591,360	$	(101,461	)	$	489,908

From August 22, 2020 through September 30, 2020
	Shares Outstanding		Common Stock		Additional Paid-in- Capital			Retained Earnings (Accumulated Deficit)			Total Stockholders' Equity
Balance, August 21, 2020		0	$	0	$	0		$	0		$	0
HighPeak business combination with HPK LP		81,383		8		521,674			(90,780	)		430,902
Conversion of Pure Common Stock		1,232		0		12,324			0			12,324
Forward Purchases		8,977		1		89,768			0			89,769
Offering costs (including costs incurred at Pure prior to HighPeak business combination)		—		0		(22,035	)		0			(22,035	)
Deferred income tax liability at HighPeak business combination		—		0		(40,500	)		0			(40,500	)
Stock-based compensation costs:
Compensation costs included in net loss		—		0		14,508			0			14,508
Net loss		—		0		0			(11,516	)		(11,516	)
Balance, September 30, 2020		91,592	$	9	$	575,739		$	(102,296	)	$	473,452

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		0		5,466		0			5,466
Stock-based compensation costs:
Shares issued upon options being exercised		154		0		1,574		0			1,574
Compensation costs included in net income		-		0		966		0			966
Net income		-		0		0		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		0		0		0			0
Compensation costs included in net income		-		0		1,023		0			1,023
Net income		-		0		0		5,743			5,743
Balance, June 30, 2021		92,729	$	9	$	590,455	$	(96,722	)	$	493,742

Three and Six Months Ended June 30, 2020
From January 1, 2020 and July 1, 2020 through September 30, 2020									From January 1, 2020 and July 1, 2020 through September 30, 2020
	General Partner Capital		Limited Partners' Capital			Total Partners' Capital				General Partner Capital		Limited Partners' Capital			Total Partners' Capital
Balance, December 31, 2019	$	0	$	464,716		$	464,716			$	0	$	464,716		$	464,716
Cash capital contributions		0		54,000			54,000				0		54,000			54,000
Net loss		0		(80,831	)		(80,831	)			0		(80,831	)		(80,831	)
Balance, March 31, 2020		0		437,885			437,885				0		437,885			437,885
Net loss		0		(4,147	)		(4,147	)			0		(4,147	)		(4,147	)
Balance, June 30, 2020	$	0	$	433,738		$	433,738				0		433,738			433,738
Distribution to partners											0		(2,780	)		(2,780	)
Net loss											0		(56	)		(56	)
Balance, September 30, 2020										$	0	$	430,902		$	430,902

	●	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.

	As of June 30, 2021								As of September 30, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liabilities:
Commodity price derivatives – current									$	0	$	14,134	$	0	$	14,134
Commodity price derivatives – noncurrent										0		5,268		0		5,268
Commodity price derivatives	$	0	$	12,558	$	0	$	12,558	$	0	$	19,402	$	0	$	19,402

	Six Months Ended June 30, 2021			Nine Months Ended September 30, 2021
Beginning capitalized exploratory well costs	$	32,592		$	32,592
Additions to exploratory well costs		75,289			127,444
Reclassification to proved properties		(106,749	)		(155,528	)
Exploratory well costs charged to exploration and abandonment expense		0			0
Ending capitalized exploratory well costs	$	1,132		$	4,508

	June 30,			December 31,		September 30,			December 31,
	2021			2020		2021			2020
Revolving Credit Facility due 2024	$	14,000		$	0	$	95,000		$	0
Debt issuance costs, net (a)		(2,082	)		0		(1,898	)		0
Total debt		11,918			0		93,102			0
Less current portion of long-term debt		0			0		0			0
Long-term debt, net	$	11,918		$	0	$	93,102		$	0

	Six Months Ended June 30, 2021			Nine Months Ended September 30, 2021
Beginning asset retirement obligations	$	2,293		$	2,293
Liabilities incurred from new wells		610			877
Liabilities assumed in acquisitions					980
Liabilities divested					(6	)
Revision of estimates (a)		(10	)		(10	)
Accretion of discount		72			116
Ending asset retirement obligations	$	2,965		$	4,250

	~~June~~September 30, 2021
Approved and authorized awards		12,047,866
Awards issued under plan		(9,681,506	)
Awards available for future grant		2,366,360

	Stock Options			Exercise Price		Remaining Term in Years		Intrinsic Value (in thousands)		Stock Options			Exercise Price		Remaining Term in Years		Intrinsic Value (in thousands)
Outstanding at August 22, 2020		0									0
Awards granted		9,705,495		$	10.00						9,705,495		$	10.00
Outstanding at December 31, 2020		9,705,495		$	10.00		9.7	$	57,942		9,705,495		$	10.00		9.7	$	57,942
Exercised		(154,268	)	$	10.00						(154,268	)	$	10.00
Outstanding at June 30, 2021		9,551,227		$	10.00		9.2	$	0
Forfeitures											(10,000	)	$	10.00
Outstanding at September 30, 2021											9,541,227		$	10.00		8.9	$	—

Vested at December 31, 2020		7,204,163		$	10.00		9.7	$	43,009		7,204,163		$	10.00		9.7	$	43,009
Exercisable at December 31, 2020		7,204,163		$	10.00		9.7	$	43,009		7,204,163		$	10.00		9.7	$	43,009

Vested at June 30, 2021		7,049,895		$	10.00		9.2	$	2,232
Exercisable at June 30, 2021		7,049,895		$	10.00		9.2	$	2,232
Vested at September 30, 2021											8,293,903		$	10.00		8.9	$	—
Exercisable at September 30, 2021											8,293,903		$	10.00		8.9	$	—

	June 30, 2021			September 30, 2021
Remainder of 2021	$	164		$	562
2022		79			466
Total lease payments		243			1,028
Less present value discount		(4	)		(38	)
Present value of lease liabilities	$	239		$	990

	Six Months Ended June 30, 2021		Nine Months Ended September 30, 2021
Current tax expense	$	0	$	0
Deferred tax expense		2,535		4,680
Income tax expense	$	2,535	$	4,680

	Six Months Ended June 30, 2021			Nine Months Ended September 30, 2021
Income tax expense at U.S. federal statutory rate	$	2,735		$	4,875
Limited tax benefit due to stock-based compensation		(81	)		(61	)
Other		(119	)		(134	)
Income tax expense	$	2,535		$	4,680
Effective income tax rate		19.5	%	20.2		%

	Three			Six			Three			Nine
	Months Ended			Months Ended			Months Ended			Months Ended
	June 30,			June 30,			September 30,			September 30,
	2021			2021			2021			2021
Net income as reported	$	5,743		$	10,487		$	8,047		$	18,534
Participating basic earnings (a)		(407	)		(743	)		(1,193	)		(1,669	)
Basic earnings attributable to common stockholders		5,336			9,744			6,854			16,865
Reallocation of participating earnings		0			1			392			1
Diluted net income attributable to common stockholders	$	5,336		$	9,745		$	7,246		$	16,866

Basic weighted average shares outstanding		92,676			92,634			92,676			92,648
Dilutive warrants and unvested stock options		0			196			2			67
Diluted weighted average shares outstanding		92,676			92,830			92,678			92,715